United States Office of Ground Water EPA/816-R-99-014i
Environmental and Drinking Water (4601) September 1999
Protection Agency
The Class V Underground Injection
Control Study
Volume 9
Spent Brine Return Flow Wells
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Table of Contents
Page
1. Summary 1
2. Introduction 2
3. Prevalence of Wells 3
4. Injectate Characteristics and Injection Practices 4
4.1 Injectate Characteristics 4
4.1.1 Arkansas 5
4.1.2 Michigan 5
4.2 Well Characteristics 9
4.2.1 Arkansas 9
4.2.2 Michigan 11
4.3 Operating Practices 11
4.3.1 Arkansas 13
4.3.2 Michigan 13
5. Potential and Documented Damage to USDWs 13
6. Alternative and Best Management Practices 14
7. Current Regulatory Requirements 14
7.1 Federal Programs 15
7.2 State and Local Programs 16
Attachment A: State and Local Program Descriptions 17
Attachment B: Chemical Characteristics of Spent Brine Injectate in Arkansas 22
References 26
September 30, 1999
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SPENT BRINE RETURN FLOW WELLS
The U.S. Environmental Protection Agency (USEPA) conducted a study of Class V
underground injection wells to develop background information the Agency can use to evaluate the risk
that these wells pose to underground sources of drinking water (USDWs) and to determine whether
additional federal regulation is warranted. The final report for this study, which is called the Class V
Underground Injection Control (UIC) Study consists of 23 volumes and five supporting appendices.
Volume 1 provides an overview of the study methods, the USEPA UIC Program, and general findings.
Volumes 2 through 23 present information summaries for each of the 23 categories of wells that were
studied (Volume 21 covers 2 well categories). This volume, which is Volume 9, covers Class V spent
brine return flow wells.
1. SUMMARY
Naturally occurring surface and underground brines are used as the source for commercial
production of a variety of mineral commodities, including common salt, calcium chloride, sodium sulfate,
and/or magnesium, iodide, or bromide compounds. When underground brines serve as the raw
material for production of mineral commodities, the brine is extracted from the subsurface through
production wells, the target compounds or elements are extracted, and the resulting "spent brine" is
normally1 returned to the subsurface through spent brine return flow (injection) wells.
The chemical characteristics of the injected spent brine are determined primarily by the
characteristics of the brine that is withdrawn for processing and the nature of the extraction and
production processes used. As a result, spent brine characteristics can vary substantially from facility to
facility, although in some cases the brine characteristics are similar when several facilities withdraw brine
from a common formation, as is the case in Arkansas. In Arkansas, available data indicate that
concentrations of barium and boron in spent brine routinely exceed primary maximum contaminant
levels (MCLs) or health advisory levels (HALs). Data available for Michigan facilities indicate that
chloride, copper, iron, manganese, total dissolved solids, and pH levels frequently exceed secondary
MCLs. Data are not available to determine whether concentrations of some other constituents,
including some heavy metals, are present at concentrations above health-based levels.
Spent brine return flow wells inject spent brine into the same formation from which it was
withdrawn, which in all current cases is below the lowermost USDW. (In fact, most spent brine return
flow wells were initially drilled as production wells and subsequently converted to injection wells.) The
chemical composition of the spent brine is generally similar to that of the produced brine except that the
concentration of target elements (e.g., magnesium) has been reduced and the concentration of other
elements (e.g., calcium) may have been increased through substitution. Thus, the MCL exceedances
observed for the spent brine are also typical for the produced brine and the receiving formation.
1 At least one facility disposes of spent brines from extraction of minerals from brine withdrawn from
underground sources by surface discharge (to a playa lake bed) instead of by injection.
September 30, 1999
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No incidents of USDW contamination by spent brine return flow wells were identified during
preparation of this report. In addition, spent brine return flow wells are not likely to receive accidental
spills or illicit discharges. Corrosion of some well materials by the brine is a common problem,
however. Therefore, injection is through corrosion-resistant tubing and well integrity is monitored on an
ongoing basis.
According to the state and USEPA Regional survey conducted for this study, there are 98
documented spent brine return flow wells that are regulated as Class V injection wells in Arkansas (74)
and Michigan (24). Several other states, including New "Vbrk, Tennessee, California, and Oklahoma,
indicate that spent brine wells exist, but they are regulated as Class n or m wells.
The specific features of well construction and operation may vary somewhat with the location
and timing of construction of the well, but in general, all the wells are built according to regulatory or
permit requirements that have many features in common with Class I and Class n injection wells.
Arkansas has placed jurisdiction over spent brine return flow wells in its Oil and Gas Commission,
which applies Class n UIC permitting requirements as well as a special set of construction and
operating standards. For wells in Michigan, individual UIC permits are issued by USEPA Region 5.
2. INTRODUCTION
Spent brine return flow wells are described in 40 CFR 146.5(e) as "wells used to inject spent
brine into the same formation from which it was withdrawn after extraction of halogens2 or their salts."
Also included in the scope of this discussion are wells used for injection of spent brine (also commonly
referred to as tail brine) that results from production of non-halogen compounds such as calcium salts,
sodium sulfate, and magnesium compounds. Spent brine wells by definition do not include wells used
to reinject brines produced from oil and gas wells or brines injected as part of oil and gas enhanced
recovery operations. Such wells are in the Class n injection well category. In addition, injection wells
used in solution mining of salt are not spent brine wells. Rather, they are solution mining wells that are in
the Class HI injection well category.
The spent brine subcategory includes wells that inject into a formation that is below the
lowermost USDW, as defined in 40 CFR 146.3, and wells that inject into or above a USDW.3
Injection wells that are used to reinject geothermal brine after extraction of both heat and minerals (e.g.,
metals), such as operations that will occur in connection with the zinc recovery facility currently being
2 Any of the five elements that form part of group VIIA of the periodic table (i.e., fluorine, chlorine,
bromine, iodine, and astatine).
3 Spent brine return flow wells were explicitly identified as Class V wells in the technical corrections
to the UIC Technical Criteria and Standards (40 CFR 146) published on August 27, 1981 (46 FR 43156)
and subsequently have been considered to be Class V wells regardless of whether injection occurs above,
into, or below a USDW. At the present time, all active spent brine return flow wells inject below the
lowermost USDW.
September 30, 1999
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constructed near the Salton Sea in California, are covered along with other electric power geothermal
injection wells in \blume 17 of the Class V study.
3. PREVALENCE OF WELLS
For this study, data on the number of Class V spent brine return flow wells were collected
through a survey of state and USEPA Regional UIC Programs. The survey methods are summarized in
Section 4 of Volume 1 of the Class V Study. Table 1 lists the numbers of Class V spent brine return
flow wells in each state, as determined from this survey. The table includes the documented number
and estimated number of wells in each state, along with the source and basis for any estimate, when
noted by the survey respondents. If a state is not listed in Table 1, it means that the UIC Program
responsible for that state indicated in its survey response that it did not have any Class V spent brine
return flow wells.
As shown in Table 1, there are a total of 98 spent brine return flow wells in Michigan (24) and
Arkansas (74) that are regulated as Class V injection wells. Spent brine return flow wells are also used
in Oklahoma in association with iodine recovery from brines. These wells in Oklahoma were generally
drilled as oil and gas wells and the state, which is Primacy State for Class V wells (see Section 7.1 for
the definition of Primacy State), applies Class II requirements to these wells. Several other states,
including New "fork, Tennessee, and California, indicated in the survey that wells that inject brines are
considered Class n or in wells. This report only covers spent brine return wells that are regulated
primarily as Class V wells.
Use of Class V spent brine return flow wells may decrease in Michigan because injection may
be changed to a different formation due to increasing pressure in the source (and current injection)
formation. Such a change would cause the new (replacement) injection wells to be classified as Class I
wells (Micham, 1999). The number of wells in use in the future may also increase or decrease
depending on the relative competitiveness in world markets of the mineral production processes that
currently rely on these wells for brine disposal.
September 30, 1999
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Table 1. Inventory of Spent Brine Return Flow Wells in the U. S.
Estimated Number of Wells
State Number of Wells1 Number Source of Estimate and Methodology
USEPA Region 1 -
USEPA Region 2 -
USEPA Region 3 -
USEPA Region 4 -
USEPA Region
MI 24 24
None
None
None
None
5
N/A
USEPA Region 6
AR 74 74
USEPA Region 7 -
USEPA Region 8 -
USEPA Region 9 -
N/A
None
None
None
USEPA Region 10 - None
All USEPA Regions
All States 98 98
1 The number of wells in Michigan is based on July, 1999 information provided by USEPA Region 5.
N/A Not available.
4. INJECTATE CHARACTERISTICS AND INJECTION
PRACTICES
4.1 Injectate Characteristics
Injectate characteristics are determined primarily by the characteristics of the brine source, the
extraction process and reagents used, and whether or not other wastes are mixed with the spent brine
for disposal by injection.4 Underground brine brought to the surface for processing (often referred to
as "feed brine") may contain natural gas, crude oil, ammonia, and hydrogen sulfide in addition to
dissolved mineral salts.
4 For the purposes of this discussion, other wastes, if any, injected with spent brine are assumed not
to have characteristics that would change the classification of the injection well (e.g., are non-hazardous).
September 30, 1999
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4.1.1 Arkansas
All of the Class V spent brine return flow wells in Arkansas are associated with facilities that
produce bromide compounds from brine extracted from the Smackover formation. Data from routine
sampling by the Arkansas Department of Environmental Quality (DEQ) in December, 1998 of spent
brine prior to reinjection into the Smackover formation are presented in Attachment B to this document
(Arkansas DEQ, 1999). As shown, concentrations of barium, boron, copper, and manganese exceed
MCLs or HALs.5 It can not be determined if concentrations of arsenic, cadmium, chromium, iron,
lead, nickel, and selenium are above MCLs or HALs because the reported detection levels are above
these set values. Although some constituents exceed MCLs, it is important to note that the injection
zone is more than 6,000 feet below the lowermost USDW with several confining units separating the
two.
4.1.2 Michigan
Class V spent brine return flow wells in Michigan are associated with three companies (Martin
Marietta Magnesia Specialties, Morton Performance Chemicals, and The Dow Chemical Company)
that produce magnesium compounds, bromide compounds, and/or calcium chloride from natural brines
in the Filer Sandstone or Sylvania Sandstone formations.6 The top of the production/injection formation
is found at approximately 2,600 feet below ground surface (bgs) (with the exact depth dependant on
the well location), approximately 2,000 feet below the lowermost USDW.
Characteristics of feed brine produced from the Filer Sandstone and spent brine injected into
the same formation at the Martin Marietta Magnesia Specialties plant in Manistee are summarized in
Table 2. As shown, the typical characteristics of the spent brine are generally similar, with some
exceptions, to the characteristics of the brine in the Filer Sandstone. The spent brine is essentially
devoid of magnesium and contains a higher concentration of calcium than the source brine as a result of
the substitution of calcium for magnesium in the brine during reaction with dolime to precipitate
magnesium hydroxide. The concentration of all constituents is reduced by the addition of water. Water
is injected in small quantities at the source brine well head7 and it is added during the process to
generate a relatively chloride-free magnesium hydroxide product. The pH of the spent brine is adjusted
5 Monitoring for volatile compounds is also conducted, but the results are reported by the laboratory
as questionable due to the presence of bubbles in the samples. (Volatile samples are collected with zero
headspace in the sampling container, but bubbles form as the brine cools following sampling.)
6 Some geologists say that the Filer Sandstone is a part of or is the same as the Sylvania Sandstone,
which is the lowest member of the Detroit River Group. Others say that the Filer Sandstone is a member
of the Amhertsburg formation. The Filer Sandstone is believed to be a closed lens and is restricted to the
western portion of the Michigan Basin. The Filer Sandstone is overlain by the dolomite of the
Amherstburg formation and is underlain by the Bois Blanc formation (Richmond, 1999a).
7 Water is added to prevent salt precipitation from the saturated brine caused by the temperature
reduction that occurs during transport in the pipeline to the plant and during storage at the plant.
September 30, 1999
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to approximately 6 prior to injection as compared to an in-situ pH of about 4.5 to 5.0 (Richmond,
1999aandl999b).
As shown in Table 2, the available data indicate that the concentration of boron in the spent
brine at the Martin Marietta facility exceeds the HAL while the concentrations of chloride and iron
exceed secondary MCLs and pH levels are outside the secondary MCL range. It is important to note
that the boron concentration is higher and the pH lower in the receiving formation than in the spent brine
that is injected (Richmond, 1999a).
Table 2. Characteristics of Produced and Injected Brine for Wells in Manistee, Michigan
Parameters
CaCl2
MgCl2
NaCl
KC1
SrCl2
Chloride
Boron
Iron
PH
Bromide
Sulfur
Lithium
Specific Gravity
Units '
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
. , . . Drinking Water Health Advisory
Typical Composition , ,
Standards Levels
Brine from
the formation
215,000
120,000
45,000
10,000
4,000
265,000
60
10
5
3,000
500
105
1.28-1.29
Spent brine to the
mg/1 P/S* mg/1 N/C*
formation
280,000
2,000
40,000
9,000
3,000
220,000 250 S
32 - 0.6 N
<1 0.3 S
6 6. 5 to 8. 5 S
2,000
--
90
1.22-1.25
* P=primary; S=secondary; N=non-cancer; C=cancer
Source: Richmond, 1999a
The Dow Chemical facility in Ludington, Michigan manufactures calcium chloride, magnesium
hydroxide, and bromide compounds from natural brine produced from wells in the Filer Sandstone.
Table 3 presents data from annual analysis of the characteristics of injected spent brine over the period
of 1994 through 1998. Variation in the characteristics of the injected brine are in part due to changes in
plant activities. Manufacturing processes at the plant are highly integrated; the byproducts of each
process are raw materials for another product. Exactly which processes are operated on a given day
depend on market conditions (Ryder, 1999b). The following paragraphs describe the production
process used (or not used, depending on market conditions) to illustrate how injectate characteristics
may vary depending on the products the plant chooses to produce.
September 30, 1999
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Table 3. Injectate Characteristics for Wells in Ludington, Michigan
Annual Analysis of Reinjected Brine
1994-1998
Parameter
Sodium
Calcium
Magnesium
Barium
Total Iron
Chloride
Sulfate
Carbonate
Bicarbonate
Sulfide
Total Dissolved Solids
pH@25°C
Ohm-meter @ 25°C
Specific Gravity
Units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Average
22,374
48,424
1,120
0.15
1.6
145,415
21
91
63
<0.5
204,727
9.18
0.064
1.16
Median
21,619
54,925
565
0.15
1.3
130,117
17
98
47
<0.5
206,800
9.2
0.06
1.15
Minimum
13,160
15,625
169
0.05
0.4
69,688
4
0
4
<0.5
20,300
8.9
0.04
1.08
Maximum
33,050
89,125
7,086
0.6
13.4
333,557
64
166
377
<0.5
345,600
9.4
0.12
1.61
Drinking Water Health Advisory
Standard Level
mg/1
-
-
-
2
0.3
250
500
-
-
-
500
6.5-8.5
-
-
P/S* mg/1 N/C*
-
-
-
P 2 N
S
S
P
-
-
-
S
S
-
-
* P=primary; S=secondary; N=non-cancer; C=cancer
Source: Ryder, 1999a
In the first process, bromide ion in the brine is converted into liquid bromine by chlorine
oxidation, steam stripping, and condensation. This bromine is sold as elemental bromine or converted
into bromide compounds by downstream processes. The debrominated brine from the bromine
stripping tower is acidic; it is neutralized with alkali so that it can be pumped through steel pipes and
stored in steel tanks. If market demand for calcium chloride and magnesium hydroxide is slack, the
debrominated brine is pumped directly to a mixing tank and then reinjected. Otherwise, it is pumped to
the magnesium hydroxide manufacturing process. Scrubber water from the bromine process vents is
also high in halides and may be sent directly to the mixing tank or added to the debrominated brine
stream for further processing (Ryder, 1999b).
The second process produces magnesium hydroxide by precipitating the magnesium ion in the
brine with alkali. The alkali used is typically lime, so the calcium ion from the lime replaces the
magnesium ion in solution to form an intermediate strength calcium chloride solution. Magnesium
hydroxide is separated from the calcium chloride solution by settling, filtration, and washing with water.
The clear fluids from the settling and filtration steps are usually pumped to an evaporator to produce
concentrated calcium chloride solution. If calcium chloride demand is low, these fluids may also be sent
to the mixing tank and injected. Wash water from the magnesium hydroxide process may also be used
to produce calcium chloride solution if market demand is sufficient. Otherwise, it is added to the mixing
tank and injected. The calcium chloride solutions from this process are alkaline because they are
saturated with magnesium hydroxide. If these solutions are injected, hydrochloric acid or debrominated
brine is usually added to reduce the alkalinity of the fluid (Ryder, 1999b).
September 30, 1999
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Evaporation is the third major process in the manufacturing sequence at the Ludington facility.
In this step, steam is used to boil water out of the intermediate strength solution and make strong
calcium chloride solution for direct sale or for production of dry calcium chloride products. As the
calcium chloride solution is concentrated, sodium chloride that was present in the natural brine
separates out as crystals. The sodium chloride crystals are redissolved in the mixing tank to increase
the density and viscosity of the injected solution (Ryder, 1999b).8
Dry calcium chloride manufacturing is the final process in the manufacturing sequence.
Concentrated calcium chloride solution is converted into either flakes or pellets for consumer or
industrial use by boiling off most of the remaining water. Dust produced during conveying and
packaging of the dry product is collected with water scrubbers. The scrubber water is pumped to the
mixing tank for subsequent injection (Ryder, 1999b).
After the various streams from the production plants are blended in the mixing tank, the
resulting fluid is filtered to remove most of the precipitated solids prior to injection. Solids that pass
through the filter (and, thus, are injected) collect on the sandstone face of the well bore and are
dissolved by periodic addition of hydrochloric acid to the injected spent brine at each injection well
(Ryder, 1999b).
Available data for this Dow facility in Ludington indicate that the average and median
concentrations of iron, chloride, total dissolved solids, and pH in the spent brine exceed secondary
MCLs (Ryder, 1999a).
The third facility in Michigan using a spent brine return flow well is Morton Performance
Chemicals in Manistee. The facility uses brine from the Sylvania Sandstone as feed for the process
(USEPA, No date #2). Data from the USEPA Region 5 permit files on characteristics of spent brine
reinjected into the formation are summarized in Table 4. As shown, pH levels are outside the
secondary MCL range.
8 High concentrations of halide salts are desirable in the injected fluid because the salts increase the
viscosity of the fluid and so reduce the tendency of the injected brine to "finger" through the natural brine
in place.
September 30, 1999
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Table 4. Injectate Characteristics for Single Manistee Well
Reinjected Brine Analysis Drinking Water Health Advisory
1997 Standard Level
Parameter
Sodium
Calcium
Magnesium
Barium
Iron
PH
Ohm-meter @ 25 °C
Specific Gravity
Units
mg/1
mg/1
mg/1
mg/1
mg/1
Concentration
10,300
53,800
2,090
0.42
0.273**
2.54
0.07
1.13
mg/1
-
--
--
2
0.3
6.5-8.5
-
-
P/S* mg/1 N/C*
-
-
-
P 2 N
S
S
-
-
* P=primary; S=secondary; N=non-cancer; C=cancer
** Low spike recovery reported, so sample result may be biased low.
Source: Great Lakes Environmental Center, 1997 and U.S. Filter Corp., 1997
4.2 Well Characteristics
Two general types of well construction are used for spent brine return flow wells. Most wells
utilize injection tubing set into a packer immediately above the injection zone. In the other less common
arrangement, the tubing (and sometimes a liner as well) is cemented into the well and no annulus is
present. This second arrangement makes it harder to monitor the well for loss of mechanical integrity
during well operation and this approach is not currently used for new spent brine wells in Michigan or
Arkansas. It has sometimes been used when a well is converted to an injection well9 and or when there
is corrosion or another type of damage to the long string (production) casing (Jones, 1988; Looney
1999; Richmond, 1999a, 1999b).
4.2.1 Arkansas
Figure 1 illustrates a spent brine return flow well from Arkansas. Currently, Great Lakes
Chemical Corporation in Union County and the Albemarle Corporation in Columbia County use a total
of 74 injection wells to return spent brine to the Smackover formation. The top of the Smackover
formation occurs at a depth ranging from 7,150 feet to 8,600 feet, depending on location, while the
lowermost USDW lies from 875 feet to 1,200 feet below ground surface. The Midway formation is
located just below the USDW and is comprised of shale 400 feet to 700 feet thick. The Midway
formation is underlain by alternating layers of shale, sandstone, and limestone, which include several
layers of additional separation. Immediately above the Smackover formation is 200 feet of Anhydrite
and Shale, the Buckner formation, which acts as a confining bed (Looney, 1998).
9 For example, Martin Marietta used this approach to convert a well purchased from another
company for use an injection well. Because the casing cementing program used when the well was
initially constructed was not available, a liner was cemented in place inside the casing.
September 30, 1999
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Figure 1. Example of a Typical Class V Spent Brine Return Flow Well in Arkansas
(depths in feet below ground surface)
if
M
Cv
O^
120T/ Based lavermoGtLJSDW >§
1
J
K
||
\\^
lO<
'
i
l
i
N
r
r
.
1
\\
^?s^
^1 ^/nr Prnrl irhinr ffTti-kr 'T. fl^dYr'1
7* Iniorfinn Ti ihrin /LTrKfiTl
Tnn, rrf Orrnrlmrw 'flh TT J(V
Source: Looney, 1998
September 30, 1999
10
-------
The injection wells are typically constructed with both surface and long string casings ranging
from about 7 to 10 inches in diameter. The surface casing is set 250 feet below the lowermost USDW
and cemented back to the surface. Long string (production) casing is set at the top of the Smackover
formation (the injection zone) and cemented back to the surface. Injection is typically through tubing
with a packer set within 100 feet of the top of the Smackover formation. Thus, there are three layers of
pipe and two layers of cement between the injected fluid and the USDW. Some wells constructed
before 1991 (when current well construction requirements were established) have surface pipe
cemented to the surface, long string casing cemented to the surface, and a casing liner (steel or FRP)
cemented to the surface (Arkansas Oil and Gas Commission, 1991; Looney 1998).
4.2.2 Michigan
Figure 2 illustrates the construction of an injection well at the Martin Marietta Magnesia
Specialties production facility in Manistee. At this site, the base of the lowermost USDW, located in
glacial drift, is approximately 634 feet below the ground surface. Approximately 2,000 feet of
sedimentary rock strata separates the injection zone and the lowermost USDW (USEPA Region 5, No
date #1). Subsurface characteristics and well construction are similar for the injection well at Morton
Performance Chemicals (USEPA Region 5, No date #2).
In the example shown in Figure 2, the surface and long string casings are cemented to the
surface to prevent the movement of fluids between formations penetrated by the well. Injection is
through tubing with a packer set in the long string casing adjacent to a cemented interval that is within or
below the nearest impermeable confining layer immediately above the injection zone. A variety of
tubing materials may be used to resist corrosion, including fiberglass reinforced plastic, steel casing with
a thick film internal coating, and PVC-lined steel casing (Richmond, 1999a).
4.3 Operating Practices
The operation of Class V spent brine return flow wells is typically integrated with overall facility
operation, because plant production is dependent on injection in at least two ways. First, plant
production may need to be curtailed if injection capacity is limited. Second, injection can also interfere
with production if the injected fluid lowers the concentration of the target constituents in the formation at
the production wells.
Basic operating characteristics such as injection pressure and flow rate may vary with changes
in production. These characteristics may be limited by permit conditions or regulations. In addition,
requirements for monitoring and reporting of injectate quality, operating conditions, and mechanical
integrity testing are specified by permit or regulations.
September 30, 1999 11
-------
Figure 2. Example of a Typical Class V Spent Brine Return Flow Well in Michigan
(depths in feet below ground surface)
Pressure Gu;ip!
Vdve
-------
4.3.1 Arkansas
Mechanical integrity testing is conducted before injection is allowed to commence and then
every five years at a minimum. Annual mechanical integrity testing is required for any well without
tubing and packer. The annual test could either be a Radioactive Tracer Survey, a Spinner Survey, or
the use of coil tubing with an inflatable packer to prove integrity of the well bore and proper disposal of
spent brine (Looney 1998).
4.3.2 Michigan
Under the terms of permits issued by USEPA Region 5, mechanical integrity must be
demonstrated before well operation and every five years thereafter, as indicated by a two-part test.
Part I must demonstrate no significant leaks in the casing, tubing, or packer, and Part n must ensure no
significant fluid movement into a USDW through vertical channels adjacent to the wellbore. Therefore,
facilities must conduct Part I mechanical integrity testing by pressure testing the annular space between
the tubing and casing. Part n mechanical integrity testing requires conducting a noise, temperature, or
oxygen activation log test (State of Michigan, 1998).
In addition to Part I and Part n testing, the annular between the injection tubing and the casing
is filled with a liquid to permit continuous monitoring of the mechanical integrity during operation of the
well. At the Martin Marietta Magnesia Specialties facility, for example, the annular space is filled with
either fresh water or produced brine treated with a corrosion inhibitor and bactericide, with the top 10
to 50 feet filled with fuel oil to prevent freezing. The annulus surge tank (see Figure 2) is filled to one-
third to one-half of its capacity with fuel oil. Nitrogen fills the remaining tank volume and provides the
initial pressure on the annulus system. Tank pressure and liquid level are recorded at least three times a
week. If a rapid fluid loss or pressure anomaly is observed, pressure testing and/or maintenance of the
well is performed to investigate and correct, if necessary, loss of mechanical integrity (Richmond,
1999a).
5. POTENTIAL AND DOCUMENTED DAMAGE TO USDWS
The primary constituent properties of concern when assessing the potential for Class V spent
brine return flow wells to adversely affect USDWs are toxicity persistence, and mobility. The toxicity
of a constituent is the potential of that contaminant to cause adverse health effects if consumed by
humans. Appendix D of the Class V UIC Study provides information on the health effects associated
with contaminants found above drinking water standards or health advisory levels in the injectate of
spent brine return flow wells and other Class V wells.
Persistence is the ability of a chemical to remain unchanged in composition, chemical state, and
physical state over time. Appendix E of the Class V UIC Study presents published half-lives of
common constituents in fluids released in spent brine return flow wells and other Class V wells. All of
the values reported in Appendix E are for ground water. Caution is advised in interpreting these values
because ambient conditions have a significant impact on the persistence of both inorganic and organic
September 30, 1999 13
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compounds. Appendix E of the Class V UIC Study also provides a discussion of mobility of certain
constituents found in the injectate of spent brine return flow wells and other Class V wells.
Based on the information presented in section 4.1, the following constituents routinely or
frequently exceed health-based standards in spent brine from one or more facilities: barium, boron, and
copper. Manganese, iron, chloride, total dissolved solids, and pH are routinely above secondary
drinking water standards at some facilities. The persistence and mobility of these constituents is
expected to be approximately the same following injection as in the produced brine because injection is
into the producing formation. If spent brine were accidentally released to another formation, the
persistence and mobility of these constituents may be different than in the producing formation.
Discussion of behavior of these constituents outside the producing formation is not included here
because there have been no reported instances in which spent brine return flow wells have contributed
to contamination of a USDW. Specifically, the State of Arkansas has not had any incidents in which a
spent brine return flow well contributed to contamination of a USDW (Looney 1998).10 Similarly,
USEPA Region 5, which implements the UIC program in Michigan, reports no incidents in which spent
brine return flow wells contributed to contamination of a USDW (Cadmus, 1999).
6. ALTERNATIVE AND BEST MANAGEMENT PRACTICES
Alternatives to injection for disposal of spent brine at the facilities that use spent brine return
flow wells appear limited at this time.11 Although discharge to surface waters may have been common
in some locations in Michigan approximately 20 to 25 years ago, injection is now the disposal approach
for most spent brine generated by these facilities.
As discussed in the next section, requirements applicable to spent brine return flow wells in
Michigan and Arkansas go well beyond the requirements for most Class V wells and are similar in
many respects to the requirements applicable to Class I and Class n injection wells. No best
management practices in addition to the current requirements were identified during the preparation of
this report.
7. CURRENT REGULATORY REQUIREMENTS
Several federal, state, and local programs exist that either directly manage or regulate Class V
spent brine return flow wells. On the federal level, management and regulation of these wells fall
10 Spent brine from the plant has been injected into the Filer formation for over 45 years to maintain
the pressure in the pores of the sandstone and displace the natural brine towards production wells (%der,
1999).
11 Although all facilities in Michigan and Arkansas that currently recover minerals from underground
brines use spent brine return flow wells to inject spent brine back into the producing formation, at least
one facility in California (near Searles Lake) disposes the spent brine to a playa lake bed instead of
injection wells.
September 30, 1999 14
-------
primarily under the UIC program authorized by the Safe Drinking Water Act (SDWA). Some states
and localities have used these authorities, as well as their own authorities, to extend the controls in their
areas to address concerns associated with spent brine return flow wells.
7.1 Federal Programs
Class V wells are regulated under the authority of Part C of SDWA. Congress enacted the
SDWA to ensure protection of the quality of drinking water in the United States, and Part C specifically
mandates the regulation of underground injection of fluids through wells. USEPA has promulgated a
series of UIC regulations under this authority. USEPA directly implements these regulations for Class
V wells in 19 states or territories (Alaska, American Samoa, Arizona, California, Colorado, Hawaii,
Indiana, Iowa, Kentucky, Michigan, Minnesota, Montana, New York, Pennsylvania, South Dakota,
Tennessee, Virginia, Virgin Islands, and Washington, DC). USEPA also directly implements all Class
V UIC programs on Tribal lands. In all other states, which are called Primacy States, state agencies
implement the Class V UIC program, with primary enforcement responsibility.
Spent brine return flow wells currently are not subject to any specific regulations tailored just
for them, but rather are subject to the UIC regulations that exist for all Class V wells. Under 40 CFR
144.12(a), owners or operators of all injection wells, including spent brine return flow wells, are
prohibited from engaging in any injection activity that allows the movement of fluids containing any
contaminant into USDWs, "if the presence of that contaminant may cause a violation of any primary
drinking water regulation ... or may otherwise adversely affect the health of persons."
Owners or operators of Class V wells are required to submit basic inventory information under
40 CFR 144.26. When the owner or operator submits inventory information and is operating the well
such that a USDW is not endangered, the operation of the Class V well is authorized by rule.
Moreover, under section 144.27, USEPA may require owners or operators of any Class V well, in
USEPA-administered programs, to submit additional information deemed necessary to protect
USDWs. Owners or operators who fail to submit the information required under sections 144.26 and
144.27 are prohibited from using their wells.
Sections 144.12(c) and (d) prescribe mandatory and discretionary actions to be taken by the
UIC Program Director if a Class V well is not in compliance with section 144.12(a). Specifically, the
Director must choose between requiring the injector to apply for an individual permit, ordering such
action as closure of the well to prevent endangerment, or taking an enforcement action. Because spent
brine return flow wells (like other kinds of Class V wells) are authorized by rule, they do not have to
obtain a permit unless required to do so by the UIC Program Director under 40 CFR 144.25.
Authorization by rule terminates upon the effective date of a permit issued or upon proper closure of the
well.
In Michigan, USEPA Region 5 directly implements the UIC Class V program and requires
individual permits for spent brine return flow wells. The specific permit requirements are discussed
along with the state's permit requirements in Attachment A of this volume.
September 30, 1999 15
-------
Separate from the UIC program, the SDWA Amendments of 1996 establish a requirement for
source water assessments. USEPA published guidance describing how the states should carry out a
source water assessment program within the state's boundaries. The final guidance, entitled Source
Water Assessment and Programs Guidance (USEPA 816-R-97-009), was released in August
1997.
State staff must conduct source water assessments that are comprised of three steps. First,
state staff must delineate the boundaries of the assessment areas in the state from which one or more
public drinking water systems receive supplies of drinking water. In delineating these areas, state staff
must use "all reasonably available hydrogeologic information on the sources of the supply of drinking
water in the state and the water flow, recharge, and discharge and any other reliable information as the
state deems necessary to adequately determine such areas." Second, the state staff must identify
contaminants of concern, and for those contaminants, they must inventory significant potential sources
of contamination in delineated source water protection areas. Class V wells, including spent brine
return flow wells, should be considered as part of this source inventory, if present in a given area.
Third, the state staff must "determine the susceptibility of the public water systems in the delineated area
to such contaminants." State staff should complete all of these steps by May 2003 according to the
final guidance.12
7.2 State and Local Programs
Two states, Arkansas and Michigan, reported existing Class V solution mining injection wells
that are covered in this document. Attachment A of this volume describes how each of these states
currently addresses these wells. Both states issue individual permits. In Arkansas, a UIC Primacy
State for Class V wells, jurisdiction over spent brine return flow wells rests with the Oil and Gas
Commission, which applies UIC Class n permitting requirements, as well as a special set of
construction and operating standards in a rule applicable to Class V (bromine related) injection wells.
In Michigan, the Michigan Department of Environmental Quality, Geological Survey Division, issues
permits for spent brine return flow wells under the authority of Part 625 of the Michigan Natural
Resources and Environmental Protection Act (NREPA). USEPA Region 5 also permits spent brine
return flow wells under the nonendangerment clause using standards similar to those applied to Class n
wells. Thus, in Michigan spent brine return flow wells are permitted by both USEPA Region 5 and the
state.
12 May 2003 is the deadline including an 18-month extension.
September 30, 1999 16
-------
ATTACHMENT A
STATE AND LOCAL PROGRAM DESCRIPTIONS
This attachment describes the control programs in Arkansas and Michigan, the two states with
Class V spent brine return flow wells covered by this document.
Arkansas
Arkansas is a UIC Primacy State for Class V wells. The Arkansas Underground Injection
Control Code of 1989 (Code) adopts, by reference, federal UIC regulations (Code §3). The Code
identifies wells used to inject spent brine into the same formation from which it was withdrawn after
extraction of halogens or their salts as Class y and also specifies that as of the effective date of May 4,
1989, such wells were operating in the state (Code §5(E)(14) and (F)).
The Arkansas Oil and Gas Commission (AOGC) in 1991 adopted the Class V (Bromine
Related) Injection Wells Rule (Rule). That rule establishes permitting, construction and operation
requirements.
Permitting
The Underground Injection Control Code provides that no person may construct, install, alter,
modify, or operate any Class V bromine-related brine disposal well without a permit from the AOGC
(Code §4(A)). The AOGC rule applicable to Class V (bromine related) injection wells also provides
that the application for a permit to dispose of salt water by subsurface injection shall be the same as is
required for Class n wells (Rule § 17). Because the state has adopted by reference federal UIC
regulations, including Part 144, Subpart D, the application will include the information required by 40
CFR § 144.31(e). This will include a description of the activities conducted by the applicant,
information identifying the business and its location, a listing of all permits or construction approvals
required under specified environmental protection programs, maps, and a plugging and abandonment
plan.
Siting and Construction
The AOGC rule pertaining to Class V (bromine related) injection wells provides the following.
All injection must be through tubing and packer with packer set within 100 feet of the top of the
Smackover formation, unless otherwise approved by AOGC. On all newly drilled wells, the
operator is required to drill into the top of the Smackover formation prior to setting long string,
to ensure that when the well is logged the operator will be able to identify the top of the
Smackover formation and verify that the water will be injected into it.
Surface casing must be set 250 feet "below the lowermost USDW." Production casing (long
string) must be cemented from the top of the injection zone to the "top of the ground." The
September 30, 1999 17
-------
setting of the surface and production casing must be witnessed by a representative of the
AOGC.
On all wells being converted from productive status to injection status, the operator is required
to run a cement bond log from the top of the injection zone to the top of the ground. These
wells also must be constructed in such a manner as to have surface casing set at least 250 feet
below the lowermost USDW. Wells that are completed with one size casing down to a certain
point and a smaller size hung inside the larger size down to total depth will have the smaller size
pipe run from the surface down to the top of the existing string and cement circulated back to
the top of the ground. The larger size casing will be considered surface casing, and the smaller
size will be considered production casing. Production casing with cement to the top of the
ground, tubing, and packer set within 100 feet of the top of the Smackover formation is
required, unless AOGC approves other casing.
A cement bond log is required on all wells converted from producing status to injection status
and on any newly drilled wells that fail to circulate cement back to the top of the ground. All
cement bond logs must be witnessed by an AOGC representative.
For any newly drilled well that fails to circulate cement back to the top of the ground, the top of
the cement will be determined by a cement bond log. In the event that the top of the cement is
not above the Sparta Sand, the operator will be required to bring the top of the cement above
the Sparta Sand.
Operating Requirements
The AOGC rules provide the following.
All water injection will be into the Smackover formation. Injection into other zones must be
approved by USEPA.
Injection pressure is not to exceed 0.5 psi per foot of depth to the top of the injection zone.
Only debrominated brine will be authorized for injection.
All wells must maintain a positive annulus pressure (amount to be determined by the AOGC).
The annulus pressure must be monitored by a pressure chart. The chart must be changed
weekly and copies filed with the AOGC monthly. Any change in pressure must be explained in
writing, and any unsatisfactory explanation will result in the well being tested for mechanical
integrity.
Any time an injection well is worked over, the operator must notify AOGC prior to the
beginning of the work over, and a mechanical integrity test must be run on the well after the
work over is completed if the packer has become unseated.
September 30, 1999 18
-------
Mechanical Integrity
The AOGC rules provide the following.
All wells must pass an annulus pressure test once every 5 years. Wells that cannot be tested in
this manner must have a radioactive tracer survey run annually.
All wells that fail to pass a mechanical integrity test (MIT) must be repaired or plugged and
abandoned within 90 days of the failure date. The well is to be shut-in immediately after failure
to pass the MTT and must remain shut-in until it passes a mechanical integrity test or is plugged
and abandoned.
Financial Responsibility
A $25,000 bond is required for each Class V well in Arkansas (Card, 1999). An annual fee of
$100 is assessed.
Plugging and Abandonment
Because the state has adopted by reference the federal UIC requirements, plugging and
abandonment can be required under the general non-endangerment requirements. The state's rules for
Class V (bromine related) injection wells do not contain any plugging and abandonment requirements.
Michigan
USEPA Region 5 implements the UIC Class V program in Michigan. In addition, the
Geological Survey Division (GSD) of the Michigan Department of Environmental Quality also has
authority under the state's Natural Resources and Environmental Protection Act (NREPA) Part 625 to
establish standards for construction, testing, operation, and plugging and abandonment of mineral wells
and to permit such wells.
Permitting
USEPA Region 5 requires a permit for spent brine return wells under the non-endangerment
clause, and applies permitting standards similar to those applicable to Class n injection wells. Injection
is allowed only into a formation that is separated from a USDW by a confining zone free of known
open faults or fractures.
The Michigan GSD also separately permits spent brine return wells as disposal wells. NREPA
defines a disposal well as a well drilled or converted for subsurface disposal of waste products or
processed brine (324.62501(d) NREPA). The statute requires that permits must be issued before
drilling or conversion of any brine, storage, or waste disposal well (324.62509 NREPA). The GSD
has promulgated rules requiring permits to drill, deepen, rework, or convert brine and waste disposal
September 30, 1999 19
-------
wells (R299.2201 to 299.2298). Special requirements expedite permits to drill, deepen, rework, or
convert brine, storage and disposal wells, which may be issued within 10 days of receipt of the
application if the exact location of the well is established. This is accomplished by submitting a survey,
map or plat indicating key features, including well depth or deepest zone or formation, and filing a
security bond (R299.2211 and .2212). A public hearing on drilling or conversion of a storage or
disposal well may be held (R299.2213).
Siting and construction
USEPA Region 5 requires well construction to meet the requirements of 40 CFR 144.52(a)(l).
The permittee must submit construction data to USEPA Region 5.
NREPA specifies that the Supervisor of Mineral Wells in GSD may require the locating,
drilling, deepening, reworking, reopening, casing, sealing, injecting, mechanical and chemical treating,
and plugging of wells to be accomplished in a manner that is designed to prevent surface and
underground waste. Toward that end, logs may be required to be kept, and drill cuttings, cores, water
samples, pilot injection tests and records, and operating records may be required (324.62508
NREPA). The regulations specify casing and sealing requirements for brine, storage, and disposal
wells, including requirements that the drive pipe be landed, or surface pipe set and cemented to the
surface, at sufficient depth to protect fresh water aquifers. Tubing is required for use in injection
operations (R299.2253).
Operating Requirements
USEPA Region 5 requires a standardized annulus pressure test (SAPT) [Part I of the
mechanical integrity demonstration] to be passed prior to commencing injection and every 5 years
thereafter. In addition, an SAPT must be performed after any workover of the wells. SAPT's are
usually witnessed by the USEPA. Wells must be monitored for injection pressure, flow rate, annulus
pressure, and cumulative volume on a weekly basis, annulus liquid loss on a quarterly basis, and
chemical composition of injectate annually. SAPT results and monitoring results must be provided to
USEPA Region 5. A part n demonstration of a mechanical integrity test, including temperature or
oxygen activation measurements, must also be conducted prior to injection every 5 years. The USEPA
or its designee has the opportunity to witness all Part I or n mechanical integrity tests.
Requirements for operation of wells also are specified in the GSD rules and additional
requirements may be established by GSD in permits. These requirements include records of rates of
injection, operating pressures, types and volumes of fluids injected, and other pertinent information.
Those volumes, injection rates, and pressures may not exceed those specified in the approval of the
well (R299.2268).
September 30, 1999 20
-------
Financial Responsibility
NREPA provides that security bonds may be required (324.62508 NREPA). Rules set the
security bond for a single disposal well at $15,000 and for 2 or more such wells at $25,000
(R299.2231). The bonds provide security for compliance with the statute and satisfactory plugging
and abandonment of the wells.
Plugging and Abandonment
Plugging is required to be carried out based on instructions from the GSD (R229.2282).
September 30, 1999 21
-------
ATTACHMENT B
CHEMICAL CHARACTERISTICS OF SPENT BRINE INJECTATE IN ARKANSAS
Parameters
Dissolved Metals
Arsenic
Barium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Nickel
Potassium
Selenium
Silver
Sodium
Zinc
Semivolatile Compounds
2-Fluorophenol (Surr.)
Phenol-d6 (Surr.)
Nitrobenzene-d5 (Surr.)
2-Fluorobiphenyl (Surr.)
2-4-6 Tribromophenol (Surr.)
Terphenyl-dl4 (Surr.)
2-Picoline
Aniline
Phenol
units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
%Rec
%Rec
%Rec
%Rec
%Rec
%Rec
mg/1
mg/1
mg/1
Great Lakes
South
<1
8.8
192
<.014
34130
< .4
< .5
1.9
<15
0.4
3.27
7.5
<2
3.64
<3
<.043
67.2
1.3
88.663
40.017
103.03
77.886
73.866
79.587
< .00065071
<. 00031393
.00126500
Spent Brine
Great Lakes
Central
<1
2.9
141
<.014
30720
< .4
< .5
2
<15
0.4
3.36
2.7
<2
2.53
<3
<.043
63.1
<1
88.583
50.395
106.27
89.207
93.654
77.653
<. 00031 169
.00062481
.00069123
Concentration By
Great Lakes
Newell
<1
2.8
167
<.014
34280
< .4
< .5
1.8
<15
0.4
3.49
2.6
<2
2.37
<3
<.043
66.1
<1
44.359
35.367
102.24
87.906
32.697
78.445
< .00042681
< .00020591
.00062187
Facility
Albermarle
South
<1
13.7
168
<.014
35290
< .4
< .5
2.2
<15
0.4
3.63
10
<2
3.03
<3
<.043
70.7
1.6
0.91785
5.3875
107.19
94.32
4.6313
73.333
< .0004755
< .0002294
<. 00013548
Great Lakes
Mville
<1
13.4
176
<.014
35450
< .4
< .5
2
<15
0.4
3.48
8.6
<2
2.21
<3
1.8
69.4
<1
43.802
24.32
104.51
95.421
36.723
73.292
< .00028534
.00015013
.00055998
Drinking Water
Standard
Primary or
m8/1 c A
Secondary
0.05 P
2 P
-
0.005 P
-
0.1 P
-
1.3 P
0.3 S
0.015 P
-
0.05 S
0.1 P
-
0.05 P
0.1 S
-
5 S
-
-
-
-
-
-
-
-
-
Health Advisory Level
Cancer or
Non Cancer
0.002 C
2 N
0.6 N
0.005 N
-
0.1 N
-
-
-
-
-
-
0.1 N
0.1 N
2 N
-
-
-
4 N
NOTE: The metals analyses were affected by the high dissolved solids in the sample. This resulted in very high detection limits for some metals.
A + in front of data indicates that value is less than the detection limit but tentatively reported as present.
September 30, 1999
22
-------
ATTACHMENT B
CHEMICAL CHARACTERISTICS OF SPENT BRINE INJECTATE IN ARKANSAS
(continued)
Parameters
Bis(2-chloroethyl)-Ether
2-Chlorophenol
1 -3-Dichlorobenzene
1 -4-Dichlorobenzene
Benzyl-alcohol
1 -2-Dichlorobenzene
2-Methylphenol
Acetophenone
N-Nitroso-di-n-propylamine
4-Methylphenol
Hexachloroethane
Nitrobenzene
N-Nitro sopiperidine
Isophorone
2-Nitrophenol
2-4-Dimethylphenol
Bis(2-chloroethoxy)methane
2-4-Dichlorophenol
1 -2-4-Trichlorobenzene
2-6-Dichlorophenol
4-Chloroaniline
Naphthalene
Hexachlorobutadiene
N-Nitrosodibutylamine
4-Chloro-3-methylphenol
2-Methylnaphthalene
HexachlorocvcloDentadiene
units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
ma/1
Great Lakes
South
<. 00082411
< .00039505
< .00026503
< .00023816
< .00055806
< .00026682
+.00044512
.00054924
< .00355470
< .00056491
< .00067309
< .00065818
<. 0003 1926
< .00052321
< .00072503
< .00020852
< .00032239
< .00035685
< .00044094
< .00039436
<. 0001 1540
.00246590
< .00009851
<. 00185620
< .00042086
.00409950
<. 00015622
Spent Brine
Great Lakes
Central
< .00039475
< .00025016
<. 00016154
<. 00014516
< .00038097
< .00016263
+.00040478
.00046947
.00028080
< .00046454
< .00043940
<. 00044431
< .00022763
<. 00006319
< .00033333
.00018422
< .00014799
< .00020135
<. 00015075
<. 00022251
< .00008595
.00358930
< .00005781
< .00024139
< .00028720
.00251790
.00019704
Concentration By
Great Lakes
Newell
< .00054055
< .00018166
< .00024087
< .00021645
< .00046915
< .00024250
< .00045046
.00041587
< .00126220
< .00036647
< .00042898
< .00042196
< .00023355
< .00019068
< .00026334
< .00010623
< .00019523
< .00015907
< .00032222
< .00017579
< .00006904
.00075556
< .00007984
< .00063832
< .00025206
.00074498
< .00016026
Facility
Albermarle
South
< .00060221
< .00023304
<. 00011588
<. 00010413
< .00033389
<. 0001 1666
< .00030369
.00048899
<. 001 12660
< .00024706
< .00056877
< .00047093
< .00023941
< .00027848
< .00039266
<. 00013285
< .00028405
< .00017597
< .00032733
<. 00019447
<. 0001 1460
.00158330
<. 00013940
< .00064209
<. 00022193
.00273400
< .00022488
Drinkin
Stan
Great Lakes
Mvrlle mg/1
< .00036138
< .00013199
< .00015040
< .00013515 0.075
< .00025335
<. 00015141 0.6
< .00029356
.00061437
< .00029824
< .00023883
< .00022432
< .00027521
< .00017833
< .00009787
< .00017061
< .00009340
< .00014631
< .00014722
< .00013778 0.07
< .00016270
< .00005375
.00025201
< .00006096
< .00016848
< .00018414
.00019648
.00024357 0.05
j Water
, , Health Advisory Level
dard
Drimary or
C J "^
Secondary
-
0.04
0.6
P 0.075
-
P 0.6
-
-
-
-
0.001
--
-
0.1
-
-
-
0.02
P 0.07
-
-
0.02
0.001
--
P
Cancer or
Non Cancer
N
N
N
N
N
N
N
N
N
N
NOTE: The metals analyses were affected by the high dissolved solids in the sample. This resulted in very high detection limits for some metals.
A + in front of data indicates that value is less than the detection limit but tentatively reported as present.
September 30, 1999
23
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ATTACHMENT B
CHEMICAL CHARACTERISTICS OF SPENT BRINE INJECTATE IN ARKANSAS
(continued)
Parameters
1 -2-4-5-Tetrachlorobenzene
2-4-6-Trichlorophenol
2-4-5-Trichlorophenol
2-Chloronaphthalene
1 -Chloronaphthalene
2-Nitroaniline
Dimethyl-phthalate
2-6-Dinitrotoluene
Acenaphthylene
3-Nitroaniline
Acenaphthene
Pentachlorobenzene
Dibenzofuran
2-4-Dinitrotoluene
4-Nitrophenol
2-Naphthylamine
2-3-4-6-Tetrachlorophenol
1-Naphthylamine
Diethyl-phthalate
Fluorene
4-Chlorophenyl-phenyl-ether
4-Nitroaniline
Diphenylamine
1 -2-Dipheny Ihy drazine
Phenacetin
4-Bromophenyl-phenyl-ether
Hexachlorobenzene
units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
ma/1
Great Lakes
South
<. 00016130
< .00074769
<. 00069135
< .00010469
<. 00015178
< .00052246
< .00007962
< .00090715
<. 00015365
< .00050483
<. 00019522
< .00007403
< .00009241
< .00063682
< .00090687
< .00024731
< .00043890
< .00027092
.00144470
.00070219
< .00004973
< .00059442
< .00050923
< .00020297
< .00022567
< .00007795
< .00007986
Spent Brine
Great Lakes
Central
< .00006796
.00023915
< .00012867
< .00006192
< .00008977
<. 0003 1146
.00020055
< .00022968
< .00006812
< .00025523
<. 00015240
< .00006935
<. 00003 120
< .00016124
<. 00031685
< .00012335
< .00020240
.00030961
.00147790
.00022452
< .00005953
< .00030053
< .00007268
< .00014390
<. 00015506
.00013396
.00013918
Concentration By
Great Lakes
Newell
< .00010046
< .00021589
< .00019962
< .00005072
< .00007353
< .00029912
.00021422
< .00046322
< .00006341
< .00039129
<. 00011559
< .00006455
< .00006292
< .00032518
< .00055914
< .00012979
< .00025299
< .00014218
.00141950
.00017808
< .00005060
< .00046074
< .00018675
<. 00013931
< .00018753
.00005440
.00037572
Facility
Albermarle
South
<. 00015528
<. 00018967
< .00017537
< .00005823
.00028647
< .00041439
.00025014
< .00062608
<. 00019982
< .00047575
< .00024810
< .00009452
< .00007441
< .00043950
< .00058704
<. 00019735
<. 00021871
<. 00021619
.00167840
.00030023
< .00008202
<. 00056018
< .00020421
< .00014847
< .00016644
.00006603
< .00008108
Drinkin
Stan
Great Lakes
,, ... mg/1
Mville
< .00006837
< .00008325
< .00007698
< .00004707
< .00006824
< .00024427
.00066864
<. 000400 11
< .00005628
< .00021398
<. 0001 1263
< .00005125
< .00002470
< .00028087
< .00039515
< .00009682
< .00008792
< .00010606
.00257060
+.00005940
.00003050
< .00025196
< .00005599
< .00008878
<. 000 11 092
< .00004827
.00011633 0.001
j Water
, , Health Advisory Level
dard
Drimary or Cancer or
Secondary Non Cancer
-
0.3 C
-
-
-
-
-
0.005 C
-
-
-
--
-
0.005 C
0.06 N
-
-
-
5 N
-
-
-
0.2 N
--
P 0.002 C
NOTE: The metals analyses were affected by the high dissolved solids in the sample. This resulted in very high detection limits for some metals.
A + in front of data indicates that value is less than the detection limit but tentatively reported as present.
September 30, 1999
24
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ATTACHMENT B
CHEMICAL CHARACTERISTICS OF SPENT BRINE INJECTATE IN ARKANSAS
(continued)
Parameters
Pentachlorophenol
Pentachloronitrobenzene
4-Aminobiphenyl
Pronamide
Phenanthrene
Anthracene
Di-n-butyl-phthalate
Fluoranthene
Pyrene
Dimethylaminoazobenzene
Butyl-benzyl-phthalate
Benzo(a)anthracene
3-3'-Dichlorobenzidine
Chrysene
Bis(2-ethylhexyl)phthalate
Di-n-octyl-phthalate
Benzo(b)fluoranthene
Benzo(k)fluoranthene
Benzo(a)pyrene
Dimethylbenzo(a)anthracene
3-Methylcholanthrene
Dibenzo(a-j )acridine
Indeno(l-2-3-cd)pyrene
Dibenz(a-h)anthracene
Benzo(g-h-i)perylene
units
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
mg/1
Great Lakes
South
< .00027423
< .00033692
< .00087168
< .00028414
.00095485
< .00020522
.00941360
<. 00007518
< .00005607
<. 000051 17
.00658070
< .00006897
< .00003290
.00050251
.00450470
< .00009469
< .00003563
< .00002500
< .00003299
< .00008581
< .00005555
.00218150
<. 00001352
< .00002214
< .00001722
Spent Brine
Great Lakes
Central
< .00022142
<. 00019166
.00034833
<. 00013783
.00026840
< .00007903
.00513620
< .00002138
.00013147
< .00003298
.00366920
<. 00001 135
< .00002447
<. 00001 124
.02792000
< .00004848
< .00002523
< .00001770
< .00002336
<. 00005518
< .00005589
.00068519
<. 00001 170
< .00002571
< .00001491
Concentration By
Great Lakes
Newell
.00071602
< .00033134
< .00031967
< .00017661
.00046404
<. 0001 1452
.00423780
< .00006198
.00098731
< .00004420
.00372540
< .00003091
< .00002416
.00236880
.03643200
< .00004013
< .00002589
< .00001816
< .00002397
< .00003842
< .00004570
< .00001548
< .00001589
< .00002082
< .00002024
Facility
Albermarle
South
<. 00028155
< .00042342
< .00034956
<. 00019757
.00036623
<. 0001 1267
.00362250
< .00003790
<. 00002631
< .00006891
.00308250
< .00003505
< .00003759
< .00003470
.01255200
< .00006536
< .00004273
< .00002998
< .00003957
< .00006162
< .00006380
< .00003750
<. 00001380
< .00002087
< .00001758
Drinkin
Stan
Great Lakes
Mvrlle mg/1
< .00016798 0.001
< .00014541
< .00009583
< .00013176
.00014553
< .00006295
.00456420
.00009380
.00006360
< .00003889
.00247440
< .00002901
< .00002167
< .00002872
.00852200
< .00002957
< .00002222
< .00001559
< .00002058 0.0002
< .00003451
< .00004582
.00049219
< .00000952
< .00001375
< .00001212
j Water
, , Health Advisory Level
dard
Drimary or Cancer or
mg/1
Secondary Non Cancer
P 0.03 C
-
-
0.05 N
-
-
-
-
-
-
-
--
-
-
-
-
-
-
P 0.0002 C
-
-
-
-
--
-
Source: Arkansas Department of Environmental Quality, 1999
NOTE: The metals analyses were affected by the high dissolved solids in the sample. This resulted in very high detection limits for some metals.
A + in front of data indicates that value is less than the detection limit but tentatively reported as present.
September 30, 1999
25
-------
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Memorandum from Robert Allen to Richard Thompson, January 6, 1999.
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23, 1991.
The Cadmus Group. 1999. State-by-State Notebooks Compiling Results from the Class V
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1999.
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September 30, 1999 26
-------
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U.S. EPA. 1980. "Volume HI, Chapter 13." Multi-Media Assessment of the Inorganic Chemicals
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U.S. EPA. 1984. National secondary drinking water regulations. Publication No. USEPA 570/9-76-
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U.S. EPA. 1986. "Underground Injection Control Program Final Permit for Paradox \&lley
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1986.
U.S. EPA. 1988. "1988 Final Draft Summary Report of Mineral Industry Processing Wastes."
USEPA 2-77-2-84. Washington: USEPA Office of Solid Waste.
U.S. EPA. 1994. Region 5 UIC Permit No. MI-105-5X16-17, effective March 28, 1994 through
March 28, 2004.
U. S. EPA. 1998a. National primary drinking water regulations. 40 CFR §141.32.
U. S. EPA. 1998b. National secondary drinking water regulations. 40 CFR §143.
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September 30, 1999 27
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