HomeMy WebLinkAboutAppendix 4 NYSDEC Site Investigation Protocols1.4-1
TECHNICAL
FIELD GUIDANCE
SITE INVESTIGATION PROCEDURES
NOTES
1.4-2
SITE INVESTIGATION PROCEDURES
GUIDANCE SUMMARY-AT-A-GLANCE
#While no two spills are alike and, therefore, the scope of each site investigation varies,
it is possible to group the various activities into these categories:
--Identifying the type and source of the spill;
--Determining the site history and property ownership;
--Determining the extent of surface, subsurface, and structural contamination; and
--Documenting the site investigation.
#We don't expect each spill responder to be or become an expert in all the skill areas
encompassed by a site investigation. Standby and other spill response contractors can
supply much of the needed expertise. The BSPR Central Office and more of the
regional offices now have hydrogeologists on staff who can assist you. Nonetheless,
the more you understand, the more reasonable and supportable your decisions will be.
#Determining the type and volume of material spilled very early in the spill investigation
process is important to determining what levels of personal and respiratory protection
may be required. BSPR's authority to clean up spills using state and federal monies is
also limited to spills of petroleum products.
#Physical/chemical properties of the spilled material determine: (a) the identity of the
spill's source (if not already known), (b) how the material may have spread in the
environment, (c) how much of a health and/or environmental hazard the spill may
represent, and (d) what initial and longer-term corrective action measures may be
needed to clean up the spill.
#When the source of the spill is known, you should be able to get information on the
characteristics of the spilled material from the owner/operator or through other
technical assistance agencies. However, it is still advisable to sample the material for
laboratory analysis to verify the information provided. All analyses should be
conducted by a laboratory approved by DEC to perform the specific analysis required.
#Don't deliberately smell, handle, or taste product or material contaminated by product
(e.g., soil) to establish its identity. For an unknown believed to be, or containing some
kind of, petroleum product or for an older gasoline spill, ask the laboratory to analyze
the sample for total petroleum hydrocarbons using a gas chromatograph. If the tentative
conclusion is that the product is relatively fresh gasoline, the sample should be
reanalyzed for benzene, toluene, ethylbenzene, and toluene (BTEX).
NOTES
1.4-3
SITE INVESTIGATION PROCEDURES
GUIDANCE SUMMARY-AT-A-GLANCE
(continued)
#The source(s) of a spill is sometimes readily apparent or is identified when a spill is
reported. In other cases, you will have to piece together information derived from
interviews, from your inspection of the site and surrounding area, from records, and
from testing and sampling data to isolate the most probable spill sources. Start your
search by examining potential sources within a few hundred feet of the discovered spill
or nuisance condition and then expand the search radius uphill, upgradient, or upstream.
It is possible that the spill's source may never be conclusively identified. This is
especially a problem in urban settings.
#The process of identifying the spill source can also involve backtracking from a
discovered nuisance condition to the probable source area. A common example is
moving upgradient (in the case of liquid and gaseous product) or downgradient (in some
cases with vapors) along sewer manholes from the location of the discovered nuisance
condition.
#Assuming you are allowed on the premises to continue your investigation, ask to
examine the following records (see page 29):
--Equipment installation and maintenance data.
--Inventory records.
--Precision testing records.
--Repair records.
--Records of the water content in, or any water pump-outs from the tanks.
--Records for any previous tank removal or abandonment projects.
#Documenting property ownership and responsibility for the spill is important -- we want
spillers to clean up spills themselves or reimburse the state for funds spent in a state-
directed cleanup. Documentation concerns, should not, however, outweigh the emphasis
you place on your primary concern: protection of human health and the environment and
mitigation of environmental damage.
#Site investigation methods for determining the extent of contamination vary to some
degree for surface, subsurface, and structural contamination due to a spill. Investigatory
methods for each of these contamination types are discussed in this section (begins on
page 38).
NOTES
1.4-4
1.4 Site Investigation Procedures
During the investigation of a spill and spill site a standby contractor or the spiller collects the
information that you will use to judge the degree of human health and/or environmental hazard
posed by the spill. This information establishes the need for and the extent of cleanup (state-
or RP-directed), and, eventually whether the cleanup can be discontinued. For state-directed
spill response, your site investigation also involves making on-the-scene inquiries and
inspections and doing a records search, when necessary, to establish responsibility for the
spill.
Site investigation is often thought of as a discrete step in the spill response process, as
presented in the introduction to this manual and as diagrammed in Exhibits 1.4-1 and 1.4-2.
In reality, however,a site investigation is a continuous activity that starts with receipt of the
spill report and the first visit to the site and ends with preparation of the Investigative Summary
Report (ISR). In some cases, only a brief examination of the spill site, a limited records
search, and a review of some sampling data may be all that is needed for you to reach a
reasonable judgment on the degree of cleanup necessary. In other cases, you, a spill contractor,
or a spiller will spend several weeks or months collecting and analyzing data until an informed
decision can be made.
While a set of investigation procedures may be useful for one spill and inappropriate for
another, it is possible to group the various activities into these categories:
#Identifying the type and source of the spill;
#Determining the site history and property ownership;
#Determining the extent of surface, subsurface, and (occasionally) structural
contamination; and
#Documenting the site investigation.
Otherwise, physical factors such as geological conditions; the presence and depth of sewers,
basements, and wells; the amount of material spilled; the proximity of sensitive populations and
surface water; the relative congestion of the area; and many other variables will determine the
course of an investigation for a particular spill and site. Exhibit 1.4-3 provides another view
of the objectives of the site investigation.
In this section, we provide general guidance for each of the basic site investigation activity
areas outlined above, as well as guidelines for the design, conduct, and interpretation of
sampling and analytical activities. We have presented the material in a rough chronological
order, but keep in mind that a site investigation often proceeds on many fronts at once. We
assume in this discussion of site investigation procedures that a response to any emergency
condition that might exist is being or has been taken. More specifically, it is assumed that:
1.4-11
Exhibit 1.4-3
Site Investigation Objectives
1.Determine Spill Type and Type of Release (Sudden or Long-Term)
#underground storage tank
#aboveground storage tank
#tank truck
#other
2.Determine Spill Location
#facility name & address
#facility type
#if transportation spill, name of road and corresponding mile markers and/or cross
roads
#primary and principal aquifer determination
3.Determine Product Type
#leaded gasoline
#unleaded gasoline
#diesel fuel
#fuel oil (#)
#kerosene
#jet fuel
#used oil
#other
#unknown
4.Date Spill was Discovered
5.Discovery Method (e.g., tank test failure, vapors in home)
6.Determine if Fire/Explosion Hazard exists
7.Determine Threatened and/or Impacted Resources
#soil
#ground water
#surface water
#storm sewer
#wetland
#other
8.Determine Need for Immediate Clean-Up Actions
1.4-12
#you have selected and called out a standby contractor, if needed (see Part 1,
Section 2);
#the immediate fire and safety hazards are being addressed (see Part 1, Sections
3.1 and 6.2);
#the spill has been stopped, if the source is known (see Part 1, Section 3.2); and
#readily apparent free product has been confined and removed (Part 1, Sections
6.2, 6.4, and 6.5).
Any on-site investigation cannot begin safely until all imminent health and safety hazards are
under control and initial measures have been taken to minimize the impact of the spill.
Note that to properly conduct a site investigation you must possess or have access to a wide
range of specialized skills. Whether you're directing the cleanup or overseeing an RP-directed
cleanup, you'll need some expertise in (or, at a minimum, access to good references on) the
chemistry, health effects, and environmental behavior of different petroleum and chemical
products. We provide some background in these topics in this section (page 18) as well as
guidance on structuring a search for the source of a spill (page 19). You'll need to know how
to locate, work with, and/or interpret aerial photographs, tax records, and other legal
documentation to establish property ownership and operational details (i.e., the possible
identity of the spiller). For subsurface spills, like those from underground storage tanks, you
need to be familiar with geological and hydrogeological principles (as well as have access to
the experts) in order to make decisions about locating monitoring pits and/or wells and to
interpret the complex, and sometimes confusing, monitoring data that are generated over time
(see page 41).
We don't expect each spill responder to be or become an expert in all the skill areas
encompassed by a site investigation. Standby and other spill response contractors can supply
much of the needed expertise. The BSPR Central Office and more of the regional offices now
have hydrogeologists on staff who can assist you. Nonetheless, the more you understand, the
more reasonable and supportable your decisions will be.
Other portions of this manual containing guidance relevant to the conduct of site investigations
include:
#Introduction, Overview of the Spill Response Program, Section B, Roles of the
DEC Spill Responder (provides an overview of spill responder's roles in the
spill response process);
#Part 1, Section 1.2, Enforcement of Spiller Responsibility, and Section 1.3,
Access and Right-of-Entry (discusses BSPR procedures for notifying spillers
of their responsibilities for spill cleanup, BSPR authority to enter private
property to investigate a spill, and procedures for gaining access);
1 Hazardous materials include substances listed in the Code of Federal Regulations (CFR) 40,Part 261, by EPA as hazardous wastes or any other hazardous raw materials.
1.4-13
#Part 1, Section 2, Contractor Selection and Call-Out (reviews procedures for
calling out standby spill contractors to respond to a spill);
#Part 1, Section 3.1, Emergency Response to Fire and Safety Hazards, and
Section 3.2, Confining and Containing Releases (reviews spill responder's
role in an emergency response and proper emergency response procedures);
#Part 1, Section 6, Corrective Action (provides guidance on the investigation and
initial remediation of vapor hazards in structures and sewers; free product in
structures and sewers; free product on the soil surface; free product on surface
water; contaminated soil; and contaminated ground water);
#Part 2, Section 1, Personal Health and Safety Protection (provides guidance
on health and safety practices and guidelines for spill responders);
#Part 2, Section 2, Equipment Training, Calibration, and Maintenance
(provides guidance on the use, calibration, and maintenance of field screening
equipment);
#Part 2, Section 3, Proper Management of Spill Residuals and Debris
(discusses proper treatment and/or disposal of residuals or debris generated in
spill response activities);
#Part 2, Section 4, Quality Assurance/Quality Control Procedures (provides
QA/QC guidelines for sample collection, analysis, and chain-of-custody
procedures).
1. Identifying the Type of Spilled Material
Determining the type and volume of material spilled very early in the spill
investigation process is critical. First, this information is important in
determining what levels of personal and respiratory protection may be required
so that you are prepared before you arrive on the spill scene. Second, BSPR's
authority to clean up spills using state and federal monies is limited to spills of
petroleum products. Although spill responders assist in the emergency response
to a hazardous material spill, the cleanup of a hazardous material spill is the
responsibility of the Hazardous Waste Remediation Division.1 If the spilled
material is a non-petroleum product, contact other regional DEC offices. For
sewage or non-hazardous material spills (e.g., vegetable oil or dairy products)
contact the Regional Water Quality Section. For gaseous releases, contact the
Air Pollution Control Section. For hazardous material spills, contact the Bureau
of Hazardous Waste Remediation.
2 Make sure to establish a Project Identification Number (PIN) first. Later, when theresponsible party has been identified, the costs incurred by the state for sampling can be billedto the spiller.
3 Calibrate these instruments to the manufacturer's instructions before and after every use. Refer to Part 1, Section B, Equipment Training, Calibration, and Maintenance, for moreinformation.
1.4-14
Knowing the physical/chemical properties of the spilled material you can
determine: (a) the identity of the spill's source (if not already known), (b) how
the material may have spread in the environment (e.g., it is very volatile or very
soluble in water), (c) how much of a health and/or environmental hazard the spill
may represent (e.g., it is flammable), and (d) what initial and longer-term
corrective action measures may be needed to clean up the spill (e.g., the material
binds tightly to soils). Exhibit 1.4-4 shows the likely partitioning of different
petroleum constituents. Such information has a bearing on where (i.e., in which
medium) a particular contaminant might be detected.
When the source of the spill is known (e.g., an overturned tanker truck or a
leaking aboveground tank), you should be able to get information on the
characteristics of the spilled material from the owner/operator or through other
technical assistance agencies (see Part 1, Section 3, Emergency Response).
Nevertheless, it is still advisable to order a laboratory analysis of samples of the
material to verify the information provided by the owner/operator. Several
typical field scenarios and the sampling response are presented in Exhibit 1.4-5.
Obtaining a sample of the material spilled is even more critical when the source
of the spill is unknown or in dispute.2 First, learn as much as possible from the
physical characteristics of the material such as its color, odor, or viscosity. For
example, super unleaded gasoline is often pink in color and a #6 fuel oil will be
very viscous, almost asphalt-like (see also Attachments 1.4-1 and 1.4-2). Many
petroleum products will leave a sheen on water. This characteristic can be
tested for by means of the so-called "jar test" where contaminated soil is placed
in a jar of water, shaken, and allowed to settle to see if an oil sheen forms on the
water surface. Don't deliberately smell, handle, or taste product or material
contaminated by product (e.g., soil) to establish its identity as these
techniques present a significant health risk.
Second, you can also use some direct-reading instruments to establish the
presence qualitatively and, in some cases, the identity of a contaminant.3 If
substance spilled is believed to be volatile, the following instruments can be
used to obtain direct readings of vapors coming off the spill mass, contaminated
water, or an area or sample of contaminated soil:
#Photoionization Detector detects most organic and selected
inorganic compounds;
1.4-15
Exhibit 1.4-4
Likely Partitioning of Petroleum
Product Constituents
Will Predominantly Will Predominantly Will Predominantly Will be Found
Absorb to Soil Volatilize into the Solubilize in in Multiple
Particles Air or Soil Gas Water Media
benzo(a)pyrene (n)hexane phenol benzene
phenanthrene (n)heptane MTBE ethyl benzene
benz(a)anthracene (n)pentane napthalene
tetraethyl lead 1-pentane toluene
(o)xylene
1.4-16
Exhibit 1.4-5
Sampling Recommendations for Different Field Scenarios
Situation Type of Sampling Suggested
Report of petroleum odor in well water.
Investigation shows several possible sources
in area.
Use DOH Method 310-13 to identify the type of
petroleum product in the well. To help cross-
match, also take a sample from each potential
source for comparison.
Downgradient monitoring well is free of
product presently, but there has been a spill at
an upgradient gasoline station.
To match the gasoline in the station, use DOH
Method 310-13 to identify petroleum products in
water. Obtain sample from station for
comparison. Use 503.1 to detect dissolved BTX.
Use a modified Method 624 to detect MTBE.
Report of gasoline odors in home.
Investigation confirms odors smell like
gasoline.
Coordinate indoor air sampling with DOH
following DOH Indoor Air Sampling Protocol.
Discover soil pile at a service station that is
being remodeled. Soil has an oily odor.
Use DOH Method 310-13 after extraction or
312-4 for soil to determine if petroleum
contamination.
Several abandoned drums found in an empty
field. Drums contain a black liquid and there
is a varnish-like odor.
Use Methods 624 and 625 to determine if
substance is a petroleum product or a solvent.
Recovery system installed for a diesel spill is
discharging "clean" water to a nearby stream.
Should an air stripper be used to treat the
"clean" water?
Use Method 610 for PAH and 503.1 or 524.2 for
comparison to state standards for such a
discharge. An oil and grease analysis may be
needed.
Reports of chemical odor (like a solvent) in
the well water of several homes. No known
gasoline station in area. A previous BTX
analysis of well water samples indicated no
detectable levels.
Use Methods 601 and 503.1 to identify if the
substance is a solvent or a petroleum product.
Report of a petroleum odor in a well. No
source can be identified. Homeowner heats
with gas.
Use Method 503.1 to identify if odor is
petroleum with the exceptions of fuel oil and
diesel. Use Method 914C in the Standard
Methods to check for pseudomonas.
Unknown substance seeping from stream bank
into stream.
Use Methods 624 and 625 to analyze a liquid
sample. If a liquid sample cannot be obtained,
use Methods 8240 and 8270 to test sample.
NOTES
1.4-17
#Organic Vapor Analyzer measures trace levels of organic vapors;
#Detector Tubes can identify a specific chemical group in a short
amount of time based on a color change in the material inside the
tube; and
#Explosimeter (or Combustible Gas Indicator) measures vapor
concentrations sufficient to support an explosion.
Be conservative in your reporting of readings for an unknown contaminant using
these instruments. Report your readings, for example, as a "needle deflection"
or "positive instrument response" rather than referring to a specific concentration
value. A reading of zero should be reported as "no instrument response" rather
than as "clean" or "no contamination". As a general rule, these instruments
cannot detect vapors at concentrations below 1 ppm. These instruments have
also shown a poor correlation with laboratory results, especially in situations
where the spill has weathered (i.e., much of the volatile fraction has volatilized)
or when the soil is contaminated by migrating vapors as opposed to free product.
These instruments should not be used at diesel tank spills since diesel fuels
contain far less volatiles than does gasoline. Some direct-reading instruments
that detect a particular class of substances (e.g., detector tubes) are also subject
to interferences (i.e., may also react to other substances) and may give a false
reading.
Finally, collect samples of the spilled material for laboratory analysis. All
analyses should be conducted by a laboratory approved by DEC to perform the
specific analysis required. Make sure that the samples collected are of adequate
quality to ensure an efficient and informative analysis. The following factors
affect the quality of samples collected and, thus, the analytical results:
#Decontamination of equipment;
#Preparation of sample containers;
#Sample preservation;
#QA/QC procedures for sample collection; and
#Chain-of-custody recordkeeping.
Follow the guidance provided in Part 2, Section 4, Quality Assurance/Quality
Control Procedures, concerning these factors for the collection and analysis of
field samples.
a. Sample Analysis Considerations
Gasoline is a mixture of over 200 petroleum-derived chemicals plus
several synthetic additives (see Attachment 1.4-1 at the end of this
section). The majority of gasoline components range from C4 to C12
hydrocarbons, and include both straight-chain and aromatic hydrocarbons.
Diesel fuels, on the other hand, consist primarily of C10 to C23 straight-
chain hydrocarbons (the C16 and C17 hydrocarbons predominate) with
very few aromatic constituents. These differences in composition must be
NOTES
1.4-18
kept in mind when deciding upon chemical analyses for petroleum
constituents in samples.
For a suspected spill of a gasoline product, samples should be analyzed
for benzene, toluene, ethylbenzene, and total xylenes (BTEX), methyl-
tertiary butyl ether (MTBE), and total petroleum hydrocarbons (TPH).
This group of constituents is found in most gasoline blends in fairly high
concentrations and comprise the more mobile (to varying degrees) fraction
(see also Attachments 1.4-1 and 1.4-2 to this section). Benzene, in
particular, is of concern because it is a known human carcinogen, is very
volatile, and has a relatively high water solubility. However, because
BTEX are more mobile than the remaining constituents, an analysis of
BTEX alone, without characterizing the entire contaminated soil profile,
cannot be used to quantify the amount of petroleum contamination in soil.
In addition, BTEX is present in much lower concentrations in fuel oils
(actually toluene will be present in a fuel oil in higher concentrations than
benzene or xylene) and, therefore, is not a reliable indicator. Older (two
or more years) gasoline spills of gasoline will have also lost most of the
BTEX fraction (see Attachment 1.4-1 for an expanded discussion of
weathered spills). The older the gasoline spill, therefore, the more it will
look like a fuel oil when analyzed in the laboratory. Few laboratories
have the capability to analyze for other constituents known to be part of
commercial gasoline blends that could still be found in a weathered
sample.
It is hard to distinguish between weathered gasoline product and fuel oil.
If you have a possible old leaded gasoline spill, you can ask the laboratory
to analyze the sample for lead, but since lead doesn't travel very far in
soils, the laboratory may not find it in a sample taken at some distance
from the source of the spill. In addition, unless the laboratory can analyze
for organic lead, a total lead analysis will also measure natural organic
and inorganic lead levels and not just lead levels due to the spill alone
(i.e., it is possible to obtain a false reading, especially for soils high in
inorganic lead). Reliable measures of organic lead contamination can only
be obtained where background total lead concentrations are known or can
be analyzed.
For these reasons, therefore, we recommend that a TPH analysis also be
conducted to check for other less mobile petroleum constituents. For an
unknown believed to be, or to contain some kind of, petroleum product, for
older spills, or for known spills of diesel and fuel oils, the laboratory
should be asked to analyze the sample first for TPH using a gas
chromatograph (GC). This analysis detects straight-chain hydrocarbons
and aromatic constituents, and the results are reported as the sum of all
hydrocarbons in the sample, rather than as individual chemicals. The GC
analysis should then be compared against the patterns for different
petroleum product standards to determine if the pattern resembles, for
NOTES
4 While TPH levels generally indicate fuel contamination, certain sites may have natural orhistorical use characteristics (e.g., natural hydrocarbon production) that make interpreting theanalytical results difficult. Reported soil concentrations of volatile organic chemicals may alsovary with soil type. Complete recovery of volatiles during sample collection is difficult in sandysoils due to losses from evaporation, and adsorption may limit extraction efficiency in clayeysoils. Soils with high organic and/or clay materials are more difficult to analyze than those withminimal amounts of these materials.
1.4-19
example, gasoline-type product or a fuel oil. If the tentative indication is
that the product is gasoline, the sample should be analyzed for BTEX.4
Refer to Exhibits 1.4-6 and 1.4-7 for additional guidelines on analytical
methods. For more guidance on sampling and analysis procedures,
including guidance on where to sample, see the subsection on Determining
the Extent of Contamination on Page 38.
NYSDEC does have monthly sampling and yearly laboratory analysis
requirements for monitoring wells at major petroleum storage facilities,
i.e., those facilities that have an aggregate storage capacity of 400,000
gallons or more of petroleum. All sampling and testing must be conducted
by a private or "out-of-house" laboratory approved by NYSDOH to
perform the specific analyses required. The Department will allow the
facility operator to perform monthly monitoring for free product.
Each monitoring well at a major facility must be sampled monthly for free
product (either by visual means, use of product paste, or electronically).
Three to five well water volumes must be purged before taking a sample.
If free product is found, the facility operator must notify NYSDEC
immediately and testing for purgeable aromatics and petroleum products
in water becomes unnecessary.
Initially after installation and then six months after the initial testing, all
monitoring wells must be sampled and tested for purgeable aromatics
(EPA 503.1) or petroleum products (DOH 310-13) in water. Based on
both the first and six-month testing results, NYSDEC will then establish a
facility-specific testing schedule with at least one laboratory test
performed annually. All results from laboratory analysis must be
submitted to the appropriate regional office.
2. Identifying the Source(s) of Spill
The source(s) of a spill is sometimes readily apparent or is identified when a
spill is reported. In other cases, you will have to piece together information
derived from interviews, from your inspection of the site and surrounding area,
from records, and from testing and sampling data to isolate the most probable
spill sources (there can be more than one). The type of product spilled (see
subsection 1 above) will provide clues as to the probable source(s). Gasoline
1.4-20
Exhibit 1.4-6
Alternative Analytical Methods
AnalyticalMethods General Description Applicability Limitations
TOTALPETROLEUMHYDROCARBONS(TPH or PHC)
#Uses GC/FID analysis to measure concentration of totalpetroleum hydrocarbons extracted from sample using asolvent
#Must specifically request "fingerprint" analysis foridentification of types of petroleum hydrocarbons
#Can be used to analyze water and soil samples
#Most applicable for determining presence of oils (i.e.,fuel oil, waste oil, etc.)
#Can provide information on "weathered" product
#Should specify if analysis of dissolved fraction of groundwater is desired
#Need to specify to laboratory the type of data desired
#Possible to use to identify presence of gasoline product butloss of gasoline can occur during extraction
#Identification of product types can be approximate unlesssamples of pure product (i.e., from the suspected source)are analyzed
______________________________________________________________________________________________________________________________________________________________________
INFRARED(IR--EPAMethod418.1)
#Measures concentration of total petroleum hydrocarbonsextracted from sample using freon #Can be used to analyze water and soil samples
#Most applicable for determining presence of oils
#Can be used to measure lighter oils
#Does not provide identification of types of hydrocarbons
#Subject to interference since analysis also measures non-petroleum hydrocarbons (e.g., organic acids)
#Possible for gasoline sites, however, loss of up to 1/2 oftotal gasoline can occur during extraction______________________________________________________________________________________________________________________________________________________________________OIL ANDGREASE(StandardMethod503)
#Measures weight of oil and grease extracted fromsample using freon #Can be used to analyze soil and water samples
#Better for heavy oils
#Inappropriate for gasoline or oils with volatile fraction (e.g.,waste oils with solvent contamination) due to loss ofvolatiles during extraction
______________________________________________________________________________________________________________________________________________________________________
GASCHROMATO-GRAPHY (GC-EPAMethod 602-water; EPAMethod 8020-soil)
#Measures purgeable aromatics (volatile fraction) usingpurge and trap method
#Provides data on benzene, toluene, ethyl benzene, andtotal xylenes (BTEX). (May need to request xylene dataspecifically.)
#Compound I.D. is not definitive, i.e., compared to massspectrometry (MS) results, which are verifiable
#Good for gasoline
#Can detect some solvents in waste oils
#Not optimum for fuel oils (particularly heavier oils) sincethose compounds lack significant volatile fractions
______________________________________________________________________________________________________________________________________________________________________
1.4-21
Exhibit 1.4-6
Alternative Analytical Methods
(continued)
Analytical
Methods General Description Applicability Limitations
GC (EPAMethod601-water; EPAMethod 8010-soil)
#Measures purgeable halocarbons using purge and trapmethod
#As with Method 602, compound I.D. cannot beconfirmed
#Best for detecting presence of solvents in waste oils #Not applicable for petroleum hydrocarbons
______________________________________________________________________________________________________________________________________________________________________
GC/MassSpectro-metry (MS)(EPAMethod624-water;EPA Method8240-soil)
#Measures purgeable halocarbons and aromatics
#Provides positive identification of BTEX constituents
#Most applicable for gasoline #Not optimum for fuel oils (particularly heavier oils) sincethose compounds lack significant volatile fraction
1.4-22
Exhibit 1.4-7
EPA Analytical Methods
Analytical Group Constituent Analytical Method
Gasoline(motor gasoline, aviation gasoline, and gasohol)1,2-DichloroethaneBenzeneTolueneEthylbenzeneTotal XylenesTotal Volatile Organic Aromatics1,2-Dibromoethane
Methyl-Tertiary-Butyl-EtherTotal Petroleum Hydrocarbon
EPA Method 8010EPA Method 8020EPA Method 8020EPA Method 8020EPA Method 8020All detectable compounds by EPA Method 8020EPA Method 8010 with ECD substituted (EDB) for Halldetector, 2 column confirmationEPA Method 8020EPA Method 418.1
Middle Distillates(kerosene, diesel, jet fuel, and light fuel oils)Napthalenes2-methylnaphthalene, I-methylnaphthalene, and otherswith peaks greater than 10 ppbBenzeneTolueneTotal XylenesEthylbenzenen-Propylbenzene
Total Volatile Organic AromaticsVolatile Organic HalocarbonsTotal Petroleum Hydrocarbon
EPA Method 8270
EPA Method 8020EPA Method 8020EPA Method 8020EPA Method 8020EPA Method 8020
All detectable compounds by EPA Method 8020All detectable compounds by EPA Method 8020EPA Method 418.1
Other or Unknown Priority Pollutant: MetalsPriority Pollutant: Volatile OrganicsPriority Pollutant: Extractable OrganicsNon-priority Pollutant: Organics (with GC/MS peaksgreater than 10 ppb)Total Petroleum Hydrocarbons
Method used dependent on metal analyzedEPA Method 8240EPA Method 8270
EPA Methods 8240 and 8270EPA Method 418.1
NOTES
5 This particular factor is, of course, not peculiar to city settings. Several potential sourcesmay also be grouped together at a single intersection or along a single stretch of road insuburban and rural settings as well.
6 In addition, the property owner may not be the spiller.
7 There also tend to be more broken or leaking water mains in the city (especially the oldercities) that will influence the flow of a subsurface spill.
1.4-23
contamination in a drinking water well suggests a source like a nearby
gasoline station, automobile dealer or repair shop, or bus fleet operation
among the many types of businesses that can operate gasoline tanks (see
Exhibit 1.4-8). Fuel oil in a well, on the other hand, suggests the possibility
of a home heating oil tank leak or overfill or problems with the tanks of a fuel
oil distributor down the street. Compare what you come to learn about the
type of spill with what you learn about possible sources in the area.
It is possible, of course, to never identify the spill's source conclusively. This
is especially a problem in urban settings, like New York City, for several
reasons. First, city zoning regulations tend to group similar sources with the
result that there may be numerous gasoline stations in one area.5 Second, there
is considerable turnover in property ownership, many sublease arrangements,
and/or many abandoned properties in some cities like New York. The task of
unraveling the property ownership trail may be so time consuming that the spill
responder might better spend the time just cleaning up the spill.6 Third, there
tend to be many more conduits and utility lines underlying an urban site. These
conduits and lines will act as preferential flow paths to distribute the spill
over a wide area making tracking the spill back to its source almost, if not
entirely, impossible.7
Under conditions such as these, your role is essentially to be the detective who
pieces together information from a variety of sources. If any persons involved
in or were witnesses to a reported spill, obtain spill-related information
directly from them. Police reports may also contain such information.
Residents also frequently know a great deal about the past history of a site
(e.g., that it was a former gasoline station), including who may have owned the
site previously, or about businesses in the vicinity that could be the source
(e.g., local residents saw a tank being removed from the ground at a particular
gasoline station). The local fire department will also typically know a great
deal about possible area sources and may have records concerning tank
installations and removals. Local fire or police department personnel may
have already talked to the suspected spiller(s) as well and may have had better
success in getting some information. In smaller towns, real estate agents and
the postmaster will often know quite a bit about the past owners of local
properties. There may also be a town or local area historian who may be a
good resource as well.
1.4-24
Exhibit 1.4-8
Possible Petroleum Spill Sources
Service Stations
Motor Vehicle Garages
Automobile Dealerships
Convenience Stores
Municipal Garages
Abandoned or Converted Service Stations
Fleet Operators (e.g., taxicab and vehicle rental companies)
Cleaning Establishments
Industrial Plants, including refineries, terminals, & bulk plants
Schools, Hospitals, & Other Institutions
Airports
Pipelines
Abandoned Oil & Gas Wells
Subsurface Disposal and Injection Systems
Home Heating Oil
Oil for Farming Use
Source:American Petroleum Institute. June 1980. Underground Spill Cleanup Manual.
API Publication 1628.
1.4-25
Your on-site inspection of possible sources may also turn up evidence of a spill.
The key is to know what to look for as evidence of a spill or release at different
types of facilities.
At a gasoline service station, there are several areas you should check where
evidence of a spill might be uncovered. Each of these areas is referenced on a
schematic of a typical gasoline service station in Exhibit 1.4-9.
#Area #1 -- Vent Pipes. Check their condition. Does the number of
vent pipes correspond to the number of known tanks?
#Area #2 -- Pavement Patching. Evidence that the pavement has been
patched/repaired may indicate that subsurface problems (e.g., tank
leak, piping leak, pump failure) may have occurred in the past or
fairly recently. Check age and condition of the patched area. Look
for oil stains, subsidence, buckling of pavement, etc.
#Area #3 -- Pump Islands. Look for cracks and/or stains at base of
pumps. Check to see if pumps are in good repair and not tilted as if
they were struck. Check to see if piping is disconnected. Look for
evidence of meter tampering, abraded hoses, and gasoline-eroded
asphalt in paved area near island.
#Area #4 -- Storm Drains. Are trench or "zipper" drains clean of oil
and silt? Where do these drains lead? Any evidence of staining
indicating gasoline or oil has been flushed into these drains? Any
indication of excavation or other repair work around these drains?
#Area #5 -- Fill Boxes. Check to see if soil around fill boxes has
been eroded by water/gasoline spills (any petroleum odor to soil?).
Are box and pipe tilted in the ground? Is the box cap missing? Any
excavation/repair work in evidence? Gauge boxes and pipes.
#Area #6 -- Repair Bay(s). Look for cracks in the pavement in this
area or for signs of concrete patching. Look for drains and evidence
of frequent and significant spills (e.g., concrete staining,
discoloration).
#Area #7 -- Waste Oil Collection Area. Waste oil may be collected
and stored in an aboveground tank, underground tank, or in drums.
Look for evidence of spills around any filler spouts or containment
areas. Check to see if waste oil
1.4-26
Exhibit 1.4-9
Schematic of a Gasoline Station:
Areas to Check for Evidence of Spills
1 = Vent pipes 7 = Waste Oil Collection
2 = Pavement patching 8 = Street Drains
3 = Pump islands 9 = Station records
4 = Storm drains 10 = Bathroom(s)
5 = Fill boxes 11 = Vapor recovery system
6 = Repair bay(s)12 = Underground tanks
NOTES
1.4-27
has been disposed of in on-site dry wells or pits. Has waste gasoline
been disposed of with the waste oil? If yes, establish dates. Check the
inventory of any waste oil tank. Use a tape with water paste if you
suspect that the tank is below the water table.
#Area #8 -- Street Drains. Check for evidence of product dumping in
nearby sewers and batch basins. Check for petroleum vapors.
#Area #9 -- Station Records. Check inventory book; Petroleum Bulk
Storage License (PBS) if eligible; tank/piping test records; waste oil
disposal receipts; violation orders from other agencies (if any); and
other property/tank owner records, including leases. Check the alarm
panel for the leak detection system. Is the power switched off?
#Area #10 -- Bathroom(s). Look for dumping of waste oil and/or
gasoline down bathroom toilets or sinks. Some station
owners/operators decant the water from their gasoline tanks into these
facilities, which can lead to potentially explosive vapors in sewers.
Confirm whether bathroom drains lead to sewer or septic system.
#Area #11 -- Vapor Recovery System. Some vapor recovery lines have
condensate basins. Check to see if there is any product accumulation or
evidence of a leak.
#Area #12 -- Underground Tanks. Gauge tanks with a water paste tape to
check for water contamination, which may indicate ground-water
infiltration. As a general rule-of-thumb, smaller tanks usually mean an
older station. Check to see if PBS license conforms to what you find.
We recommend that each regional office develop schematics such as for other kinds
of facilities prevalent in their area.
A general search strategy for locating the spill source(s) would be as follows.
Generally, the source of a flammable liquid will be near the location of the
discovery of unconfined liquids or vapors. Start a check of the potential sources
within a few hundred feet of where the nuisance condition or spill was discovered.
Begin with the nearest and most obvious potential source(s) and work outward from
there. All potential sources should be investigated regardless of the age of the
source. Move uphill, upgradient of the presumed ground-water flow direction
(based on surface topography), or upstream of the sewer or conduit flow in
expanding your search radius. If this initial search fails to discover an obvious
source, go back to the nearby potential source(s) and request that the
owners/operators test their equipment for leaks while you continue to expand the
search radius.
The process of identifying the spill source may involve backtracking from a
discovered nuisance condition to the probable source area. A common example of
the backtracking scenario occurs in the investigation of free product and/or vapors in
NOTES
8 Some vapors can migrate upstream for a few hundred feet. This is a common occurrenceduring the winter months when the air in the sewer is warmed by the sewer flow and ventsupward. This is the same effect as that which occurs in a chimney.
1.4-28
sewers. Move upgradient (in the case of liquid and gaseous product) or
downgradient (in some cases with vapors) from the location of the discovered
nuisance condition along the branches of a sewer line while measuring vapor
concentrations and/or looking for an accumulation of free product in the each
manhole.8 Measure vapor concentrations with a combustible gas meter or
photoionization detector equipped with a long sampling probe; do not enter the
sewer to obtain a reading. Free product can be detected using absorbent material
tied to a length of string or rope, which may be left secured in the manhole to help
isolate the contaminant entry point. Eventually, you will reach a manhole where you
can no longer see/detect free product or get a vapor reading; backtrack to your last
positive reading or observation and you're probably in the vicinity of the source of
the spill.
There are also geophysical and soil gas survey methods that can be employed to
isolate sources of subsurface spills. For example, a metal detector or terrain
conductivity unit (in the in-phase survey mode) can be used to locate underground
tanks. A terrain conductivity meter can also be used to detect soil conductivity
changes (i.e., decreases in conductivity below background readings), which
indicates the presence of organics in the subsurface. Soil gas samples can be
collected at fairly shallow depths (one to four feet) over an area (e.g., between two
suspect tanks) to detect volatile contamination emanating from one or more sources.
Each method is fairly non-intrusive and can be conducted with a minimum of
disruption to ongoing site operations, taking as little as one day, depending on the
size of the area to be covered. Special equipment and training are required,
however, and both methods cannot be used in all geologic settings (e.g., the use of
soil gas in heavy clay soils must be done cautiously). Both methods are limited in
their ability to detect low levels of contamination.
Knowing that you've found what you're looking for is also not easy. Your search for
the source of a particular spill may turn up evidence of another old spill separate
from or even mixed in with the more recent spill. Make sure that the source you
identify matches what is known about the spill (e.g., the possible volume of material
spilled) before you stop this phase of the site investigation.
The final phase of identifying the spill source is obtaining data that confirms one or
more probable sources as the actual source(s) of the spill. For example, you may
have backtracked the spill to an intersection with a gasoline station on each corner.
Approach each owner/operator to ask about their tanks. In doing so, follow the
guidelines discussed in Part 1, Section 1.3, Access and Right-of-Entry. Assuming
you are allowed on the premises to continue your investigation, look for indications
of recent excavations or patched concrete or asphalt. Inspect the product dispensers
to see if they have been dented as if hit by a vehicle, as this may indicate damage to
the underground piping. Operate the remote pumps to see if they are leaking and
check for evidence of any spill in this area. Ask to examine the following records:
NOTES
1.4-29
#Equipment installation and maintenance data. Check if the
installation and maintenance records reveal any inadequacies in
practices or procedures, or whether the tank may be located
within the seasonal water table. Determine if there was a recent
overfill or other surface spill.
#Petroleum Bulk Storage certificates. The owner of any
petroleum storage facility having a capacity of over 1,100 gallons
must register the facility with NYSDEC and renew this
registration every five years. These registration certificates
contain information on the ownership and operation of the facility,
and contain other data on the design and operational features of
the facility.
#Inventory records. Discrepancies in the daily tank inventory
records can identify a leaking tank system. These records can be
used to estimate the cumulative amount of the spill. Determine if
accurate daily inventory records are maintained. If the records
are poor, the facility should be regarded as a potential source and
a candidate for precision testing. If the records are properly
maintained and reconciled, review them for discrepancies and
loss trends.
#Precision testing records. Examine the precision testing records
to determine the past performance of the tank system (i.e., tanks
and piping). Be suspicious of any indication that problems were
experienced in testing the system or that multiple tests were
conducted over a short period of time.
#Repair records. Examine the records concerning any repaired
components of the tank system as these will often be the source of
a spill, either before or after the repair was completed.
#Records of the water content in, or any water pump-outs from,
the tanks. The presence of water in a tank UST may indicate a
hole in the tank wall or a loose joint that has allowed ground
water to flow into the tank and probably product out of the tank as
well.
#Records for any previous tank removal or abandonment
projects. Examine any available documentation of the condition
of the tanks when they were removed and of the tank excavation.
Look for evidence that product, water, and/or soil was removed
from the excavation. If the tank system was abandoned in place,
determine if product was removed from the tank(s) and whether
any product may have remained.
For state-directed spill response, the worksheets included as Attachment 1.4-3
at the end of this section may be used in organizing the information collected.
9 The U.S. EPA has also made extensive studies of leak detection methods for underground storagetank systems. Although EPA makes no recommendations, the Agency's report -- Underground TankLeak Detection Methods: A State-of-the-Art Review, EPA/600-2-86/001, January 1986 -- is a goodreview of all the available methods.
1.4-30
Unless the owner/operator can provide you with recent tank system precision
test results (no more than a year old), ask that his or her tank systems (piping
and tanks) be tested for possible leaks. If the owner/operator refuses or is
unable to test the tank systems, ask for his or her permission to let DEC test the
tanks, indicating that if the test shows that the system is leaking and is the
source of the spill that the owner/operator will be billed for the cost of testing.
If permission is granted, follow the testing guidelines discussed below. If
permission is not granted, inform the owner/operator that he or she may still
be identified as the spiller and held responsible for cleaning up the spill.
The basic tank testing methods include volumetric leak test methods and
nonvolumetric leak test methods. A volumetric leak test is the most accurate
tank testing method for detecting a leak in a storage tank or delivery system.
This tank testing method involves sealing and pressurizing a tank or piping
system to test for leaks based on changes in volume of stored product. Make
sure that any tank test is performed according to the National Fire Protection
Association (NFPA) 329, "Precision Test" requirements (summarized in
Exhibit 1.4-10) and by a qualified precision testing company. A comparison
of these methods is provided in Exhibit 1.4-11.9 Nonvolumetric leak tests
include a variety of tank test methods, such as acoustical monitoring, air tracer
systems, or internal tank inspections. Leak tests performed using many of
these methods are not accepted by DEC. A list of methods considered
unacceptable and the reasons why DEC does not permit their use is provided
in Exhibit 1.4-12.
An internal inspection for certain bulk storage tanks may be acceptable as an
alternative to tightness testing. Guidance for conducting internal inspections is
provided in Exhibit 1.4-13 along with a list of the acceptable methods.
General guidelines to follow when inspecting the exterior of an aboveground
storage tank for evidence of a spill include the following:
1.4-31
Exhibit 1.4-10
Summary of Precision Tests Requirements
1.Precision Test means any test that takes into consideration the temperature coefficient of
expansion of the product being tested as related to any temperature change during the test, and is
capable of detecting a loss of 0.05 gal (190 ml) per hour (a limiting criterion widely accepted by
most authorities).
2.A test chosen from currently available technology to reasonably determine whether an
underground liquid storage and handling system is leaking should be used.a Precision Tests should
be performed by qualified technical personnel experienced in the use of the test method and in the
interpretation of data produced.
3.The test procedure should measure the amount of liquid lost based upon fundamentally sound
principles. It should detect a leak anywhere in the complete underground storage and handling
equipment. If the net change exceeds 0.05 gal (190 ml) per hour or equivalent criterion established
for the technology employed, a leak is likely to exist, and appropriate corrective action is necessary.
4.The Precision Test should account for all the variables that will affect the determination of the
leak rate. Besides equipment accuracy and operator error, factors that may affect the precision of
the testing include:b
#Temperature;
#Deformation of the tank or piping;
#Depth of water table;
#Entrapped vapor; and
#Evaporation.
a See Underground Tank Leak Detection Methods: A State-of-the-Art Review, EPA/600/2-
86/001, January 1986, for a detailed review of various tank leak detection methods. Also refer to
TOGS Memo 4.1.2 and 6 NYCRR Part 613 requirements.
b Refer to NFPA 329 for a detailed discussion of the effects of these factors on Precision
Tests.
Source: NFPA 329 (1987)
1.4-32
Exhibit 1.4-11
Comparison of Precision Test Methods Accepted by NYSDEC
Ainlay TankTegrity HornerEzy-Check Heath Petro Tite Hunter LeakLocator MooneyTest Tank Auditor Principle ofOperation -pressuremeasurement bya coil typemanometer,determineproduct levelchange in apropane bubblingsystem
-pressuremeasurement,determineproduct levelchange in an airbubblingsystem
-pressurize asystem by astandpipe-keep the levelconstant byproduct addingor removing-measurevolume change-product circu-lation by pump
-"principle ofbuoyancy" theapparent lossin weight of anyobjectsubmerged ina liquid is equalto the weight ofthe displacedvolume ofliquid
-level changemeasurementwith a dipstick
-"principle ofbuoyancy"
ClaimedAccuracy(gal/hr)
-0.02 -less than 0.01 -less than 0.05 -0.05 even atproduct level atthe center of atank
-0.02 -0.00001 in fillpipe-0.03 at centerof 10.5'diameter tank Approx. Cost -$225/day +exps. (3tanks/day)
-$300/tank -$75/1000 gal.-$500/tank -$250/tank -$400/tank
Single TankPrep. for Test -fill tank eveningbefore -fill 4 hrs. priorto test (usuallytest at night)
-fill tank prior totest -typically filltank beforetesting
-fill tank 12-14hrs. prior totest
-none
Tests Single orMultiple Tanks -2 -2 -4 -3 -3 -1
Potential forPrintedReadout
-no -yes -no -yes -no -yes
Tests @Pressure NoGreater Than 5PSIG
-yes -yes -sometimes no -yes -yes -yes
TotalDowntime forTesting
-10-12 hrs. (fillednight before 1.5hrs of testing)
-4-6 hrs. (2 hr.wait after fill up,1 hr. test)
-6-8 hrs.-3-4 hrs.-14-16 hrs.(12-14 hr. waitafter fill up, 1-2hr. test)
-1.5-3 hrs.
RequiresEmpty/Full/Overfilled Tankfor Test
-full -full -overfilled -typically full -full -typically full
Source: TOGS Memo 4.1.2 (August 16, 1986).
1.4-33
Exhibit 1.4-11
Comparison of Precision Test Methods Accepted by NYSDEC(continued)
Ainlay Tank
Tegrity
Horner
Ezy-Check
Heath
Petro Tite
Hunter Leak
Locator
Mooney
Test
Tank
Auditor TemperatureCompensation -3 temperaturesensors-0.01oFaccuracy
-averagingtemperaturecoil-0.001oFaccuracy
-onetemperaturesensor-0.003oFaccuracy-productcirculation
-onetemperaturesensor atmid-volume-0.001oFaccuracy-3 sensors atunusualconditions
-5 tempera-ture sensors-0.001oFaccuracy
-usereferencetubs
Ground-waterMasking -may conducttesting whenleak iscompletelymasked
-conduct testby standpipeif water tableis suspected
-tests bystandpipe -may conducttesting whenleak iscompletelymasked
-may conducttesting whenleak iscompletelymasked
-the test isperformed attwo differentlevels
End Deflection -overnight waitafter fill up-if tank is filledone hourbefore test,deflection isrecognized byevaluation ofresults
-recognized bytests resultsevaluation
-stops the enddeflectionwithin 2 hoursby test resultsevaluation
-enddeflectionoccursimmediatelyafter fill up-1.5 hour waitfortemperatureadjustment
-test 12-14hours afterfilling
-test atnormaloperatingconditions or3-6 hrs. afterdelivery
Vapor Pockets -if vapor pocketis recognized,tank top will beexcavated andthe vaporremoved bydrilling
-could bereleased by afloat tube-usesstandpipe tostabilizevapor pocket
-the presenceof vaporpockets isrecognized byobservingbubbles in thestandpipe
-compensateif the pocketis released-not affectedduring in-tank testing
-no com-pensation -not com-pensatedduringtesting in afilled tank-notapplicableduring in-tank testing Evaporation -uses propanegas to reduceevaporation-short testingintervals
-testing time isshort-overnighttesting(usually)-could usestandpipe
-the graduatetop is capped -compensated by a hollowsensor filledwith product
-compen-sated byusing anevaporationcap
-short testing-compen-sated bytemperatureprobe
Wind -notcompensated -partiallycompensatedby printedresultevaluation
-not affected -partiallycompensated
-not com-pensated -compen-sated
Source: TOGS Memo 4.1.2 (August 16, 1986).
1.4-34
Exhibit 1.4-11
Comparison of Precision Test Methods Accepted by NYSDEC(continued)
Ainlay Tank
Tegrity
Horner
Ezy-Check
Heath
Petro Tite
Hunter Leak
Locator
Mooney
Test
Tank
Auditor Vibration -notcompensated -partiallycompensatedby resultevaluation orby using astandpipe
-not affected -partiallycompensated
-not com-pensated -not com-pensated
Noise -not affected -not affected -not affected -not affected -not affected -not affected TankGeometry -notcompensatedfortemperaturecompensation-reduced bycalibration
-notcompensatedfortemperaturecompensation
-notcompensatedfortemperaturecompensation
-notcompensated fortemperaturecompensation
-notcompensated fortemperaturecompen-sation
-compen-sated bycalibration
Instrumenta-tion Limitation -leak ratemeasurementwhen volumechange is lessthan 0.06 gal.during test
-no limitationfor typicaltank testing(4-inch fillpipe)
-no limitationfor typicaltank testing(4-inch fillpipe)
-sometimesdue to tankinclination
-no limita-tionfor typicaltank testing(4-inch fillpipe)
-sometimesdue to tankinclination
Operator Error -insignificant -insignificant -insignificant -insignificant -insignificant -insignificant AtmosphericPressure -not affected -not affected -not affected -compensated -not affected -not affected
Inclined Tank -by calibration -by calibration -by calibration -bycalibration -bycalibration -bycalibration PowerVariation -not affected -not affected -not affected -notcompensated
-affected -notcompensated
Source: TOGS Memo 4.1.2 (August 16, 1986)
1.4-35
Exhibit 1.4-12
Tank Test Methods Currently Unacceptable to NYSDEC
Test results obtained using any of the following methods are considered to be unacceptable to
DEC for one or more of the reasons listed below.
A.The following tank testing methods are unacceptable because they are run only on partially
full tanks and, therefore, do not test the entire tank:
# ARCO HTC Underground Tank Leak Detector; and
# Ethyl Tank Sentry.
B.The following tank testing methods are unacceptable because they are more properly used
as monitoring rather than testing methods and/or because they cannot detect leaks as small
as 0.05 gallons per hour:
#Standpipe (Hydrostatic) test;
# Pneumatic (Air Pressure) test;
#Inventory Reconciliation;
# Veeder-Root Tank Level Sensor (TLS); and
# Smith and Dennison Helium Test.
C.The following tank testing methods are unacceptable because they are experimental or not
commercially available:
# Certi-Tek Testing;
# Helium Differential Pressure Testing;
# PALD-2 Leak Detector;
# SRI Laser Beam Leak Detection;
# Acoustical Monitoring System (AMS);
# Ultrasound, Ultrasonic Leak Detector;
# Varian Leak Detector;
# Vacutect (Tanknology); and
# TRC Rapid Leak Detector.
Source: TOGS Memo 4.1.2 (August 16, 1986)
1.4-36
Exhibit 1.4-13
Guidance for Internal Tank Inspections
Internal inspection will be accepted as an alternative to precision tightness tests under the
following conditions:
#Tank size is greater than 50,000 gallons;
#Tanks are considered "technically impossible to test" in reference to precision test. For
example, a tank that is only one half under the ground is susceptible to variations in
temperature, and cannot adequately be evaluated by precision testing methods.
Initially, all product and tank bottoms must be removed, and the tank interior cleaned to remove
loose scale, corrosion, and residual product. Tank entry is an extremely dangerous procedure and
should only be performed by properly trained and equipped personnel. Tanks containing gasoline
residues are explosive, and all possible ignition sources should be kept at a safe distance. Positive
ventilation and standby personnel should also be provided as additional precautionary measures.
Further information on safety precautions is provided by the American Petroleum Institute (API) and
National Fire Protection Association (NFPA) publications.*
In some locations and for some types of equipment, adequate inspection consists of visual
inspection of the tank shell to detect corrosion, and a more detailed inspection by using one or more of
the following methods:
#Ultrasonic techniques;
#Acoustic emission techniques;
#Aural inspection (ballpeen hammer test);
#Magnetic particle inspection;
#Liquid penetrant inspection;
#Fluorescent inspection; or
#Electromagnetic inspection.
* References for fire and safety precautions: (1) API Publication 2015, Cleaning Petroleum Storage
Tanks, 1982; (2) API Publication 2015A, Guide for Controlling the Lead Hazard Associated with Tank
Entry and Cleaning, June 1982; (c) NFPA 30, Flammable and Combustible Liquids Code, 1984.
Source: TOGS Memo 4.1.2 (August 16, 1986).
NOTES
1.4-37
# Discoloration of paint is often an indication of leakage or overfills.
# Check for gross leaks resulting from corrosion or cracks. Check all
fixtures and seams.
# Check valves, pipe fittings, and hoses for evidence of wear due to high
liquid turbulence or velocity changes that stress the system. Leaks are
most likely to occur around pipe bends, elbows, tees, and other restrictions
(e.g., orifice plates and throttling valves).
# Check loading and unloading hoses used as flexible connections between
vehicles and storage tanks, these are extremely vulnerable to wear and
tear.
# Check product transfer pumps and compressors for deterioration from
mechanical wear, erosion, or corrosion. They can also fail because of
improper operating conditions; piping stresses; cavitation and foundation
deterioration; foundation cracks; uneven settling; missing anchor bolts;
faulty pump seals; excessive vibrations and noise; deterioration of
insulation; and excessive dirt. A burning odor or smoke may indicate
pump and compressor failure.
# Examine heat exchangers or condensers and inspect the pressure-release
valves and bladder-height gauges in vapor control systems.
# Concrete curbing around the base of the foundation and foundation
ringwalls can crack or decay. Concrete pads, base rings, piers, column
legs, stands, and any other general support structures should be examined
for cracks and splitting. Wooden tank supports should be checked for
rotting. Anchor bolts should also be checked for structural integrity and
tightness.
Once you have identified the most probable source, your on-site inspection
should focus on such questions as the following:
1.If a leak has occurred, has it been stopped?
2.Has the fire department been consulted to determine whether or not
a fire hazard or explosive situation exists? Is there any safety
hazard? Are vapor exposures significant to workers/residents in
nearby buildings through windows, ventilation systems, or
subsurface electrical vaults? Is ponded product finding its way into
sewer lines and posing a potential explosion hazard?
3.Does ponded product exist in the excavation, on the ground water,
or elsewhere in the area?
NOTES
1.4-38
4.Is this site near sensitive land uses (e.g., next to homes, a school)?
5.Are existing pathways of concern apparent (i.e., sewer laterals,
utility conduits, nearby wells, surface runoff)?
3. Determining the Site History and Property Ownership
Interviews should be combined with checks of the Petroleum Bulk Storage
records searches of the historical records concerning land uses and property
ownership over time. The latter can include a review of a historical series of
aerial photographs, interviews with a town or local area historian, a search
through the tax records and maps, and a search of the property deed recordings.
A key question in this regard is how much time should you spend in tracking
down people and records in an attempt to document responsibility for a spill
(remember, identifying who owns property does not necessarily identify the
possible spiller). The answer is, "it depends." Documenting responsibility for
the spill is a very important concern -- we want spillers to clean up spills
themselves or reimburse the state for funds spent in a State-directed cleanup.
These concerns, however, should not outweigh the emphasis you place on your
primary concern: protection of human health and the environment. If you believe
a spill is serious enough to demand an immediate clean-up effort, then you should
concentrate on the cleanup and not spend time documenting ownership and
establishing the chain-of-events leading up to the spill. At the same time, there
comes a point in each spill response where there will be sufficient time to work
on establishing spiller responsibility; it shouldn't be ignored.
Remember that establishing property ownership definitively may prove very
difficult for spills in urban settings where properties are often abandoned or
change ownership frequently.
4. Determining the Extent of Contamination
A critical consideration in your estimation of the severity of the spill and the
urgency and complexity of the clean-up effort will be how much area has been
impacted, and who or what might be exposed to the contamination in that area.
Determining the horizontal (and, in some cases, vertical) extent of contamination
must occur fairly quickly unless you have other information to indicate
otherwise. Learning that you have a small, localized spill that has soaked into
a few inches of soil versus a free and dissolved product plume stretching
towards a municipal well field, for example, would be very important
information towards determining how and how fast you must investigate the
problem. The latter scenario may mean there is little time to waste (depending
upon the velocity of ground-water flow and the influence of the pumping wells)
investigating the extent of contamination (i.e., how close to the well field is it?),
or that actions must be taken quickly to buy the time to investigate the situation
carefully (e.g., stop pumping the municipal wells closest to the source).
NOTES
1.4-39
Site investigation methods for determining the extent of contamination vary to
some degree for surface, subsurface, and structural contamination due to a spill.
Investigatory methods for each of these contamination types are covered below.
a. Determining the Extent of a Surface Spill
Contamination on the ground or water surface may not necessarily
originate from an obvious surface spill (therefore, an investigation of a
surface spill may actually involve investigating a subsurface spill). For
example, a subsurface spill can contaminate surface waters and soil after
product has migrated through the soil and via ground water to emerge as
a surface seep (see Determining the Extent of a Subsurface Spill on Page
40). However, it is usually easier to determine the extent of surface spill
than it is to determine the extent of a subsurface spill because the
contamination is more easily seen or measured, especially for a liquid or
solid product spill. A surface spill of a gaseous product is more difficult
to track without access to sophisticated monitoring stations unless there is
contaminant deposition from the vapor cloud that can be measured in the
surface soil and/or water.
The extent of contamination from a surface spill depends on the physical
properties of the released product, the amount and duration of the release,
and on various site-specific characteristics. The transport of the released
product is affected by certain properties: specific gravity, solubility,
viscosity, and volatility. The specific gravity of the released product
determines whether it will float on or sink into the water. The degree of
solubility of the product constituents in water determines how difficult it
may be to separate the dissolved contaminant from water. The viscosity
of the released product also affects its mobility in the environment. If the
spilled product is particularly volatile, a spill may evaporate before it
travels any great distance to contaminate soil or water. These properties,
together with other site-specific factors, determine how fast the spill may
move through the environment.
The effects of soil type on the transport of released product are discussed
in the next subsection, Determining the Extent of a Subsurface Spill. Other
site-specific characteristics, such as the topography of the spill area,
surface drainage patterns, and utility line configurations, also affect the
direction and/or pattern of surface contamination. Streams and utility lines
provide excellent conduits for transporting the released product. Cracks
in the sidewalk in more urban settings also complicate the spread of a
surface spill. Assessing the levels of contamination at various spots in a
stream, utility system, or water supply source can help define the extent of
contamination. Depending upon the size of a spill, a visual survey of the
area may be sufficient to track its path, or you may need to consult aerial
photographs or topographic maps and other geographic information for the
NOTES
10 Common sources for such maps and photos include: United States Geological Survey(USGS), the Soil Conservation District Offices, the engineering or architectural firms thatdesigned or built nearby structures, local surveyors, the town or city department of public works,libraries, and stationery stores.
11 High hydrocarbon concentrations in a deep clay layer could be regarded as evidence thatthe downward migration of the contaminants is restricted. Alternatively, this clay layer could beregarded as a long-term source of contaminants. This example illustrates that the sameobservation can be interpreted very differently.
1.4-40
area.10 Use maps and photographs whenever possible to effectively
illustrate the areas (lands, surface waters, and the like) that are known to
be contaminated or appear susceptible to contamination. For spills
yielding hazardous gases, record the principal wind direction and its speed
from data obtainable through local weather stations or airports and use this
information to predict how fast and in what likely direction the vapor
cloud will migrate.
b. Determining the Extent of a Subsurface Spill
Determining the extent of contamination from a subsurface spill includes
examining both soil contamination and ground-water contamination
(free and/or dissolved product). Subsurface spills will always
contaminate some area of soil. How much soil becomes contaminated is
determined by how quickly the spill was detected, how much was spilled
(a very large leak can be detected very quickly and a small leak that isn't
detected can amount to a large spill over time), and how easily the
material moves through soil. Whether ground water also becomes
contaminated by a subsurface spill depends on these same factors plus the
depth to ground water at the site. An underground tank located near or
within the seasonal high water table, if it leaks, will contaminate ground
water. An intervening clay layer may act to retard contaminant migration.11
However, if contaminated soil is not removed or otherwise remediated, it
can act as a continuing source of free product and dissolved contaminants
as rainwater leaches contaminants deeper into the soil or as a function of
changes in water table elevation. As a general rule (based on ground-
water modeling studies), the greater the amount of contaminated soil,
independent of the contaminant concentrations, the greater the risk of
ground-water contamination and the higher the expected dissolved
contaminant concentrations.
Depending upon the size and duration of the spill, investigating the extent
of contamination from a subsurface spill can be both costly and time
consuming. Before digging monitoring pits or installing soil borings and
ground-water monitoring wells, make as much use as possible of water
quality data from existing water supply (or other) wells and from surface
water (which is usually hydraulically connected to ground water) located
in the vicinity of the spill. These data provide information on the
contaminant concentrations to which people are exposed and can give you
an idea of how far ground-water contamination may have spread.
NOTES
12 These methods are also subject to interferences. Geophysical methods, for example, aresensitive to sources of electromagnetic radiation (e.g., overhead power lines). Other volatilematerials within the subsurface can present interferences for soil gas methods. Methane gas isone such example, particularly in municipal landfills, in wetland areas, or in any area ofextensive fill.
1.4-41
Access available geologic information to determine soil types, soil
composition, type of bedrock and depth to bedrock, and depth to ground
water. This literature search can determine, for example, that the site is
underlain by shallow, fractured bedrock, or that there are sand layers in the
near-surface and largely clayey soils. In the former instance, attempting
to track contamination in the bedrock ground water would be exceedingly
difficult given all the possible migration paths the contamination can take.
It is conceivable that many monitoring wells could be drilled in this
environment and not intercept the contamination at all. Accordingly, one
might not drill wells at all, but might dig a trench down and into bedrock
as a more effective monitoring and recovery technique since the trench
will intercept a greater number of flow paths.
In the latter instance, you would want to locate monitoring wells in these
channel sands as the contamination is likely to preferentially flow along
these more permeable pathways. Again, it is conceivable that, lacking this
knowledge, one could drill monitoring wells in this environment and
completely miss the migrating subsurface contamination.
One way to minimize the "hit or miss" aspect of a well drilling program is
to utilize techniques like soil gas monitoring and terrain conductivity.
These techniques are essentially screening methods that can be used to
quickly assess an area to generate data on the extent of subsurface
contamination sufficient to guide where confirmatory sampling (soil
borings and monitoring wells) should be conducted. This latter point is
important. Soil gas and/or geophysical surveys alone cannot conclusively
map the extent of subsurface contamination.12 Each must be used in
combination with a confirmatory sampling program, that is, it is still
necessary to drill soil borings and/or sample ground water for
contaminants. The benefit to using these techniques, however, is that they
generate more information that you can use to guide your selection of
drilling locations. The result can be that potentially fewer borings/wells
are installed in comparison to a drilling program based upon, for example,
moving out from a source in ever-larger concentric circles or squares.
Soil Properties
Soil type and composition directly affects the permeability of the soil to
the released product. Liquids or vapors enter, accumulate, or flow through
soil or rock in the void or pore spaces between the particles that make up
the soil or rock. The size of the voids in soil vary from large (gravel), to
small (sand and topsoil), to essentially zero (dense clay). This variation
13 The hydraulic conductivity, K, is defined by
vK = ----- i
where v is the flow rate, and i is the hydraulic gradient (defined as the drop in pressure head perunit distance between two points in the soil). K is generally determined in the laboratory undercontrolled flow conditions when v and i are known. Alternately, the flow rate, v, can be estimatedfrom field measurements for i and a laboratory-determined value for K.
1.4-42
in void size and the interconnections between the void spaces translates in
differences in permeability to product (or water or water and product) that
can range from several feet per minute in gravel to one foot per day in
shale or sandstone. Hydraulic conductivity is an index by which to
measure the permeability of soil or rock. Exhibit 1.4-14 provides a quick
reference to the range in hydraulic conductivity for selected soils and
rocks for estimating potential flow rate.13
The flow pattern of a subsurface spill is more difficult to predict in
heterogeneous soils or those with irregular patterns of fractured bedrock
(Exhibit 1.4-15). A subsurface spill mass that encounters an impermeable
clay layer will accumulate and then spread laterally until it can once again
migrate downward through more permeable earth materials. As noted
earlier, a fractured bedrock flow system often makes it very difficult to
predict the direction of subsurface flow. Similarly, areas where fill
materials have been deposited (e.g., along shorelines or in wetland areas)
may exhibit complicated flow patterns.
Not all of the subsurface spill will reach ground water, however.
Significant amounts of the product will remain trapped in the void spaces
in the earth materials to remain in what is known as the residual saturation
state (see Part 1, Section 6.7, Ground-Water Remediation). The type of
soil and the depth to ground water will directly affect the amount of
released product that remains in the residual saturation state. In addition,
as the void spaces fill with water (i.e., become more saturated), there is
less pore space left for the continued downward migration of product.
Consequently, the spill mass begins to spread along the water table (see
Part 1, Section 6.7, Ground-Water Remediation). If the product has a
specific gravity less than water (water has a specific gravity of one), the
result is a free product layer although some of the more soluble product
constituents will dissolve into the aquifer. If the product has a specific
gravity greater than water, the product mass will sink into and, perhaps,
through the aquifer until it reaches a confining layer. Again, the more
soluble constituents in this "sinking product" will dissolve into the aquifer.
NOTES
1.4-45
Information on soil characteristics is generally available from the state
geological survey office, the U.S. Geological Survey, the Soil
Conservation Service, area universities, and from samples you can take
when you install monitoring pits, soil borings, monitoring wells, recovery
wells, interceptor trenches, or soil ventilation systems. A local public
works department can also be a source of valuable information concerning
the types of materials encountered in excavations, water table depths, and
probable direction of flow. A geologist should log all borings. Be careful
in making hasty assumptions and inferences about the soil characteristics
over a large area based on only a few soil samples as soils are rarely
uniform over an extensive area. Building foundations, sewer lines, water
mains, and utility conduits add to the heterogeneity of the subsurface
materials and will often provide preferential flow paths for contaminant
migration.
Hydrogeology
Having the following hydrogeologic information is essential for assessing
the extent of subsurface contamination:
#Minimum depth from ground surface to the water table. Depth
to ground water, or the water table, directly affects the probability
of ground-water contamination from a spill. For example, with
increased depth to ground water, an increased amount of the spilled
product can be retained in the void spaces. It is possible for all of
the product to be adsorbed in these spaces before it reaches the
water table. Note, however, that this reservoir of product will
represent a continuing source of contamination over time to the point
that eventually some of the contamination will reach ground water.
# Slope of the water table. The slope (gradient) of the water table
determines in which direction free product and dissolved material
will migrate. The slope of water table can be determined by
comparing the water levels at three or more monitoring wells, and
often is approximated by the ground surface topography and slope.
Ground water and free product will flow from higher to lower
elevations.
#Seasonal fluctuations of the water table. A typical water table
will fluctuate up and down in response to seasonal changes,
variations in rainfall, and in response to ground-water usage. A
rising water table will carry free petroleum product upward
(possibly causing nuisance conditions, like free product or vapors
in a basement, to reappear), and will trap some product below the
water table. A falling water table will leave behind residual
product in the void spaces (see Exhibit 1.4-16). The result is a
greater distribution of product in the subsurface and product trapped
NOTES
1.4-46
below the water table will generally not be recoverable unless the
water table drops precipitously (see Part 1, Section 6.7, Ground-
Water Remediation).
#Hydraulic connection between the ground-water system and
nearby surface water. Ground water is often hydraulically
connected to surface water; that is, ground water contributes to the
surface water flow. A subsurface spill can migrate in ground water
to appear later in the surface water or as a seep as shown in Exhibit
1.4-17.
Other Site-Specific Characteristics
As noted above, the presence of sewer or utility lines at a spill site
can provide for preferential flow paths (i.e., along the higher
permeability backfill material) for liquid and vapor contamination
to migrate in directions not expected on the basis of the local
geology or hydrogeology. Locating these underground utilities is
important for another reason as well: you will need to know the
location of all the underground utilities before beginning a drilling
program. The presence of existing pumping wells in the vicinity
will also influence ground-water flow patterns potentially in
directions not expected on the basis of the surface topography. The
records on these wells may also provide important geological and
hydrogeological information for your investigation such as
stratigraphic data and the depth to ground water.
Field Monitoring
Much of the site investigation to determine the extent of a subsurface
spill will involve the collecting of data from the sampling of
subsurface soils and ground water. Designing a monitoring program
involves two related considerations. Select monitoring locations to
learn as much as possible about subsurface conditions and to
establish the vertical and horizontal extent of contamination. In
addition, some monitoring locations should be located to help
measure the progress of remedial measures taken at the site.
NOTES
1.4-49
Both monitoring pits or trenches and monitoring wells are used.
Monitoring pits/trenches work well when bedrock and ground
water are shallow (i.e., less than 15 feet). A monitoring pit/trench
can reveal considerable information about the stratigraphic soil
layers between ground surface and bedrock. In addition, since the
pit/trench intercepts a large area of flow paths or channels, it is
possible to have them double as effective product collection and
recovery systems in subsurface environments, such as fractured,
near-surface bedrock, where intercepting the contaminant flow
with a well would have been a "hit or miss" proposition. The use
of monitoring pits/trenches is limited, however, by the depth to
which pits/trenches can be dug without the use of special
equipment. Using a backhoe, this maximum depth is about 15 feet,
and as the depth increases, more consideration must be given to
shoring the sides of the trench to prevent collapse. In addition,
trenches are difficult to keep open in very wet soils where the
walls will tend to slough in.
If the contamination is known to have reached depths greater than
15 feet or so, you will need to install soil borings and monitoring
wells to sample soils at depth and sample ground-water quality.
Various drilling methods are used depending upon the drilling
depth and the nature of the geologic materials that must be passed
through (see Exhibits 1.4-18 and 1.4-19). Caution should be
exercised in drilling through contaminated zones and confining
layers so as to not provide a route for contaminants to migrate
vertically. Any well drilled through a contaminated zone or
confining layers should be adequately sealed. It may be prudent
not to drill through confining layers in certain areas, or to drill
only partly into them to determine their effectiveness in retarding
the vertical movement of contaminants. Before drilling also
contact utility companies ("Miss Utility") so that buried pipes and
cables can be located. A minimum of three borings, taken below
or next to the underground tank or the area previously occupied by
the tank, should be used for soil sampling to check for lateral and
vertical movement of contaminants. Additional borings may be
necessary in some locations, particularly where the associated
piping is suspected of leaking. Soil samples should be taken for
laboratory analysis of total
1.4-50
Exhibit 1.4-18
Basic Well Drilling Methods
Drill
Typea
Normal
Diameter
Hole
Maximum
Depth
Average
Time
Per Hole
Normal
Expense Advantages
Disadvantages
1.
Mud Rotary
Air Rotary
4"-20"Unlimited Fast Expensive 1.Good for deep holes
2.Can be used in soils
and relatively soft rock
3.Wide availability
4.Controls caving
1.Need to use drilling fluid
2.Potential bore hole damage
from drilling fluid.
2.
Solid Stem Auger
4"-8"100-150 ft.Fast
under
suitable
soil
conditions
Inexpensive
to
moderate
1.Wide availability
2.Very mobile
3.Can obtain dry soil
samples while drilling
1.Difficult to set casing in
unsuitable soils (caving)
2.Cannot penetrate large
stones, boulders, or bedrock
3.Normally cannot be used to
install recovery wells
4.Difficult to obtain
undifferentiated soil samples
3.
Hollow Stem Auger
4"-12"100-150 ft.Fast
under
suitable
soil
conditions
Inexpensive
to
moderate
1.Good for sandy soil
2.Can set casing thru
hollow stem
3.Very mobile
4.Can obtain dry soil
samples and split spoon
samples
5.Controls caving
1.Casing diameter normally
limited to 4"-6"
2.Cannot penetrate boulders or
bedrock
3.Limited avail- ability
1.4-51
Exhibit 1.4-18
Basic Well Drilling Methods
(continued)
DrillTypea
NormalDiameterHole MaximumDepth
AverageTimePer Hole NormalExpense Advantages Disadvantages
4.KelleyAuger
8"-48"100 ft.Fast Moderatetoexpensive
1.Can install large-diam. recovery wells2.Drills holes withminimum soil walldisturbance orcontamination3.Can obtain gooddisturbed soilsamples
1.Large equipment2.Seldom available inrural areas3.May require casingwhile drilling4.Does not work inwet sandy soils
5.BucketAuger
12"-72"90 ft.Fast Moderatetoexpensive
1.Can obtain gooddisturbed soilsamples2.Can install large-diam. recovery wells3.Good in sandy soils
1.Typically requiresdrilling fluid2.Normally very largeoperating arearequired
6.Cable Tools 4"-16"Unlimited Slow Inexpensivetomoderate
1.Wide avail- ability2.Can be used in soilor rock
1.Slower than othermethods2.Hole often crooked3.May require casingwhile drilling
aSee Part 3, Section 1, for a description of these drilling methods.
1.4-52
Exhibit 1.4-18
Basic Well Drilling Methods
(continued)
Drill
Typea
Normal
Diameter
Hole
Maximum
Depth
Average
Time
Per Hole
Normal
Expense Advantages Disadvantages
7. Air Hammer 4"-12"Unlimited Fast Expensive Fast penetration in consolidated rock 1.Inefficient in unconsolidated soil2.Geophysical logs not available3.Control of dust/air release4.Excessive water inflow will limit use
8. Casing Driving (well point)
2"-24"60 ft.Slowtomoderate
Inexpensive 1.Wide availability2.Very portable 1.Limited to unconsolidated soil; cannot penetrate largeboulders or bedrock2.No soil samples3.Generally inefficient method to install recovery well
9. Dug Wells Unlimited 10-20 ft.Fast Inexpensive 1.Wide availability2.Very large-diam. hole easily available 1.Caving can be severe problem2.Limited depth3.Greater explosive hazard during excavating intohydrocarbons
10.Reverse Rotary 4"-36"Unlimited Fast Expensive 1.Same as rotary2.Good in loose, sandy soil 1.Same as rotary
11.Reverse Air 4"-50"Unlimited Fast Expensive 1.Good for large-diameter holes2.Less drilling fluid required 1.Need dual-walled drilling pipe2.Increased drill pipe handling
12.Jetting 3"-12"100 ft.Fast Moderate Good in loose sand Need to use water as drilling fluid
Source: [2]
1.4-53
Exhibit 1.4-19
Relative Performance of Different Drilling Methods
in Various Types of Geologic Formations
Direct Direct Direct Rotary Reverse ReverseRotaryRotary(Down-the-Direct Rotary Rotary RotaryCable(with with hole air (Drill-through (with (Dual HydraulicType of Formation Tool fluids)air)hammer)casing hammer)fluids)Wall)Percussion Jetting Driven Auger Dune Sand 2 5 NRa/NR 6 5b/6 5 5 3 5Loose sand and gravel 2 5 NR NR 6 5b/6 5 5 3 5Quicksand 2 5 NR NR 6 5b/6 5 5 NR 1Loose boulders in alluvial fans 3-2 2-1 NR NR 5 2-1 4 1 1 NR 1 or glacial driftClay and silt 3 5 NR NR 5 5 5 3 3 NR 3Firm shale 5 5 NR NR 5 5 5 3 NR NR 2Sticky shale 3 5 NR NR 5 3 5 3 NR NR 2Brittle shale 5 5 NR NR 5 5 5 3 NR NR NRSandstone--poorly cemented 3 4 NR NR NR 4 5 4 NR NR NRSandstone--well cemented 3 3 5 NR NR 3 5 3 NR NR NRChert nodules 5 3 3 NR NR 3 3 5 NR NR NRLimestone 5 5 5 6 NR 5 5 5 NR NR NRLimestone with chert nodule 5 3 5 6 NR 3 3 5 NR NR NRLimestone with small cracks or 5 3 5 6 NR 2 5 5 NR NR NR fracturesLimestone, cavernous 5 3-1 2 5 NR 1 5 1 NR NR NRDolomite 5 5 5 6 NR 5 5 5 NR NR NRBasalts, thin layers 5 3 5 6 NR 3 5 5 NR NR NR sedimentary rocksBasalts--thick layers 3 3 4 5 NR 3 4 3 NR NR NRBasalts--highly fractured 3 1 3 3 NR 1 4 1 NR NR NR lost circulation zones)Metamorphic rocks 3 3 4 5 NR 3 4 3 NR NR NRGranite 3 3 5 5 NR 3 4 3 NR NR NR
Rate of penetration: 1 = impossible; 2 = difficult; 3 = slow; 4 = medium; 5 = rapid; 6 = very rapid.
aNR = not recommended. bAssuming sufficient hydrostatic pressure is available to contain active sand (under high confining pressures)
Source: [3]
NOTES
14It may or may not be safe to enter the excavation to obtain these samples due to the possibility of vapor
hazards or collapse of the excavation walls. If it is not safe to enter the excavation to obtain the sample with a
trowel or hand auger, these samples may be obtained from a backhoe bucket. Accuracy is improved by
disturbing the soil as little as possible so as to not cause the release of volatile contaminants.
1.4-54
petroleum hydrocarbons (TPH) and benzene, tolulene, ethylbenzene,
and total xylenes (BTEX). Sampling for methyl-tertiary butyl ether
(MTBE) may also be appropriate as it is quite soluble in water and
may be present at the leading edge of a migrating contaminant plume.
If the tank is being closed in place, the top of the tak should be
exposed. Three (3) samples should be taken, two in the area where the
tank and piping meet and the other at the oposite end of the tank (unless
exposing the top of the tank reveals other areas where leakage appears
likely. If the tank is being or has been removed, soil samples should
be taken one to two feet below the bottom of the excavation at likely
leak locations, and should be taken as soon as possible after the tank
is removed.14 These samples should be taken from the excavation (as
opposed to being taken from locations next to the excavation) for each
tank suspected to have leaked. Likely leak locations include: areas
around the tank and piping, or where they used to be; areas around the
tank or piping, or where they used to be, that look.
In completing each boring, take split-spoon samples starting at ground
surface and then at least every five feet thereafter until ground water
is encountered or until auger refusal. If a dissimilar layer of soil is
found to exist entirely between the five-foot sampling intervals, obtain
a sample from this layer. Sampling protocols are provided in
Attachment 1.4-4 to this section. A geologist should log each boring.
The components of a typical monitoring well are illustrated in Exhibit
1.4-20, and DEC specifications for installing monitoring wells are
listed in Exhibit 1.4-21. Two important considerations in well design
are (1) the chemical compatibility between the spilled material and the
well construction materials, and (2) the wettability and size of the well
screen.
Exhibit 1.4-22 shows the chemical compatibility between petroleum
products and certain types of well casings and screens.
Polyvinylchloride (PVC) screens are the mostly frequently used
because of the low cost of materials and installation. The probability
that a PVC screen will dissolve under field conditions is low, but will
depend upon the concentration of the petroleum product in the ground
water surrounding the well and the length of the
1.4-56
Exhibit 1.4-21
Specifications of Ground-Water Monitoring Wells
1.All wells are to have a nominal four (4) inch diameter.
2.Boring logs shall be recorded for each boring. Samples shall be taken from each soil layer
encountered or, at a maximum, at five (5) foot intervals to obtain a general description of the
underlying soils.
3.Wells must be installed plumb and straight.
4.Flush-threaded joints must be used to avoid contamination of well by glued joints.
5.Well screens must be machine slotted and of sufficient length and placement to accommodate
seasonal variations in the water table. (Length will generally be 10' to 15' with the mean water
table in the middle of the screen.)
6.The filter pack must be compatible with the soil around the screened portion of the well and with
the screen opening. It must extend approximately one foot below the screen and three-to-five feet
above the screen.
7.The well must be sealed with an impermeable material between the casing and the bore hole and
capped with concrete or other suitable material to prevent contamination from the surface.
8.The well must be sufficiently developed to ensure that samples will accurately represent the
condition of the ground water.
9.Survey well elevations to a known datum point.
10.The tops of the wells must be enclosed by a protective metal casing and locked.
11.All wells must be marked clearly as monitoring wells.
Source: NYSDEC TOGS 4.1.1 (1987)
1.4-57
Exhibit 1.4-22
Chemical Compatibility Between Selected Well Casing and Screen Materials
and Petroleum Products
Stainless Steel Cyoloc Polyvinylchloride316304440Bronze(ABS)Kynar Polypropylene PVC Teflon
Benzene B B B A D A C C A
Hexane A A A A -A B B A
Toluene A A A A D A C D A
Xylene A A A A D A C D A
Naptha A A A B D A C C A
Gasoline A A A A D A C C A
Turpentine A A B C -A B B A
Kerosene A A A A D A A A A
Jet Fuel A A A A -A A A A
Diesel Fuel A A -A -A A A A
Fuel Oils A A A A D A C A A
Lube Oil A A A A -A A B A
Creosols A A -C D A D D -
Asphalt A B B A -A B A A
A = No Effect B = Minor Effect C = Moderate Effect D = Severe Effect
Source: Cole Parmer (1987)
NOTES
15 Determining ground-water velocity requires conducting slug tests to estimate hydraulicconductivity, and physical soil tests to estimate porosity may be needed. Slug tests consist of asudden introduction of a known volume of water (or a cylinder of known volume) and thenmeasuring the time it takes for the water level in the well to stabilize. A bail test is similar excepta known volume of water is removed.
1.4-58
monitoring period. Stainless steel is better suited to more corrosive
environments for long-term monitoring, but is about three times more
costly than PVC. TeflonR is even more durable than stainless steel,
but its use is generally limited to severe conditions because of its
higher cost.
Wettability is a term used to describe the affinity of a liquid to a
solid surface. The relative wettabilities of water and the spilled
material to the well screen affects the amount of material entering the
well. Wettability may not be an important concern when the
released material is dissolved in ground water; on the other hand, if
the spilled material does not mix with water (e.g., petroleum), the
samples collected from the monitoring well may not adequately
represent the conditions of the area surrounding the well. Additional
guidance on well construction materials and design is provided in
Part 1, Section 6.7, Ground-Water Remediation.
Ground-water elevations are best determined by short-screened (one
to five feet) piezometers. More broadly screened ground-water
monitoring wells are used to determine gradient, but cannot be used
to determine the vertical components of the gradient. Well screens
must be machine slotted and of sufficient length and placement to
accommodate seasonal variations in the water table. Generally, the
screen will need to extend five feet above the high water table
elevation (i.e., the entire screen is ten to fifteen feet long) in order to
ensure that any floating product will flow freely into the well.
The actual placement of monitoring wells and the number required
are dependent on spill- and site-specific information. A minimum
of three wells is needed to establish ground-water flow direction.15
If the water table surface is irregular or the vertical components of
flow are significant, a minimum of four wells will be needed. At
least one well should be located hydraulically upgradient of the spill
source to establish background ground-water quality. A general
rule-of-thumb is that as the heterogeneity of the subsurface
environment increases, the number of wells should increase, and
their positioning should reflect what is known about the subsurface
geology. Typically, more wells will be placed on the downgradient
side of the spill source for potential contamination. Wells arranged
in the configuration of a rectangle or equilateral triangle improve the
chance that a well is positioned correctly to obtain a downgradient
sample.
NOTES
16 There are instruments that can measure water turbidity in water. A nephelometer is onesuch instrument that measures the amount of light transmitted through and reflected by particlesin a water sample. A nephelometric turbidity unit (N.T.U.) guideline of less than 5 units has beenapplied to judging the adequacy of well development activities.
1.4-59
In guidance issued on special ground-water protection conditions for
major onshore petroleum facilities, NYSDEC specifies these
monitoring well locational and design requirements:
#Major facilities (except those facilities or portions thereof
storing No. 6 fuel oil or heavier oils) shall install ground-
water monitoring wells outside of their secondary containment
systems. If it is impractical to install wells outside the
containment system, these wells may be installed inside or on
the dike walls if: (a) their wells casings extend at least three
feet above the ground (or to a height to prevent product from
entering the well in event of a spill); (b) the wells are sealed
to prevent product flow down around the casing in the event of
a spill; and (c) written approval from NYSDEC is obtained;
#At least one well must be installed hydraulically upgradient of
the facility to be representative of the ambient ground-water
quality in the uppermost aquifer only and not affected by the
facility; and
#At least three wells must be installed hydraulically
downgradient of the facility to detect ground-water
contamination in the uppermost aquifer only.
Well Development and Sampling
Each installed well must be developed; that is, the well must be
purged of drilling fluids and sediment that may have moved through
the filter pack and well screen. Otherwise, the presence of these
fluids and sediment may restrict the flow of water and product from
the aquifer materials into the well.
Well development is accomplished by cyclic removal of water from
the well using a pump or a bailer. Air-lift and diaphragm pumps are
used for well development when there is an expectation that sand
will be withdrawn with water; this sand would damage a centrifugal
pump. A surge block may also be used for well development. A rod
attached to the surge block is used to manipulate the block up and
down inside the well; this piston action forces water and sediment
back and forth through the screen and filter pack.
Development of the well continues until there is no sediment in the
removed water or until there seems to be no further improvement in
water quality. Make note of the well water levels, and the clarity,
color, and odor of the development water.16 The total volume of
NOTES
1.4-60
water and any product removed during development should be
recorded. Development water must be managed in compliance with
local, state, and federal regulations.
Before sampling a well (monitoring well or supply well), first
measure the water level and product level, if product is present. It
is then necessary to purge the well of the standing water in order to
obtain a "representative" ground-water sample. Usually, three to
five full volumes of standing well water will have to be purged, but
continue purging any well capable of a sustained yield until there is
10 percent or less variability in three consecutive measurements of
pH, temperature, and specific conductance. This is done by setting
the pump intake just beneath the water surface and pumping at a low
enough rate to keep the pump below the water surface. If a well is
not capable of producing a sustained yield, purge the well
completely and allow the water level to recover to 60 to 80 percent
of the original level before taking a sample. It will be necessary to
follow the water level down with the pump intake as the well is
purged.
There are different kinds of equipment available for use in purging
wells. The type of equipment is selected based upon the size of the
well casing and the depth of water in the well. Equipment
recommendations are provided in Exhibit 1.4-23. Avoid using air-
lift equipment if product is present in the well as free product and
vapor will be forced up the well -- this is a health and safety hazard.
When sampling a well, it is important to:
#Select sampling devices constructed of inert materials such as
stainless steel, non-flexible PVC, or Teflon (see Exhibit 1.4-
24);
#Place plastic sheeting around the wellhead so that sampling
equipment does not come into contact with the soil or drilling
fluids;
#Measure and record the water level and free product thickness,
if product is present, to the nearest 0.01 foot;
1.4-61
Exhibit 1.4-23
Recommended Purging Equipment
Submersible
Diaphragm Submersible Submersible Electric
Diameter Peristaltic Vacuum “Trash” Diaphragm Electric Pump Casing Bailer Pump Pump Airlift Pump Pump Pump with Packer
1.25 inchWater level<25 ft X X X XWater level>25 ft X
2-inchWater level<25 ft X X X X X XWater level>25 ft X X X
4-inchWater level<25 ft X X X X X X X XWater level>25 ft X X X X X
6-inchWater level<25 ft X X X XWater level>25 ft X X X
8-inchWater level<25 ft X X X XWater level>25 ft X X X
Source: [4]
1.4-62
Exhibit 1.4-24
Advantages and Disadvantages of Different
Ground-Water Sample Collection Methods
Category Method Advantages Disadvantages
Down-HoleCollectionDevices
Methods in this category offer a greaterpotential to preserve sample integritythan many other methods becausepressure differences are not used tocollect sample.
Most devices in this category areunsuitable for purging because theyprovide only small, volumes of water. Thisproblem can be avoided by using anothermethod, which may be disruptive, to purgethe well prior to using the down-holecollection device for sampling.
Bailers Inexpensive to purchase or fabricate andeconomical to operate. This may permitthe assignment of one collection devicefor each installation to be sampled,thereby circumventing problems ofcross-contamination.
Very simple to operate and requires nospecial skills.
Easily cleaned, though cleaning of ropesand/or cables may be more difficult.
Can be made of inert materials.
Very portable, and requires no powersource.
Usually very time consuming when usedfor purging installations, especially whenthe device has to be lowered to greatdepths. It can also be very physicallydemanding on the operator when thedevice is lowered and raised by hand.
Can cause chemical alterations due todegassing, volatilization, or atmosphericinvasion when transferring the sample tothe storage container.
MechanicalDepth-SpecificSamplers
Inexpensive to construct.
Very portable and requires no powersource.
Stratified sampler is well suited forsampling distinct layers of immisciblefluids.
Can be made of inert materials.
Stratified sampler is easily cleaned.
Some of the materials used can causecontamination (e.g., rubber stoppers).
Activating mechanism can be prone tomalfunctions.
May be difficult to operate at great depths.
Can cause chemical alternations whentransferring sample to storage container.
Difficult to transfer sample to storagecontainer.
Kemmerer sampler is difficult to cleanthoroughly.
PneumaticDepth-SpecificSamplers
Can be made of inert materials.
Easily portable, and requires only a smallpower source (e.g., hand pump).
Solinst sampler and Syringe sampler canbe flushed down-hole with the water to besampled
Syringe of the syringe sampler can beused as a short-term storage container.
Syringe sampler is very inexpensive.
Types that are commercially available aremoderately expensive.
Westbay sampler is only compatible withthe Westbay casing system.
Solinst and Westbay samplers are difficultto clean.
Materials used in disposable syringes ofsyringe samplers can contaminate thewater.
Water sample comes in contact withpressurizing gas in Solinst and Westbaysamplers (but not in syringe samplers). Source: [5].
1.4-63
Exhibit 1.4-24Advantages and Disadvantages of DifferentGround-Water Sample Collection Methods(continued)
Category Method Advantages Disadvantages
Suction-LiftMethods Simple, convenient to operate, and easilyportable.
Inexpensive to purchase and to operate.
Easily cleaned.
Components can be of inert materials.
Depending on the pumping mechanism,these methods can be very efficient forremoving standing water from thesampling installations.
Provides a continuous and variable flow-rate.
Limited to situations where the water levelis less than 7-8 m (23-26 feet) belowground surface.
Can cause sample bias as a result ofdegassing and atmosphericcontamination, especially if the sample istaken from an in-line vacuum flask.
Can cause contamination if water isallowed to touch pump components.
Positive-DisplacementMethods
Methods in this category offer reducedpossibility of degassing and volatilizationbecause the sample is delivered toground surface under positive pressure. In some situations, the pressure atground surface may be substantially lessthan the natural water pressure in theformation and thus the degassingproblem cannot be ignored entirely.
Sample does not contact theatmosphere.
Sampling pumps for use in monitoringwells as small as 3.8-5 cm (1.5-2 in) arecommercially available.
Most of the commercially availabledevices have a sufficient flow rate forpurging wells.
Cost of the commercially available pumpsused in these methods is substantial(roughly $2,000 to $5,000). It wouldtherefore not be feasible to dedicate asampling pump to each sampling point.
Can be difficult to clean between samplingsessions.
Cleaning of cables and/or delivery tubingis required between sampling points.
Commercially available devices are toolarge for very small-diameter wells suchas the bundle piezometers.
SubmersibleCentrifugalPumps
Can pump at large and variable flowrates.
Johnson-Keck pumps can fit down wellsas small as 5 cm (2 in).
Johnson-Keck pump is easily portable.
Conventional pumps are usually muchcheaper than the Johnson-Keck pump.
Johnson-Keck pump offers little potentialfor sample contamination because it ismade mostly of stainless steel andTeflon.
Subject to excessive wear in abrasive orcorrosive waters.
Conventional submersible pumps cannotbe used in wells with diameters less thanabout 12 cm (4 in).
Potential for contaminating water becauseof contact with metals and lubricants isgreater in conventional pumps.
Johnson-Keck pump has intermittent flow(15 min on, 15 min off).
Source: [5].
1.4-64
Exhibit 1.4-24Advantages and Disadvantages of DifferentGround-Water Sample Collection Methods(continued)
Category Method Advantages Disadvantages
SubmersiblePistonPumps
Gas-drive piston pumps havesmall power requirements.
Gas-drive piston pump ofGillham and Johnson (1981) isinexpensive and can beassigned permanently tosampling point, therebyeliminating problems of cross-contamination.
Double-acting pumps havecontinuous adjustable flowrates.
Can be built of inertmaterials (most commerciallyavailable pumps are not,however).
Rod pumps require large powersource and are permanentlymounted.
Difficult to clean.
When used as part of a well,the gas drive pump of Gillhamand Johnson (1981) cannot beretrieved for servicing orrepair.
Single-acting pumps haveintermittent flow.
Gas SqueezePumps Can be built of inertmaterials.
Commercially available pumpscan fit in wells as small as 5cm (2 in).
Can easily be taken apart forcleaning.
Intermittent, but adjustableflow.
Requires large, but portable,power source.
Can be inconvenient to cleanbetween sampling sessions.
Gas-LiftMethods Simple to construct or areavailable commercially atrelatively low cost.
Can be used in very narrowwells.
Can be easily portable.
Easily cleaned.
Can only be used efficientlywhen roughly one-third of theunderground portion of thedevice is submerged.
Contamination of the samplewith the driving gas,atmospheric contamination, anddegassing are all unavoidable.
Needs large power source(gas).
Gas-DriveMethods Offers good potential forpreserving sample integritybecause (1) very little of thedriving gas comes in contactwith the water sample, and (2)the sample is driven by agradient of positive pressure.
Can be incorporated as part ofthe sampling installation,thereby removing thepossibility of cross-contamination.
The triple-tube sampler iswell suited for wells of verynarrow diameter (e.g., 0.95 cm[3/8 in]) where the only otherpossible sampling method isnarrow-tube bailers, orsuction-lift (whenapplicable).Inert materials can be used.
Not very efficient for purgingwells larger than about 2.5 cm(1 in).
Can be difficult to cleanbetween sampling sessions.
Because the driving gas comesin contact with the water, thebeginning and the end of theslug of water obtained at thesurface can be contaminated.
When used as part of apermanent samplinginstallation, they cannot beretrieved for repair orservicing.
Pumps intermittently and at avariable flow rate.
Source: [5].
1.4-65
Exhibit 1.4-24Advantages and Disadvantages of DifferentGround-Water Sample Collection Methods(continued)
Category Method Advantages Disadvantages
Jet Pumps Can be used at great depths.
Useful for purging monitoring wells.
Uses circulating water which mixes withthe pumped water. A large amount ofwater needs to be pumped before thecirculating water has a composition that isclose to the water in the installation.
The water entering the verturi assembly issubjected to a pressure drop (which maybe large), and can therefore undergodegassing and/or volatilization.
The circulating pump at the surface cancontaminate the pumped water because ofits materials and lubricants.
DestructiveSamplingMethods
Can provide very useful information in thereconnaissance surveys and in otherspecific field situations.
Most of the techniques are used duringthe drilling operation and will not interferewith the construction of a permanent well.
Coring-extraction methods are the onlyconvenient means of obtaining severalparameters related to both the liquid andsoil phases (e.g., exchangeable cations,total microbial population, samples of theformation, etc.), and also, for certainsituations they may be the least bias-inducing method (e.g., in very fine-grained formations).
Temporary wells can, in some situations,be the most cost-effective way ofobtaining preliminary and/orreconnaissance data.
Because no permanent well is left in theground, these methods cannot be used formonitoring long-term trends in waterquality. In most cases, however, they donot interfere with the construction ofpermanent wells.
Can result in large drilling costs.
Water contained in cores can becontaminated with drilling fluids and canundergo degassing and volatilization at theground surface.
Source: [5].
NOTES
1.4-66
#Use a sampling technique suited to the contaminants of interest
(e.g., do not use methods or pump at a rate that would liberate
volatiles, if you are sampling for volatiles; and
#Discard the first few volumes of water withdrawn from the
well before taking a sample.
Do not collect water samples for dissolved contaminant analysis
from any well where free product is present.
5. Determining the Extent of Structural Contamination
Both surface and subsurface spills can contaminate structures, including
buildings, sewer lines, water mains, machinery equipment, or any other physical
man-made features of the site. You may determine the extent of structural
contamination through a visual inspection or sampling survey.
A visual inspection can identify gross contamination such as apparent free
product pools or stained surfaces. Rafters, ventilation ducts, sumps, crawl
spaces, window wells, and the like should be inspected for visual evidence of
deterioration (e.g., as a result of strong chemical reactions) as well as for
chemical residues.
Sampling surveys may identify contamination not apparent during visual
inspections. A sampling survey can be as simple as using air monitoring
instruments (e.g., HNu meters or organic vapor analyzer) to detect organic
vapors or can involve taking samples from the surface of the structure. There are
two basic techniques for sampling contamination on structural or equipment
surfaces: wet-wipe and dry-wipe. With wet-wipe techniques water or some
other solvent is used to extract material off the contaminated structural surface
when it is wiped with a Q-tip or filter paper disk, whereas with dry-wipe
techniques no solvent is used.
6. Documenting the Site Investigation
You must keep some sort of a chronological record of your site investigation
activities for each spill whether it is a personal field logbook or completed Job
Inspection Reports (see Part 4, Section 1, Case Documentation). Do not hesitate
to record comments on the information you collect, but make sure facts are
always distinguished from guesses or estimations. Do not record personal
comments that could be regarded as offensive or make allegations in your field
notes. Remember that these notes become part of the official case file, and as
such, may be subject to legal scrutiny. It is, therefore, best to restrict your entries
to observations of fact.
Include the following information/illustrations in the spill case records:
NOTES
1.4-67
#A simple site and vicinity map (see Attachment 1.4-2 or develop
your own);
#Dates and times of activities and findings;
#Names and titles of principal people involved in a specific event;
#Source(s) of information;
#Photographs of site conditions; and
#Other unusual or noteworthy events you feel are important.
Again, the worksheets provided as an attachment to this section may be useful for
organizing the information collected in a site investigation. Exhibit 1.4-25
summarizes additional recordkeeping guidelines.
The information contained in this chronological record will help you prepare the
Investigative Summary Report (ISR), which is the official document of your
findings from the investigations. Step-by-step guidance on preparing the ISR are
provided in Part 4, Section 1, Case Documentation.
7. Site Restoration
Almost every spill investigation/cleanup will involve disturbing the site area in
some way. How much time, effort, and money you should invest in restoring a
site will depend on a number of factors, that is, your decision will vary by site
and circumstance. The following, however, are some general guidelines for
making that decision. Additional questions should be directed to your RSE or
to Central Office staff.
1.First, make sure the affected parties understand what you intend to do and
the possible consequences of those actions before you start any spill
investigation/cleanup.
2.In cases of a suspected leaking tank, explain to the owner that you may:
--Test the tank system, and if the system tests tight and there is no other
evidence of a problem, the site will be restored by NYSDEC;
--Test the tank system, and if the system is found to be leaking, you
will remove the tanks and contaminated soil; possibly install
monitoring wells and recovery system; and will restore the site to a
safe condition only. NYSDEC will not install new tanks, hook up
tanks, replace a leaking tank, repave an area, or rebuild the pump
islands.
NOTES
1.4-68
3.Explain that due care will be exercised to minimize the impact of the
investigation/cleanup work, but that this work has to be done to protect the
environment/public health. (In some cases this will give the owner added
incentive to clean up the spill himself or herself.)
4.When dealing with other parties affected by the spill, but not the cause of
the spill, you should explain that you will restore the site to as close as
possible to the original conditions, but that you are not authorized to do
additional work. For example, if you remove part of a gravel driveway,
you will replace it with a gravel driveway, not a black-top driveway.
1.4-69
Exhibit 1.4-25
Suggested Recordkeeping Practices Checklist
for Spill Investigations
#Fill out Spill Report Form with information received from caller.
#Phone parties with information on spill and record contacts (e.g., spiller, witnesses, other
agency personnel).
#Record information gained in initial visit to spill site, including date and time of visit, your
observations, statements by witnesses, statements by alleged spiller, actions taken, etc. Use Job
Inspection Form or keep log book.
--add brief summary to Spill Report Form
--attach additional notes/reports to Spill Report Form
--attach media reports or reports from other agencies
--stick to factual events; no allegations or personal comments.
#Make a more detailed report on spill if subsequent visits to site are necessary. Cover
chronological events.
--include names and titles of principals involved in spill
--state if and when samples, measurements, etc., where taken
--include dates and times (if possible) of events such as contractor call-out or when
alleged spiller was directed to start clean up
--include any other information you deem important
--include maps and refer to them in reports.
#Take all samples in accordance with approved procedures and follow quality assurance/quality
control guidelines.
--record time, date, and location of samples taken
#Take pictures of site features, path of spill (if evident), source of spill, free product (if evident),
sampling locations.
--number and date all pictures and indicate location and direction of picture taken on
reverse side.
1.4-70
REFERENCES
1.Freeze, R.A. and Cherry, J.A. Ground Water, Prentice-Hall, Inc. Englewood Cliffs, NJ, 1979.
2.American Petroleum Institute. Underground Spill Cleanup Manual. API Publication 1628. June
1980.
3.Dricoll, F.G. Ground Water and Wells. 2nd Edition. Johnson Division, St. Paul, MN. 1986.
4.California Leaking Underground Fuel Tank Field Manual: Guidelines for Site Assessment,
Cleanup, and Underground Storage Tank Closure. May 1988.
5.American Petroleum Institute. Advantages and Disadvantages of Ground-Water Sample
Collection Methods. API Publication 4367.
6.Emergency Action Guides. Association of American Railroads. Washington, D.C. 1987.
1.4-71
ATTACHMENT 1.4-1
CHEMICAL COMPOSITION OF GASOLINE
AND SELECTION OF INDICATOR CHEMICALS FOR ANALYSIS
1.4-72
The following material was extracted from "The Appropriateness of Benzene as an Indicator Chemical
for Leaking UST Sites" (March 1987), prepared for the U.S. EPA's Office of Underground Storage
Tanks by Camp, Dresser, and McKee, Inc. Exhibit 1.4-26 on the chemical Composition was taken from
the California Leaking Underground Fuel Tank Manual: Guidelines for Site Assessment, Cleanup and
Underground Storage Tank Closure (May 1988).
1.4-73
Chemical Composition of Gasoline
Gasoline is a colorless blend of volatile liquid-petroleum fractions. A typical blend of gasoline will
contain several hundred hydrocarbons. In addition, gasoline additives are blended into gasoline to
function as anti-knock agents, anti-oxidants and sweetening inhibitors, metal deactivators, corrosion
inhibitors, deicing and anti-stall agents, preignition preventors, dyes, and upper cylinder lubricants.
Aromatics are known to be the most toxic constituents in gasoline, although the toxicity of many of the
additives--which are found in significantly smaller concentrations than the aromatics--is unknown. It
is virtually impossible to create a detailed and specific breakdown of the chemicals in gasoline in
general and of the additives in particular. The composition of gasoline varies in terms of the crude oil
from which it was produced and with seasonal operating requirements. Product composition may
change daily depending on refinery operations. Product additives can be changed seasonally to
accommodate temperature changes. The lucrative market for effective chemical additives generates
numerous new additive formulations each year. Moreover, because most additives are patented, their
chemical formulations and uses in specific products are often considered proprietary. See also Exhibit
1.4-26.
1. Chemicals of Possible Concern Other Than Benzene, Toluene, and Xylene (BTX)
There are some 241 chemicals in petroleum products, of which nine constituents of gasoline are
regulated under CERCLA as hazardous substances (including benzene, toluene, and xylene). In
addition, there are four chemicals used as gasoline additives that are regulated under CERCLA.
These 13 chemicals, which are currently known to be in gasoline and regulated under CERCLA,
are listed in Exhibit 1.4-27.
The toxicities of these 13 compounds are also shown in Exhibit 1.4-27 based on final toxicity
Reportable Quantity (RQ) categories assigned to each chemical under CERCLA. An RQ is that
quantity of a substance which, if released, triggers a requirement to report that release. An RQ
value reflects EPA's subjective judgment of which substances are the most hazardous. The
lower the RQ value, the more toxic the substance. Various measures of toxicity have been
established in other fields such as industrial hygiene and safety, cancer research, and wildlife
conservation. However, these measures of toxicity are not necessarily equivalent to one another,
or directly comparable. They do provide a relative benchmark for determining the principal
chemicals of concern (albeit for different reasons) to protect public health and the environment.
Based on the RQ values contained in Exhibit 1.4-27, there are eight chemicals besides benzene,
toluene, o-xylene, m-xylene, and p-xylene that might be of concern because of their toxicity:
#ethylbenzene
#naphthalene
#phenol
#ethylene dibromide (EDB)
#ethylene dichloride (EDC)
#tetraethyl lead (TEL)
#dimethylamine
#cyclohexane
To evaluate the relative health threats posed by these eight substances certain other factors are
considered:
1.4-74
#The percentage by volume and weight of each substance in gasoline;
#The percentage of gasolines that contain each substance; (i.e., its prevalence in the
marketplace);
#The ease with which the substances move into the environment (mobility, fate, and
transport);
2. Presence in Gasoline Products
Exhibit 1.4-27 includes data that address these factors for the 13 chemicals identified as
hazardous substances. Data gaps exist, especially with regard to percentages by volume in
gasoline and the percentage of gasolines that contain these compounds. We have attempted to
fill in the data gaps, but, in some cases, the information is not necessarily reliable. A rating that
reflects the confidence we have in the composition data is also included on Exhibit 1.4-27. A
brief discussion of each compound is presented below.
Ethylbenzene
Ethylbenzene makes up a significant part of the aromatic portion of gasoline (up to 4.6% by
volume). It is a colorless liquid used in both petroleum refining and the organic chemical
industry.
EDB
Of the eight chemicals, EDB is one of the two pure products that are potential carcinogens. EDB
is an additive, which has been found in concentrations of 177 ppm, 1.9 ppm, and 0.7 ppm for
regular, unleaded, and super unleaded gasolines, respectively. It makes up 0.024 percent of
gasoline by weight. What percentage of gasolines contain EDB is not precisely known, but it
is estimated that less than 40 percent contain this chemical; that percentage is expected to decline
as the use of lead in gasoline is phased out. EDB has also been widely used as an agricultural
fumigant, which has led some to question the value of EDB as a reliable indicator of gasoline
contamination, especially in agricultural areas.
EDC
EDC, another additive, is the other chemical that is a potential carcinogen. The exact percentage
of EDC in gasoline, by weight, is not known, but it has been estimated to be less than the
percentage, by weight, of EDB found in gasoline. It is not known what percentage of gasolines
contain EDC, but, again, estimates are that less than 40 percent contain this chemical, and the
percentage is likely to decline as the use of lead in gasoline is phased out.
Tetraethyl Lead
TEL is an additive that is being phased out per government order. Again, it is not known what
percentage of gasolines contain TEL, but it is believed that less than 40 percent contain TEL; its
use will decrease in the future. TEL does not readily partition into air or water. Rather, it has
a strong affinity for soils and, in those rare instances when it is detected, it is typically found at
or very near the spill source.
Naphthalene
1.4-75
Naphthalene is another chemical that does not move in the environment very easily. It is found
in as much as 90 percent of gasolines being marketed today, accounting for less than 0.1 percent
of the weight of gasoline.
Phenol
Phenol is known to biodegrade quickly into a less toxic compound. It is found in more than 90
percent of the gasolines being marketed today.
Dimethylamine
Few data were found on dimethylamine. Dimethylamine is one of the most soluble additives in
gasoline.
Cyclohexane
Cyclohexane is another colorless component of gasoline. It makes up 0.17 percent of the weight
of gasoline.
3. Fate and Transport
There are two types of fate mechanisms by which chemicals are transported or transformed.
Physical processes, which include solubility, vaporization, and adsorption, transfer the
substances across media/phase interfaces. Kinetic processes, which include biotic and abiotic
chemical transformations, decrease the concentration of a chemical by degrading it into other
products. How a chemical is affected by fate mechanisms depends on a number of specific
chemical and environmental factors. Exhibit 1.4-27 lists the solubilities, vapor pressures, and
adsorption coefficients that were available for the 13 chemicals that are regulated under
CERCLA and also are found in gasoline.
Of the eight chemicals of concern, four are more soluble than benzene:
Compound Times more soluble than benzene
EDB 2 times
EDC 4 times
Phenol 37 times
Dimethylamine 560 times
Only ethylbenzene is as volatile as benzene, toluene, or xylene.
Given that these chemicals move into air and water more easily than BTX, one would expect to
find these even when BTX is not detected; but this is not necessarily the case. The likelihood
of detecting a particular contaminant is more a function of its original concentration in gasoline
as well as the extent to which it's used in a gasoline product.
For example, BTX is used in almost every gasoline, and can be detected in significant
concentrations. One would expect to find BTX at almost every leaking gasoline UST site where
free product exists.
1.4-76
On the other hand, EDB, which makes up only 0.02 percent of gasoline and is not used in every
gasoline, would be found in significantly lower concentrations than benzene (or toluene or
xylene). This does not mean that EDB will never be detected. EDB has been detected in wells
in the vicinity of known gasoline releases in Florida and Maine, among other states. It is
unclear, however, whether and to what extent the detected EDB originates from gasoline or from
agricultural fumigants. Sampling for a wide range of compounds in the low parts per billion
range could lead to a number of "false positives."
In focusing efforts on cleaning up BTX--which make up a considerably larger portion of gasoline
and are found in much greater concentrations than any of the additives--the most significant
public health and environmental concerns are being addressed. What remains are low levels
of BTX and some of the additives. The health hazard posed by low level concentrations of these
additives is unknown.
4. Measurement of Benzene and Other Hydrocarbons in Aged Plumes
Benzene is the gasoline constituent most often used to determine the extent of a leaking UST
problem. Benzene is relatively volatile and soluble, so that it can usually be detected in both
air and water. Toluene and xylene are sometimes used in conjunction with benzene to make
these determinations. However, relying on measurements of benzene alone to provide an
accurate characterization of the extent of a problem and the hazard it represents could lead to
incorrect assumptions about where and how concentrated the plume is (and consequently, where
the focus of corrective actions should be) especially with regard to aged plumes.
a. Monitoring Soil Gases in Aged Plumes
Soil gas monitoring can be used to determine the extent of dissolved plumes resulting
from a gasoline release. The atmosphere above the ground acts as a sink while the
free and/or dissolved portion of the gasoline spill acts as a source of volatile
organics. Thus, a situation arises where volatile organics can move up through the
unsaturated zone. Measuring the concentrations of diffusing volatile organics in
shallow soil gas can provide an estimate of the direction, extent, and chemical
composition of an underground gasoline plume. Most of the major volatile
constituents found in gasoline can be successfully measured with this technique.
Measuring benzene in soil gas can -- in certain instances -- be used to determine the
extent of the gasoline plume. However, because of benzene's volatility, solubility,
and biodegradability, the results of soil gas monitoring for benzene will not be
reliable if the sampling is not undertaken close to the source, or if the gasoline plume
is significantly "weathered" (i.e., aged). If the plume has aged significantly, or has
migrated from the source, chances are that significant amounts of benzene and other
volatile organics have evaporated into the air or dissolved in the water, and what
benzene remains in the soil gas is at such low concentrations that the remote vapor
sensing equipment may not detect its presence. Therefore, to ensure more reliable
determinations of the extent of a plume, groups of volatile organics should be
measured, either as BTX or total volatile organics or total petroleum hydrocarbons,
instead of just benzene (or any one specific volatile compound for that matter).
b. Monitoring Water Quality in Aged Plumes
1.4-77
Water quality samples taken from an aged plume are also likely to show different
constituents than samples taken from a plume from a "newer" spill because different
components of gasoline are adsorbed, hydrolized, biodegraded, and volatilized at
different rates.
Studies of time for several gasoline constituents to biotransform in ground water
under aerobic conditions has shown that after 124 days, significant amounts of five
of the gasoline constituents of concern can be more or less removed or transformed.
Virtually, all of the mass of BTX that was injected was biodegraded after 434 days.
These findings suggest that a spill that has been in the ground as long as six months
can undergo significant chemical transformations. A conservative assumption is that
a gasoline plume that has been in the ground longer than 2 years can be
considered an "aged" plume.
It is possible that if a plume had been in the ground long enough, and all the free
product had been removed, then no benzene, toluene, or xylene would be detected.
If that were the case, and water quality samples showed no BTX to be present, a
conclusion might be drawn that no release occurred. To avoid this misinterpretation,
the analysis might focus on other constituents in gasoline that are more persistent than
BTX or the alcohols. It is difficult, however, to find constituents that do not
biodegrade or volatilize or hydrolize to some degree.
The best indicator chemicals for aged plumes are refractory compounds that have high
molecular weight. The more complex hydrocarbons (such as those associated with
No. 2 and No. 6 fuel oils) are likely to be present to some degree after long periods
of time. C22 compounds would take considerable time to break down (see Exhibit
1.4-28 at the end of this attachment). Other persistent chemicals, such as tetraethyl
lead, which are not highly soluble or volatile, might be found in trace amounts close
to the spill source. Because these compounds are not used in all fuels, they may not
be detected at all locations.
Ground water beneath the floating product plume is enriched with ethylbenzene,
benzene, toluene, and xylene. The more soluble compounds dissolve in ground water
and disperse. One of the most soluble compounds in gasoline is methyl-tertiary butyl
ether (MTBE).
MTBE is becoming one of the more popular octane-enhancing additives used by the
gasoline companies, now that the use of tetraethyl lead is being phased out.
Commercially produced beginning only in 1979, MTBE is now among the top 50
chemicals produced in the United States. It is used in only about 10 percent of the
gasolines produced today. Its percentage in gasoline, by weight, is not known, nor
is the degree of health threat posed by low level concentrations of MTBE. It is an
irritant, like many other chemicals found in gasoline. It may be a nervous system
depressant. It is up to 24 times more soluble than benzene.
Because it is one the most soluble compounds in gasoline, MTBE may be the only
contaminant whose concentration exceeds the detection limit over large areas of the
plume, especially at the edges of the plume. MTBE plumes are believed to occur as
"haloes" around gasoline plumes. Thus, it is possible that a part of the plume might
go undetected if benzene alone were used as the sole indicator compound. Sampling
1.4-78
for MTBE along with benzene might allow for a more accurate delineation of the
gasoline plume, and more importantly, its direction and the extent of migration, if the
plume source happened to be one of the 10 percent of gasolines that contain MTBE.
5. Analytical Measurement of Chemicals of Concern
Exhibit 1.4-27 presents the analytical method used for analyzing each constituent. There are two
basic types of analysis: purge and trap gas chromatography (GC), which determines presence,
and gas chromatography/mass spectrometry (GC/MS), which provides quantitative
concentrations. A brief discussion of each follows:
Method 601 is a purge and trap gas chromatographic method used to determine the presence of
29 halocarbons. It can be used to detect EDB and EDC. Method 624 provides GC/MS
conditions appropriate for the qualitative and quantitative confirmation of results.
Method 602 is a purge and trap gas chromatographic method used to determine the presence of
various purgeable aromatics, including benzene, toluene, xylene, and ethylbenzene. Method 624
provides GC/MS conditions appropriate for the qualitative and quantitative confirmation of
results.
Method 604 is a GC method used to determine the presence of phenols and certain substituted
phenols. Method 625 provides GC/MS conditions appropriate for the quantitative confirmation
of results.
Method 607 is a GC method used to determine the presence of nitrosamines. A modified method
607 can be used to determine the presence of dimethylamine. Method 625 provides GC/MS
conditions appropriate for the qualitative and quantitative confirmation of results.
Method 610 is a GC method used to determine the presence of certain polynuclear aromatic
hydrocarbons, including naphthalene. Methods 625 provides GC/MS conditions appropriate for
the qualitative and quantitative confirmation of results.
Method 624 can be used to quantitatively and qualitatively confirm the presence of (benzene,
toluene, o-, m-, p-xylene, ethylbenzene, EDB, EDC, and cyclohexane) nine of the 13 compounds
(volatile components).
Method 625 can be used to confirm three of the 13 compounds shown in Exhibit 1.4-27.
1.4-79
Exhibit 1.4-26
Physical/Chemical Data for Gasoline
Physical Description:A volatile colorless to amber or pale brown liquid, which may also be dyed
various colors.
Chemical Description:A complex mixture of hydrocarbons, averaging five to ten carbon atoms per
molecule.
Virgin gasoline usually contains:
#Around 50 percent alkanes (paraffins)
#Around 40 percent cyclic alkanes (naphthenes)
#Around 10 percent aromatics.
Blended gasolines are mixtures of virgin gasoline, catalytically cracked
gasoline, and thermally reformed gasolines, and may contain up to 30
percent alkenes (olefins).
Constants:Flash point:-38oF to -50o (-38.9 to 45.6oC) closed cup.
Density: 0.66 to 0.70
Auto-ignition temperature:minimum of 536oF (280oC); maximum of
853oF 456oC); varies with grade
Vapor density:3 to 4 times that of air. Vapors may travel a
considerable distance to a source of ignition and flash
back. Vapors may persist in pits, hollows, and
depressions.
Flammability limits of vapor in air:
Upper:7.1-7.6 percent
Lower:1.2-1.4 percent
Viscosity: Slightly less than water
Average boiling range: 140-390oF (60-99oC) at 1 atmosphere.
Source: [6].
1.4-81
Exhibit 1.4-28
Chemical Composition of Gasoline
Concentration
Number of (Percent by
Compound Carbons Weight) (a)Reference
Straight Chain Alkanes
Propane 3 0.01 - 0.14 8,10
n-Butane 4 3.93 - 4.70 8,10,11
n-Pentane 5 5.75 - 10.92 8,10,11
n-Hexane (b) 6 0.24 - 3.50 8,10,11
n-Heptane 7 0.31 - 1.96 10,11
n-Octane 8 0.36 - 1.43 10
n-Nonane 9 0.07 - 0.83 10
n-Decane 10 0.04 - 0.50 10
n-Undecane 11 0.05 - 0.22 10
n-dodecane 12 0.04 - 0.09 10
Branched Alkanes
Isobutane 4 0.12 - 0.37 8,10
2,2-Dimethylbutane 6 0.17 - 0.84 10
2,3-Dimethylbutane 6 0.59 - 1.55 8,10,11
2,2,3-Trimethylbutane 7 0.01 - 0.04 10
Neopentane 5 0.02 - 0.05 10
Isopentane 5 6.07 - 10.17 8,10,11
2-Methylpentane 6 2.91 - 3.85 8,10,11
3-Methylpentane 6 2.4 (vol)8,10,11
2,4-Dimethylpentane 7 0.23 - 1.71 8,10,11
2,3-Dimethylpentane 7 0.32 - 4.17 8,10,11
3,3-Dimethylpentane 7 0.02 - 0.03 10
2,2,3-Trimethylpentane 8 0.09 - 0.23 10,11
2,2,4-Trimethylpentane 8 0.32 - 4.58 8,10
2,3,3-Trimethylpentane 8 0.05 - 2.28 10
2,3,4-Trimethylpentane 8 0.11 -2 .80 10,11
2,4-Dimethyl-3-ethylpentane 9 0.03 - 0.07 10
2-Methylhexane 7 0.36 - 1.48 10
3-Methylhexane 7 0.30 - 1.77 10,11
2,4-Dimethylhexane 8 0.34 - 0.82 10
2,5-Dimethylhexane 8 0.24 - 0.52 10
3,4-Dimethylhexane 8 0.16 - 0.37 10
3-Ethylhexane 8 0.01 10
2-Methyl-3-ethylhexane 9 0.04 - 0.13 10
2,2,4-Trimethylhexane 9 0.11 - 0.18 10
2,2,5-Trimethylhexane 9 0.17 - 5.89 10
1.4-82
Exhibit 1.4-28
Chemical Composition of Gasoline
(continued)
Concentration
Number of (Percent by
Compound Carbons Weight) (a)Reference
2,3,3-Trimethylhexane 9 0.05 - 0.12 10
2,3,5-Trimethylhexane 9 0.05 - 1.09 10
2,4,4-Trimethylhexane 9 0.02 - 0.16 10
2-Methylheptane 8 0.48 - 1.05 10
3-Methylheptane 8 0.63 - 1.54 10
4-Methylheptane 8 0.22 - 0.52 10
2,2-Dimethylheptane 9 0.01 - 0.08 10
2,3-Dimethylheptane 9 0.13 - 0.51 10
2,6-Dimethylheptane 9 0.07 - 0.23 10
3,3-Dimethylheptane 9 0.01 - 0.08 10
3,4-Dimethylheptane 9 0.07 - 0.33 10
2,2,4-Trimethylheptane 10 0.12 - 1.70 10
3,3,5-Trimethylheptane 10 0.02 - 0.06 10
3-Ethylheptane 10 0.02 - 0.16 10
2-Methyloctane 9 0.14 - 0.62 10
3-Methyloctane 9 0.34 - 0.85 10
4-Methyloctane 9 0.11 - 0.55 10
2,6-Dimethyloctane 10 0.06 - 0.12 10
2-Methylnonane 10 0.06 - 0.41 10
3-Methylnonane 10 0.06 - 0.32 10
4-Methylnonane 10 0.04 - 0.26 10
Cycloalkanes
Cyclopentane 5 0.19 - 0.58 8,10
Methylcyclopentane 6 Not quantified 8
1-Methyl-cis-2-ethylcyclopentane 8 0.06 - 0.11 10
1-Methyl-trans-3-ethylcyclopentane 8 0.06 - 0.12 10
1-Cis-2-dimethylcyclopentane 7 0.07 - 0.13 10
1-Trans-2-dimethylcyclopentane 7 0.06 - 0.20 10
1,1,2-trimethylcyclopentane 8 0.06 - 0.11 10
1-Trans-2-cis-3-trimethylcyclopentane 8 0.01 - 0.25 10
1-Trans-2-cis-4-trimethylcyclopentane 8 0.03 - 0.16 10
Ethylcyclopentane 7 0.14 - 0.21 10
n-Propylcyclopentane 8 0.01 - 0.06 10
Isopropylcyclopentane 8 0.01 - 0.02 10
1-Trans-3-dimethylcyclohexane 8 0.05 - 0.12 10
Ethylcyclohexane 8 0.17 - 0.42 10
Exhibit 1.4-28
1.4-83
Chemical Composition of Gasoline
(continued)
Concentration
Number of (Percent by
Compound Carbons Weight) (a)Reference
Straight Chain Alkenes
cis-2-butene 4 0.13 - 0.17 10
trans-2-butene 4 0.16 - 0.20 10
Pentene-1 5 0.33 - 0.45 10
cis-2-pentene 5 0.43 - 0.67 8,10
trans-2-pentene 5 0.52 - 0.90 10,11
cis-2-hexene 6 0.15 - 0.24 10
trans-2-hexene 6 0.18 - 0.36 10
cis-3-hexene 6 0.11 - 0.13 10
trans-3-hexene 6 0.12 - 0.15 10
cis-3-heptene 7 0.14 - 0.17 10,11
trans-2-heptene 7 0.06 - 0.10 10
Branched Alkenes
2-Methyl-1-butene 5 0.22 - 0.66 8,10,11
3-Methyl-1-butene 5 0.08 - 0.12 10
2-Methyl-2-butene 5 0.86 - 1.28 8,10,11
2,3-Dimethyl-1-butene 6 0.08 - 0.10 10
2-Methyl-1-pentene 6 0.20 - 0.22 10,11
2,3-Dimethyl-1-pentene 7 0.01 - 0.02 10
2,4-Dimethyl-1-pentene 7 0.02 - 0.03 10
4,4-Dimethyl-1-pentene 7 0.06 (vol)11
2-Methyl-2-pentene 6 0.27 - 0.32 10,11
3-Methyl-cis-2-pentene 6 0.35 - 0.45 10
3-Methyl-trans-2-pentene 6 0.32 - 0.44 10
4-Methyl-cis-2-pentene 6 0.04 - 0.05 10
4-Methyl-trans-2-pentene 6 0.08 - 0.30 10
4,4-Dimethyl-cis-2-pentene 7 0.02 10
4,4-Dimethyl-trans-2-pentene 7 Not quantified 10
3-Ethyl-2-pentene 7 0.03 - 0.04 10
Cycloalkenes
Cyclopentene 5 0.12 - 0.18 10
3-Methylcyclopentene 6 0.03 - 0.08 10
Cyclohexene 6 0.03 10
Alkyl Benzenes
Benzene (b) 6 0.12 - 3.50 6,7,8,9,
10,11,12
1.4-84
Exhibit 1.4-28
Chemical Composition of Gasoline
(continued)
Concentration
Number of (Percent by
Compound Carbons Weight) (a)Reference
Toluene (b) 7 2.73 - 21.80 5,6,7,8,9,10,11,12
o-Xylene (b) 8 0.68 - 2.86 6,9,10,12
m-Xylene (b) 8 1.77 - 3.87 10
p-Xylene (b) 8 0.77 - 1.58 10
1-Methyl-4-ethylbenzene 9 0.18 - 1.00 10
1-Methyl-2-ethylbenzene 9 0.19 - 0.56 6
1-Methyl-3-ethylbenzene 9 0.31 - 2.86 6,9,10,11
1-Methyl-2-n-propylbenzene 10 0.01 - 0.17 6,9,10
1-Methyl-3-n-propylbenzene 10 0.08 - 0.56 9,10
1-Methyl-3-isopropylbenzene 10 0.01 - 0.12 10
1-Methyl-3-t-butylbenzene 11 0.03 - 0.11 10
1-Methyl-4-t-butylbenzene 11 0.04 - 0.13 10
1,2-Dimethyl-3-ethylbenzene 10 0.02 - 0.19 6,10
1,2-Dimethyl-4-ethylbenzene 10 0.50 - 0.73 6
1,3-Dimethyl-2-ethylbenzene 10 0.21 - 0.59 6,9
1,3-Dimethyl-4-ethylbenzene 10 0.03 - 0.44 6,10
1,3-Dimethyl-5-ethylbenzene 10 0.11 - 0.42 6,10
1,3-Dimethyl-5-t-butylbenzene 12 0.02 - 0.16 10
1,4-Dimethyl-2-ethylbenzene 10 0.05 - 0.36 6,10
1,2,3-Trimethylbenzene 9 0.21 - 0.48 6
1,2,4-Trimethylbenzene 9 0.66 - 3.30 6,9,10,11
1,3,5-Trimethylbenzene 9 0.13 - 1.15 6,9,10
1,2,3,4-Tetramethylbenzene 10 0.02 - 0.19 6,10
1,2,3,5-Tetramethylbenzene 10 0.14 - 1.06 6,9,10
1,2,4,5-Tetramethylbenzene 10 0.05 - 0.67 6,9,10
Ethylbenzene (b) 8 0.36 - 2.86 6,9,10,11,12
1,2-Diethylbenzene 10 0.57 9
1,3-Diethylbenzene 10 0.05 - 0.38 6,9,10
n-Propylbenzene 9 0.08 - 0.72 6,9,10
Isopropylbenzene 9 <0.01 - 0.23 6,9,10,12
n-Butylbenzene 10 0.04 - 0.44 6,9,10
Isobutylbenzene 10 0.01 - 0.08 9,10
sec-Butylbenzene 10 0.01 - 0.13 9,10
t-Butylbenzene 10 0.12 9
n-Pentylbenzene 11 0.01 - 0.14 10
Isopentylbenzene 11 0.07 - 0.17 10
1.4-85
Exhibit 1.4-28
Chemical Composition of Gasoline
(continued)
Concentration
Number of (Percent by
Compound Carbons Weight) (a)Reference
Indan 9 0.25 - 0.34 6
1-Methylindan 10 0.04 - 0.17 10
2-Methylindan 10 0.02 - 0.10 10
4-Methylindan 10 0.01 - 0.16 10
5-Methylindan 10 0.09 - 0.30 10
Tetralin 10 0.01 - 0.14 10
Polynuclear Aromatic Hydrocarbons
Napthalene (b)10 0.09 - 0.49 6,10
Pyrene 16 Not quantified 6
Benz(a)anthracene 18 Not quantified 6
Benz(a)pyrene 20 0.19 - 2.8 mg/kg 6
Benzo(e)pyrene 20 Not quantified 6
Benzo(g,h,i)perylene 21 Not quantified 6
Elements
Bromine 80 - 345 ug/g 3
Cadmium 0.01 - 0.07 ug/g 1
Chlorine 80 - 300 ug/g 3
Lead (c)530 - 1120 ug/g 8
Sodium <0.6 - 1.4 ug/g 3
Sulfur (d)0.10 - 0.15 (ASTM)
Vanadium <0.02 - 0.001 ug/g2,3
Additives
Ethylene dibromide (b)0.7 - 177.2 ppm 4
Ethylene dichloride (b)150 - 300 ppm 8
Tetramethyl lead
Tetraethyl lead
a Conversion from other units assumed 0.75 specific gravity.
b Compounds for which AALs are being developed.
c ASTM specification, maximum, unleaded gasoline, 0.013 g/l maximum, conventional grade
gasoline, 1.1 g/l. Title 13, CAC, Section 2253.2, maximum, leaded gasoline other than leaded high
octane gasoline, 0.8 g/gallon maximum, leaded high octane gasoline, 1.0 g/gallon. Federal standards,
January 1, 1986, maximum, 0.1 g/gallon.
d ASTM maximum, unleaded gasoline, 0.10 by percent weight. Conventional grade gasoline,
0.15 by percent weight, Title 13, CAC, Section 2252, maximum 300 ppm by weight.
1.4-86
REFERENCES
1.American Petroleum Institute, 1985. Cadmium: Environmental and Community Health
Impact. Washington, D.C. EA Report API 137C.
2.American Petroleum Institute, 1985. Vanadium: Environmental and Community Health
Impact. Washington, D.C. EA Report API 37D.
3.C. Block and R. Dams, 1978. Concentration Data of Elements in Liquid Fuel Oils as Obtained
by Neutron Activation Analysis. Journal of Radioanalytical Chemistry 46:137-144.
4.Clifford J. Bruell and George E. Hoag, 1984. Capillary and Packed Column Gas
Chromatography of Gasoline Hydrocarbons and EDB. Proceedings of the NWWA/API
Conference on Petroleum Hydrocarbons and Organic Chemicals in Ground Water:
Prevention, Detection, and Restoration. NWWA, Worthington, Ohio, pp. 234-266.
5.W. Emile Coleman, Jean W. Munch, Robert P. Streicher, H. Paul Ringhand, and Frederick C.
Kopfler, 1984. The Identification and Measurement of Components in Gasoline, Kerosene, and
No. 2 Fuel Oil that Partition into the Aqueous Phase After Mixing. Arch. Environ. Contam.
Toxicol. 13:171-178.
6.George P. Gross, 1971. Gasoline Composition and Vehicle Exhaust Gas Polynuclear
Aromatic Content. Esso Research and Engineering Co., Linden, N.J., 124 p. PB 200 266.
7.Harold E. Guard, James Ng, and Roy B. Louglin, Jr., 1983. Characterization of Gasolines,
Diesel Fuels, and Their Water Soluble Fractions. Naval Biosciences Laboratory, Oakland,
CA, September 1983.
8.H.J. McDermott and S.E. Killiany, 1978. Quest for a Gasoline TLV. Am. Ind. Hyg. Assoc. J.
39:110-117.
9.National Research Council, 1981. The Alkyl Benzenes. National Academy Press, Washington,
D.C.
10.W.N. Sanders and J.B. Maynard, 1968. Capillary Gas Chromatographic Method for
Determining the C3-C12 Hydrocarbons in Full-Range Motor Gasolines. Analytical Chemistry
40(3):527-535.
11.Mark E. Myers, Jr., Janis Stollsteiner, and Andrew M. Wims, 1975. Determination of
Hydrocarbon-Type Distribution and Hydrogen/Carbon Ratio of Gasolines by Nuclear Magnetic
Resonance Spectrometry. Analytical Chemistry 47(12):2010-2015.
12.L.L. Stavinoha and F.M. Newman, 1972. The Isolation and Determination of Aromatics in
Gasoline by Gas Chromatography. Journal of Chromatographic Science 10(9):583-589.
1.4-87
ATTACHMENT 1.4-2
OTHER CHARACTERISTICS OF REFINED PETROLEUM PRODUCTS
1.4-88
MOTOR GASOLINES
Motor gasolines are a complex mixture of relatively volatile hydrocarbons, with or without small
quantities of additives, that have been blended to yield a fuel suitable for use in spark-ignition engines.
Specifications for motor gasoline, as given in ASTM Specification D 439 or Federal Specification VV-
G-1690C, include a boiling range of 122o to 158oF at the 10% point to 365o to 374oF at the 90% point
and a Reid vapor pressure range from 9 to 15 psi. "Motor gasoline" includes finished leaded gasoline,
finished unleaded gasoline, and gasohol. Blendstock is excluded until blending has been completed.
Alcohol that is to be used in the blending of gasohol is also excluded.
Leaded Regular Gasoline
As defined in ASTM D 439 and EPA Specifications, gasoline anti-knock designation 3 produced
with the use of any lead additives or that contains more than 0.05 grams (g) of lead per gallon
or more than 0.005 g of phosphorus.
Unleaded Regular Gasoline
As defined in ASTM D 439 and EPA Specifications, gasoline anti-knock designation 2
containing not more than 0.05 g of lead per gallon and not more than 0.005 g of phosphorus.
Leaded Premium Gasoline
As defined in ASTM D 439 and EPA Specifications, gasoline anti-knock designation 5 produced
with the use of any lead additives or that contains more than 0.05 g of lead per gallon or more
than 0.005 g of phosphorus.
Unleaded Premium Gasoline
As defined in ASTM D 439 and EPA Specifications, gasoline anti-knock designation 4
containing not more than 0.05 g of lead per gallon and not more than 0.005 g of phosphorus.
Gasohol
A blend of finished motor gasoline (leaded or unleaded) and alcohol (generally ethanol but
sometimes methanol) in which 10 percent or more of the product is alcohol.
AVIATION GASOLINES
All special grades of gasoline for use in aviation reciprocating engines, as given in ASTM specification
D 910 and military Specification MIL-G-5572. Specifications for aviation gasoline in ASTM
specification D 910 include a boiling range of 167oF at the 10% point to 275oF at the 90% point and
a Reid vapor pressure range of 5.5 to 7.0 psi. Excludes blending components that will be used in
blending or compounding into finished aviation gasoline. Three grades of aviation gasoline are known
as: Grade 80-red, Grade 100-green, and Grade 100-LL-blue.
Grade 80
As defined in ASTM D 910, an aviation gasoline with an octane value of 80. It is colored red
if it contains 0.5 mg of lead per gallon.
Grade 100
1.4-89
As defined in ASTM D 910, an aviation gasoline with an octane value of 100 and containing a
maximum of 4 mg of lead per gallon. It is colored green to distinguish it from the grade 100-LL,
which is the same fuel but with a lower lead content.
Grade 100-LL
As defined in ASTM D 910, an aviation gasoline with an octane value of 100 and containing a
maximum of 2 mg of lead per gallon. It is colored blue to distinguish it from the grade 100,
which is the same fuel but with a higher lead content.
AVIATION TURBINE FUELS
A quality kerosene product with an average gravity of 40.7o API, and a 10% distillation temperature
of 400oF. It is covered by ASTM Specification D 1655 and Military Specification MIL-T-5624L
(Grades JP-5 and JP-8). See also Exhibit 1.4-29.
Jet A
A relatively high flood point distillate of the kerosene type with a maximum freezing point of -
40oCentigrade.
Jet A-1
Same as Jet A but with a maximum freezing point of -47oC.
Jet B
Jet B is a relatively wide boiling range volatile distillate. A relatively low freezing point
distillate of the kerosene type, it is used primarily for commercial turbojet and turboprop aircraft
engines.
JP-5
A mixture of special kerosene and aviation gasoline specially designed for Navy carrier
operations.
JP-8
A kerosene-type, high-flash-point fuel similar to the jet fuel JP-4, developed for British and
European military planes. The U.S. military is converting some places from JP-4 to JP-8 to
reduce vapor loses at the high temperatures produced by supersonic aircraft. Current use of JP-8
within the United States is very limited.
NAPHTHA-TYPE JET FUEL: JP-4
A fuel in the heavy naphtha boiling range with an average gravity of 52.8oF API and up to 90%
distillation temperatures of 290o to 470oF, meeting Military Specification MIL-T-5624L (Grade
JP-4). It is a blend of 25-35% kerosene and 65-75% gasoline. JP-4 is used for turbojet and
turboprop aircraft engines, primarily by the military. See also Exhibit 1.4-29.
DISTILLATE FUEL OILS
1.4-90
A general classification for one of the petroleum fractions produced in conventional distillation
operations. It is used primarily for space heating, as fuel for on- and off-highway diesel engines
(including railroad locomotive engines and agricultural machinery engines), and for electric
power generation. See also Exhibit 1.4-29.
No. 1 - D (Diesel)
A volatile distillate fuel oil (from kerosene to the intermediate distillates) with a boiling range
between 300o and 375oF and used in high-speed diesel engines generally operated under varying
in speed and load conditions. Includes type C-B diesel fuel used for city buses and similar
operations. Properties are defined in ASTM Specification D 975.
No. 1
A light distillate fuel oil (a little heavier than kerosene, but lighter than No. 2 oil) intended for
use in vaporizing pot-type burners. ASTM Specification D 396 specifies this grade maximum
distillation temperatures of 420oF at the 10% point and 550oF at the 90% point, and kinematic
viscosities (see Exhibit 1.4-30 for kinematic viscosities of gasoline, kerosene, and fuel oils)
between 1.4 and 2.2 mm2/sec, or centistokes (CST), at 100oF. No. 1 oil is a colorless to light
brown liquid known commonly as kerosene or range oil.
No. 2-D (Diesel)
A gas or oil type distillate of lower volatility with distillation temperatures at the 90% point
between 540o and 640oF for use in high-speed diesel engines generally operated under uniform
speed and load conditions. Includes Type R-R diesel fuel used for railroad locomotive engines,
and Type T-T for diesel-engine trucks and tractors. No. 2 diesel fuel is also used in agricultural
machinery and in marine vehicles. Properties are defined in ASTM Specification D 975.
No. 2
A distillate fuel oil (a light brown liquid with an odor like kerosene) for use in atomizing type
burners for domestic heating or for moderate capacity commercial-industry burner units. ASTM
Specification D 396 specifies for this grade distillation temperatures at the 90% point between
540o and 640oF, and kinematic viscosities between 2.0 and 3.6 CST at 100oF.
RESIDUAL FUEL OILS
See also Exhibit 1.4-29.
No. 4-D (Diesel)
A fuel oil used in low and medium speed engines operating under sustained loads and nearly
constant speeds. These engines can be either compression or ignition type.
1.4-91
No. 4 Light
A fuel oil for commercial burner installations not equipped with preheating facilities. It is used
extensively in industrial plants. This grade is a blend of distillate fuel oil and residual fuel oil
stocks that conforms to ASTM Specification D 396 of Federal Specification VV-F-815C; its
kinematic viscosity is between 2.0 and 5.8 CST at 100oF.
No. 4
A fuel oil (a brownish liquid with a characteristic fuel oil or kerosene odor) for commercial
burner installations not equipped with preheating facilities. It ranges from a light distillate type,
low viscosity fuel to heavier residual type fuel oil, depending on the burner. It is used
extensively in small boilers in schools, apartment buildings, and industrial plants. This grade
is a blend of distillate fuel oil and residual fuel oil stocks blended to the viscosity needs of the
burner. It is rarely used in the United States.
No. 5 Light
A residual fuel (a brownish liquid with a kerosene odor) with as high a viscosity as can be
handled and burned without preheating. It is seldom produced in refineries but is made by
diluting No. 6 fuel oil with distillate oils to meet certain viscosity specifications of the buyer.
It also has a higher ash content than the lighter fuel oils. It is commonly used by burners capable
of handling fuels more viscous than grade No. 4.
No. 5 Heavy
A heavy residual fuel (a brownish liquid with a kerosene odor) produced by diluting No. 6 fuel
oil with distillate oils to lower its viscosity to meet the specifications of the burner. Like No.
5-Light, it too has a higher ash content, which means it produces more residue when burned. It
is generally used in small installations with medium rates of consumption and equipped with
preheaters. In cold climates, preheating also may be required for handling.
No. 6 (Bunker C)
The residual oil that is left when light oils, gasoline naphtha, kerosene, and distillate oils are
extracted from crude at normal temperatures and pressure. It is a thick, dark brown, semifluid
material that requires heating for handling. It requires burners with preheaters and is used for
commercial and industrial heating by facilities with heated equipment for proper handling. It
is frequently used to power large ships and is known as Bunker C in this application.
GAS-TURBINE FUEL OILS
This is a general classification for various grades of fuels used in gas turbines. Heavier grades (such
as grade 4-GT) are not suited for aircraft use. Properties are defined in ASTM Specification D 2880-
80.
1.4-92
Grade O-GT
A product of naphthas and low flash distillates, Grade O-GT is used in gas turbines that require
clean-burning fuels. It has a very low flash point and ash content. Includes naptha, Jet B fuel,
and other volatile hydrocarbon liquids.
Grade 1-GT
Grade 1-GT is made from light distillates, which include gas oil fractions. It can be used in
nearly all gas turbines. The minimum flash point of Grade 1-GT is 38oC (100oF), and 90%
distills at a maximum temperature of 288oC (550oF). Corresponds to No. 1 fuel oil and No. 1.4
diesel fuel in general physical properties.
Grade 2-GT
This fuel oil is similar to No. 2 distillate fuel oil, as it includes heavier distillates than Grade
1-GT. Its primary application is for gas turbines requiring a fuel with low ash characteristics
(0.10 percent), but not necessarily as clean burning as Grade 1-GT. Grade 2-GT has a minimum
flash point of 38oC (100oF) and a 90% distillation point from 282o to 338oC (540o to 640oF).
Corresponds in general to No. 2 fuel oil and No. 2-D fuel oil in physical properties.
Grade 3-GT (Residual)
This is a heavier grade compared to the gas turbine oils described above, but also has a low ash
content when burned. It is used for gas turbines that often require fuel heating equipment and
whose inlet temperatures are below 605oC (1202oF). Grade 3-GT has a minimum flash point
of 55oC (131oF) and a minimum kinematic viscosity of 5.5 CST.
Grade 4-GT (Residual)
This grade is somewhat similar to Grade 3-GT (above), but this fuel is used in gas turbines that
can use fuels with less severe restrictions on ash content. Grade 4-GT has a minimum flash
point of 66oC (151oF).
ILLUMINATING OILS
Kerosene
Kerosene is a petroleum distillate that boils at a temperature between 300o and 500oF, has a
flash point higher than 100oF by ASTM Method D 56, has a gravity range from 40o to 46o API,
and has a burning point in the range of 150o to 175oF. Color ranges from colorless to light
brown. Included are the two classifications recognized by ASTM Specification D 3699-83, No.
1-K (low sulfur grade) and No. 2-K (regular grade), and all grades of kerosene called range or
stove oil that have properties similar to No. 1 fuel oils, except their gravity is about 43o API and
their maximum endpoint is 625oF. Kerosene is used in space heaters, cook stoves, and water
heaters and is suitable for use as an illuminant when burned in wick lamps.
1.4-93
Mineral Seal Oil, Other Long-Burning Oils, 300 Oil, Mineral Colza Oil
Mineral Seal oil, long-time burning oils, 300 oil, and mineral colza oil are straight-run (non-
cracked) treated distillates from paraffinic or mixed-based crudes. These types of oils are used
in applications where prolonged burning is required.
IX. SOLVENTS
Most hydrocarbon solvents are straight-run naphthas from paraffinic or mixed-based crudes. Aromatic
solvents are derived from petroleum aromatics (via aromatization processes) and must be in a specific
boiling range.
Stoddard Solvent - Type I Solvent
Stoddard solvent is a commercial reference for Type I dry-cleaning solvent. It is chemically
treated straight-run naphtha made from paraffin-based or mixed-base crude oils. Stoddard
solvent has a minimum flash point of 38oC (100oF) and a maximum dry point (distillation) of
208oC (406oF). Specifications are listed in ASTM D 235.
Petroleum Spirits, Minerals Spirits, Petroleum Ether-Types II, III, IV Solvents
These solvents are made in a similar fashion to Stoddard solvent and are used as paint varnish
and thinners. They are mostly aliphatic petroleum fractions with a boiling point of 90o to 150oC
(194o to 302oF) and have properties similar to dry cleaning solvents Types I-IV (i.w., low flash
point, colorless liquids). (Specifications for Types I-IV dry cleaning solvents are published in
ASTM D 235, ASTM D 86.) Distillation dry points (point at which all liquid evaporates) are
in the 185o to 212oC (365o to 414oF) range.
Varnish Makers' and Painters' (VM&P) Naphthas, Type I, II, III Solvents
These solvents, also known as VM&P naphthas, are very similar to the previous solvents and
are used as thinners in paints, varnishes, and coatings. They too are grouped into types based
on physical properties. Type I is the regular VM&P naphthas, Type II has a higher flash point,
and Type III is odorless. VM&P naphthas are defined in ASTM specification D 3735.
Petroleum Extender Oils - Types 101, 102, 103, 104
Petroleum extender oils are naphthas from paraffin-based crudes used in processing rubber
products. The four varieties, Types 101-104, range in asphaltene content from 0.75% to 0.1%,
polar composition from 25% to 1%, and saturated hydrocarbon composition from 20% to 65%.
(Asphaltene is an asphalt constituent, which is soluble in carbon disulfide but not in paraffin
naphthas and consists of polynuclear hydrocarbons joined by alkyl chains.) Specifications for
extender oils are listed in ASTM D 2226-82.
Commercial Hexane
A solvent composed of n-hexane plus varying amounts of related isohexane compounds,
depending on the initial crude oil stock used in the distillation process. Primary commercial
uses are in the production of gasoline, as the solvent for extracting oils from seed crops and
reaction mediums for various polymerization reactions. Commercial hexanes are also used in
the manufacture of quick-drying adhesives, lacquers, and printing inks.
LUBRICANTS
1.4-94
Lubricants are generally petroleum products designed to protect moving machine parts from friction,
heat, and wear. The various lubricants used can be classified broadly as automotive or industrial,
depending on the type of machinery the lubricant is used on.
Automotive Lubricants
Automotive lubricants are used in cars, trucks, tractors, and other motor vehicles. The lubricants
themselves are either viscous liquids (such as motor oil) or semi-solid (such as bearing grease).
Some motor oil products are also synthetically derived petrochemicals but serve the same
lubrication function. Specifications for automotive lubricants are listed by Society of Automotive
Engineers (SAE) or American Petroleum Institute (API) standards.
Crankcase Oils
Crankcase oils, known commonly as "motor oil," are made from fractionated and refined
paraffin-based, mixed-base, or cycloparaffin-based crudes. They may also be produced
from solvent-refined mixed-based crudes. Motor oils often contain various additives,
including anti-oxidants, detergents, and viscosity builders. Commercial oils are labeled
with the specifications and weights to which they conform.
Transmission and Axle Lubricants
Transmission and axle lubricants are made from well-refined heavy oils and contain
various additives to improve film strength or high-pressure performance. Some of these
fluids are made for closed systems to last the lifetime of the vehicles.
Industrial Lubricants
Industrial lubricants are used in large industrial machines, steam-turbines, compressors, and
gears. Many are products of paraffin-based oils but may also come from other crudes; almost all
contain additives. Their viscosities are often measured in Saybolt Universal seconds (SUs),
which are derived from viscosity measurements in centistokes (based on temperature).
Machine and Engine Oils
These oils are of medium viscosity and are made from paraffin-naphthene-, or mixed-based
crudes -- the same base as for crankcase oils. As indicated above, they may contain
additives, depending on the specific application.
Steam-Turbine Oils
These oils are used as lubricants, coolants, and corrosion inhibitors in steam turbines. Like
machine oils, they are made from paraffin-based or mixed-based crudes, but they are more
highly refined (or solvent-treated). The viscosity is in the range of 150-450 SUs (32-97
CST).
Steam-Engine and Cylinder Oils
Steam engine oils are used as lubricants and sealing fluids in the cylinders of these engines.
They are of high viscosity and are mostly paraffin-based. When used with saturated or set
steam systems, these oils have 2-5% fat as an additive.
Textile-Machinery Oil
1.4-95
These oils are used in textile machines, mostly for lubrication, cooling, and corrosion
prevention of high-speed parts. They are made from paraffin-based or solvent-refined oils
and sometimes have rust-preventive additives. Viscosity is in the 60-200 SUs (10-43 CST)
range.
Refrigerating-Machine Oils
These oils are wax-free oils of medium viscosity (similar to steam-turbine oils) used in
refrigerating machines. They must be able to withstand direct contact with fluorocarbon or
ammonia refrigerants.
Gear Oils
A great variety of gear oils exist, ranging from light-colored, highly refined, low viscosity
(90-150 SUs or 18-32 CST) oils to black, residual oils that contain volatile components.
Depending on the gear application, they may contain film-strength improvers or additives
to improve performance under high pressure.
BUILDING MATERIALS
Many of these materials come from refinery bottoms or residual oils. A large number of them are solid
or semi-solid. Only those materials that are liquids at standard temperature and pressure, however, are
discussed below.
Liquid Asphalt (Cutback Asphalt)
This type of asphalt is made from residual materials from vacuum distillation (especially from
asphalt-based crudes), but it is "cut back" with naphtha (for rapid-curing) or kerosene (medium-
curing). Liquid asphalt is useful as a binder in road surface treatment, cold patching, or cold-
weather construction of macadam surfaces.
Dust-Laying Oils
Unlike other petroleum product building materials, dust-laying oils are low viscosity materials.
These oils are made from untreated distillates or lighter-grade fuel oils.
INSULATING AND WATER PROOFING MATERIALS
Transformer Oils
Transformer oils serve as electrical insulators and coolants for oil-filled transformers, circuit
breakers, and switch boxes. They have generally been made from cycloparaffinic bases but more
recently have been made from paraffinic bases. Polychlorinated biphenyl additives have been
eliminated from transformer oil manufacture but may still be found in transformer oils that have
been in use for some time.
Cable Oils
Cable oils are composed of conventionally refined naphthene oils. Lighter grades are used in oil-
filled cables, while heavier grades are applied to paper-wrapped cables. They are also used for
thermal and electrical insulation.
OTHER PETROLEUM SUBSTANCES
1.4-96
Crude Oils
A naturally occurring mixture, predominantly hydrocarbon with sulphur, nitrogen, and/or oxygen
derivatives, which is found in natural underground reservoirs in liquid phase and which remains
liquid at atmospheric pressure after passing through surface operating facilities. Crude oil
includes condensate and liquid hydrocarbons produced from tar sands, gilsonite, and oil shale.
Drip gases are also included, but topped crude oil (residual oil) and other unfinished oils are
excluded. Liquids produced at natural gas processing plants and mixed with crude oil are
likewise excluded.
Crude Oil Fractions
Streams or fractions into which crude oil has been separated without being otherwise modified.
Petroleum Feedstocks
Products from the refinery process, prior to conversion or upgrading, from which gasoline, fuel
oil, and petrochemicals are produced by thermal or catalytic cracking. Petroleum feedstocks
commonly include benzene, toluene, xylene, naphtha, and gas oils.
Petroleum Fractions
Products or mixtures of products from the refinery distillation process that are characterized by
similar properties, particularly boiling ranges. The most important petroleum fractions are
naphtha, kerosene, fuel oil, and tarry or waxy residues. Same as crude oil fractions if
hydrocarbon source is crude oil.
Used Oil
A petroleum-derived or synthetic oil, including, but not limited to, oil that was used in one of the
following applications:
(1)as a lubricant (engine, turbine or gear);
(2)as a hydraulic fluid (including transmission fluid);
(3)as a metal working fluid (including cutting, grinding, machining, rolling, stamping,
quenching, and coating oil); or
(4)as a coolant that is contaminated through use or subsequent management.
Waste Oil
Waste oil is defined as that portion of used oil that is bound for disposal rather than recycling.
1.4-97
Exhibit 1.4-29
Physical/Chemical Data for
Various Petroleum Products
Product PhysicalDescription FlashPoint
Auto- IgnitionTemperature DensityRange
Explosion Limitsof Vapor(in air) VaporDensity PourPoint
AverageBoiling Range Composition ASTM Definition
JP-1 95 to 145EF(35 to 63EC)44EF(6.7EC)
JP-4 -10 to 30EF(-23 to -1EC)468EF(242EC)65% gasoline, 35" lightpetroleum distillate.
JP-5 95 to 145EF
(35 to 63EC)
475EF
(246EC)
Specifically refined
kerosene.
JP-6 100EF(38EC)435EF(224EC)A higher kerosene cutthan JP-4 with fewerimpurities.
FuelOil #1(Kerosene)
A paleyellowor clearoily
liquid
100 to165EF(38 to 74EC)
444EF(229EC)0.80 to0.8756.879 to7.085 lb/gal
Upper: 5.0%Lower: 0.7%
4.5 timesthat of air 0EF(-18EC)345 to510EF(174 to266EC)
A complex mixture ofhydrocarbons, usuallycontaining 10 to 16carbon atoms permolecule. Chemical
composition by percentis: alkanes, 30%; cyclicalkanes, 60%; andaromatics, 10%.
A light distillate intended for use inbusiness of the vaporizing type inwhich the oil is converted to vaporby contact with a heated surface orby radiation. High volatility is
necessary to ensure thatevaporation yields minimal residue.
FuelOil #2a(Diesel)
A yellowviscousliquid
100EF(38EC)494EF(257EC)0.825 to0.9257.128 to7.490 lb/gal
20EF(-7EC)93 to365EF(34 to185EC)
A complex mixture ofhydrocarbons with 12 to20 carbon atoms permolecule. Averagechemical composition
by percent is: alkanes,30%; cyclic alkanes,45%; aromatics, 25%.
A heavier distillate than Fuel Oil #1,it is intended for use in atomizingtype burners that spray the oil into acombustion chamber where tinydroplets burn while in suspension.
This grade of oil is used in mostdomestic burners and in manymedium capacity commercial-industrial burners.
Exhibit 1.4-29
Physical/Chemical Data for
1.4-98
Various Petroleum Products
(continued)
Product PhysicalDescription FlashPoint
Auto- IgnitionTemperature DensityRange
Explosion
Limitsof Vapor(in air) VaporDensity PourPoint
AverageBoiling Range Composition ASTM Definition
Fuel Oil#4 Can beprepared bycombining40% fuel oil
#6, or may bea high-boilingdistillate orlight residualof the crude
oil.
130EF(54EC)505EF(263EC)7.538 to7.587lb/gal
20EF(-7EC)Fuel oil #4 is intended for use inburners that atomize oils of higherviscosity than domestic burners canhandle. Its permissible viscosity
ranges allow it to be pumped andatomized at relatively low storagetemperatures. Thus, in all butextremely cold weather, it requiresno preheating for handling.
Fuel Oil#5(Navy
SpecialorBunker"B")
May beprepared bycombining
20-25% fuelOIl #2 with75-80% FuelOil #6
Over130EF(over
54EC)
7.686 to7.891lb/gal
Light: a residual oil of intermediateviscosity for burners capable ofhandling fuel more viscous than Fuel
Oil #4 without preheating. Preheating may be necessary insome types of equipment and incolder climates.
Heavy: a residual fuel oil moreviscous than No. 5 light and intendedfor use in similar service. Preheatingto 170E to 220EF (77 to 104EC) isrecommended.
Fuel Oil#6(Bunker"C")
Very viscous,dark-coloredliquid
Above150EF(66EC)
765EF(407EC)7.998 to8.108lb/gal
Low pour: 60EFmaximumhigh pour:
nomaximum
A complex mixture ofheavy molecular weighthydrocarbons. Averagechemical composition is:
alkanes, 25%; polarcompounds, 15%;aromatics, 25%; cyclicalkanes, 45%.
A high viscosity oil used mostly incommercial and industrial heating,Fuel Oil #6 requires preheating to220E to 260EF (104E to 127EC) to
permit pumping and atomizing. Theadditional equipment andmaintenance required to handle thisfuel usually precludes its use at smallfacilities.
aTypes of No. 2 Fuel Oil include No. 1-D (a volatile distillate for engines in service requiring frequent speed and load changes), No. 2-D (a distillate of lower volatility for
engines and heavy mobile service) and No. 4-D (a fuel for low- and medium-speed engines).
17Kinematic viscosity affects the rate at which a petroleum product will leak from a tank and the rate at which it will move through the
unsaturated sone. The lower a product’s kinematic viscosity, the faster it will move through the subsurface. It is also a temperature-dependent
property. Fuel products with a high kinematic viscosity need to be heated if the fuel is to flow freely. The following illustration shows how
these products can be grouped according to their kinematic viscosity and vapor pressures.
Low Motor gasoline High
Kinematic Aviation gasoline Vapor
Viscosity VM&P Napthas (all types)Pressure
(Fastest movers)Aromatic Napthas (Type I & II)(most vapor released)
|Gas turbine fuel oil #0-GT |
|Petroleum spirits (all types) |
| |
|Jet fuels A, A-1, & B |
|Kerosene 1K & 2K |
|Fuel oil #1 |
|Diesel Fuel #1D |
|Gas turbine fuel oil #1-GT |
| |
|Fuel Oils #2 & #4 |
|Diesel Fuels #2D & #4D |
|Gas turbine fuel oil #2-GT |
| |
High Fuel Oils #5 & #6 Low
Kinematic Gas Turbine Oils #3-GT & #4-GT Vapor
Viscosity Lubricating Oils Pressure
(Slowest movers)(Least vapor released)
Data is in centistokes (1 centistoke = 1 centimeter2/second).
q Data is not available
1.4-99
Exhibit 1.4-30
Kinematic Viscosity of Petroleum Products
KINEMATIC VISCOSITY17
PRODUCT MIN.MAX.CENTISTOKES @ 38oC or 40oC
MOTOR GASOLINE 0.5 0.65 NAq
FUEL OIL
No. 1 1.4 2.2 1.65
No. 2 2.0 3.6 2.97
No. 4-light 2.0 5.8 NA
No. 4-heavy 5.8 26.4 NA
No. 5-light >26.4 65 NA
No. 5-heavy >65 194 NA
DIESEL FUEL OIL
No. 1D 1.3 2.4 1.64
No. 2D 1.9 4.1 1.97
No. 4D 5.5 24.0 NA
GAS TURBINE FUEL OIL
No. 1-GT 1.3 2.4 NA
No. 2-GT 1.9 4.1 NA
No. 3-GT 5.5 638 NA
No. 4-GT 5.5 638 NA
KEROSENE 1.0 1.9
NOTE:Adapted from Camp Dresser & McKee Inc. January 1986. Fate and Transport of SubstancesLeaking from Underground Storage Tanks. Volume 1. Technical Report. Section 5.0. Preparedfor the U.S. Environmental Protection Agency, Office of Underground Storage Tanks.
1.4-100
ATTACHMENT 1.4-3
SAMPLE WORKSHEETS FOR ORGANIZING
SITE INVESTIGATION INFORMATION
1.4-101
SITE INSPECTION AND HISTORY WORKSHEET
Spill Number:
Date of Investigation:
Investigator Name:
Name of Owner:
Name of facility:
Location (may include address
and legal description):
Location of tank(s) (attach
reference, schematic drawing,
etc.):
Type(s) of fuel:
Tank description:
(volume, gal.)(material of construction)
Tank test results (recorded/
measured leakage rate; may
want to append results):
Date of tank test:
Test method:
Inventory loss (period of
record; percent loss; volume
unaccounted for, if available):
Failure/discharge (circle):(A) Catastrophic Loss
(B) Long-term leakage
(C) Overtopping
(D) Unknown
(E) Other
If "Other," describe:
Location(s) of failure(s)(A) Tank
(circle):(B) Lines
(C) Connections
(D) Other
(E) Undetermined
1.4-102
SITE INSPECTION AND HISTORY WORKSHEET
(continued)
Please describe briefly (for
example, "...hole in side of
tank from corrosion," or
"...crack at union of tank
and discharge line"):
Age of tank(s) (if available):
Date of tank installation:
Name of installer:
History of previous tankage
on site (that is, could previous
tank have also contributed to
the problem?):
History of other tanks in
area or on site:
Reports of nuisance odors: Yes No
If "Yes," describe and give detail as to how nuisance odors were investigated, with particular
emphasis as to how fire/explosion potential was investigated and/or mitigated:
Nuisance odors (how handled
if reported):
Fire and explosion potential
(how evaluated and handled):
Has air monitoring occurred? Yes No
Date of qualitative analysis
Conducted by (name, title,
agency, or company)
Type of instrument
1.4-103
SITE INSPECTION AND HISTORY WORKSHEET
(continued)
Serial number or manufacturer's
identification
Calibrated to (compound, i.e.,
benzene, methane, etc.)
Date calibrated
Number of background samples
taken (locations should be il-
lustrated on schematic drawing, if
possible, or otherwise documented)
Results of background samples Sample No.Response
average
Qualitative analysis of soil
samples from excavation
Sample No.Description*Response
average
*For example, "...from near area of suspected leak, randomly located, visually stained or
discolored, etc."
Qualitative analysis Pass Fail
(samples below (sample above
background) background)
If "Pass," no further analysis required.
If "Fail," quantitative analysis required.
Has indoor air been sampled? Yes No
If "Yes," present analytical results and procedures per NYSDOH indoor air sampling protocol and
compare reported values (at existing or potential points of exposure) with background samples.
Note that background levels of ambient air at tank sites often contain fuel constituents of concern. It
is important to identify the precise source of
1.4-104
SITE INSPECTION AND HISTORY WORKSHEET
(continued)
the air contaminants and not assume that the source is the tank. Fuel may have spilled on paved
surfaces.
Will site be paved or capped
after remediation? Yes No
If "Yes," describe and document follow-up monitoring.
Identify points and structures
likely to allow vapor migration
and/or exposure:
1.4-105
SITE SAMPLING AND QUANTITATIVE ANALYSIS WORKSHEET
Spill Number:
Name of Investigator:
Date of Events Required:
A.Site Drawing
The site drawing should be to scale and more detailed than the drawing recommended under
"Site Inspections and History." The drawing should identify boring locations, ground-water
monitoring locations, tank and line locations, nearby structures, proximity of underground utilities
and conveyances, suspected location(s) of leakage, etc. This drawing will also be used to illustrate
the direction of ground-water flow, based on measurements of on-site water levels.
B.Subsurface Investigation
#Boring and well logs (including description of drilling apparatus) should include all
field logs and notes, as well as refined logs.
#Geologic cross-section(s).
#Chemical stratigraphy (i.e., pattern of contamination observed in borings and displayed
with cross-section).
#Occurrence of ground water (depth to ground water).
C.Hydrogeologic Setting
Describe/Discuss Setting:
Recharge or discharge zone (if known).
Describe/Discuss:
Agreement/disagreement of subsurface conditions at site with regional setting (i.e., significant
subsurface structures and deposits as expected or as not expected).
Describe/Discuss:
Evidence of excessive heterogeneity in subsurface deposits (excessive heterogeneity
introduced by fractured rock, coarse sand, and gravel deposits, etc., may necessitate a more
conservative investigatory approach).
1.4-106
SITE SAMPLING AND QUANTITATIVE ANALYSIS WORKSHEET
(continued)
Describe/Discuss:
Beneficial use(s) of ground water, including existing water usage and existing (documented)
water quality.
D.Soil Sampling
LEVEL IN SOIL (ppm)
Constituent Sample #1 Sample #2 Sample #3 Sample #4 Sample #5
Benzene
Xylene
Toluene
Ethylbenzene
Lead (optional)
TPH
Sample Locations:
1.
2.
3.
4.
5.
1.4-107
SITE SAMPLING AND QUANTITATIVE ANALYSIS WORKSHEET
(continued)
E.Interpretation of Results of Ground Water Analysis
Analytical Results (append, including analytical results for any QA/QC samples
collected).
Depth of ground water measured on site? Yes No
If "No," give basis for determining depth to ground water. Also, describe those
conditions (i.e., historically documented excessive depth to ground water) or intervening
low-permeability strata that were believed to preclude/inhibit migration to ground
water, thus reducing the need for determining the actual depth to ground water.
Minimum expected depth to ground water: The minimum expected depth to ground
water should be used. This depth may vary from the depth to ground water measured on
a given date due to seasonal and long-term fluctuations of the water table. Adjusting the
value of depth to ground water is particularly important for those areas where: (1)
annual fluctuations in the water table are significant, (2) existing depth to ground water
is slight, and (3) existing water levels are measured during the dry season. Historical
records and basin studies can aid in determining an appropriate adjustment to the
observed depth of ground water.
Direction of ground-water flow: Illustrate on-site drawing, including monitoring
locations and relative measured elevations of water surface.
1.4-108
SITE SAMPLING AND QUANTITATIVE ANALYSIS WORKSHEET
(continued)
Analytical Results for Downgradient Water Samples
Reported
Concentration Detection Limit
Constituent (ug/l)(ug/l)
benzene xylene benzene xylene
toluene ethylbenzenes toluene ethylbenzenes
Sample No. 1
No. 2
No. 3
No. 4
No. 5
Analytical Results for Upgradient Water Samples
Reported
Concentration Detection Limit
Constituent (ug/l)(ug/l)
benzene xylene benzene xylene
toluene ethylbenzenes toluene ethylbenzenes
Sample No. 1
No. 2
No. 3
No. 4
No. 5
1.4-109
Site Drawing
Prepare a drawing of the site showing distances to nearby streams or other surface water, structures, roadways,
subsurface utilities, residences, and other surface and subsurface features. Relationship of the tank to permanent
objects, such as curbs or buildings, should be shown to facilitate finding the tank or excavation at a later date.
Highlight the suspected or known spill source (e..g, tank location). Drawing should be approximately to scale,
including distances and directions, as measured, notably the north arrow.
Spill No. PIN:
Site Name: Date:
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Signature: