1. Introduction
1.1. Purpose
2. Site Setting
3.1. LNAPL Recovery
4.1. LNAPL Properties
4.2. LNAPL Distribution
4.3. LNAPL Recoverability
4.4. LNAPL CSM Summary
6. Vapor Phase
8.1. Remediation Management Area No. 1
8.2. Remediation Management Area No. 2
8.3. Remediation Management Area No. 3
8.4. Remediation Management Area No. 4
8.5. Remediation Management Area No. 5
8.6. Remediation Management Area No. 6
8.7. Remediation Management Area No. 7
8.8. Remediation Management Area No. 8
8.9. Remediation Management Area No. 9
8.10. Remediation Management Area No. 10
9. References
Tables
Figures
Figure 1-1. Site Layout
Figure 2-1 North Olive Lithology Compare
Figure 2-2 North Market Lithology Compare
Figure 2-3 Isometric Compare
Figure 2-4. North Olive Stratum Extent And Isopach
Figure 2-5. Rand Stratum Extent And Isopach
Figure 2-6. Epa Stratum Extent And Isopach
Figure 2-7. Main Silt Extent And Isopach
Figure 3-1. Total Petroleum Hydrocarbons Recovered Since 1978
Figure 3-2. Vapor Collection System Layout And Production Well Locations
Figure 4-1. LNAPL Characterization And Viscosity Results
Figure 4-2. Benzene Effective Solubility And Dissolved Phase Concentrations
Figure 4-3. Laser Induced Fluorescence Boring And LNAPL Sample Locations
Figure 4-4. Three Dimensional LNAPL Distribution
Figure 4-5. LNAPL Thickness In The Rand Stratum, Low Groundwater
Condition, January 2006
Figure 4-6. LNAPL Thickness In The Rand Stratum, Low Groundwater
Condition, March 2015
Figure 4-7. LNAPL Thickness In The Rand Stratum, Average Groundwater
Condition, April 2007
Figure 4-8. LNAPL Thickness In The Rand Stratum, Average Groundwater
Condition, July 2017
Figure 4-9. LNAPL Thickness In The Rand Stratum, High Groundwater
Condition, July 2008
Figure 4-10. LNAPL Thickness In The Rand Stratum, High Groundwater
Condition, January 2016
Figure 4-11. LNAPL Thickness In The Main Sand Stratum, Low Groundwater
Condition, January 2006
Figure 4-12. LNAPL Thickness In The Main Sand Stratum, Low Groundwater
Condition, March 2015
Figure 4-13. LNAPL Thickness In The Main Sand Stratum, Average
Groundwater Condition, April 2007
Figure 4-14. LNAPL Thickness In The Main Sand Stratum, Average
Groundwater Condition, July 2017
Figure 4-15. LNAPL Thickness In The Main Sand Stratum, High Groundwater
Condition, July 2008
Figure 4-16. LNAPL Thickness In The Main Sand Stratum, High Groundwater
Condition, January 2016
Figure 4-17. Fluid Level Saturations For Soil Cores
Figure 4-18. Schematic Diagram Of Dual Optimal LNAPL Response Model
Figure 5-1. Saturated Thickness North Olive Stratum, Low Groundwater
Conditions, March 2015
Figure 5-2. Saturated Thickness North Olive Stratum, High Groundwater
Conditions, January 2016
Figure 5-3. Saturated Thickness Rand Stratum, Low Groundwater Conditions,
March 2015
Figure 5-4. Saturated Thickness Rand Stratum, High Groundwater Conditions,
January 2016
Figure 5-5. Potentiometric Surface Map Main Sand Stratum, Low Groundwater
Conditions, March 2015
Figure 5-6. Potentiometric Surface Map Main Sand Stratum, Average
Groundwater Conditions, July 2017
Figure 5-7. Hydraulic Head Analysis, Monitoring Point Mp-079d (Zone 1)
Figure 5-8. Hydraulic Head Analysis, Monitoring Point Mp-053c (Zone 5)
Figure 5-9. Hydraulic Head Analysis, Monitoring Point Mp-085d (Zone 6)
Figure 5-10. Detailed Potentiometric Surface Map Main Sand Stratum,
January 2016
Figure 5-11. Detailed Potentiometric Surface Map Main Sand Stratum,
April 2016
Figure 5-12. Detailed Potentiometric Surface Map Main Sand Stratum,
July 2016
Figure 5-13. Detailed Potentiometric Surface Map Main Sand Stratum,
October 2016
Figure 5-14. Historical Dissolved Phase Constituents Of Concern, Shallow
Hydrostratigraphic Units (2006 - 2008)
Figure 5-15. Dissolved Phase Constituents Of Concern, Shallow
Hydrostratigraphic Units (2013 - 2018)
Figure 5-16. Dissolved Phase Constituents Of Concern, Deep
Hydrostratigraphic Units (2013 - 2018)
Figure 5-17. Dissolved Phase Natural Attenuation Indicators, Shallow
Hydrostratigraphic Units (2013 - 2018)
Figure 5-18. Dissolved Phase Natural Attenuation Indicators, Deep
Hydrostratigraphic Units (2013 - 2018)
Figure 5-19. Dissolved Phase Constituents Of Concern And
Hydrogeochemical Indicator Summary Versus Distance
Figure 5-20. Assimilative Capacity Through Centerline
Figure 6-1. Vapor Intrusion Conceptual Site Model
Figure 6-2. Structures With Historical Fire And Odor Complaints
Figure 6-3. Typical Soil Vapor Extraction Wellhead Completion Detail
Figure 6-4. Typical Wellhead, Stinger, And Flowrate Measurement Device
Details For New And Modified Extraction Wells
Figure 6-5. Effectiveness Monitoring Network And Lines Of Section
Figure 6-6. Typical Stinger Detail
Figure 6-7. Total Volatile Petroleum Hydrocarbon Mass Recovery Rate By
SVE Effectiveness Zone
Figure 6-8. Distribution Of Benzene In Soil Vapor Under Low And High River
Stage (2004-2005)
Figure 6-9. Distribution Of Isopentane In Soil Vapor Under Low And High
River Stage (2004-2005)
Figure 6-10. River Stage Triggered Event Summary (2007 - 2011)
Figure 6-11. River Stage Triggered Event Summary (2012 - 2017)
Figure 6-12. Structures That Have Been Monitored And Mitigated
Figure 6-13. Select Constituents Of Concern Versus Total Volatile Petroleum
Hydrocarbons In Indoor Air
Figure 6-14. Vapor Intrusion Pathway Decision Flowchart
Figure 7-1. Site-Specific Attenuation Factors
Figure 8-1. Proposed Remediation Management Areas
Appendices
Appendix A
Appendix B
Appendix C
Appendix D
Appendix E
Appendix F
Appendix G
Appendix H
Appendix I
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Conceptual Site Model, March 2018
Hartford Petroleum Release Site
3. INTERIM MEASURES
Numerous releases of petroleum hydrocarbons attributed to the refining, storage, and transport of petroleum hydrocarbons have been documented within or immediately adjacent to the Hartford Site. Refining, storage, and transport of petroleum hydrocarbons continues to be conducted adjacent to and beneath the Village of Hartford. As shown on Figure 1-1, there are numerous active and inactive product lines traversing the Hartford Site (Clayton 2004c). These included but are not limited to the following:
Petroleum hydrocarbons likely migrated from buried petroleum-related wastes (e.g., tank bottoms, sludges, etc.) and releases (spills and leaks from tanks, process units, pipelines, sewers, etc.) which occurred on the British Petroleum, Shell, and Premcor facilities. In addition,there is evidence and records from the refineries, terminals, and pipeline operators indicating that some of the pipelines beneath the Village of Hartford had developed slow, continuous leaks over time (USEPA et al. 2010).
The various and multiple sources of releases resulted in a complicated distribution of petroleum hydrocarbons beneath the Hartford Site. While a portion of the releases may have migrated overland with storm water runoff, much of the released hydrocarbons (referred to herein as LNAPL) migrated down through the subsurface under the influence of gravity until encountering groundwater or the shallow clay units underlying the refineries and the Hartford Site. Due to capillary forces, some fraction of the LNAPL was retained in soil pore space, whereas some fraction of the LNAPL displaced water present in the pore space. As the volume of LNAPL increased over time, further lateral and vertical migration. Vertical migration into deeper hydrostratigraphic units is believed to have occurred where the less permeable layers were discontinuous or absent. The distribution of LNAPL stabilized as gravity and capillary forces approached equilibrium and natural smear zone depletion reduced the mass of hydrocarbons (notably along the vertical and horizontal margins of the smear zone).
Vertical smearing of the LNAPL occurred over time as a result of fluctuation of the groundwater, leaving some LNAPL within the soil pore spaces within each of the hydrostratigraphic units. The bottom of the “smear zone” is roughly coincident with the historical low groundwater elevation in the Main Sand. The thickness of the smear zone is variable measuring only a few inches at the plume periphery, to tens of feet in locations near historical releases. The vertical and lateral distribution of the smear zone also varies due to heterogeneities in the lithology. In general, the LNAPL smear zone and dissolved phase plume limits are coincident. At the most, the dissolved phase plume extends approximately 100 feet beyond the LNAPL smear zone boundary.
Petroleum hydrocarbons are a mixture of thousands of individual constituents from several classes, including aliphatics, aromatics, paraffins, isoparaffins, olefins, and naphthalenes. Each constituent has somewhat different physical, chemical, and toxicological properties. Some of these constituents are sufficiently toxic to pose a potential human health risk via dermal contact, ingestion, and inhalation if present at sufficient concentration. Once released into the subsurface, petroleum hydrocarbons may be present as: (1) mobile, and potentially recoverable LNAPL, (2) immobile, or residual LNAPL, (3) vapor phase in unsaturated zone portions of the subsurface, and (4) dissolved phase within saturated portions of the subsurface. A dynamic equilibrium exists between these various phases at the Hartford Site, for instance a change in the Mississippi River stage can expose or submerge portions of the smear zone affecting LNAPL saturation and conductivity, as well as the distribution of volatile and soluble constituents in soil vapor and groundwater.
Interim measures performed at the Hartford Site since 1978 have primarily included skimming of LNAPL and vapor extraction. As shown on Figure 3-1, approximately 3.2 million gallons of LNAPL have been recovered, with 1.3 million gallons removed via skimming and 1.9 million gallons recovered as vapor through operations of the SVE system.
It is also recognized that that natural smear zone depletion processes have reduced the mass of petroleum hydrocarbons in the subsurface since the releases occurred. Most petroleum hydrocarbons are readily degradable by soil microorganisms in the presence of oxygen, a process referred to as aerobic biodegradation. These microorganisms can thrive within the saturated and unsaturated zones beneath the ground. Petroleum hydrocarbons are also degraded by soil microorganisms in the absence of oxygen, via anaerobic respiration, but generally at a slower rate compared with aerobic degradation. In these cases, secondary oxidizers such as iron, manganese, sulfate, nitrates, and carbon dioxide are reduced. It is important to note that the use of the terms natural attenuation, intrinsic biodegradation, and natural smear zone depletion are all synonymous and have been collectively used herein to describe the natural depletion of petroleum hydrocarbons. While estimates of the total mass loss from natural smear zone depletion have not been made for the Hartford Site, empirical evidence indicating that natural processes are actively reducing the mass of volatile and soluble constituents within the LNAPL are provided in Section 5 and Section 6 of this updated CSM.
3.1. LNAPL RECOVERY
Between 1978 and 1979, Clark Oil Company installed two large diameter groundwater production wells (RW-001 and RW-002, shown on Figure 3-2) at the Hartford Site for the purpose of skimming LNAPL. Between 1978 and 1990, LNAPL skimming was performed within these two production wells, with the exception of a period between 1983 and 1984 when operations were temporarily ceased. Approximately 1.15 million gallons of LNAPL were recovered from these two wells through 1990. Skimming rates ranged from approximately 1,000 to 29,000 gallons per month (Engineering-Science 1992).
A third production well (RW-003, shown on Figure 3-2) was installed at the Hartford Site by Premcor in 1993. From January 1994 through September 2002, Premcor reportedly recovered 82,700 gallons of LNAPL from the three production wells (USEPA et al. 2010).
Beginning in 2004, a consortium of oil companies including Premcor, Shell, BP, and Sinclair Oil Corporation (referred to as the Hartford Working Group) began managing interim measures, including LNAPL skimming. In 2004, the Hartford Working Group installed three additional wells (RW-004, RW-004A, and RW-005, shown on Figure 3-2) for the purpose of LNAPL skimming. Approximately 21,500 gallons of LNAPL were recovered via skimming activities from the six production wells between 2004 and 2009.
In addition, the Hartford Working Group performed a number of pilot tests over this five-year period to evaluate potential remedial technologies (Clayton 2006). These pilot tests primarily involved (1) multiphase extraction (MPE), which was defined as high vacuum recovery of vapor, groundwater, and LNAPL using a stinger placed slightly above the LNAPL-air interface, and (2) dual phase extraction (DPE), defined as LNAPL recovery augmented with limited groundwater extraction (maximum of 2.5 feet of drawdown was achieved during testing). Approximately 6,000 gallons of LNAPL was recovered as part of performing these pilot tests by the Hartford Working Group.
In March 2009, routine operations, monitoring, and maintenance (OMM) of the interim measures at the Hartford Site were transferred to Apex. Apex continued to conduct LNAPL skimming in two of the recovery wells (RW-002 and RW 004A) until December 2010, recovering 15,000 gallons of LNAPL. In addition, Apex conducted LNAPL skimming activities within the groundwater monitoring network beginning in late 2009 through the end of 2012, recovering 25,000 gallons of LNAPL. Skimming within recovery wells RW-002 and RW-004A resumed in 2016, resulting in the recovery of 450 gallons of LNAPL between 2016 and 2017.
Additional pilot testing was performed by Apex between 2011 and 2015. These additional pilot tests were performed in fulfillment of the remedial alternatives evaluation process described within the Active LNAPL Recovery System 90% Design Report, The Hartford Area Hydrocarbon Plume Site, Hartford, Illinois (90% Design Report, Clayton et al. 2006) and included further evaluation of MPE and DPE in Area A (situated along North Olive Avenue as shown on Figure 3-2) of the Hartford Site. The three large-scale pilot tests resulted in no additional LNAPL being recovered from Area A. The results of these three pilot tests are further examined within Section 4.3.5.
3.2. SOIL VAPOR EXTRACTION
The original SVE system was installed by Clark Oil & Refining Corporation (now Premcor) and operated from approximately 1992 until it was upgraded in 2004. The original SVE system consisted of 12 vapor control boreholes, two 75-horsepower (HP) blowers, and a single thermal treatment oxidizer. As shown on Figure 3-1, more than 820,000 gallons of volatile petroleum related hydrocarbons were recovered by Clark Oil & Refining Corporation via the original SVE system.
The original system was replaced in three phases beginning in 2004 by the Hartford Working Group and currently consists of a network of 118 vapor extraction wells primary installed within the shallow hydrostratigraphic units (North Olive and Rand strata). The extraction wells are connected through a series of piping and valves to a single 12-inch pipe that conveys recovered vapors from the Hartford Site below the Union Pacific, Kansas City Southern, and Norfolk Southern Railroads rights-of-way located east of North Olive Avenue to four 75-HP blowers located on the Premcor facility. The four blowers have a total capacity of approximately 3,200 standard cubic feet per minute (scfm). The recovered soil vapor is treated using between one and four thermal oxidizers, each capable of processing 9 million British thermal units (BTUs) per hour.
Detailed records of hydrocarbon recovery rates have been documented for the SVE system since it was replaced by the Hartford Working Group in 2005. As shown on Figure 3-1, approximately 1 million gallons of volatile petroleum hydrocarbons have been recovered through the SVE system through the end of 2017. Vapor recovery has not reached asymptotic conditions and is directly related to the groundwater elevations within the various hydrostratigraphic units. Additional discussion of the SVE system as it relates to volatile petroleum related constituent distribution beneath the Hartford Site is included in Section 6.3.