INVESTIGATION OF THE HYDRAULIC EFFECTS OF
DEEP-WELL INJECTION OF INDUSTRIAL WASTES
Edward Mehnert, Craig R. Gendron, and Ross D. Brower
Illinois State Geological Survey
Final Report
Prepared for
United States Environmental Protection Agency
Office of Drinking Water
David Morganwalp, Project Officer
EPA Cooperative Agreement No. CR-813508-01-0
and
Hazardous Waste Research and Information Center
Department of Energy and Natural Resources
Jacqueline Peden, Project Officer
ENR Contract No. HWR 86022
1990
ENVIRONMENTAL GEOLOGY 135
HWRIC RR 051
ILLINOIS STATE GEOLOGICAL SURVEY
Natural Resources Building
615 East Peabody Drive
Champaign, Illinois 61820
HAZARDOUS WASTE RESEARCH AND INFORMATION CENTER
One East Hazelwood Drive
Champaign, Illinois 61820
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CONTENTS
FIGURES
TABLES
ACKNOWLEDGMENTS
ABSTRACT
EXECUTIVE SUMMARY
GLOSSARY
1. INTRODUCTION
Background
Purpose
2. GEOLOGY OF THE INJECTION SYSTEM
Overview of the Geologic Environment
Regional Geology and Hydrogeology
3. HYDROGEOLOGIC INVESTIGATION OF THE INJECTION SYSTEM
Stratigraphic and Structural Definition of the Injection System
Field Investigations
4. NUMERICAL MODELING
Model Selection
Model Description
Input Data
Modeling Results
Model Projections for Long-Term Injection
Hypothetical Conduits
5. SUMMARY AND CONCLUSIONS
Evaluation of Injection Scenarios
Evaluation of Monitoring Strategies
REFERENCES
APPENDIX A Theory and practical application of geophysical
logging instruments
APPENDIX B Reduction and analysis of geophysical log data
APPENDIX C Brucite formation: proposed mechanism of formation
APPENDIX D Sensitivity analysis
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FIGURES
1 Location of investigation site 2
2 Generalized areal geology of the bedrock surface 5
3 Generalized statewide cross sections of Illinois 6
4 Description of rock units and their hydrogeologic roles 8
5 Geologic structures in Illinois 10
6 Seismic risk map for Illinois 11
7 Earthquake epicenters in Illinois 12
8 Oil and gas fields of the Illinois Basin 13
9 Location of underground gas storage projects in Illinois 15
10 Generalized thickness and distribution of the Maquoketa Group 16
11 Cross section from Rockford to Cairo showing position of base of the USDW 17
12 Generalized thickness and distribution of the Hunton Supergroup and the
TDS boundary for USDW 18
13 Generalized thickness and distribution of the New Albany Group 19
14 Generalized thickness and distribution of the Mississippian System and
the TDS boundary for USDW 21
15 Well locations 25
16 Geologic column for the injection system at WDW2 26
17 Stratigraphic correlation utilizing resistivity logs for southwest-northeast
cross section 27
28
18 Qualitative permeability correlation utilizing permeability indicator logs
for southwest-northeast cross section 28
19 Stratigraphic correlations utilizing resistivity logs for north-south
cross section 29
20 Structure contour map of the top of the Lingle Formation in the vicinity
of the Velsicol plant 30
21 Injection system in WDW2 indicating permeable and impermeable units
delineated with available geophysical logging 31
22 Injection system in WDW2 indicating permeable and impermeable units
delineated after phase I logging 33
23 Injection system in WDW2 indicating permeable and impermeable units
delineated after phase II logging 37
24 Core locations for WDW2 39
25 Core permeabilities (air and water) versus depth for WDW2 41
26 Core permeabilities versus core porosities for WDW2 41
27 Unit locations for WDW2 42
28 Water level record for the Devonian Observation Well (DOW), including
data from injection test 47
29 Plot of data used for Cooper-Jacob analysis 47
30 Schematic for WDW2 50
31 Schematic for DOW 51
32 Relationship between waste viscosity and specific gravity 52
33 The compressibility of water and various NaCI solutions versus temperature 53
34 Comparison of model-predicted drawdowns with results from Theis analysis 55
35 Comparison of model-predicted drawdowns versus time with Hantush analysis 55
36 Conceptual model 1 of the injection system 56
37 Comparison of model-predicted Ah versus field data 59
38 Head buildup versus radial distance for q = 1.82x10"4 m3/sec 59
39 Injection scenario 1: head buildup and decline with time at the DOW 59
40 Injection scenario 2: head buildup and decline with time at the DOW 60
41 Injection scenario 2: head buildup and decline with time at WDW2 60
42 Conceptual model 2 of the injection system 61
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43 Effect of microannuius on the head buildup at the WDW2 63
44 Effect of microannuius on the head buildup at the DOW 63
45 Effect of microannuius on the head buildup in the "Carper sand" 63
46 Head buildup in the "Carper sand" versus radial distance from WDW2 63
A-1 Caliper Log tool which utilizes a dual potentiometer configuration 70
A-2 Continuous Spinner Flowmeter Log tool 71
A-3 Generalized Sonic Log tool 73
A-4 Idealized schematic of receiver (R) signal 73
A-5 Generalized Borehole Compensated Sonic Log tool 74
A-6 Generalized Compensated Neutron Log tool 75
A-7 Generalized two-detector Density Log tool 76
A-8 Schematic diagram of induction log principles 77
A-9 Schematic diagram of lateral logging system 78
A-10 Schematic diagram of normal logging system 78
A-11 Schematic diagram of spontaneous potential circuit 79
B-1 "Tornado" chart for Dual Induction-Focused Log analysis 81
B-2 Neutron porosity lithologic correction chart 81
B-3 Compensated Neutron Log and Borehole Compensated Acoustilog
porosity crossplot 82
B-4 Determination of the cementation factor 85
B-5 Rm-Rmf-Rmc relationships 86
B-6 NaCI concentration for different temperatures and fluid resistivities 87
B-7 Core porosity versus log porosity (phase I, cross-plotted porosity) for WDW2 87
B-8 Core water saturation versus log water saturation for WDW2 87
C-1 Injection system in WDW2 indicating permeable and impermeable zones
delineated with the aid of geophysical logging 89
C-2 Core composition: dolomite, brucite for WDW2 91
C-3 SEM photograph for core at 2,484.5 feet KB (x58.5) 92
C-4 SEM photograph for core at 2,484.5 feet KB (x1,050) 93
C-5 SEM photograph for core at 2,479.5 feet KB (x80) 93
C-6 SEM photograph for core at 2,479.5 feet KB (x1,080) 94
C-7 SEM photograph for core at 2,456.5 feet KB (xl 13) 94
C-8 SEM photograph for core at 2,456.5 feet KB (x1,160) 95
D-1 Conceptual model 1 of the injection system 96
D-2 Conceptual model 2 of the injection system 97
D-3 Sensitivity analysis: effect of injection rate 99
D-4 Sensitivity analysis: effect of rock compressibility 99
D-5 Sensitivity analysis: effect of fluid compressibility 100
D-6 Sensitivity analysis: effect of hydraulic conductivity 100
D-7 Sensitivity analysis: effect of anisotropy 100
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TABLES
1 Wells used in study 24
2 Data from geophysical logs run in the DOW 34
3 Data from existing geophysical logs run in WDW2 35
4 Summary of important formation characteristics 36
5 Fluid loss percentage calculated from CSFL 36
6 Core location and analysis 38
7 Results of core analysis 40
8 Summary of hydrogeological data for a portion of the disposal zone 43
9 Additional hydrogeological data for primary injection sections 45
10 Selected chemical and physical properties of water injected during injection test 46
11 Volume injected into WDW2 during injection test 46
12 Analysis of injection test 46
13 Selected parameters for fluids injected via WDW2 51
14 Chemical analysis of waste and brine 53
15 Compressibility of waste and brine 54
16 I nput data for the Theis solution 55
17 Input data for leaky aquifer simulation 56
18 Selected input data for model calibration 56
19 Comparison of transmissivity (T) and storativity (S) values 57
20 Permeability of the microannulus 62
B-1 Data from geophysical logs run in the DOW 81
B-2 Data from existing geophysical logs run in WDW2 84
B-3 Summary of important formation characteristics 85
C-1 Core porosities and brucite concentration 90
C-2 Effect of brucite concentration on total flow 90
D-1 Effect of boundary conditions on head buildup 97
Printed by authority of the State of Illinois/1990/1000
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ACKNOWLEDGMENTS
We thank the following people for their assistance throughout this project.
Jeffrey S. Brown, Robert Colvin, and Thomas Capps, Velsicol Chemical Corporation, for allowing
us access to their site and assistance in the completion of the field tests conducted on-site.
Frank Brookfield and Lance Perry, Hazardous Waste Research and Information Center (HWRIC),
for their tireless assistance with the PRIME computer—from debugging and compiling code to not
complaining when we monopolized the computer time.
Richard A. Cahill, Beverly Seyler, Robert R. Frost, Herbert Glass, and William R. Roy, Illinois
State Geological Survey (ISGS), for performing various chemical and physical analyses on
samples of the core, waste stream, and native formation brine. These analyses included ther-
modynamic modeling, x-ray fluorescence, microprobe, scanning electron microscopy, and x-ray
diffraction.
Lynn R. Evans, ISGS, for compiling the data regarding the chemical and physical characteristics
of the UIC wastes.
David Morganwalp, project manager for the U.S. Environmental Protection Agency, for his assis-
tance and patience during this project.
Jackie Peden, HWRIC project manager, and Gary D. Miller, former project manager, for their as-
sistance and patience during this project.
Adrian Visocky, Illinois State Water Survey, for his advice regarding the analysis of the data from
the injection test.
Anne M. Graese, Bruce R. Hensel, Timothy H. Larson, Janis D. Treworgy, and Steven T.
Whitaker, ISGS, for their insightful review of this report.
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ABSTRACT
A numerical modeling study was conducted to investigate the hydraulic effects of liquid waste in-
jection on an injection system. The site investigated was a chemical refinery with an operational
Class I well and an observation well, both completed in Devonian limestone. Input data for the
model were obtained from available records and field investigations.
The regional geologic investigation indicated that the injection system (defined here as the injec-
tion zone and its associated confining units) was laterally continuous. The hydraulic response of
the injection system was numerically modeled under two injection scenarios: average historical in-
jection rate and maximum average permitted rate. For both scenarios, pressure buildup from
waste injection during the simulated 30-year injection and 30-year postinfection periods did not ap-
proach the pressure calculated to be necessary to initiate or propagate fractures in the injection
system. Therefore, injected waste would be contained, and waste injection at this site and for the
scenarios modeled would not endanger human health or the environment.
This analysis assumes that hydraulic conductivity remains constant; however, the formation of
brucite within the injection zone may invalidate this assumption and the preceding analysis.
Brucite formation within the injection zone requires additional study.
The model was also used to investigate the response of the injection system when a hypothetical
conduit was introduced. This hypothetical conduit connected the uppermost injection zone with an
overlying aquifer. Differences in head buildup were not monitorable in the injection well or in an
observation well completed in the injection zone. Monitorable head differences were observed
only in the overlying aquifer, when the hydraulic conductivity of the hypothetical conduit was
greater than or equal to 1 x10"10 m2.
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EXECUTIVE SUMMARY
Concern over the potential for groundwater contamination from waste injection prompted a multi-
faceted research effort funded by the U.S. Environmental Protection Agency (USEPA) and in-
dustry. The research will provide the USEPA with data needed to determine if underground
injection of hazardous waste endangers human health or the environment. One facet of this re-
search effort was an investigation of the hydraulic effects of deep-well injection on the injection
system.
The injection system includes the geologic units constituting the injection zone and the upper and
lower confining units. The site of this investigation was a chemical refinery in Illinois that has an
operational injection well and an observation well completed in Devonian limestone.
Data Collection and Analysis
Before numerical modeling could be conducted, a hydrogeologic description of the site was
developed from available records and geophysical logs. Numerous records and logs were avail-
able from oil- and gas-related tests and wells within a 10-mile radius of the site. Logs and records
for on-site wells were also used.
In addition, hydraulic tests and geophysical logs were run to obtain detailed hydrogeologic data
on the injection system. Two hydraulic tests were run in the injection well: a continuous spinner
flowmeter survey and a 15-day injection test. Sidewall cores were also retrieved from the injection
well. The following geophysical logs were run in the observation well: Compensated Neutron Log,
Borehole Compensated Sonic Log, Minilog, Dual Induction Spherically Focused Log, and Gamma
Ray Log.
Although analyses of the data from these logs and tests yielded much information concerning the
hydrogeologic character of the injection system, there was one discrepancy—the results of the
spinner flowmeter indicated that the waste was flowing through different zones of the injection sys-
tem than had been theorized from the results of geophysical logging. To clarify this discrepancy,
we conducted additional analyses (x-ray diffraction and scanning electron microscopy). The dis-
crepancy can be explained briefly as follows. Because of its high pH, the injected wastewater
reacts with the Mg2+ present in the injection zones or in solution, forming brucite (Mg[OH]2).
Brucite accumulation reduces the permeability of the injection zone. Greater amounts of brucite
apparently formed in the injection zones where the flow of fluid was greater; thus the zones with
higher permeability were affected first. Additional work beyond the scope of this project is needed
to verify the brucite-formation hypothesis. Also, the long-term effect of this decrease in per-
meability on injectivity needs to be investigated.
Numerical Modeling
Site Analysis
A description of the regional and site-specific stratigraphy, structural geology, and hydrogeology
of the injection system was generated from a review of available data and the field work con-
ducted during this project. This description formed the basis of input for the numerical model.
Model input also included data on the physical and chemical characteristics of the injected waste-
water and the native brine in the injection system.
These data were employed as input data for a three-dimensional groundwater flow model
(HST3D). Before the effects of various injection scenarios were evaluated, HST3D was verified
with respect to two analytical solutions and calibrated by the use of data collected during a 2-
week injection test. Both verification and calibration were considered satisfactory.
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Once calibrated, the model was used to predict the effects of various injection scenarios. The ef-
fect of long-term injection was investigated at two constant injection rates—the average historical
rate (1.15x10"2 m3/sec) and the maximum average rate permitted under Class I regulations
(2.21x10"2 m3/sec). With both scenarios, significant head buildup was observed at the injection
well and radially from it. During the simulated 30-year injection period, steady state was ap-
proached but not obtained for both injection scenarios. During the subsequent 30-year postinjec-
tion period, dropoff in head buildup was fairly rapid, falling to half in less than 2,000 hours for both
scenarios. The maximum hydraulic pressures at the bottom of the well and at the base of the
upper confining unit were significantly lower than the pressures calculated to initiate hydraulic frac-
turing. A fracture gradient of 1.5x104 Pa/m (Pascals/meter) (0.65 psi/ft) was used to calculate the
hydraulic fracture pressures.
The regional and site-specific geological analysis revealed the continuity of the stratigraphy and
qualitative permeability on a regional basis. The numerical modeling indicated that injection pres-
sures were lower than calculated pressures required to initiate hydraulic fracturing. Therefore,
from a hydraulic viewpoint, waste injected into this injection system would be contained, and
waste injection at this site and for the scenarios modeled would be considered protective of
human health and the environment.
These results were based on an assumption that the permeability remains constant. If the
hypothesis concerning the formation of brucite is correct, its formation may reduce the per-
meability of the injection zones and invalidate this analysis. Any reduction in permeability of the in-
jection zones will probably increase the hydraulic pressure resulting from waste injection if the
injection rate remains constant. In such a situation, hydraulic fracturing may be of concern. Be-
cause of the potential ramifications, formation of brucite within the injection zone requires addition-
al geochemical analysis.
Effects of Hypothetical Conduit
The model was also used to investigate the hydraulic response of the injection system to the intro-
duction of a hypothetical conduit. The conduit, a microannulus (0.01 m wide) at the injection well,
hydraulically connects the uppermost injection zone and an aquifer immediately overlying the
upper confining unit. To determine the impact of the microannulus, the head buildup with the
microannulus present was compared with the buildup from runs with the microannulus not pre-
sent. Differences in head buildup at selected positions and for certain times were computed. Dif-
ferences in the head buildup were considered unmonitorable at the injection well and the
observation well. The difference in head buildup in the overlying aquifer was monitorable only
when the microannulus had a hydraulic conductivity greater than or equal to 1.00x10"1° m2. The
head buildup in the overlying aquifer is a function of its hydraulic conductivity, the hydraulic con-
ductivity of the microannulus, and the radial distance from the microannulus. Thus for the
scenario modeled, leakage via a microannulus could not be hydraulically monitored by use of the
injection well or an observation well completed within the injection zone. This leakage was
monitorable only through the use of an observation well in the overlying aquifer.
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GLOSSARY
AIF
aquifer influence boundary
b
thickness
DOW
Devonian Observation Weil
GL
ground level
HST3D
Heat and Solute Transport Model
ISGS
Illinois State Geological Survey
k
permeability
K
hydraulic conductivity
KB
Kelly Bushing
m
modulus of shear for the medium
Pa
Pascals
POR
porosity
psi
pounds per square inch
q
pumping rate
s
storativity
SEM
scanning electron microscopy
SWIFT
Sandia Waste Isolation Flow and Transport Model
SWIP
Survey Waste Isolation Program
T
transmissivity
TDS
total dissolved solids
USDW
underground sources of drinking water
USEPA
United States Environmental Protection Agency
WDW2
Waste Disposal Well 2
a
matrix compressibility
P
fluid compressibility
Ah
head buildup
P
fluid density
H
fluid viscosity
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1. INTRODUCTION
Background
Liquid waste is disposed of through underground injection by pumping the waste into or allowing
it to flow through a specially designed and monitored well. Developed by the petroleum industry in
the 1930s as a method for brine disposal, the technique was adapted by other industries in the
1950s for the disposal of industrial waste streams. As regulations for the disposal of waste into
landfills and surface waters became more stringent, the volume of waste disposed of by under-
ground injection increased.
Regulatory agencies have classified injection wells according to the purpose of the wells and the
proximity of injection reservoirs to the lowermost underground source of drinking water (USDW).
The five classes of injection wells are:
Class I — wells used to inject hazardous and nonhazardous wastes below the
lowermost USDW (this report is concerned with this class of wells).
Class II — wells associated with the production and storage of oil and gas below
the lowermost USDW.
Class III — wells used in special process (mining) operations to inject fluid above,
into, or below an USDW.
Class IV — wells used to inject hazardous waste into or above an USDW (this
class of wells is currently banned).
Class V — wells used to inject all other wastes into or above an USDW.
According to the U.S. Environmental Protection Agency (USEPA), there were 429 Class I injec-
tion wells active in 1986 (USEPA 1986). Although the volume of waste disposed of nationwide via
these wells is difficult to estimate, accurate figures are available from some states. In Illinois,
nine Class I wells were used in 1984 to dispose of 310 million gallons of waste (Brower et al.
1989).
With the promulgation of the Hazardous and Solid Waste Amendments of 1984, the level of inter-
est in underground injection increased tremendously. Provisions of the act mandated that the ad-
ministrator of USEPA determine if underground injection is a threat to human health and the
environment for the period the waste remains hazardous. If underground injection is found to be
hazardous to human health and the environment, or if the determination is not made by the Con-
gressionally mandated date, all underground injection will be banned. Some environmental
groups want situations detailed in which underground injection has endangered or may endanger
human health or the environment.
The USEPA developed an extensive research agenda to examine pertinent issues. The USEPA
has funded to date one or more projects in each of the following areas: identification and clas-
sification of Class I well failures; techniques to detect abandoned wells; monitoring of various
aspects of the well; flow and transport modeling of various injection scenarios; geochemical
modeling of injected waste, injection formation, and brine; and hydrogeologic characterization of
important injection formations and associated confining formations. Industry also has conducted
research into pertinent topics of underground injection.
In this project, a numerical model was used to investigate the hydraulic effects of waste injection
on the geologic reservoir. The site of the investigation is a chemical refinery located near Mar-
shall, Illinois, in north-central Clark County (fig. 1). The chemical company used the injection well
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to dispose of alkaline (pH>l2) waste. An observation well, which is completed in the same forma-
tion as the injection well, is located 506 meters north of the injection well.
Purpose
The primary purpose of this project was to investigate the pressure response (flow modeling) of
an actual injection formation and its associated confining formations due to waste injection via a
Class I well. Modeling of solute transport was not investigated here but was addressed by other
researchers sponsored by USEPA and industry. Flow modeling requires detailed characterization
of the site hydrogeology, so this project bridged two areas of concern—flow modeling and
hydrogeologic characterization. In addition, the effectiveness of pressure-monitoring systems to
detect movement of fluid beyond the injection formation was evaluated.
0 .5 1 km
Figure 1 Location of investigation site.
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2. GEOLOGY OF THE INJECTION SYSTEM
The geologic environment of an injection well site controls many aspects of the disposal operation
and the fate of the injected wastes. This section includes a summary of the regional geology and
hydrogeology of the units involved with the deep-well injection operation. The geologic setting is
described within the context of the regional geology to show regional trends and the degree of
uniformity in geologic conditions.
Only those aspects of geology pertinent to underground injection are described. The major em-
phasis is on the hydrogeology of the confining units and the injection interval, specifically, the
hydrogeology of the upper confining unit (New Albany Group), the lower confining unit (Ma-
quoketa Group), and the injection interval (Hunton Supergroup). The Borden Siltstone, which
overlies the New Albany Group, acts as an additional confining zone.
Overview of Geologic Conditions Affecting Waste Injection
The principal geologic factors for the regional evaluation are those affecting (1) the capacity of
geologic units in the injection system to accept and confine injected waste, (2) the chemical inter-
action of the waste with injection system components, (3) the generation of dislocations that
developed during the forming of structural features or seismic events, and (4) the use of subsur-
face space and commercial grade resources in the area of disposal influence.
In this section we have focused on the broader regional issues that relate to local geologic condi-
tions. Broadly defined lithologic units form a key component of the regional discussion. These
units have been described in the literature, and the uniformity of their general geologic conditions
and structural trends have been established by oil, gas, water, and mineral resource exploration
activities in the region.
The character and trends of the regional geology have been determined from data gathered from
key well records, reports, and publications. This information reveals the distribution of aquifers
that meet regulatory requirements for Class i injection, i.e., aquifers that contain saline water
(>10,000 mg/L total dissolved solids [TDS]) and that have confining intervals capable of protect-
ing all USDW from contamination by injection activities. Injection is limited to selected aquifers in
the southern two-thirds of Illinois, including the Hunton Supergroup and the Salem Limestone,
which have been used for disposal at the study site. Injection system response to waste injection
is primarily controlled by porosity and permeability characteristics, which can be directly related
regionally to specific geologic units.
Porosity and permeability develop during sedimentation processes and are modified by other
geologic processes. Thus porosity and permeability have a general relationship with specific
lithologies. Each geologic unit in the region exhibits a range of values and areal trends. The
sedimentary geologic units in east-central Illinois exhibit relatively uniform characteristics over
large areas; however, both vertical and radial trends are noted within each unit. Similar patterns
can also be expected within the subdivisions of each unit, but determining this would require a
detailed study of subsurface records.
The lithology of the geologic units forming the injection system plays an important role in the
chemical interaction between the injected waste and injection system. Chemical interaction be-
tween injected waste and the injection system can affect flow conditions (porosity and per-
meability) and under certain disposal conditions can compromise the integrity of the confining
intervals. However, beneficial interactions may also occur that would improve flow conditions, in-
volve retention of some waste components near the well, and provide treatment for selected, un-
desirable components in the waste.
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This discussion focuses on the general regional characteristics of principal geologic units and re-
lates these characteristics to hydrogeologic parameters for characterizing flow in the injection sys-
tem. An effective evaluation by numerical modeling requires that the hydrogeologic character of
the geologic units accepting and retaining injected waste be predictable and relatively uniform
throughout the area influenced by injection. A more detailed description of the character and
radial uniformity of the units in the injection system is presented in chapter 3.
General Geologic Setting
The geologic framework of Illinois in which deep-well disposal is practiced can be described as a
sequence of areally extensive sedimentary rock units deposited in a large midcontinent basin
known as the Illinois Basin. The study site, in the east-central part of the basin, is immediately
east of the axis of the Marshall-Sidell Syncline and about 14 miles east of the La Salle Anticlinal
Belt, the most dominant structural feature in the area. Figure 2 shows the generalized geology of
the bedrock surface in Illinois. Generalized geologic cross sections of Illinois are depicted in fig-
ure 3. Figure 4 provides a generalized geologic column and comments on the stratigraphy, lithol-
ogy, hydrogeology, and groundwater geochemistry of the geologic units associated with or
protected from waste injection. Additional details on geologic units covered in this report are avail-
able in the Handbook for Illinois Stratigraphy (Willman et al. 1975), the Bibliography of Illinois
Geology (Willman et al. 1968) and reports prepared by Brower et al. (1989), Cluff et al. (1981),
Gray et al. (1979), and Piskin and Bergstrom (1975).
In Illinois, lithologies range from very fine- to coarse-grained elastics, a variety of carbonates, and
a few evaporites and organics. Relatively uniform lithologic characteristics exist on a regional
basis within individual units as a whole and within the subdivisions of each unit.
Many processes have been involved in forming, altering, and structurally readjusting these units
from the time of deposition to the present day. Sedimentary deposition began early in the
Paleozoic Era on the eroded surface of igneous and metamorphic rock of the Precambrian base-
ment complex. Deposition and some erosion continued throughout the Paleozoic. Several
episodes of deposition in the Mesozoic and Cenozoic Eras produced nonlithified sedimentary
units. The present-day landscape has developed principally on these nonlithified sediments.
Marine carbonate and clastic lithologies are dominant in the Paleozoic units, but terrestrial elas-
tics and some organic deposits are present in the upper part of the Paleozoic (Mississippian and
Pennsylvanian Systems).
The thickness of the sedimentary sequence in Illinois ranges from approximately 2,000 feet
northwest of Rockford to more than 20,000 feet in the southeastern corner of the state, the
deepest part of the Illinois Basin (Sargent and Buschbach 1985). In the project area, the total
thickness of the sedimentary units is approximately 8,500 feet. Lithologies include dolomite, lime-
stone, sandstone, siltstone, shale, and some coal and evaporite. The stratigraphic column in
figure 4 provides a summary of the typical sedimentary sequence in the Illinois Basin.
Widespread carbonate lithologies are dominant in the lower part of the Paleozoic, and a few
sandstones and some shales are interbedded with these carbonates. Most of the carbonates be-
come sandy to the north, and a few grade into sandstones in the far northern part of the state.
Greater variations in regional lithology exist in the upper part of the Devonian through the middle
part of the Mississippian. Cyclic deposits of fine-grained elastics (shales and siltstones), some car-
bonates, and some coarse-grained elastics (sandstones) accumulated in the upper part of the
Mississippian and in all of the Pennsylvanian as numerous sea-level oscillations shifted
shorelines across shallow-marine and flat-lowland terrestrial environments.
The study site is in the Marshall-Sidell Syncline (see fig. 5), a broad structural feature of low relief
between the La Salle Anticlinal Belt, about 14 miles to the west, and the Kankakee Arch more
than 90 miles to the northeast. These two structures are reflected in the distribution of the
boundaries of the geologic units exposed at the bedrock surface (fig. 2). The regional dip of the
units in the study area is to the southwest from the Kankakee Arch and into the Illinois Basin, but
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nr
40
40
_L.
60 Mi
-H
90 km
Pleistocene and
Pi ocene not shown
TERITIARY
CRETACEOUS
PENNSYLVANIAN
Bond and Mattoon Formafi
includes narrow belts of
oider formations along
LaSalle Anticline
PENNSYLVANIAN
Carbondale and Modesto Formations
PENNSYLVANIAN
Caseyville, Abbott, and Spoon
Formations
MISSISSIPPI
Includes Devonian in
Hardin County
DEVONIAN
Includes Silurian in Douglas.
Champaign, and western
Rock Island Counties
_URIAN
includes Ordovician and Devonian in Calhoun.
Greene, and Jersey Counties
ORDOVICiAN
CAMBRIAN
& Des Planes Disturbance—Ordovician to Pennsyivaman
Fault
[11
[H
Study area
Figure 2 Generalized area! geology of the bedrock surface (from Willman and Frye 1970).
boundaries of the geologic units exposed at the bedrock surface (fig. 2). The regional dip of the
units in the study area is to the southwest from the Kankakee Arch and into the Illinois Basin, but
locally the units dip gently in a south-to-southwesterly direction toward the axial trend of the Mar-
shall-Sidell Syncline.
Waste Injection Potential In Illinois
Some sequences of Paleozoic units possess sufficient porosity, permeability, and confinement to
accept and retain wastes injected at moderate to high injection rates. Criteria for acceptable injec-
5
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Rock Island
B
Elev.
(ft)
Mocnence
B'
-2000-1-
PENN 0Ev PENN
La Salle
Q PENN Q
' PENN j
£ f —^SILURIAN
SILURIAN
. ORDOV1CIAN
ORDOVICIAN
i
CAMBRIAN
Q - Quaternary T - Tertiary PENN - Pennsylvanian
K - Cretaceous S - Silurian DEV - Devonian
100 mi
i—
50
100 km
Figure 3 Generalized statewide cross sections of Illinois (from Willman et al. 1975).
6
-------
Protection Act (Title 35, Illinois Administrative Code). Within Illinois, the base of the USDW ranges
in depth from 500 to slightly more than 3,000 feet. All units below the lowermost USDW contain
groundwater with a TDS content exceeding 10,000 mg/L (milligrams/liter). Injection is feasible
only in portions of Cambrian through basal Pennsylvanian units that meet the criteria for waste in-
jection established in the Illinois Environmental Protection Act.
In the study area, the base of the USDW has been established at a depth of about 500 feet (Pis-
kin 1986). In the immediate vicinity of the study site, significant injection potential for the Salem
and Hunton carbonate units has been proved by oil exploration and waste-injection testing con-
ducted to a depth of 6,000 feet. Recently, injection has been limited to the Devonian portion of the
Hunton. Very limited groundwater supplies have been obtained from the uppermost part of the
Pennsylvanian bedrock. The City of Marshall obtains a moderate to large water supply from a
shallow sand and gravel aquifer in the nearby valley of Big Creek.
Seismic Activity in Illinois
Earthquake waves traveling through earth materials can affect deep-well disposal systems.
Earthquakes are infrequent in Illinois, and most have been low to moderate in magnitude and in-
tensity (fig. 7). Several earthquakes of low-to-moderate magnitude recently occurred in the
vicinity of the Wabash Valley Fault System, which extends northward into Edwards and Wabash
Counties from southeastern Illinois (fig. 5). The largest earthquakes affecting Illinois in recorded
history occurred near New Madrid, Missouri, in 1811 and 1812 (Heigold 1968,1972). Although
faulting is reported in other areas of Illinois, field studies and drilling records available to the Il-
linois State Geological Survey indicate that no faults are mapped at the surface or known to have
occurred in the subsurface in the vicinity of the study area.
The greatest likelihood for major damage from earthquakes exists in 14 southern Illinois counties
(figs. 6 and 7). This region of the state is in Area 3 on the Seismic Risk Map (fig. 6) compiled by
Algermissen (1969). The project site is near the southern margin of Area 1, the area in which the
damage expectancy from potential earthquakes is rated as minor.
Subsurface Resources
Subsurface resources in Illinois exclusive of groundwater resources include mineral deposits,
hydrocarbon deposits, and subsurface storage space. Many of the geologic units containing sub-
surface resources also qualify as potential disposal horizons. The regulations for deep-well dis-
posal require a review of all subsurface resources of commercial value in order to reduce the
potential for conflicts between injection and resource extraction.
Oil and limited natural gas resources have been exploited in numerous permeable units above
the St. Peter Sandstone. Oil production is mainly associated with Mississippian units; however,
significant production has come from other Paleozoic units. The petroleum-producing regions in Il-
linois are confined to the Illinois Basin (fig. 8). Wells drilled for production provide valuable infor-
mation about subsurface conditions; however, if not properly sealed, these wells can be potential
avenues for fluid movement into overlying geologic units.
Oil has been produced in the Weaver Field about 9 miles to the east-southeast of the study area
and in several small fields on the La Salle Anticlinal Belt, more than 14 miles to the west. Ex-
ploratory wells have been drilled throughout the vicinity of the study site; a few of these wells are
within the 2.5-mile area of review of the disposal well. No commercial oil pools have been
reported in the Marshall-Sidell Syncline in the vicinity of the study site.
Coal deposits are more widespread than petroleum deposits in the Pennsylvanian units, and mul-
tiple coal deposits are often found where Pennsylvanian units are present. Although more than 50
potential coal horizons have been found in Illinois, only a few are thick enough for commercial
development. The coals in the project area tend to be relatively thin and deeply buried. Most coal
deposits mined in Illinois are shallow (less than 500 ft) and lie within units designated as USDW.
7
-------
00
Rock Units and Their Hydrogeologic Roles
Southern Illinois
Geologic Column
Hydrogeologic Description
Formation
Member
SYS.SER.
Thickness
Feet
Group
Glacial drift, loess,
and alluvial deposits
pl
"Lafayette" Gravel
Porters Creek Clay
Clayton Fm.
Ow! Creek Fm.
McNairy Sand
Tuscaloosa Gravel
Greenup Ls.
I l i I ,_|| Shumway La.
Mattoon Fm.
:i i11 ' i
rrffi:
Omega La
Milleraville La.
Skoal Creek Le.
No. 8 Coal
Modesto Fm.
xxxxxxxx
I'iasa Ls.
No. 7 Coal
x x xxx
mWrn:
No. 6 Coal
Carbondale Fm.
No. 6 Coal
5-10
0-10
200-400
Confining Bed/Aquifer: Quaternary —
unconsolidated deposits; glacial pebbly clay
(till), silt, clay, loess, sand and gravel; alluvial
silt, sand, and gravel; major source of drink-
ing water with larger yields from sands and
gravels along present-day streams and in
buried bedrock valleys; well yields are
variable to more than 2,000 gpm; a few
inches to more than 400 ft thick; tills and
clays from uppermost confining interval.
Aquifer: Cretaceous-Tertiary — sands,
clays, silts, and some gravels; aggregate
maximum thickness of 900 ft; occurrence
limited to southern tip of Illinois; McNairy and
Tuscaloosa Formations are the most produc-
tive; local drinking water source with yields
up to 1,000 gpm.
Confining Bed/Aquifer: Pennsylvanian —
mainly shale, with some sandstone, silt-
stone, and coal; maximum thickness of 2,500
ft; forms the bedrock surface in most of the
area; sandstone in upper few hundred feet
constitutes a source of drinking water;
commonly yields less than 10-15 gpm locally
near outcrop area in southwest; yields of
50-100 gpm are possible; water is highly
mineralized below depth of about 500 ft.
Geologic Column
Hydrogeologic Description
Formation
Member
SYS. SER.
Thickness
Feet
Group
Yankectown Ss.
Renault Ls.
Aux Vases Ss.
Ste. Genevieve L.s,
Fort Payne Fm.
Borden Sts.-
Springville Sh.
-Carper sand
^Chouteau Ls.
IHannibal-
Saverton Sh.
Grassy Creek Sh.
-m^w
Sweetland Creek Sh. ?
z
Alto-Blocher Sh.
Lingle Ls.
Grand Tower Ls,
1Q-SQ
¦0-50*
' 1-50'
0-110
0-100
Aquifer/Confining Bed: Valmeyeran —
predominantly limestones with some sand-
stones, siltstones, shales, and dolomites;
underlies most of central and southern Illi-
nois; thin in west, more than 800 ft thick in
north-central part of region, and more than
1,800 ft thick in southeastern Illinois;
constitutes a drinking water source in outcrop
areas in western part and southern margin
of the state; variable yields, typically less
than 30 gpm but locally up to 1,800 gpm;
highly mineralized at depth away from out-
crop area.
Confining Bed: New Albany—black, gray,
and green shale; covers almost entire
southern half of the state; over 300 ft thick.
-------
(continued from previous page)
DeKoven Coal
Davit Coal
Spoon Frr
Curlew Ls.
Murray Bivff St.
Abbott Fm.
Grindstaff S*.
Caseyville Fm,
Battery fiock St.
Lusk Sh.
Grove Church Sh.
Palestine Ss.
Menard Ls.
Waltersburg Frn.
I Vienna Ls.
35-80
0-15
Tar Springs Ss.
30-150
Glen Dean Ls.
Hardinsburg Ss.
10-70
15-180
Haney Ls.
TS
c
10-80
Fraiieys Sh.
IBeeeh Crot'k Ls,
V
©
O
50-100
2-25
Cypress Ss.
30-160
r&L—-2y \/c
| V 'l
Kidenhower Fm.
t Bethel Sr.
Downeys Bluff Ls
0-600
40-100
50-110
30-140
30-150
5-120
5-30
Alternating Sequence of Confining
Beds/Aquifers: Chesterlan—limestone-
shale alternates with sandstone-shale;
underlies much of the southern half of
Illinois; thickness southward to more than
1,400 ft in southern part of Illinois Basin;
some limestones and especially sand-
stones constitute sources of drinking water
in outcrop areas along the perimeter of the
Illinois Basin; commonly yields less than
25 gpm; at depth away from outcrop areas,
water is highly mineralized.
(continued in right column of previous page)
Figure 4 Description of rock units and their hydrogeologic roles (Brower at al 1989).
(continued from previous page)
I * 7*
_ Dutch Creek Ss
Clear Creek Cherl
Backbone Ls.
& / & 6 Grassy Knob Chert
^4-
- ' 1 1 V I
Bailey Ls.
Moccasin Springs Ls.
St, Clair Ls.
Sexton Creek Ls.
Llwood-Wilhelmi Frr
Girardeau I,!..
Brainard Sh.
_Fort Atkinson Ls.
Thebes Ss
Scale* Sh.
_LL
^TtTT~
Dunlpith Km
Guttenberg Ini
Kin^s Lake Ln
"Spocnn Ferry Hr.
Quimbys Mill I'm
TT
Grand Detour f-v
Xx
7T1
30-150
250-450
15-80
0-60
0-4fi
0-150
0-50
50-1 50
0-20
0-50
0-20
0-15
0-16
15-35
Aquifer: Silurian-Devonian (Hunton
Supergroup)—predominantly limestone
with dolomite, siltstone, shale and chert;
thickness of 200 ft in the west to more than
1,800 ft in the southeast part of the region;
constitutes drinking water source from frac-
tured limestones in outcrop areas; Devonian
cherts are sources for small to moderate sup-
plies in southern and western parts of the
region; well yields range from moderate to
maximum of 300 gpm; away from outcrop
areas units are highly mineralized.
Confining Bed: Maquoketa — mainly
shale, some limestone and sandstone; un-
derlies almost all of southern Illinois; more
than 300 ft thick along eastern margin of
state.
Aquifer/Confining Bed: Galena-Plattevllle
— dominantly limestone, some dolomite,
shales and cherts; a possible source of
drinking water where these units form upper
bedrock along the western-southwestern
boundary of Illinois; thickness increases
southward to a maximum of about 725 ft in
southeastern part of region; away from out-
crop area this sequence contains highly
mineralized water.
D'j'chtown Ls.
0-200
65-300
Aquifer/Confining Bed: Joachlm-Dutch-
town-St. Peter (Ancell Group)—- dolomite,
limestone, sandstone with a few anhydrite or
gypsum deposits; underlies southern half of
Illinois; reaches maximum thickness of 700
ft in the southern tip of the region; St. Peter
thins southward as carbonate units become
thicker; constitutes a limited source of
drinking water in extreme western Illinois.
-------
,
-------
Figure 6 Seismic risk map for Illinois (after Algermissen 1969).
Other mineral resources, including building stone, agricultural lime, clay, sand, sand and gravel,
metals, fluorite, barite, and tripoli, have been mined commercially throughout Illinois (Samson
1983,1989). Most of the mining operations are at or near the land surface. Only limited surface
mining (for aggregate and stone) has been done near the study area, and apparently neither the
mining nor the injection operations have affected each other.
Natural gas storage fields in aquifers having localized structural closure features are scattered
throughout the state. Three storage fields are located about 10 miles north and northeast of the
study site (fig. 9). Aquifers of sandstone and limestone strata of Cambrian through Pennsylvanian
age have been used for storage. Drilling and testing records from the Nevins, State Line, and
Elbridge storage facilities have provided much useful information about subsurface geologic and
11
-------
-------
-------
hydrogeologic conditions at the study site. Injection activities in the nearby natural gas storage
fields and at the study site do not appear to affect each other significantly, although both utilize
the same units of the Hunton.
Regional Geology and Hydrogeology
The units that are part of the injection system and are penetrated by the disposal well include the
basal confining interval (Maquoketa Group), the injection interval (Hunton carbonate sequence),
and the upper confining interval (New Albany shale sequence). Additional impermeable units and
some aquifers lie between the upper confining interval and land surface. The first significant
aquifer above the injection interval is the Salem Limestone.
Waste Disposal Well 2 (WDW2) was originally drilled to 6,000 feet (Eminence-Potosi Dolomites).
It was plugged back into the uppermost unit of the Silurian limestone part of the Hunton because
the immediately overlying Devonian limestone was the deepest, most receptive injection interval
available.
Ordovician System
Ordovician strata (fig. 4) range in thickness from 700 feet (in northern Illinois) to more than 6,000
feet (in southern Illinois). The thickness increases gradually toward the south. Dolomites and lime-
stones are the predominant lithologies; however, several distinct sandstones are found in the
lower (Gunter and New Richmond Sandstones) and middle (St. Peter Sandstone) parts of the Or-
dovician. A thick shale-shaly carbonate sequence (Maquoketa Group) forms the upper part of the
Ordovician. Many of the units below the Maquoketa are relatively impermeable and act as
aquitards. The St. Peter Sandstone, a thin (50-ft), fine-grained, low-permeability sandstone in
Clark County, is the first significant aquifer below the Hunton injection interval.
Maquoketa Group (Lower Confining Unit)
The Maquoketa Group (fig. 4) consists of two shale units and an interbedded shaly limestone-
dolomite unit. The thickness of the Maquoketa ranges from approximately 150 feet in the western
part of the state, where the top is eroded, to nearly 300 feet along the eastern edge of the state
(fig. 10). In the vicinity of Marshall, the Maquoketa is less than 300 feet thick.
Hydroiogic Characteristics of the Ordovician System
In northern Illinois, carbonate units of the Ordovician that are at or near land surface have
moderate to relatively low permeabilities. As the burial depth of these units increases toward the
south, the permeabilities of the units generally decrease. Carbonate units lying below freshwater
zones (groundwater with less than 10,000 mg/L TDS) are essentially aquitards. Figure 11 shows
the basal position of USDW in a north-south cross section from Rockford to Cairo. The southward-
pointing tongue of USDW in the Ordovician lies in the St. Peter Sandstone. The TDS level of the
St. Peter in the Marshall area is greater than 50,000 mg/L (Meents 1952).
Porosities in carbonate units in the southern half of the state are generally less than 10 percent;
permeabilities in the more permeable units rarely exceed 1 to 30 millidarcys (Ford et al. 1981,
Mast 1967). Porosities and permeabilities across vertical sections of the St. Peter are quite varia-
ble. The more permeable horizons measured in northern Illinois had porosities ranging from 12 to
17 percent and permeabilities ranging from 25 to 250 millidarcys. In the south, where the St. Pe-
ter is thinner, finer-grained, and more shaly, porosity and permeability values can be expected to
be smaller. The shale units in the Maquoketa Group are expected to be very tight (<1 millidarcy).
Hunton Supergroup (Injection Interval)
The limestone and dolomite units of the Silurian and Devonian Systems have similar lithologic
and hydrogeologic characteristics and thus are considered one large unit, the Hunton Super-
group. The thickness of the Hunton ranges from a featheredge along the Mississippi River to
more than 1,800 feet near the southern tip of the state. Figure 12 shows the thickness and dis-
14
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~/I Waukegan
Chicago
# Brocton
Nevins
> ^Elbridge
Ashmorei
Study area
Waterloo
— Major gas pipelines
~ City
• Active storage project
O Abandoned storage project
o
h-r-
20
T
0 20 40 k
40 mi
H
Figure 9 Location of underground gas storage projects in Illinois (after Buschbach and Bond 1974).
15
-------
qO^ Isopach
interval 50 ft
Outcrop area
Maquoketa overlain
unconformably by Devonian
Mississippian, or Pennsylvanian
r i—r
0 20 40 km
40 mi
4 1
Study area
Figure 10 Generalized thickness and distribution of the Maquoketa Group (after Willman et al. 1975).
16
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A
A'
Cairo Centralis Decatur La Salle Rockford
ILi
g -4000
c -2000
o
-6000
0
¦Study area
Boundary between USDW and
aquifers with groundwater
containing > 10,000 rng/L TDS
Figure 11 Cross section from Cairo to Rockford (see fig. 3) showing the position of base of the USDW
(Brower et al. 1989).
tribution of this unit. Note that erosion has truncated the Hunton in a large area in the northern
third of the state. Near the project site the Hunton is about 800 feet; its upper 350 feet includes
units of the Devonian System.
Silurian Part of Hunton Supergroup
The Silurian consists of Alexandrian (lower part) and Niagaran (middle part) units and thickens
eastward from an erosional featheredge in western Illinois to more than 700 feet in the east-
central part of the state. In places, pinnacle reefs may increase the thickness to 1,000 feet. Units
of the Cayugan (upper part) are thin or missing in Illinois. The Niagaran, the principal unit of the
Silurian, consists of three dominant carbonate fades: shaly dolomite in the south, intermediate-
purity carbonate in the north-central and northeast, and relatively high-purity carbonate in the
northwest. Reefs are found throughout the Silurian units, and those in the southern part of the
state (particularly in the southwestern part) may be oil-bearing (Wh'rtaker 1988).
The uppermost Silurian unit in the study area is the Moccasin Springs Formation (fig. 4). The Moc-
casin Springs consists mostly of red (or red-and-gray-mottled), very silty, argillaceous limestone
and calcareous siltstone; shale is common near the top. The Moccasin Springs contains
numerous reefs, dominantly limestone, which have well-defined flank structures. The Moccasin
Springs is commonly 160 to 200 feet thick and is more than 160 feet thick in the study area.
Devonian Part of the Hunton Supergroup
The Devonian part of the Hunton is composed of a basal sequence of four cherty limestones (in-
cluding the Bailey Limestone) and an upper sequence of two limestones (the Grand Tower Lime-
stone and the Lingle Formation). The Bailey Limestone is a silty, cherty, thin-bedded, hard
limestone that begins along a southwesterly trending featheredge in central Illinois. Southeast of
Marshall, additional cherty carbonate units were successively deposited above the Bailey. The
combined thickness of these units reaches 1,200 feet in the southern part of the state. The Bailey
is 144 feet thick in the Marshall area. The overlying Grand Tower Limestone and Lingle Formation
begin along a southwesterly trending featheredge 75 miles northwest of Marshall and thicken
southward to more than 400 feet in Gallatin County. Near Marshall, these two units have a total
thickness of 96 feet; the Lingle is 22 feet thick.
17
-------
Hydrogeology of the Hunton Supergroup
Fresh water is found at or near the surface in the Hunton in the northern half of the state and
along the margins of the Illinois Basin. Well yields vary, depending mostly on the degree of frac-
ture development. Variations in primary porosity and permeability can be related to lithology,
which exerts some control on the degree of fracture development. Fracture development is
greatest near the surface and generally decreases as depth of burial increases, particularly where
the Hunton is overlain by impermeable shale units of the New Albany and Pennsylvanian.
The boundary marking the base of USDW in the Hunton is shown in figure 12. Typically,
groundwater mineralization increases rapidly southward from this boundary. However, in Clark
County the rate of increase in the TDS of the brine is relatively lower southwest of the USDW
boundary, resulting in a TDS content of approximately 16,000 mg/L in the permeable Devonian
units. Increased groundwater circulation in units with higher permeabilities allows less mineralized
water to advance greater distances downdip (Brower et al. 1989). Other examples of this
phenomenon are shown in figure 11; tongues of fresher water in the St. Peter Sandstone (Or-
dovician), the Ironton-Galesville Sandstone (Cambrian), and in certain shallow units (Silurian
through basal Pennsylvanian near Cairo) move downdip into the Illinois Basin (Student et al.
1981). In the deeper parts of the basin, the mineral content of groundwater in the Hunton may
reach from 150,000 to more than 200,000 mg/L TDS (Graf et al. 1966).
Drilling records and testing for the region show that the Lingle, portions of the Grand Tower, and a
major part of the Silurian are relatively tight. The Bailey and several horizons in the Grand Tower
and the Silurian have significant zones of permeability. Selected intervals of higher permeability in
the Bailey have been used for disposal at the study site.
Figure 12 Generalized thickness and distribution of the Hunton Supergroup (after Willman et al. 1975) and
the TDS boundary for USDW (Brower et al. 1989).
Study area
18
-------
Porosity and permeability data obtained from tests run on samples collected from oil exploratory
and gas storage wells scattered around the state show a mean porosity of 13 percent and a
mean permeability of 40 millidarcys (Mast 1967). These data included values obtained from units
in the Galena Group. Ford et al. (1981) reported porosity values of 12 to 19.5 percent and per-
meability values of 50 to 300 millidarcys for 269 wells completed in Devonian carbonate reser-
voirs of Illinois.
Evaluation of geophysical logs and sample cuttings conducted during the course of this study and
for related studies of the disposal wells indicated that discrete, areally extensive horizons having
high, moderate, and low permeabilities occur in the Bailey. Pore sizes range from 5 microns (|j.m)
to over 300 (average range, 10 to 25 n.m), and the pores have a fair degree of interconnection.
New Albany Group
Sedimentation during Late Devonian and Kinderhookian (Mississippian) time produced
widespread accumulation of black, gray, and green shales and some limestones and siltstones.
The rock units that accumulated during this time attained a total thickness of 100 to 450 feet
through central and southeastern Illinois (fig. 13). Cluff et al. (1981) identified three formations
present in east-central Illinois. The Blocher Shale, the basal unit, appears several miles west of
the study area and thickens toward the southeast. The Blocher consists of calcareous-to-
dolomitic, pyritic shale that is rich in organic matter. The Blocher is overlain with the Sweetland
Creek Shale, which thickens from about 50 feet at an erosional cutoff in the central part of the
state to more than 350 feet in Hardin County in southern Illinois. The Sweetland Creek is dark
gray (in some places, green) and has poorly developed, laminated bedding. The unit is similar in
Figure 13 Generalized thickness and distribution of the New Albany Group (after Cluff et al. 1981).
I I outcrop (may be covered by unconsolidated sediments)
ESMil subcrop beneath Pennsylvanian strata
-100- thickness line; interval 50 ft
limit of New Albany
19
-------
appearance to both the Blocher and the overlying Hannibal Shale, but has widely traceable key
beds. The overlying Hannibal Shale or its equivalent is less than 10 feet thick and indistinctly
bedded. These formations are not differentiated at the study site.
Hydrogeology of the New Albany Group
The units of this group are very tight and therefore serve as an upper confining interval for the
Hunton Supergroup. Natural gas storage fields completed in the Hunton utilize the low porosity
and very low permeability of these units to retain gas in the underlying storage reservoirs
(Buschbach and Bond 1974). The shale units in this group have essentially no water- or oil-yield-
ing potential.
Mississlppian Units
Mississippian units cover the southern two-thirds of the state and reach a maximum thickness of
3,300 feet in Williamson and Saline Counties (fig. 14). The widespread, thin, irregularly bedded
Chouteau Limestone (Buschbach 1952) rests on the top of the New Albany and marks the base
of three simultaneously deposited units: (1) the deltaic, tongue-shaped Borden Siltstone trending
southwesterly across the state from the west-central part of Indiana; (2) the Burlington-Keokuk
Limestones to the northwest; and (3) the Fort Payne Formation and Ullin Limestone to the
southeast. The Borden consists of siltstone, some silty shale, and a few beds of fine sandstone
and coarse siltstone. The "Carper sand" is present in places near the base of the Borden. The
Ullin or its equivalent overlaps the top of the Borden with 150 feet of limestone and some shale in
the Marshall area. Widespread limestone units, including the Salem, St. Louis, and Ste.
Genevieve Limestones, accumulated between the Borden and the overlying alternating sequen-
ces of shale-limestone and shale-sandstone units that were deposited during Chesterian time.
The Mississippian section above the Chouteau is approximately 1,200 feet thick in the Marshall
area and includes 450 feet of Borden Siltstone. The "Carper sand" is approximately 20 feet thick
and lies very near the base of the Borden.
Hydrogeologic Conditions in the Mississippian
Mississippian units are used extensively for small (and some moderate) water supplies in and
near outcrop areas. Most wells are finished at shallow depths, typically less than 300 to 500 feet.
Groundwater mineralization increases rapidly with increasing depth of burial and in a down-dip
direction toward the Illinois Basin (Meents 1952).
The Borden Siltstone is a thick unit of very low-permeability material that provides confinement in
addition to the New Albany Group, the primary confining unit of the Hunton injection interval. The
"Carper sand" provides the first somewhat permeable horizon above the top of the Hunton.
Several thin, fine-grained sandstones also lie near the top of the Borden. Available porosity logs
suggest that porosities of about 8 to 12 percent can be expected in these sandstones. At the
study site, the Salem Limestone is the first overlying aquifer having significant permeability; it has
been used for waste injection in the past. The measured static water level in the Salem is about
50 feet lower than the water level in the Bailey. The mineral content of the Salem and the Bailey
in the Marshall area is similar (about 15,000 to 16,000 mg/LTDS). The groundwater in these units
has an anomalously low mineral content, which appears to be related to the relatively high
porosity and permeability of these units. Figures 12 and 14 show the location of the USDW bound-
ary in Hunton and Mississippian units. The less permeable units of the Mississippian, particularly
those in the upper part, contain groundwater with a much higher mineral content.
Pennsyivanian Units
The bedrock surface in the southern two-thirds of the state has been formed on Pennsyivanian
units. Shale and clay units (more than 50% of the total thickness), sandstones and siltstones
(more than 25%), limestones (less than 10%), and coals comprise more than 500 distinguishable
units. Pennsyivanian strata reach a maximum thickness of 2,500 feet in the south-central part of
the basin. Sandstones are interbedded with the shale throughout the Pennsyivanian but are most
20
-------
»Approximate boundary
Of 10,000 mg/L TDS
in Valmeyran
E — Eroded
n0 Isopach interval 200 ft
Outcrop area
jg§iil Top eroded beneath Pennsylvania!
(Cretaceous in south)
o 20 40 mi
I—r—S H—I—' 1
0 20 40 km
Figure 14 Generalized thickness and distribution of the Mississippian System (after Wiilman et al. 1975)
and the TDS boundary for USDW (Brower et al. 1989).
21
-------
abundant in the lower two of seven formations. Limestones are more abundant in the second for-
mation from the top, and the most well-developed coal units are in the middle (fourth) formation.
In the Marshall area, the Pennsylvanian is about 1,050 feet thick. The thicker sandstones are
found near the base of the Pennsylvanian. Coal units are present but thin. The more prominent
coals occur below a depth of 400 feet.
Hydrogeologic Conditions in the Pennsylvanian Units
Fresh water exists in the upper 300 to 500 feet of the Pennsylvanian units and is a principal
source for low-volume water supplies where no potential for supply exists in overlying glacial
deposits. Near the margins of the basal formations, the more permeable sandstones contain
fresh water to depths of more than 1,000 feet. In the Marshall area, mineralization of groundwater
increases rapidly below depths of 50 to 75 feet, and water wells rarely penetrate to depths below
100 to 200 feet. The base of USDW is estimated from geophysical logs to lie about 500 feet
below the surface (Piskin 1986).
Sandstones in the upper three-fourths of the Pennsylvanian are thin and widely spaced and yield
very little water. The basal sandstones in the Marshall area may yield up to 20 gpm; however,
water from these sandstones has a very high mineral content (38,000 mg/LTDS) (ISGS UIC files).
Porosity and permeability values measured from cores and wells collected from or finished in all
types of Pennsylvanian units range from 9 to 25 percent and 10 to 10,000 millidarcys (Ford et al.
1981). Porosities measured in oil-producing sandstones are relatively uniform, averaging 17 to 20
percent (Whiting et al. 1964). Whiting also reported permeabilities of 100 to 400 millidarcys, which
decrease as depth of burial increases.
Quaternary System
Glacial deposits consisting of loess, silt, clay, till, sand, and gravel cover a large part of the
bedrock surface of Illinois. In the Marshall area, the drift is less than 10 to 50 feet thick in the
upland areas and up to 30 to 100 feet thick in the larger stream valleys. Peoria Loess (2 to 6 ft
thick) and Roxana Silt (0 to 3 ft thick) mantle the Glasford Formation (clay, sand, and till, 0 to >21
ft thick) on the upland. The Banner Formation (clay and till 0 to >20 ft) underlies Glasford Forma-
tion till where thicker drift is present in the upland areas (ISGS UIC files 1981). Cahokia Alluvium
(silt, sand, and clay) overlies Henry Formation (outwash sand and gravel up to 70 ft thick) in the
valley of Big Creek. Very limited to small water supplies are available from the upland glacial
deposits. Moderate to large water supplies are available along some segments of Big Creek val-
ley. Marshall obtains its water supply from the Henry Formation, about 2.25 miles east of the
study site.
22
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3. HYDROGEOLOGIC INVESTIGATION OF THE INJECTION SYSTEM
This chapter briefly discusses techniques used to collect and analyze hydrogeologic data. Details
of the techniques and analyses are in appendices A and B. Specifically, stratigraphic correlations
within the injection system from regional (5 to 10 miles) and local (3 miles) perspectives are dis-
cussed, along with methods used to collect additional data from the site of the injection well.
These methods include geophysical logging, sidewall coring and associated analysis, and
hydraulic testing. A hydrogeologic description of the injection system at the site is also given.
Stratigraphic and Structural Definition of the Injection System
The injection system consists of the geologic materials constituting the injection zone and its as-
sociated upper and lower confining units. To evaluate the confining and injection potential for the
Devonian injection system, data were collected from wells in three gas storage fields (Nevins,
Elbridge, and State Line), wells within 5 to 10 miles from the project site, and wells within 3 miles
of the site (see figure 15 and table 1). The gas storage fields are approximately 9 miles northeast
of Velsicol's Waste Disposal Well 2 (WDW2). Data from these wells were used to correlate
hydrogeologic units within the injection system and to construct a structure map of the top of the
Lingle Formation. The injection interval for WDW2 lies within the Devonian limestone sequence,
immediately below the Lingle and Grand Tower Formations.
Each of the three gas storage fields utilizes a domal structure with closure to concentrate and
store the gas. Each domal structure was formed by the deposition of Devonian- and Silurian-age
shelf fades sediments over Silurian-age reef facies sediments.
Although this type of structure is not present in the area immediately surrounding the Velsicol
plant, the general stratigraphic relationship of the rock units near the storage fields and those
near the disposal well was shown to be consistent. Inferences were then made regarding data
from the gas storage fields to the disposal well at Velsicol.
Geophysical logs from wells at a 5- to 10-mile radius from the plant were used to correlate stratig-
raphy and to give a regional picture of the configuration of the injection system. Geophysical logs
from wells within 3 miles of the injection well were used to construct a structure map consistent
with regional data.
Stratigraphic Description of the Injection System
The stratigraphy of the injection system includes the Silurian-age Moccasin Springs Formation at
the base through the Grassy Creek Shale, the uppermost Devonian unit of the New Albany
Group. Figure 16 is a geologic column showing the stratigraphic position and hydrogeologic char-
acteristics of these units at the waste disposal well studied. Much of the strata information is from
Willman et al. (1975). Additional data were obtained forthe Middle Devonian strata from North
(1969) and for the strata of the New Albany Group from Cluff et al. (1981).
The Devonian strata comprise three series—the Lower, Middle, and Upper. The Bailey Lime-
stone, basal unit of the Lower Devonian Series, is dominantly gray to greenish gray, silty, cherty,
thin-bedded, very hard limestone. Some beds are argillaceous. The chert, black to dark gray, oc-
curs in bands up to 2 feet thick. An upper zone, 0 to 100 feet thick, is limestone that is pure,
white, coarsely crystalline, and only slightly cherty.
A major unconformity occurs at the Lower and Middle Devonian interface. The basal formation of
the Middle Devonian Series is the Grand Tower Limestone, which is mostly coarse-grained, light
gray, medium- to thick-bedded, cross-bedded, pure, fossiliferous limestone. It also contains
lithographic limestone, which becomes more abundant upward. One member differentiated at the
study site is the Tioga Bentonite Bed, which is found 10 to 30 feet from the top of the Grand
23
-------
Table 1 Wells used in study
Well No.
Name
Location
3
Richard Lindley #1
29-11N-10W
4
Thomas Coats #2
31-10N-13W
5
C. A. Pence #1
31-10N-13W
6
Burger #1
23-10N-13W
7
H. 0. Coldren #1
4-11N-11W
8
A. Kannmacher #1
24-10N-13W
9
Clifford 1 Morgan, et at. #1
4-11N-11W
10
Gus Birchfiela #1
24-10N-13W
12
Frank Morgan, et. al. #1
19-10N-13W
13
S. M. Scholfield #1
6-11N-11W
14
Birchfield-Shumaker Comm. #1
34-11N-11W
15
Boyd #1
5-11N-14W
17
Smitley #1
7-11N-11W
19
F. Kuhn #1
8-11N-11W
21
D. M. Davison #1
8-11N-11W
23
Eugene Chenowith #1-A
9-11N-11W
25
Alfred Seidel #1
15-10N-11W
26
Russel Higginbottom, et. al. #1
34-10N-12W
27
E. P. Daly #1
8-11N-14W
28
E. F. Newman, et. al. #1
30-10N-13W
29
Ella Mae Young #1
19-10N-13W
30
Ormal Higginbotham #1
22-11N-13W
33
Fraker #1
16-11N-11W
35
Lickert #1
16-11N-11W
36
Guinnip-Keyes Comm. #1
10-11N-12W
37
Southerland Comm. #1
16-11N-11W
39
Southerland #2
16-11N-11W
43
Gunder #1
19-11N-11W
45
Monk #1
21-11N-11W
48
WDW1
12-11N-12W
49
DOW
12-11N-12W
50
Redman #1
5-11N-14W
51
Mary E. Kendall #1
22-11N-11W
52
G. and E. Herrington #1
8-11N-10W
53
Frank Morgan #2
24-10N-14W
54
WDW2
12-11N-12W
55
J. C. Yeley #1
27-12N-11W
56
Elbridge #1 (gas storage)
2-12N-11W
57
Nevins #6 (gas storage)
5-12N-11W
58
State Line #1 (gas storage)
28-12N-10W
61
Hall #1
1-11N-12W
69
Alton Blankenship #1
16-11N-12W
77
Bays #1
21-11N-12W
79
Anna Brosman #1
21-11N-12W
81
Minnie L. Jackson #1
21-11N-12W
85
John W. Dawson #1
22-11N-12W
87
Frahm-Cole-Lee Comm. #1
28-11N-12W
103
Glen Morgan #1
21-11N-12W
111
Waller Comm. #1
21-11N-11W
Tower. The Tioga is a greenish to brownish gray shale that contains biotite flakes and an abun-
dance of silicate minerals that distinguish it from other shales. The Tioga generally is only 1 to 2
inches thick, but it may be 6 to 8 inches thick.
The Lingle Formation overlies the Grand Tower and is more argillaceous, darker, and finer-
grained than the Grand Tower. At the study site, the Lingle is composed of two members, the
Howardton Limestone Member and the Tripp Limestone Member. Howardton, the basal member,
is gray, fine-grained, slightly silty, argillaceous limestone, most of which has thin, shaly partings.
The Tripp is heterogeneous, containing limestone, dolomite, chert, siltstone, and shale. It is large-
ly cherty, argillaceous, silty limestone, but beds of shale are abundant near its base and top.
The New Albany Group overlies the Lingle Formation. The Devonian portion of this group in-
cludes the Blocher, Selmier (Sweetland Creek), and Grassy Creek Shales. These units were not
24
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Figure 15 Well locations. Cross sections for A-A'and B-B'appear in figures 17, 18, and 19.
differentiated at the study site. The Blocher is the basal formation of the New Albany Group and is
a calcareous or dolomitic black shale. The Blocher is the only shale in the New Albany containing
much caicite.
The Selmier Shale Member overlies the Blocher and consists of greenish gray, dolomitic, biotur-
bated mudstone at the top that grades downward through an interbedded zone to black dolomitic
laminated shale at the base. North (1969) placed these same units in the Sweetland Creek Mem-
ber. The Selmier is conformably overlain by the Grassy Creek Shale Member.
The Grassy Creek is the uppermost Devonian unit of the New Albany Group and consists of
brownish black to grayish black, finely laminated, pyritic, carbonaceous shale.
25
-------
WDW2 Gamma Sidewall
Hay Neutron Porosity
{API units)
Figure 16 Geologic column for the injection system at Waste Disposal Well 2 (WDW2).
Geophysical Log Correlations
Figures 17,18, and 19 illustrate the stratigraphic continuity of the hydrogeologic units within the in-
jection system and the base of the New Albany Group within a 10-mile radius of WDW2. Figure
17 shows a southwest-northeast cross section based on resistivity logs, Induction Electric Logs
(IEL), and Electric Logs (EL). Figure 18 is also a southwest-northeast cross section, but it is
based on qualitative permeability log (Minilog) responses. Figure 19 shows a north-south cross
section that is based on resistivity logs. Qualitative permeability logs were not available for all
wells along this cross section.
26
-------
A
Southwest
53
Frank Morgan #2
24-10N-14W
( 992) New Albany Group
A'
Northeast
Frahrn-Cole-Lee Comm P1
28-11N-12W
/ (-1819)
2150 :
] \ #1-Injection zone (unit 4)
EH #Z-lnjection zone (unit 9}
M #3-lnjection zone {unit 11)
2400 depth below surface
(-1773) elevation equivalent
to mean sea level
Figure 17 Stratigraphic correlation utilizing resistivity logs for southwest-northeast cross section.
-------
A A?
Southwest Northeast
57
53 87 54 Nevins #6
Frank Morgan #2 Frahm-Cole-Lee Comm. #1 WDW2 5-12N-11W
24 10N-14W 28-11N-12W 12-11N-12W M318)
Figure 18 Qualitative permeability correlation utilizing permeability indicator logs for southwest-northeast
cross section.
-------
B B'
North South
57 54 26
Nevins #6 WDW2 Russei Higginbotom et al. #1
5-12N-11W 12-11N-12W 34-«>hM2W
Figure 19 Stratigraphic correlation utilizing resistivity logs for north-south cross section.
-------
The data presented in figures 17 and 19 show the hydrogeologic units within the injection system
to be laterally continuous across the study area with one exception. Likewise, the continuity of the
qualitative permeability of these units is inferred from figure 18, On the basis of resistivity and
qualitative permeability logs, injection zone no. 2 could not be differentiated from the overlying
unit in some wells in the study area. These unit designations are not included in these cross sec-
tions.
Nevertheless, the stratigraphic and qualitative permeability continuity of the Devonian limestone
and the New Albany shale between the wells at Velsicol and the wells in the gas storage fields
can be inferred; thus, continuity of quantitative permeability can be inferred. Analysis of core
retrieved from WDW2 provided quantitative permeability data for the various hydrogeologic units.
The quantitative permeability data obtained from wells at the three gas storage field wells are
summarized later in this chapter (see Hydrogeology of the Site, p. 40).
A structure map of the top of the Lingle Formation was constructed (fig. 20) using information
from wells within a 3-mile radius of Velsicol.
Stratigraphic and Structural Characterization
On the basis of correlations between the disposal well at Velsicol and the wells within a 5- to 10-
mile radius of the plant, both the upper and lower confining units and the injection zones appear
to be continuous across the study area. Although information about the thickness of the lower con-
fining unit is limited, figures 17,18, and 19 clearly show its stratigraphic location.
The analysis of available geophysical logs for regional hydrogeology of the injection system is
summarized in figure 21. A confining unit is distinguished from an "impermeable" unit by its posi-
tion with respect to the permeable units. Confining units lie directly above the uppermost perme-
Figure 20 Structure contour map of the top of the Lingle Formation in the vicinity of the Velsicol plant.
30
-------
able unit or directly below the lowermost permeable unit; impermeable units lie between perme-
able units. For permitting purposes, the upper confining unit includes the base of the New
Albany shale and 26 feet of the Lingle Formation and Grand Tower Formation. Thickness varia-
tions for this section of the upper Devonian limestone are limited to about ±8 feet over the 10-mile
region of investigation. In terms of the hydraulic confinement of the injection interval, the upper
confining unit is composed of Grand Tower Limestone. Its thickness is approximately 74 feet at
WDW2.
For permitting purposes, the Maquoketa shale is considered the lower confining unit. In terms of
hydraulic confinement, the lower confining unit consists of the Moccasin Springs Limestone. Its
total thickness could not be determined in this study because of limited data, but it is at least 160
feet thick at WDW2, based on available geophysical log data.
It is evident from figure 20 that the structure in the Velsicol plant area is generally flat with a
gradual inclination of about 25 feet/mile to the northeast.
2300
New Albany Group
Lingle
Grand Tower
Bailey Limestone
Moccasin Springs Fm
2700
Figure 21 Injection system in
WDW2 indicating permeable and
impermeable zones delineated with
available geophysical logging.
confining unit
[X;XJ impermeable unit
^ permeable unit
31
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Determination of Horizontal Hydraulic Gradient
If the horizontal gradient is to be properly calculated, the hydraulic head within the injection sys-
tem must be known for various locations. The initial reservoir pressure, obtainable from drill stem
tests (DSTs), would be an excellent source of data. For initial reservoir pressure calculations, the
pressure versus time chart from the DST is needed. This chart, however, was not available for
wells in this area. Final flow and final closed-in pressures, as well as static water levels, were
used to calculate the horizontal gradient. According to limited, high-quality data, the greatest
horizontal gradient existed between wells 54 (WDW2) and 57. The hydraulic gradient (dh/dl) has
a magnitude of 3.5x1 CT4 in a general direction of north to south.
Field Investigations
Two phases of geophysical logging were performed at the Velsicol site. During phase I, data on
porosity and qualitative permeability, stratigraphic orientation, and the lithology of the rock units
within the disposal zone were obtained from the Devonian Observation Well (DOW), Well 49.
Data reduction indicated the units most favorable for fluid infiltration. Phase II was a detailed
study based on information obtained from phase I. Results from phase II included quantitative
data on permeability (air and water), bulk compressibility, hydraulic conductivity, specific dis-
charge, and specific storage of the injection horizon. Those units with the greatest injection poten-
tial were further characterized for thickness, storativity, and transmissivity. In addition, hydraulic
testing (flowmeter and injection testing) of the injection system was conducted.
Phase I Investigations
Records (well logs, drilling records, and other data) provided a general overview of the structure
and regional continuity of stratigraphic units particularly important to waste injection and confine-
ment. These data, however, were only one aspect of the overall integrated approach used to char-
acterize the injection system. Additional data were needed to precisely define the character of
possible confining and injection intervals. The methods and techniques used to characterize the
disposal zone are discussed briefly and considered in detail in appendix A.
Existing geophysical logs. After a review of the historical records, a preliminary estimate was
made of the stratigraphic location of the potential confining units (upper and lower) and the imper-
meable units associated with the operational waste disposal well (WDW2). These hydrogeologic
units were delineated using four principal downhole geophysical logs, which were run during ini-
tial well (WDW2) construction in 1971. The logs were the Sidewall Neutron Log (SNL), Induction
Electric Log (IEL), Gamma Ray Log (GRL), and Microlog (MIL). The hydrogeologic units deter-
mined from analysis of these logs are presented in figure 22. Consideration of all four logs was
necessary to fully evaluate porosity, qualitative permeability, shale percentage, and lithology of
the geologic materials. Interpretation methods used in the evaluation of these logs are discussed
in appendix B.
Additional existing geophysical logs include the Temperature/Salinometer and GR/Neutron Logs
run in the DOW in 1981 and 1973, respectively, and a Sonic Log (SL) run in WDW1 in 1965.
However, since logging instrument technology has progressed dramatically and subsequent equa-
tions and modeling of formation characteristics have advanced since these logs were run, a new
suite of logs was run. Use of these geophysical logs enabled further delineation of the
hydrogeologic characteristics of the injection system.
Phase I geophysical logging. A suite of logs was selected on the basis of the considerations
discussed above and the physical dimensions of the casing and tubing in the three wells at Vel-
sicol. The only well suitable for study during phase I was the DOW. Dresser Atlas performed the
logging. The two types of porosity logs run were the Compensated Neutron Log (CNL) and the
Borehole Compensated Sonic Log (BCS). The Minilog (MIL) was run to qualitatively determine
permeability. Resistivity parameters were determined by the Dual Induction Spherically Focused
32
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2300
2350-
New Albany Group
Lingle
Grand Tower
Bailey Limestone
2600-
2650-
2700-
Moccasin Springs Fm
Figure 22 Injection system in
WDW2 Indicating permeable and
impermeable zones delineated
after phase I logging.
j confining unit
|1 impermeable unit
permeable unit
Log (DISFL), Finally, to provide the best stratigraphic correlation between the three wells at Vel-
sicol, the Gamma Ray Log (GR) was run. (See appendix A for a discussion of the theory and
general application of these logs.)
The techniques used to reduce the geophysical log data are discussed in appendix B. The data
from these logs, analyzed and reported in 2-foot intervals, are presented in table 2. With the use
of these modem logging tools and incorporation of improved analytical techniques, it was pos-
sible to obtain more accurate hydrogeologic data of the geologic materials constituting the injec-
tion interval. These data consisted of the formation's matrix-corrected CNL porosity ([PORJNcor),
matrix-corrected BCS porosity ([PORjBCScor), cross-plotted porosity ([PORJxp), secondary
porosity ([POR]sec), true resistivity (Rt), matrix lithology (MA), water saturation (SW), shale
volume (Vsh), and qualitative permeability (k). The same data were obtained from existing logs
for WDW2 and are reported in table 3. Important parameters from these tables are summarized
in table 4.
33
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Table 2 Data from geophysical logs run in the DOW
DEPTH
GR
(POR)
(POR)
(POR)
(POR)
(POR)
RT
MA
sw
Vsh
k
GL
NIs
Ncor
t
BCScor
*P
sec
(«)
(API)
(%)
(%)
(sec)
(%)
(%)
(%)
(ohm-m)
(%)
(%)
2434
28
4.3
4.3
53
3.8
4.3
0.5
50.0
LS
100
6.2
N
36
40
5.0
5.0
53
3.8
5.0
1.2
65.0
LS
100
15.4
N
38
35
12.0
12.0
60
8.8
10.0
3.2
20.0
LS
100
11.5
N
40
25
18.0
18.0
69
15.1
16.4
2.9
11.0
LS
100
3.8
N
42
30
19.0
19.0
69
15.1
16.7
3.9
7.0
LS
100
7.7
Y
44
25
23.8
23.8
77
20.8
21.7
3.0
5.0
LS
100
3.8
Y
46
22
22.6
22.6
76
20.1
21.1
2.5
4.8
LS
100
1.5
Y
48
23
23.0
17.0
70
18.2
18.2
0.0
7.0
DOL
100
2.3
N
50
30
16.0
10.0
62
12.7
12.0
0.0
10.0
DOL
100
7.7
N
52
30
17.5
11.5
57
9.3
9.7
2.2
16.0
DOL
100
7.7
N
54
22
19.0
13.0
60
11.3
11.7
1.7
13.0
DOL
100
1.5
N
56
17
22.0
16.0
62
12.7
13.3
3.3
9.0
DOL
100
0.0
N
58
20
20.6
14.6
63
13.4
13.6
1.2
10.0
DOL
100
0.0
N
60
28
21.8
15.8
61
12.0
12.7
3.8
9.0
DOL
100
6.2
N
62
27
24.6
18.6
65
14.8
15.6
3.8
7.0
DOL
100
5.4
Y
64
32
24.0
18.0
66
15.5
16.0
2.5
5.5
DOL
100
9.2
Y
66
22
25.5
19.5
70
18.2
18.5
1.3
4.8
DOL
100
1.5
Y
68
23
28.5
22.5
78
23.7
23.5
0.0
4.0
DOL
100
2.3
Y
70
17
29.2
23.2
82
26.5
26.0
0.0
3.3
DOL
100
0.0
Y
72
18
28.0
28.0
82
24.3
25.7
3.7
3.0
LS
100
0.0
Y
74
17
30.0
30.0
87
27.9
28.8
2.1
3.2
LS
100
0.0
Y
76
17
28.0
28.0
83
25.0
26.3
3.0
3.5
LS
100
0.0
Y
78
19
26.8
20.8
78
23.7
23.2
0.0
3.9
DOL
100
0.0
Y
80
17
26.3
20.3
77
23.0
22.6
0.0
4.4
DOL
100
0.0
Y
82
20
29.0
23.0
74
21.0
21.4
2.0
4.0
DOL
100
0.0
Y
84
24
23.5
17.5
71
18.9
18.5
0.0
4.6
DOL
100
3.1
Y
86
26
21.3
15.3
63
13.4
13.7
1.9
7.1
DOL
100
4.6
N
88
23
22.3
16.3
64
14.1
14.5
2.2
10.0
DOL
100
2.3
N
90
23
16.5
10.5
60
11.3
11.1
0.0
11.0
DOL
100
2.3
N
92
30
16.4
10.4
56
8.6
8.9
1.8
16.0
DOL
100
7.7
N
94
29
19.8
13.8
57
9.3
10.2
4.5
21.0
DOL
100
6.9
N
96
60
19.0
13.0
60
11.3
11.6
1.7
20.0
DOL
100
30.8
N
98
84
18.5
12.5
60
11.3
11.5
1.2
15.0
DOL
100
49.2
N
2500
52
19.3
13.3
62
12.7
12.7
0.6
14.0
DOL
100
24.6
N
2
37
18.2
12.2
57
9.3
9.8
2.9
14.0
DOL
100
13.1
N
4
33
22.0
16.0
59
10.7
11.8
5.3
11.0
DOL
100
10.0
N
6
45
23.0
17.0
64
14.1
15.1
2.9
8.0
DOL
100
19.2
N
8
30
19.8
13.8
60
11.3
12.1
2.5
9.0
DOL
100
7.7
N
10
23
20.0
14.0
58
10.0
11.3
4.0
8.5
DOL
100
13.1
N
12
20
22.8
16.8
60
11.3
13.2
5.5
8.2
DOL
100
0.0
N
14
32
20.7
14.7
64
14.1
14.4
0.6
9.0
DOL
100
9.2
N
16
30
20.1
14.1
60
11.3
12.4
2.8
10.5
DOL
100
7.7
N
18
42
20.8
14.8
62
12.7
13.6
2.1
8.5
DOL
100
16.9
N
20
38
19.0
13.0
60
11.3
12.1
1.7
10.0
DOL
100
13.8
N
22
30
20.3
14.3
56
8.6
10.4
5.7
11.0
DOL
100
15.4
N
24
23
21.7
15.7
61
12.0
13.3
3.7
10.0
DOL
100
2.3
N
26
24
20.0
14.0
60
11.3
12.2
2.7
8.0
DOL
100
3.1
N
28
23
16.0
10.0
57
9.3
9.7
0.7
9.0
DOL
100
2.3
N
30
23
19.0
13.0
61
12.0
12.5
1.0
10.0
DOL
100
2.3
N
32
21
20.4
14.4
63
13.4
13.8
1.0
12.0
DOL
100
0.8
Y
34
-------
Table 2 Continued
DEPTH
GR
(POR)
(POR)
(POR)
(POR)
(POR)
RT
MA
sw
Vsh
k
GL
Nls
Ncor
t
BCScor
*P
sec
(ft)
(API)
(%)
(%)
(sec)
(%)
(%)
(%)
(ohm-m)
(%)
(%)
2534
33
22.5
16.5
60
11.3
12.2
5.2
10.0
DOL
100
10.0
Y
36
27
22.0
16.0
63
13.4
13.9
2.6
7.5
DOL
100
5.4
Y
38
28
24.3
18.3
65
14.8
15.5
3.5
6.5
DOL
100
6.2
Y
40
29
24.0
18.0
63
13.4
14.2
4.6
5.8
DOL
100
6.9
Y
42
35
17.3
11.3
61
12.0
11.8
0.0
7.1
DOL
100
11.5
N
44
40
16.5
10.5
59
10.7
10.6
0.0
9.0
DOL
100
15.4
N
46
42
21.3
15.3
63
13.4
13.7
1.9
8.5
DOL
100
16.9
Y
48
40
22.5
16.5
70
18.2
17.7
0.0
6.7
DOL
100
15.4
Y
50
40
20.6
14.6
66
15.5
15.1
0.0
6.7
DOL
100
15.4
Y
52
38
15.6
15.6
65
12.3
13.3
3.3
10.0
LS
100
13.8
N
54
29
8.6
8.6
57
6.6
7.4
2.0
20.0
LS
100
6.9
N
Table 3 Data from existing geophysical logs run in WDW21
DEPTH
GR
(POR)
(POR)
(POR)
(POR)
(POR)
RT
MA
SW
Vsh
k
GL
Nls
Ncor
t
BCScor
xp
sec
(ft)
(API)
(%)
(%)
(sec)
(%)
(%)
(%)
(ohm-m)
(%)
(%)
2582
26
8.1
8.1
63
10.9
10.1
0.0
30.0
LS
90
4.6
N
84
30
10.0
10.0
66
13.0
12.2
0.0
28.0
LS
77
7.7
N
86
34
15.0
15.0
71
16.5
16.3
0.0
17.0
LS
74
10.8
N
88
38
14.7
14.7
73
18.0
17.1
0.0
13.0
LS
81
13.8
Y
90
37
13.5
13.5
73
18.0
16.9
0.0
13.0
LS
82
13.1
Y
92
26
7.8
11.1
68
8.8
10.0
2.3
20.0
SS
100
4.6
Y
94
29
6.1
9.3
65
7.1
8.2
2.2
38.0
SS
98
6.9
N
1 All logs used for study were from WDW2 (run during well installation), except the Sonic Log (SL),
which was from WDW1 (run during well installation). The methods of analysis used were the same
as above. All depths measured are from Kelly Bushing (KB), which is 12 feet above GL.
From the data (see appendix B) it appeared that the host formation, the Bailey Limestone, was
composed mainly of a clean dolomite with less than 20 percent shale throughout most of the inter-
val logged. Since the Bailey Limestone is predominantly a dolomite, secondary porosity is always
a consideration. A comparison of CNL and BCSL data suggested that secondary porosity may ac-
count for up to 10 percent of the total porosity. The intervals with higher relative permeability have
a slightly higher secondary porosity and, in turn, total porosity.
Also, the entire interval is primarily 100 percent water saturated with a fluid resistance of ap-
proximately 0.247 ohm-m. At a formation temperature of about 80°F and depth of 2,460 feet GL,
the fluid composition was estimated to be approximately 24,000 ppm NaCI.
Phase I log analysis provided qualitative data of the disposal horizon. On the basis of this
analysis, an additional section of the disposal horizon (2,518 to 2,539 ft KB [Kelly Bushing]) was
eliminated as a possible injection zone (fig. 23).
35
-------
Table 4 Summary of important formation characteristics
(POR)xp.ave = 16%
(POR)sec,ave = 1.98%
tave = 66.7x10"6 sec/ft
tmax = 87x10"6 sec/ft
tmin= 56x10"6 sec/ft
Rt.ave m 8.6 ohm-m
Vsh.ave = 8.05%
(POR)xp,max= 28.8
(POR)sec,max= 5.7%
Rt,max= 21 ohm-m
Vsh,max«= 49.2%
%(POR)xp, min = 8.9%
Rt,min= 3 ohm-m
Vsh,min= 0.0%
Formation lithoiogy (based on 98 feet of "higher permeability, higher porosity" unit), 61.0% dolomite, 35.0%
limestone, and 4.0% sandstone.
Phase II Geophysical Logging
Phase II analysis consisted of a detailed site-specific evaluation of the injection/confining interval.
Continuous Spinner Flowmeter logging (CSFL) and core analysis formed the basis of the study.
Scanning Electron Microscope (SEM) analysis and formation brine/wastewater analysis were
also conducted.
Continuous spinner flowmeter logging. The foregoing data were obtained exclusively from a
static environment, i.e., no fluid injection into the well. For a quantitative evaluation of the
response of the formation to "normal" or near-normal injection rates, a Continuous Spinner Flow-
meter Log (CSFL) was run in WDW2. (An X-Y Caliper Log run prior to the CSFL provided
borehole volumetric data to be used in conjunction with the CSFL data.) Again, as with the pre-
vious set of geophysical logs, borehole conditions in WDW2 restricted the interval available for
logging. But work-over operations subsequent to the WDW2 logging permitted coverage of all an-
ticipated injection zones as delineated by historical and phase I logging (fig. 23).
The CSFL data were used in two ways. First, the data enabled the delineation of specific injection
zones and the calculation of the percentage of total flow into each zone. Second, the data were
used to identify the lower boundary of fluid infiltration (i.e., the upper limit of the basal confining
unit).
To evaluate the effect of varying injection rates, we recorded flow rates at three surficial injection
rates; 75 gallons per minute (gpm), 100 gpm, and 150 gpm. The results are reported in table 5.
Fluid loss is the percentage, on a volumetric basis, of fluid moving into a particular unit. For ex-
ample, on average, 14 percent of the fluid flows into injection zone 1. The 150-gpm rate is the
closest to the "average" waste injection rate (182 gpm) for WDW2 (see p. 58).
The repeatability of the flowmeter was verified by taking measurements as the flowmeter moved
both up and down the borehole. With the flowmeter stationary, data were collected adjacent to
suspected high permeability units and below the base of the anticipated injection horizon (2,594 ft
KB from the other geophysical surveys). The validity of the results was checked by obtaining data
with a stationary flowmeter in the 7-inch casing. At surficial injection rates of 75 gpm, 100 gpm,
Table 5 Fluid loss percentage calculated from CSFL
Injection
zone no.
Depth (ft
below KB)
Fluid Loss (%)
injection rates (gpm)
75
100
150
Average
1
2448-2458
11
15
17
14
2
2552-2558
40
38
29
36
3
2584-2594
49
47
54
50
36
-------
and 150 gpm, calculated flow rates in the 7-inch casing were 81 gpm, 107 gpm, and 163 gpm,
respectively (margin of error less than 10%).
The effective interval of injection at the time of logging the CSFL (from the base of the 7-inch
casing to the deepest depth of penetration of the logging tool) was from 2,437 to 2,614 feet KB. If
conditions remain stable, fluid should infiltrate exclusively into the zones listed in table 5 and
shown on figure 23. No flow was detected below 2,614 feet.
As shown on figure 23, data from the CSFL were not consistent with the interpretation of the
geophysical logs. First, the interval from 2,468 to 2,496 feet was identified from both the historical
and phase I logging as a potential injection zone, but the CSFL indicated an absence of flow into
this interval. Second, data from the CSFL indicated that only a portion of the potential injection in-
terval from 2,538 to 2,568 feet allowed substantial fluid infiltration. And third, on the basis solely of
porosity and permeability data, zone 3 should have accepted less fluid than either zones 1 or 2;
j confining unit
impermeable unit
|n\n| permeable unit - phase I
|^\\\?j permeable unit - phase II
37
-------
however, this scenario was not supported by the CSFL data. In an effort to resolve these dis-
crepancies and to obtain two additional parameters (quantitative permeability and bulk compres-
sibility) essential to injection-interval evaluation, we conducted lab testing of sidewall cores.
Core retrieval and analysis. Several criteria were used to choose the coring zones. In order of
decreasing priority, the selection criteria were to (1) cover all possible injection zones determined
from the historical and phase I logging, (2) obtain cores from the anticipated lower confining unit
indicated by logging data, and (3) cover a range of permeabilities and other physical properties
present in the disposal horizon. Core depths are indicated in figure 24 and table 6.
Twenty-nine sidewall cores were retrieved with Gearhart's Hard Rock Coring tool. Gearhart In-
dustry Inc. Corelab performed the core analysis. Additional core study was done at the ISGS. The
core analysis provided data on quantitative permeability, bulk compressibility, and mineralogic
composition, and provided a means to evaluate the accuracy of the downhole geophysical
methods employed. The results of the core analysis are reported in table 7 and figures 25 and 26.
Table 6 Core location and analysis
Core
Core
kw1
Strength2
no.
depth
(Y,N)
test (Y,N)
Comments3
1
2663.0
N
N
No ka
2
2622.0
Y
Y
3
2620.0
Y
N
4
2617.5
N
N
No ka
5
2606.0
N
N
6
2605.0
Y
Y
7
2588.5
Y
N
8
2573.5
Y
N
9
2572.5
N
N
No ka
10
2560.5
N
N
11
2556.5
N
N
No ka
12
2555.0
Y
Y
13
2551.5
N
N
No ka
14
2539.5
N
N
15
2509.5
Y
Y
16
2508.5
N
N
17
2491.5
N
N
18
2490.5
N
N
19
2484.5
Y
Y
20
2482.5
N
N
No ka
21
2481.0
N
N
22
2479.5
N
N
23
2478.5
N
N
No ka
24
2463.5
N
N
25
2462.5
N
N
26
2457.5
N
N
No ka
27
2456.5
N
N
28
2451.5
Y
Y
29
2450.5
N
N
No ka
1 Water permeabilities (kw) derived from air permeabilities (ka) by applying a
Klinkenburg correction.
2 Separate test which yields Poisson's ratio, Young's modulus, and bulk com-
pressibility (corrected for in situ pore and confining pressures).
3 Basic analysis and x-ray diffraction performed on all cores. Basic analysis con-
sists of ka, total porosity, water saturation (Sw), and fluorescence. X-ray diffraction
identifies all minerals that have an abundance of 1% or more by weight and the
total clay percentage.
38
-------
Figure 24 Core locations for WDW2.
Available data indicate that the discrepancies between the injection zones identified from phase I
and phase II are due to the presence of brucite (Mg[OH]2). The supporting data used to develop
the brucite-formation hypothesis are summarized below and more fully described in appendix C.
Mineralogic analysis of sidewall cores identified brucite (up to 45% by weight) to be present in
potential injection zones, as identified from phase I logging. Brucite, not present in the injection
system prior to well operation, forms during waste injection. Brucite apparently formed in zones
having the highest potential for fluid flow, as identified from phase I logging. Brucite formation
does not reduce porosity (as identified from geophysical logs) but does reduce the permeability
significantly. Flow rates in the different injection zones appear from CSFL results to be proportion-
al to the brucite concentration within that zone, i.e., zones with higher brucite concentrations have
lower flow rates.
39
-------
Table 7 Results of core analysis
Depth
POR
ka
kw
Compress x10"12
(ft KB)
(%)
(md)
(md)
(cm sec2/gm)
2450.5
24.2
51.5
26.1
0.640
0.476
15.5
56.5
27.7
62.54
62.5
13.2
0.0076
63.5
11.5
0.0087
79.5
26.4
0.178
81.0
24.8
0.017
82.5
56.1
84.5
30.8
14.97
12.940
8.70
90.5
29.4
2.292
91.5
24.2
0.457
2508.5
9.9
0.0089
09.5
11.4
0.017
0.001
3.36
39.5
17.7
0.203
51.5
8.9
55
18.0
0.060
0.017
8.41
60.5
17.1
0,095
73.5
5.2
0.0050
0.00013
88.5
16.6
0.021
0.004
11.9
2605
3.1
0.0055
0.00042
4.71
06
4.6
0.0029
17.5
4.8
20
4.6
0.0034
22
3.8
0.0038
63
6.7
The source of ions for brucite formation is not clear. The source of OH" is the injected waste
(pH > 12), but the source of Mg2+ is unclear. Two possible sources are the waste fluid or the
dolomite within the injection zones.
Hydrogeology of the site. Having developed a hypothesis to explain brucite formation, we quan-
tified the hydrogeologic characteristics of the injection system, which allowed the data to be used
as parameter input for the numerical model. The disposal interval was divided into 12 units based
on hydrogeologic characteristics (fig. 27 and table 8), using data derived from figure 23. These 12
units were used for differentiating the stratigraphic cross sections (figs. 17,18, and 19). Local and
regional stratigraphic/structural studies, presented in Stratigraphic and Structural Definition of the
Injection System, page 23, were also considered to ensure that the units chosen were not local-
ized anomalies (i.e., noncontinuous).
Table 8 lists the units and their associated characteristics. Permeability, air (ka) and water (kw),
and bulk compressibility data were obtained from core analysis. Hydraulic conductivity (K) and
specific storage (Ss) measurements were derived from these results. The porosity measurements
(POR) were taken from table 2 (geophysical logging results) and core analysis results. Storativity
(S) and transmissivity (T) data were calculated only for the three injection zones delineated pre-
viously (table 9). Units 2,9, and 11 in table 8 correspond to injection zones 1, 2, and 3, respective-
ly. The thicknesses (b) for units 2,9, and 11 were determined from figure 27,
The three gas-storage field wells mentioned in Stratigraphic and Structural Definition of the Injec-
tion System, page 24, provided additional permeability data for the intervals corresponding to
unit 1 and the overlying strata (above 2,402 feet KB), Values for vertical water permeabilities of
40
-------
1-
(0
O)
o
05
O
-1 -
-3-I
-4-
•
ft
•
• air permeability (ka)
A water permeability (kw)
1
•
•
•
•
•
•
•
A *
#
•
• a : *
~
A
A
A
A
2440
2480
2520 2560
depth below KB (ft)
2600
Figure 25 Core permeabilities (air and water) versus depth for WDW2.
M
•
• f
•
•
•
•
•
• A
•
• • •
A
A
A
A
A
A
• air permeability (ka)
A water permeability (kw)
O)
o
O) -2
o *
-3
-4-
10
20
porosity(%)
Figure 26 Cora permeabilities versus core porosities for WDW2.
~r
30
41
-------
Figure 27 Unit locations for WDW2.
7.85x10-5 md (millidarcys) for the interval corresponding to unit 1 and 3.51 x10"5 md for the overly-
ing strata were obtained.
Long-Term Inject/on Test
A long-term injection test was conducted to obtain T and S values for the injection formation. An
injection test is similar to a standard pump test except that water is injected into the well instead
of being withdrawn from it.
The injection test started at 10 a.m., July 9,1987, and was completed at 7 a.m., July 24,1987.
The test ended at this time because of a power outage scheduled by the power company. Velsicol
42
-------
Table 8 Summary of hydrogeological data for a portion of the disposal system
Depth
POR
ka
kw
CompressxIO'12
K*x10""
Ssbx10*
Unit
(ft KB)
(%)
(md)
(md)
(cm sec2/gm)
cm/sec
cm'1
2432
2.0
1
34.5
2.0
1
36
4.0
1
38
2.0
1
40
7.8
7.85x10'5"
1
42
4.0
1
44
4.3
1
46
5.0
1
48
10.0
1
50
21.7
1
50.5
24.2
1
51.5
26.1
.640
.476
15.5
52.73
2.67
2
52
21.1
2
54
18.2
2
56
18.2
2
56.5
27.7
62.54
2
57.5
18.2
2
58
15.0
2
60
12.0
3
62
9.7
3
62.5
13.2
.0076
3
63.5
11.5
.0087
3
64
11.7
3
66
13.3
3
68
13.3
3
70
15.6
4
72
16.0
4
74
18.5
4
76
18.5
4
78
23.5
4
79.5
26.4
.178
4
80
26.0
4
81
24.8
.017
4
82
25.7
4
82.5
56.1
4
84
28.8
4
84.5
30.8
14.97
12.940
8.70
1434
2.21
4
86
26.3
4
88
23.2
4
90
22.6
4
90.5
29.4
2.292
4
91.5
24.2
.457
4
92
21.4
4
94
18.5
4
96
13.7
5
98
14.5
5
2500
11.1
5
02
8.9
5
04
10.2
5
06
11.6
5
08
11.5
5
08.5
9.9
.0089
5
09.5
11.4
.017
.001
3.36
.111
.831
5
10
12.7
5
12
9.8
5
14
11.8
5
16
15.3
6
18
11.0
6
20
11.0
6
43
-------
Tabie 8 Continued
Depth
POR
ka
kw
CompressxIO'"
K'xIO"8
Ssbx10"8
Unit
(ft KB)
(%)
(rnd)
(md)
(cm sec'/gm)
cm/sec
cm'1
22
14.3
6
24
9.5
6
26
9.5
6
28
12.2
6
30
14.2
6
32
14.2
6
34
11.9
6
36
9.3
6
38
12.0
6
39.5
17.7
.203
7
40
14.1
7
42
12.2
7
44
13.9
7
46
15.5
7
48
14.2
7
50
11.8
7
51.5
8.9
7
52
10.6
8
54
13.7
8
55
18.0
.060
.017
8.41
1.88
1.62
8
56
17.7
8
56.5
17.0
8
58
15.1
8
60
13.3
9
60.5
17.1
.095
9
62
17.8
9
64
14.5
9
66
7.0
9
68
6.2
9
70
4.0
10
72
1.0
10
73.5
5.2
.0050
.00013
.0144
10
74
1.0
10
76
1.0
10
78
6.2
10
80
5.0
10
82
5.0
10
84
5.5
11
86
8.9
11
88
9.8
11
88.5
16.6
.021
.004
11.9
.443
1.90
11
90
7.0
11
92
4.0
11
94
4.0
11
96
4.0
12
98
4.0
12
2600
4.0
12
02
4.2
12
04
4.4
12
05
3.1
.0055
.00042
4.71
.0465
.597
12
06
4.6
.0029
12
17.5
4.8
12
20
4.6
.0034
12
22
3.8
.0038
12
63
6.7
12
Average vertical water permeability (kaw) and POR from three gas injection wells in the study area.
44
-------
Table 8 Additional hydrogeological data for primary injection zones
Section
b(ft)
Sc x 10"® (-)
T* x 10"® (cm21 sec)
2
10
8.14
161
8
6
2.96
3.44
10
10
5.79
1.35
Explanation for tables 8 and 9:
(a) K = kwpg / [i
where
K = hydraulic conductivity
kw = water permeability (Klinkenburg corrected air permeability)
p = water density = 0.997 gm/cm3*
g= acceleration due to gravity = 980 cm/sec2
|a= water viscosity = 0.008705 gm/cm sec*
* temperature used to determine p and p. was taken to be 26°C. This came from
Temperature Log run in WDW2 assuming the cooling effect due to past injection was
extremely localized (see appendix A).
(b) Ss = pg (a + np)
where
Ss = specific storage
a = matrix bulk compressibility
P = fluid bulk compressibility* = 4.513x10"11 cm-sec2/g
n= porosity
* temperature used to determine p was taken to be 26°C (see note above).
(c) S = Ssb
where
S = storativity
Ss = specific storage
b = zone thickness
(d) T= Kb
where
T = transmissivity
K = hydraulic conductivity
b= zone thickness
injected water from its stormwater retention ponds during the test. Table 10 shows the physical
and chemical properties of the fluid injected during the in injection test (Velsicol, 1987). Table 11
shows the volume and rate of fluid injected. The average injection rate was 288.4 gpm.
Head data were collected at the DOW using a Stevens water level recorder (fig. 28). The water
level recorder was set with a 11 gearing and an 8-day chart.
Data obtained from the DOW were analyzed by two techniques: Theis analysis and Cooper-
Jacob analysis (see Todd 1980 or Freeze and Cherry 1979 for a detailed explanation of these
techniques). Theis analysis is a curve-fitting technique; therefore, the T and S values obtained
from this method depend on the analyst's judgment. The Cooper-Jacob technique is somewhat
less subjective since the data plot is a straight line on semilog paper.
45
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Table 10 Selected chemical arid physical properties of water injected during injection test (Velsieol 1987)
Suspended solids
29 mg/L
Dissolved solids
1205 mg/L
Sodium chloride
794 mg/L
Sodium hydroxide
235 mg/L
pH
8.0
Specific gravity
1.004
Sample temperature
58"F
Table 11 Volume injected into WDW2 during injection test
Volume
Injection
Reporting Hours
Injected
rate
date operated
(gallons)
(gpm)
7/10/87 21
340,673
270.4
7/11 24
414,607
287.9
7/12 24
422,409
293.3
7/13 24
419,684
291.2
7/14 24
423,836
294.2
7/15 24
419,042
290.8
7/16 24
401,760
278.8
7/17 24
418,939
290.8
7/18 24
411,973
285.9
7/19 24
413,270
286.9
7/20 24
411,616
285.7
7/21 24
410,420
284.9
7/22 24
424,717
294.8
7/23 24
424,211
294.4
1124 24
419,352
291.0
Average
411,767
288.4
Table 12 Analysis of injection test
Method S(-)
Transmlsslvity (m2/min)
Theis 2.75 x 10~4
0.385
Cooper-Jacob (r= 0.960) 2.47 x10"4
0.386
r = correlation coefficient for the linear regression
For the Cooper-Jacob technique, head buildup was plotted versus log time {fig. 29). Linear regres-
sion was used to calculate the parameters (S and to) for this method. An iterative approach was
taken since the data used in the analysis depend on the outcome of the analysis. For the Cooper-
Jacob method, u (u = rS/ (4Tt)) must be less than to 0.01. From the definition of u and the
value of T and S, a minimum time can be determined (i.e., only field data where t > tmin can be
used). Thus, an iterative technique was necessary to calculate T and S. Table 12 shows the
results of the analyses (only the values for the final iteration of the Cooper-Jacob analysis are
presented). Note the good agreement between the Theis and Cooper-Jacob analyses. The
values obtained by the Cooper-Jacob technique are considered to be the more accurate since
this technique is less subjective.
46
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•¦injection started
200
400
Time (hours)
600
800
Figure 28 Water level record for DOW, including
data from injection test.
-u 2-
0
a>
1
1 1—i—i i i 111 1 1—i—i i i i n 1 r-
1 10 100
Time since injection began (hours)
Figure 29 Plot of data used for Cooper-Jacob
analysis.
47
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4. NUMERICAL MODELING
Model Selection
Model selection is an important step in conducting a modeling investigation of a groundwater flow
problem. The model should be able to handle all significant physical processes of the
groundwater flow system. If the model does not incorporate these processes, it cannot be ex-
pected to simulate the field situation with any degree of accuracy.
The literature contains descriptions of many general and specialized numerical models. At the out-
set of this project, it was thought that a model capable of simulating three-dimensional (3D) flow
and flow through complex hydrogeologic regimes would be required. Several 3D groundwater
flow models have been developed, including the Sandia Waste Isolation Flow and Transport
Model (SWIFT) (Reeves and Cranwell, 1981) and the Heat and Solute Transport Program
(HST3D) (Kipp 1987). SWIFT and HST3D are finite difference groundwater flow and transport
models that are independent modifications of SWIP (INTERCOMP, 1976). This original model,
developed to model the effects of deep-well waste injection, includes sophisticated well functions
rarely incorporated into other models. Although SWIFT and HST3D have a more general focus
than does their predecessor, both models retain these well functions, and either model could be
used for this project. Since a version of HST3D compatible with the Prime 9650 computer used in
this project was available before a similar version of SWIFT (II), HST3D was selected.
Model Description
HST3D is a descendent of the Survey Waste Isolation Program (SWIP) written for the U.S.
Geological Survey by INTERCOMP Resource Development and Engineering Consultants.
HST3D represents a complete rewrite of SWIP with many major and minor modifications, im-
provements, and corrections.
Overview of Model
HST3D simulates saturated groundwater flow and associated heat and solute transport in three
dimensions. The following equations are solved numerically: the saturated groundwater flow equa-
tion, formed from combining the conservation of total fluid mass and Darcy's Law for flow through
porous media; the heat transport equation from the conservation of enthalpy for the fluid and
porous medium; and the solute transport equation from the conservation of mass for a single
solute, which may adsorb onto the porous medium and/or decay (Kipp 1987). These equations
are coupled through the dependence of advective transport on the interstitial fluid velocity field,
fluid viscosity on temperature and solute concentration, and fluid density on pressure, tempera-
ture, and solute concentration.
For the dependent variables of pressure, temperature, and mass fraction, numerical solutions are
obtained successively using a set of modified equations that more directly link the original equa-
tions through the velocity, density, and viscosity coupling terms. Finite difference techniques are
used for the spatial and temporal discretization of the equations. When supplied with appropriate
boundary and initial conditions and system-parameter distributions, a wide variety of heat and
solute transport simulations can be performed (Kipp 1987).
The basic source-sink term represents wells. A complex well-flow model may be used to simulate
specified flow rate and pressure conditions at the land surface or within the aquifer, with or
without pressure constraints. Types of boundary conditions include specified value, specified flux,
leakage, heat conduction, an approximate free surface, and two types of aquifer influence func-
tions. All boundary conditions may be functions of time (Kipp 1987).
48
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Assumptions Incorporated into the Model
Since this project was concerned with simulation of fluid flow and not heat and/or contaminant
transport, only the assumptions incorporated into the flow model will be discussed. Kipp (1987) in-
corporated the following assumptions into the partial differential equation describing groundwater
flow:
• Groundwater fully saturates the porous medium within the region of groundwater flow.
• Groundwater flow is described by Darcy's Law.
• The porous medium and the fluid are compressible.
• The porosity and permeability are functions of space.
• The coordinate system is chosen to be aligned with the principal directions of permeability ten-
sor so that this tensor is diagonal for anisotropic media.
• The coordinate system and the principal directions of the permeability tensor are orthogonal.
• The coordinate system is right-handed with the z-axis pointing vertically upward.
• The fluid viscosity is a function of space and time through dependence on temperature and
solute concentration.
• Density-gradient diffusive fluxes of the bulk fluid are neglected relative to advective-mass
fluxes.
• Dispersive-mass fluxes of the bulk fluid from spatial-velocity fluctuations are excluded.
Input Data
Input data required by HST3D for modeling fluid movement may be categorized as follows:
hydrogeologic properties of the aquifer, physical dimensions of the aquifer, physical dimensions of
the well(s), hydraulic properties of the well(s), and physical and chemical properties of the fluid.
Additional input data are required for any attempts to model solute and/or heat transport.
Physical Configuration of the Injection System
As defined here, the injection system refers to the geologic deposits that constitute the injection
zone and its associated confining units. The hydrogeology of the site is described in chapter 3.
The physical dimensions and hydrogeologic properties of the injection system used as model
input will be described where appropriate in each section.
Description of the Injection and Observation Wells
Waste Disposal Well 2 (WDW2) at the Velsicol Chemical Corporation's Marshall Plant was
modeled. WDW2 is a packer-annulus-type well completed in Devonian limestone (fig. 30).
Originally, the well was drilled to a total depth of 6,007 feet and was completed open-hole from
2,440 to 2,737 feet. Preceding the phase II field testing of the well, Velsicol completed extensive
well workover procedures to remove debris, which had partially filled the well. These procedures
included a high-pressure jet wash of the well bore. In addition to suspending and removing the
debris in the well, the tool scoured the well bore. Thus it is assumed that the skin effect for this
well would be negligible. Access for geophysical tools to total depth was blocked at 2,610 feet,
presumably due to bridging of materials sloughed from the well face. However, the bridging
probably did not plug the well from a hydraulic standpoint.
Located 506 meters due north of WDW2 is the Devonian Observation Well (DOW), which was
completed open-hole starting near the top of the Devonian limestone (fig. 31). Total depth for this
well is 2,580 feet. Water-level data were collected from this well during this project.
Physical and Chemical Properties of the Fluids
HST3D requires input of various physical properties of the fluids, including density, temperature,
viscosity, and compressibility. These data are required for the fluid injected and the native fluid in
the formation (brine). Fluid-compressibility data for injected wastes and/or brines were generally
not available but were estimated on the basis of the chemical composition of these fluids. Much of
these required input data were available from a database compiled by the ISGS.
49
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Lithology
Waste Disposal Well #2
Aquifers (USDW)
Unconsolidated
Shale
Dolomite
Sandstone
Limestone
Primary freshwater aquifer
(0-2,500 mg/l)
Secondary aquifer
(2,500-10,000 mg/l)
Stratigraphic Units
Q Quaternary
P Pennsylvanian
M Mississippian
Mc Chesterian sandstone
Msg, si Ste. Genevieve Limestone
St. Louis Limestone
Msa Salem Limestone
Mb Borden Siltstone
Mch Chouteau Limestone
M/D Mississippian/Devonian
M/Dna New Albany Group
D Devonian
Dlgb Lingle Limestone
Grand Tower Limestone
Bailey Limestone
S Silurian
Sm Moccasin Springs Fm
Su Undifferentiated dolomite
O Ordovician
Om Maquoketa Shale
Ogp Galena-Platteville dolomite
Osp St. Peter Sandstone
Opdc Prairie du Chien dolomite
-€ Cambrian
-Sep Eminence-Potosi dolomite
Injection System Components
M/Dna Upper confining unit
Dlgb Injection unit
Sm Lower confining unit
Depth
(ft)
- 2,000 -
Figure 30 Schematic for WDW2 (modified from Brower et al. 1989).
50
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Devonian Observation well
Depth
(ft)
Kelly Bushing 635 ft
Ground Level 630 ft
•-v '-v
. Mc' -—
Msg, Msl
J Msa
Mb
^^M/Dna-
iDlgb-
_L_
\„,u \
T ~Sm\
"V
-3,000 —
-Su-
i
I-
I
11% in. OD.
casing to
1086 ft
41/2 in. OD.
casing to
2,434 ft
Packer
shoes set
at 2,434 ft
- Open hole
6V4 in.
Figure 31 Schematic for DOW (Velsicol 1984).
General Parameters
Velsicol injected hazardous waste consisting of production wastewater and surface runoff water
from on-site process areas. Chlorinated pesticides were produced at this site. The waste was
highly alkaline (pH >12) and contained pesticides and other chlorinated hydrocarbons. The rela-
tive concentrations of constituents in the waste were NaCI > NaOH > hexachlorocyclopen-
tadiene (hex) > chlordane.
Velsicol has been required by permit to sample and analyze the waste injected into WDW2 and
the brine from the DOW. Thus an extensive database of physical and chemical properties of the
injected fluid and brine is available. This database was compiled by the ISGS and used extensive-
ly in this project. For WDW2, available data date back to early 1973, when operating reports were
first required. Data for dissolved solids, specific gravity, and viscosity are presented in table 13.
Table 13 Selected parameters for fluids injected via WDW2
Parameter (unit)
Range
Average
Standard
deviation
Number
Dissolved solids (mg/L)
200 - 254,000
38,346
35,388
671
Specific gravity (-)
0.9948-1.14
1.027
0.025
538
Viscosity (centipoise)
0.7161 -0.9822
0.7857
0.0700
33
51
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Data for dissolved solids in table 13 show the variability of the injected fluid, which is predominant-
ly storm water runoff. Brower et al. (1989) attributed this variation in dissolved solids to variation
of precipitation frequency and intensity.
A relationship between specific gravity and viscosity seems to exist (fig. 32). Linear regression of
these variables produced a correlation coefficient of 0.873. If additional viscosity data had been
available, this correlation might have improved.
The mean value for specific gravity of the waste was used as input for the numerical model. For
comparison, Devonian brine sampled during construction of WDW2 had a specific gravity of
1.011. The linear relationship between viscosity and specific gravity was assumed to be valid;
thus, viscosity was determined using the mean specific gravity of the waste (fig. 32).
All modeling was conducted under isothermal conditions. Although the temperature of the injected
fluid varied throughout the year, it was assumed that the temperature of the formation would not
change significantly from its mean temperature because of injection. The formation temperature
was determined from a temperature log run down the DOW on December 18,1986. The mean
formation temperature was 34.4°C (94°F).
Compressibility of the Fluids
Lab-determined values for the compressibility of the waste and brine were not available; however,
compressibility values for common saline solutions were available in the literature. Millero et al.
(1974) published compressibility values for NaCI, MgCte, NaSC>4, and MgS04 as a function of
temperature and molality. Figure 33 depicts the fluid compressibility in relation to temperature and
molality for NaCI solutions.
Roy et al. (1989) characterized the brine and waste as predominantly NaCI solutions. Table 14
shows the chemical analysis of the Velsicol waste, Velsicol dilute waste, and Devonian brine. In
this context, waste refers only to the fluids from the plant processes. Dilute waste, typically the
fluid injected, comprises fluids from the plant processes and surface runoff. The sample of
Devonian brine was obtained from the DOW in June 1987.
1.00
0.95
0.90
-------
T(°C)
Figure 33 The compressibility of water and NaCI solutions versus temperature (Millero et al. 1974).
Table 14 Chemical analysis of waste and brine
Parameter (unit)
Waste
Dilute waste
Brine
PH
12.92
12.85
9.07
Eh (mV)a
+572
+572
-154
EC (mmhos @ 25'C)
403
56b
22
TDS (mg/L)
215,900b
37,300b
—
CI (mg/L)
112,664
15,400
12,700
F (mg/L)
151
—
20.1
Na (mg/L)
86,350
—
8,370
SO4 (mg/L)
61.5
—
182
NO3 (mg/L)
274
—
25.1
Mg (mg/L)
<0.07
—
117.0
a: relative to a standard ZoBell solution
b: Mravik (1987)
from Roy (1987)
Concentrations of the major anion and cation were used to determine the molality of each fluid.
Compressibility of each fluid was determined on the basis of the molality and two assumptions:
(1) that the temperature was 34.4°C and (2) that the fluids could be considered NaCI solutions.
Table 15 shows the molality and compressibility of the three fluids.
Review of the TDS data for the waste and dilute waste indicated that the "average" waste injected
into WDW2 (TDS = 38,346 mg/L) had a slightly higher TDS concentration than the dilute waste.
Thus the compressibility of the "average" waste should be close to, but slightly lower than, the
compressibility of the dilute waste. (See table 18 for the value used.)
53
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Table 15 Compressibility of waste and brine
Fluid
Molality (moles/kg) Compressibility (1/Pa)
Waste
Dilute waste
Brine
Waste
3.76
0.799
0.703
3.185 x 10'10
4.105 X 10"10
4.145 x 10'10
4.46 x 10"10
Volume of Injected Waste
Since waste injection began in March 1972, Velsicol (1987) reported that 1.4623x109 gallons of
fluid have been injected via WDW2. Simple volumetric equations were used to determine the ex-
tent to which these fluids have moved within the injection zone.
Cross-plotted analysis of geophysical logs indicated that the thickness-averaged porosity of the in-
jection zone is 12.5 percent. Assuming that waste has flowed through the entire thickness (174 ft)
of the injection zone and radially from the well, the pore volume of the injection zone from WDW2
to the DOW (1,660 ft) is 1.406x109 gallons. Thus the cumulative volume of injected fluid is
equivalent to 1.04 pore volumes. To account for this fact, model input of fluid data was based on
the physical properties of the waste. In this project, only groundwater flow was simulated; thus,
the properties of the fluid must be homogeneous throughout the injection system. To consider
nonhomogeneous fluids, one would need to model solute transport.
Modeling Results
Most numerical modeling studies of groundwater flow include several modeling phases, which
have also been followed in this study. First, verification of the model is conducted. In this stage,
the model is used to simulate known analytical solutions. This phase is typically followed by his-
tory matching or model calibration. Here, the model was used to simulate field data, usually col-
lected during a pump test. Sensitivity analysis generally follows model calibration. During this
phase, the effect of pertinent parameters is quantified. The final stage is the prediction stage,
which is an exercise in "what if." For example, what will the pressure buildup be at the well if a cer-
tain flow rate is continued for 30 years. The following discussion describes each of these phases
for this project.
Model Verification
Model verification was necessary since HST3D was a new code. Verification allowed the modeler
a chance to become familiar with this new model and to check the model accuracy versus analyti-
cal solutions. HST3D was verified using two analytical solutions: unsteady radial flow in a con-
fined aquifer with constant pumping rate (Theis 1935), and unsteady radial flow in leaky systems
with no storage in the semipervious layer at a constant pumping rate (Hantush 1964).
Theis Solution. Theis solution is an analytical solution for unsteady radial flow in confined
aquifers. This solution is readily available in any groundwater text and is not repeated here. Input
data for the analytical solution and HST3D are listed in table 16.
A radial coordinate system was used to discretize the groundwater flow domain: 50 nodes in the r-
direction and 20 nodes in the z-direction. The radius of the aquifer simulated was 24,960 m. No-
flow conditions were applied at all boundaries.
Figure 34 shows the drawdown at a point 100 m from the pumping well determined by numerical
and analytical methods. The two solutions are identical.
Leaky Aquifer Solution. HST3D was also verified against an analytical solution for wells in
leaky systems without storage in the semipervious layer (no storage in the semipervious is an as-
54
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Table 16 Input data for the Theis solution
HST3D
aquifer thickness, b = 3.05 m
hydraulic conductivity, K = 3.29 x 10~4 m/sec
porosity, n = 0.20
matrix compressibility, a = 3.34 x 10"8 Pa"1
fluid compressibility, p = 4.53 x 10"1° Pa"1
viscosity, jx = 0.001 kg/m-sec
fluid density, p = 999.5 kg/m3
pumping rate, q = 3.00 x 10"3 m3/sec
Analytical solution
transmissivity, T = 0.001 m2/sec
storativity, S = 0.001
pumping rate, q = 3.0x10"3 m3/sec
sumption inherent to HST3D) (Hantush 1964). A radial coordinate system was used to discretize
the aquifer: 50 nodes in the r-direction and 5 nodes in the z-direction. No-flow conditions were ap-
plied at the lower and radial boundaries. A leaky aquifer boundary condition is applied at the top
boundary. The remaining input data for this simulation are listed in table 17.
The drawdown for a well 20 m from the pumping well was determined using the analytical and
numerical solutions (fig. 35). The numerical solution tends to slightly underestimate the draw-
down. These results are closer to the analytical solution than those reported by Ward et al. (1984)
and are considered to be acceptable.
Model Calibration
Data used for model calibration (history matching) were obtained from the long-term injection test
described in chapter 3 (p. 42). and plotted on figure 28. The conceptual model for the injection
system was based on data presented in Long-Term Injection Test (p. 42) and is shown on figure
36. The hydraulic conductivity and physical dimensions in the vertical direction are also depicted
on this figure. Other pertinent input data are listed in table 18. The injection system was dis-
cretized with radial coordinates: 60 nodes in the r-direction and 22 nodes in the z-direction.
Figure 34 (left) Comparison of model-predicted Figure 35 Comparison of model-predicted draw-
drawdowns with results from Theis Analysis. downs in relation to time with Hantush Analysis.
55
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Table 17 Input data for leaky aquifer simulation
HST3D
Analytical solution
transmissivity, T = 10"3 m2/sec
storativity, S = 10"4
aquitard hydraulic conductivity,
K' = 3 x 10"10 m/sec
aquitard thickness, b' = 0.30 m
pumping rate, q = 0.014 m3/sec
aquifer thickness, b = 3.05 m
aquifer intrinsic hydraulic
conductivity, K = 3.35x10"11 m2
. 'Pa"1
4.53x10"10 Pa"1
matrix compressibility, a = 3.34x10
fluid compressibility, p
fluid density, p = 999.5 kg/ma
viscosity, m = 1.00x10"3 kg/m-sec
aquitard intrinsic hydraulic
conductivity, K = 3.06x10'17 m2
aquitard thickness, b' = 0.30 m
pumping rate, q = 0.014 m3/sec
Table 18 Selected input data for model calibration
radius, r = 15870.90 m
p= 4.00 x 10"10 Pa"1
a = 4.50 x 10"10 Pa"1
p = 1020 kg/m3
p. = 7.87 x 10"4 kg/m-sec
No-flow conditions were applied at the top and bottom boundaries, while an aquifer influence was
applied at the radial boundary.
Kipp (1986) describes the use of aquifer influence boundary conditions (AIF BC) as a simple, but
approximate, method for embedding an inner region of groundwater simulation within a larger
region where groundwater flow may be treated in an approximate fashion. The use of aquifer in-
fluence functions reduces the size of the computational grid with a corresponding reduction in
computer storage and execution time.
The natural hydraulic gradient of the Devonian limestone is very low (see p. 32); thus, the hydrau-
lics of the injection well will dominate the groundwater hydraulics in the area surrounding the well.
The flow rate across an AIF boundary is a function of the potentiometric head and hydrogeologic
characteristics of the aquifer. The use of the AIF BC was favored over a specified head or flow-
type BC, since the AIF is a more accurate representation of the hydraulics of the injection system.
Stratigraphy
New Albany Group,
Lingle and Grand Tower
Limestones
T
Bailey Limestone
elev. above
reference (m)
128.29
Moccasin Springs Formation
55.76
52.71
24.06
22.23
14.31
11.28
0
Hydrogeologic Role
K
(m2)
"xg&upper confining unit WUSi
4.35 x 10 21
upper injection zone
2.51 X 10-"
2.30 x 10~14
middle injection zone
9.65 x 10"
2.99 x 10"14
lower injection zone
7.72 x 10 "
9.68 X 10"14
Figure 36 Conceptual model 1 of the injection system.
56
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The T and S values calculated on the basis of input data, as well as the values determined from
field testing, are presented in table 19. The input data and field data match reasonably well.
Closer agreement of the field and model T and S values probably could have been obtained with
minor adjustments to the input data (chiefly K, a, and P); however, the T and S values used were
considered satisfactory.
The model values for T and S were even more satisfactory considering that two of the chief input
parameters, a and p, are consistent with published values. Fluid compressibility (P) has been pre-
viously discussed (p. 52).
Table 19 Comparison of transmissivity (T) and storativity (S) values
Field test
HST3D
T (m2/min)
0.386
0.373
S(-)
2.47 x 10"4
2.65 x 10-4
Our rock compressibility (a) values also agreed with values in the literature. Birch (1966) reports
that a = 1.22x10"11 Pa"1 for dolomite. Domenico and Mifflin (1965) report a for sound rock
ranges from 10"9 to 10"10 Pa"1, while a for jointed rock ranges from 10"8 to 10"10 Pa"1. Since
secondary porosity was present in the cores retrieved, one would have expected that a for the
dolomite at the study site would be slightly greater than a = 1.22x10"11 Pa"1. In fact, the values
of the cores tested range from 1.55x10 to 3.26x10"11 Pa"1. Thus the use of a = 4.50x10"1
Pa"1 for model calibration seemed reasonable. As discussed in appendix C, the scanning elec-
tron microscopy (SEM) work indicated that secondary porosity was present, primarily in the form
of vugginess and some localized microfractures. The microfractures were very small and tended
to be interconnected. Because of the close spacing and size of the microfractures, modeling
flow through this geologic material as flow through porous media was considered to be a valid
assumption.
The intrinsic permeability values for the three injection zones ranged from 2.5x10"11 to 9.7 x
10"11 m2 (25.4 to 97.8 darcys). Schmoker et al. (1985) summarized data for limestone and dolo-
mite petroleum reservoirs throughout the United States. These authors report that only 11 percent
of all dolomite reservoirs exceed 0.1 darcy. Freeze and Cherry (1979) list 0.2 darcy as an upper
permeability limit for limestone and dolomite. Clearly, the permeability values for the injection
zones seem to be quite high. The permeabilities used as model input were based on the results
of the injection test and were higher than the laboratory-determined permeabilities. There appear
to be two explanations for the apparent high permeability values. First, the permeability values
were actually calculated from transmissivity values and thickness of "permeable" units of the
aquifer. The thickness of these units could have been underestimated. Another possibility was
that the cores may not be representative of the overall injection system. Greater emphasis was
placed on the results of the injection test, since this is an in situ measurement of the system.
In addition to aquifer transmissivity, another control on specifying intrinsic permeability was the
results of the flowmeter survey conducted during phase II of the field experiments. The intrinsic
permeability of the three injection zones was adjusted so that the flow into each of these three
zones matched the flow profile defined by the flowmeter. Thus in the model, 48.1 percent of the in-
jected fluid flowed into the lower injection zone, 36.2 percent into the middle zone, and 15.7 per-
cent into the upper zone.
Figure 37 depicts the head build-up at the DOW during the injection test and the buildup pre-
dicted by HST3D versus time. The model overpredicted the head buildup at times by less than 20
hours; however, the results at later times are very close. Oscillation of the head buildup (field
data) is also evident in figure 37. This oscillation is believed to be a manifestation of earth tides
and not a variation in the pumping rate.
57
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Matching model results with the later field results was considered more important because the
main use of the model was to predict long-term effects of injection. The input data were reason-
able, and the predicted head buildup matched reasonably well the head buildup observed in the
field; therefore, model calibration was deemed successful.
Sensitivity Analysis
A rigorous sensitivity analysis as described by Yeh (1986) was riot conducted. The sensitivity
analysis conducted here involved varying significant parameters and noting the effect of this varia-
tion on head buildup (Ah) at the DOW, the parameter of interest. The significance of various
parameters (i.e., injection rate, hydraulic conductivity) was observed during the two previous
stages of this project. Based on these observations, sensitivity analysis was conducted for the fol-
lowing parameters: boundary conditions, injection rate, rock compressibility, fluid compressibility,
hydraulic conductivity, and anisotropy. The sensitivity analysis is summarized here and described
in detail in appendix D.
Injection rate and hydraulic conductivity were the most sensitive input parameters. That is, a
given change in injection rate or hydraulic conductivity would produce the largest change in Ah ob-
served at the DOW. The type of boundary condition and the location of the boundary could also
significantly affect the head buildup predicted by the model. In decreasing order, the most sensi-
tive parameters were injection rate and hydraulic conductivity, rock compressibility, anisotropy,
and fluid compressibility.
Model Projections for Long-Term Injection
Using the conceptual model developed during the model calibration phase, we investigated the ef-
fects of long-term, continuous injection at two rates: 1.150 x 10~2 and 2.208 x 10~2 m3/sec. The
first injection rate is the "average" rate at which the company injected waste during the life of the
well. This was calculated by dividing the cumulative volume of waste injected by the length of
operation for WDW2. The second injection rate is the maximum average injection rate permitted
by the Illinois Environmental Protection Agency (IEPA1987).
Embedded in this calculation of the "average" injection rate is the assumption that the well was
operated on a continual basis; however, WDW2 was not in operation continually. A larger head
buildup in the injection system would be produced by assuming continuous (24-hour) operation
because pressure in the injection system would never bleed off.
HST3D was used to predict the head buildup in the injection system over a 30-year period. The
decline in head was also modeled for an additional 30-year postinjection period. Thirty years was
chosen since this is typically the length of service for an injection well. Because of problems ex-
perienced with HST3D, the injection rate during the postinjection period could not be set to zero.
During the postinjection period, the injection rate was set as low as possible, q= 1.82x10"4
m3/sec. Figure 38 shows the head buildup in relation to radial distance from the injection well
after 10,927 days (30 years). At the DOW, Ah after this time is 0.03 m. Thus, use of q = 1.82x10"4
m3/sec during the postinjection period did not significantly impact the pressure decline during the
postinjection period.
Injection Scenario 1
Injection scenario 1 is injection for 30 years at a rate of 1.150x10~2 m3/sec, followed by a postin-
jection period in which q = 1.82x10"4 m3/sec. Figure 39 shows the response of the injection sys-
tem during both 30-year periods (262,980 hours each). Head buildup at the DOW increases
exponentially. After 30 years of injection, Ah = 1.61 m at the DOW. In terms of Ah, steady state
was approached but not reached. The head buildup at the DOW also dropped exponentially. Ap-
proximately 900 hours after the change in the injection rate, the head buildup was approximately
half of its maximum value. Nearly 7.5 years (66,000 hours) after the change in the injection rate,
58
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Figure 37 (left) Comparison of model-predicted Ah Figure 38 Head buildup versus radial distance
versus field data for DOW. from WDW2 q - 1.82x10"4 m3/sec.
the head buildup was only 0.01 m, after correcting for Ah due to injection at q = 1.82x10"4 m3/sec.
During the 30-year postinjection period, the head buildup did not reduce to 0.00 m.
Injection Scenario 2
During the second injection scenario, the effects of injection for 30 years at q = 2.208x10"2 m3/sec
were investigated. A postinjection period followed during which q = 1.82x10"4 m /sec. Figure 40
shows the head buildup at the DOW. The results were similar to the results for injection scenario
1. The head buildup increased exponentially to a maximum Ah = 3.20 m after 30 years of Injec-
tion. Also, after the injection rate was reduced, the head fell exponentially. The head buildup ap-
proached but did not go to 0.00 m during the postinjection period.
Figure 39 Injection scenario 1: head buildup and decline with time at the DOW.
59
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Figure 41 shows the head buildup at the WDW2 during the injection and postinjection periods.
The results were similar to the results shown in figure 40 except the magnitude of the head
buildup was greater at the injection well. After 30 years of injection, Ah at WDW2 was 7.88 m. For
comparison, Ah at WDW2 for injection scenario 1 was 4.22 m.
Maximum hydraulic pressure was 7.081x106 Pa (1,027 psi) and occurred at the bottom of the well
after 30 years of injection under injection scenario 2. The pressure at the base of the confining
layer equaled 6.687x10s Pa (970 psi). The pressure increase due to 30 years of injection was
7.73x104 and 6.69x104 Pa at the bottom of the well and the base of the confining unit, respective-
ly. The pressures resulting from injection scenario 1 (q = 1.150x10"2 m3/sec) were slightly lower
than those listed here.
60
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In Illinois, the hydraulic fracture gradient is generally considered to be equal to 1.5x104 Pa/m
(0.65 psi/ft). Using this value, the hydraulic pressure necessary to initiate fractures was calculated
as 1.19 x 107 Pa (1,694 psi) for the bottom of the well (depth = 794.3 m) and as 1.12x107 Pa
(1,591 psi) for the base of the confining unit (746.2 m). Thus pressures due to 30 years of con-
tinuous injection at the maximum permitted injection rate were much less than the pressure calcu-
lated to initiate hydraulic fracturing.
Hypothetical Conduits
During this final phase of modeling, the hydraulic response due to the presence of hypothetical
conduits was investigated throughout the injection system. Jones and Haimson (1986) describe
some hypothetical conduits pertinent to underground injection. These conduits, which allow fluid
movement from the injection zone, include abandoned wells, microannuli at the injection well, and
permeable fault zones. Time constraints restricted the investigation to the effect of a microan-
nulus at the injection well. Accomplishing this task required numerical modeling to evaluate
whether the pressure response in the injection system or in an overlying unit could be used to
identify fluid movement from the injection zone. Three monitoring strategies were evaluated:
monitoring at the injection well (WDW2), at the observation well (DOW), and in the overlying
aquifer.
A new conceptual model of the site hydrogeology was developed for this task (fig. 42). A thicker
sequence of geologic materials than that previously used included the Devonian limestones, the
overlying New Albany Shale (a confining unit), the "Carper sand" (a permeable unit), and the
Borden Siltstone (another confining unit). Since "Carper sand" lies near the base of Borden
Siltstone, for purposes of modeling, it is considered the basal horizon of this formation. Hydro-
geologic characteristics for these units appear on figure 42.
For this conceptual model, the head buildups at the injection and monitoring wells were slightly
lower than the buildups used in the original model; however, the results were considered accept-
able. The slight decrease (0.03 m at the DOW) was probably due to the greater thickness of com-
pressible geologic materials for the conceptual model.
Stratigraphy
elev. above
reference (m)
178.28
Bordon Siltstone
"Carper sand"
New Albany Group,
Lingle and Grand Tower
Limestones
Bailey Limestone
Moccasin Springs Formation
139.57
128.29 -
Kr
K2-
55.76 -
52.71 -
24.06
22.23
14.31
11.28
0
Hydrogeologic Role
K
(m2)
iiiilSiiffigconfining unit
4.35 x 10 21
1st overlying aquifer
5.0 x 10"13
g: upper confining unit||S:;:::;|
4.35 x 10'21
upper injection zone
2.51 x 10"
2.30 x 10'14
middle injection zone
9.65 x 10 "
2.99 x 10"'4
lower injection zone
7.72 x 10 "
•: basal Confining unit':::::*:*:*::
9.68 x 10-14
Radial distance (m)
Figure 42 Conceptual model 2 of the injection system
61
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Modeling Results: Hypothetical Conduit Scenario
In this scenario, a microannulus was assumed to have developed at the injection well. Extending
from the top of the uppermost injection zone to the base of the Carper, the microannulus con-
nected these two permeable units (fig. 42) and was input into the model as two zones. The first
zone was considered the microannulus, and the second zone, a transition between the microan-
nulus and the New Albany Shale. Both zones were 0.01 m thick and discretized using three
nodes. Several runs were made, with different zone permeabilities (table 20). CT3DB1 was the
baseline run used for comparison.
Table 20 Permeability (m2) of the microannulus
Run Microannulus (K1) Transition zone (K2)
CT3DB1 4.35 x 10"21 4.35 x 10"21 *
CT3DB2 1.00 X10"12 1.00X10"14
CT3DB3 1.00 x10"10 1.00 x10"12
CT3DB5 1.00 x 10"9 1.00 x 10 11
CT3DB4 1.00 x 10"8 1.00 x 10"10
* same permeability as New Albany shale.
For this series of model runs, the maximum permitted injection rate (q = 2.208x10"2 m3/sec) was
used to maximize the pressure gradients in the injection system. Injection continued at this rate
for 365 days. Because the "Carper sand" does not produce water or hydrocarbons, hydrogeologic
data for this unit are rare. On the basis of interpretations of geophysical logs from wells near Mar-
shall, which indicated that the Carper is a permeable sandstone, permeability was assumed to be
5.0x10~13 m2.
For analysis of results, a head difference of 0.05 m, when compared with results of CT3DB1, was
considered monitorable. Differences of less than 0.05 m were not considered sufficient to be
monitored because of errors in measurement, head fluctuations due to earth and/or barometric
tides, and related factors.
Head buildup in relation to time is shown for WDW2 (fig. 43), DOW (fig. 44), and the base of the
Carper at WDW2 (fig. 45). As the permeability of the microannulus increased, the head buildup at
WDW2 decreased slightly. For CT3DB4 (K1 = 1.00x10"® m2), difference in head buildup was
-0.23 m after 1 year. Head buildup for the other cases were lower— for instance, Ah = -0.10 m
when K1 = 1.00x10"10 m2. A change in the head build-up of this magnitude at an operating injec-
tion well might not be monitorable because of head buildup associated with other factors, such as
wellbore plugging and pipe friction increases.
For the five cases investigated, no monitorable difference in head buildup was observed at the
DOW (fig. 44). For CT3DB4 (K1= 1.00x10"8), head buildup was lower than the other cases by
just 0.01 m after 365 days. Thus monitoring the DOW would not detect the leak at the micro-
annulus. Monitorable differences in head buildup were predicted at the base of the Carper in
three of the four cases. For CT3DB3, the difference after 365 days was 0.08 m. The differences
after 365 days were greater for CT3DB5 (0.77 m) and CT3DB4 (3.98 m). The radial extent of
head buildup at the base of the Carper varied for each of the cases. For CT3DB5, it was ap-
proximately 100 m, and for CT3DB4, more than 6,000 m (fig. 46).
In summary, monitoring the DOW would not reveal the presence of a leaky microannulus, in part
because of the distance between the injection and observation wells. Monitoring the injection well
might reveal a leaky microannulus, but the differences in head buildup for the cases investigated
might be masked by well bore plugging, corrosion buildup in the tubing, and other related factors.
Finally, monitoring in the overlying aquifer appears to be the best alternative, but it depends on
the hydraulic conductivity of the microannulus. As the hydraulic conductivity of the hypothetical
62
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conduit increases, the volume of fluid moving into the overlying aquifer and the head buildup also
increases. The head buildup observed in the Carper is also a function of its hydraulic conductivity.
Lower Ah would be observed if the Carper were more permeable. On the other hand, higher Ah
would be observed over a smaller area if the Carper had a lower hydraulic conductivity.
8ri
J-„
5-i
1 ^
0
CT3DB1
CT3DB2
¦ ¦¦¦¦ CT3DB3
111 is CT3DB5
~~~~a CT3DB4
TTI IFTfJ Tl IITITJ] I I I Hlll[ I I 111171] I I 111 111] I I I tllll|—
10""1 10"3 10"* 10~' 1 10 10
Time (hours)
i nnii[—i 11 Mill
10 3
Figure 43 Effect of microannulus on the head
buildup at the WDW2.
Q_ _
D
"D
T3
O
CT3DB1
• •••• CT3DB2
¦ ¦¦¦¦ CT3DB3
aaaaa CT3DB5
~~~~~ CT3DB4
*i 1111hi|—i > iWiii|—i 11iiiii) ¥\ 11ini|—i 11mii|—i nimij—rmntri rrin
10 -* 10 ~3 10 10"' 1 10 10 2 10 r
Time (hours)
Figure 44 Effect of microannulus on the head
buildup at the DOW.
3-
CT3DB1
>•••• CT3DB2
¦¦¦¦¦ CT3DB3
44111 CT3DB5
~ ~~do CT3DB4
0 |*M lllllll—I II Btll|—I I 11 IIIII—Pi I llllll—I I lllRl—I I MINI]—I WIIIUI—I I mil
10"* 10 ~3 10 "2 10"' 1 10 10J 103
Time (hours)
Figure 45 Effect of microannulus on the
head buildup in the "Carper sand."
3-
a
D
•5 2-
_o
X)
o
ID
X
10
.CT3DB1
¦ ¦¦¦¦ CT3DB3
iini CT3DB5
~ ~~~~ CT3DB4
0~"—* i i Xujp—0 i iPiiiiP—> i i Mnf—i ifciiii|®—tii'
10 10 1
Radial distance (m)
10
Figure 46 Head buildup in the "Carper sand" versus
radial distance from WDW2.
63
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5. SUMMARY AND CONCLUSIONS
Evaluation of Injection Scenarios
Available records and fogs pertinent to the injection system were studied, hydraulic tests were
conducted, geophysical logs were run, and other tests were conducted on-site to determine the
hydrogeologic characteristics of the injection system. Regional and site-specific descriptions of
the system's stratigraphy, structural geology, and hydrogeology were generated from analyses of
these logs and test results. These descriptions formed the basis of input for the numerical
groundwater flow model (HST3D) used to investigate the hydraulic effects of injection upon the in-
jection system. Other input included data on the physical and chemical characteristics of the in-
jected wastewater and the native brine in the injection system.
Before the effects of various injection scenarios were investigated, HST3D was verified with
respect to two analytical solutions (figs. 34 and 35) and calibrated with respect to data collected
during an injection test (fig. 37). Both verification and calibration were considered satisfactory.
Once calibrated, the model was used to predict the effects of various injection scenarios. The ef-
fect of long-term injection was investigated at two constant injection rates: the average historical
rate (1.150x10 2 nrr/sec) and the maximum average permitted rate (2.208x10 m3/sec). Under
both scenarios, significant head buildup was observed at the injection well and radially from it.
During the simulated 30-year injection period, steady state was approached but not obtained
during either injection scenario. During the subsequent 30-year postinjection period, decrease in
head buildup was fairly rapid—dropping to half in less than 2,000 hours for both scenarios. The
maximum hydraulic pressures at the bottom of the weii and at the base of the upper confining unit
were significantly lower than the pressures calculated to initiate hydraulic fracturing.
The continuity of the regional stratigraphy and its qualitative permeability were determined from
the regional and site-specific study. Numerical modeling indicated that the pressures resulting
from waste injection were lower than pressures calculated to initiate hydraulic fracturing; thus new
fractures would not be initiated. From a hydraulic viewpoint, therefore, waste injected within this
injection system would be contained and would be considered protective of human health and the
environment for the two injection scenarios investigated.
These results are based on an assumption that hydraulic conductivity remains constant. How-
ever, from available data it appears that the high pH of the injected wastewater causes it to react
with the dolomite present in the injection zones, forming brucite (Mg[OH]2), which reduces the
hydraulic conductivity of the injection zone. Apparently, greater amounts of brucite formed in the
zones where there was a greater flow of fluids; thus the zones with higher permeability were af-
fected first. This hypothesis must be verified by additional work, which is beyond the scope of
this project. At the study site, the long-term effect of this decrease in permeability on injectivity
needs to be investigated. Any further decrease in the hydraulic conductivity of the injection zones
will invalidate the results of the numerical modeling conducted for this study. In addition, any
reduction in hydraulic conductivity of the injection zones will most likely cause an increase in
hydraulic pressure if the injection rate remains constant. In such a case, hydraulic fracturing may
be of concern.
Evaluation of Monitoring Strategies
The model was also used to investigate the hydraulic response throughout the injection system
when a hypothetical conduit was introduced. In this scenario, a microannulus at the injection well
was introduced, hydraulically connecting the uppermost injection zone and an aquifer immedi-
ately overlying the upper confining unit.
64
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Model results were reported in terms of difference in head build-up when the microannulus was
and was not present. At the WDW2, Ah (-0.23 m) was greatest for the scenario with the greatest
microannulus permeability (1x10"8 m2). A difference of this magnitude at an operating well would
be considered unmonitorable because of interferences such as increased Ah resulting from well
bore plugging or tubing corrosion. At the DOW, Ah was considered too low to be monitorable.
The difference in the overlying aquifer (Carper sand) was considered monitorable for the microan-
nulus permeability greater than or equal to 1x10"10 m2. The head buildup in the Carper is a func-
tion of its hydraulic conductivity, the hydraulic conductivity of the microannulus, and the radial
distance from the microannulus. Thus from a practical standpoint and for the scenario modeled,
the overlying aquifer is the only viable location for hydraulically monitoring leakage via the
microannulus.
65
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Waste-Isolation Flow and Transport Model (SWIFT): Sandia National Laboratory, SAND83-
1154, NUREG/CR-3316,155 p.
Whitaker, S. T., 1988, Silurian pinnacle reef distribution in Illinois: model for hydrocarbon explora-
tion: Illinois State Geological Survey, Illinois Petroleum 130,32 p.
Whiting, L. L., J. Van Den Berg, T. F. Lawry, R. F. Mast, and C. W. Sherman, 1964, Petroleum in Il-
linois, 1963: Illinois State Geological Survey, Illinois Petroleum 79,99 p.
Willman, H. B„ and J. C. Frye, 1970, Pleistocene stratigraphy of Illinois: Illinois State Geological
Survey, Bulletin 94, 204 p.
Willman, H. B., J. A. Simon, B. M. Lynch, and V. A. Langenheim, 1968, Bibliography and index of
Illinois geology through 1965: Illinois State Geological Survey, Bulletin 92,373 p.
Willman, H. B., E. Atherton, T. C. Buschbach, C. Collinson, J. C. Frye, M. E. Hopkins, J. A.
Lineback, and J. A. Simon, 1975, Handbook of Illinois stratigraphy: Illinois State Geological
Survey, Bulletin 95,261 p.
68
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Veh, W. W-G., 1986, Review of Parameter Identification Procedures in Groundwater Hydrology:
The Inverse Problem: Water Resources Research, v. 22, n. 2, p. 95-108.
69
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APPENDIX A. THEORY AND PRACTICAL APPLICATION OF GEOPHYSICAL
LOGGING INSTRUMENTS
Geophysical logging was used in this study to investigate the site and regional hydrogeology, and
this section briefly explains the basic operational theory and applications of the geophysical tools
used. Comprehensive coverage of every aspect of tool theory or all possible applications is
beyond the scope of this project. These tools and their many applications are discussed in
greater detail in Bateman 1985a, Bateman 1985b, Helander 1983, Leach et al. 1974, Curtis 1966,
Peebler, Hallenburg 1984, Dobrin 1976, Kovaes and Associates 1981, Pickett 1977, Hilchie 1977,
Brock 1984a, Brock 1984b, Rider 1986, Gearhart, Gearhart 1983, Dresser Atlas 1981, Schlum-
berger 1984, Schlumberger 1985, Dresser Atlas 1985a, Dresser Atlas 1985b, Dresser Atlas
1985c, Prasada Rao 1985, Keys and MacCary 1971, and Martin 1982. The discussion below
draws liberally from these references.
Caliper Log (CL)
The Caliper Log tool is a theoretically uncomplicated instrument. Most tools still rely on a single or
a series of potentiometers {fig. A-1). The potentiometers respond to a number of arms (caliper
arms), which transmit information about the borehole environment to the potentiometer actuator.
This information is relayed as a series of pulses to the surface recording equipment, which then
processes the data.
There are a number of different arm configurations with the CL tool. For the purposes of injec-
tion/confining interval evaluation, the one- and four-arm tools are appropriate.
For applications that utilize the numerical CL data, such as calculations involving the Flowmeter
Log (FL), the more sensitive four-arm CL tool is employed. For other applications, such as mud-
cake and washout location and general borehole conditions, a one-arm CL tool (usually run in
mechanical combination with another device, such as an Neutron Log, Density Log, or Per-
meability Log) is utilized almost invariably.
Round Pipe Hole in Pipe Restriction in Pipe
Figure A-1 Caliper Log tool that utilizes a dual potentiometer configuration (from Dresser Atlas 1985c)
70
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Flowmeter Log (FL)
Several types of Flowmeter Log tools are available, and they all operate In a similar fashion. The
tool considered in this report is the continuous variety, which would be the most appropriate at the
high flow rates often encountered in waste-disposal wells.
The Continuous Spinner Flowmeter Log (CSFL) tool, shown in figure A-2, incorporates an im-
peller into its design. The impeller rotates in response to fluid movement. This rotation generates
a series of electrical pulses that are transmitted uphole to the surface equipment for computer
processing. The number of pulses generated is proportional to the number of revolutions per
second of the impeller, which can be related to flow velocity. The volumetric flow rate, the meas-
urement of most interest, can be calculated from borehole diameter data obtained from the four-
arm CL tool.
The CSFL tool measures fluid velocity very satisfactorily in turbulent fluid flow. Although this flow
regime is encountered most often, it nonetheless requires verification. One method of defining
whether a flow regime is turbulent is to use the Reynold's Number (Re). Re is defined as
Re = vDp/fi [A-1
where p = fluid density, g/cm3
v = average fluid velocity, cm/sec
D = hole diameter, cm
H = fluid viscosity, poise
Pipe Wall
Wireline Cable
Instrument Body
Figure A-2 Continuous Spinner Flowmeter Log
tool (from Dresser Atlas 1981).
71
-------
Re values of 3,000 or greater are used to represent turbulent flow in most literature dealing with
fluid flow. For most applications of the CSFL tool in injection/confining interval evaluation, fluid will
be injected at the surface to initiate impeller movement. A useful conversion in Re calculations is
V = (0.3637) Q/D2
where v = average fluid velocity, cm/sec
D = hole diameter, cm
Q = flowrate, barrels per day
[A-2]
This conversion is combined with the definition of the Reynold's Number to yield
Re = (0.3637)Qp/|xD
[A-3]
Gamma Ray Log (GRL)
As its name suggests, the GRL detects gamma rays—random, high-energy electromagnetic
waves emitted during the decay of unstable radioisotopes. The radioisotopes normally found in
rocks are 40K and the daughter products of the uranium and thorium decay series. The GRL dis-
cussed here is unable to differentiate the contribution of each individual radioisotope to the total
intensity of gamma radiation.
The detector of the tool normally consists of a sodium iodide (Nal) crystal optically coupled to a
photomultiplier tube. Atoms of the Nal crystal absorb gamma ray collision energy, which places
the electrons of the atoms in a higher energy state. When the excited electrons lose this acquired
energy and fall back into their original state, they give off light that is converted to a voltage pulse
through the photomultiplier tube. These pulses are transmitted uphole and converted, on the ap-
propriate scale, to a measure of the gamma ray intensity.
Because of the high natural concentration of in clay minerals, shales generally exhibit a high
gamma ray intensity. On the other hand, sandstones and carbonates generally produce a lower
gamma ray count because of their relatively low concentration of clays and other highly radioac-
tive constituents. Because of this difference in gamma ray intensity, various lithologies can easily
be identified (allowing correlation of lithologic units), and a rock unit's shale volume can be deter-
mined.
During phase I logging, a GRL that used a Geiger Mueller type of detector was run. The Geiger
Mueller replaced the Scintillation type of detector employed in the previous GRL. This change
results in a smoother, less fluctuating GR, which provides a better estimate of the formation's
natural gamma ray activity (GR, measured in API units).
Sonic Log (SL)
The Sonic Log is an acoustic device that generates acoustic waves and measures reflected
acoustic waves. The measurements taken from the SL tool are the direct result of the propagation
of acoustic (elastic) waves through the borehole environment. The two important waves to the SL
tool are the compressional (longitudinal) and the shear (transverse) waves.
The initial energy to produce the sound (acoustic) waves is generated by the transmitter (T) por-
tion of the tool (fig. A-3). The velocity of a shear wave (Vs) is given by:
Vs = (M/p)0'5
[A-4]
where \i = modulus of shear for the medium
p = density of the medium
72
-------
Transmitter
Acoustic
Isolator —
j Bumpe
ti Travel Time from
Transmitter to
Receiver(Com pressional
Wave Travel Path)
Arrival at
Recorder
S-Wave
C-Wave s
Receiver
Orilling Fluid
Figure A-3 (left) Generalized Sonic Log tool
(from Helander 1983).
Figure A-4 Idealized schematic of receiver (R)
signal (from Helander 1983).
Since the incident energy generated by the SL transmitter must first traverse a liquid medium in
the borehole (where n = 0), it would appear that no shear wave would be generated, and subse-
quently received, by the SL tool. However, the occurrence of both shear and compressional
waves in the response from the tool (fig. A-4) is a curious and useful anomaly. This apparent dis-
crepancy can be resolved by noting that as the compressional wave strikes an interface or simply
an adjacent medium with different elastic properties, a shear wave is produced. Therefore, as the
compressional wave traverses from the transmitter (T) to the receiver (R) on the tool, the wave
generates a shear wave that can, in this manner, be detected by the receiver circuitry. Shear
waves generally are of a larger amplitude and about half as fast as compressional waves.
The transmitter-receiver array is chosen to account for abnormalities present in the borehole en-
vironment, i.e., washouts and tool tilting. The standard transmitter-receiver (T-R) arrangement is
shown in figure A-5. Although other T-R configurations are available, this configuration is most
nearly suited to the needs of injection/confining interval evaluation. The specific SL tool that incor-
porates this T-R array into its design is the Borehole Compensated Sonic Log (BCSL) tool. The
main benefit of this type of T-R spacing is the compensation for washouts and tool tilting effects
on travel time measurements.
Since the compressional wave has the fastest velocity of propagation, it is the one of most con-
cern with the BCSL. If tfi is the time taken to travel through the pore space (fluid travel time) and
tma is the time taken to travel through the matrix, the total travel time will be t (the travel time
recorded by the BCSL tool). The porosity (POR)BCS (Borehole Compensated Sonic) can be rep-
resented be the Wyllie time-average equation,
The compressional wave (p-wave, also called C-wave) takes the path of least resistance. Areas
of isolated (not interconnected) pockets of porosity, which would normally be found in the case of
secondary porosity, will not have a pronounced effect on the travel time of the p-wave. By compar-
ing the BCSL data with data from a tool that is influenced by the total porosity (primary and secon-
dary), the amount of secondary porosity present can be estimated. The following equation applies
to this situation,
(POR)BCS = (t - tma)/(tf| - tma)
[A-5]
(POR)tot = (POR)sec + (POR)prim
[A-6]
73
-------
: formation
upper
transmitter
R,
,R2
r3
R,
lower
- transmitter
cable
upper
transmitter TR2
-V
—Ar-
-v
- time -
j lower tr3
3 transmitter
TR4
TR,
upper system A t = TR4 - TR2
lower system A t = TR, - TR3
A t recorded on log =
(TR. - TR2) + (TR, - TR3)
Figure A-S Generalized Borehole Compensated Sonic Log tool (from Bateman 1985b).
During phase I logging, the BCSL was run in place of the SL. A more advanced detection system
in the BCSL allows compensation for environmental factors that affect the signal transit time (t)
used by the BCSL to make porosity determinations. A more accurate porosity profile results with
the use of the BCSL.
One other SL tool that should be mentioned is the Long Spaced Sonic Log (LSSL) tool. It incor-
porates a longer T-R spacing than does the BCSL tool. In this manner, the LSSL tool is affected
by a zone farther away and less disturbed by drilling operations than the zone at the borehole in-
terface. This tool has been used for shear wave analysis, which when combined with compres-
sional wave data results in an evaluation of some of the formation's strength characteristics, such
as the pressure required to fracture the formation and the formation's elastic properties. If a hole
has a large potential for washouts, this tool may be the best SL tool to use.
Neutron Log (NL)
The neutron is a fundamental particle found in the nucleus of all atoms except hydrogen, which
contains only a proton. The neutron is a chargeless particle with about the same mass as the
proton. The NL tool exploits these two properties of the neutron particle. The neutron source is
usually a mixture of americium and beryllium, which react together to continuously emit neutrons.
Since the neutron is a small and electrically neutral particle, it passes with ease through most mat-
ter. During its passage, the neutron particle loses energy by colliding with other atoms. When the
neutron's energy is reduced to a level equal to the surrounding matter (a function of absolute
temperature), the neutron is called a thermal neutron. The energy of a thermal neutron is in the
range of 0.025 eV.
Simple force relationships reveal that the maximum energy loss in the collision of two balls occurs
when the two balls are of equal mass. Since the neutron and the hydrogen atom's proton have
nearly equal masses, hydrogen dominates the behavior of neutrons and, in turn, the response of
the NL tools. The thermal neutron flux is therefore controlled by the hydrogen content of the for-
mation. Since hydrogen is found in the water molecules filling the pore space, the thermal neutron
flux is a direct indication of the porosity of the formation.
Environmental factors such as hole size and mud weight influence the response of the NLtool.
This influence can be corrected by taking two readings of thermal neutron flux at different spac-
ings and using them to define the slope of the response line of the tool. This slope is relatively un-
altered by environmental effects. The Compensated Neutron Log (CNL) tool utilizes this concept.
The primary measurement of the CNL tool is therefore a ratio of the two count rates, far and near.
Figure A-6 shows a CNL tool schematic.
74
-------
Figure A-6 Generalized Compensated Neutron Log tool (from Bateman 1985b).
The CNL displays a measurement of total porosity. Thus, it can be combined with the BCSL to
provide an estimate of secondary porosity. Along with another porosity device, usually the BCSL
or the Compensated Density Log (CDL), a lithologic determination may be made in addition to an
accurate estimate of total porosity (cross-plotted porosity).
The CNL has replaced the Sidewall Neutron Log (SNL). The CNL utilizes a dual detector while
the SNL has only one. The second detector enables the CNL to compensate effectively for en-
vironmental factors not taken into account with the SNL, such as salinity and temperature of the
borehole fluid and diameter of the borehole. Accounting for these factors results in a more
accurate determination of porosity with the CNL, ([POR]Nls).
Density Log (DL)
The DL utilizes a focused gamma ray source, normally cesium-137, which emits gamma rays into
the formation from a pad assembly that is forced against the borehole wall via a back-up arm.
The gamma rays interact with the electrons in the material opposite the focused source mainly
through Compton scattering. This results in the gamma ray losing energy at each collision. The in-
tensity of the back-scattered gamma ray is then measured by the gamma ray detectors (usually
two) (fig. A-7). The measured gamma ray intensity is a function of the electron density of the for-
mation. As the electron density of the formation increases, the probability of collision increases,
resulting in reduced gamma ray intensity measured by the gamma ray detectors. The electron
density, pe, has been related to the bulk density, pb, by the following equation,
pe = pb(2Z/A) [A-7]
where Z = atomic number or the number of electrons per atom
A = atomic weight
In most cases, the ratio, 2Z/A, is approximately equal to 1.0. Therefore pe = pb, and the apparent
bulk density response of the tool is a response to the bulk density, pb, of the formation material op-
posite the tool.
A two-detector DL or Compensated Density Log (CDL), which was used for phase I logging, al-
lows for the compensation of the mudcake's effect on CDL tool response. In this way, an accurate
75
-------
total porosity measurement is obtained, CDL response can be compared to BCSL porosity to es-
timate secondary porosity or cross-plotted with the BCSL or CNL to produce lithologic and total
porosity determinations.
Resistivity Log (RL)
The property of a material that opposes the flow of an electrical current is called electrical resis-
tance. Resistivity is a measure of the resistance of a volume of material. Several authors have
noted that formation resistivity can be determined by,
R- KV/i [A-8]
where R = resistivity
K = geometric factor specific for a particular tool
V = potential across current path
I = current.
Since the RLtool measures the potential, and K and I are known, R can be calculated. The calcu-
lated resistivity is dependent on the amount of porosity and fluid contained in the pores.
RL tools have a number of applications. For this study, the resistivity device was needed for two
purposes: to determine an accurate, true formation resistivity for fluid saturation calculations,
cementation factor determinations, and stratigraphic correlations; and to estimate the invasion of
borehole fluids into the formation, which may affect the RL tool's response.
Two appropriate resistivity logging systems are available: the Dual Laterolog Microspherically
Focused Log tool and the Dual Induction Laterolog (Spherically Focused Log) tool. Although both
systems will provide the necessary results, specific borehole conditions dictate which one is ap-
propriate. The former is used when sea water or brine mud fills the borehole and the latter when
fresh or oil-based mud is present. For this discussion, the Dual Induction Laterolog (DIL) tool will
be considered. (The Dual Induction Spherically Focused Log [DISFL] tool is similar in principle to
the DIL.)
Figure A-7 Generalized two-detector Density Log tool (from Helander 1983).
76
-------
The DIL tool comprises two sections; the induction and the lateral. The induction section
produces two measurements, the "induction log deep" and the "induction log medium"; the lateral
section yields one, the "iaterolog."
The induction section, shown in schematic in figure A-8, is equipped with transmitter-receiver
(T-R) coil pairs. An alternating current is applied to the transmitter, which generates a magnetic
field around the tool, thereby inducing current flow in the surrounding formation. The current flow
generates a magnetic field in the formation which, in turn, induces a voltage in the receiver coils.
The measured voltage is proportional to the formation conductivity, which is inversely related to
the formation resistivity.
Figure A-8 Schematic diagram of induction log principles (from Hallenburg 1984).
77
-------
Lateral devices pass a current of constant intensity from the tool into the formation (fig. A-9). This
current flow creates equipotential spheres around the source electrode (A). Potential measuring
electrodes (M, N) record the potential created by the current flow. The potential measured is then
converted to formation resistivity.
The three curves generated have different depths of investigation into the formation, because of
T-R spacing on the induction section and A-M,N spacing on the laterolog section. In this way, an
evaluation of the amount of invasion is made, which is used to correct the deepest measurement
(induction log deep) for invasion effects to produce an accurate, true formation resistivity. This
resistivity can be used to obtain the cementation factor and fluid saturation of the formation.
The DISFL has replaced the Induction Electric Log (IEL). With the addition of one more resistivity
curve to the output of the DISFL, the Induction Log Medium resistivity, and a deeper reading In-
duction Log Deep resistivity, factors that affected the resistivity response of the DISFL can be
taken into account. These factors include the depth of invasion of the borehole fluids and the ef-
fect of this invasion on the determination of a true resistivity for the formation. The result is an In-
duction Log Deep resistivity corrected for invasion effects, which is considered more accurate
than the formation's true resistivity determined by the IEL.
Permeability Log (PL)
The Permeability Log tool used most frequently today is the Minilog (MIL) tool. The MIL replaced
the Microlog. Advanced electronics have increased the sensitivity of the Minilog as compared with
the Microlog. Use of the Minilog results in more accurate information on permeability, mud (Rm),
mud filtrate (Rmf), and mudcake (Rmc) resistivities.
The MIL, which utilizes the same resistivity theory discussed for the RL, is not discussed in detail
here. The output of the MIL tool consists of two measurements: normal and lateral resistivities.
The lateral configuration is described above. The normal measurement utilizes a slightly different
system, shown in general schematic in figure A-10. The two arrays are housed in a nonconduc-
tive, fluid-filled rubber pad that is forced against the borehole wall by a back-up arm. This con-
figuration is necessary to prevent the borehole fluid from short-circuiting the closely spaced
current electrodes.
B
i"
Depth reference
= Vi AM —
~' i Spacing = AM
/
Depth Reference Point
M
Figure A-9 (left) Schematic diagram of lateral logging
system (from Helander 1983).
Figure A-10 Schematic diagram of normal logging
system (from Helander 1983)
78
-------
By utilizing two different configurations, MIL can produce vaiying depths of investigation. A com-
parison of the curves indicates the presence and magnitude of invasion of the borehole fluids into
the formation. This enables a qualitative determination of the presence of permeability.
Spontaneous Potential Log (SPL)
Although the SPL system has one of the simplest physical configurations (fig. A-11), it is the
result of many different factors. The SPL system records the change in naturally occurring poten-
tials as a function of depth in the borehole. Two types of potential may contribute to the total
Spontaneous Potential (ESp): electrochemical (Ec) and electrokinetic (Ek). In well log analysis
it is assumed that the measured SP response is due solely to the electrochemical component;
therefore, Esp = Ec.
79
-------
The electrochemical potential is composed of the membrane potential (Em) and the liquid junction
potential (Ej). The membrane potential is caused by the separation of two fluids of different ac-
tivity by a permeable, charged membrane. An analogy might be mud and formation water
separated by shale. The liquid junction potential is the result of the contact of two solutions of dif-
fering activity, such as mud filtrate and formation water.
The ESp is commonly written as
Esp = -Kclog(Rmf /Rw) [A-9]
where Kc = 61 + 0.133T(°F)
Rmf = mud filtrate resistivity
Rw = formation water resistivity.
This equation illustrates one application of the SPL system, namely Rw determination. The other
applications relevant to this study are stratigraphic correlation and qualitative permeability estima-
tion. The latter two are available through a consideration of the fluids and formation materials that
give rise to the membrane and liquid junction potentials.
Temperature Log (TL)
The TL tool is simply a device that records the magnitude of the subsurface temperature. This is
accomplished by incorporating into the tool's design a sensor element that provides ultrasensi-
tive, stable readings over a suitable temperature range. A temperature probe in contact with the
borehole environment transmits the thermal energy to the sensor, which converts the energy to a
signal coverted by the surface equipment to absolute and differential temperature. These data
can be useful to injection/confining interval evaluation in several ways. First, in many injection
wells the temperature of the injection fluid is anomalously cooler than the native formation
temperature. This anomaly can often be detected by the TL, providing another method, along with
the CSFL, for delineating the location of fluid infiltration into a formation. Also, data from the TL
provide temperature values to be used in the selection of appropriate temperature-corrected fluid
and formation parameters (such as fluid density and water compressibility) necessary in many cal-
culations.
Radioactive Tracer Log (RATL)
The Radioactive Tracer Log tool "traces" the movement of a radioactive source. This is ac-
complished by injecting a short-lived, radioactive isotope (usually1311) from one section of the
tool and recording its movement with a detection gamma ray package housed in another section
of the tool. As the radioactive isotope decays, it emits gamma rays that are detected by the
gamma ray apparatus. It is in this way that the position of the radioactive "slug" can be monitored
as it makes its way through the cased and uncased borehole. Thus it is another technique for
delineating fluid flow within the injection zone.
80
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APPENDIX B. REDUCTION AND ANALYSIS OF GEOPHYSICAL LOG DATA
Improved modeling techniques (correction charts) were used to interpret the advanced suite of
togs run during phase I and II. Use of these charts generally improved the accuracy of data ob-
tained from the phase 1 and II logs, compared with logs run during WDW2 construction. Figures
B-1, B-2, and B-3 are examples of the correction charts used. By using these modem logging
tools and incorporating improved analytical techniques, we were able to determine more accurate-
ly the following hydrogeologic data on geologic materials constituting the injection interval: the
forma-tion's matrix-corrected CNL porosity ([PORJNcor), matrix corrected BCS porosity
{[PORJBCScor), cross-plotted porosity ([PORJxp), secondary porosity ([PORJsec), true resistivity
(Rt), matrix lithology (MA), water saturation (SW), shale volume (Vsh), and qualitative permea-
bility (k). These values, computed at 2-foot intervals throughout the injection zone, are reported in
table B-1. The same parameters for geophysical logs run down WDW2 are reported in table B-2.
Figure B-1 (left) "Tornado" chart for Dual Induction- Figure B-2 Neutron porosity lithologic correction
Focused Log analysis (Dresser Atlas 1981). chart (Dresser Atlas 1981).
Table B-1 Data from geophysical logs run in the Devonian Observation Well
Depth
GR
(POR)
(POR)1
(POR)2
(ponf
(POR)4
RT*
MA*
SWT
Vsha
k*
GL
NIs
Ncor
t
BCScor
xp
sec
(ft)
(API)
<%)
(%)
(sec)
(%)
{%)
<%)
(ohm-m)
(%)
(%)
2,434
28
4.3
4.3
53
3.8
4.3
0.5
50.0
LS
100
6.2
N
36
40
5.0
5.0
53
3.8
5.0
1.2
65.0
LS
100
15.4
N
38
35
12.0
12.0
60
8.8
10.0
3.2
20.0
LS
100
11.5
N
40
25
18.0
18.0
69
15.1
16.4
2.9
11.0
LS
100
3.8
N
42
30
19.0
19.0
69
15.1
16.7
3.9
7.0
LS
100
7.7
Y
44
25
23.8
23.8
77
20.8
21.7
3.0
5.0
LS
100
3.8
Y
46
22
22.6
22.6
76
20.1
21.1
2.5
4.8
LS
100
1,5
Y
48
23
23.0
17.0
70
18.2
18.2
0.0
7.0
DOL
100
2.3
N
50
30
16.0
10.0
62
12.7
12.0
0.0
10.0
DOL
100
7.7
N
52
30
17.5
11.5
57
9.3
9.7
2.2
16.0
DOL
100
7.7
N
81
-------
Table B-1 continued
Depth
GR
(POR)
(POR)1
(POR)2
(POR)'
(POR)4
RT4
MA'
sw7
Vsh8
GL
NIs
Ncor
t
BCScor
*P
sec
(ft)
(API)
(%)
(%)
(sec)
(%)
(%)
(%)
(ohm-m)
(%)
(%)
54
22
19.0
13.0
60
11.3
11.7
1.7
13.0
DOL
100
1.5
N
56
17
22.0
16.0
62
12.7
13.3
3.3
9.0
DOL
100
0.0
N
58
20
20.6
14.6
63
13.4
13.6
1.2
10.0
DOL
100
0.0
N
60
28
21.8
15.8
61
12.0
12.7
3.8
9.0
DOL
100
6.2
N
62
27
24.6
18.6
65
14.8
15.6
3.8
7.0
DOL
100
5.4
Y
64
32
24.0
18.0
66
15.5
16.0
2.5
5.5
DOL
100
9.2
Y
66
22
25.5
19.5
70
18.2
18.5
1.3
4.8
DOL
100
1.5
Y
68
23
28.5
22.5
78
23.7
23.5
0.0
4.0
DOL
100
2.3
Y
70
17
29.2
23.2
82
26.5
26.0
0.0
3.3
DOL
100
0.0
Y
72
18
28.0
28.0
82
24.3
25.7
3.7
3.0
LS
100
0.0
Y
74
17
30.0
30.0
87
27.9
28.8
2.1
3.2
LS
100
0.0
Y
76
17
28.0
28.0
83
25.0
26.3
3.0
3.5
LS
100
0.0
Y
78
19
26.8
20.8
78
23.7
23.2
0.0
3.9
DOL
100
0.0
Y
80
17
26.3
20.3
77
23.0
22.6
0.0
4.4
DOL
100
0.0
Y
82
20
29.0
23.0
74
21.0
21.4
2.0
4.0
DOL
100
0.0
Y
84
24
23.5
17.5
71
18.9
18.5
0.0
4.6
DOL
100
3.1
Y
86
26
21.3
15.3
63
13.4
13.7
1.9
7.1
DOL
100
4.6
N
88
23
22.3
16.3
64
14.1
14.5
2.2
10.0
DOL
100
2.3
N
90
23
16.5
10.5
60
11.3
11.1
0.0
11.0
DOL
100
2.3
N
92
30
16.4
10.4
56
8.6
8.9
1.8
16.0
DOL
100
7.7
N
94
29
19.8
13.8
57
9.3
10.2
4.5
21.0
DOL
100
6.9
N
96
60
19.0
13.0
60
11.3
11.6
1.7
20.0
DOL
100
30.8
N
98
84
18.5
12.5
60
11.3
11.5
1.2
15.0
DOL
100
49.2
N
50
52
19.3
13.3
62
12.7
12.7
0.6
14.0
DOL
100
24.6
N
2
37
18.2
12.2
57
9.3
9.8
2.9
14.0
DOL
100
13.1
N
4
33
22.0
16.0
59
10.7
11.8
5.3
11.0
DOL
100
10.0
N
6
45
23.0
17.0
64
14.1
15.1
2.9
8.0
DOL
100
19.2
N
8
30
19.8
13.8
60
11.3
12.1
2.5
9.0
DOL
100
7.7
N
10
23
20.0
14.0
58
10.0
11.3
4.0
8.5
DOL
100
13.1
N
12
20
22.8
16.8
60
11.3
13.2
5.5
8.2
DOL
100
0.0
N
14
32
20.7
14.7
64
14.1
14.4
0.6
9.0
DOL
100
9.2
N
16
30
20.1
14.1
60
11.3
12.4
2.8
10.5
DOL
100
7.7
N
18
42
20.8
14.8
62
12.7
13.6
2.1
8.5
DOL
100
16.9
N
20
38
19.0
13.0
60
11.3
12.1
1.7
10.0
DOL
100
13.8
N
22
30
20.3
14.3
56
8.6
10.4
5.7
11.0
DOL
100
15.4
N
24
23
21.7
15.7
61
12.0
13.3
3.7
10.0
DOL
100
2.3
N
26
24
20.0
14.0
60
11.3
12.2
2.7
8.0
DOL
100
3.1
N
28
23
16.0
10.0
57
9.3
9.7
0.7
9.0
DOL
100
2.3
N
30
23
19.0
13.0
61
12.0
12.5
1.0
10.0
DOL
100
2.3
N
32
21
20.4
14.4
63
13.4
13.8
1.0
12.0
DOL
100
0.8
Y
2,534
33
22.5
16.5
60
11.3
12.2
5.2
10.0
DOL
100
10.0
Y
36
27
22.0
16.0
63
13.4
13.9
2.6
7.5
DOL
100
5.4
Y
38
28
24.3
18.3
65
14.8
15.5
3.5
6.5
DOL
100
6.2
Y
40
29
24.0
18.0
63
13.4
14.2
4.6
5.8
DOL
100
6.9
Y
42
35
17.3
11.3
61
12.0
11.8
0.0
7.1
DOL
100
11.5
N
44
40
16.5
10.5
59
10.7
10.6
0.0
9.0
DOL
100
15.4
N
46
42
21.3
15.3
63
13.4
13.7
1.9
8.5
DOL
100
16.9
Y
48
40
22.5
16.5
70
18.2
17.7
0.0
6.7
DOL
100
15.4
Y
50
40
20.6
14.6
66
15.5
15.1
0.0
6.7
DOL
100
15.4
Y
52
38
15.6
15.6
65
12.3
13.3
3.3
10.0
LS
100
13.8
N
54
29
8.6
8.6
57
6.6
7.4
2.0
20.0
LS
100
6.9
N
82
-------
Notes for table B-1
1.
2.
3.
4.
5.
6.
7.
8.
9.
Matrix corrected using figure B-2.
Matrix corrected using (POR)BCSoor = (tlog - tma)/(tf1 - tma) x 1/Cp,
where tma
tma
tf1
transit time from log
transit time of the matrix
constant for shale correction
1, since no shale correction is needed
47.6 x 10 sec/ft for limestone
43.5 x 10"6 sec/ft for dolomite
189x10"® sec/ft
tlog
tma
Cp
assume Cp
See figure B-3
(POR)sec = (POR)Ncor - (POR)BCScor
Since Rilm and Rild are approximately equal, a correction for invasion was not necessary; see
figure B-1
Taken from (POR)N versus t crossplot, figure B-3
Using SW2 = Ro/Rt = FRw/Rt = Rw/(por)2Rt = Rw/(por)xp2Rt,
from this, all zones were 100% water saturated.
Using Vsh = (GRIog - GRc1)/(GRsh - GRc1),
where GRIog = GR reading taken off log.
GRcl = GR reading from the zone with the lowest GR (10 @ 2,474 ft).
GRsh = GR reading from nearest shale zone (140 @ 2,242 ft).
Based on interpretation of MIL, Y denotes zone interpreted as having "significant" permeability.
N denotes zone interpreted as not having "significant" permeability. MIL response is adversely
affected by unevenness of borehole. A4-arm caliper run indicated a very even borehole:
6.3-inch diameter from 2,424 to 2,524 ft, 6.2-inch diameter from 2,525 to 2,556 ft, and 5.8-inch
diameter from 2,557 to 2,560 ft.
40 -i
35-
30-
25-
E
§
^ 2CH
c
0
w
"O
1 15H
-10 0 10 20 30 40
compensated neutron apparent limestone porosity (%)
Figure B-3 Compensated Neutron Log and Borehole Compensated Acoustilog porosity crossplot (Dresser
Atlas 1983).
83
-------
Table B-2* Data from existing geophysical logs run in WDW2**
DEPTH
gr
(POR)
(POR)
(POR)
(POR)
(POR)
RT
MA
SW
Vsh
k
GL
NIs
Ncor
t
BCSeor
xp
sec
(ft)
(API)
(%)
<%)
(sec)
(%)
(%)
(%)
(ohm-m)
(%)
(%)
2582
26
8.1
8.1
63
10.9
10.1
0.0
30.0
LS
90
4.6
N
84
30
10.0
10.0
66
13.0
12.2
0.0
28.0
LS
77
7.7
N
86
34
15.0
15.0
71
16.5
16.3
0.0
17.0
LS
74
10.8
N
88
38
14.7
14.7
73
18.0
17.1
0.0
13.0
LW
81
13.8
Y
90
37
13.5
13.5
73
18.0
16.9
0.0
13.0
LS
82
13.1
Y
92
26
7.8
11.1
68
8.8
10.0
2.3
20.0
SS
100
4.6
Y
94
29
6.1
9.3
65
7.1
8.2
2.2
38.0
SS
98
6.9
N
* For explanation of column headings, see table B-1.
** All togs used for study were run during well installation, and all were from WDW2 except the
sonic log (SL), which was from WDW1. Analysis methods used were those described in table B-
1. All depths measured are from Kelly Bushing (KB), which is 12 ft above ground level.
A brief discussion of the computation of the correction factors and assumptions used to analyze
the logging data follows. The analysis focused on data from intervals with higher relative per-
meabilities (as displayed by the Minilog and higher porosities from the CNL). These zones were
2,440 to 2,506 ft GL, 2,532 to 2,552 ft GL, and 2,572 to 2,582 ft GL as logged in DOW.
From figure B-4:
m = 1.54 or 1.76; this value is in close agreement with an assumed value of m = 2 for
limestone (Ls) and dolomite (Dol).
From Minilog:
Rm = 0.30 ohm-m
Therefore, from figure B-5,
Rmf= 0.23 ohm-m and
Rme= 0.41 ohm-m
From temperature log on WDW2,
Temperature @ 2,460 ft = 75.6° F.
Determine Rw:
Using Archie's Equation:
F = a/(por)2 = Ro/Rw and
SW"= Ro/Rt
where F = formation factor
Ro= true resistivity of the formation at 100% water saturation
(when SW= 100%)
n= saturation exponent
a= constant
For limestone and dolomite,
Assume a = 1,m = n = 2
Therefore,
F = 1/(por)2
SW2= Ro/Rt
@ 2473 ft assume SW = 100%
SVT= Ro/Rt
Ro = Rt
Assume Rt = Rildcorr
84
-------
Correct Rild for invasion, figure B-1
Rildcorr = 3ohm-m
Rt - 3 ohm-m
Ro= 3 ohm-m
Ro = F x Rw = Rw/(por)2
Rw = Rox(por)2
Porosity is needed; assume por - porxp of Sonic vs CNS
porxp = 28.7%
Therefore,
Rw = 0.247 ohm-m
These factors were used to analyze the logging data reported in tables B-1 and B-2. Important
hydrogeologic parameters of the injection zones are summarized in table B-3.
Table B-3 Summary of important formation characteristics
(POR)xp.ave = 16%
(POR)sec.ave = 1.98%
tave = 66.7x10"® sec/ft
tmax « 87x10"6 sec/ft
tmin = 56x10"8 see/ft
Rt.ave = 8.6 ohm-m
Vsh.ave - 8.05%
(POR)xp,max = 28.8%
(POR)sec.max = 5.7%
Rt.max - 21 ohm-m
Vsh.max « 49.2%
(POR)xp.min = 8.9%
Rt,min - 3 ohm-m
Vsh.min = 0.0%
Formation I it ho logy (based on 98 ft of "higher permeability, higher porosity" zone), 61.0% dolomite, 35.0%
limestone, and 4.0% sandstone.
100
(POR) Ncorr (%)
Figure B-4 Determination of the cementation factor.
85
-------
After reviewing the data, we concluded that the host formation, the Bailey Limestone, is com-
posed mainly of a clean dolomite with less than 20 percent shale throughout most of the interval
logged. Since the Bailey Limestone is predominantly a dolomite, secondary porosity is always a
consideration. A comparison of CNL and BCSL data suggests that secondary porosity may ac-
count for up to 10 percent of the total porosity. The intervals with higher relative permeability have
a slightly higher secondary porosity and therefore a higher total porosity.
The entire interval is primarily 100 percent water saturated and has a fluid resistance of ap-
proximately 0,247 ohm-m. At a formation temperature of about 80*F and depth of 2,460 feet GL,
the fluid composition is estimated to be approximately 24,000 ppm NaCI (fig. B-6).
As stated in chapter 3, one use of the core data was to verify data obtained from the geophysical
logs. Figure B-7 shows good agreement between the two methods for porosity data. Figure B-8 in-
dicates a close correlation between the two methods for true formation resistivity values (Rt); this
correlation becomes more apparent when the equation used to derive water saturation (Sw) is
reviewed,
o Rw
Sw= , . 2 W)
(por) x £
Sw is shown to be indirectly proportional to the square root of Rt.
Figure B-5 Rm-Rmf-Rmc relationships (Gearhart).
86
-------
500,000
.005 .01 02 .05 .1 .2 .5 1 2 5 10 20
fluid resistivity (ohms m2 m)
50 100
Figure B-6 NaCI concentration for different temperatures and fluid resistivities (Gearhart).
o
Q.
60-
40-
20-
• core porosity
~ log porosity
2440
2460
2480 2500
depth below KB (ft)
2520
2540
2560
Figure B-7 Core porosity versus log porosity (phase I, cross-plotted porosity) for WDW2.
100
s
OT
c
o
5
-------
APPENDIX C. BRUCITE FORMATION: PROPOSED MECHANISM OF FORMATION
The hydrogeologic site descriptions developed from phase I and phase II data (see chapter 3) dif-
fered from each other significantly; however, the reason for these differences was not readily ap-
parent. To develop a hypothesis to explain the results and increase our understanding of the site
hydrogeoiogy, we conducted additional analyses.
Core Analysis
Analysis of sidewall core obtained during phase II was critical to the development of a hypothesis
to explain the discrepancies described in chapter 3. Our core analysis included hydraulic testing,
mineralogic analysis, and scanning electron microscope (SEM) investigation.
Hydraulic Testing
Hydraulic testing provided no hard evidence to resolve the discrepancies between phase I and
phase II data. Injection zones 1,2, and 3 (fig. C-1) had abnormally high porosities and per-
meabilities, but core analysis data did not agree with the results from the CSFL. First, the zone
from 2,468 to 2,496 feet KB showed some injection potential. Core analysis indicated that at least
some portions of this zone (e.g., 2,481.0 ft KB) were not permeable enough to allow fluid flow;
however, most of this zone appeared to have sufficient permeability. Second, the core from
2539.5 feet KB seemed to have sufficient porosity and permeability to allow fluid flow, but the
CSFL did not show any flow at this location. On the basis of CSFL results, zone 3 should have
had the highest porosity and permeability, zone 2 the next highest, and zone 1 the lowest; how-
ever, core analysis indicated just the opposite. Therefore, the same discrepancies were en-
countered with core analysis as with geophysical logging.
Mineralogic Analysis
Cores were also analyzed for their mineralogical content. Brucite was found in the anomalous
zones, and its presence was confirmed by x-ray diffraction (XRD) analysis. Brucite was not ex-
pected to be present in the injection system environment of WDW2. Brucite is normally found in
veins in serpentine and basic rocks and as flakes scattered through some marbles (Pough 1953).
Roy et al. (1989) analyzed a sample of the native formation brine taken from the DOW. The
sample was vastly undersaturated with respect to brucite, Mg(OH)2. The ion activity product of
Mg and OH" (brucite) in the sample was 3 percent of that predicted by the solubility of brucite
determined by thermodynamic modeling (Roy 1987).
Mineralogical analysis conducted on a few representative samples of the original well cuttings col-
lected during the drilling of WDW2 indicated that none of these samples contained brucite.
Downhole geophysical data (table 2) also confirmed the absence of brucite and indicated that
prior to injection, the disposal horizon was predominantly dolomitic.
Apparently the injected waste, which consisted of a number of organics in a very alkaline
(pH>12), brinelike solution, created an environment in the injection system that promoted the for-
mation of brucite. Although the waste had a component of Mg2+, dolomite (from injection zone
rock) was the most likely source of Mg2+ for two reasons. First, an increase in the brucite con-
centration accompanied a corresponding decrease in the dolomite concentration (fig. C-2).
Second, the porosity throughout the injection zone subsequent to brucite precipitation should
have been lower than the original (pre-injection) porosity if the brine was the source of the Mg2+.
Data from log analysis did not indicate a decrease in porosity. Therefore, on the basis of available
data, the most plausible hypothesis is that dissolution of dolomite from injection zone rock
released magnesium, which then combined with the OH" in the waste stream to form brucite.
If this hypothesis is correct, the zones that originally had the highest porosities and permeabilities
would accept the greatest volume of waste fluid and thus would show the highest brucite con-
88
-------
New Albany Group
Lingle
Grand Tower
Bailey Limestone
Moccasin Springs Fm
confining unit
impermeable unit
^ permeable unit
Figure C1 Injection system in
WDW2 indicating permeable and
nonpermeable zones delineated
with the aid of geophysical logging.
centrations. Table C-1 gives porosity arid brucite percentages for the cored intervals. For com-
parison, the Sidewall Neutron Log run during well construction was used to obtain original
porosity data. Five intervals were identified and ranked on the basis of porosity characteristics.
Zones with higher average porosity were given a higher porosity ranking.
Table C-2 shows the five highest ranked zones with their corresponding average brucite con-
centrations, air permeabilities (ka), and percentages of total flow (from the CSFL). These data
indicate that the presence of brucite has a profound effect on fluid movement. However,
laboratory permeability values for zones with higher brucite concentrations were greater than the
values for zones with lower brucite concentrations, and laboratory porosity values for zones with
higher brucite concentrations were similar to the pre-injection porosities.
89
-------
In an attempt to explain this finding, we reviewed the analytical procedure used to determine per-
meability. Laboratory permeabilities were performed on dried samples. If the cations (Na+) that
may have been lodged between the brucite layers were lost during drying, a volume reduction in
brucite would occur. Therefore, in samples with high brucite concentrations, abnormally high
permeability measurements could be encountered, and the cores at 2,479.5,2,481.0,2,490.5,
2,491.5, 2,439.5, and 2,560.5 ft KB should have higher permeabilities than expected. These
depths corresponded to the zones in which discrepancies were noted between core and CSFL
analysis. The anomalously high core permeabilities appeared to be the result of a volume
reduction of the brucite upon drying.
Table C-1 Core porosities and brucite concentrations
Depth
Original
(KB)
porosity
Porosity
Brucite
(ft)
(%)
ranking
(wt %)
2450.5
23
3
9
2451.5
25
3
21
2456.5
24
3
0
2462.5
17
18
2463.5
19
"
22
2479.5
30+
1
45
2481
30+
1
45
2484.5
30+
1
12
2490.5
30+
1
39
2491.5
30
1
31
2508.5
18
_
26
2509.5
19
35
2539.5
27
2
41
2551.5
20
2
38
2555
24
4
7
2556.5
28
2
45
2560.5
28
2
45
2572.5
4
2
2573.5
5
"
0
2588.5
15
5
0
2605
6
0
2606
6
-
0
Table C-2 Effect of brucite concentration on total flow
Porosity
Brucite
Ave ka
Total Flow
ranking
(wt %)
(md)
(vol %)
1
40
1
0
2
42.3
0.1
0
3
10
0.6
14
4
7
0.06
36
5
0
0.02
50
90
-------
depth below KB (ft)
Figure C-2 Core composition: dolomite and brucite in WDW2.
On the basis of available data, this explanation appeared to be reasonable, but two problems with
the results remained unresolved: (1) the cores at 2,462.5,2,463.5,2,508.5, and 2,509.5 ft KB
showed slightly higher than expected brucite concentrations (approximately 25% brucite), and (2)
the core at 2,484.5 ft KB had an extremely high core permeability (ka = 14.97 md) but a relatively
low concentration of brucite (12%). Scanning Electron Microscope (SEM) analysis was performed
on selected core samples in an attempt to resolve these discrepancies, gain additional informa-
tion on the factors affecting fluid flow, and confirm some of the assumptions inherent in the pre-
vious discussion.
SEM Analysis
Eight cores chosen for analysis represented the three injection zones and the major areas where
anomalous results were encountered by various analytical procedures (e.g., core analysis, CSFL,
and standard geophysical logging). Generally, two magnifications were used per sample: ap-
proximately 100x to show the general porosity type and any large-scale features such as fractur-
ing, and 1,000x to show the pore geometry and other small-scale features. Although a detailed
discussion of SEM analysis results is beyond the scope of this project, a few generalizations can
be made to help resolve the discrepancies noted.
SEM analysis was performed on dried samples; therefore, the effect of cation adsorption into the
crystal lattice of brucite was assumed to be unrecognizable.
Data from historical and phase I logging indicated that the core at 2,484.5 ft KB should have had
a high injection potential. When the CSFL indicated a lack of fluid flow into this zone, we
reasoned—on the basis of core analysis—that the lack of flow into this zone could have been due
to the presence of brucite in the sample. However, only 12 percent brucite was found in this core,
91
-------
compared with an average of 40 percent in the other adjacent samples. Another explanation for
the lack of flow was obviously needed. Figures C-3 and C-4 indicate that the predominant type of
porosity in this sample is fracture porosity. Figure C-3 shows that the fracturing is discontinuous
on a large scale. Figure C-4 is a close-up of the fracture depicted in figure C-3. The platy material
on the fracture walls was interpreted to be brucite.
Another sample selected was the core at 2,479.5 feet KB, which is from the same zone as the
previous sample. No fractures can be seen in figures C-5 and C-6, and the crystals and matrix of
the sample are coated. Core analysis indicated that this sample was 45 percent brucite, so this
coating was assumed to be brucite. With such a widespread occurrence of brucite, the decrease
in permeability seems reasonable.
A sample from the uppermost injection zone (2,456.5 ft KB) (figs. C-7 and C-8) is free of the coat-
ing present in the previous samples. Core analysis indicated that this sample had no brucite,
which agrees with SEM analysis and the supposition that brucite has not affected fluid flow in the
uppermost injection zone.
The hypothesis used to resolve the brucite formation explains the available data and was con-
firmed to some extent by SEM analysis. But to evaluate this hypothesis more fully, additional work
beyond the scope of this project is necessary.
Additional Research
To support the hypothesis developed regarding brucite formation, the following work should be
done. A hydrogeochemical investigation of the Velsicol waste stream and the Devonian lime-
stone, similar to that of Roy et al. (1989), should be conducted. Core from the DOW could be
used in this type of investigation. This type of work would help define the conditions favorable for
brucite formation.
92
-------
0.5mm
Figure C-3 SEM photograph of core at 2,484.5 feet KB (x58.5).
20
Figure C-4 SEM photograph of core at 2,484.5 ft KB (x 1,050).
93
-------
0.5mm
Figure C-5 SEM photograph of core at 2,479.5 KB (x80).
Figure C-6 SEM photograph of core at 2,479.5 KB (x1,080).
94
-------
200 |xm
Figure C-7 SEM photograph of core at 2,456.5 KB (x113).
20
Figure C-8 SEM photograph of core at 2,456.5 feet KB (x1,160).
95
-------
APPENDIX D. SENSITIVITY ANALYSIS
A rigorous sensitivity analysis as described by Yeh (1986) was not conducted. The sensitivity
analysis conducted for this project involves the variation of significant parameters and the effect
of this variation on head buildup (Ah) at the DOW, the parameter of interest. The significance of
various parameters (injection rate, hydraulic conductivity, etc.) was observed during the validation
and calibration stages of modeling. On the basis of these observations, sensitivity analysis was
conducted for the following parameters: boundary conditions, injection rate, rock compressibility,
fluid compressibility, hydraulic conductivity, and anisotropy.
Throughout this phase of the project, the same conceptual model as depicted in figure D-1 was
used unless otherwise noted. The injection system was modeled using cylindrical coordinates
with 60 nodes in the r-direction and 22 nodes in the z-direction. A no-flow boundary condition was
applied at the upper and lower boundaries, while an aquifer influence function (AIF) condition was
applied at the radial boundary.
Boundary Conditions
Boundary conditions (BC) are the most difficult and critical issue in the development of a concep-
tual model for a numerical modeling study and must be selected carefully (Franke and Reilly
1987). In all cases, the upper and lower boundaries were modeled as no-flow boundaries.
The type and distance of the radial boundary from the injection well were varied. For the pur-
poses of comparison, VELS14I was considered the baseline run. Five other runs were made in
order to note the effect of the boundary condition on head buildup at various locations within the
injection system. Table D-1 summarizes the types of boundary conditions and results.
The results of VELS14G2 indicate that the no-flow boundary condition did not cause an increase
in head buildup at the DOW during the 14-day period investigated, but a slight increase in Ah
occurred at the radial boundary. For VELS14H, the radial boundary is located farther from the in-
jection well than in VELS14G2; no Ah was observed at the radial boundary. These two runs and
the other runs of the VELS14 series show that the radial boundary exerted no real influence on
the head buildup at the DOW (r = 505.95 m) during the time period investigated.
VELS14I and VELS14I2 indicate the effect of the intrinsic permeability of the aquifer influence
region (kAiF). A reduction in kAiF may increase the Ah observed at the radial boundary. Although
Stratigraphy
New Albany Group,
Lingle and Grand Tower
Limestones
_ ____ T
Bailey Li
mestone
>
'
Moccasin Springs Formation
elev. above
reference (m)
128.29
Hydrogeologic Role
K
(m2)
55.76
52.71
24.06
22.23
14.31
11.28
0
HgSgsupper confining unitwSSHi
4.35 x 10"21
upper injection zone
2.51 x 1CT11
2.30 X 10 "
middle injection zone
9.65 x 10"11
2.99 x 10*14
lower injection zone
7.72 x 10 "
basa: confining unit>
9.68 x 10"14
Figure D-1 Conceptual model 1 of the injection system.
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Table D-1 Effect of boundary conditions on head buildup
No. of
Radius
Type1
Ah @ DOW3
Ah @ radial
Run
r-nodes
(m)
of BC
kAiF2 (m2)
(m)
boundary (m)
VELS14I
60
15870.9
AIF
1.00X10"11
1.28
0.011= 14.0 days
VELS14G2
60
15870.9
NF
1.28
0.021 = 7.16 days
VELS14H
60
35703.0
NF
1.28
0.001< 14.0 days
VELS14I2
60
15870.9
AIF
1.00x10"12
1.28
0.021= 14.0 days
VELS18H2
60
15870.9
AIF
1.00X10"11
1.25
—
VELS18J
50
2090.8
AIF
1.00x10"11
0.75
—
Notes: (1) AIF = aquifer influence boundary condition; NF = no-flow boundary condition; (2) kAiF = intrinsic
permeability of aquifer influence region; (3) all values given at t = 14.00 days.
not shown in Table D-1, if kAiF were reduced, the cumulative fluid outflow via the AIF boundary
also would be reduced. In this case, the cumulative fluid outflow across the radial boundary, in
terms of the total volume of fluid injected, was reduced from 3.0 percent (VELS14I) to 0.69 per-
cent (VELS14I2) when kAiF was reduced one order of magnitude.
Over longer periods, the radial boundary would certainly influence the head buildup at the DOW.
Thus the use of an AIF BC appeared to be a better choice for the radial boundary, especially
when the model is used as a tool to predict long-term (30-year) effects of injection upon the sys-
tem. In addition, the regional hydrogeologic investigation covered a 10-mile (16,000-m) radius
from the well; thus use of a radius larger than 10 miles was considered speculative.
Two runs from the VELS18 series are included to show the effect of the position of the AIF BC.
The conceptual model for the VELS18 series is more complex than the VELS14 series and in-
cludes a thicker sequence of geologic materials (fig. D-2). The results from VELS18H2 are in
agreement with VELS14I, allowing for a slightly lower head buildup for VELS18H2 due to the
greater thickness of compressible geologic materials. For VELS18J, distance to the radial
Stratigraphy
elev. above
reference (m)
178.28
Hydrogeologic Role
K
(m2)
Bordon Siltstone
"Carper sand"
New Albany Group,
Lingle and Grand Tower
Limestones
Bailey Limestone
24.06
Moccasin Springs Formation
139.57
128.29
K,
K2
55.76
52.71
14.31
11.28
0
; ;i::./:|.:C°Ofi'ling Unit1::;:;:-;-.::;::.:.
4.35 x 10'21
1st overlying aquifer
5.0 x 10 "
9
V
V
V
Sjupper confining unit
4.35 x 10"21
2.51 x 10"
upper injection zone j
2.30 x/10:'"
middle injection zone
9.65 x 10 "
2.99 x 10"'4
lower injection zone
7.72 x 10_"
¦: . basa' confining unit
9.68 x 10"14
<6
Radial distance (m)
Figure D-2 Conceptual model 2 of the injection system.
97
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boundary was much closer than for VELS18H2. In addition, the head buildup at the DOW was
much lower, although kAiF is the same for both runs. For both VELS18H2 and VELS18J, the AIF
zone is more transmissive than the inner discretized zone; therefore, decreasing the radial dis-
tance of this zone from the injection well allows fluid to move more readily and with less head buil-
dup. The results of VELS18H2 and VELS18J indicate the effect of the location of the boundary
and the need to properly define the intrinsic permeability of the aquifer influence region.
Injection Rate
Three runs were made to investigate the effect of the injection rate upon head buildup at the
DOW. VELS14I (q = 1.820x10"2 m3/sec) is the baseline run. For VELS15A, the injection rate was
increased 10 percent, q = 2.00 2x10 m3/sec. For VELS15B, the injection rate was decreased
10 percent to 1.638x10"2 m3/'sec. Figure D-3 shows the Ah at the DOW with time. Increasing the
qby 10 percent resulted in a 10.2-percent increase in Ah. The increase in Ah was noticeable after
several hours of injection. In a similar fashion, a 10-percent reduction in the injection rate resulted
in a 9.4-percent decrease in Ah. This decrease was also noticeable after several hours of injec-
tion. Round-off error for the percentage increase/decrease of Ah was responsible for these values
not being equal and the deviation of these values from 10 percent as predicted by Darcy's Law.
Rock Compressibility
Storativity may be defined according to the following equation (Lohman 1972).
S = rr?b(p+ a/n) [D-1]
where S = storativity (-)
n = porosity (-}
Y = unit weight of fluid (kg/m3)
b = aquifer thickness (m)
P = fluid compressibility (Pa-1)
a = rock compressibility (Pa1)
Rock compressibility (a) is one of two major components of storativity. For HST3D, Kipp (1987) in-
dicated that it is more convenient to use rock and fluid compressibility than a storativity term,
since fluid density (i.e., unit weight) may be variable.
Three runs were used to investigate the effects of rock compressibility. VELS14I was the baseline
run with a = 4.50x10"10 Pa"1. For VELS15C, rock compressibility was reduced 10 percent to a =
4.05x10"10. For VELS15D, a was increased 10 percent, a = 4.95x10"10. Figure D-4 shows the
results of the runs. Decreasing a by 10 percent resulted in a 1.6-percent increase in Ah at the
DOW. Similarly, a 10-percent increase in a resulted in a 1.6-percent decrease in Ah. The increase
and decrease in Ah were evident after several hours of injection.
Fluid Compressibility
Fluid compressibility (jJ) is the other major component of storativity. VELS14I, VELS15G, and
VELS15H were used to investigate the effect of varying fluid compressibility on the head buildup
at the DOW. For VELS14I, p = 4.00x10"10 Pa"1. A 10-percent reduction in p was used for
VELS15G, p = 3.60x10"10. For VELS15H, p was increased to p = 4.40x10"10.
Figure D-5 shows the results from these runs. Decreasing p did not cause any change in Ah. In-
creasing p produced a negligible change in Ah, which was probably due to round-off error. The
lack of sensitivity of Ah to p can easily be explained. Referring back to equation D-1, one can see
that S is proportional to the quantity (P + a/n). For the situation investigated here, a/n was ap-
proximately 8 times larger than p; thus minor changes in p did not affect S and did not affect Ah.
98
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1.6
1.6
1 10 v 100
100
Time (hours)
Time (hours)
Figure D-3 (left) Sensitivity analysis: effect of
injection rate.
Figure D-4 Sensitivity analysis: effect of rock
compressibility.
Hydraulic Conductivity
The results from VELS14I, VELS15I, and VELS15J were used to demonstrate the effect of
hydraulic conductivity on Ah. For VELS15I, the hydraulic conductivity of each of the 7 layers was
reduced by 10 percent, compared with the hydraulic conductivity values used for VELS14I.
Similarly, the hydraulic conductivity values used in VELS15J were all increased by 10 percent.
Figure D-6 shows the results for all runs. As expected, decreasing the hydraulic conductivity
resulted in an increase in Ah observed at the DOW. A 10-percent decrease in hydraulic conduc-
tivity resulted in a 9.4-percent increase (within round-off error of 10 percent) in Ah at the DOW. In-
creasing the hydraulic conductivity by 10 percent caused only a 7-percent decrease in Ah at the
DOW. The deviation of this value from 10 percent, as predicted by Darcy's Law, is due to the
Kaif. The Kaif for VELS15J was not increased from the value used for VELS14I, causing the
head build-up within the inner aquifer region to be higher than anticipated.
Anisotropic Conditions
To this point, isotropic conditions have been assumed. On the basis of the hydrogeologic and
geophysical tests conducted at the site during the project, it was not possible to establish the
predominance of isotropic or anisotropic conditions. Thus, this series of runs was conducted to in-
vestigate the effect of this assumption.
Two runs were used to investigate this effect, VELS14I and VELS15K. Isotropic conditions (i.e.,
kr/kz = 1) were assumed for VELS14I. For VELS15K, kz was decreased so that k was 10 times
greater in the radial direction than in the vertical direction (i.e. kr/kz =10). Figure D-7 indicates
that under anisotropic conditions, Ah observed at the DOW was lower by approximately 2 percent
than under isotropic conditions. Thus, if the assumption of isotropic conditions is not correct, the
hydraulic conductivity of the geologic materials determined during model calibration may need to
be reduced by nearly 2 percent.
99
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Summary of Sensitivity Analysis
On the basis of the preceding sensitivity analysis, injection rate and hydraulic conductivity were
the most sensitive input parameters. That is, a given change in injection rate or hydraulic conduc-
tivity produced the largest change in Ah observed at the DOW. The type of boundary condition
and the location of the boundary can also have a significant effect on the head buildup predicted
by the model. In decreasing order, the most sensitive parameters were injection rate and
hydraulic conductivity, rock compressibility, anisotropy, and fluid compressibility.
n "T i Til 11 1 1—i I I j 111 1 i—i > i i m 1 r
1 10 x 100
Time (hours)
Figure D-5 (left) Sensitivity analysis: effect of fluid
compressibility.
1 10
Time (hours)
Figure 0-6 Sensitivity analysis; effect of hydraulic
conductivity.
Time (hours)
Figure D-7 Sensitivity analysis: effect of anisotropy.
100
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