DRAFT
Investigation of Ground Water
Contamination near
Pavillion, Wyoming
oEPA
United States
Environmental Protection
Agency
EPA 600/R-00/000 | December 2011 | www.epa.gov/ord
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Office of Research and Development
National Risk Management Research Laboratory, Ada, Oklahoma 74820
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DRAFT
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DRAFT
Investigation of Ground Water
Contamination near
Pavillion, Wyoming
Dominic C. DiGiulio
Richard T. Wilkin
Carlyle Miller
U.S. Environmental Protection Agency
Office of Research and Development
National Risk Management Research Laboratory
919 Kerr Research Drive
Ada, OK 74820
Gregory Oberley
U.S. Environmental Protection Agency
Region 8
1595 Wynkoop Street
Denver, CO 80202
Office of Research and Development
National Risk Management Research Laboratory, Ada, Oklahoma 74820
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Notice
This report has been reviewed and approved by the U.S. Environmental Protection Agency's Office of Research
and Development. Approval does not signify that the contents necessarily reflect the views and policies of the
Agency, nor does mention of trade names or commercial products constitute endorsement or recommendation
for use.
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Foreword
The U.S. Environmental Protection Agency (EPA) is charged by Congress with protecting the Nation's land, air,
and water resources. Under a mandate of national environmental laws, the Agency strives to formulate and
implement actions leading to a compatible balance between human activities and the ability of natural systems
to support and nurture life. The scientific arm of EPA, the Office of Research and Development (ORD), conducts
leading-edge research that helps provide the solid underpinning of science and technology for the Agency. The
work at ORD laboratories, research centers, and offices across the country helps improve the quality of air,
water, soil, and the way we use resources. The research described in this report was designed and conducted by
ORD's National Risk Management Research Laboratory in Ada, Oklahoma, working in close collaboration with
scientists from EPA Region 8 in Denver, Colorado.
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Acknowledgements
The authors would to like to acknowledge valuable comments from 1 internal and 3 external reviewers used to
improve this manuscript. We would also like to acknowledge Dr. Randall Ross, Dr. Junqi Huang, Dr. Doug Beak,
Mr. Steve Acree, Mr. Tony Lee, Mr. Ken Jewell, Mr. Tim Lankford, Mr. Russell Neil, and Ms. Kristie Hargrove
from ORD/NRMRL/Ada and Mr. Christopher Ruybal and Ms. Alexandra Kirkpatrick (student contractors) for their
assistance in collecting ground water and gas samples. We would like to acknowledge Dr. Jennifer Gundersen of
EPA's Region 3 Laboratory for conducting analysis water samples for glycols and 2-butoxyethanol and Dr.
William Batschelet of EPA's Region 8 Laboratory for conducting and arranging the analysis of water samples for a
number of classes of compounds. We also thank Mr. John Cox, Mr. Steve Markham, Ms. Tracy Pardue, Dr. Feng
Lu, Mr. Joseph Karikari, Ms. Lisa Hudson, Dr. Sujith Kumar, Mr. Joe Tyburski, Mr. David Kessler, Mr. Jim Wilson
(Shaw Environmental and Infrastructure), Mr. Mark White, Ms. Lynda Callaway, and Mr. Dennis Miller
(ORD/NRMRL/Ada) for analytical support. We would like to thank Mr. Nathan Wiser, Mr. Robert Parker, and Ms.
Johanna Miller of EPA Region 8 and Mr. Ron Mellor (SEE employee) for assistance in interpreting data and
numerous helpful comments. We would like to acknowledge Mr. Steve Vandegrift of ORD/NRMRL/Ada for
providing helpful comments in improving QA/QC aspects of this investigation and overseeing development of
the QAPP and ADQs. We would like to acknowledge Dr. John Wilson for assistance in interpretation of data. We
are grateful to Ms. Ayn Schmit of EPA Region 8 and Dr. David Jewett of ORD/NRMRL/Ada for ongoing support in
their respective management roles and ability to effectively communicate technical details in this manuscript to
others. We would like to express our appreciation to Mr. Jeff Locker and Ms. ZoeAnn Randall for access to their
property for monitoring well installation and to Mr. Louis Meeks for access to his property for domestic well
sampling. We are grateful to Mr. John Fenton for access to his property for domestic well sampling and
facilitating contact with domestic well owners in the area. We are grateful to Ms. Kathy Tynsky of SRA for
assistance in developing graphics in this document.
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Contents
Notice ii
Foreword iii
Acknowledgements iv
Figures vi
Tables ix
Extended Abstract xi
1.0 Site Background 1
2.0 Methods 5
Sampling Chronology 5
Deep Monitoring Well Installation 5
Ground Water Sampling of Deep Monitoring Wells in Phase III and IV 11
Gas Sampling from Casing of Deep Monitoring Wells in Phase III and IV 15
Domestic Well Sampling for Methane Using a Closed System in Phase IV 15
Review of Borehole Geophysical Logs 15
Review of Cement Bond/Variable Density Logs 16
3.0 Results and Discussion 17
Ground Water and Soil Sample Results near Three Pits 17
Inorganic Geochemistry 17
Organic Geochemistry 23
Natural Gas Migration 27
Evaluation of Cement Bond/Variable Density Logs Along Transect 29
Potential Migration Pathways 32
4.0 Conclusions 33
5.0 References 40
Appendices A1
Appendix A-Summary of Analytical Results A1
Appendix B - Quality Assurance and Quality Control (QA/QC) for Analysis B1
Appendix C - Photographic Log of Deep Monitoring Well Construction CI
Appendix D - Photographic Log of Ground Water Sampling D1
Appendix E - Examples of Cement Bond/Variable Density Log Interpretation El
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Figures
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Figure 1. (a) Location of Wind River Basin in Wyoming, (b) Location of Pavillion Gas Field in the Wind River Basin.
Figure from Johnson et al. 2007 1
Figure 2. Chronology of production well completion at the Pavillion Gas Field 2
Figure 3. Histograms summarizing depths of top of perforation interval of production wells, base of surface
casing of production wells, and base of screened interval of domestic wells 2
Figure 4. Generalized stratigraphic columns and correlations of Mississippian through Eocene strata in the Wind
River Basin, Wyoming. The Pavillion Gas Field is located in the Western Wind River Basin. Figure from Johnson
et al. 2007 3
Figure 5. Map illustrating location of oil and gas production wells, sampled PGDWxx series domestic wells (only
numbers shown to conserve space), two deep monitoring wells, and three shallow monitoring wells near pits.
PGDW07 and PGDW08 are municipal wells in the town of Pavillion 6
Figure 6a. Schematic illustrating construction of MW01 9
Figure 6b. Schematic illustrating construction of MW02 10
Figure 7. Resistivity as a function of depth in MW01 and MW02. MW01 and MW02 were screened at 233 - 239
m and 293 - 299 m bgs respectively corresponding to elevated resistivity and presence of coarse-grained
sandstone. FID readings in MW01 denote detections of methane during open air logging of mud. FID
monitoring at MW02 was sporadic and is not illustrated here 11
Figure 8. Variation of water level as a function of time in M W01 during Phase 4 well purging. The initial
pumping rate was 24.2 L/min. After approximately 30 minutes of purging, the flow rate was decreased to 7.6
L/min. This reduced flow rate caused partial recovery of the water level and confirmation that formation water
was being accessed 12
Figure 9. Flow-cell readings as a function of time for specific conductance, dissolved oxygen, pH, and oxidation-
reduction potential (well MW02, Phase IV sampling) 13
Figure 10. Schematic of closed (no contact to atmosphere) sampling train for domestic wells. Water flow from
domestic well and into sparge cell was approximately 5 and 1 L/min respectively. Excess water bled through
valve used for sampling prior to sample collection. Gas flow into sparge cell and portable FID/PID sparge cell
was approximately 20 and 1 L/min. Excess air was bled through splitter above sparge cell 16
Figure 11. Durov diagram showing ground water chemistry trends obtained in Phase I - IV sampling events and
the composition of irrigation water 17
Figure 12. Depth trends of chloride, pH, sulfate, and potassium (filled black squares = domestic wells, filled red
circles = monitoring wells) 18
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Figure 13. Saturation indices for (a) gypsum versus sulfate concentration and (b) calcite versus calcium
concentration. Saturation Index is equal to the logarithm of the ratio of the ion activity product to the mineral
solubility product. A Saturation Index of 0 corresponds to chemical equilibrium; values less than 0 and greater
than 0 correspond to undersaturated and oversaturated conditions, respectively 19
Figure 14. Concentration trends versus specific conductivity. Note the monitoring wells show high pH and low
sulfate, calcium, and sodium relative to the general trend observed in the domestic wells (filled black squares =
domestic wells, filled red circles = monitoring wells) 21
Figure 15. (a) Results of KOH titration models plotted as pH versus grams of KOH added per kilogram of
solution. Initial water compositions are from PGDW49, PGDW20, and PGDW32. Model accounts for reactions
taking place in solution as KOH is added and equilibrated. pH range in deep monitoring wells shown for
reference; (b) Buffer Intensity plot or first derivative of titration plot, pH versus change in concentration of base
(CB) per change in pH 22
Figure 16. Hydrogen and oxygen isotope values (permil, Vienna Standard Mean Ocean Water, VSMOW) for
ground water samples (black squares=domestic wells; red circles=deep monitoring wells) relative to the Global
Meteoric Water Line from Craig (1961) 22
Figure 17. Organic compounds detected in deep monitoring wells MW01 and MW02 during Phase III and IV
sampling events 25
Figure 18. (a) Stable isotope ratios of carbon of methane versus ratio of methane (Ci) to ethane (C2) and
propane (C3) in gas from production wells, monitoring wells, and domestic wells. Values of 100,000 are used to
denote non detection of ethane and propane in samples, (b) Stable isotope ratios of carbon versus hydrogen of
methane in gas from production wells (both literature and measured values), monitoring wells, and domestic
wells. 6D was not determined for PGDW32. Oxidation pathway (enrichment of 13C of remaining CH4 with
biodegradation) is illustrated, (c) Methane concentration in domestic and monitoring wells as a function of
proximity to production wells and depth. Values of 1.0 were used for non-detection (detection limit 5 |ag/L) ....28
Figure 19. Map illustrating transect used to develop lithologic cross section and evaluation of CBL/VDLs 30
Figure 20. Lithologic cross-section along transect illustrating production wells (with evaluation of CBL/VDLs),
domestic wells, and blowout location. Red arrows denote depths of hydraulic fracturing of unknown areal
extent 31
Figure CI. Photograph of drilling rig on platform with shakers for mud recirculation at MW02 C2
Figure C2. Photograph of blowout prevention (BOP) for annular space at base of drilling rig platform at MW02
C2
Figure C3. Photograph of blowout preventer for drillstem C2
Figure C4. Photograph of bit and drillstem with bit for mud rotary drilling at MW02 C3
Figure C5. Photograph of water truck used to transport water to mix mud C4
Figure C6. Photograph of Quik-Gel bentonite (Halliburton) used to create mud for drilling C4
Figure C7. Photograph of mud additives EZ Mud Gold (Halliburton) and Dense Soda Ash C4
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Figure C8. Photograph of mud additive Penetrol (Halliburton) C4
Figure C9. Photograph of flow of mud and cuttings from borehole at MW02 C5
Figure CIO. Photograph of monitoring of mud and cuttings using a Thermo Scientific TVA-1000B FID/PID at
MW02 C5
Figure Cll. Photograph of pump used to transport mud and cuttings to shakers at MW02 C6
Figure C12. Photograph of flow of mud and cuttings to shakers at MW02 C6
Figure C13. Photograph of shakers separating mud from cuttings at MW02 C7
Figure C14. Photograph of cuttings transported to disposal bins at MW02 C8
Figure C15. Photograph of pumping of mud back to borehole at MW02 C9
Figure C16. Photograph of injection of mud to borehole at MW02 CIO
Figure C17. Photograph of collection of cuttings for lithologic characterization at MW02 Cll
Figure C18. Photograph of removal of mud from cuttings at MW02 Cll
Figure C19. Photograph of white coarse-grained sand targeted by local well drillers and media in which screens
are set in for both deep monitoring wells Cll
Figure C20. Photograph of setting of stainless-steel pre-packed screen and sand basket into borehole at MW02
C12
Figure C21. Photograph of securing sand basket and casing above screen C13
Figure C22. Photograph of placement of sand in sandbasket C13
Figure C23. Photograph of well development at MW02 C14
Figure Dl. Photograph of flow from submersible pump through flowmeter at MW02 D2
Figure D2. Photograph of flow of water to purge water disposal tank at MW02 D2
Figure D3. Photograph (close-up) of flow of water into purge water disposal tank at MW02 D3
Figure D4. Photograph of water (foaming) flowing into YSI flow cell at MW02 D3
Figure D5. Photograph of sampling at MW02. The sample train was split prior to entry into purge water
disposal container D4
Figure D6. Photograph of field filtering samples for metals analysis at MW02 D4
Figure D7. Photograph of sample collection at PGDW14 D5
Figure D8. Photograph of cooler packed with samples for shipment D5
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Figure El. Example of CBL/VDL indicating "no cement" at Pavillion Fee 34-03B. The CBL/VDL indicates no
cement 2750 feet below ground surface at the time of logging
E2
Figure E2. Example of "sporadic bonding" at Pavillion Fee 41-10 from 1000 to 1640 ft bgs. Hydraulic fracturing
occurred at 1618 feet below ground surface. Arrow denotes interval of hydraulic fracturing E3
Figure E3a. Example of "sporadic bonding" at Pavillion Fee 11-11B. Hydraulic fracturing occurred at 1516 feet
below ground surface. Arrow denotes interval of hydraulic fracturing. Depths on CBL/VDL difficult to read and
inserted on left margin E4
Figure E3b. Example of "sporadic bonding" Pavillion Fee 11-11B between 2350-3200 feet below ground suface.
Hydraulic fracturing occurred at 3165 feet below ground surface. Arrow denotes interval of hydraulic fracturing.
Depths on CBL/VDL difficult to read and inserted on left margin E5
Figure E4. Example of "Sporadic Bonding" at Tribal Pavillion 24-02. Hydraulic fracturing occurred at 1538 feet
bgs. Arrow denotes interval of hydraulic fracturing E6
Figure E5. Example of "Good Bonding" (from surface casing at 645 ft bgs to 820 ft bgs) followed by "Sporadic
Bonding" (from 820 ft bgs 1310 ft bgs) to "Good Bonding" at 1310 to target depth at Pavillion Fee 41-10B E7
Tables
Table 1. Drilling additives, properties and product use recommendations 7
Table 2. Analytical results of additives (compounds listed are those detected in ground water) 8
Table 3. Geochemical impacts in deep ground water monitoring wells 24
Table 4. Association of inorganic and organic anomalies with compounds used for hydraulic fracturing 26
Table Al. Summary of subsurface sample locations, depth of sample collection, times (phases) of sampling,
target analytes, laboratories utilized, and analytical methods A2
Table A2a. Geochemical results for Pavillion ground water A8
Table A2b. Charge balance calculations for deep monitoring wells A9
Table A3a. Summary of aqueous analysis of light hydrocarbons A10
Table A3b. Summary of gas and headspace analysis of light hydrocarbons A12
Table A3c. Summary of isotopic data for dissolved, gas phase, and headspace analysis A14
Table Bl. Sample collection containers, preservation, and holding times for ground water samples B2
Table B2. Field QC samples for ground water analysis B3
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Table B3. QA/QC requirements for analysis of metals and major ions B3
Table B4. QA/QC requirements for analysis of dissolved gases, DIC/DOC, VOCs, low molecular weight acids and
stable isotopes of water B4
Table B5. QA/QC requirements for analysis of semi-volatiles, GRO, and DRO B5
Table B6. QA/QC requirements for LC/MS/MS analysis of glycols B6
TableB7a. ICP-OES blank results for Phase III and Phase IV sampling B7
Table B7b. ICP-OES blank results for Phase III and Phase IV sampling B7
Table B7c. ICP-MS blank results for Phase III and Phase IV sampling B8
Table B8. Blank results for Capillary Electrophoresis, Lachat Flow Injection Analysis, Dissolved Inorganic Carbon
(DIC) and Dissolved Organic Carbon analyses for Phase III and Phase IV sampling B8
Table B9. Blank results for Volatile Organic Compounds (|ag/L) in Phase III and Phase IV sampling (Region 8
laboratory, Golden, CO) B9
Table BIO. Blank results for Volatile Organic Compounds (|ag/L) in Phase IV sampling (ORD laboratory, Ada, OK)
Bll
Table Bll. Blank results for Semi-Volatile Organic Compounds (i-ig/L) in Phase III and Phase IV sampling (Region
8 laboratory, Golden, CO) B12
Table B12. Blank results for GRO and DRO analyses for Phase III and Phase IV sampling (Region 8 laboratory,
Golden, CO) and blank results for glycol ethers in Phase IV sampling (Region 3 laboratory, Fort Meade, MD) . B13
Table B13. Duplicate data for selected major ions, DOC, and DIC in ground water samples collected during
Phase III and Phase IV sampling activities B14
Table B14. Duplicate data for methane and selected dissolved organic compounds in ground water samples
collected during Phase III and Phase IV sampling activities B15
Table B15. QA/QC requirements for analysis of 613C of DIC B16
Table B16. QA/QC requirements for analysis for 613C and 6D of light hydrocarbons for aqueous and gas samples
B16
Table B17. QA/QC requirements for analysis of fixed gases and light hydrocarbons for aqueous and gas samples
B16
Table B18. Summary of quality control samples, purpose, method, and frequency to support gas analysis B17
Table B19. Summary of analytes, instruments, calibration, and check standards for portable gas analyzers.... B17
Table B20. QA/QC Requirements for portable gas analyzers B17
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Extended Abstract
In response to complaints by domestic well owners regarding objectionable taste and odor problems in well
water, the U.S. Environmental Protection Agency initiated a ground water investigation near the town of
Pavillion, Wyoming under authority of the Comprehensive Environmental Response, Compensation, and Liability
Act. The Wind River Formation is the principal source of domestic, municipal, and stock (ranch, agricultural)
water in the area of Pavillion and meets the Agency's definition of an Underground Source of Drinking Water.
Domestic wells in the area of investigation overlie the Pavillion gas field which consists of 169 production wells
which extract gas from the lower Wind River Formation and underlying Fort Union Formation. Hydraulic
fracturing in gas production wells occurred as shallow as 372 meters below ground surface with associated
surface casing as shallow as 110 meters below ground surface. Domestic and stock wells in the area are
screened as deep as 244 meters below ground surface. With the exception of two production wells, surface
casing of gas production wells do not extend below the maximum depth of domestic wells in the area of
investigation. At least 33 surface pits previously used for the storage/disposal of drilling wastes and produced
and flowback waters are present in the area. The objective of the Agency's investigation was to determine the
presence, not extent, of ground water contamination in the formation and if possible to differentiate shallow
source terms (pits, septic systems, agricultural and domestic practices) from deeper source terms (gas
production wells).
The Agency conducted four sampling events (Phase I - IV) beginning in March 2009 and ending in April, 2011.
Ground water samples were collected from domestic wells and two municipal wells in the town of Pavillion in
Phase I. Detection of methane and dissolved hydrocarbons in several domestic wells prompted collection of a
second round of samples in January, 2010 (Phase II). During this phase, EPA collected additional ground water
samples from domestic and stock wells and ground water samples from 3 shallow monitoring wells and soil
samples near the perimeter of three known pit locations. Detection of elevated levels of methane and diesel
range organics (DRO) in deep domestic wells prompted the Agency to install 2 deep monitoring wells screened
at 233 - 239 meters (MW01) and 293 - 299 meters (MW02) below ground surface, respectively, in June 2010 to
better evaluate to deeper sources of contamination. The expense of drilling deep wells while utilizing blowout
prevention was the primary limiting factor in the number of monitoring wells installed. In September 2010
(Phase III), EPA collected gas samples from well casing from MW01 and MW02. In October 2010, EPA collected
ground water samples from MW01 and MW02 in addition to a number of domestic wells. In April 2011 (Phase
IV), EPA resampled the 2 deep monitoring wells to compare previous findings and to expand the analyte list to
include glycols, alcohols, and low molecular weight acids.
Detection of high concentrations of benzene, xylenes, gasoline range organics, diesel range organics, and total
purgeable hydrocarbons in ground water samples from shallow monitoring wells near pits indicates that pits are
a source of shallow ground water contamination in the area of investigation. When considered separately, pits
represent potential source terms for localized ground water plumes of unknown extent. When considered as
whole they represent potential broader contamination of shallow ground water. A number of stock and
domestic wells in the area of investigation are fairly shallow (e.g., < 30 meters below ground surface)
representing potential receptor pathways.
Determination of the sources of inorganic and organic geochemical anomalies in deeper ground water was
considerably more complex than determination of sources in shallow media necessitating the use of mulitiple
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lines of reasoning approach common to complex scientific investigations. pH values in MW01 and MW01 are
highly alkaline (11.2-12.0) with up to 94% of the total alkalinity contributed by hydroxide suggesting addition of
a strong base as the causative factor. Reaction path modeling indicates that sodium-sulfate composition of
ground water typical of deeper portions of the Wind River Formation provides little resistance to elevation of pH
with small addition of potassium hydroxide. Potassium hydroxide was used in a crosslinker and in a solvent at
this site.
The inorganic geochemistry of ground water from the deep monitoring wells is distinctive from that in the
domestic wells and expected composition in the Wind River formation. Potassium concentration in MW02 (43.6
milligrams per liter) and MW01 (54.9 milligrams per liter) is between 14.5 and 18.3 times values in domestic
wells and expected values in the formation. Chloride concentration in monitoring well MW02 (466 milligrams
per liter) is 18 times the mean chloride concentration (25.6 milligrams per liter) observed in ground water from
domestic wells and expected in the formation. Chloride enrichment in this well is significant because regional
anion trends show decreasing chloride concentration with depth. In addition, the monitoring wells show low
calcium, sodium, and sulfate concentrations compared to the general trend observed in domestic well waters.
The formulation of fracture fluid provided for carbon dioxide foam hydraulic fracturing jobs typically consisted of
6% potassium chloride. Potassium metaborate was used in crosslinkers. Potassium hydroxide was used in a
crosslinker and in a solvent. Ammonium chloride was used in crosslinker.
A number of synthetic organic compounds were detected in MW01 and MW02. Isopropanol was detected in
MW01 and MW02 at 212 and 581 micrograms per liter, respectively. Diethylene glycol was detected in MW01
and MW02 at 226 and 1570 micrograms per liter, respectively. Triethylene glycol was detected in MW01 and
MW02 at 46 and 310 micrograms per liter, respectively. Another synthetic compound, ferf-butyl alcohol, was
detected in MW02 at a concentration of 4470 micrograms per liter. Isopropanol was used in a biocide, in a
surfactant, in breakers, and in foaming agents. Diethylene glycol was used in a foaming agent and in a solvent.
Triethylene glycol was used in a solvent, ferf-butyl alcohol is a known breakdown product of methyl ferf-butyl
ether (a fuel additive) and ferf-butyl hydroperoxide (a gel breaker used in hydraulic fracturing). Material Safety
Data Sheets do not indicate that fuel or tert-butyl hydroperoxide were used in the Pavillion gas field. However,
Material Safety Data Sheets do not contain proprietary information and the chemical ingredients of many
additives. The source of ferf-butyl alcohol remains unresolved. However, ferf-butyl alcohol is not expected to
occur naturally in ground water.
Benzene, toluene, ethylbenzene, and xylenes (BTEX) were detected in MW02 at concentrations of 246, 617, 67,
and 750 micrograms per liter, respectively. Trimethylbenzenes were detected in MW02 at 105 micrograms per
liter. Gasoline range organics were detected in MW01 and MW02 at 592 and 3710 micrograms per liter. Diesel
range organics were detected in MW01 and MW02 at 924 and 4050 micrograms per liter, respectively.
Aromatic solvent (typically BTEX mixture) was used in a breaker. Diesel oil (mixture of saturated and aromatic
hydrocarbons including naphthalenes and alkylbenzenes) was used in a guar polymer slurry/liquid gel
concentrate and in a solvent. Petroleum raffinates (mixture of paraffinic, cycloparaffinic, olefinic, and aromatic
hydrocarbons) were used in a breaker. Heavy aromatic petroleum naphtha (mixture of paraffinic, cycloparaffinic
and aromatic hydrocarbons) was used in surfactants and in a solvent. Toluene and xylene were used in flow
enhancers and a breaker.
Detections of organic chemicals were more numerous and exhibited higher concentrations in the deeper of the
two monitoring wells. Natural breakdown products of organic contaminants like BTEX and glycols include
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acetate and benzoic acid. These breakdown products are more enriched in the shallower of the two monitoring
wells, suggesting upward/lateral migration with natural degradation and accumulation of daughter products.
Hydraulic gradients are currently undefined in the area of investigation. However, there are flowing conditions
in a number of deep stock wells suggesting that upward gradients exist in the area of investigation.
Alternative explanations were carefully considered to explain individual sets of data. However, when considered
together with other lines of evidence, the data indicates likely impact to ground water that can be explained by
hydraulic fracturing. A review of well completion reports and cement bond/variable density logs in the area
around MW01 and MW02 indicates instances of sporadic bonding outside production casing directly above
intervals of hydraulic fracturing. Also, there is little lateral and vertical continuity of hydraulically fractured tight
sandstones and no lithologic barrier (laterally continuous shale units) to stop upward vertical migration of
aqueous constituents of hydraulic fracturing in the event of excursion from fractures. In the event of excursion
from sandstone units, vertical migration of fluids could also occur via nearby wellbores. For instance, at one
production well, the cement bond/variable density log indicates no cement until 671 m below ground surface.
Hydraulic fracturing occurred above this depth at nearby production wells.
A similar lines of reasoning approach was utilized to evaluate the presence of gas in monitoring and domestic
wells. A comparison of gas composition and stable carbon isotope values indicate that gas in production and
monitoring wells is of similar thermogenic origin and has undergone little or no degradation. A similar
evaluation in domestic wells suggests the presence of gas of thermogenic origin undergoing biodegradation.
This observation is consistent with a pattern of dispersion and degradation with upward migration observed for
organic compounds.
Elevated levels of dissolved methane in domestic wells generally increase in those wells in proximity to gas
production wells. Near surface concentrations of methane appear highest in the area encompassing MW01.
Ground water is saturated with methane at MW01 which is screened at a depth (239 meters below ground
surface) typical of deeper domestic wells in the area. A blowout occurred during drilling of a domestic well at a
depth of only 159 meters below ground surface close to MW01. A mud-gas log conducted in 1980 (prior to
intensive gas production well installation) located only 300 m from the location of the blowout does not indicate
a gas show (distinctive peaks on a gas chromatograph) within 300 meters of the surface. Again, with the
exception of two production wells, surface casing of gas production wells do not extend below the maximum
depth of domestic wells in the area of investigation. A number of production wells in the vicinity of MW01 have
sporadic bonding or no cement over large vertical instances. Again, alternate explanations of data have been
considered. Although some natural migration of gas would be expected above a gas field such as Pavillion, data
suggest that enhanced migration of gas has occurred within ground water at depths used for domestic water
supply and to domestic wells. Further investigation would be needed to determine the extent of gas migration
and the fate and transport processes influencing migration to domestic wells.
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1.0
Site Background
In early 2008, the U.S. Environmental Protection
Agency (EPA) received complaints from several
domestic well owners near the town of Pavillion,
Wyoming regarding sustained objectionable taste and
odor problems in well water following hydraulic
fracturing at nearby gas production wells. In response
to these complaints, EPA initiated a comprehensive
ground water investigation in September 2008 under
authority of the Comprehensive Environmental
Response, Compensation, and Liability Act. The area
of investigation is a sparsely populated rural area in
west-central Wyoming directly east of the town of
Pavillion. Land use by residents consists primarily of
ranching (horse and cattle) and alfalfa hay production
for use by ranchers and commercial sale. Fields are
periodically flooded using water obtained from canals
and laterals.
Domestic wells in the area of investigation overlie the
Pavillion gas field which is one of several gas fields
within the Wind River Basin - a large, complex,
structural, asymmetric, deep sedimentary basin
covering much of central Wyoming (Figure 1). Oil and
gas exploration wells were drilled in the 1950s.
Commercial natural gas extraction in the field
commenced in 1960 (Single 1969) with gas production
well installation activity intensifying in the late 1990s
through 2006 (Figure 2). The field currently consists
of approximately 169 vertical production wells.
Ninety-seven production wells are designated as
"Tribal Pavillion" and are regulated by the U.S. Bureau
of Land Management (BLM). The remaining wells are
designated as "Pavillion Fee" and are regulated by
Wyoming Oil and Gas Conservation Commission
(WOGCC).
Figure 1. (a) Location of Wind River Basin in
Wyoming, (b) Location of Pavillion gas field
in the Wind River Basin. Figure from
Johnson et al. 2007.
I I Oil field
¦ Gas Field
WRB Province
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40-r
35-
30-
w
25-
i
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20-
o
T1
15-
O
D.
10-
5-
0-
ii
Figure 2. Chronology of production well completion
at the Pavillion gas field.
A review of production well records obtained on line
from WOGCC indicates that hydraulic fracturing in gas
production wells occurred as shallow as 372 m (1220
ft) below ground surface (bgs) with associated surface
casing in production wells as shallow as 110 m (361 ft)
bgs. Information obtained from the Wyoming State
Engineer's Office and homeowners indicates that
domestic wells (including stock wells) in the area of
investigation are screened as deep as 244 m (800 ft)
bgs. With the exception of two production wells,
surface casings of gas production wells do not extend
below the maximum depth of domestic wells in the
area of investigation (Figure 3).
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Gas extraction occurs from both the lower Eocene
Wind River Formation and underlying Paleocene Fort
Union Formation (Figure 4). The Wind River
Formation consists of interbedded layers of
sandstones and shale with coarse-grained meandering
stream channel deposits (Osiensky et al. 1984) and
extends from the surface to approximately 1036 m
(3400 ft) bgs. The Fort Union Formation ranges in
thickness from 762 to 914 m (2500 to 3000 ft) in the
area (Flores and Keighin 1993). The Waltman Shale
Member in the Fort Union Formation is absent below
the Pavillion Gas Field. The most productive zone of
gas extraction in the Wind River Formation occurs at
its base and is often targeted for gas extraction (Single
1969). Gas trapping in the lower Wind River and Fort
Union Formations occurs in localized stratigraphic
sandstone pinchouts on the crest and along flanks of a
broad dome (Mueller 1989, Keefer and Johnson 1993).
30-J
20-
c
o
m-
u
0-
120-
c
80-
3
o
O
40-
0-
15-r
12-
9-
o
6-
U
3-
0 T
X
>0 1000 1250
Depth bgs (m)
Figure 3. Histograms summarizing depths of top of
perforation interval of production wells, base of
surface casing of production wells, and base of
screened interval of domestic wells.
There is substantial vertical and lateral stratigraphic
variation over short distances in both formations
(Single 1969, Flores and Keighin 1993). Individual
productive sandstones in the two formations generally
vary in thickness from 1 to 21 m with permeability
varying from 0.1 to 300 millidarcies and porosity
ranging from 4 to 28 percent (Single 1969). Gas from
the Fort Union and lower Wind River Formations
varies little in 613C for methane, ethane, and propane
with depth from the lower Eocene Wind River
Formation to deeper mature and post-mature Upper
Cretaceous source rocks (Figure 4) suggesting upward
gas migration (Johnson and Rice 1993, Johnson and
Keighin 1998) from deep source rocks. 613C is defined
as
813C(%o) =
(13C/12Cjsample
13C/12C)standard
--1
x1000
where the standard is the Pee Dee Belemnite (PDB)
reference standard. Stable isotope ratios are reported
as the relative difference in the ratio of the less
abundant heavier isotope to the more abundant
lighter isotope of the sample with respect to a
2
-------
DRAFT
System
Series
Western Wind River Basin
Southern and central
Wind River Basin
Eastern Wind River Basin
03
Q.
>
CL
<
I—
CL
LLI
LU
2 _
lu e
U to
OB
LlI
UJ
O
O
LU
<
CL
U1
ID
O
LU
o
£
UJ
CL
O
CL
UJ
CL
CL
3
CL
PERMIAN
Wind River and
Indian Meadows Formations
Wind River and
Indian Meadows Formations
Wind River and
Indian Meadows Formations
JURASSIC/
TRIASSIC
PENNSYLVANIAN
(part)
Shotgun
Member
Lower member
Lance
Formation
3
Meeteetse
Formation
Waltman Shale
Member
Lower member
Lance
Formation
,—
Meeteetse Formation
and
Lewis Shale undivided
Teapot Sandstone
Member
Parkman Sandstone M-'inlii-t
_ Wallace Creek Tongue ot Cody Shale
Fates Sandstone Member
Cody Shale
_ JJ£per sa ndyjriember
Upper sandy
member
Lower shalv member
Lower shaly member
Upper sandy meniber
Cody Shale
Lower shaly member
Frontier Formation
Frontier Formation
Frontier Formation
Mowry Shale
Muddy Sandstone
Thermopolis Shale
Cloverly Formation
Jurassic and Triassic rocks undifferentiated
Phosphoria/Park City/ Goose Egg Formation
Tensleep Sandstone
Eastern
Wind
River Basin
Figure 4. Generalized stratigraphic columns and correlations of Mississippian through Eocene strata in the Wind River
Basin, Wyoming. The Pavillion Gas Field is located in the Western Wind River Basin. Figure from Johnson et al. 2007.
3
-------
DRAFT
reference standard. Ratios are expressed in parts per
thousand or permil (%o). A substantial amount of
additional compositional and isotopic data is available
on the Wind River and Fort Union Formations but is
classified as Confidential Business Information by the
gas field operator.
Ground water from the upper Wind River Formation is
the principal source of domestic, municipal, and stock
(ranching, agriculture) water in the Pavillion area (WY
State Water Plan 2003). The Wind River Formation
meets the definition of an Underground Source of
Drinking Water (USDW) under the United States Code
of Federal Regulations, Title 40, Section 144.3. Water
yields from wells in the upper Wind River Formation
range up to 11,300 L/min with total dissolved-solids
(TDS) concentrations ranging from 100 to 5,110 mg/L
(WY State Water Plan 2003, Daddow 1996). The town
of Pavillion has five municipal wells screened at
depths ranging from 122 to 158 m bgs with average
daily use estimated at 60,000 L/day (WY State Water
Plan 2003). Fluids used for hydraulic fracturing were
injected directly into the Wind River Formation.
-------
2.0
Methods
Sampling Chronology
Four sampling events (Phase I - IV) were conducted
commencing in March 2009 and ending in April 2011.
In March 2009 (Phase I), EPA collected aqueous
samples from 35 domestic wells (including two
samples from post reverse osmosis systems) in the
area of investigation and 2 municipal wells in the town
of Pavillion. Detection of methane and dissolved
hydrocarbons in several domestic wells prompted
collection of a second round of samples in January
2010 (Phase II). During this phase, EPA collected: (1)
ground water samples from 17 domestic wells (10
previously sampled), 4 stock wells, and 2 municipal
wells; (2) a filter sample from a reverse osmosis
system; (3) surface-water and sediment samples from
5 locations along Five-Mile Creek (a creek traversing
the area of investigation); (4) gas and produced
water/condensate samples (organic compounds only)
from 5 production wells; and (5) ground water
samples from 3 shallow monitoring wells and soil
samples near the perimeter of three known pit
locations.
Detection of elevated levels of methane and diesel
range organics (DRO) in deep domestic wells
prompted EPA to install 2 deep monitoring wells in
June 2010 to differentiate potential deep (e.g., gas
production related) versus shallow (e.g., pits) sources
of ground water contamination. Monitoring wells
MW01 and MW02 were screened at 233 - 239 m (765
- 785 ft) and 293 - 299 m (960 - 980 ft) bgs,
respectively. The expense of drilling deep wells while
utilizing blowout prevention was the primary limiting
factor in the number of monitoring wells installed. In
September 2010 (Phase III), EPA collected gas samples
from well casing from MW01 and MW02. In October
2010, EPA collected ground water samples from
MW01 and MW02 in addition to a previously
unsampled domestic well and two previously sampled
domestic wells. In April 2011 (Phase IV), EPA
resampled the 2 deep monitoring wells to compare
previous findings and expand the analyte list to
include glycols, alcohols, and low molecular weight
acids. Eight previously sampled domestic wells and
three previously sampled stock/irrigation wells were
also sampled at this time. Sampling chronology and
analytical methods for all sampling events are
summarized in Table Al. The location of production
wells, monitoring wells, and sampled domestic wells is
illustrated in Figure 5.
Deep Monitoring Well Installation
EPA installed two deep monitoring wells (designated
as MW01 and MW02) using air (0 - 6 m bgs) and mud
rotary (6 m bgs to target depth). Mud rotary was
selected for installation of deep monitoring wells
because it allowed the use of blowout prevention
(BOP). Use of mud rotary with BOP was necessary
given that a blowout occurred during installation of a
domestic well at only 159 m (522 ft) bgs in December
2005 in the vicinity of MW01. Both deep monitoring
wells were located away from gas production wells,
known locations of pits, and areas of domestic waste
disposal (abandoned machinery). There were no
incidents of fuel spillage used to power pumps and
generators.
Mud rotary required the use of drilling mud to remove
cuttings and additives to avoid heaving of shale during
drilling and well placement. Jet Lube Well Guard
hydrocarbon free lubricant was used for outside
threads for drillstem and submersible pipe
connections. Mud composition consisted of formation
water, municipal drinking water from Riverton, WY
(transported on site by water truck), Quik-Gel high
yield bentonite and additives listed on Table 1.
Municipal water was mixed with bentonite to create
drilling mud. The pH of mud during drilling varied
between pH 8 - 9. Aqua-Clear (Halliburton) was used
during well development to facilitate removal of mud.
Drilling additives were extracted in water (1:20 to
1:100 dilution) and analyzed for pH, inorganics,
organics, glycols, and alcohols. Despite the highly
concentrated nature of these solutions (not
5
-------
• f • • »
» "MW02*J*
.. * • • L002
Figure 5. Map illustrating location of oil and gas production wells, sampled PGDWxx series domestic wells (only numbers shown to
conserve space), two deep monitoring wells, and three shallow monitoring wells near pits. PGDW07 and PGDW08 are municipal
wells in the town of Pavillion.
Legend
• Oil and Gas Wells
• EPA Deep Monitoring Wells
• Sampled Domestic Wells
Pit Monitoring Wells
2,000
4,000
6,000
8,000 Meters
O
JO
>
CT)
-------
DRAFT
Table 1. Drilling additives, properties and product use recommendations
Ingredient
Manufacturer
Purpose
Composition from
MSDS
Specific gravity
Recommended
mixture with
water (wt/wt)
pH
Properties
Aqua-Clear
PFD
Halliburton
Dispersant/
mud
removal
anionic
polyacrylamide
(30-60%)
1.2-1.4
1:2500
neat
6.5 to 7.5
liquid
Penetrol
Halliburton
Non-ionic
wetting
agent
diethanolamine
(1-5%) and coco
diethanolamide
(10-30%)
0.98
1:400 to 1:100
1%
solution
9.5
liquid
EZ-Mud Gold
Halliburton
Clay/shale
stabilizer
"no hazardous
substances"
0.8-1
1:1400 to 1:350
1%
solution
7.75
solid
Dense Soda
Ash
OCI Chemical
Corp
Improve
bentonite
Sodium carbonate
(100%)
Ts
_____
~5%
solution
11.5
solid
Quik-Gel
Halliburton
Viscosifier/
bentonite
ae-to- te (60%),
crystalline silica
quartz (1-5%),
crystalline silica
cristobalite (0-1%),
crystalline silica
tridymite (0-1%).
2.6
1:60 to 1:30
3%
solution
8.9
solid
Quik-Trol
Gold
Halliburton
Ease of
mixing and
improved
filtration
cellulose derivative
(polysaccharide)
(60-100%)
0.6-0.9
1:3500 to 1:200
1%
solution
6-8
(listed)
solid
representative of significantly lower levels in drilling
mud, see recommended product use mixture listed in
Table 1), the pH of samples varied between 6.6 to
11.2, potassium varied between 0.1 to 1.2 mg/L,
chloride varied between not detected to 214 mg/L,
ethanol and isopropanol detections were less than 90
Hg/L, and acetone, ferf-butyl alcohol (TBA), benzene,
toluene, ethylbenzene, xylenes (BTEX),
trimethylbenzenes, and glycols were not detected
(Table 2). Organics were not analyzed in the dense
soda ash and Quik-Gel because dissolved organic
carbon concentrations were low and because of
difficulties in analyzing the viscous gel (Quik-Gel).
Since inorganic and organic concentration patterns
measured in the drilling additives do not match
patterns observed in the deep monitoring wells and
because large volumes of ground water were
extracted from the wells during development and
prior to sampling, it is unlikely that ground water
chemistry was impacted by drilling additives.
Composite samples of cuttings were collected and
sent to TestAmerica Laboratories in Denver, Colorado
for Toxic Characteristic Leaching Procedure (TCLP).
Samples were analyzed for TCLP volatile organic
compounds using gas chromatography-mass
spectrometry (GC-MS) in accordance with EPA SW-846
Methods 1311/8260B, and for TCLP semivolatile
organic compounds (GC-MS) in accordance with EPA
SW-846 Methods 1311/8270C, for TCLP metals in
accordance with EPA SW-846 Methods 1311/ 6010B,
for TCLP mercury in accordance with EPA SW-846
Methods 1311/7470A. Acetone, toluene, and m & p-
xylene were detected in one sample at 6.9, 0.63, and
1.0 |-ig/L, respectively. Cuttings were disposed offsite
in a landfill.
A photographic log of drilling, mud circulation,
examination of cuttings, screen placement, and well
development is provided in Appendix C. Well
construction schematics are provided for MW01 and
-------
DRAFT
Table 2. Analytical results of additives (compounds listed are those detected in ground water)
Aqua-Clear
PFD
Penetrol
EZ-Mud
Gold
Dense
Soda Ash
Quik-Gel
Blank
Extraction ratio
(wt/wt)
1:20
1:20 1:100 1:100
1:100
pH measured
7.96
8.51
6.64
11.2
8.35
Specific
Conductance
(mS/cm)
13.3
0.47
0.24
15.5
0.20
Dissolved Organic
Carbon (ppm)
1640 (1650)t
1500
388
0.58
2.11
0.28
CI (ppm)
214 (230) +
85 2.22 7.03
nd
nd
S04 (ppm)
121 (117) t
597 nd nd
3.53
nd
K (ppm)
0.40 (0.40) t
0.63 1.16 0.12
0.09
0.07*
Acetone (ng/L)
nd
nd
nd
nd
nd
Tert-butyl alcohol
(^g/L)
nd
nd
nd
nd
nd
nd
Isopropanol (|ig/L)
85(87)+*
43*
27*
--
Ethanol (ng/L)
59(62)+*
58*
nd
Benzene(ng/L)
nd
nd
nd
...
Toluene (ng/L)
nd
nd
nd
nd
nd
nd
Ethylbenzene
(Hg/L)
nd
nd
nd
Xylene
(Hg/L)
nd
nd
nd
Trimethylbenzenes
(Hg/L)
nd
nd
nd
nd
Naphthalene
nd
2.00
nd
"
nd
Ethylene glycol
(ng/i)
nd
nd
nd
nd
Diethylene glycol
(Hg/L)
nd
nd
nd
nd
nd - not detected. — not measured. Drilling additives were extracted at the specified weight ratio into deionized water,
t - Duplicate analysis. Blank sample is analysis of water used for the extraction of drilling additives, * Concentration above
minimum detection limit, but below the level of quantification.
MW02 in Figures 6a and 6b, respectively. During
installation of MW02, cuttings were allowed to settle
at the cessation of drilling and form a 5 m (17 ft) base
for placement of the screen. Cuttings were never
added to the borehole. Since a significant vertical
distance existed between the depth of drilling and
screen placement at MW01, cement grout was utilized
to form the base for screen placement. No lubricants
were used to attach sections of casing or casing to
screens. Well screens, sections of casing and tremie
pipe were mounted above ground (never touched soil)
and power washed (no detergents used) prior to
(deployment. Locations of both MW01 and MW02
were in fields used for alfalfa hay production away
from production wells, pads, and pits.
Cuttings were continuously examined during drilling
by manually washing drilling mud from rock fragments
with observations recorded as a function of depth in
borehole logs. At the cessation of drilling, open-hole
geophysical logging (caliper, density, resistivity,
spontaneous potential, natural gamma) was
conducted by Colog Inc., prior to placement of well
8
-------
DRAFT
-------
DRAFT
-------
construction materials. Examination of resistivity and
cuttings indicated elevated resistivity at depths where
white coarse-grained sandstone was observed. This
relationship was utilized to place screens at both deep
monitoring wells at the deepest observed interval of
white coarse-grained sand (Figure 7). White coarse-
grained sandstones in the area of investigation
contain little or no shale and are targeted by local well
drillers for domestic well installation. During drilling,
mud and cuttings were monitored in an open
atmosphere with a TVA-1000B Thermo-Scientific
portable flame- and photo-ionization detector
(FID/PID) for health and safety monitoring.
Comparison of FID and PID readings (PID readings
remained at background and are not sensitive to
methane) indicates the presence of methane at
various intervals from ground surface in MW01
(Figure 7).
Depth (m bgs)
Figure 7. Resistivity as a function of depth in MW01
and MW02. MW01 and MW02 were screened at
233 - 239 m and 293 - 299 m bgs, respectively,
corresponding to elevated resistivity and presence
of coarse-grained sandstone. FID readings in IV1W01
denote detections of methane during open air
logging of mud. FID monitoring at MW02 was
sporadic and is not illustrated here.
Ground Water Sampling of Deep Monitoring
Wells in Phase III and IV
Ground water in deep monitoring wells was sampled
using dedicated explosion proof submersible pumps
(10-cm Franklin Electric 3HP). Wells were purged at a
flow rate of approximately 5 to 30 L/min. The rate of
pumping was measured using a Model TM0050 in-line
turbine flow meter with associated Model FM0208
flow monitor manufactured by Turbines, Inc.
Drawdown during pumping was measured with a
sonic water level sensor obtained from Eno Scientific,
Inc. (Model WS2010 PRO). The flow was split, with
one portion going to waste and the other portion
going to a flow-cell equipped with a YSI 5600
multiparameter probe to track stabilization of pH
(<0.02 standard units per minute), oxidation-reduction
potential (<2 mV per minute), specific conductance
(<1% per minute), dissolved oxygen (DO), and
temperature. Purge volumes prior to sampling ranged
from about 200 to 450 L (Phase III) and 1100 to 1250 L
(Phase IV). Lower purge volumes in Phase III sampling
were due to initial gas invasion into the screened
intervals that caused cavitation and concern about
prolonged pump operation. By the time of Phase IV
sampling, disruptive gas invasion was no longer
observed and extended purging was possible.
Turbidity ranged from 1.7 to 29.7 Nephelometric
Turbidity Units (NTUs) in domestic wells (Phase III and
IV). Turbidity in MW01 was 7.5 NTUs in Phase III and
7.9 NTUs in Phase IV. Turbidity in MW02 was 28.8
NTUs in Phase III and 24.0 NTUs in Phase IV. Turbidity
measurements in MW01 and MW02 could be
impacted by gas exsolution. A photographic log of
deep monitoring and domestic well sampling is
provided in Appendix D.
In April 2011, the static water level in MW01 prior to
purging was 61.2 m (200.8 ft) below the top of the
casing (BTOC) measured using the Well Sounder 2010.
The initial pumping rate was approximately 27.6
L/min. The pumping rate declined during purging to
approximately 24.2 L/min as a result of the increasing
depth to water. At approximately 30 min after the
li
-------
DRAFT
start of purging, the pumping rate was reduced using
an in-line valve to 7.6 L/min. This resulted in
approximately 18.2 m (60 ft) of rebound in the water
level within the well at the start of sampling (Figure 8).
Given that the screen length is only 6.1 m (20 ft) and
that the pump was set approximately 0.6 m (2 ft)
above the screen, this indicates that ground water
obtained during sampling was derived from the
formation with no component of casing storage. The
total volume of water purged at the start of sampling
was approximately 1117 L. The static water level in
MW02 prior to purging was 80.5 m (264.2 ft) BTOC
measured using the Well Sounder 2010 (April 2011).
The initial pumping rate was approximately 18.9
L/min. The Eno Scientific well sounder was unable to
measure the depth to water during most of the
purging cycle perhaps due to a more rapid rate of
decline in the water level in the casing. Sampling was
initiated after approximately 1249 L of water were
removed. The pump cavitated after approximately
1287 L were purged. The pump was subsequently
stopped, allowed to cool, and restarted approximately
10 min later to complete the sampling.
Start of Sampling
O
O
l—
CD
Pumping Rate
Decreased
-------
DRAFT
m
£
8
E
CO
S
o
O
0
«E
1
Q.
CO
Note: variability likely due to off-gasing
\_
3.05 mS/ciT
10
~~r~
20
o>
E
d
©
o>
X
O
>
o
MS
(0
30 40 50
Time, mill
60
80
13.0-
12.0 -
11 5-
11,0 -
10.5-
10,0-
¦ ¦ ¦
11.78
—i—i—i—¦—i—i—i—
10 20 30 40
-50
>
E
.23 -ioo.
c
®
"5
a.
o -150
t3
n
TJ
m
cc
C -200 ¦
o
16
-a
x
o _250
0.02 mg/L
¦•¦"¦•¦-¦-I
i
10
i
20
30 40
Time, min
50
i
60
I
70
80
—] ¦ 1 1 1 r
50 60 70 80
-300
¦ ¦ Ba
-108 mV
, 1 , 1 1 \ 1 1 1 1 1 1 r
10 20 30 40 50 60 70 80
Time, min
Time, min
Figure 9. Flow-cell readings as a function of time for specific conductance, dissolved oxygen, pH, and oxidation-reduction
potential (well MW02, Phase IV sampling).
13
-------
Sample preservation and holding time criteria are
listed in Table Bl. Field quality control (QC) samples
are summarized in Table B2. These included several
types of blanks, duplicate samples, and field matrix-
spike samples. All of these QC sample types were
collected, preserved, and analyzed using identical
methodologies as used for the water samples
collected in the field (Table Bl). Quality
assurance/quality control (QA/QC) requirements for
analysis of metals and major ions are summarized in
Table B3. QA/QC requirements for analysis of
dissolved gases, DIC/DOC, VOCs, low molecular weight
acids and stable isotopes of water are summarized in
Table B4. QA/QC requirements for analysis of
semivolatile organic compounds (SVOCs), GRO, and
DRO are summarized in Table B5. QA/QC
requirements for analysis of glycols are summarized in
Table B6. Results of Phase III and Phase IV blank
samples are provided in Tables B7 to B12. Detections
observed in the blank samples were generally very
low-level and generally much lower than
concentrations measured in the deep monitoring
wells. Some blank samples showed detections of
acetone (1 |ag/L), m,p-xylene (up to 0.7 |ag/L), toluene
(up to 0.5 |-ig/L), benzoic acid (3 |ag/L), and
tetraethylene glycol (3 i-ig/L). Concentrations of these
analytes in MW01 and MW02 in Phase III and Phase IV
sampling ranged from: 80 to 641 ng/L (acetone), non-
detect to 750 ng/L (total xylenes), 0.6 to 617 ng/L
(toluene), 209 to 457 ng/L (benzoic acid), and 7 to 27
Hg/L (tetraethylene glycol). Detected concentrations
of toluene (Phase III), xylene (Phase IV), and
tetraethylene glycol (Phase IV) in MW01 are within
about 2 times the detected levels of these chemicals
in some of the applicable blank samples.
Consequently, reported detections and concentrations
of these chemicals in MW01 were used cautiously in
this study. In one of the six blank samples collected
for DRO, an elevated concentration of 135 ng/L or 6
times the reporting limit was observed (Table B12); all
other DRO blank samples were non-detects (<20
Hg/L). Concentrations of DRO in the deep monitoring
wells ranged from 634 to 4050 j-ig/L.
DRAFT
Duplicate samples were collected in three locations
during Phase III and Phase IV sampling activities.
Results for the duplicate analyses are presented
Tables B13 and B14. Relative percent differences
(RPDs) were generally less than 10% for most
inorganic constituents indicating very good precision.
RPD is defined as
RPD =
x1-x2
(x1 + x2)/2
x1000
where xl = sample and x2 = sample duplicate. RPDs
for methane, volatile organic compounds, and semi-
volatile organic compounds were generally less than
25% (Table B14). The lower reproducibility for these
compounds detetected in MW02 is likely due to
difficulties in sampling and preserving water that is
oversaturated in gas.
Major ions were quality checked by calculating ion
balances. The AqQA (v.1.1.1) software package was
used to evaluate cation/anion balance, which ranged
from <0.1 to 17.2% with 90% of the calculated
balances better than 5%.
Geochemical equilibria in ground water were
evaluated with the Geochemist's Workbench package
(version 8; Bethke 1996). Speciation and mineral
equilibria calculations were made by entering the
concentrations of major cations (Na+, K+, Ca2+, Mg2+),
anions (CI", S042", HC03"), pH, and temperature. For
domestic well samples, bicarbonate concentrations
were determined from alkalinity measurements. For
the deep monitoring wells, because alkalinity included
a significant contribution from hydroxide,
concentrations of dissolved inorganic carbon were
used for bicarbonate/carbonate input. Activity
corrections were made using the Debye-Hiickel
equation. The LLNL (EQ3/6) thermodynamic database
was selected for use in the calculations (Delany and
Lundeen 1990). Model simulations were also
conducted by tracing alkaline-addition titration paths.
In order to do this, an additional entry was made to
14
-------
DRAFT
the thermodynamic database describing the solubility
of KOH (log K= 24.9; KOH(s) + H+ = K+(aq) + H20(i,).
Audits of Data Quality (ADQs) were conducted by a
contractor (independent of this investigation) or an
EPA QA Manager for all analyses conducted outside
EPA's Contract Laboratory Program (CLP) with the
exception of data collected during Phase I, which is till
in progress. This included data from EPA's Region VIII
laboratory in Golden, Colorado, EPA's Region III
laboratory in Fort Mead, MD, EPA's Office of Research
and Development Laboratory in Ada, Oklahoma, and
Isotech Laboratories in Champaign, Illinois. A
technical systems audit of Isotech Laboratories
included an on-site visit by the independent
contractor and EPA QA Manager. Two on-site field
technical system audits were also conducted by the
independent contractor and the EPA QA Manager to
ensure compliance with the Category I (highest of four
levels in EPA) Quality Assurance Project Plan
established for this site for ground water and gas
sample collection.
Gas Sampling from Casing of Deep Monitoring
Wells in Phase III and IV
Gas samples were collected from casing of deep
monitoring wells by connecting a 12.7 mm NPT
stainless-steel Swagelok quick-connect body and a
Swagelok single-end shutoff stem to a 12.7 mm brass
ball valve. The stem was connected to 6.35 mm
internal diameter Tygon Masterflex tubing and a 0.5
liter Cali-5 Bond gas sampling bag equipped with a
Leur-Fit Valve™ and a Leur-taper Quick-Mate™
connector. A Masterflex E/S portable peristaltic pump
was used to extract gas at 1 L/min. Samples were
collected after stabilization (± 1%) of 02, C02, and CH4
readings on a GEM-2000 Plus CES-LANDTEC portable
gas analyzer.
Domestic Well Sampling for Methane Using a
Closed System in Phase IV
During the Phase IV sample event, water from
domestic wells was screened using a Thermo-Scientific
TVA-1000B portable FID/PID and a 10 L Plexiglas
sparge cell (Figure 10). Samples from domestic wells
were routed through a closed (no contact with the
atmosphere to avoid offgassing) sample train and
collected in 0.5 L Cali-5 Bond gas sample bags.
Ultrapure N2 gas was introduced into the bags and
placed on a rotary shaker for one hour prior to
headspace analysis on site using a portable GC
equipped with a thermal conductivity detector.
Portable FID readings provided an immediate
indication of methane in well water prior to GC
analysis. Samples were also submitted to EPA's Office
of Research and Development (ORD) laboratory in
Ada, Oklahoma for analysis of dissolved gases.
Review of Borehole Geophysical Logs
Borehole geophysical logs available on line from
WOGCC were utilized to map lithology in the area of
investigation. Depending upon the specific well,
various combinations of natural gamma, resistivity,
self-potential, density, and neutron porosity logs were
utilized. Log resolution was sufficient to discern
distinct layers of shale 1 m or greater in thickness but
not sufficient to differentiate coarse-, medium-, and
fine-grained sandstones nor sandstones containing
various proportions of shale. Descriptions of cuttings
logged during installation of deep monitoring wells
and domestic wells obtained from a local driller were
used for near surface description. Neither grain size
nor proportions of shale in sandstone were
differentiated in near surface sandstones to maintain
consistency with descriptions from geophysical logs.
Lithology in the area of investigation is highly variable
and difficult to correlate from borehole to borehole,
even for boreholes in close proximity to one another
consistent with other observations in the Wind River
Formation (Osiensky 1984). Sandstone and shale
layers appeared thin and of limited lateral extent,
again consistent with previous observations of
lithology in the Wind River Formation (Single 1969,
Flores and Keighin 1993).
15
-------
DRAFT
6.35 mm ID
/ Tygon
Masterflex
Tubing
Brass
Threaded
Hose Adapter
Stainless-Steel
Swagelok Threaded
Barbed Fitting
Stainless-Steel
Swagelok Tee
6.35 mm OD'
Stainless-Steel
Tubing"
Stainless-Steel
Nupro Valve
10 Liter Plexiglass
Sparge Cell
6.35 mm ID
Tygon
Masterflex
Tubing
Brass Threaded
Barbed Fitting
Air/Water
Separator
~ aooo
~ ~ ~~~
~ aooa
1 ~~~~
Discharge
Figure 10. Schematic of closed (no contact to atmosphere) sampling train for domestic wells. Water
flow from domestic well and into sparge cell was approximately 5 and 1 L/min respectively. Excess
water bled through valve used for sampling prior to sample collection. Gas flow into sparge cell and
portable FID/'PID sparge cell was approximately 20 and 1 L/min. Excess air was bled through splitter
above sparge cell.
TVA-1000B
Thermo Scientific
Dual FID/PID
Gast Diaphragm Pump
Review of Cement Bond/Variable Density Logs
Cement bond/variable density (CBL/VDL) logs,
available for less than half of production wells, were
obtained online from WOGCC to evaluate well
integrity. Sporadic bonding is defined as an interval
having an amplitude (mV) greater than A80 (EPA 1994)
where
=1 o0'21og^+0'81os"4100
and Ago, A0, and Aioo = amplitude at 80%, 0%, and
100% bond respectively. A0 typically corresponds to
amplitude in free pipe whereas A100 corresponds to
the best-bonded interval on the CBL. Examples of "no
cement", "sporadic bonding", and "good bonding" are
provided in Appendix E.
CBL/VDLs provide an average volumetric assessment
of the cement in the casing-to-formation annular
space and are considered low resolution tools
compared to ultrasonic imaging tool logs which
provide a high-resolution 360° scan of the condition of
the casing-to-cement bond (Bybee 2007). Acoustic
imaging tools do not directly measure cement seal.
Communication of fluids between intervals has been
observed to occur despite indication of "good to
excellent" cement bond on acoustic logs (Boyd et al.
2006). All CBL/VDLs available from WOGCC reflect
pre-hydraulic fracturing conditions.
16
-------
3.0
Results and Discussion
Ground Water and Soil Sample Results
Near Three Pits
DRAFT
organic compounds including benzene and m, p~
xylene were detected at concentrations up to 390 and
150 |ig/L, respectively (EPA 2010), indicating pits as a
source of shallow ground water contamination in the
area of investigation. EPA's maximum concentration
level (MCL) for benzene is 5 [ig/L.
There are at least 33 pits previously used for
storage/disposal of drilling wastes, produced water,
and flowback fluids in the area of investigation.
Discussions are ongoing with stakeholders to
determine the location, delineate the boundaries, and
extent (areal and vertical) of contamination associated
with these pits. The operator has initiated
remediation of selected pit areas. Concentrations of
DRO, gasoline range organics (GRO), and total
purgeable hydrocarbons (TPH) detected in soil
samples adjacent to three pits investigated in Phase II
were as high as 5010, 1760, and 6600 mg/kg,
respectively (EPA 2010). Concentrations of GRO, DRO,
and TPH in ground water samples from shallow (4.6 m
bgs) monitoring wells were as high as 2.4, 39, and 3.8
mg/L, respectively (EPA 2010). A wide variety of
Inorganic Geochemistry
Inorganic geochemical results for ground water (all
phases) are summarized in Table A2a and Figure 11.
Major ion chemistry of ground water in the Pavillion
area varies as a function of aquifer depth. Shallow
ground waters (< 31 m bgs) collected from drinking
water wells and stock wells are near-neutral (pH 7.7 ±
0.4, n = 19) (Figure 12) and display calcium-
bicarbonate composition. With increasing depth,
ground water becomes moderately alkaline (pH 9.0 ±
1.0, n = 55) (Figure 12), and with only one exception
(MW02), is dominated by sodium and sulfate as the
major cation/anion pair (Figures 11 and 12, Table
A2a). This gradient in pH and water chemistry likely
arises from the wide-scale surface application of
irrigation water from the Wind River to support
• Phase 1 - March 2009
• Phase 2 - January 2010
• Phase 3 - October 2010
• Phase 4-April 2011
• Wyoming Canal, irrigation water
(Morris et al., 1959)
Figure 11. Durov
diagram showing ground
water chemistry trends
obtained in Phase I - IV
sampling events and the
composition of irrigation
water.
17
-------
DRAFT
500 ¦
400 ¦
Q.
Q_
O
200 ¦
100.
"i—1—I—>—i—1—r
4000.
¦ m ¦ ¦
•* ¦ ^ Vi.-jv,
3500.
3000.
2500.
Q_ 2000.
CL
o
CO
—i—'—i ' i 1 —i—•—i—•—i—>—i—
1350 1400 1450 1500 1550 1600 1650 1700
m (AMSt)
1000-
500-
0-
-i—i—i—i—i—i—i—>—i—i—i—'—r
¦ B
¦¦ ¦
, , 1 , , , 1 , 1 1 1 r
1350 1400 1450 1500 1 550 1600 1-350 1700
m (AMSL)
12-
10-
X
CL
"i—1—i—1—i—'—i—>—r
¦ ¦
¦ 1
¦ *
I I
40.
E 30.
Q.
Q_
10.
1 1 1 1 1 , 1 1 , 1 1 1 1 r
1350 1400 1450 1500 1550 1600 1650 1700
, , , , 1 , 1 1 , r-
11
—i—i—,—,—,—,—|—,—|—,—,—,—|—p
1350 1400 1450 1500 1550 1600 1650 1700
m (AMSL)
m (AMSL)
Figure 12. Depth trends of chloride, pH, sulfate, and potassium (filled black squares = domestic wells, filled red circles:
monitoring wells).
18
-------
DRAFT
crop growth since irrigation water appears to
represent an endmember composition (Figure 11).
The chemical alteration from bicarbonate-type
recharge water to sulfate-type ground water involves
multiple water-rock interactions, including salt
dissolution, carbonate mineralization, and exchange of
divalent cations for sodium (Morris et al. 1959). Total
dissolved solids concentrations are <6000 mg/L in all
ground water samples collected to depths up to 296 m
(Figure 11).
Saturation indices of gypsum (CaS04-2H20) and calcite
(CaC03), plotted against sulfate and calcium
concentrations, are shown in Figure 13. The trend for
gypsum saturation suggests that sulfate
concentrations in the aquifer are limited by the
solubility of gypsum. Ground water is also close to
equilibrium with calcite which likely is an important
control on pH and concentrations of calcium and
bicarbonate. Some residents have described the
development of particulates in ground water samples
collected and stored in glass jars. Precipitates that
formed from PGDW05 ground water were analyzed by
powder X-ray diffraction and found to be dominantly
calcite. Because calcite has retrograde solubility,
precipitation of calcite is possibly triggered by
warming calcite-saturated ground water to ambient
conditions.
The geochemistry of ground water from the deep
monitoring wells is distinctive from that in the
domestic wells. Chloride enrichment in monitoring
well MW02 is 18 times the mean chloride
concentration (25.6 mg/L) observed in ground water
from domestic wells. Chloride enrichment in this well
is significant because regional anion trends tend to
show decreasing CI concentrations with depth. The
mean potassium concentration in domestic wells
a)
E
3
m
Q.
>.
0
X
©
TJ
JE
c -2
.2
V-*
ro
3
•*->>
m
w
saturated
H •
7
"1 1 1 ' 1 1 1—
0 10 20 30
Sulfate, mmol/L
2.0-
b)
1.5 •
1.0-
jfi
o
« 0,5 •
O
x"
®
TS
40
0,0-
| -0.5.
1
1 -1-0-
-1.5 •
-2.0 •
•#
#
~ saturated
10
Calcium. mmol/L
Figure 13. Saturation indices for (a) gypsum versus sulfate concentration and (b) calcite versus calcium concentration.
Saturation Index is equal to the logarithm of the ratio of the ion activity product to the mineral solubility product. A
Saturation Index of 0 corresponds to chemical equilibrium; values less than 0 and greater than 0 correspond to
undersaturated and oversaturated conditions, respectively.
19
-------
screened to 244 m bgs is 3 mg/L, with 99% of values
<10 mg/L Potassium enrichment in MW01 and
MW02 is between 8.2 and 18.3 times the mean value
of domestic wells (Table A2a). pH values in MW01
and MW02 are highly alkaline (11.2-12.0), above the
pH range observed in domestic wells (6.9-10), and
above the pH range previously reported for the Wind
River Formation (Plafcan et al. 1995, Daddow 1996).
In the deep monitoring wells, up to 94% of the total
alkalinity is contributed by hydroxide. In addition, the
monitoring wells show low calcium, sodium, and
sulfate concentrations compared to the general trend
observed in domestic well waters (Figure 14).
The high pH measured in the deep monitoring wells
was unusual and unexpected. Although ground water
pH in these wells was >11, total alkalinity was not
particularly high (<500 mg/kg), and as already noted
up to 94% of the total alkalinity was present as
hydroxide (see charge balance calculations, Table
A2b). Alkalinity contributed by carbonate/bicarbon-
ate was less than the hydroxide component. In fact,
inorganic carbon concentrations were so low in MW02
as to prevent the measurement of 813C of dissolved
inorganic carbon. Presence of hydroxide alkalinity
suggests strong base addition as the causative factor
for elevated pH in the deep monitoring wells. The
possibility of cement/grout intrusion into the screened
intervals was considered as a possibility for both
monitoring wells, although precautions were taken to
prevent downward migration of cement during well
construction. Cement intrusion typically leads to pH
values between 10 and 11, lower than the pH values
measured in the deep monitoring wells (Gibb et al.
1987). Prolonged purging did not show decreasing pH
trends (e.g., Figure 9) and water chemistry results
indicate that ground water from the wells was highly
undersaturated with respect to cement phases (e.g.,
portlandite), suggesting that cement was not the
cause of elevated pH.
In order to gain additional insight, reaction path
modeling was conducted to evaluate pH response to
addition of strong base (potassium hydroxide, KOH).
Geochemical modeling was carried out by using
ground water compositions for PGDW49, PGDW20,
and PGDW32 (initial pH 7.3, 8.9, and 9.9, respectively).
Modeled titration results are shown in Figure 15a; pH
is plotted versus the mass of KOH added per kg of
solution. Model titration results vary as a function of
ground water composition. Samples PGDW20 and
PGDW32 have Na-S04-type compositions typical of
deeper portions of the aquifer. In both of these cases,
attainment of pH values between 11.2 and 12.0
requires small quantities of KOH addition (<250 mg
KOH per kg of solution). Sample PGDW49 is elevated
in Ca2+ and Mg2+, lower in pH, and typical of shallower
ground water compositions. In this case, significantly
more KOH addition is required to attain pH values
observed in the monitoring wells. The first derivative
of the titration curve, or buffer intensity, is shown in
Figure 15b. The buffer intensity indicates that ground
water compositions like PGDW20 and PGDW32
inherently have little resistance to pH change up to
about pH 12, at which point increased KOH additions
are necessary to further increase pH. PGDW49 shows
a broad peak on the buffer intensity diagram (pH 10 to
11) which reflects precipitation reactions to form
calcium carbonate and magnesium hydroxide,
reactions that consume hydroxide and therefore limit
pH increases, until divalent cations are completely
consumed. The model results clearly show that
ground water typical of the Pavillion aquifer below
100 m depth (Na-S04-type composition) is especially
vulnerable to the addition of strong base, with small
KOH additions driving significant upward pH changes.
Paired values of 5180 and 82H in ground water samples
plot below the Global Meteoric Water Line (Figure 16;
-16.6 to -12.4%o 5180 and -129.2 to -97.4%o 82H).
Shallow ground water samples generally tend to be
depleted in 180 and 2H compared to deeper ground
water samples and may be more reflective of local
recharge. Ground water isotope data from the deep
monitoring wells (red circles, Figure 16) follow along
the same 5180 versus 82H trajectory established by the
domestic well data, suggesting similar recharge and
evolutional paths (e.g., Bartos et al. 2008).
20
-------
DRAFT
12
10-
Q_
u m
I
V.
v" s
4000-
3500-
3000-
2500-
E 2000-
Q.
Q~
%
§ 1500-
1000-
500-
! , 1 , , , j , 1 , 1 r-
0 1000 2000 3000 4000 5000 8000 7000
Specific Conductance, pS/cm
¦ <
*
-•—i—•—i—<—i—i—i—¦—i—•—i—¦-
0 1000 2000 3000 4000 5000 6000 7000
Specific Conductance, nS/cm
1400 ¦
1200.
1000.
800
E
a
600.
400.
200.
0-
"1 ' :::1 * ! : i ' j 1 f
¦ ¦
—i—>—i—i—i—>—i—
1000 2000 3000 4000
—I ' !
5000 6000
I ' I 1 I ' I 1 H
500-
400-
300-
ra
O 200-
100-
7000
Specific Conductance, fiS/cm
¦- ' *
1 1 1 1 1 1 . 1 ' 1 1 1 r-
0 1000 2000 3000 4000 5000 6000 7000
Specific Conductance, nS/cm
Figure 14. Concentration trends versus specific conductivity. Note the monitoring wells show high pH and low sulfate,
calcium, and sodium relative to the general trend observed in the domestic wells (filled black squares = domestic wells,
filled red circles = monitoring wells).
21
-------
DRAFT
Q.
XS
-to
O
13
b)
3,0-
to
c
CD
+-i
c
I
3
m
2.0-
10-
0.0-
PGDW49
PGDW20
10
PGDW32
—J-
11
12
PH
13
Figure 15. (a) Results of KOH
titration models plotted as pH
versus grams of KOH added per
kilogram of solution. Initial
water compositions are from
PGDW49, PGDW20, and
PGDW32. Model accounts for
reactions taking place in solution
as KOH is added and
equilibrated. pH range in deep
monitoring wells shown for
reference; (b) Buffer Intensity
plot or first derivative of
titration plot, pH versus change
in concentration of base (CB) per
change in pH.
6,0O (permit, VSMOW)
Figure 16. Hydrogen and
oxygen isotope values (permil,
Vienna Standard Mean Ocean
Water, VSMOW) for ground
water samples (black
squares=domestic wells; red
circles=deep monitoring wells)
relative to the Global Meteoric
Water Line from Craig (1961).
22
-------
DRAFT
Organic Geochemistry
Organic and inorganic geochemical impacts in deep
ground water monitoring wells (Phase III and IV) are
summarized in Table 3. The monitoring wells produce
ground water near-saturated in methane at ambient
pressure, with concentrations up to 19.0 mg/L. Gas
exsolution was observed while sampling at both
MW01 and MW02. A wide variety of organic
chemicals was detected in the monitoring wells
including: GRO, DRO, BTEX, trimethylbenzenes,
phenols, naphthalenes, acetone, isopropanol, TBA, 2-
butoxyethanol, 2-butanone, diethylene glycol,
triethylene glycol, and tetraethylene glycol (Figure 17;
Table 3). Concentrations of these chemicals range
from ng/L to mg/L levels. Concentrations of benzene
in MW02 exceed EPA's MCL in drinking by a factor of
49 times. Detections of organic chemicals are more
numerous and exhibit higher concentrations in the
deeper of the two monitoring wells (Figure 17, Table
3). This observation, along with trends in methane,
potassium, chloride, and pH, suggest a deep source
(>299 m bgs) of contamination. Natural breakdown
products of organic contaminants like BTEX and
glycols include acetate and benzoic acid; these
breakdown products are more enriched in the
shallower of the two monitoring wells, suggesting
upward/lateral migration with natural degradation
and accumulation of daughter products (Corseuil et al.
2011, Caldwell and Suflita 2000, Dwyer and Tiedje
1983). Other trace-level detections of semi-volatile
organic compounds included: bis(2-ethylhexyl)
phthalate (MW01 and MW02, Phase III and IV), bis(2-
chloroethyl) ether, bis(2-ethylhexyl) adipate (MW01,
Phase IV), butyl benzyl phthalate, and 4-methyl-2-
pentanone (MW02, Phase IV).
Well completion reports obtained online from WOGCC
and Material Safety and Data Sheets (MSDSs)
obtained from the operator were reviewed to
examine inorganic and organic compounds in
additives used for hydraulic fracturing and similarity
with detected elements and compounds in ground
water. Well completion reports were limited to a
subset of production wells and included dates of
injection, injection depths, pressure, flow, and volume
for slickwater and carbon dioxide foam fracture jobs.
Some MSDSs list chemical formulation as proprietary
(e.g., proprietary alcohols) or list a chemical family
(e.g., blend of organic surfactants) rendering
identification of constituents impossible. This review
is summarized in Table 4. Inorganic additives are
potential sources of elevated K, CI, and OH in deep
monitoring wells.
Detection of compounds associated with petroleum-
based additives in ground water samples using
analytical methods employed in this investigation
would be manifested as GRO, DRO, BTEX,
naphthalenes, and trimethylbenzenes observed in
deep monitoring wells.
TBA was detected in MW02 during Phase 4 sampling
at a concentration of 4470 |ag/L. Two possible
formation pathways for TBA are: 1) biodegradation of
methyl ferf-butyl ether (MTBE, synthetic chemical
used as a fuel additive) under methanogenic
conditions (e.g., Mormile et al. 1994, Bradley et al.
2001); and 2) breakdown of ferf-butyl hydroperoxide
(a gel breaker used in hydraulic fracturing; e.g., Hiatt
et al. 1964). TBA biodegradation is generally slow
compared to the degradation of MTBE; this suggests
that TBA could be present and persist even after
complete MTBE removal from ground water impacted
by fuel releases (Wilson et al. 2005). MTBE was not
detected in either of the deep monitoring wells. A
second pathway of TBA production is from the
decomposition of the gel breaker ferf-butyl
hydroperoxide. Hiatt et al. (1964) found that
decomposition of ferf-butyl hydroperoxide yielded a
10-fold molar quantity of TBA, oxygen, d/'-ferf-butyl
peroxide, and acetone. Acetone was detected in
MW02 during Phase 4 sampling at a concentration of
641 |-ig/L. This breaker is used in hydraulic fracturing
formulations; however, the MSDSs made available to
EPA do not indicate whether ferf-butyl hydroperoxide
was used in the Pavillion gas field for well stimulation.
Elevated concentrations of TBA are not expected in
unimpacted aquifers and its presence in MW02
remains unresolved. Additional insight about the
occurrence of TBA (and other organic compounds)
might be obtained by conducting compound-specific
isotope analyses.
23
-------
DRAFT
Table 3. Geochemical impacts in deep ground-water monitoring wells
Compound
MW01
MW02
MW01
MW02
Phase 3
Phase 3
Phase 4
Phase 4
10/6/2010
10/6/2010
4/20/2011
4/19/2011
PH
11.9
12.0
11.2
11.8
K, mg/L
54.9
39.5
24.7
43.6
CI, mg/L
23.3
466
23.1
457
CH4, mg/L
16.0
19.0
17.9
18.8
Benzene +
nd
246
nd
139
Toluene
0.75
617
0.56
336
Ethylbenzene
nd
67
nd
21.5
Xylenes (total)
nd
750
0.89 c
362
1,2,4 Trimethylbenzene
nd
69.2
nd
18.5
1,3,5 Trimethylbenzene
nd
35.5
nd
nd
Diesel Range Organics
634
1440
924
4050
Gasoline Range Organics
389
3710
592
2800
Phenola
11.1
56.1
20.9
64.9
Naphthalene b
nd
6.06
nd
6.10
Isopropanol
212
581
Tert-Butyl Alcohol
nd
4470
2-Butanone
nd
120
Diethylene Glycol
226
1570
Triethylene Glycol
46
310
Tetraethylene Glycol
1.3'"*
27.2
2-Butoxyethanol *
nd
nd
2-Butoxyethanol **
nd
nd
12.7
nd
Acetone
79.5
641
Benzoic Acid
212
244
457
209
Acetate
8050
4310
Formate
112
558
Lactate
69
213
Propionate
309
803
t All values in pg/L unless otherwise noted.
— not analyzed,
nd - not detected.
8 Includes phenol, 2.4-dimethylphenol, 2-methylphenol, 3&4 methylphenoL
b Includes naphthalene, 1 -methylnaphthalene, and 2-methylnaphthalene.
c Value below quantitation limit of 10 pg/L,
d Chemical detected in a blank sample at a similar level
* 2-Butoxyethanol determined by HPLC-MS-MS.
** 2-Butoxyethanol determined by GC-MS.
-------
DRAFT
10000 -g
Phase 3
_i1000
~CT>
c 100
o
2
c
CD
O
C
O
O
10-
0.1
n
MW01
MW02
y/^A/
# /V>
^ V> ^ >® N® J
^
-------
DRAFT
Table 4. Association of inorganic and organic anomalies with compounds used for Hydraulic fracturing
Compound/
Compound Class
Information from MSDSs and Well Completion Reports
PH
K, CI
CI
BTEX
Trimethylbenzenes
DRO and GRO
Naphthalene
Isopropanol
Tert-Butyl Alcohol
Glycols
2-Butoxyethanol
Acetone
Benzoic Acid,
Acetate, Formate,
Lactate, Propionate,
2-Butanone, Phenols
KOH was used in a crosslinker (<5%) and in a solvent (85-100%).
The formulation of fracture fluid provided for foam jobs typically consisted of C02, 6%
KCI, 10% methanol, and "clean" fluid and "additives." Potassium metaborate was used
in crosslinkers (5-10%, 30-60%). KOH was used in a crosslinker (<5%) and in a solvent
(85-100%).
Ammonium chloride was used in crosslinker (1-27%).
Aromatic solvent (typically BTEX mixture) was used in a breaker (<75%). Diesel oil
(mixture of saturated and aromatic hydrocarbons including naphthalenes and
alkylbenzenes) was used in a guar polymer slurry/liquid gel concentrate (30-60%) and in
a solvent (60-100%). Petroleum raffinates (mixture of paraffinic, cycloparaffinic,
olefinic, and aromatic hydrocarbons) was used in a breaker (<30-60%). Heavy aromatic
petroleum naptha (mixture of paraffinic, cycloparaffinic and aromatic hydrocarbons)
was used in surfactants (5-10%, 10-30%, 30-60%) and in a solvent (10-50%). Toluene
was used in a flow enhancer (3-7%). Xylenes were used in a flow enhancer (40-70%) and
a breaker (confidential percentage).
1,2,4-trimethylbenzene was used in surfactants (0-1%). Diesel oil (mixture of saturated
and aromatic hydrocarbons including naphthalenes and alkylbenzenes) was used in a
guar polymer slurry/liquid gel concentrate (30-60%) and in a solvent (60-100%).
Petroleum raffinates (mixture of paraffinic, cycloparaffinic, olefinic, and aromatic
hydrocarbons) was used in a breaker (<30-60%). Heavy aromatic petroleum naptha
(mixture of paraffinic, cycloparaffinic and aromatic hydrocarbons) was used in
surfactants (5-10%, 10-30%, 30-60%) and in a solvent (10-50%).
Diesel oil (mixture of saturated and aromatic hydrocarbons including naphthalenes and
alkylbenzenes) was used in a guar polymer slurry/liquid gel concentrate (30-60%) and in
a solvent (60-100%). Petroleum raffinates (mixture of paraffinic, cycloparaffinic,
olefinic, and aromatic hydrocarbons) was used in a breaker (<30-60%). Heavy aromatic
petroleum naptha (mixture of paraffinic, cycloparaffinic and aromatic hydrocarbons)
was used in surfactants (5-10%, 10-30%, 30-60%) and in a solvent (10-50%).
Naphthalene was used in surfactants (0-1, 5-10%) and a breaker (confidential
percentage). Hydrotreated light petroleum distillates (mixture of C10-C14 naphthenes,
iso- and n-paraffins) were used in a guar polymer slurry/liquid gel concentrate (40-60%).
Diesel oil (mixture of saturated and aromatic hydrocarbons including naphthalenes and
alkylbenzenes) was used in a guar polymer slurry/liquid gel concentrate (30-60%) and in
a solvent (60-100%),
Isopropanol was used in a biocide (20-40%), in a surfactant (30-60%), in breakers (<1%,
10-30%), and in foaming agents (<3%, 1-5%, 10-30%).
No MSDS listing. Breakdown product of methyl terf-butyl ether and terf-butyl
hydroperoxide - found in gel breakers. See discussion.
Diethylene glycol was used in a foaming agent (5-10%) and in a solvent (0.1-5%).
Triethylene glycol was used in a solvent (95-100%).
2-butoxyethanol was used in a surfactant (10-30%), in foaming agents (<10%, <11%,
<12%, 1-10%, 10-30%) and in solvents (15-40%, 60-100%).
Breakdown product of terf-butyl hydroperoxide - found in gel breakers. See discussion.
Natural breakdown products of organic contaminants (e.g., BTEX, glycols, etc.).
26
-------
Natural gas condensates are composed primarily of
aliphatic hydrocarbons; however, condensates may
contain low quantities of aromatic compounds, such
as BTEX. Gas from the Fort Union and lower Wind
River Formations is generally dry (Cx/CrCs = 0.95 -
0.96 where methane = C1( ethane = C2, propane = C3,
butane = C4, pentane = C5) (Johnson and Rice 1993)
and unlikely to yield liquid condensates at ground
water pressure and temperature conditions. In
addition, a condensate origin for BTEX compounds in
ground water is doubtful because dissolved gas
compositions and concentrations are similar between
the two deep monitoring wells and therefore would
yield similar liquid condensates, yet the compositions
and concentrations of organic compounds detected in
these wells are quite different (Figure 17) further
suggesting a deep source of BTEX in MW02. The
presence of synthetic compounds such as glycol
ethers, along with enrichments in K, CI, pH, and the
assortment of other organic components is explained
as the result of direct mixing of hydraulic fracturing
fluids with ground water in the Pavillion gas field.
As noted previously, this investigation was prompted
by homeowner complaints over perceived changes in
water quality. Domestic well results showed: the
presence of DRO and GRO (in 23 of 28 samples), and
trace levels of exotic organic compounds in some
domestic wells including adamantanes, 2-
butoxyethanol phosphate, phenols, naphthalene, and
toluene (EPA 2009, EPA 2010). Methane was detected
in 10 of 28 samples at concentration levels below 0.8
mg/L. Foul odors associated with some domestic wells
correlate with detections of GRO and DRO.
Anomalous trends in inorganic constituents observed
in the deep monitoring wells (e.g., K, CI, pH) were not
revealed in domestic well waters. In several instances,
glycols were detected in domestic wells using gas
chromatography with flame ionization detection (GC-
FID; EPA Standard Method 8015). However, glycol
analysis using liquid chromatography with tandem
mass spectroscopy (GC/MS/MS) failed to replicate
these glycol detections, even though the method
reporting limit was over an order of magnitude lower,
suggesting that Method 8015 is prone to false positive
results (possibly due to interactions between the
chromatographic column and organic compounds in
sample water). This result points to the need for
continued and future improvements of analytical
methods to detect and quantitate low levels of
organic chemicals that may be associated with
hydraulic fracturing fluids. Although contamination
was detected in some domestic wells proximal to the
deep monitoring wells, underscoring potential future
risk, the existing data at this time do not establish a
definitive link between deep and shallow
contamination of the aquifer. An increased number of
sampling points (monitoring wells) with vertical
profiling in targeted locations are necessary to better
define transport and fate characteristics of organic
and inorganic contaminants in the ground water
system and impact on domestic wells.
Natural Gas Migration
A review of open-hole geophysical logs obtained from
the WOGCC internet site indicates the presence of
gas-filled porosity at three locations at 198, 208, and
252 m bgs between the years 1965 -1973 suggesting
the presence of natural gas in ground water at depths
used for domestic water supply prior to extensive
commercial development. However, a review of 10
mud-gas logs recorded in the mid-1970s and early
1980s obtained on line from WOGCC, do not indicate
gas shows within 300 m of the surface at any location.
Aqueous analysis of light hydrocarbons, gas and
headspace analysis of light hydrocarbons, and isotopic
data for dissolved, gas phase, and headspace analysis
are summarized in Tables A3a, A3b, and A3c
respectively (all investigative phases). Elevated levels
of dissolved methane in domestic wells generally
increase in those wells in proximity to gas production
wells (Figure 18c). Methane was not detected in
shallow domestic wells (e.g., < 50 m) regardless of
proximity to production wells (Figure 18c). With the
exception of two domestic wells where methane was
27
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DRAFT
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1300
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Figure 18. (a) Stable isotope ratios of carbon of methane versus ratio of methane (Cj) to ethane (C2) and propane (C3) in
gas from production wells, monitoring wells, and domestic wells. Values of 100,000 are used to denote non detection of
ethane and propane in samples, (b) Stable isotope ratios of carbon versus hydrogen of methane in gas from production
wells (both literature and measured values), monitoring wells, and domestic wells. 6D was not determined for PGDW32.
Oxidation pathway (enrichment of 13C of remaining CH4 with biodegradation) is illustrated, (c) Methane concentration in
domestic (red circles and black squares) and monitoring wells (green squares) as a function of proximity to production
wells and AMSL. Values of 1.0 were used for non-detection (detection limit 5 ng/L).
28
-------
detected at less than 22 i-ig/L, methane was not
detected in domestic wells with 2 or less production
wells within 600 m (Figure 18c). All domestic wells
with the exception of PGDW25 with 2 or less
production wells within 600 m are located on the
periphery of the gas field (Figure 5). PGDW25 is
located within 1600 m of 15 gas production wells.
Of particular interest is the area encompassing MW01,
PGDW30, and PGDW05 (Figure 19). Ground water is
saturated with methane at MW01 which is screened
at a depth (239 m bgs) typical of deeper domestic
wells in the area. Methane was detected in PGDW30
at 808 ng/L at a depth of only 80 m, the highest level
in any domestic well. A blowout occurred during
drilling at a depth of only 159 m bgs in December 2005
adjacent to PGDW05. Natural gas exited the borehole
for three days until the gas field operator was ordered
to plug the borehole with a dense mud. The owner of
PGDW05 was attempting at the time to replace this
well due to taste, odor, and yield reduction he stated
occurred after hydraulic fracturing at nearby
production wells. A mud-gas log conducted on
11/16/1980 at Tribal Pavillion 14-2 (illustrated on
Figure 19 as 14-2) located only 300 m from the
location of the uncontrolled release does not indicate
a gas show (distinctive peaks on a gas chromatograph)
within 300 m of the surface. The owner of PGDW05
complained that well yield decreased after hydraulic
fracturing at nearby production wells. Records
obtained from the Wyoming State Engineer's office
dated January 1973 indicate a yield of 30 to 38 L/min
with 1.2 meters of drawdown after 10 hours of
pumping. During a sampling event in April 2005,
PGDW05 became dry after pumping at a rate of 21.6
L/min for 14 minutes. The cause of reduced well yield
requires further investigation.
Similarity of 613C values for methane, ethane,
propane, isobutane, and butane between gas
production and monitoring wells and plots of 613C-CH4
versus 6D -CH4 (Figure 18b) and 613C-CH4 versus Cj(C2
+ C3) (Figure 18a) indicate that light hydrocarbons in
casing and dissolved gas in deep monitoring wells are
similar to produced gas and have undergone little
oxidation or biodegradation. These observations
combined with radiocarbon analysis of CH4 (< 0.2%
percent modern carbon) obtained from gas in casing
of both MW01 and MW02 indicate that methane in
deep monitoring wells is of thermogenic origin. Gas
from the Fort Union and lower Wind River Formations
is isotopically heavy (613C-CH4from to -40.24 to -
38.04%o) and as previously stated, dry (Johnson and
Rice 1993, Johnson and Keighin 1998). Values of 613C-
CH4 and 6D -CH4 more negative than -64%o and -
175%o, respectively, are indicative of microbial origin
(Schoell 1980). The absence of ethane and propane in
three of four domestic wells having sufficient methane
to allow isotopic analysis and a shift of 613C-CH4 and
6D-CH4 values in a positive direction relative to
produced gas suggests the presence of gas of
thermogenic origin in domestic wells undergoing
biodegradation and subsequent enrichment of 613C
and 6D. This observation is consistent with a pattern
of dispersion and degradation with upward migration
observed for organic compounds. Values of 613C-CH4
more positive than -64%o and C!/(C2+C3) ratios above
1000 are often interpreted to indicate gas of mixed
biogenic-thermogenic origin or gas of biogenic origin
undergoing biodegradation (Whiticar 1999, Whiticar
and Faber 1986) since neither ethane nor propane are
biogenically generated in significant amounts.
However, preferential loss of ethane and propane
relative to methane in thermogenic gas produces a
similar response (Valentine 2010, Kinnaman et al.
2007).
Evaluation of Cement Bond/Variable Density
Logs Along Transect
CBL/VDLs and lithology were examined along a
transect (Figure 19) which included the deep
monitoring wells and three domestic wells where
elevated levels of methane were detected. At
Pavillion Fee 34-03B, a CBL/VDL conducted on
10/22/2004 indicates no cement below surface casing
until 802 m msl (Figure 20) and sporadic bonding to
604 m msl (not illustrated). The well completion
29
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DRAFT
13-02B
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PGDW45
PGDW05
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14-12
Legend
^ Oil and Gas Wells
O EPA Deep Monitoring Wells
^ Sampled Domestic Wells
Q Pit Monitoring Wells
0 400 800 1,200 1,600 2,000 Meters
1 1 1 1 1 1 1 1 1 1 1
Figure 19. Map illustrating transect used to develop lithologic cross section and evaluation of CBL/VDLs.
report for this production well indicates that hydraulic
fracturing was performed at 601 m msl on 11/9/2004,
A cement squeeze was subsequently performed at
802 m msl on 4/1/2005 (no CBL/VDL after cement
squeeze) with hydraulic fracturing at 689 m msl on
4/19/2005. At Pavillion Fee 34-03R, the CBL/VDL
indicates no cement below surface casing until 968 m
msl (Figure 20). At Tribal Pavillion 41-10 and 41-10B,
CBL/VDLs indicate sporadic bonding over extensive
intervals. A CBL/VDL conducted on 4/20/2005 at
Tribal Pavillion 24-02 after a squeeze perforation at
the base of the surface casing indicates poor bonding
outside production casing below surface casing to the
first perforation interval (Figure 20). At Tribal Pavillion
11-11B, a CBL/VDL indicates poor or sporadic bonding
to 991 m bgs and no cement or cement bridging from
675 - 857 m msl. Thus, a review of well completion
reports and CBL/VDLs indicates instances of sporadic
bonding directly above intervals of hydraulic
fracturing. This review also indicates instances where
cement outside production casing is lacking over an
extensive interval providing a potential conduit for
fluid migration to within 300 m of the surface. As
graphically illustrated in Figure 20, production wells
having no or sporadic cement outside production
casing are located in proximity to deep monitoring
wells where aqueous constituents consistent with
hydraulic fracturing were detected and methane
exsolved from solution during sampling and locations
of domestic wells where elevated levels of methane
were detected and where an uncontrolled release of
natural gas occurred.
30
-------
DRAFT
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Potential Migration Pathways
Further investigation is necessary to determine
mechanisms of aqueous and gas phase transport in
the area of investigation. However, at least three
mechanisms can be postulated at this time. The first
mechanism is aqueous and/or gas transport via
boreholes due to insufficient or inadequate cement
outside production casing. Both aqueous (brine) and
gas phase migration vertically up compromised
wellbores have been simulated (Nordbotten et al.
2004, 2005a, 2005b) and indicate decreasing mass flux
toward the surface with increasing number of
permeable formations encountered along the way.
Thus, the severity of ground water contamination
increases with depth. Migration of gas via wellbores is
well documented in the literature (e.g., Harrison 1983,
Harrison 1985, Van Stempvoort et al. 2005, Taylor et
al. 2000). In Bainbridge, Ohio, an operator initiated
hydraulic fracturing despite knowing that only 24 m of
cement was present above the perforation interval
(Bair et al. 2010, ODNR 2008). Hydraulic fracturing
fluid flowed to the surface via surface-production
casing annulus which pressurized upon shut-in. Gas
subsequently migrated through natural fractures to
domestic wells eventually causing an explosion at one
home. In northeastern Pennsylvania, two operators
were fined for enhanced gas migration into domestic
wells attributed to incomplete or inadequate cement
outside production casing in wells used for hydraulic
fracturing (PADEP 2009a, 2009b, 2010).
The second mechanism is fracture fluid excursion from
thin discontinuous tight sandstone units into
sandstone units of greater permeability. This would
be accompanied by physical displacement of gas-rich
solutions in both tight and more permeable sandstone
formations. As illustrated in Figure 20, there is little
lateral and vertical continuity to hydraulically
fractured tight sandstones and no lithologic barrier
(laterally continuous shale units) to upward vertical
migration of aqueous constituents of hydraulic
fracturing in the event of excursion from fractures. A
third mechanism is that the process of hydraulic
fracturing generates new fractures or enlarges existing
ones above the target formation, increasing the
connectivity of the fracture system.
In all three transport pathways, a general correlation
(spatial relationships ultimately determined by fault
and fracture systems in addition to lithology) would
exist between proximity to gas production wells and
concentration of aqueous and gas phase constituents
in ground water. For instance, Osborn et al. (2011)
observed a correlation between methane
concentration and proximity to hydraulically fractured
gas production wells at locations above the Marcellus
and Utica formations in Pennsylvania and New York.
Isotopic data and other measurements for methane in
the drinking water were consistent with gas found in
deep reservoirs such as the Marcellus and Utica shales
at the active sites and matched gas geochemistry from
shale-gas wells sampled nearby. Also, in all three
transport pathways, advective/dispersive transport
would be accompanied by degradation causing a
vertical chemical gradient as observed during
sampling of MW01 and MW02. Reduced mass flux to
the near surface environment and subsequent
degradation along vertical and lateral transport
pathways would explain lack of detection in domestic
wells of compounds observed in MW02.
32
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4.0
Conclusions
The objective of this investigation was to determine
the presence of ground water contamination in the
Wind River Formation above the Pavillion gas field and
to the extent possible, identify the source of
contamination. The combined use of shallow and
deep monitoring wells allowed differentiation
between shallow sources of contamination (pits) and
deep sources of contamination (production wells).
Additional investigation is necessary to determine the
areal and vertical extent of shallow and deep ground
water contamination.
Detection of high concentrations of benzene, xylenes,
gasoline range organics, diesel range organics, and
total purgeable hydrocarbons in ground water
samples from shallow monitoring wells near pits
indicates that pits are a source of shallow ground
water contamination in the area of investigation. Pits
were used for disposal of drilling cuttings, flowback,
and produced water. There are at least 33 pits in the
area of investigation. When considered separately,
pits represent potential source terms for localized
ground water plumes of unknown extent. When
considered as whole they represent potential broader
contamination of shallow ground water. A number of
stock and domestic wells in the area of investigation
are fairly shallow (e.g., < 30 m) representing potential
receptor pathways. EPA is a member of a stakeholder
group working with the operator to determine the
areal and vertical extent of shallow ground water
contamination caused by these pits. The operator of
the site is currently engaged in investigating and
remediating several pit areas.
Detection of contaminants in ground water from deep
sources of contamination (production wells, hydraulic
fracturing) was considerably more complex than
detection of contaminants from pits necessitating a
multiple lines of reasoning approach common to
complex scientific investigations. In this approach,
individual data sets and observations are integrated to
formulate an explanation consistent with each data
set and observation. While each individual data set or
observation represents an important line of reasoning,
taken as a whole, consistent data sets and
observations provide compelling evidence to support
an explanation of data. Using this approach, the
explanation best fitting the data for the deep
monitoring wells is that constituents associated with
hydraulic fracturing have been released into the Wind
River drinking water aquifer at depths above the
current production zone.
Lines of reasoning to support this explanation consist
of the following.
1. High pH values
pH values in MW01 and MW02 are highly
alkaline (11.2-12.0), above the pH range
observed in domestic wells (6.9-10), and
above the pH range previously reported for
the Wind River Formation with up to 94% of
the total alkalinity contributed by hydroxide.
The presence of hydroxide alkalinity suggests
addition of base as the causative factor for
elevated pH in the deep monitoring wells.
Reaction path modeling indicates that sodium-
sulfate composition ground water typical of
deeper portions of the Wind River Formation
provides little resistance to elevation of pH
with small addition of potassium hydroxide.
With the exception of soda ash, the pH of
drilling additives in concentrated aqueous
solution was well below that observed in the
deep monitoring wells. Dense soda ash was
added to the drilling mud which varied
between pH 8 - 9.
The possibility of cement/grout intrusion into
the screened intervals was considered as a
possibility for elevated pH in both monitoring
33
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DRAFT
wells. However, cement intrusion typically
leads to pH values between 10 and 11 - below
that observed in deep monitoring wells.
Prolonged purging did not show decreasing
pH trends. Water chemistry results indicate
that ground water from the wells was highly
undersaturated with respect to cement
phases (e.g., portlandite).
Material Safety Data Sheets indicate that
potassium hydroxide was used in a crosslinker
(<5%) and in a solvent.
2. Elevated potassium and chloride
The inorganic geochemistry of ground water
from the deep monitoring wells is distinctive
from that in the domestic wells and expected
composition in the Wind River formation.
Potassium concentration in MW02 (43.6
mg/L) and MW01 (54.9 mg/L) is between 14.5
and 18.3 times the mean value of levels
observed in domestic wells (3 mg/L, 99% of
values < 10 mg/L). Chloride enrichment in
monitoring well MW02 (466 mg/L) is 18 times
the mean chloride concentration (25.6 mg/L)
observed in ground water from domestic
wells. Chloride concentration in this well is
significant because regional anion trends
show decreasing chloride concentrations with
depth. In addition, the monitoring wells show
low calcium, sodium, and sulfate
concentrations compared to the general trend
observed in domestic well waters.
Potassium levels in concentrated solutions of
drilling additives were all less than 2 mg/L.
One additive (Aqua Clear used during well
development) contained 230 mg/L chloride in
a concentrated solution. Information from
well completion reports and Material Safety
Data Sheets indicate that the formulation of
fracture fluid provided for foam jobs typically
consisted of 6% potassium chloride.
Potassium metaborate was used in
crosslinkers (5-10%, 30-60%). Potassium
hydroxide was used in a crosslinker (<5%) and
in a solvent. Ammonium chloride was used in
crosslinker (1-27%).
Alternative explanations for inorganic
geochemical anomalies observed in deep
monitoring wells have been provided and
considered. These alternate explanations
include contamination from drilling fluids and
additives, well completion materials, and
surface soil, with contamination from all these
sources exacerbated by poor well
development. Contamination by drilling fluids
and additives is inconsistent with analysis of
concentrated solutions of bentonite and
additives. Well construction materials (screen
and sections of casing) consisted of stainless
steel and were power-washed on site with
detergent-free water prior to use. Sections of
tremie pipe used to inject cement above
screened intervals were also power washed
with detergent-free water prior to use.
Stainless-steel screens and sections of casing
and tremie pipe remained above ground level
(did not touch soil) prior to use. Both deep
monitoring wells were purposefully located
away from the immediate vicinity of gas
production wells, known locations of pits, and
areas of domestic waste disposal (abandoned
machinery) to minimize the potential of
surface soil contamination. Conductor pipe
installed over the first 30.5 m (100 ft) of
drilling at both deep monitoring wells
eliminated the possibility of surface soil entry
into the borehole. Turbidity measurements in
MW01 during sampling ranged from 7.5 and
7.9 Nephelometric Turbidity Units (NTUs).
Turbidity measurements in MW02 during
sampling ranged from 24.0 to 28.0 NTUs,
slightly above the stated goal of 10.0 NTUs but
nevertheless was clear water typical of
domestic wells during sampling. A low
34
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DRAFT
recharge rate in MW02 necessitated a
prolonged period of well development which
was likely due in part to gas flow (reduced
relative permeability to water) into the well
during development.
Detection of synthetic organic compounds
Isopropanol was detected in MW01 and
MW02 at 212 and 581 j-ig/L, respectively.
Diethylene glycol was detected in MW01 and
MW02 at 226 and 1570 j-ig/L, respectively.
Triethylene glycol was detected in MW01 and
MW02 at 46 and 310 j-ig/L, respectively.
Another synthetic compound, ferf-butyl
alcohol, was detected in MW02 at a
concentration of 4470 i-ig/L. Tert-butyl alcohol
is a known breakdown product of methyl ferf-
butyl ether (a fuel additive) and ferf-butyl
hydroperoxide (a gel breaker used in hydraulic
fracturing). EPA methods were utilized for
analysis when applicable for compounds or
classes of compounds. Detection of synthetic
organic compounds in MW01 and MW02 was
made in part through the use of non-
commercially available modified EPA
analytical methods. For instance, high
performance liquid chromatography/mass
spectrometry/mass spectrometry was utilized
for analysis of diethylene, triethylene and
tetraethylene glycols. Ethylene glycol, which
was widely used for well stimulation, required
additional method modification and was not
analyzed during this investigation.
Isopropanol was detected in concentrated
solutions of drilling additives at a maximum
concentration of 87 |ag/L, well below that
detected in deep monitoring wells. Glycols
were not detected in concentrated solutions
of drilling additives.
Material Safety Data Sheets indicate that
isopropanol was used in a biocide (20-40%), in
a surfactant (30-60%), in breakers (<1%, 10-
30%), and in foaming agents (<3%, 1-5%, 10-
30%). Diethylene glycol was used in a foaming
agent (5-10%) and in a solvent (0.1-5%).
Triethylene glycol was used in a solvent (95-
100%). Material Safety Data Sheets do not
indicate that ferf-butyl hydroperoxide was
used in the Pavillion gas field. The source of
this compound remains unresolved. However,
ferf-butyl alcohol is not expected to occur
naturally in ground water. Material Safety
Data Sheets do not contain proprietary
information and the chemical ingredients of
many additives.
Alternative explanations provided to date and
considered by EPA for detection of synthetic
organic compounds in deep monitoring wells
include arguments previously listed and
addressed.
4. Detection of petroleum hydrocarbons
Benzene, toluene, ethylbenzene, and xylenes
(BTEX) were detected in MW02 at
concentrations of 246, 617, 67, and 750 ng/L
respectively. Trimethylbenzenes were
detected in MW02 at 105 i-ig/L. Gasoline
range organics were detected in MW01 and
MW02 at 592 and 3710 |ag/L, respectively.
Diesel range organics were detected in MW01
and MW02 at 924 and 4050 ng/L respectively.
Naphthalene was detected in MW02 at 6
Hg/L. EPA methods were utilized for analysis.
BTEX and trimethylbenzenes were not
detected in concentrated solutions of drilling
additives.
Material Safety Data Sheets indicate that
aromatic solvent (typically BTEX mixture) was
used in a breaker (<75%). Diesel oil (mixture
of saturated and aromatic hydrocarbons
including naphthalenes and alkylbenzenes)
was used in a guar polymer slurry/liquid gel
-------
DRAFT
concentrate (30-60%) and in a solvent (60-
100%). Petroleum raffinates (a mixture of
paraffinic, cycloparaffinic, olefinic, and
aromatic hydrocarbons) were used in a
breaker (<30-60%). Heavy aromatic
petroleum naphtha (mixture of paraffinic,
cycloparaffinic and aromatic hydrocarbons)
was used in surfactants (5-10%, 10-30%, 30-
60%) and in a solvent (10-50%). Toluene was
used in a flow enhancer (3-7%). Xylenes were
used in a flow enhancer (40-70%) and a
breaker (confidential percentage). Gasoline
range organics correspond to a hydrocarbon
range of C6 - C10. It includes a variety of
organic compounds ketones, ethers, mineral
spirits, Stoddard solvents, and naphthas.
Detection of gasoline range organics does not
infer the use of gasoline for hydraulic
fracturing.
Alternative explanations provided to date and
considered by EPA for detection of petroleum
compounds in deep monitoring wells include
arguments previously listed and addressed. An
additional alternate explanation for detection
of petroleum compounds includes use of
lubricants on the drillstem and well casing, use
of electrical tape on submersible pumps, and
components of submersible pumps. Jet Lube
Well Guard hydrocarbon free lubricant
specifically designed for monitoring well
installation was used for drillstem
connections. No lubricants were used to
attach sections of casing or sections of tremie
pipe during cementation. Clamps, not
electrical tape, were used to bind electrical
wires for submersible pumps. Water collected
for samples during recharge at MW01 and
MW02 would have a short contact time with
components of submersible pumps. For
components of submersible pumps to be a
causative factor of high concentrations of
petroleum hydrocarbons observed in MW01
and MW02, components of submersible
pumps would have to contain high levels of
water extractable petroleum compounds and
consist of a matrix allowing rapid mass
transfer, neither of which is plausible.
Another alternate explanation is that
detection of petroleum hydrocarbons in
ground water is expected above a natural gas
field. Gas from Fort Union and Wind River
Formations is dry and unlikely to yield liquid
condensates at ground water pressure and
temperature conditions. In addition, a
condensate origin for petroleum
hydrocarbons in ground water is doubtful
because dissolved hydrocarbon gas
compositions and concentrations are similar
between the two deep monitoring wells and
therefore would yield similar liquid
condensates, yet the compositions and
concentrations of organic compounds
detected in these wells are quite different.
Breakdown products of organic compounds
Detections of organic chemicals were more
numerous and exhibited higher
concentrations in the deeper of the two
monitoring wells. Natural breakdown products
of organic contaminants like BTEX and glycols
include acetate and benzoic acid. These
breakdown products are more enriched in the
shallower of the two monitoring wells,
suggesting upward/lateral migration with
natural degradation and accumulation of
daughter products.
Hydraulic gradients are currently undefined in
the area of investigation. However, there are
flowing stock wells (e.g., PGDW44 - one of the
deepest domestic wells in the area of
investigation at 229 m below ground surface)
suggesting that upward gradients exist in the
area of investigation. In the Agency's report
on evaluation of impacts to USDWs by
hydraulic fracturing of coalbed methane
36
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DRAFT
reservoirs (EPA, 2004), hypothetical
conceptual models were presented on
contaminant migration in a USDW during
injection of fracturing fluids into a USDW. In
these conceptual models, highly concentrated
contaminant plumes exist within the zone of
injection with dispersed lower concentration
areas vertically and laterally distant from
injection points. Data from deep monitoring
wells suggests that this conceptual model may
be appropriate at this site.
Sporadic bonding outside production casing
directly above intervals of hydraulic fracturing
It is possible that wellbore design and integrity
issues were one causative factor in deep
ground water contamination at this site
(surface casing of production wells not
extending below deepest domestic wells, little
vertical separation between fractured zones
and domestic wells, no cement or sporadic
bonding outside production casing).
A review of well completion reports and
cement bond/variable density logs in the area
around MW01 and MW02 indicates instances
of sporadic bonding outside production casing
directly above intervals of hydraulic fracturing.
For instance, at Pavillion Fee 34-03B, a cement
bond/variable density log conducted on
10/22/2004 indicated no cement until 838 m
(2750 ft) and sporadic bonding to 1036 m
(3400 ft) below ground surface. The well
completion report for this production well
indicates that hydraulic fracturing was
performed at 1039 m (3409 ft) below ground
surface on 11/9/2004 prior to cement squeeze
jobs at 823 m (2700 ft) and 256 m (840 ft)
below ground surface in April 2005. At Tribal
Pavillion 41-10 a cement bond/variable
density log indicates sporadic bonding directly
above the interval of hydraulic fracturing at
493 m (1618 ft) below ground surface. A
cement bond/variable density log conducted
7.
on Tribal Pavillion 24-02 after a squeeze job at
the base of the surface casing indicates
sporadic bonding outside production casing
below surface casing to the interval of
hydraulic fracturing at 469 m (1538 ft) below
ground surface. At Tribal Pavillion 11-11B, a
cement bond/variable density log indicates
sporadic bonding between 305 to 503 m
(1000 to 1650 ft) below ground surface with
hydraulic fracturing occurring at 463 m (1516
ft) below ground surface.
Hydraulic fracturing into thin discontinuous
sandstone units
There is little lateral and vertical continuity to
hydraulically fractured tight sandstones and
no lithologic barrier (laterally continuous shale
units) to stop upward vertical migration of
aqueous constituents of hydraulic fracturing in
the event of excursion from fractures.
Sandstone units are of variable grain size and
permeability indicating a potentially tortuous
path for upward migration.
In the event of excursion from sandstone
units, vertical migration of fluids could also
occur via nearby wellbores. For instance, at
Pavillion Fee 34-03R, the cement
bond/variable density log indicates no cement
until 671 m (2200 ft) below ground surface.
Hydraulic fracturing occurred above this depth
at nearby production wells.
Although some natural migration of gas would be
expected above a gas field such as Pavillion, data
suggest that enhanced migration of gas has occurred
to ground water at depths used for domestic water
supply and to domestic wells. Lines of reasoning to
support this explanation consist of following.
1. Hydrocarbon and isotopic composition of gas
The similarity of 613C values for methane,
ethane, propane, isobutane, and butane
-------
DRAFT
between gas production and monitoring wells
and plots of 613C-CH4 versus 6D -CH4 and 613C-
CH4 versus methane/(ethane + propane)
indicate that light hydrocarbons in casing and
dissolved gas in deep monitoring wells are
similar to produced gas and have undergone
little oxidation or biodegradation indicative of
advective transport. The absence of ethane
and propane in three of four domestic wells
having sufficient methane to allow isotopic
analysis and a shift of 613C-CH4 and 6D-CH4
values in a positive direction relative to
produced gas suggests the presence of gas of
thermogenic origin in domestic wells
undergoing biodegradation. This observation
is consistent with a pattern of dispersion and
degradation with upward migration observed
for organic compounds.
2. Elevation of dissolved methane
concentrations in proximity to production
wells
Levels of dissolved methane in domestic wells
generally increase in those wells in proximity
to gas production wells. With the exception of
2 domestic wells where methane was
detected at less than 22 i-ig/L, methane was
not detected in domestic wells with 2 or less
production wells within 600 m.
3. Spatial anomaly near PGDW05
Methane concentrations in ground water
appear highest in the area encompassing
MW01, PGDW30, and PGDW05. Ground
water is saturated with methane at MW01
which is screened at a depth (239 m bgs)
typical of deeper domestic wells in the area.
Methane was detected in PGDW30 at 808
Hg/L at a depth of only 80 m, the highest level
in any domestic well. A blowout occurred
during drilling at a depth of only 159 m bgs in
December 2005 adjacent to PGDW05.
An alternative explanation of high methane
concentrations in this area is that it is close to
the top of the dome comprising the Pavillion
gas field which may facilitate natural gas
migration toward the surface. However, this
geologic feature would also facilitate
enhanced gas migration. Also, a mud-gas log
conducted on 11/16/1980 (prior to intensive
gas production well installation) at Tribal
Pavillion 14-2 located only 300 m from the
location of the uncontrolled release does not
indicate a gas show (distinctive peaks on a gas
chromatograph) within 300 m of the surface.
4. Shallow surface casing and lack of cement or
sporadic bonding outside production casing
With the exception of two production wells,
surface casing of gas production wells do not
extend below the maximum depth of
domestic wells in the area of investigation.
Shallow surface casing combined with lack of
cement or sporadic bonding of cement
outside production casing would facilitate
migration of gas toward domestic wells.
The discussion on migration of fluids
associated with hydraulic fracturing is relevant
for gas migration and is not repeated here for
brevity. Of particular concern are wellbores
having no or little cement over large vertical
instances. For instance, at Pavillion Fee 34-
03R, the cement bond/variable density log
indicates no cement until 671 m (2200 ft)
below ground surface. At Pavillion Fee 34-03B,
a cement bond/variable density log conducted
on 10/22/2004 indicated no cement until 838
m (2750 ft) below ground surface. Migration
of gas via wellbores having no cement or poor
cement bonding outside production casing is
well documented in the literature.
An alternative explanation of wellbore gas
migration provided to EPA and considered is
that domestic wells are poorly sealed and thus
38
-------
DRAFT
constitute a potential gas migration pathway.
However, lack of cement and sporadic
bonding outside casing in production
constitutes a major potential gas migration
pathway to the depth of deep monitoring and
domestic wells. It is possible that domestic
wells could subsequently facilitate gas
migration toward the surface.
5. Citizens' complaints
Finally, citizens' complaints of taste and odor
problems concurrent or after hydraulic
fracturing are internally consistent. Citizens'
complaints often serve as the first indication
of subsurface contamination and cannot be
dismissed without further detailed evaluation,
particularly in the absence of routine ground
water monitoring prior to and during gas
production.
An alternate explanation provided and
considered by EPA is that other residents in
the Pavillion area have always had gas in their
wells. Unfortunately, no baseline data exists
to verify past levels of gas flux to the surface
or domestic wells.
Hydraulic fracturing for coal-bed methane recovery is
often shallow and occurs directly into USDWs (EPA
2004). TDS less than 10,000 mg/L in produced water
is common throughout the Rocky Mountain portion of
the United States (USGS 2011; Dahm et al. 2011).
Ground water contamination with constituents such
as those found at Pavillion is typically infeasible or too
expensive to remediate or restore (GAO 1989).
Collection of baseline data prior to hydraulic fracturing
is necessary to reduce investigative costs and to verify
or refute impacts to ground water.
Finally, this investigation supports recommendations
made by the U.S. Department of Energy Panel (DOE
2011a, b) on the need for collection of baseline data,
greater transparency on chemical composition of
hydraulic fracturing fluids, and greater emphasis on
well construction and integrity requirements and
testing. As stated by the panel, implementation of
these recommendations would decrease the
likelihood of impact to ground water and increase
public confidence in the technology.
A lines of reasoning approach utilized at this site best
supports an explanation that inorganic and organic
constituents associated with hydraulic fracturing have
contaminated ground water at and below the depth
used for domestic water supply. However, further
investigation would be needed to determine if organic
compounds associated with hydraulic fracturing have
migrated to domestic wells in the area of
investigation. A lines of evidence approach also
indicates that gas production activities have likely
enhanced gas migration at and below depths used for
domestic water supply and to domestic wells in the
area of investigation.
Hydraulic fracturing in the Pavillion gas field occurred
into zones of producible gas located within an
Underground Source of Drinking Water (USDW).
39
-------
5.0
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43
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DRAFT
Appendix A
Summary of Analytical Results
A1
-------
Table Al. Summary of subsurface sample locations, depth of sample collection, times (phases) of sampling, target analytes, laboratories utilized, and analytical methods
Sample
Latitude
Longitude
Depth
(m bgs)
Type
Media
Major
anions arid
alkalinity
phase(lab)
Metals
phase(lab)
Alcohols
and VOCs
phase(lab)
Low
molecular
weight
acids, glycols
phase(lab)
SVOCs
Pesticides
PCBs, TICs
phaseflab)
GRO, DRO,
THE, TPH
pbase(lab)
Bacteria
phase(lab)
Fined gases,
CiQ4,
613C and 6D C,-C,
DOC
DIC, 6UC D1C
and 6D water
PGPP01 (Tribal
Paviliion 14-10}
43.245788S7
-108.6356735
PG
gas/
fluid
—
-
ll(R82)
•
11(R8J)
tl(R8*)
....
m
PGPP02
43,2486496 ' -108.6274796
PG
ess
......
—
—
ik^)
PGPP04 (Tribal
Paviliion 24-02)
1
43.25984955 -108.G11G409
1
PG
gas /
fluid
M(R8'}
IURS5)
IKR84)
HO')
PGPP05 (Tribal
Paviliion 33-10}
43.2486496 -108,6274796
PG
gas/
fluid
(i(R82)
11(R83)
ll(R84)
—
110')
PGPP06 (Tribal
Paviliion 14-2)
43.26016998 -108,6165009
PG
gas/
fluid
—
tl(R8z)
ll(R83)
ll(R84)
mi1)
MW01
|
43,25682 -108.62185
233-
239
MW
gas/
water
III(O)
IV(O')
nits1) iv(s') "KM
II (A, RS3)
IV|R83)
l(Es)
IKE2, RS4)
l(E') ll(E')
l(R85)
l)(R8s)
IV(IJ,0J,03,SC1
-------
Sample
Latitude
Longitude
Depth
|m bgs)
Type
Media
Major
anions and
alkalinity
phase(lab)
Metals
pliase(lab)
Alcohols
and VQCs
phase(lab)
Low
molecular
weight
acids, glycols
phase (lab)
SVOCs
Pesticides
PCBs, TICs
phase(lab)
GRO, ORO,
THE, TPH
phase|lab)
Bacteria
phase(lab)
Fixed gases,
Cr Cr,+,
613C and 6D C,-C
DOC
DIC, 6UCDIC
fi'*0 and 6D water
PGDW06
43.27110813
-108.5599211
115.8
DW
water
l(R8!)
l(K)
km
—
t(L,R83)
—
—
PGDW07
43.24678442
-108.6879085
154,2
PGP
water
l(RS')
l(K)
KM
_
1&.R83)
—
I(RS3)
PGDW08
43.24697265
-108.6840567
157,0
PGP
water
l(R83)
l(K)
KM
1(L.R8')
PGDWG9
43.27211644
-108.615144
9.1
DW
water
ICRS')
l(K)
KM
)(L,R8S)
—
—
PGDW10
43.23574855
-108.6S63896
227,1
DW
water
l(RS')
ll(RB')
l(K)
ll{A4)
l(L) ll[A,R8')
—
I(L,R8S)
II (A, RE3)
I(EJ)
II(£!,R84)
H(E!|
f(R84)
ll[l',R85)
PGDW11
43.24312049
-108.6228628
227,1
DW
water
l(R8')
KKl
KM
i(L,RSJ)
PGDW12
43.27628927
-108.5661502
115,8
DW
water
l(H8")
l(K)
KM
KL.Ra4)
PGDW13
43.2444457
-108.6772771
DW
water
f(RS')
i(K)
KM
t(L,RS')
PGDW14
43.25154027
-108.6273311
57.9
DW
water
l(R8')
l(K)
KM,
IV|R8J,SJ)
IV(S*,R3)
t(L,R8J)
IV(0',5*)
PGDW1S
43.24312129
-108.6671791
30.5
DW
water
l(RS')
l(K)
KM
t(L,R85)
—
_
PGDW16
43.20381363
-108.6405183
1615
DW
water
l(RS')
«K)
KM
1
>
UJ
-------
>
Sample
Latitude
Longitude
Pepth
(m fags)
Type
Media
Major
anions and
alkalinity
phase(lab)
phase(lab)
Alcohols
and VOCs
phiase(lab)
Low
molecular
weight
acids, glycols
phase(lab)
SVOts
Pesticides
PCBs, TICs
phase(lab)
GRO, DRO,
THE, TPH
phase (lab)
Bacteria
phase(lab)
Fixed gases,
C i C*
s"c and 6D C, C,
DOC
DIC, aljc DIC
6'"0 and 6D water
PGDW30
43.25753218
-108.6225755
79.2
DW
water
l(RS')
ll(RS')
111(0*)
IV(O')
l(K)j tl(A4l
Itl (51) IVfS1)
1(1) lt(A, R8Z)
lll[R8J,SJ)
IV(R83,S3|
iv(s\r3)
l
1
ll{E;,R8J)
IV(RB')
"(E1)
1(R85)
ll(R85)
IV(I:, 6', 03,S6)
PGDW33
43.23855522
-108 5964146
9.1
DW
water
l(RS')
<(K)
l(L)
t(L,Ri?J]
PGDW34
43.23605297 -108.6058086
30.5
DW
water
tfRB1)
KK)
KL)
f(L,R83)
PGDW35
43.23021564 -108.6241763
88.4
DW
water
l£R8!)
l(K)
1(L)
((L.RS3)
IjRB1!
PGDW36
43.25905726
108,5987059
30.5
DW
water
l(RS')
UK)
1(1)
l(L,RSs)
KE1)
PGDW37
43,24016136
1086585376
24.4
DW
water
t(R8")
KK)
l(L)
t(L,R8')
—
PGDW38
43.2296203
-108.572037
48.8
DW
water
l(R8;)
l(K)
KM
1(1,R8J)
l(FJ)
1(R8S)
PGDW39
43.23750687
108.5781708
6.1
DW
water
l(L) lt(R8)
1(1). ll(A4j
KU,
M(A,H8JJ
KL.R8'),
ll(A,R83)
IKE1}
PGDW40
43.26156616
-108.6198273
67.1
DW
water
llfRS)
ll(A4)
ll(A,R8J)
ll(A,R85}
ll(E2,RSaJ
IKE1)
ilii'.RS5)
PGDW41
43.262146
108.6378479
114.6
DW
water
ll(R8),
IV(0L)
ll(A4)IV(S')
ll(A, R8J)
IV(R8J,5a)
IV(S\R3)
ll(A,R8')
(V
llfE^RS4),
IV
-------
DRAFT
Laboratories, Analytes, and Methods
A - ALS Laboratory Group, Salt Lake City, UT. VOCs, SVOCs, pesticides, TCBs, TICs determined using methods specified under the CLP.
A4 - A4 Scientific, The Woodlands, TX. TAL metals determined using methods specified under the CLP.
E1 - Energy Laboratories Inc., Billings, MT. Heterotrophic plate counts, iron reducing bacteria, sulfur reducing bacteria.
E2 - Energy Laboratories Inc., Billings, MT. GRO, DRO, THE, and TPH.
11 - Isotech Laboratories, Champaign, IL under contract by EnCana. Fixed gases and light hydrocarbons determined using ASTM D1945-03 in gas samples
and headspace of aqueous samples. 613C and 6D for Ci determined using gas stripping and I RMS in aqueous samples. 613C and 6D for CrC4 determined
using IRMS for gas samples.
12 - Isotech Laboratories, Champaign, IL. Fixed gases and light hydrocarbons determined using ASTM D1945-03 in headspace of aqueous samples. 613C and
6D for Ci and 613C for C2 and C3 determined using gas stripping and IRMS in aqueous samples. 613C DIC using gas stripping and IRMS.
13 - Isotech Laboratories, Champaign, IL. Fixed gases and light hydrocarbons determined using ASTM D1945-03 in headspace of aqueous samples. 613C and
6D for Ci, 613C for C2 - C5, and 613C for DIC gas stripping and IRMS in aqueous samples.
14 - Isotech Laboratories, Champaign, IL. Fixed gases and light hydrocarbons determined using ASTM D1945-03 in gas samples. 613C and 6D for Ci - C3 using
IRMS in gas samples.
15 - Isotech Laboratories, Champaign, IL. Fixed gases and light hydrocarbons determined using ASTM D1945-03 in gas samples. 613C and 6D for Ci - C3 using
IRMS in gas samples. 14C using AMS in gas samples.
K - KAP Laboratories, Vancouver, WA. TAL metals determined under the CLP.
L - Liberty Analytical, Salt Lake City, UT. VOCs, SVOCs, PCBs, and TICs determined under the CLP.
01 - EPA, ORD, Ada, OK. S04, CI, F, and Br determined using RSKSOP 276v3 and EPA Method 6500. N03 + N02 and NH4 determined using RSKSOP 214v5
and EPA Method 350.1 and 353.2
02 - EPA, ORD, Ada, OK. DIC and DOC determined using RSKSOP-330v0 and EPA Method 9060A.
03 - EPA, ORD, Ada, OK. Ci determined using RSKSOP 175v5 and Cali-5 gas sampling bags.
R3 - U.S. EPA Region 3 Laboratory, Fort Mead, MD. Diethylene glycol, triethylene glycol, tetraethylene glycol, and 2-butoxyethanol analysis by LC/MS/MS.
This method is under development with no finalized SOP. EPA Methods 8000C and 8321 were followed for method development and QA/QC limits where
applicable.
R81 - U.S. EPA Region 8 Laboratory, Golden, CO (fluoride, chloride, nitrite-N, nitrate-N, orthophosphate-P, and sulfate determined using EPA Method 300.0
and EPA Region SOP 310. Alkalinity determined using EPA Method 310.0).
R82 - U.S. EPA Region 8 Laboratory, Golden, CO. VOCs determined using EPA Method 8260B.
R83 - U.S. EPA Region 8 Laboratory, Golden, CO. SVOCs determined using ORGM-515 rl.l and EPA Method 8270D.
R84 - U.S. EPA Region 8 Laboratory, Golden, CO. GRO determined using ORGM-506 rl.O and EPA Method 8015D. DRO determined using ORGM-508 rl.O
and EPA Method 8015D.
R85- U.S. EPA Region 8 Laboratory, Golden, CO. Dissolved Ci in Phase I and dissolved CrC3 in Phase II using EPA Method 524.2.
51 - Shaw Inc, Ada, OK in Phases III and IV. Metals and metals speciation determined using RSKSOP 213v4 and 257v2, or 332V0 and EPA Methods 200.7 and
6020.
52 - Shaw Inc, Ada, OK in Phases III and IV. Aromatics and chlorinated hydrocarbons determined using method RSKSOP-259vl and EPA Method 5021A plus
8260C.
53 - Shaw Inc, Ada, OK . Alcohols, aromatics, and chlorinated hydrocarbons determined using method RSKSOP-259vl.
54 - Shaw Inc, Ada, OK. Low molecular weight acids determined using RSKSOP-112v6.
55 - Shaw Inc, Ada, OK. Dissolved gases CrC4 determined using RSKSOP 194v4 and 175v5.
56 - Shaw Inc, Ada, OK. Hydrogen and oxygen isotope ratios of water determined using RSKSOP-296vO.
A5
-------
DRAFT
Abbreviations
I () - Phase l(laboratory/method). Samples collected March, 2009
ll() - Phase ll(laboratory/method). Samples collected January, 2010
lll() - Phase lll(laboratory/method). Samples collected September and October 2010
IV() - Phase IV(laboratory/method). Samples collected April 2011.
PG - gas production well
MW - deep monitoring wells
PGM - shallow monitoring wells near pits
PGS - soil samples near pits
DW - domestic wells
PGP - municipal wells in the Town of Pavillion
IRMS - isotope-ratio mass spectrometry
AMS - accelerated mass spectrometry
Ci (methane), C2 (ethane), C3 (propane), iC4 (isobutane), nC4 (normal butane), iC5 (isopentane),
hydrocarbons)
VOCs - volatile organic compounds
SVOCs - semivolatile organic compounds
PCBs - polychlorinated biphenyls
TICs - tentatively identified compounds
DRO - diesel range organics
GRO - gasoline range organics
TEH - total extractable hydrocarbons
TPH - total purgeable hydrocarbons
DIC - dissolved inorganic carbon
TAL - target analyte list
CLP - U.S. EPA Contract Laboratory Program
nC5 (normal pentane), C6+ (hexanes + other light
Analytical Methods
ORGM-506 rl.O - Region 8 Standard Operating Procedure.
ORGM-508 rl.O - Region 8 Standard Operating Procedure.
ORGM-515 rl.l - Region 8 Standard Operating Procedure.
RSKSOP-112v6 - Standard Operating Procedure for Quantitative Analysis of Low Molecular Weight Acids in Aqueous Samples by HPLC, 22 p.
RSKSOP-175v5 - Sample Preparation and Calculations for Dissolved Gas Analysis in Water Samples Using a GC Headspace Equilibration Technique, 16 p.
RSKSOP-194v4 - Gas Analysis by Micro Gas Chromatographs (Agilent Micro 3000), 13 p.
RSKSOP-213v4 - Standard operating procedure for operation of Perkin Elmer Optima 3300 DV ICP-OES, 21 p.
RSKSOP-214v5 - Quality control procedures for general parameters analysis using Lachat Flow Injection analysis (FIA), 10 p.
RSKSOP-259vl - Determination of volatile organic compounds (fuel oxygenates, aromatic and chlorinated hydrocarbons) in water using automated
headspace gas chromatography/mass spectrometry TEKMAR 7000 HS-Varian 2100T GC/MS system-ION trap detector, 28 p.
RSKSOP-257v2 - Standard operating procedure for elemental analysis by ICP-MS, 16 p.
RSKSOP-299vl - Determination of Volatile Organic Compounds (Fuel Oxygenates, Aromatic and Chlorinated Hydrocarbons) in Water Using Automated
Headspace Gas Chromatography/Mass Spectrometry (Agilent 6890/5973 Quadruple GC/MS System), 25 p.
RSKSOP-276v3 - Determination of major anions in aqueous samples using capillary ion electrophoresis with indirect UV detection and Empower 2
software, 11 p.
RSKSOP-296vO - Determination of hydrogen and oxygen isotope ratios in water samples using high temperature conversion elemental analyzer (TC/EA), a
continuous flow unit, and an isotope ratio mass spectrometer (IRMS), 8 p.
RSKSOP-297vl - Metals Speciation Determination by LC/ICP-MS, 21 p.
RSKSOP-298vl - Arsenic Speciation Determination by LC/ICP-MS with Anion Suppression and NaOH Mobile Phase, 21 p.
RSKSOP-313vl - Determination of R-123 using the H25-IR Infrared Refrigerant Gas Leak Detector, 12 p.
RSKSOP-314vl - Determination of Fixed Gases using the GEM2000 and GEM2000 Plus Gas Analyzers & Extraction Monitors, 13 p.
RSKSOP-320vl - Determination of Organic and Inorganic Vapors Using the TVA-1000B Toxic Vapor Analyzer, 18 p.
RSKSOP-330v0 - Determination of Various Fractions of Carbon in Aqueous Samples Using the Shimadzu TOC-VCPH Analyzer, 16 p.
U.S. EPA Method 200.7 - Determination of Metals and Trace Elements in Water and Wastes by Inductively Coupled Plasma-Atomic Spectrometry, Rev. 5,
Jan 2001.
U.S. EPA Method 300.0 - Determination of Inorganic Anions by Ion Chromatography, Rev. 2.1, Aug. 1993.
U.S. EPA method 310.1 - Alkalinity (Titrimetric, pH 4.5), Rev. 1978.
U.S. EPA Method 350.1 - Determination of Ammonia Nitrogen by Semi-Automated Colorimetry, Rev. 2, Aug. 1993.
A6
-------
DRAFT
U.S. EPA Method 5021A - Volatile Organic Compounds in Various Sample Matrices Using Equilibrium Headspace Analysis, Rev. 1, June 2003.
U.S. EPA Method 6020- Inductively Coupled Plasma-Mass Spectrometry, Rev. 1, Feb. 2007.
U.S. EPA Method 6500 - Dissolved Inorganic Anions in Aqueous Matrices by Capillary Electrophoresis, Rev. 0, Feb. 2007.
U.S. EPA Method 8260C - Volatile Organic Compounds by Gas Chromatography/Mass Spectrometry (GC/MS), Rev. 3, Aug. 2006.
U.S. EPA Method 8015B - Determination of Nonhalogenated Organics Using GC/FID, Rev. 2, Dec. 1996.
U.S. EPA Method 8015D - Nonhalogenated Organics Using GC/FID, Rev. 4, May 2003.
U.S. EPA Method 8270D - Determination of Semivolatile Organic Compounds by Gas Chromatography/Mass Spectrometry (GC/MS), Rev. 4, Feb. 2007.
U.S. EPA Method 8000C - Determinative Chromatographic Separations, Rev. 3, Mar. 2003.
U.S. EPA Method 8260C - Volatile Organic Compounds by Gas Chromatography/Mass Spectrometry (GC/MS), Rev. 3, Aug. 2006.
U.S. EPA Method 8270D - Semivolatile Organic Compounds by Gas Chromatography/Mass Spectrometry (GC/MS), Rev. 4, Feb. 2007.
U.S. EPA Method 9060A-Total Organic Carbon, Rev. 1, Nov. 2004.
-------
DRAFT
Table A2a. Geochemical results for Pavillion ground water
Sample
ID
T
(cc)
PH
SC
(jiS/cm)
Alkalinity
(mg/k£>
Na
(pprn)
K
(ppm)
Ca
(ppm)
Mg
(ppm)
CI
(ppm)
SO4
(ppm)
F
(ppm)
NO,
(N)
(ppm)
PGDW01
2
8
6
3
9
3-1.1
1860
0
6.2
PGDVV02
13.4
8.11
551
108
86
1.8
34.8
5.3
2.6
175
0.7
<0.5
PGDW03
> 11.1
9.37
1333
40
272
0.4
16.3
0.3
25.1
549
0.9
<0.5
PGDW04
J 11.8
9.17
1370
29
270
0.4
18.0
0.1
21.6
551
0.9
<0.5
PGDW05
1 12.0
9.02
956
93
192
0.3
3.6
0.1
17
295
0.9
<0.5
PGDW06
f 13.8
10.20
1262
35
249
0.3
7.1
<0.1
31
485
1.3
<0.5
PGDW07
i 12.4
8.85
1016
61
213
0.3
8.9
0.1
15.7
390
1.2
<0.5
PGDW08
f 12.4
8.5/
1883
83
390
0.6
36./
0.2
18.9
85/
0.5
<0.5
PGDW09
12.4
8.35
1128
254
233
2.1
16.6
4.1
10.5
279
2.4
3.2
PGDW10
12.2
8.95
9
147
2
0
6
0
8
2
0
<0.5
PGUW11
13.1
7.17
3400
312
423
5.5
363
80.9
15.3
1/80
0.2
1.3
PGDW12
> 12.4
10.04
1344
37
256
0.6
7.8
0.4
30.8
497
1.5
<0.5
PGDW13
J 10.9
6.89
1155
303
196
1.9
61.0
19.9
6.2
343
0.7
1.0
PGDW14
I 10.8
/.85
2990
159
690
4.5
154
18.1
26.1
1820
0.4
0./
PGDW15
f 11.4
7.48
1728
277
269
1.2
72.2
10.2
9.9
520
0.6
1.8
PGDW16
i 13.2
9.30
1011
145
188
0.3
6.4
0.1
13.4
258
0.8
<0.5
PGDW17
f 12.7
9.61
1490
21
2/8
0.4
21.2
0.5
49.5
583
2.0
<0.5
PGDW18
i 10.3
8.87
2002
21
509
0.8
84.5
0.3
27
1380
1.8
0.5
PGDW19
11.8
7.75
7
291
1
1
2
3
6
1
0
2.6
PGDW20
9.3
8.76
2005
70
""52O
1
7
9
3
1370
0
<0.5
PGDW22
> 8.3
6.93
6180
332
837
9.0
416
126
7
2720
<0.2
43.6
PGDW23
J 11.5
9.13
816
61
208
0.3
6.5
0.1
19.8
365
1.2
<0.5
PGDW24
I 9.7
7.65
4700
165
938
7.0
327
131
55.7
3200
0.6
<0.5
PGDW25
f 13.3
8.68
972
205
249
1.1
1.1
1.1
8.4
355
4.1
<0.5
PGDW26
i 9.2
7.13
2390
337
220
6.8
364
57.7
14.6
1240
0.7
1.5
PGDW28
f 10.7
8.30
1170
258
239
2.2
40.6
12.9
16.7
298
0.5
3.7
PGDW29
1 11.5
9.72
1442
52
298
0.4
19.7
0.5
52.3
596
0.9
<0.5
PGDW30
1 104
9.60
9
96
2
0
0
0
1
3
0
<0.5
PGDW31
9.0
8.60
2006
83
4
0
3
0
1
1030
0
0.5
PGDW32
> 9.5
10.47
908
34
199
0.3
7.2
<0.1
34.1
373
2.3
<0.5
PGDW33
J 3.7
7.77
1662
276
178
5.0
228
40.9
28
670
0.2
2.1
PGDW34
t 8.3
7.87
4480
373
786
7.4
325
113
23
2690
0.5
3.5
PGDW35
1 10.6
8.63
2810
84
587
1.1
118
1.1
24.1
1610
0.3
0.5
PGDW36
i 9.8
7.62
649
232
42
2.6
89.5
28.9
3.2
195
1.0
1.2
PGDW37
f 10.5
8.14
819
342
187
0.9
12.1
1.3
8.7
89.9
0.9
1.2
PGDW38
i 9.5
8.68
2030
47
373
2.3
70.0
2.3
46.9
908
1.3
5.9
PGDW39
> 6.7
7.79
6410
127
1110
5.3
389
147
52.9
3640
0.4
0.6
PGDW40
J 11.5
9.06
1229
86
244
5.0
6.6
5.0
13.1
426
<0.3
PGDW41
1 7.2
7.63
4470
108
1030
2.7
270
57.5
31.4
2670
0.5
<0.3
PGDW42
f 12.1
9.18
888
89
181
5.0
5.1
5.0
13.2
311
1.0
<0.3
PGDW43
i 0.2
8.19
4410
113
911
5.0
208
13.7
38.4
2470
0.4
<0.3
PGDW44
1 9.4
8.13
4080
100
994
5.0
259
28.3
39.5
2880
0.3
<0.3
PGDW45
i 9.3
7.63
1103
379
59
2.6
138
31.2
14.5
213
1.9
0.3
PGDW46
f 7.9
7.79
855
329
91
1.8
90.3
9.9
8.4
126
0.5
2.3
PGDW47
8.2
9.52
970
44
183
5.0
6.9
5.0
21.6
330
1.5
<0.3
PGDW48
> 8.7
8.21
3550
90
725
5.0
147
4.4
24.1
1840
0.3
<0.3
PGDW49
J 7.8
7.66
5470
243
1210
11.4
486
153
64.3
3160
0.4
7.7
PGDW03-0110
> 8.3
8.71
1390
28
251
5.0
16.3
5.0
20.7
570
0.8
<0.3
PGDW04-0110
J 8.3
9.07
1388
38
265
5.0
15.5
5.0
23.3
532
0.9
PGDW05-0110
> 9.4
8.22
900
88
188
5.0
3.3
5.0
16.5
287
0.9
<0.3
PGDW10-0110
J 10.4
8.62
985
147
195
5.0
5.8
5.0
7.5
293
0.9
<0.3
PGDW20-0110
9.3
8.89
2690
68
550
5.0
71.7
8.1
32.6
1270
0.8
<0.3
PGDW22-0110
8.2
7.06
4230
337
9
'""5.8
3
1
7-1.6
2780
40.7
PGDW23-0110
8.2
9.72
7
54
1
5.0
""5.8
"To
1
3
1
<0.3
PGDW25-0110
J 7.2
7.94
1511
295
269
5.0
70.1
9.6
9.5
441
1.7
PGDW30-0110
> 9.2
9.39
967
94
195
5.0
4.1
5.0
15.5
333
0.9
<0.3
PGDW32-0110
! 8.3
9.87
1018
32
193
5.0
6.9
5.0
21.4
368
2.4
<0.3
A8
-------
DRAFT
Sample
ID
T
rc)
pH
SC
(US/cm)
Alkalinity
mg/kg
Na
(ppm)
(ppm)
Ca
(ppm)
Mg
(ppm)
CI
(ppm)
SO,
(ppm)
(ppm)
NO,
(N)
(ppm)
MW01
11.8
11.91
3265
430
334
5
15.6
0.05
23.3
398
1
0.15
MW02
I 12.3
12.01
3812
456
420
39.5
73.3
0.03
466
12.1
1.0
0.38
RD01
I 11.5
9.24
1068
78
208
0.2
4.3
0.10
15.2
357
1.0
0.23
LD01
i 10.9
8.85
2940
54
562
1.1
71.9
8.1
33.0
1320
0.9
0.35
PGDW05-0411
i 10.5
9.06
820
80
190
0.24
3.35
0.08
16.8
276
1.2
ND
PGDW14-0411
8.5
7.73
3473
156
753
3.52
154
18.6
23.7
1760
<0.05
0.36
PGDW20-0411
8.3
8.59
2430
102
520
0.78
63
6.86
22.9
1150
1.3
<0.03
PGDW23-0411
i ii.o
9.07
959
72
208
0.31
6.7
0.17
19.9
365
1.6
<0.03
PGDW26-0411
8.3
6.95
2390
196
232
5.15
334
56
13.2
1180
1.0
1.37
PGDW30-0411
10.4
8.92
938
82
210
0.29
4.5
0.09
16.1
327
1.1
<0.03
PGDW32-0411
11.1
9.30
885
46
198
0.09
7.2
0.03
18.8
361
2.0
<0.03
PGDW41-0411
8.2
7.05
4866
112
896
3.18
452
46.9
97.6
2640
<0.05
17.5
PGDW44-0411
i 10.0
8.17
4730
94
1060
2.09
259
19.2
32.1
2900
<0.05
<0.03
PGDW45-0411
9.1
6.85
1085
364
61.6
2.81
159
34.5
18.4
251
1.7
0.64
PGDW49-0411
10.4
7.34
5333
296
982
9.66
417
127
54.3
3200
<0.05
8.75
MW01-0411
i 11.2
11.24
2352
388
304
24.7
13.6
0.12
23.1
339
1.9
<0.03
MW02-0411
i 12.0
11.78
3099
482
448
43.6
60.5
0.03
457
63
1.5
<0.03
not measured. SC - specific conductance. Alkalinity - mg/kg CaC03. Other cations detected include Al (0.05 to 0.74 ppm), Ba (0.01 to 0.21
ppm), Fe (<0.02 to 2.4 ppm), Mn (<0.01 to 0.23 ppm), NH4+ (0.4 to 4.6 ppm), and Sr (0.06 to 8.4 ppm). Sulfide was detected in LD01 (0.16 ppm,
Phase III, same location as PGDW20), PGDW20 (0.12 ppm, Phase IV), and MW01 (1.1 ppm Phase III, 1.8 ppm Phase IV). Turbidity ranged from
1.7 to 29.7 in domestic wells (Phase III and IV). Turbidity in MW01 was 7.5 (Phase III) and 7.9 (Phase IV). Turbidity in MW02 was 28.8 (Phase III)
and 24.0 (Phase IV). All turbidity values are in Nephelometric Turbidity Units (NTUs). Turbidity measurements in MW01 and MW02 could be
impacted by gas exsolution.
Table A2b. Charge balance calculations for deep monitoring wells
Well
Phase
Ca,
meq
Mg,
meq
Na,
meq
K,
meq
SO4,
meq
C03,
meq
CI,
meq
F,
meq
OH,
meq
Icat,
meq
Ian,
meq
Balance,
%
cations anions
MW01
III
0.78
0.00
14.53
1.40
8.29
4.48
0.66
0.08
9.56
16.71
2-5.08
16.0
MW02
III
¦5.66
0.00
18.27
1.01
0.25
3.40
13.14
0.05
12.04
22.94
28.89
11.5
MW01
IV
0.68
0.01
1-5.22
0.63
7.06
2.12
0.65
0.10
1.97
14.54
11.90
10.0
MW02
IV
¦5.02
0.00
19.49
1.12
1.30
0.2-5
12.89
0.08
7.01
2-5.h2
21.52
4.7
Balance (%) = |(Zcat-Zan)/(Zcat+Zan)*100|. meq OH is calculated as 1000*[oOh-/Yoh-], where a0H- = lO"(14"pH| and y0H- = 0.85 to 0.88. meq C03 is
estimated from measurements of Dissolved Inorganic Carbon (DIC) as 2*[DIC/12], where DIC is in mg/L.
A9
-------
DRAFT
Table A3a. Summary of aqueous analysis of light hydrocarbons
Sample (matrix)
Phase
Date
Ci
(ug/l)
Cz
(ug/l)
c3
(ug/l)
C,
(ug/l)
MW01(w)
III
10/6/2010
15950
2230
790
158
MW01(w)
IV
4/20/2011
17930
2950
1250
172
MW02(w)
III
10/6/2010
18990
3290
1820
355
MW02(w)
IV
4/19/2011
18820
2550
2260
276
MW02(w)-dup
IV
4/19/2011
22620
3120
2770
356
PGMWOl(w)
II
01/21/10
474
nd(10)
nd(15)
PGMW02(w)
II
01/21/10
361
299
43.8
PGMW03(w)
II
01/21/10
528
nd(10)
nd(15)
PGDWOB(w)
II
01/20/10
nd(5.0)
nd(10)
nd(15)
PGDW04(w)
1
03/03/09
nd(5.0)
PGDW04(w)
II
01/21/10
nd(5.0)
nd(10)
nd(15)
PGDW05(w)
1
03/03/09
16.6
PGDW05(w)
II
01/18/10
5.44
nd(10)
nd(15)
PGDW05(w)
IV
04/19/11
65*
discarded
nd(1.3)
nd(1.6)
PGDW07(w)
1
03/03/09
nd(5.0)
PGDWlO(w)
1
03/03/09
nd(5.0)
PGDWlO(w)
II
01/18/10
nd(5.0)
nd(10)
nd(15)
PGDW14(w)
IV
04/20/11
discarded
nd(1.3)
nd(1.4)
nd(1.7)
PGDW17(w)
1
03/04/09
10.6
PGDW20(w)
1
03/04/09
137
PGDW20 (w)
III
10/06/10
189
24.3
nd(0.22)
nd(0.21)
PGDW20(w)-dup
III
10/06/10
168
17.4
nd(0.22)
nd(0.21)
PGDW20(w)
IV
04/18/11
137
discarded
nd(1.43)
2.93
PGDW21(w)
1
03/04/09
54.3
PGDW22(w)
1
03/04/09
nd(5.0)
PGDW22(w)
II
01/18/10
nd(5.0)
nd(10)
nd(15)
PGDW23(w)
1
03/04/09
146
PGDW23(w)
II
01/18/10
149
nd(10)
nd(15)
PGDW23(w)
IV
04/21/11
176
nd(5.7)
nd(6.6)
nd(6.9)
PGDW25(w)
II
01/19/10
nd(5.0)
nd(10)
nd(15)
PGDW26(w)
1
03/05/09
nd(5.0)
PGDW26(w)
IV
04/18/11
nd(2.2)*
nd(1.4)
nd(1.5)
nd(1.8)
PGDW29(w)
1
03/05/09
nd(5.0)
PGDW30(w)
1
03/05/09
558
PGDW30(w)
II
01/19/10
808
nd(10)
nd(15)
PGDW30(w)
III
10/05/10
762
nd(0.19)
nd(0.23)
nd(0.21)
PGDW30(w)
IV
04/18/11
644
discarded
nd(1.5)
4.6
PGDW32(w)
1
03/05/09
21.4
A10
-------
DRAFT
Sample (matrix)
Phase
Date
Ct
(ue/i)
C2
(ug/l)
c,
(ug/l)
c,
(ug/l)
PGDW32(w)
II
01/20/10
36.3
nd(10.0)
nd(15.0)
PGDW32(w)
IV
04/18/11
nd(2.2)*
nd(1.2)
nd(1.3)
nd(1.5)
PGDW32(w)-dup
IV
04/18/11
discarded
discarded
nd(1.4)
discarded
PGDW35(w)
1
03/05/09
21.6
PGDW38(w)
1
03/05/09
nd(5.0)
PGDW39(w)
II
01/19/10
nd(5.0)
nd(10.0)
nd(15.0)
PGDW40(w)
li
01/22/10
98.9
nd(10.0)
nd(15.0)
PGDW41(w)
II
01/21/10
nd(5.0)
nd(10.0)
nd(15,0)
PGDW41(w)
IV
04/20/11
385
142
nd(1.35)
discarded
PGDW42(w)
II
01/19/10
60
nd(10.0)
nd(15.0)
PGDW43(w)
II
01/21/10
nd(5.0)
nd(10.0)
nd(15.0)
PGDW44(w)
II
01/18/10
nd(5.0)
nd(10.0)
nd(15.0)
—
PGDW44(w)
IV
4/21/2011
nd(2.2)*
nd(1.3)
nd(1.4)
nd(1.7)
PGDW45(w)
II
01/18/10
nd(5,0)
nd(10.0)
nd(15.0)
PGDW45(w)
IV
04/19/11
nd(2.2)*
discarded
nd(1.3)
nd(1.6)
PGDW46(w)
II
01/20/10
nd(5.0)
nd(10.0)
nd(15.0)
PGDW47(w)
II
01/19/10
nd(5.0)
nd(10.0)
nd(15.0)
—
PGDW48(w)
II
01/20/10
nd(5,0)
nd(10.0)
nd(15.0)
—
PGDW49(w)
II
01/20/10
nd(5.0)
nd(10.0)
nd(15.0)
PGDW49(w)
IV
4/20/2011
nd(2.2)*
discarded
nd(1.3)
nd(1.6)
LD02(w)
III
10/20/2010
229
21
nd(0.24)
nd(0.23)
PGPWOl(w)
II
01/20/10
nd(5.0)
nd(10.0)
nd(15.0)
PGPW02(w)
II
01/20/10
nd(5.0)
nd(10.0)
nd(15.0)
Travel Blank(w)
III
10/6/2010
23.3
nd(2.0)
nd(0.24)
nd(0.23)
Equipment
Blank(w)
III
10/6/2010
23.0
nd(2.0)
nd(0.29)
nd(0.27)
Field Blank(w)
III
10/6/2010
76.4
nd(2.0)
nd(0.28)
nd(0.26)
Travel Blank(w)
IV
4/14/2011
18.5
56.4
nd(1.63)
nd(1.6)
Field Blank(w)
IV
4/18/2011
45.0
67.9
nd(1.36)
nd(1.66)
equipment
blank(w) (on-site
GC analysis)
IV
4/18/2011
nd(2.2)
—
equipment
blank(w) (on-site
GC analysis)
IV
4/19/2011
nd(2.2)
—
equipment
blank(w) (on-site
GC analysis)
IV
4/20/2011
nd(2.2)
—
equipment
blank(w) (on-site
GC analysis)
IV
4/20/2011
nd(2.2)
field blank(w)
IV
4/21/2011
nd(0.32)
nd(l.lS)
nd(1.27)
nd(1.54)
* Determined by on-site GC analysis in Phase IV. Fixed laboratory analysis rejected in Phase IV if detection
of methane and ethane less than 100 |ig/L.
All values of methane in Phase III greater than 100 \xg/l accepted.
Ultrapure nitrogen was used for equipment and travel blanks for on-site GC analysis.
nd() - not detected(detection limit) not analyzed
All
-------
DRAFT
Table A3b. Summary of gas and headspace analysis of light hydrocarbons
Sample
Phase
Date
C,
MUM
OH,
C,
MIM
nC,
iCs
nC,
Cs+
(matrix)
(%)
(%)
(%)
(%)
(%)
(%)
(%)
(%)
(%)
Tribal Pavillion
14 6(g) (WR)
....
Johnson
and Rice
(1993)
95.28
2.83
0.3
0.11
0.18
0.05
0.02
Govt 21-5(g)
(WR)
....
Johnson
and Rice
(1993)
93.24
3.75
0.73
0.33
0.22
0.16
0.09
Tribal Pavillion
41-09(g) (FU)
....
Johnson
and Rice
(1993)
88.17
3.35
0.36
0.14
0.09
nd
nd
Tribal Pavillion
14-ll(g) (FU)
....
Johnson
and Rice
(1993)
66.00
1.96
0.06
0.054
0.006
0.006
0.002
Blankenship
4-8(g) (FU)
....
Johnson
and Rice
(1993)
93.38
4.00
0.41
0.05
0.06
0.07
0.01
Tribal Pavillion
1410(g)
II
01/21/10
92.47
4.04
0.001
1.21
0.415
0.372
0.183
0.114
0.486
(WR)(PGPP01)
Tribal Pavillion
43-10(g)
II
01/21/10
94.86
3.48
0.0001
0.356
0.143
0.0618
0.0501
0.0194
0.18
(FU)(PGPP02)
Tribal Pavillion
242(g)
II
01/21/10
90.16
4.64
0.0017
1.46
0.581
0.512
0.335
0.211
1.39
(WR)(PGPP04)
Tribal Pavillion
33-10(g)
II
01/21/10
94.68
3.64
nd
0.373
0.131
0.055
0.0427
0.014
0.107
(FU)(PGPP05)
Tribal Pavillion
142(g)
II
01/21/10
93.23
3.93
0.0012
0.903
0.321
0.25
0.151
0.0905
0.506
(FU)(PGPP06)
MW01(g)
III
9/23/2010
84.22
3.43
0.0007
0.791
0.327
0.191
0.143
0.0632
0.111
MW01(w)
III
10/6/2010
35.11
2.02
0.0008
0.414
0.114
0.0871
0.0499
0.0241
0.0539
MW01(g)
IV
4/18/2011
89.43
3.92
0.0013
0.907
0.298
0.211
0.109
0.0574
0.0972
MW01(g)-dup
IV
4/18/2011
89.49
3.91
0.0013
0.902
0.295
0.206
0.103
0.0533
0.0804
MW01(w)
IV
4/20/2011
38.33
2.46
0.0016
0.504
0.113
0.101
0.0422
0.0229
0.0566
MW02(g)
III
9/24/2010
1.05
0.048
nd
0.022
0.0089
0.0053
0.0020
0.0008
0.0012
MW02(g)-dup
III
9/24/2010
1.04
0.048
nd
0.022
0.0089
0.0053
0.0020
0.0008
0.0009
MW02(w)
III
10/6/2010
28.03
2.16
nd
0.693
0.128
0.101
0.0185
0.0067
0.0174
MW02(g)
IV
4/18/2011
6.74
0.383
nd
0.142
0.0401
0.026
0.0070
0.0025
0.0034
MW02(g)-dup
IV
4/18/2011
7.41
0.422
nd
0.156
0.0439
0.0284
0.0077
0.0027
0.0035
MW02(w)
IV
4/19/2011
26.17
1.80
nd
0.765
0.259
0.147
0.0416
0.0141
0.0237
MW02(w)-dup
IV
4/19/2011
21.32
1.49
nd
0.623
0.204
0.118
0.0324
0.011
0.018
PGMWOl(w)
II
01/21/10
2.47
nd
nd
nd
0.0054
0.005
0.0287
0.0092
0.537
PGMW02(w)
II
01/21/10
3.57
1.13
nd
0.103
0.402
0.0134
0.13
0.0003
0.398
PGDW03(w)
II
01/20/10
0.0122
nd
nd
nd
nd
nd
nd
nd
nd
PGDW04(w)
II
01/21/10
0.0036
nd
nd
nd
nd
nd
nd
nd
nd
PGDWOB(w)
IV
04/19/11
0.0966
nd
nd
nd
nd
nd
nd
nd
nd
PGDW10(w)
II
01/18/10
0.0266
nd
nd
nd
nd
nd
nd
nd
nd
PGDW14(w)
IV
04/20/11
0.0005
nd
nd
nd
nd
nd
nd
nd
nd
A12
-------
DRAFT
Sample
(iiidtrix)
Phase
Date
(%)
C2
(%)
C2H„
(%)
c,
(%)
iC,
(%)
nC,
(%)
iCb
(%)
nC,
(%)
c„+
(%)
PGDW20 (w)
III
10/06/10
0.191
0.007
nd
0.0006
nd
nd
nd
nd
nd
PGDW20(w)-
dup
III
10/06/10
0.134
0.005
nd
nd
nd
nd
nd
nd
nd
PGDW20(w)
IV
04/18/11
0.221
0.007
nd
0.0007
nd
nd
nd
nd
nd
PGDW22(w)
II
01/18/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW23(w)
IV
04/21/11
0.248
nd
nd
nd
nd
0.0015
nd
nd
0.0008
PGDW25(w)
II
01/19/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW26(w)
IV
04/18/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW30(w)
II
01/19/10
5.99
nd
nd
nd
nd
nd
nd
nd
nd
PGDW30(g)
III
09/23/10
0.0123
nd
nd
nd
nd
nd
nd
nd
nd
PGDW30(w)
III
10/05/10
1.19
nd
nd
nd
nd
nd
nd
nd
nd
PGDW30(w)
IV
04/18/11
1.46
nd
nd
nd
nd
nd
nd
nd
nd
PGDW32(w)
II
01/20/10
0.197
nd
nd
nd
nd
nd
nd
nd
0.0085
PGDW32(w)
IV
04/18/11
0.0752
nd
nd
nd
nd
nd
nd
nd
0.0019
PGDW32(w)-
dup
IV
04/18/11
0.0522
nd
nd
nd
nd
nd
nd
nd
0.0013
PGDW39(w)
II
01/19/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW40(w)
II
01/22/10
0.418
nd
nd
nd
nd
nd
nd
nd
nd
PGDW41(w)
II
01/21/10
0.0091
nd
nd
nd
nd
nd
nd
nd
nd
PGDW41(w)
IV
04/20/11
0.0005
nd
nd
nd
nd
nd
nd
nd
nd
PGDW42(w)
II
01/19/10
0.291
nd
nd
nd
nd
nd
nd
nd
nd
PGDW43(w)
II
01/21/10
0.0016
nd
nd
nd
nd
nd
nd
nd
nd
PGDW44(w)
IV
4/21/11
0.0022
nd
nd
nd
nd
nd
nd
nd
nd
PGDW45(w)
II
01/18/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW45(w)
IV
04/19/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
PGDW46(w)
II
01/20/10
0.0016
nd
nd
nd
nd
nd
nd
nd
nd
PGDW47(w)
II
01/19/10
0.0428
nd
nd
nd
nd
nd
nd
nd
nd
PGDW47(w)-
dup
II
01/19/10
0.0365
nd
nd
nd
nd
nd
nd
nd
nd
PGDW49(w)
IV
4/20/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
LD02(w)
III
10/20/10
0.12
0.007
nd
0.001
0.0008
0.0007
nd
0.0005
nd
PGPWOl(w)
II
01/20/10
0.0253
nd
nd
nd
nd
nd
nd
nd
nd
PGPW02(w)
II
01/20/10
0.0389
nd
nd
nd
nd
nd
nd
nd
nd
field blank(w)
II
01/21/10
0.0068
nd
nd
nd
nd
nd
nd
nd
0.0021
field blank(w)
II
01/22/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
travel blank(g)
III
9/23/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
equipment
blank(g)
III
9/23/10
0.0029
nd
nd
nd
nd
nd
nd
nd
nd
travel blank(g)
III
9/24/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
equipment
blank(g)
III
9/24/10
nd
nd
nd
nd
nd
nd
nd
nd
nd
travel blank(g)
IV
4/18/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
equipment
blank(g)
IV
4/18/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
equipment
blank(g)
IV
4/18/11
nd
nd
nd
nd
nd
nd
nd
nd
nd
WR - Wind River Formation FU - Fort Union Formation not analyzed nd () not detected
A13
-------
>
I-*
Table A3c. Summary of isotopic data for dissolved, gas phase, and headspace analysis
Sample
(matrix)
Phase
Date
5UC-
c,
(%»)
fiD-Ci
{%-)
6"C-
Ci
l*»)
6D-C;
(%.)
6liC-
Q
(%»)
6D-C3
(X»)
6"C-IG,
(%.,
5DIC,
(%»)
6°C-nC
(%.)
5DnC,
(%»)
6UC-IC,
(%.)
61JC-nC5
(%.)
%
(pMC)
5iaC
DIC
(M.)
f>'sO
N,0
(%.)
6D HjO
Tribal Pavilllon
14-6(|) (WR}
—
Johnson
and Rice
(1993)
-39.24
—
—
—
—
—
—
—¦
—
Govt 21-5(g)
(WR)
—
Jonnson
and Rice
(1993)
-40.2
—
Tribal Pavillion
4109(g) (FU)
Johnson
and Rice
(1993)
-38,04
—
Tribal Pavillion
14-ll(g) (FU)
—
Johnson
arid Rica
(1993)
-38.4
—
—
Blankenshlp
4-S(g> (FU)
—
Johnson
and Rice
(1993)
-38.08
—
Tribal Pavillion
14-10(g)
(WR)(PGPP01)
11
--
01/21/10
-3875
-203.4
-26.93
-162.5
-24.93
-147.2
-25.83
-152.4
-25.26
-151.3
Tribal Pavillion
4310(g)
(FU)(PGPP02)
II
01/21/10
-39.07
-212.9
-25.99
-157.5
-19.4
-23.87
Tribal Pavillion
24-2(g)
(WR)(PGPP04)
It
01/21/10
-39.26
-204.9
-26.79
-166.2
-25.33
-148.0
-25.66
-155.5
-25.05
-154
—
Tribal Pavillion
33-10(g)
(FU}(PGPP0S)
II
01/21/10
-39.05
-207.3
-26.21
-161.1
-18.46
-101,7
-23.96
-23.64
Tribal Pavillion
142(e)
[FU}(PGPP06)
II
01/21/10
-39.28
-215.3
-26.42
-162,3
-24.01
-145.2
-25.33
-150.1
-24.87
-152
MW01|g)
III
9/23/2010
-39.44
-209.1
-26.63
-165.0
-23.76
-143.7
—
—
<0.2
—
—
MW01(w)
III
10/6/2010
-38.89
-191.3
-26.55
-23.85
—
—
-12.18
-13.77
-113.77
MW01|g)
IV
4/18/2011
-39.25
-211.2
-26.67
-166.8
-23.74
-146.1
—
MWm(g)-dup
tv
4/18/2051
-39 28
-210.1
-76.67
-167.4
-23.91
-146.6
—
.....
MW01(w)
IV
4/20/2011
-38.88
-211.6
-26.70
-24.40
-25.3
-24,4
-250
-24 7
-12.01
-13.26
-109.53
M WO 2(g)
III
9/24/2010
-41.05
-209.4
<0.2
MW02(g)-dup
III
9/24/2010
-41.72
-209.2
-
-
<0.2
-------
Sample
(matrix)
Phase
Date
6i5C-
c,
(%„}
6D-C,
(%•>
6i3C-
C.
(*»)
6D-C2
<%»)
fi'3C-
Q
(%.)
6D-C,
(%o)
6uC-(Ci
6D-IC1
(%¦>
6"c-nC,
<%°)
6D-nCj
(%>>
6l5C-IC5
CM
6"c-nCs
"Ci
(pMC)
6"C
DIC
(%.J
6"0
H,0
(«.)
6D HzO
(%•)
MWOZ(w)
III
10/6/2010
-41.83
-203.8
-26.4
-24.28
Low
DIC
-15,55
-117.41
MWOZ(g)
IV
4/18/2011
-41.05
-208.9
-26.10
-170.5
-24.05
MW02(g)-dup
IV
4/18/2011
-41.01
-210.8
-26.09
-171,4
-24.06
—-
—
—
—
—
—-
—
MW02(w)
IV
4/19/2011
-41.30
-210,7
-25.25
-24.29
-25.3
-24,3
-
—
Low
DIC
-14.24
-113.42
MWQ2(w)-
dup
IV
4/19/2011
-41,37
-208.2
-26.28
-24.28
—
-25.3
-24.5
Low
DIC
-14.27
-113.46
PGDW05(w)
IV
04/19/11
—
-15.12
-13,11
-109.64
PGDW14(w)
IV
04/20/11
—
-11.94
-15.79
-126.04
PGDW20 (w>
III
10/06/10
—
-16.04
-13.22
-107.70
PGDW20(w}-
dup
III
10/06/10
—-
—
-----
-—
-15.91
¦13.18
¦107.38
PGDW20(w)
IV
04/18/11
¦33.1
-175
—
—-
—-
¦16.24
¦13.31
¦108.35
PGDW23(w)
IV
04/21/11
—
-13.29
-12,40
-97,35
PGDW30(w)
II
01/19/10
-28.77
-143.5
—
PGDW30(w)
ill 10/05/10
-28.76
-145.8
—
-12.18
-13,02
-109,78
P6DW3Q(w)
IV
04/18/11
-27.8
-133
—
-11.66
-13.23
-108.11
PGDW32(w)
IV
04/18/11
-34.2
—
....
-11.32
-13.33
-108.10
PG0W32(wK
dup
IV
04/18/11
-34.0
—
_
-
-10.84
-13.28
-108.24
P6DW41(w)
IV
04/20/11
—
-----
-12.31
-15.91
•121.93
PQDWaa(w)
IV
4/21/2011
—
-10.35
-13.29
-100.29
PGDW45(w)
IV
04/19/11
-14.18
-16.59
-128.18
PGDW49(w)
IV
4/20/2011
—
-11.05
-15.57
-122.19
LD02(w)
III
10/20/2010
—
-18.58
-13.22
-109.20
WR-W^rid River Formation FU - Fort Union Formation —nolanalyzec rid ()-noLdetected
-------
DRAFT
-------
DRAFT
Appendix B
Quality Assurance and Quality Control
(QA/QC) for Analysis
-------
DRAFT
Table Bl. Sample collection containers, preservation, and holding times for ground-water samples for Phase III and IV
Sample Type
Analysis Method
(EPA Method)
Sample Bottles/# of bottles*'
Preservation/
Storage
Holding Time(s)
Dissolved gases
RSKSOP-194v4 &-175v5
(No EPA Method)
60 mL serum bottles/2
No Headspace
TSPf, pH>10; refrigerate
4°Ct+
14 days
Metals (filtered)
RSKSOP-213v4 &-257v3
(EPA Methods 200.7 and
6020)
125 mL plastic bottle/1
HN03, pH<2; room
temperature
6 months
(Hg 28 days)
S04, CI, F, Br
RSKSOP-276v3 (EPA
Method 6500)
30 mL plastic/1
Refrigerate <4°C
28 days
no3 + no2, nh4
RSKSOP-214v5
(EPA Method 350.1 and
353.2)
30 mL plastic/1
H2SO4, pH<2; refrigerate
<4°C
28 days
DIC
RSKSOP-102V5 or 330v0
(EPA Method 9060A)
40 mL clear glass VOA vial/2
refrigerate <4°C
14 days
DOC
RSKSOP-102v5 or 330v0
(EPA Method 9060A)
RSKSOP-299vl or259vl
40 mL clear glass VOA vial/2
H3PO4, pH<2; refrigerate
<4°C
No Headspace
28 days
VOCs
(EPA Method 5021A plus
8260C
40 mL amber glass VOA vial/2
TSPf, pH>10; refrigerate
<4°C
14 days
Low Molecular
Weight Acids
RSKSOP-112V6
(No EPA Method)
40 mL glass VOA vial/2
TSPf, pH>10; refrigerate <
4°C
30 days
0, H stable
RSKSOP-296vO
(No EPA Method)
Isotech: gas stripping and
isotopes of
water
20 mL glass VOA vial/1
Refrigerate at < 4°C
Stable
813C DIC
IRMS
(No EPA Method;
60 mL plastic bottle/1
Refrigerate <4°C
No information
S13C and 8D of
methane
Isotech: gas stripping and
IRMS
(No EPA Method;
1 L plastic bottle/1
1L amber glass bottle/2 and for
every 10 samples of ground
Caplet of benzalkonium
chloride; refrigerate <4°C
No information
ORGM-515 rl.l, EPA
Method 8270D
water need 2 more bottles for
7 days until extraction,
SVOCs
one selected sample, or if <10
samples collected, collect 2
more bottles for one select
sample
1L amber glass bottle/2 and for
every 10 samples of ground
Refrigerate <4°C
30 days after extraction
ORGM-508 rl.O, EPA
Method 8015D
water need 2 more bottles for
HCI, pH<2;
refrigerate <4°C
7 days until extraction,
DRO
one selected sample, or if <10
40 days after extraction
samples collected, collect 2
more bottles for one select
sample
40 mL amber glass VOA vial/2
and for every 10 samples of
GRO
ORGM-506 rl.O, EPA
ground water need 2 more
bottles for one selected sample,
or if <10 samples collected,
collect 2 more bottles for one
select sample
No headspace; HCI, pH<2;
14 days
Method 8015D
refrigerate <4°C
Glycols
Region III method**
(No EPA Method)
40 mL amber glass VOA vial/2
Refrigerate <49C
14 days
'Trisodium phosphate
"Above freezing point of water
*Spare bottles made available for laboratory QC samples and for replacement of compromised samples (broken bottle, QC failures, etc.).
"EPA Methods 8000C and 8321 were followed for method development and QA/AC limits were applicable.
B2
-------
DRAFT
Table B2. Field QC samples for ground-water analysis
QC Sample
Purpose
Method
Frequency
Trip Blanks (VOCs and
Dissolved Gases only)
Assess contamination
during transportation,
Fill bottles with reagent
water and preserve, take
to field and returned
without opening.
One in an ice chest with
VOA and dissolved gas
samples.
Equipment Blanks
Assess contamination
from field equipment,
sampling procedures,
decontamination
procedures, sample
container, preservative,
and shipping.
Apply only to samples
collected via equipment,
such as filtered samples:
Reagent water is filtered
and collected into bottles
and preserved same as
filtered samples.
One per day of sampling
with submersible pumps
Field Duplicates
Represent precision of
field sampling, analysis,
and site heterogeneity.
One or more samples
collected immediately
after original sample.
One in every 10 samples,
or if <10 samples
collected for a water type
(ground or surface),
collect a duplicate for one
sample.
Temperature Blanks
Measure temperature of
samples in the cooler.
Water sample that is
transported in cooler to
lab.
One per cooler.
Field Blanks**
Assess contamination
introduced from sample
container with applicable
preservative.
In the field, reagent water
is collected into sample
containers with
preservatives.
One per day of sampling.
* Reporting limit or Quantitation Limit
** Blank samples were not collected for isotope measurements, including O, H, C.
Table B3. QA/QC requirements for analysis of metals and major ions
Measurement
Analysis
Method
Blanks
(Frequency)
Calibration Checks
(Frequency)
Second
Source
(Frequency)
Duplicates
(Frequency)
Matrix Spikes
(Frequency)
Metals
RSKSOP-213V4
(EPA Methods
200.7 and
6020)
10xMDL
(Beginning and
end of each
sample queue, 10-
15 samples)
90-110% of known
value
( Beginningand end
of each sample
queue, 10-15
samples)
PE sample
acceptance
limits or 90-
110% of
known value
(Immediately
after first
calibration
check)
RPCK10 for 80%
of metals; for
results <5xQL,
difference of
-------
DRAFT
Table B4. QA/QC requirements for analysis of dissolved gases, DIC/DOC, VOCs, low molecular weight acids and
stable isotopes of water
Measurement
Analysis
Blanks
Calibration
Checks
Second Source
Duplicates
Matrix Spikes
Method
(Frequency)
(Frequency)
(Frequency)
(Frequency)
(Frequency)
-------
DRAFT
Table B5. QA/QC requirements for analysis of semi-volatiles, GRO, and DRO
QC Type
Semivolatiles
DRO
GRO
Frequency
=0.990
(different range for other
sample analysis (not daily)
compounds)
RSD<20%, r2>0.990
RSD<=20% or r2>=0.990
Initial and Continuing
80-120% of expected value
80-120% of
80-120% of expected
At beginning of
Calibration Checks
expected value
value
sample set, every
tenth sample, and
end of sample set
Second Source Standards
ICV1
ICV1
ICVs
Each time calibration
70-130% of expected value
80-120% of
80-120% of expected
performed
expected value
value
Laboratory Control Samples
Statistical Limits from DoD LCS
Use an SRM:
Use and SRM: Values of
One per analytical
(LCS)
Study (rounded to 0 or 5) or if
Values of all
all analytes in the LCS
batch or every 20
SRM is used based on those
analytes in the
should be within the
samples, whichever is
certified limits
LCS should be
limits determined by the
greater
within the limits
supplier.
determined by
the supplier.
Otherwise 70-130% of
expected value
Otherwise 70-
130% of expected
value
Laboratory Control Samples
Statistical Limits from DoD LCS
Use an SRM:
Use and SRM: Values of
One per analytical
(LCS)
Study (rounded to 0 or 5) or if
Values of all
all analytes in the LCS
batch or every 20
SRM is used based on those
analytes in the
should be within the
samples, whichever is
certified limits
LCS should be
limits determined by the
greater
within the limits
supplier.
determined by
the supplier.
Otherwise 70-130% of
expected value
Otherwise 70-
130% of expected
value
Same as LCS
Same as LCS
70-130% of expected
One per sample set or
Matrix Spikes (MS)
value
every 20 samples,
whichever is more
frequent
% Recovery same as MS
% Recovery same
% Recovery same as MS
One per sample set or
MS/MSD
RPD< 30
as MS
RPD< 25
every 20 samples,
RPD< 25
whichever is more
frequent
Reporting Limits*
0.1 ug/L (generallyffor target
lo^g/F
io'ni/L5
NA
compounds HF special
compounds are higher
'Based on 1000 mL sample to 1 mL extract
2Based on a 5 mL purge
B5
-------
DRAFT
Table B6. QA/QC requirements for LC/MS/MS analysis of glycols
QC Type
Performance Criteria
Frequency
Method Blanks
Solvent Blanks
Initial and Continuing Calibration
Checks
Second Source Standards
Laboratory Control Samples (LCS)
Matrix Spikes (MS)
MS/MSD
-------
DRAFT
Table B7a. ICP-OES blank results for Phase III and Phase IV sampling
DO
mg/L
T3
£1
BQL 0.017
"O
c
X5
£Z
T3
C
73
£Z
73
sz
m
O
O
0.049
21/21
0.019
o
d
LT)
—1
00
E
~Q
C
"a
£Z
X5
c
73
C
73
c
BQL 0.096
73
c
00
m
o
o
0.127
21/21
cn
00
O
o
cn
LT)
cu
LL.
—1
00
E
~0
£Z
~a
£Z
"a
c
73
C
73
C
73
£Z
73
£=
0.019
£900
12/21
0.019
WZ
°3
mg/L
o
o
d
a
CO
T3
C
T3
C
73
C
~a
c
73
c
T3
C
o
o
o
o
o
o
2/21
O
o
o
ZOO'O
—1
"So
E
"a
ci
BQL 0.009
"O
c
73
£Z
73
C
73
£Z
~o
£=
r-.
o
o
o
0.023
21/21
S£'£
ZSP
33
—1
"So
E
~CS
£Z
~a
ci
~a
c
73
C
"a
c
73
C
73
sz
o
o
o
o
o
o
7/21
o
o
o
m
o
o
o
eg
mg/L
X3
C
X3
£Z
73
£=
73
C
~a
c
73
£1
13
£Z
0.001
o
o
o
21/21
9000
0.210
CO
mg/L
73
C
~a
£Z
"a
c
"O
C
"O
c
73
£Z
73
C
0.006
CO
o
o
21/21
m
o
o
00
r-««
ro
o
Ag
mg/L
"a
c:
~a
c
~a
£=
73
£Z
73
c
73
C
73
C
m
o
o
0.051
0/21
73
c
13
c:
<
mg/L
X3
C
~a
£Z
73
£=
73
C
~a
c
73
£1
13
£Z
0.045
0.149
17/21
0.054
t»D
m
r-v
o
Date
10/6/2010
10/7/2010
10/5/2010
4/14/2011
4/18/2011
4/21/2011
4/21/2011
Label
Trip Blank
EQ Blank
Field Blank
Trip Blank
Field Blank
Field Blank
Equip Blank
MDL
—J
a
Detections in
samples
Concentration min
Concentration max
tifi
£
~CL
£
fD
1/1
>
Qj
tU
.9!
uZ
K
u.
U,
B7
-------
CD
00
Table B7c. ICP-MS blank results for Phase III and Phase IV sampling
Label
Date
As
Cd
Cr
a,
Hg
Ni
Pb
Se
Tl
u
pg A
ugA
Pg/L
Pg/L
PgA
PgA
UgA
PgA
PgA
Hg/L
Trip Blank
10/6/2010
BQL 0.096
nd
nd
0.96
0.46
nd
0.981
nd
0.014
EQ Blank
10/7/2010
0.258
nd
0.086
BQL 0.65
nd
0.34
nd
nd
BQL 0.004
Field Blank
10/5/2010
0.263
nd
BQL 0.018
nd
nd
nd
nd
nd
0.014
Trip Blank
4/14/2011
nd
nd
nd
nd
nd
nd
nd
nd
nd
nd
Field Blank
4/18/2011
nd
nd
nd
nd
nd
nd
nd
nd
nd
nd
Field Blank
4/21/2011
nd
nd
nd
nd
nd
nd
nd
nd
nd
nd
Equip Blank
4/21/2011
nd
nd
nd
nd
nd
nd
nd
nd
nd
nd
i
MDL
0.052
0.020
0.008
0,287
0.019
0,048
0.043
0.044
0.004
0.002
QL
0,067
0.124
0,957
0,084
0,160
0,143
0,147
0,013
0.007
Detections in
18/21
3/21
19/21
19/21
5/21
19/21
11/21
21/21
5/21
15/15
samples
Concentration mln
0.255
0.028
0.010
0,380
0117
0,060
0.123
0.337
0.014
0.005
Concentration max
4,96
0,089
0,864
18.9
0.614
9.62
2.37
16.4
0.125
'¦
80.1
BQL-below quantitation level. Units are pg/L. not measured, nd - not detected. MDL-method detection level. QL-quantitation level. Detections In samples: the number of times the
analyte was detected in Phase III and Phase IV sampling, Minimum and maximum sample concentration in Phase Ill/Phase IV sampling activities in pg/L
D
Table B8. Blank results for Capillary Electrophoresis, Lachat Flow Injection Analysis, Dissolved Inorganic Carbon (DIC) and Dissolved Organic Carbon analyses
for Phase III and Phase IV sampling
Label
Date
Ci
SO,
F
NOj+NO,
NH„
DIC
DOC
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Trip Blank
10/6/2010
nd
nd
nd
nd
nd
BQL 0,51
BQL 0,06
EQ Blank
10/7/2010
nd
nd
nd
nd
nd
BQL 0.17
BQL 0.03
Field Blank
10/5/2010
nd
nd
nd
nd
nd
BQL0.08
BQL 0.04
Trip Blank
4/14/2011
nd
nd
nd
nd
nd
BQL 0.09
BQL 0.29
Field Blank
4/18/2011
nd
nd
nd
nd
nd
BQLO,29
BQL 0,24
Field Blank
4/21/2011
nd
nd
nd
nd
nd
BQLO,20
BQL 0,17
Equip Blank
4/21/2011
nd
nd
nd
nd
nd
BQL 0.18 J BQL 0,28
MDL
0.136
0,103
0.056
0.005
0.014
0.103
0,103
QL
1.00
1.00
0.200
0.100
0.100
0.500
0.500
Detections In
samples
21/21
21/21
17/21
11/21
16/21
21/21
21/21
Concentration min
13,2
12.1
0.90
0.08
0.04
1.4
0,51
Concentration max
466
3200
2.02
17.5
4.61
89.1
19.7
BQL- below quantitation level. Units are mg/L. nd-not detected. MDL - method detection level. QL-quantitation level. Detections in samples: the number of times the analvte was detected in
Phase III and Phase IV sampling. Minimum and maximum sample concentration in Phase III /Phase IV sampling activities in mg/L.
-------
DRAFT
Table B9. Blank results for Volatile Organic Compounds (tig/L) in Phase III and Phase IV sampling (Region 8
laboratory, Golden, CO)
Trip Blank
EQ Blank
Field Blank
Trip Blank
Field Blank
Field Blank
RL
10/6/2010
10/7/2010
10/5/2010
4/14/2011
4/18/2011
4/21/2011
1,1,1,2-Tetrachloroethane
nd
nd
nd
nd
nd
nd
0.25
1,1,1-Trichloroethane
nd
nd
nd
nd
nd
nd
0.25
1,1,2,2-Tetrachloroethane
nd
nd
nd
nd
nd
nd
0.25
1,1,2-Trichloroethane
nd
nd
nd
nd
nd
nd
0.25
1,1-Dichloroethane
nd
nd
nd
nd
nd
nd
0.25
1,1-Dichloroethene
nd
nd
nd
nd
nd
nd
0.25
1,1-Dichloropropene
nd
nd
nd
nd
nd
nd
0.25
1,2,3-Trichlorobenzene
nd
nd
nd
nd
nd
nd
0.25
1,2,3-Trichloropropane
nd
nd
nd
nd
nd
nd
0.25
1,2,4-Trichlorobenzene
nd
nd
nd
nd
nd
nd
0.25
1,2,4-Trimethyl benzene
nd
nd
nd
nd
nd
nd
0.25
l,2-Dibromo-3-chloropropane
nd
nd
nd
nd
nd
nd
0.25
1,2-Dibromoethane (EDB)
nd
nd
nd
nd
nd
nd
0.25
1,2-Dichlorobenzene
nd
nd
nd
nd
nd
nd
0.25
1,2-Dichloroethane
nd
nd
nd
nd
nd
nd
0.25
1,2-Dichloropropane
n
nd
n
nd
nd
nd
0.25
1,3,5-Trimethyl benzene
nd
nd
nd
nd
nd
nd
0.25
1,3-Dichlorobenzene
nd
nd
nd
nd
nd
nd
0.25
1,3-Dichloropropane
nd
nd
nd
nd
nd
nd
0.25
1,3-Dimethyl adamantane
nd
nd
nd
nd
nd
nd
0.25
1,4-Dichlorobenzene
nd
nd
nd
nd
nd
nd
0.25
2,2-Dichloropropane
nd
nd
nd
nd
nd
nd
0.25
2-Butanone
nd
0.64
82
0.50
2-Chlorotoluene
nd
nd
nd
nd
nd
nd
0.25
4-Chlorotoluene
nd
nd
nd
nd
nd
nd
0.25
4-Methyl-2-pentanone
nd
nd
d
0.25
2-Hexanone
nd
0.
0.41
0.25
Acetone
nd
1.03
38
1.00
Acrylonitrile
nd
nd
nd
nd
nd
nd
0.25
Adamantane
nd
nd
nd
nd
nd
nd
0.25
Allyl chloride
nd
nd
nd
nd
nd
nd
0.25
Benzene
nd
nd
nd
nd
nd
nd
0.03
Bromobenzene
nd
nd
nd
nd
nd
nd
0.25
Bromochloro methane
nd
nd
nd
nd
nd
nd
0.25
Bromodichloromethane
nd
nd
nd
nd
nd
nd
0.25
Bromoform
nd
nd
nd
nd
nd
nd
0.25
Bromomethane
nd
nd
nd
nd
nd
nd
0.25
Carbon disulfide
nd
nd
nd
nd
nd
nd
0.25
Carbon tetrachloride
nd
nd
nd
nd
nd
nd
0.25
Chlorobenzene
nd
nd
nd
nd
nd
nd
0.25
Chlorodibromomethane
nd
nd
nd
nd
nd
nd
0.25
Chloroethane
nd
>5
nd
nd
nd
nd
0.25
Chloroform
nd
nd
nd
nd
nd
nd
0.25
Chloromethane
nd
nd
nd
34
nd
nd
0.25
cis-l,2-Dichloroethene
nd
nd
nd
nd
nd
nd
0.25
cis-l,3-Dichloropropene
nd
nd
nd
nd
nd
nd
0.25
Dibromomethane
nd
nd
nd
nd
nd
nd
0.25
Dichlorodifluoromethane
nd
nd
nd
nd
nd
nd
0.25
Ethyl Ether
nd
nd
nd
nd
nd
nd
0.25
Ethyl benzene
nd
nd
nd
nd
nd
nd
0.25
Hexachlorobutadiene
nd
nd
nd
nd
nd
nd
0.25
Hexachloroethane
nd
nd
nd
nd
nd
nd
0.25
lodomethane
nd
nd
nd
nd
nd
nd
0.25
Isopropyl benzene
nd
nd
nd
nd
nd
nd
0.25
m,p-Xylene
nd
nd
nd
nd
0.69
0.70
0.50
Methacrylonitrile
nd
nd
nd
nd
0.27
nd
0.25
-------
DRAFT
| Trip Blank
| EQ Blank |
Field Blank |
Trip Blank
| Field Blank
| Field Blank
1 RL
10/6/2010
10/7/2010
10/5/2010
4/14/2011
4/18/2011
4/21/2011
Methyl Acrylate
nd
nd
nd i
nd
n
nd
0.25
Methyl tert-Butyl Ether
nd
nd
nd :
nd
j nd i
nd
0.25
Methylene chloride
nd
nd
nd i
nd
n
nd
0.25
Naphthalene
j nd
nd
nd
nd
d
nd
0.25
n-Butyl Benzene
| nd
nd
_ ^
nd
j nd j
nd
0.25
n-Propyl Benzene
j nd
nd
nd !
nd
j nd !
nd
0.25
o-Xylene
] nd
nd
nd j
nd
j nd j
nd
0.25
p-lsopropyltoluene
nd
1 nd j
nd
nd
nd
nd
0.25
sec-Butyl benzene
nd
nd
nd i
nd
n
nd
0.25
Styrene
I nd
nd
nd
nd
nd
nd
0.25
tert-Butyl benzene
nd
nd
nt
nd
n_
nd
0.25
Tetrachloroethene
1 nd
nd
nd =
nd
nd
nd
0.25
Toluene
0.54
0.16
0.16
nd
nd
nd
0.25
trans-l,2-Dichloroethene
1 nd
nd
nd :
nd
nd
nd
0.25
trans-l,3-Dichloropropene
i nd
nd
nd i
nd
nd
nd
0.25
Trichloroethene
1 nd
nd
nd i
nd
nd
nd
0.25
Trichlorofluoromethane
1 nd
nd
nd i
nd
nd
nd
0.25
Vinyl chloride
• nd
nd
nd i
nd
nd
nd
0.25
Xylenes (total)
1 nd
nd
nd :
nd
nd
nd
0.75
RL - Reporting Limit (ng/L).
nd - not detected. —
- not measured.
BIO
-------
DRAFT
Table BIO. Blank results for Volatile Organic Compounds (ng/L) in Phase IV sampling (ORD laboratory, Ada, OK)
4/14/2011
4/18/2011
4/21/2011
Vinyl chloride
"nd
1 nd
j nd f
0.1/1 !
1.0
1,1-Dichloroethene
] nd
"f nd
] nd f
0.07
0.5
Methylene Chloride
j nd
1 nd
j nd f
.19
o..:>
trans-l,2-Dichloroethene
j nd
1 nd
j nd f
0.05
0"."5
cis-l,2-Dichloroethene
"nd
"j nd
j nd f"
aii 1
0.5
Chloroform
"nd
1 nd
j nd f
o.o/ :
0.5
1,1,1-Trichloroethane
] nd
"f nd
] nd f
0.03
0.5
Carbon Tetrachloride
j nd
] nd
j nd f
0.04
o..:>
1,2-Dichloroethane
"nd
1 nd
j nd f
0.03 !
0.5
Trichloroethene
"nd
"j nd
j nd f"
o.o/ 1
0.5
1,1,2-Trichloroethane
"nd
1 nd
j nd f
0" ¦¦
0.5
Tetrachloroethene
] nd
"f nd
] nd f
0
0.5
Chlorobenzene
j nd
] nd
j nd f
0.04
o..:>
1,3-Dichlorobenzene
"nd
1 nd
j nd f
0.06 !
0.5
1,4-Dichlorobenzene
"nd
"j nd
j nd f"
0.04 1
0.5
1,2-Dichlorobenzene
f nd
"I nd
f nd ["
0.03
0.5
Ethanol
j nd
1 nd
j nd f
0.11
1.0
Isopropanol
f nd
j nd
f nd £
24.7
100
n-Propanol
j nd
1 nd
j nd f
11.4 ;
100
Isobutanol
"nd
"j nd
j nd f"
13T5 1
100
n-Butanol
"nd
1 nd
j nd f
1 ¦'
100
tert-Butyl Alcohol
j nd
j nd
j nd j[
15.5
100
Methyl tert-Butyl Ether
j nd
] nd
j nd f
1./2 1
5.0
di-lsopropyl Ether
"nd
1 nd
j nd f
0.11 !
0.5
Ethyl tert-Butyl Ether
"nd
"j nd
j nd f"
oil 1
0.5
Benzene
f nd
"I nd
f nd ["
0.03
0.5
tert-Amyl Methyl Ether
j nd
1 nd
j nd f
0.06
0.5
2,5-Dimethylfuran
"nd
] nd
j nd f
0.06 1
0.5
Toluene
h 1 0.778
1 nd
"bQL*0~227
0.03 !
0.5
1,2-Dibromoethane
"nd
"j nd
j nd f"
0.03 1
0.5
Ethyl Benzene
f nd
"I nd
f nd ["
0
1.0
m+p Xylene
L 0.229
1 nd
BQL 0.133
0.03
0.5
o-Xylene
"nd
"j nd
j nd f"
0.08 1
0.5
1,3,5-Trimethyl benzene
f nd
"I nd
f nd f
0.03
0.5
1,2,4-Trimethyl benzene
j nd
1 nd
j nd f
.04
1.0
1,2,3-Trimethyl benzene
j nd
] nd
j nd f
0.02
1.0
Naphthalene
"nd
i nd f
0.04 !
1.0
All results in ng/L. MDL-
method detection level. QL-
quantitation level.
nd - not detected.
Bll
-------
DRAFT
Table Bll. Blank results for Semi-Volatile Organic Compounds (|j.g/L) in Phase III and Phase IV sampling
(Region 8 laboratory, Golden, CO)
Trip Blank
EQ Blank
Field Blank
Trip Blank
Field Blank
Field Blank
Rl
10/6/2010
10/7/2010
10/5/2010
4/14/2011
_
4/18/2011
_
4/21/2011
_
1,2,4-Trichlorobenzene
nd
nd
nd
0.100
1,2-Dichlorobenzene
nd
nd
nd
nd
nd
nd
0.100
1,2-Dinitrobenzene
nd
nd
nd
nd
nd
nd
0.100
1,3-Dichlorobenzene
nd
nd
nd
nd
nd
nd
0.100
1,3-Dinitrobenzene
nd
nd
nd
nd
nd
nd
0.100
1,4-Dichlorobenzere
nd
nd
nd
nd
nd
nd
0.100
1,4-Dinitrobenzene
nd
nd
nd
nd
nd
nd
0.100
1-Methylnaphthalene
nd
nd
nd
nd
nd
nd
0.100
2,3,4,6-Tetrachlorophenol
nd
nd
nd
nd
nd
nd
0.250
2,3,5,6-Tetrachlorophenol
nd
nd
nd
nd
nd
nd
0.250
2,4,5-Trichlorophenol
nd
nd
nd
nd
nd
nd
0.100
2,4,6-Trichlorophenol
nd
nd
nd
nd
nd
nd
0.100
2,4-Dichlorophenol
nd
nd
nd
nd
nd
nd
0.100
2,4-Dimethylphenol
nd
nd
nd
nd
nd
nd
0.100
2,4-Dichlorophenol
nd
nd
nd
nd
nd
nd
0.100
2,4-Dimethylphenol
nd
nd
nd
nd
nd
nd
0.100
2,4-Dinitrophenol
nd
nd
nd
nd
nd
nd
1.00
2,4-Dinitrotoluene
nd
nd
nd
nd
nd
nd
1.00
2,6-Dinitrotoluene
nd
nd
nd
nd
nd
nd
0.100
2-Chloronaphthalene
nd
nd
nd
nd
nd
nd
0.100
2-Chlorophenol
nd
nd
nd
nd
nd
nd
0.100
2-Methylnaphthalene
nd
nd
nd
nd
nd
nd
0.100
2-Methylphenol
nd
nd
nd
nd
nd
nd
0.100
2-Nitroaniline
nd
nd
nd
nd
nd
nd
0.100
2-Nitrophenol
nd
nd
nd
nd
_
nd
_
nd
_
0.100
3 & 4-Methylphenol
nd
n
nd
0.200
3,3-Dichlorobenzidine
nd
nd
nd
nd
nd
nd
0.500
3-Nitroaniline
nd
nd
nd
nd
nd
nd
0.100
4,6-Dinitro-2-methylphenol
nc
nd
nd
nd
nd
nd
0.500
4-Bromophenyl phenyl ether
nd
nd
nd
nd
nd
nd
0.100
4-Chloro-3-methylphenol
nc
nd
nd
nd
nd
nd
0.100
4-Chloroaniline
nd
nd
nd
nd
nd
nd
0.100
4-Chlorophenyl phenyl ether
nd
nd
nd
nd
nd
nd
0.100
4-Nitroaniline
nd
nd
nd
nd
nd
nd
0.500
4-Nitrophenol
nd
nd
nd
nd
nd
nd
1.00
Acenaphthene
nd
nd
nd
nd
nd
nd
0.100
Acenaphthylene
nd
nd
nd
nd
nd
nd
0.100
Aniline
nd
nd
nd
nd
nd
nd
0.100
Anthracene
nd
nd
nd
nd
nd
nd
0.100
Azobenzene
nd
nd
nd
nd
nd
nd
0.100
Benzo (a) anthracene
nd
nd
nd
nd
nd
nd
0.100
Benzo (a) pyrene
nd
nd
nd
nd
nd
nd
0.100
Benzo (g,h,i) perylene
nd
nd
nd
nd
nd
nd
0.100
Benzo (k) fluoranthene
nd
nd
nd
nd
nd
nd
0.100
Benzo(b)fluoranthene
nd
nd
nd
nd
nd
nd
0.100
Benzoic acid
0.83
0.78
nd
3.00
nd
nd
0.500
Benzyl alcohol
nd
0.40
0.63
nd
nd
nd
0.500
Bis(2-chloroethoxy)methane
nd
nd
nd
nd
nd
nd
0.100
Bis(2-chloroethyl)ether
nd
nd
nd
nd
nd
nd
0.100
Bis(2-chloroisopropyl)ether
nd
nd
nd
nd
nd
nd
0.100
Bis-(2-Ethylhexyl) Adipate
nd
nd
nd
nd
nd
nd
0.100
Bis(2-ethylhexyl)phthalate
nd
nd
nd
5.44
nd
nd
0.500
Butyl benzyl phthalate
nd
nd
nd
nd
nd
nd
0.100
Carbazole
nd
nd
nd
nd
nd
nd
0.100
Chrysene
nd
nd
nd
nd
nd
nd
0.100
Dibenz (a,h) anthracene
nd
nd
nd
nd
nd
nd
0.100
B12
-------
DRAFT
Trip Blank
EQ Blank
Field Blank
Trip Blank
Field Blank
Field Blank
RL
10/6/2010
10/7/2010
10/5/2010
4/14/2011
4/18/2011
4/21/2011
Dibenzofuran
nd
m
d
n
n
nd
0.100
Diethyl phthalate
nd
nd
nd
nd
nd
nd
0.100
Dimethyl phthalate
nd
nd
nd
nd
nd
nd
0.100
Di-n-butyl phthalate
nd
nd
nd
nd
nd
nd
0.100
Di-n-octyl phthalate
nd
m
d
n
n
nd
0.100
Diphenylamine
n:
m
nd
n:_.
n:_.
nil
0.100
Fluoranthene
nd
nd
nd
nd
nd
nd
*l)7ioo"
Fluorene
n:
m
nd
n:_.
n:_.
nil
0.100
Hexachlorobenzene
nd
nd
nd
nd
nd
nd
0.100
Hexachlorobutadiene
nd
nd
nd
nd
nd
nd
0.100
Hexachlorocyclopentadiene
nd
nd
nd
nd
nd
nd
0.100
Hexachloroethane
nd
nd
nd
nd
nd
nd
0.100
Indeno (1,2,3-cd) pyrene
nd
nd
nd
nd
nd
nd
0.100
Isophorone
nd
nd
nd
nd
nd
nd
0.100
Naphthalene
n:_.
m_.
nd
n:
n:
nd
0.100
Nitrobenzene
n:_.
m_.
nd
n:
n:
nd
0.100
N-Nitrosodi-n-propylamine
nd
nd
nd
nd
nd
nd
0.100
Pentachlorophenol
nd
nd
nd
nd
nd
nd
"astro
Phenanthrene
nd
nd
nd
nd
nd
nd
0.100
Phenol
nd
nd
nd
nd
nd
nd
0.100
Pyrene
nd
nd
nd
nd
nd
nd
0.100
Limonene
nd
nd
nd
nd
nd
nd
0.100
1,3-Dimethyl adamantane
nd
nd
nd
nd
nd
nd
0.100
2-Butoxyethanol
n:
m
nd
n:_.
n:_.
nil
0.100
Adamantane
n:_.
0.32
nd
n:_.
n:_.
nd
0.100
Squalene
036
0.49
0.73
nd
nd
nd
1.00
Terpiniol
nd
nd
nd
nd
nd
nd
0.100
Tri(2-butoxyethyl) Phosphate
nd~
"nd
'nd
nd
nd
______
RL- Reporting Limit (ng/L). nd - not detected. not measured.
Table B12. Blank results for GRO and DRO analyses for Phase III and Phase IV sampling (Region 8 laboratory,
Golden, CO) and blank results for glycol ethers in Phase IV sampling (Region 3 laboratory, Fort Meade, MD)
Trip Blank
EQ Blank
Field Blank
Trip Blank
Field Blank
Field Blank
RL
10/6/2010
10/7/2010
10/5/2010
4/14/2011
4/18/2011
4/21/2011
Gasoline Range Organics
n
n
nd
n
21.3
nd
2
Diesel Range Organics
nd
nd
nd
nd
nd
135
2
2-Butoxyethanol
nd
nd
nd
1
Diethylene Glycol
nd
nd
nd
50
Triethylene Glycol
nd
nd
nd
1
Tetraethylene Glycol
3.6
3.1
3.4
10
RL - Reporting Limit (ng/L). nd - not detected. not measured.
B13
-------
Table B13. Duplicate data for selected major ions, DOC, and DIC in ground water sampl
es collected during Phase III and Phase IV sampling activities
Sample
Date
Na
*
Ca
Mg
Ba
Sr
h
a
S04
N03
DOC
DIC
ppm
ppm
ppm
ppm | ppm
ppm
ppm
ppm
PPm
ppm
ppm
ppm
ppm
LD01
10/6/2010
562
1.05
71,9
8.12
0.0096
1.08
5.82
33.0
1320
0.90
0,354
0.568
17.8
LDOldup
10/6/2010
565
0.97
71.9
8.14
0.0096
1.08
5.81
32.9
1320
0.99
0.337
0.558
17.2
RPD
0.53
7.92
0.00
0.25
0.00
0.00
017
0,30
0.00
9.52
4.92
1,78
3.48
PGDW32
4/18/2011
198
0.09
7.19
0.028
0.010
0.090
6.74
18.8
361
1.95
ND
0.41
7.70
PGDW32 dup
4/18/2011
198
0.27
7.28
0.026
0.009
0.090
6.80
19.1
349
2.02
ND
0.37
7,73
RPD
0.00
100
1.24
7.41
10.53
0.00
0.89
1.58
3,38
3.53
NC
10.26
0.39
EPAMW02
4/19/2011
448
43.6
60.5
0.032
0.093
1.78
2.94
457
62.6
1.54
ND
19.7
1.40
EPAMW02 dup
4/19/2011
449
44.0
60,5
0.019
0.093
1.79
2.93
456
62.5
1.49
ND
19.7
1.39
RPD
0,22
0.91
0.00
50.98
0.00
0.56
0 34
0,22
0.16
3.30
NC
0.00
072
RPD is the calculated relative percent difference: RPD = [[(samplel-sample2)/((samplel+5ample2)/2)]i'100|. ND- not detected. not measured, NC-not calculated.
-------
Table B14, Duplicate data for methane and selected dissolved organic compounds in ground water samples collected during Phase III and Phase IV sampling activities
Sample
Date
Methane
Benzene
Toluene
m,p-Xy|enes
Isopropyl
alcohol
Tert-butyl
alcohol
Phenol
methylene
Glycol
Triethylene
Glycol
Acetone
ppm
ppb ppb
ppb
ppb
ppb
ppb
ppb
ppb
ppb
LOOl
10/6/2010
0.189
<0.25
<0.25
<0.25
—
<0.1
—
LDCildup
10/6/2010
0.168
<0.25
<0.25
<0.25
—
<0.1
.....
RPD
11,76
NC
NC
NC
NC
NC NC
NC
NC
NC
PGDWB2
4/18/2011
0,07
<0.25
<0,25
<0.25
<11.4
<1,7
<0,5
<50
<50
<10
<1.00
PGDW32 dup
4/18/2011
0.06
<0,25
<0.25
<0.25
<11.4
<1.7
<0.5
<10
<1.00
RPD
15,38
NC
NC
NC
NC
NC
NC
NC NC
NC
EPAMW02
4/19/2011
18.82
139
336
280
581
4470
14,5
1570
314
641
EPAMW02 dup
4/19/2011
22.62
164
424
354
553 4580
29.2
1610
293
616
RPD
18.34
16.50
23.16
23.34
4.94 2,43
67.28
2.52
6.92
3,98
RPD is the calculated relative percent difference: RPD - |[(sarnple]-sampie2)/((samplel+sample2)/2]]*100|. ND-not detected, not measured. NC-not calculated.
-------
DRAFT
Table B15. QA/QC requirements for analysis of 613C of DIC
QC Type
Performance Criteria
Frequency
Mass Spec Calibration Check
Difference of calibrated/true < 0.5%o
One at beginning of day, and one after sample is analyzed.
Mass Spec Zero Enrichment Check
0+/-0.1%o
Once a day
Lab Duplicates
< 1 %0
1 per every 5 samples*
Working standards were calibrated against IAEA (International Atomic Energy Agency) standard LSVEC and NBS-19; referenced to 5,3C of the PeeDee belemnite (NIST material).
*lf < 5 samples were submitted, a duplicate was run regardless of total number.
Corrective Actions: If re-analysis was not possible (such as lack of sample volume), the data was qualified with a determination about the impact on the sample data.
Table B16. QA/QC requirements for analysis for 6l3C and 6D of light hydrocarbons for aqueous and gas samples
QC Type
Performance Criteria
Frequency
Mass Spec Calibration Check
Difference of calibrated/true
<0.5%cfor 6,JC and
< 3%o for 5D
+/-1 pMCfor'*C
One at beginning of day and after samples are
analyzed for 6"C*; one at beginning of day and every
tenth sample for 6D**
Mass Spec Zero Enrichment Check
0 +/- 0.1 %0 for 6"C and 0 +/-1 %° for 6D
Once a day for 613C and every tenth sample for 5D
Lab Duplicates
< l%o for 6"Cand
< 3%o for 5D
+/-lpMCforuC
1 per every 10 samples for 513C and 6D ***
Preparation System
Check/Reference Standards
-------
DRAFT
Table B18. Summary of quality control samples, purpose, method, and frequency to support gas analysis
QC Sample
Purpose
Method
Frequency
Acceptance Criteria
Equipment Blanks
Ensure that construction
materials in gas sample bags and
the sample train are not a
source of vapors or gases of
concern
Fiii sample bags with
ultrapure N2 gas via the
sample train.
One sample per day
< Detection limit
Travel Blanks
Ensure that cross-contamination
does not occur during sampling
or transport to the laboratory
Fiii sample bags with
ultrapure N2 gas and place
in shipping container with
other samples.
One sample per shipment
< Detection limit
Duplicates
Check precision of sampling
method and analysis
Use a tee to collect two
samples simultaneously.
One sample every 10
samples
RPD< 20%
Table B19. Summary of analytes, instruments, calibration, and check standards for portable gas analyzers
Analyte
Instrument
(Detector)
Method
Range
Calibration
Check Standard
Accuracy
o2
GEM-2000 Plus
CES-LANDTEC
(EC Cell)
RSKSOP-
314vl
0-21%
4%, 10%, or
20.9%
4% 10%, 20.9%
±1.0% (0-5%)
±1.0% (5-21%)
ch4
GEM-2000 Plus
CES-LANDTEC
(IRGA)
RSKSOP-
314vl
0 -100%
2.5% or 50%
2.5%, 50%
±0.3% (0-5%)
±1% (5-15%)
±3% (15-100%)
co2
GEM-2000 Plus
CES-LANDTEC
(IRGA)
RSKSOP-
314vl
0 -100%
5%, 20%, or
35%
5%, 20%, 35%
±0.3% (0-5%)
±1.0% (5-15%)
±3.0% (15-50%)
VOCs
Thermo Scientific
TVA-1000B (FID)
RSKSOP-
320vl
1.0-
10,000
ppmv
0.0, 10, 100,
1000, 9000
ppmv CH4
10, 100, 1000,
9000 ppmv CH4
±25% or ±2.5 ppmv,
whichever is greater, from
1.0 to 10,000 ppmv.
VOCs
Thermo Scientific
TVA-1000B (PID)
RSKSOP-
320vl
0.5-500
ppmv
0.0, 250, 475
ppmv
250,
475 ppmv
isobutylene
±25% or ±2.5 ppmv,
whichever is greater, from
0.5 to 500 ppmv.
Table B20. QA/QC Requirements for portable gas analyzers
Measurement
Analysis Method
Blanks**
(Frequency)
Calibration Check Standards
(Frequency)
Second Source Standards
(Frequency)
02, CO2, CH4,
RSKSOP-314vl
beginning & end of each
sample event)
+/-1% of reading
(beginning & end of each sample event)
+/-!% of reading
(after each calibration,
optional for this project)
Hydrocarbons
RSKSOP-320vl
beginning & end of each
sample event)
90-110% of known value for FID and 80-
120% for PID
(after calibration, beginning & end of each
sample event)
NA
Corrective actions are detailed in the SOPs.
'Duplicate sample not appropriate for measurements from a sample train.
**Meter reading
B17
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Appendix C
Photographic Log of Deep Monitoring Well
Construction
ci
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Figure CI. Photograph of drilling rig on platform with shakers for mud recirculation at MW02.
DRAFT
Figure C2. Photograph
of blowout prevention
(BOP) for annular space
at base of drilling rig
platform at MW02.
Figure C3, Photograph
of blowout preventer
for drillstern.
C2
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C3
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Figure CI. Photograph of
mud additives EZ Mud
Gold (Halliburton) and
Dense Soda Ash.
Figure C5. Photograph of water truck used to transport water to mix mud.
k H,OH V'Efrp BENTONIT6
Bp.oici Industrial Drilling Product*
P.O. 3ox 1675, Houston, Texas 77251
www.baroidldp.com
Figure C6. Photograph of Quik-Gel
bentonite (Halliburton) used to create
mud for drilling.
Figure C8. Photograph of
mud additive Penetrol
(Halliburton).
C4
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Figure CIO, Photograph of monitoring of mud and cuttings using a Thermo Scientific
TVA-1000B FID/PID at MW02.
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Figure Cll. Photograph of pump used to transport mud and cuttings to shakers at MW02.
Figure C12.
Photograph of flow of
mud and cuttings to
shakers at MW02.
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Figure C13. Photograph of shakers separating mud from cuttings at MW02
C7
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C8
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Figure CIS. Photograph of pumping of mud back to borehole at MW02
C9
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cio
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Figure C17. Photograph of collection of cuttings for lithologic characterization at MW02
Figure C18. Photograph of removal of mud from
cuttings at MW02.
Figure C19. Photograph of white coarse-grained sand
targeted by local well drillers and media in which
screens are set in for both deep monitoring wells.
en
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Figure C2Q. Photograph
of setting of stainless-
steel pre-packed
screen and sand basket
into borehole at
MW02.
C12
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Figure C21. Photograph
of securing sand basket
and casing above
screen.
Figure C22. Photograph
of placement of sand in
sandbasket.
C13
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C14
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Appendix D
Photographic Log of Ground Water Sampling
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Figure D2. Photograph of flow
of water to purge water
disposal tank at MW02.
D2
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Figure D3. Photograph (close-up) of flow of water into purge water disposal tank at MW02
Figure D4,
Photograph of
water (foaming)
flowing into YSI
flow cell at MW02.
D3
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Figure D5. Photograph of sampling at MW02. The sample train was split prior to entry into
purge water disposal container.
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Figure D7. Photograph
of sample collection at
PGDW14,
Figure D8. Photograph of cooler packed with samples for shipment.
D5
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Appendix E
Examples of Cement Bond/Variable
Density Log Interpretation
El
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Qood Bond
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0 3' Amplitude (mV) 1QQ
0 Amiprfied 3 A/up (mV) 10
Figure E2. Example of "sporadic bonding" at Pavillion Fee 41-10 from 1000 to 1640 ft bgs. Hydraulic fracturing
occurred at 1618 feet below ground surface. Arrow denotes interval of hydraulic fracturing.
E3
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Figure E3a. Example of "sporadic bonding" at Pavillion Fee 11-11B. Hydraulic fracturing occurred at 1516 feet
below ground surface. Arrow denotes interval of hydraulic fracturing. Depths on CBL/VDL difficult to read
and inserted on left margin.
E4
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Figure E3b. Example of "sporadic bonding" Pavillion Fee 11-11B between 2350-3200 feet below ground
suface. Hydraulic fracturing occurred at 3165 feet below ground surface. Arrow denotes interval of hydraulic
fracturing. Depths on CBL/VDL difficult to read and inserted on left margin.
•ifJiiwiJ AiViiiidii-U i'uV/j wpoo-
An:(il.i|id. thV.'": 1(Mi'
2450'
3200'
Vitiiiii)!!-) K.1 Vs-isy •
E5
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Figure E4. Example of "Sporadic
bgs. Arrow denotes interval of
Bonding" at Tribal Pavillion 24
hydraulic fracturing.
-02. Hydraulic fracturing occurred at 1538 feet
E6
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0 A/rprtieo AmpKudeimVl 1o!
Figure E5. Example of "Good Bonding" (from surface casing at 645 ft bgs to 820 ft bgs) followed by "Sporadic
Bonding" (from 820 ft bgs 1310 ft bgs) to "Good Bonding" at 1310 to target depth at Pavillion Fee 41-10B.
E7
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&EPA
United States
Environmental Protection
Agency
PRESORTED STANDARD
POSTAGE & FEES PAID
EPA
PERMIT NO. G-35
Office of Research arid Development (8101R)
Washington, DC 20460
Official Business
Penalty for Private Use
$300
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