Atmospheric and soil-gas monitoring for surface leakage at the Michigan Basin CO2 pilot
test site in Ostego Co., Michigan, using a perfluorocarbon Tracer
Art Wells, … Tom Wilson… ?
Tentative outline
Abstract
Introduction
Background Characterization of Near-Surface Geology at the Site
Surface Geochemical Evidence of Leakage in the Area
Well Integrity and the History of Well Leakage at the Site
Monitoring Grid Design
Analysis and Sampling Protocol
Tracer Injection
Results and Conclusions from Tracer Monitoring
Conclusions:
References
Preliminary rough outline f
revision/input/comment fro
co-authors
Abstract (to be revised)
Evaluation of the near-surface geology at the MRCSP’s Ostego Co., Michigan CO2 Pilot site
reveals the presence of about 600 feet of glacial till covering lower Mississippian and upper
Devonian shale intervals that includes the Antrim Shale. The injection zone is in the Bass Island
Group approximately 4500 feet beneath the surface. The Antrim is an organic rich fractured
Devonian Shale reservoir. Any CO2 entering the Antrim would likely migrate upward through
extensive fracture systems in this reservoir. Leakage is known to occur in the area. Geochemical
sampling reveals anomalies over Niagaran reef trends to the southwest. Hydrocarbon
microseepage tends to be absent in produced areas.
A study conducted in the vicinity of the pilot site by Toelle et al. (2007) revealed that a prevalent
source of leakage in the area is associated with corroded well casing. The Niagaran reef in the
area of the injection well was inadvertently water flooded by migration of water disposal from
the shallow Dundee Formation along corroded well casing. The water flooding was extensive
and terminated production in from the reef in some wells.
Recommendations for additional sampling were based primarily on the results of the study
presented by Toelle et al. (2007), but also included consideration of the regional fracture systems
and local structural dip.
Introduction
Art, can you and others describe development of NETL tracer and soil gas testing methodologies
and results obtained from previous pilot efforts? Note other competing methodologies and the
relative merits of your methods. Describe relationship with the MRCSP. Note injection zone and
complimentary monitoring undertaken by the MRCSP: any water wells sampling from the top of
the primary seal (?); soil CO2 & CH4 flux, ….(?).
1
Background Characterization of Near-Surface Geology at the Site
A background geological characterization effort was conducted at the Michigan Basin pilot site
to provide some perspectives and insights into the potential for leakage of injected CO2.
Initially, we examined the near-surface geology in an approximately 7 square mile area
surrounding the pilot site in Ostego Co., Michigan. This initial evaluation provided a look at the
subsurface geology down to the level of the Antrim “Dark” Shale. The Antrim is a Devonian
shale equivalent to the Devonian shale of the Appalachian Basin. The Antrim is a pervasive gas
producer throughout the Michigan basin. A relatively large number of wells with information on
this shallow zone (approximately 70) were available in the area. Very few deep wells were
available. Most of the wells were completed in the Antrim Shale.
The surface is covered by a layer of glacial till between 500 and 600 feet thick (Figure 1).
The till thins to the north of the injection well and is locally thicker beneath the injection well.
Figure 1: Thickness of glacial cover in the region. The injection well is located roughly in the
center of grid of CATS near the southwest corner of the middle section (Section 30) in this map.
The depth to the till/bedrock interface at the injection well is about 640 feet. The stratigraphic
column for the basin (Figure 2) shows the relative positions of strata in the sequence overlying
2
the injection zone in the Bass Island Dolomite. The Bass Island injection zone lies at a depth of
between 3000 and 3400 feet below sea level in the area of the injection well. The surface
elevation at the injection well is 1188 feet above sea level putting the injection zone at a depth of
about 4200 to 4600 feet subsurface. The glacial till in this area covers the lower Mississippian
Coldwater Shale (Figure 2). The Antrim Shale is separated from the base of the glacial till by an
interval of shale including the Sunbury and Bedford shale intervals (Figure 2).
Is there a report from Battelle describing the results of the project, site geology and primary seal
for the site? The MRCSP never provided any information to us that I’m aware of. We would
want to be sure our analysis was complimentary and consistent.
The primary sealing strata would appear to be the Bell Shale. Neeraj (2006) refers to the Detroit
Group which appears to include the Amhertsburg, Ls, Lucas Ls.,. The Traverse Group (including
the Bell Shale?) and Dundee Limestones overlie the Detroit River Group. Dundee Ls and Bell
Shale. The USGS (http://tin.er.usgs.gov/geology/state/sgmc-unit.php?unit=MIDdr%3B0)
indicates that the Detroit River Group includes the Flat Rock dolomite (40 to 150 feet thick),
Anderdon limestone (40 to 50 feet thick), Amherstburg dolomite (20 feet thick), and Lucas
dolomite (200 feet thick) members. Would appear to be the equivalent of the Onondaga Ls in
NY. Oriskany Ss lies below the Bois Blanc Fm. The Lucas is an oil producer with 15%-30%
porosity and low perm (5-25md).
3
From Gupta, N., 2006, MRCSP
Ostego County Site: Geologic
field tests in the Michigan Basin:
DOE/NETL Regional Partnership
Annual Meeting, Pittsburgh, PA
Figure 2 (possible replacement)
….
4
Figure 2: General stratigraphic column for the Michigan basin area. Depth to base of till in the
vicinity of the injection well is approximately 600 feet. The Bass Island lies about 3000 feet
below the Antrim Shale
Bedrock elevations at the base of the glacial till (Figure 3) are relative to the sea level datum and
thus do not include the influence of variations in topographic relief which are superimposed on
the total depth to the base of the till shown in Figure 1. On this sea-level referenced view, the
pilot well is located over a bedrock high. Groundwater drainage at least at deeper levels within
the till will be away from the injection well to the northwest. The regional scale view provided
by maps indicates that at the level of the bedrock/till interface, the area surrounding the injection
well is in a bedrock low.
5
Figure 3: Elevation variations on the base of the till relative to the sea level datum.
The structure on the Antrim Shale (Figure 4) dips gently to the south-southwest in the vicinity of
the injection well and in general throughout the surrounding area. There do not appear to be local
structures related to faults in the area. Small perturbations in the contours are probably due to
variations in the density of well coverage in the vicinity of the injection well. Some anomalous
features in the surrounding area have been checked. A few wells in the data base are deviated
which leads to some differences in measured versus true vertical depths.
6
Figure 4: Structure on the top of the Antrim Shale.
The Antrim Shale is an organic rich shale that produces gas from open fracture systems. As the
depth to the top of the Antrim map reveals (Figure 4), this gas reservoir comes to within about
1000 feet of the surface and may contribute to the soil gas anomalies that are pervasive in the
basin (Wood et al., 2004a and b).
Since the Antrim is a fractured reservoir any CO2 that might make its way up through the strata
overlying the Bass Island injection interval will migrate through the fracture systems of the
Antrim in the updip, north-northeast direction in this area (Figure 4). The updip direction also
brings the unit closer to the surface (Figure 5).
7
The interval separating the base of the till and Antrim is thinnest (about 400 feet thick) to the
northwest (Figure 6). The Antrim lies nearest the surface, about 700 feet, in this area (Figure 5).
Figure 5: Depth (measured depth) to the top of the Antrim shale.
8
Figure 6: An isopach map of the thickness of the interval between the base of the till and the top
of the Antrim Shale.
Based on the near surface geology and extensive drilling history at the site our primary concern
was that CO2 might possibly migrate out of existing wells in the area. We would expect any CO2
making its way up into the Antrim to migrate updip. However, the dip is slight in the area (just
over 100 feet per mile (a little over a degree to the south-southwest).
Ryder (2003) indicates that fractures observed in outcrop about 10 to 15 miles north of the pilot
site have dominant orientations of N52E and N46W with subordinate sets oriented north-south
and east-west. These trends are inferred from approximately 5000 measurements across the
northern part of the basin. Ryder (2003) reports that fracture trend remains fairly consistent
throughout the area. Ryder (2003) provides a comprehensive summary of the general details of
fracture observations and literature review. Observations of more than 600 fractures taken from
oriented core reveal consistency with the outcrop observations (Richards, Waters, and others,
1994). The north-northeast rise in the Antrim structure combined with fracture orientation data
9
suggested that areas to the northeast along the N52E fracture trend might be good locations for
additional monitoring. If local fracture systems in the Antrim shale control flow of escaped CO2
then additional CATS could be placed in the up dip direction along an azimuth associated with
the major systematic fractures noted by Ryder. A secondary location would lie to the northwest
of the injection well along the azimuth corresponding to the secondary NW trending fracture set.
Surface Geochemical Evidence of Leakage in the Area
Extensive geochemical sampling conducted by Wood et al. (2004 a and b) reveal the presence of
hydrocarbon seeps associated with Niagaran production. Reefs exhibited propane geochemical
anomalies that formed haloes around one reef, with highs surrounding the reef and lows directly
above the reef. Pentane anomalies were also observed in some areas. Variable results were
obtained in their studies and the reader is referred to the papers by Wood et al. (1004a and b) for
the details of their study. Their studies do suggest that light hydrocarbon microseeps are present
in the area associated with deeper hydrocarbon reservoirs. These anomalies tend to be absent
over produced fields. Their observations suggest the presence of migration pathways facilitating
short term migration of light hydrocarbons from the Niagaran reef trend which lies at greater
depth than the Bass Island injection zone.
Well Integrity and the History of Well Leakage at the Site
Site evaluation also incorporated results and observations from an earlier enhanced gas recovery
(EGR) operation conducted by Core Energy in the deeper Niagaran reef trend. Schlumberger in a
joint effort with Core Energy collected 3D seismic over the reef complex. 3D seismic acquisition
was repeated to provide time lapse seismic response resulting from CO2 injection into the reef.
Toelle et al. (2007) provides perspectives on well history in the area that are pertinent to possible
leakage of CO2 injected in the shallower Bass Island Formation as part of the MRCSP carbon
sequestration pilot test. Several wells are noted in the Toelle et al. (2007) study (Figure 8).
10
Figure 8: Structure on the Antrim shale showing the location of key wells in the Toelle et al.
(2007) study.
11
Toelle et al. (2007) note that corroded casing is common to all wells in the area. Disposal of
produced water in the shallower Dundee Formation helped facilitate degradation of the casing
and eventual leakage. Eventual well corrosion caused disposal water injected into the Dundee to
drain into deeper intervals. This led to indirect water flooding of the deeper Niagaran reservoir.
The 2-30 well (Figure 9, east of the C2-30 well) began to produce water in 1985. A 100% water
cut arrived at the C2-30 well, about 20 feet down dip, in 1997. This resulted in the termination of
primary production in the field. Appearance of CO2 in the Charlton 1-30 well injected from the
end of the C2-30 lateral (Figure 9) indicates a nearly east-west connection between these two
points. The Dundee lies above the Bois Blanc injection zone and is considered to be part of the
primary sealing intervals in the Detroit River Group (Gupta, 2007). Corroded well casing might
facilitate vertical release of injected CO2 through the primary seal.
Figure 9: The end of the C2-30 injection lateral extends approximately 800 feet north-northwest
of the C2-30 surface location. CO2 injected into the C2-30 migrated into the Charlton 1-30 well.
12
Core Energy injected CO2 into the Niagaran through the deviated C2-30 well and temporarily
produced oil from the 1-30 well to the north. The plan was to produce from the 1-30 well until it
began cycling unacceptable amounts of CO2. At that point, the 1-30 well would be converted to
an injection well with the idea of pushing the remaining oil to the south. The history of the 1-30
included 5 months of water production with no oil. The well began to produce CO2 in the
production stream only a month after oil production occurred.
Figure 10: Suggestions for additional monitor locations.
Based on the history of well corrosion, water dumping and inadvertent flooding of the deeper
Niagaran Reef in the area, additional monitors were placed near wells in the surrounding area
(Figure 10). Given the history of significant casing corrosion, CATS placements were
recommended near wells noted in the study by Toelle et al. (2007). Although at some distance,
the presence of well corrosion along with interconnection over a distance of approximately 1 km
would make this a good location to monitor.
13
Monitoring Grid Design
The tracer and soil-gas monitoring grid consisted of 24 locations in the vicinity of the CO2
injection well. A rectangular grid was employed with spacing between monitors of 100 meters.
The grid is pictured below (Figure *). In addition, monitors were placed adjacent to near-by
wells to evaluate potential leakage associated with wellbores. Four of the monitors lying off the
main grid were also placed to evaluate areas of interest based upon the geological assessment of
leakage potential. The tracer-in-soil-gas monitors were ¾ inch steel pipes driven 1 meter into the
soil, and into which vial containing sorbent material (62 mg of ambersorb) were placed to collect
any tracer contained in the soil-gas exposed by removing the penetrometer head. The tops of the
pipes were sealed to prevent entry of atmosphere and ground water. The sorbent vials were
exchanged as sets: one set pre-tracer injection, one set during tracer injection, and 4 sets posttracer injection. The quantity of air or soil-gas sampled by passive diffusion into the sorbent
vials has been determined to be equivalent to 200 ml/day.
A subset of 14 of the soil-gas monitors also contained attached, passive monitors for tracer-inthe-atmosphere. These included monitors associated with wells to evaluate atmospheric tracer
plumes that might be generated by leakage from wellbores or from pipes and fittings through
which tracer containing gases or liquids were flowing. In addition, sets of active 3 liter air
samples were taken during the collection and placement off all pre- and post-injection sorbent
sets to detect atmospheric tracer plumes, and to ultimately locate their source if found. The
active air samples also provided information on the overall concentration of atmospheric tracer
near the site, which could be used to detect area wide tracer microseepage or release of tracer
from nearby gas treatment facilities, lines, etc.
Analysis and Sampling Protocol
Analysis of the sorbent packets was conducted in NETL’s PFC tracer laboratory. The
approximately 2 ½ inch long glass vials containing 62 mgs of ambersorb were thermally
desorbed to release PFC tracer collected during field exposure. Analysis employed gas
chromatography with a chemical ionization/ mass spectrometer detection system.
Instrumentation and methodologies were developed specifically to remove typical contaminates
found in soil-gas at sequestration test sites near active production areas. The detection limit for
tracer is approximately 3 fL tracer / L of soil-gas or air. This detection limit, approaching the
part-per-quadrillion level, requires a protocol to prevent cross-contamination of sorbent packets.
This protocol includes, among other measures, the physical separation of the tracer injection and
monitor placement teams (who were staying in different cities), performing all non-injection
syringe pump operations offsite, and sorbent packet exchange procedures.
Tracer Injection
o
On 20 February, 2008, under sunny skies and with temperatures right around 10 F, Hank and
Rod set up the syringe pump and transfer lines at the Lower Michigan Basin injection well. 255
ml of PMCH had already been filled into the syringe pump before arriving at the well. A
container of about 400 ml of cyclohexane was attached to the pump and the auto refill feature
was activated. The pump was set into a tedlar bag containing activated charcoal and the bag
carefully brought up over the pump and sealed at the top. One hole was provided through the
bag for the 110 VAC power cord and the 1/8” stainless steel transfer line between the pump and
the valve on the line carrying CO2 into the well. CO2 injection flow rate was 410 tons/day.
14
At 1410, injection of PMCH was begun at the rate of 350 microliters/minute, i.e. 255 ml over the
next 12 hours. Then the pump would automatically refill with cyclohexane and cyclohexane
would be pumped through the transfer line and into the well. This cyclohexane flush would
serve to clear the lines of residual tracer. After all the settings and valves were double checked
we wrapped the apparatus with a blue tarpaulin and rope and left the wellhead area.
On 21 February at 0830 Hank and Rod returned to the wellhead and found the CO2 injection
flow rate still about 410 tons/day. All 255 ml of PMCH had been injected, but only about 150
ml of the cyclohexane wash had been injected because of the transfer line icing up inside. The
tracer (255 ml of perfluoromethylcyclohexane- PMCH) was injected at a constant rate from a
syringe pump over 12 hours. Since the detection limit of tracer in soil-gas or in the atmosphere
-15
is nearly one part-per-quadrillion (10 v/v), it is inevitable that some atmospheric tracer plume
will be released during the tracer injection process. This release was minimized by sealing the
syringe pump and it’s fittings in a plastic bag, which also contains activated charcoal. This
atmospheric tracer plume was carefully monitored, and its drift noted for comparison to later
results.
Results and Conclusions from Tracer Monitoring
Results for tracer in soil-gas (Table 1) and for tracer in active 3 Liter air samples (Table 3) are
given for 1 pre-tracer injection background survey and for 4 post-tracer injection surveys.
Results for tracer in passive air samples are given in Table 2, with sorbent set 2 designed to
evaluate the atmospheric tracer plume released during tracer injection. It was found that
atmospheric levels of tracer exceeded 1,000 fl/L of air at only one site (Table 2). This was a
modest plume, and it was concluded that by comparison to past injections, efforts to limit tracer
release had been successful. No evidence of barometric pumping of tracer into the soil was
found during post-tracer injection surveys.
The following results are referenced to the 3 tables below, with pre-injection survey results in the
left hand column and an average of the 4 post-injection surveys in the right hand column.
Comparisons in Table 1 of the pre-injection soil-gas survey results (bottom of the far left
column) to averages of the 4 post-injection surveys (bottom of the far right column) are
statistically identical, and give no indication of the leakage of tracer into soil-gas. Results for
passive atmospheric monitoring (Table 2) and for active 3 Liter atmospheric monitoring (Table
3) also remained at background levels during the 4 post-injection surveys. Detection levels for
tracer in the atmosphere or in soil-gas correspond to approximately a <0.01% leakage rate per
year for an injection of this size.
Migration of tracer tagged CO2 from the target reservoir into the Antrim shale might result in
possible release channels to the surface, including wellbore, microseepage, and releases
associated with gas production infrastructure. The latter scenario would raise the overall
background levels of atmospheric tracer beyond pre-injection levels. No evidence of leakage or
migration was discernable in this study.
Conclusions:
Geologic characterization of the site reveals the presence of a thick layer of glacial till in the area
surrounding the CO2 injection well. The thickness of the glacial till near the injection well is
15
approximately 600 feet. The injection well is located in a bedrock low where till thickness
increases to about 640 feet. The till was deposited on the lower Mississippian Coldwater Shale.
The upper Devonian shales including the Antrim Shale lie within a few hundred feet of the
surface. The Antrim Shale is a tight naturally fractured gas reservoir that lies a few hundred feet
below the till. The Antrim is a prolific gas producer in the Michigan Basin. The Antrim rises
gently with a dip of about one degree to the northeast across the site. While this dip is quite
small, if CO2 were to escape from the injection zone and reach the Antrim it might move through
regional fractures systems in the up-dip direction. Geologic characterization of the area did not
suggest the presence of any faults. Some early recommendations for additional sample placement
were made on the basis of dominant trends in the Antrim natural fracture systems reported by
Ryder (2003) and on the local structural dip.
Geologic characterization of the site provides the group with several perspectives regarding the
potential for CO2 leakage and likely leakage mechanisms. Previous geochemical studies
conducted in the area by Wood et al. (2004 a and b) reveal that light hydrocarbon seeps are
prevalent in the area. These seeps have been associated with production from the Niagaran reef
trend which underlies the Bass Island CO2 injection zone. The presence of these seeps reveals
that migration pathways are present in the area and can facilitate rapid migration of light
hydrocarbons to the surface from intervals deeper than the CO2 injection zone. Extensive leakage
associated with corroded wells in the immediate vicinity of the CO2 injection well was reported
in detail by Toelle et al. (2007). Based on their study, additional recommendations were made in
direct support of the NETL plan to place samplers near wells close to the CO2 injection well.
References
Richards, J.A., Walter, L.M., Budai, J.M., and Abriola, L.M., 1994, Large and small scale
structural controls on fluid migration in the Antrim Shale, northern Michigan basin, in Advances
in Antrim Shale Technology: Gas Research Institute in cooperation with the Michigan section
SPE [Mount. Pleasant, Michigan, Dec. 13, 1994], 23 p.
Ryder, R.T., 2003, Fracture patterns and their origin in the Upper Devonian Antrim Shale gas
reservoir of the Michigan Basin: A review. USGS Open File Report 96-23.
Toelle, B., Pekot, L., and Mannes, R., 2007, CO2 EOR from a north Michigan Silurian reef:
Procedings paper, Spcietyof Petroleum Engineers SPE-111223-PP, 6p.
Wood, J. R, Wylie, A., and Quinlan, W., 2004a, Surface geochemical results complement
conventional development approaches: in WorldOil Magazine (WorldOil.com) http://www.worldoil.com/magazine/MAGAZINE_DETAIL.asp?ART_ID=2456&MONT Online Magazine Article Features – Dec-2004, 10 pages.
Wood, J. R, Wylie, A., and Quinlan, W., 2004b, Using recent advances in 2DE seismic
technology and surface geochemistry to economically redevelop a shallow shelf carbonate
reservoir” Vernon Field, Isabella County, MI: DOE Quarterly report, Award number DE-FC2600BC15122, 23p.
16
Figure 1: Tracer monitoring grid is shown on this orthophoto of the site.
17
LMB19
4991200
4991100
LMB01 LMB02 LMB03 LMB04
4991000
LMB08 LMB07 LMB06 LMB05
C3-30A
4990900
LMB09 LMB10 LMB11 LMB12
LMB17
4990800
LMB16 LMB15 LMB14 LMB13
4990700
4990600
LMB18
697700 697800 697900 698000 698100 698200
Figure *: Reference map for monitoring grid.
18
All
Values
in fl/L
SORBENT SET
#1 9-28-08, 1022-08,
BACKGROUND
SORBENT
SET #2,
During
Tracer
Injection
2-20-08
SORBENT
SET #3,
Immediatel
y After
Tracer
Injection,
2-21-08 to
3-12-08
SORBENT
SET #4,
3-12-08 to
4-08-08
SORBENT
SET #5,
4/8/08 to
5/21/08
SORBENT
SET #6,
5/21/08 to
9/17/08
Post
injection
Averages
8
7
4
7
10
9
7
8
Site
LMB-01
LMB-02
9
8
9
LMB-03
LMB-04
LMB-06
LMB-07
LMB-08
LMB-09
2
8
14
10
9
28
20
12
149
10
8
14
10
39
11
9
9
9
8
15
7
2
11
13
7
7
10
9
9
16
11
18
44
8
9
LMB-10
LBM-11
LMB-12
LMB-13
LMB-14
LMB-15
10
12
8
14
36
15
9
12
7
10
12
9
9
11
1
10
11
9
3
12
6
11
9
13
12
9
2
9
13
9
8
11
4
10
11
10
LMB-16
LMB-17
LMB-18
LMB-19
LMB-20
15
6
5
11
6
3
19
36
9
4
3
12
6
3
2
12
2
10
10
5
3
12
9
6
3
12
16
Average
Standard
deviation
Median
Max
Min
12
7.84
20
32.27
10
7.90
7
4.09
9
2.97
12
8.76
10
36
2
10
149
3
9
39
1
7
15
2
9
13
2
10
44
3
Table 1
Tracer in Soil-Gas: Pre- and Post-Tracer Injection Results
19
4991200
4991200
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
50
45
40
35
30
25
20
15
10
5
0
C3-30A
LMB09
LMB11
LMB10
LMB12
LMB17
4990800
LMB19
LMB19
4991200
4990900
Set 3
Set 3
Set 1
LMB19
LMB16
LMB15
LMB14
LMB13
4990700
4991100
4991000
LMB01
LMB02
LMB03
LMB04
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB10
LMB11
LMB12
LMB17
4990800
LMB15
LMB16
LMB14
LMB13
4990700
4990600
4990600
50
45
40
35
30
25
20
15
10
5
0
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB10
LMB11
LMB12
4990800
LMB16
LMB15
LMB14
LMB13
LMB17
4990700
4990600
LMB18
LMB18
LMB18
697700 697800 697900 698000 698100 698200
697700 697800 697900 698000 698100 698200
697700 697800 697900 698000 698100 698200
Set 5
Set 4
LMB19
LMB19
4991200
4991200
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB11
LMB10
LMB12
LMB17
4990800
LMB15
LMB16
LMB14
LMB13
4990700
50
45
40
35
30
25
20
15
10
5
0
4990600
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB10
LMB11
LMB12
4990800
LMB16
LMB15
LMB14
LMB13
LMB17
4990700
50
45
40
35
30
25
20
15
10
5
0
4990600
LMB18
LMB18
697700 697800 697900 698000 698100 698200
697700 697800 697900 698000 698100 698200
Set 6
Average
LMB19
LMB19
4991200
4991200
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB10
LMB11
LMB12
LMB17
4990800
LMB16
LMB15
LMB14
LMB13
4990700
50
45
40
35
30
25
20
15
10
5
0
4991100
LMB01
LMB02
LMB03
LMB04
4991000
LMB08
LMB07
LMB06
LMB05
C3-30A
4990900
LMB09
LMB10
LMB11
LMB12
4990800
LMB16
LMB15
LMB14
LMB13
LMB17
4990700
50
45
40
35
30
25
20
15
10
5
0
4990600
4990600
LMB18
697700 697800 697900 698000 698100 698200
LMB18
697700 697800 697900 698000 698100 698200
Figure *: PFC concentrations observed in sample sets 1 through 6 are contoured for comparison
20
50
45
40
35
30
25
20
15
10
5
0
LMB22
4992000
4991800
LMB21
4991600
LMB23
4991400
LMB19
4991200
LMB04
LMB01
LMB07 LMB06
4991000
LMB20
LMB10 LMB11
LMB24
LMB17
LMB16
4990800
697600
697800
698000
LMB13
698200
698400
Figure *: Reference map for passive atmospheric monitoring grid.
21
SORBE
NT SET
#1 928-08,
10-2208,
BACKG
ROUND
SORBENT
SET #2,
During
Tracer
Injection
2-20-08
LMB-01 P-Atm
14
20
LMB-04 P-Atm
14
All Values
in fl/L
SORBENT
SET #3,
Immediately
After Tracer
Injection,
2-21-08 to 312-08
SORBENT
SET #4,
3-12-08 to
4-08-08
SORBENT
SET 5,
4/8/08 to
5/21/08
SORBENT
SET 6,
5/21/08 to
9/17/08
Post
injection
averages
15
12
6
10
11
Site
545
13
12
7
9
10
LMB-06 P-Atm
6285
30
16
7
10
16
LMB-07 P-Atm
30
19
18
4
10
13
LMB-10 P-Atm
19
235
14
15
5
12
11
LMB-11 P-Atm
13
280
13
12
9
8
11
LMB-13 P-Atm
18
75
16
15
12
15
15
LMB-16 P-Atm
13
25
14
11
6
9
10
LMB-17 P-Atm
23
15
16
18
13
16
LMB-19 P-Atm
20
25
1
11
12
LMB-20 P-Atm
15
14
3
14
11
LMB-21 P-Atm
23
12
2
10
12
LMB-22 P-Atm
16
16
2
10
11
LMB-23 P-Atm
0
22
2
10
8
LMB-24 P-Atm
27
21
2
9
15
Average
Standard
deviation
16
3.78
753
1951.35
17
7.20
15
3.55
6
4.63
11
2.13
12
2.24
Median
Max
Min
14
23
13
53
6285
15
15
30
0
15
22
11
5
18
1
10
15
8
11
16
8
Table 2
Tracer in Passive Atmospheric Samples: Pre-, During-, and Post-Injection Results
22
Set 2 Passive
Set 1 Passive
LMB22
LMB22
4992000
4992000
4991800
28
4991600
LMB21
24
LMB23
6500
6000
5500
5000
4500
4000
3500
3000
2500
2000
1500
1000
500
0
4991800
LMB21
4991600
LMB23
20
16
4991400
4991400
12
LMB19
8
4991200
LMB04
LMB01
4
LMB07 LMB06
4991000
0
LMB20
LMB10 LMB11
LMB24
LMB19
4991200
LMB04
LMB01
LMB07 LMB06
4991000
LMB20
LMB10 LMB11
LMB24
LMB17
LMB13
LMB16
4990800
697600
697800
LMB17
698000
LMB13
LMB16
4990800
698200
698400
697600
697800
Set 3 Passive
698000
698400
Set 4 Passive
LMB22
LMB22
4992000
4992000
4991800
28
LMB21
4991600
698200
4991800
LMB23
28
LMB21
24
4991600
16
4991400
20
16
4991400
12
LMB19
8
4991200
4991000
LMB07 LMB06
LMB20
12
LMB19
8
4991200
4
LMB04
LMB01
0
LMB07 LMB06
4991000
LMB20
LMB17
LMB13
LMB16
697600
0
LMB10 LMB11
LMB24
LMB17
4990800
4
LMB04
LMB01
LMB10 LMB11
LMB24
LMB13
LMB16
4990800
698000
698400
697600
697800
Set 5 Passive
698000
698200
698400
Set 6 Passive
LMB22
LMB22
4992000
4992000
4991800
28
4991800
28
24
LMB21
4991600
24
LMB23
20
LMB23
20
LMB21
4991600
24
LMB23
20
16
16
4991400
4991400
12
12
LMB19
LMB19
8
4991200
0
LMB07 LMB06
4991000
8
4
LMB04
LMB01
4991200
4
LMB04
LMB01
LMB07 LMB06
4991000
LMB20
LMB20
LMB10 LMB11
LMB24
LMB17
LMB17
LMB16
4990800
697600
697800
698000
LMB16
4990800
LMB13
698200
0
LMB10 LMB11
LMB24
698400
697600
697800
698000
LMB13
698200
698400
Figure *: PFC concentrations observed in passive atmospheric monitoring sample sets 1 through
6 are contoured for comparison.
23
SORBE
NT SET
#1 928-08,
10-2208,
BACKG
ROUND
SORBENT
SET #2,
During
Tracer
Injection
2-20-08
SORBENT
SET #4,
3-12-08 to
4-08-08
SORBENT
SET 5,
4/8/08 to
5/21/08
SORBENT
SET 6,
5/21/08 to
9/17/08
Post
injection
averages
LMB-01 P-Atm
14
20
15
12
6
10
11
LMB-04 P-Atm
14
545
13
12
7
9
10
LMB-06 P-Atm
6285
30
16
7
10
16
LMB-07 P-Atm
30
19
18
4
10
13
All Values
in fl/L
SORBENT
SET #3,
Immediately
After Tracer
Injection,
2-21-08 to 312-08
Site
LMB-10 P-Atm
19
235
14
15
5
12
11
LMB-11 P-Atm
13
280
13
12
9
8
11
LMB-13 P-Atm
18
75
16
15
12
15
15
LMB-16 P-Atm
13
25
14
11
6
9
10
LMB-17 P-Atm
23
15
16
18
13
16
LMB-19 P-Atm
20
25
1
11
12
LMB-20 P-Atm
15
14
3
14
11
LMB-21 P-Atm
23
12
2
10
12
LMB-22 P-Atm
16
16
2
10
11
LMB-23 P-Atm
0
22
2
10
8
LMB-24 P-Atm
27
21
2
9
15
Average
Standard
deviation
16
3.78
753
1951.35
17
7.20
15
3.55
6
4.63
11
2.13
12
2.24
Median
Max
Min
14
23
13
53
6285
15
15
30
0
15
22
11
5
18
1
10
15
8
11
16
8
Table 3
Tracer in 3-Liter Active Atmospheric Samples: Pre- and Post-Injection Results
24