EPA Contract No. 68-01-6288	amir* an x-
January 1984	SMC Martin
900 West Valley Forge Road
RO. Box 859
Valley Forge, Pannsylvama 19482
INJECTION WELL PROCEDURES MANUAL:
A CASE STUDY OF THE RAFT RIVER
GEOTHERMAL PROJECT, IDAHO
s^ 'X
$ II
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ui
0
V.
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Office of Drinking Water
Ground Water Protection Branch
U.S. Environmental Protection Agency
Washington, DC 20460

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December 1983
INJECTION WELL PROCEDURES
MANUAL: A CASE STUDY OF THE
RAFT RIVER GEOTHERMAL PROJECT, IDAHO
by
David L. Kraus
Gregory J. Burgdorf
William Zamor
SMC Martin Inc.
900 West Valley Forge Road
P. O. Box 859
Valley Forge, PA 19482
EPA Contract #68-01-6288
Task #8
Project Officer
Mario Salazar
Task Officers
Joseph F. Keely
Harold M. Scott

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TABLE OF CONTENTS
Page
I. INTRODUCTION	1
Background	1
Purpose and Scope	1
Use of Manual	2
II. PROJECT HISTORY	4
III. PHYSICAL SETTING	11
Geography	11
Review Comments	13
Geology	15
General	15
Stratigraphy	15
Hydrogeology	18
Geological Structure	20
Review Comments	24
IV. WELL CONSTRUCTION AND COMPLETION TECHNIQUES	31
Drilling and Construction Summary of
Well RRGI-6	31
Drilling and Construction Summary of
Well RRGI-7	34
Review Comments	38
V. WELL LOGGING AND TESTING	4 2
Borehole Geophysical Analysis	42
Introduction	42
The Logging Program	42
Induction Log	43
SP Curve	44
Acoustic, Density, Neutron Logs	45
Other Borehole Tools/Miscel-
laneous Indicators for
Fracture Detection	47
Injection Zone Testing	47
Pump and Injection Tests	47
Review Comments	54
First Case	54
Well RRGI-7	56
VI. AREA OF REVIEW CALCULATIONS	58
Potential Injection Formulation	58
Review Comments	62
VII. GEOTHERMAL FLUID CHARACTERISTICS AND
COMPATIBILITY TESTS	65
Water Chemistry	65

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TABLE OF CONTENTS
(Continued)
Page
Water Compatibility Test	67
Filter Studies	71
Review Comments	73
VIII. MONITORING WELL PROGRAM	77
General Ground-Water Trends and Test
Responses	77
Individual. Monitoring Well Responses	79
Review Comments	82
IX. SUMMARY	8 5
REFERENCES
APPENDIX A: Conversion Factors
APPENDIX B: Permit Application Checklists

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1
2
3
4
5a
5b
6
7
8
9
10
11
12
13
Page
5
9
16
19
22
22
25
29
33
37
46
50
51
55
LIST OF FIGURES
Raft River Well Field Location
(from Dolenc et al, 1981).
Location and Construction Features of
Raft River Well System (from
Dolenc et al, 1981).
Raft River Valley and Major Structural
Features Adjoining the Valley (from
Dolenc et al, 1981).
Water Level Contours in the Raft River
Valley (from Walker et al, 1970).
An Early Interpretation of the Bridge
Fault Zone (from Dolenc et al, 1981).
A Later Interpretation of the Bridge
Fault Zone (from Dolenc et al, 1981).
Site Suitability for Deep Well Injection
(from Reeder et al, 1977).
Seismic Risk Areas of the United States
(from Algermisen, 1969).
Well Construction of RRGI-6 (from Miller
and Prestwich, 1979a).
Well Construction of RRGI-7 (from Miller
and Prestwich, 1979b).
Bulk Density-Porosity Plot from
Schlumberger Modified to Show Raft
River Rock Types (from
Dolenc, et al 1981).
Pressure Buildup During Injection Test of
Well RRGI-6 (from Dolenc et al, 1981).
Pressure Buildup During Injection Test
of Well RRGI-7 (from Dolenc et al, 1981).
Plot of Pressure Buildup Data from an
Injection Test of the Mt. Simon Formation
in Ohio (from Everett, 1980).

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LIST OF TABLES
Table
1
2
3
4
5
6
7
Page
Logs Run on RRGI-6 (from
Dolenc et al, 1981).	32
Logs Run on RRGI-7 (from
Dolenc et al, 1981).	35
Summary of Well RRGI-6 Parameters
(from Dolenc et al, 1981).	52
Summary of Well RRGI-7 Parameters
(from Dolenc et al, 1981).	53
Predicted Pressure Response (kPa) at the
end of 1 Year (t- ) and 3 Years (t.,) of
Operation, at 85* Usage, in Each Well
(from Dolenc et al, 1981).	59
Selected Physical and Chemical Data from
the Raft River Project Wells (from
Dolenc et al, 1981).	66
Water Compatibility for Geothermal
Wells RRGE-1, RRGE-2, RRGE-3, RRGP-5
and RRGI-6 (from Dolenc et al, 1981).	69
8
Monitoring Well Summary
(from Dolenc et al, 1981).
78

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I. INTRODUCTION
Background
The Safe Drinking Water Act (SDWA) was adopted in 1974
in an effort to correct deficiencies of the Clean Water Act
of 1972. The SDWA incorporated several provisions relating
specifically to ground-water protection.
Among these provisions is the requirement that the U.S.
Environmental Protection Agency (EPA) develop minimum require-
ments for state programs regarding the protection of underground
sources of drinking water (USDWs) from pollution by subsurface
fluid injection. The SDWA also requires that EPA adopt and
administer an Underground Injection Control (UIC) program in
states failing to meet those requirements or in those states
that decline primacy with regards to a UIC program. In
administering the UIC program, the responsibilities of each
EPA regional office will include reviewing permit applications
for injection facilities.
Purpose and Scope
Under EPA Contract #68-01-6288, Task #8, SMC Martin was
requested to prepare an injection well procedures manual
which would provide EPA Region X with assistance in the
evaluation of injection well permit applications. The
manual discusses a real world example of an injection well
located in a complex hydrogeologic setting and is written
for an audience familiar with injection well technology,
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hydrogeology and the Underground Injection Control Program
(UIC). The case study was to be used as an aid to the
Regional staff to review, condition and approve or disapprove
a permit application.
The selected case study describes operations at the
Raft River Geothermal Field, Idaho. The case study includes
detailed discussion and analysis on the site geology and
hydrogeology, disposal well siting, construction and comple-
tion techniques, geophysical and mechanical integrity testing,
area of review calculations, wastewater characteristics and
compatibility tests, and design of the monitoring well
network. These topics were chosen on their importance in
the siting and permitting of an injection facility under the
UIC program, and the availability of information to develop
suitable evaluations of the injection well system.
Use of Manual
The case study presented in this manual is the Raft
River Geothermal Project, Idaho operated by U.S. Department
of Energy. The technical investigations were prepared and
reported by EG&G, Idaho. In the preparation of this case
study, information was extracted from several published EG&G
reports. This case study was not intended to represent a
precise summary of all facets of the Raft River operation,
but only to present selected data relevant to a permit
reviewer.
2

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The case study is written in an instructional format.
Although the case study wells are Class V geothermal injection
wells, the requirements of the UIC program for all five
classes of injection wells and additional geologic and
engineering factors are discussed. At the conclusion of a
section or chapter, critical topics which should be considered
in the approval or disapproval of a permit application are
noted. A discussion is then presented for each topic considering
basic geologic rationale and the UIC program requirements.
In addition, the reader is given technical questions to
answer or evaluate in several chapters.
Figures in this manual were taken directly from several
publications and contain metric and/or English units. Unit
conversion procedures were not attempted on the manual's
figures. The permit writer must be knowledgeable of both
unit systems since permit applications may contain either
unit system. Conversion factors are given in Appendix A to
aid the permit writer.
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IX. PROJECT HISTORY
The Raft River Geothermal 5MW(e) Pilot Plant, located
in the Raft River Valley of south-central Idaho, utilizes a
supply and injection system which is an integrated network
of production and injection wells designed to supply the
power plant with moderate temperature geothermal fluid.
This network consists of three designated production wells;
one backup production well; two injection wells; several
monitoring wells, and one deep-well whose production was too
low for pipeline connection (Figure 1).
In late 1974 and early 1975, after an extensive feasibility
study for a geothermally based electric generating station
was completed, a cooperative venture was initiated by the
U.S. Department of Energy's Idaho Operations Office (DOE-ID),
the Raft River Rural Electrical Cooperative, and the Idatyo
Department of Water Resources (IDWR), to drill a geothermal
exploration well in the southern Raft River Valley of Idaho.
The U.S. Geological Survey (USGS) conducted an intensive
exploration program to define an optimum location for a
production well in 1973-1974; the site ultimately selected
was located between two shallow boiling water wells along
the southwest alluvial fan of the Jim Sage Mountains. A.
major consideration in selecting this location was the
anticipated interception, at depth, of the Bridge Fault.
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R26E
BRGE-1
(1521m)
MW-2
(174m)
ftUSGS-2
jfcRRGE-3 (244m)\
*(17B9m)	*
~RRfll -6 /
'1176m)
'	(311m)
Leoend
25
Geothermal wells
fr Monitor wells
 Irrigation wells
Well depths shown in parentheses
1 km
Counlour interval 10 m
i
Figure 1. Raft River Well Field Location (from Dolenc et al, 1981).

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The Raft River Geothermal Exploration Well No. 1 (RRGE-1),
drilled to a total depth of 4,990 feet (1,521m), approximately
500 feet (152m) into basement rock, encountered 295F (146C)
bottomhole temperatures with an artesian flow. This well
verified the existence of a low-salinity hydrothermal resource
approaching 300F (150C). The major production zone in
RRGE-1 was found from 3,700 feet (1,128m) to 4,500 feet
(1,372m).
A second exploration well, RRGE-2, spudded in approxi-
mately one month later, was also designed to intercept the
Bridge Fault at depth. The well was drilled to a total
depth of 4,987 feet (1,825m), over 980 feet (300m) into the
Precambrian basement rock. The major production zone encoun-
tered at this well location was from 4,249 feet (1,295m) to
4,800 feet (1463m). Fracturing of the zone from 5,000 feet
(1524m) to 5,200 feet (1,585m) contributed little to the
artesian flow of this well.
After a period of flow testing, wells RRGE-1 and RRGE-2
were injection tested for about five months. In 1976,
RRGE-2 was deepened to a total depth of 6,540 feet (1,994m).
As no fractured sections were encountered, this deepening of
the well did not result in any significant increase in flow.
In 1976, RRGE-3 was spudded 900 feet (274m) southeast
of RRGE-2. This well was drilled to determine if the geothermal
resource extended beyond the fault zone in the center of the
6

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valley. This well was originally planned to have three
directional legs in an attempt to increase production and
minimize well drilling costs. The deepest leg, drilled to a
total depth of 5,920 feet (1,804m), produced the highest
flow rate of all the legs. The maximum fluid temperature
encountered was 302F (150C), but the flow from the three
legs was less than that from RRGE-1 and RRGE-2.
Based upon the drilling experience with the RRGE-1 and
RRGE-2 wells, namely, the encountering of a permeable zone
between 1,600 feet (448m) and 3,000 feet (915m) the fourth
geothermal well, RRGI-4, was drilled with the intent of its
use for return injection purposes. This well, spudded
in 1977, was drilled to a total depth of 2,840 feet (866m)
and uncased from 1,900 feet (580m) to its total depth.
Injection testing of RRGI-4 in 1978 revealed significant
pressure responses in nearby monitoring wells MW-1, USGS-3,
and BLM offset. An increased water level in the monitoring
wells during injection testing indicated that a hydraulic
connection existed between the injection 2one and the shallow
aquifer system, and that the use of RRGI-4 as an injection
well could result in contamination of the shallow aquifer
system.
As a result of these injection tests, the decision was
made that injection operations would be more appropriate in
a deeper zone near the RRGE-3 well. Consequently, RRGI-6
was spudded in 1978, and drilled to a total depth of 3,845 feet
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(1,172m). The well was uncased (open hole) from 1,700 ft
(518m) to the total depth, leaving a large zone for injection.
Indications are that the zone can accept up to 8 50 gpm
(536L/s).
As it had become evident that the geothermal reservoir
was fracture controlled, another attempt was made to intercept
the Horse Well and/or Bridge Fault systems at depth with
RRGP-5. An additional injection well, RRGI-7, was drilled
2,300 feet (700m) southwest of the RRGI-6 well and was
nearly identical in construction with RRGI-6. It was cased
to 2,040 feet (622m) and uncased (open hole) to its total
depth of 3,845 feet (1,172m).
Drilling at the project site was completed in 1978 with
the deepening and conversion of RRGI-4 (determined unsuitable
for injection because of hydraulic connection with shallow
aquifer system) into a production well (RRGP-4). Originally
planned as triple-legged well, only two legs were drilled
because of low flows encountered and funding constraints.
The legs were drilled to a total depth of 5,420 feet (1,652m)
and 5,510 feet (1,558m), but maximum artesian flow realized
was only about 51 gpm (3.2L/s). In order to attempt to
stimulate the flow in one leg of RRGP-4, hydraulic fracturing
was performed. Well construction details and well locations
are shown on Figure 2.
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RRGE-2
Power
plant
J
RRQE-1
RRGP5ORRGP4
Location of
wells at
geothermal site
RRGE^^
m
RRGP-5
1490 m
RRGE-1
1474 m
RRGI6
RRGI-7
RRGE-2
1489 m
RRGP-4
1474 m
RRGE-3
1481 m
RRGI-7
1480 m
RRGI-6
1468 m
Ground level
elevation
50 cm
casing
to 52 m
34 cm
casing
to 456 m
1493 m
50 cm
casing
to
|275 m
34 cm
casing
to
1104m
50 cm
casing
to
270 m
1497 m lj
1521 m
34 cm
casing
1288 m
50 cm
casing
to 122 m
34 cm
casing
to 556 m
25 cm liner
from 461 m
to 1054 m
34 cm
casing
to 422 m
25 cm
casing
from 393 m
to 1291m
50 cm
casing
to 41 m
34 cm
casing
to6!9m
50 cm
casing to
32 m
34 cm
casing
to 514 m
1172 m
1172 m
1558 m
1652 m
1686 m
1804 m 1784
All depths are
referenced to
ground level
1994 m
Figure 2. Locations and Construction Features of Raft River
Well System (from Oolenc et al, 1981).

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Deep well injection disposal of produced brine water
was chosen for several reasons:
1.	A high volume discharge stream does not exist in
the Raft River Valley. The Raft River is a perennial/
intermittent stream with a low discharge rate and
sensitive ecosystem;
2.	Recycling or a usable conversion of the hot brine
waste fluid is impractical and uneconomical at
this time; and
3.	No acceptable alternative methods of brine disposal
exist in the nonpopulous area of the Raft River
Valley.
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III. PHYSICAL SETTING
Geography
The Raft River Valley in south-central Idaho is a
250 square mile basin bound on the east by the Black Pine
Mountains and the Sublett Range, on the west by the Jim Sage
and Cotterel Mountains, and on the south by the Raft River
Range. The valley opens onto the Snake River Plain to the
north. The Raft River enters the basin at the south end of
the Jim Sage Mountains and flows northward (Figure 1). The
Known Geothermal Resource Area (KGRA) is located at the
south end of the valley near the Idaho-Utah border. The
wells are depicted in Figure 2. The present topography near
the KGRA is characterized by coalescing alluvial fans and
pediments fringing the flood plain of the Raft River.
The habitat of the Raft River Valley is a delicate
cold-desert ecosystem which is very susceptible to degradation.
Once destroyed, it is difficult to re-establish this ecosystem
and a long period of regeneration is required. The vegetation
communities are dominated by low-growing shrubs and forbs
which support a diverse wildlife population.
The Raft River is the only significant stream in the
area and plays an important part of the valley's ecosystem.
The many cultivated fields within and surrounding the project
site depend entirely on ground water for irrigation. Ground-
water withdrawal has increased substantially since 1948, and
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in 1963, the State of Idaho declared the basin a critical
ground water area closed to farther ground-water development.
Cultivated fields with irrigation wells are located directly
north and west of the two project injection wells.
Several small communities exist in the Raft River
Valley; however, no communities or housing occur within the
geothermal project site.
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REVIEW COMMENTS
Note: 1) Size and shape of basin
2)	Sensitive ecosystem
3)	Importance of Raft River
4)	Heavy dependence on ground water
5)	Cultivated fields and irrigation wells to the
north and west of injection wells
6)	Sparsely populated area
1) The Raft River Valley comprises a relatively small
basin, only about 250 square miles. The amount of injection
capacity is directly related to the size of the basin. The
basin is bounded by mountain ranges with the only discharge
outlet to the north.
2,3) The permitting authority should recognize the
serious physical effects of any ground-water contamination
in this area. The Raft River is an effluent stream gaining
its base flow from ground water during low precipitation
periods and supports a delicate ecosystem. Any ground-water
contamination poses a significant threat to the river.
Questionst Are the injection well locations sited
to help prevent any possible contamination
of the river?
What is the direction of ground-water
flow and its discharge points? Remember
ground-water flow lines are perpendicular
to the equipotential/piezometric surface
contour lines in homogenous, isotropic
aquifers. Typically, heterogenous and
anisotropic conditions exist and must be
adequately characterized for an aquifer
before accurate determinations of flow
rate and directions can be made.
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4,5) The potential impact of ground-water contamination
on the area's agriculture should be noted. The permit
applicant must know the depth of local irrigation wells and
USDW zones. The number and location of these wells must be
determined for the area of review calculations as discussed
in Section VI.
6) One positive aspect of the injection well sites is
that they are in a sparsely populated area containing few
domestic wells. The permit applicant must notify any surrounding
landowner or tenant of the land within one-quarter mile of
the injection site. If an area permit is obtained, only one
notification is necessary for the entire project.
14

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Geology
General
The Raft River KGRA lies in a north-south trending,
structurally-downwarped Cenozoic basin. The bounding mountain
ranges differ stratigraphically, being composed of a) primarily
Paleozoic limestones (Black Pine Range)# b) Precambrian
gneiss mantled by allochthonous Paleozoic metamorphosed and
nonmetamorphosed rock (Raft River Range)# c) Tertiary rhyolites
and tuffaceous sediments (Jim Sage Mountains) (Figure 3).
The basin fill consists of poorly consolidated sediments
derived from the surrounding mountain ranges. The upper
sediments are lenticular deposits of alluvial, fluvial, and
loessal origin known as the Quaternary alluvium and colluvium,
and the Pleistocene Raft River Formation. The lower sediments
are marine deposits of sand, silt, minor conglomerate, and
tuff of the Tertiary Salt Lake Formation. These rocks
directly overlie a series of Precambrian metasediments
capping an intruded quartz monzonite basement. All of the
exploratory and production wells, RRGE-1 through 4 and
RRGP-5, penetrate the total thickness of the basin sediments
and are terminated in the quartz monzonite basement. The
injection wells, RRGI-6 and 7, are terminated in, and open
to, fractured and porous Salt lake Formation rock.
Stratigraphy
The surface sediments are Quaternary alluvium and
colluvium. Underlying these deposits is the Pleistocene
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Defined Faults
 Inferred Faults
Down thrown side of fault
o
Burley
Round
IDAHO
UTAH
Raft River Range
Kilometers
Figure 3. Raft River Valley and Major Structural Features
Adjoining the Valley (from Dolenc et al, 1981).
16

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Raft River Formation which consists of unconsolidated guartzose
sand and silt, tuff, and minor rhyolitic gravels. The
sediments are poorly sorted, angular, and reach up to 1,000 feet
in thickness. Cuttings from shallow monitor wells at the
KGRA indicate a fluvial and alluvial depositional environment
much like the present. The lenticular nature of deposition
makes well-to-well correlation of sediments impossible.
The Tertiary Salt Lake Formation underlying the Raft
River Formation is a lacustrine deposit up to 2,500 feet in
thickness. No definitive break occurs between the relative
abundance of volcanic material which increases downward into
the lacustrine deposits. The Salt Lake Formation consists
of light green, thin-bedded to massive, tuffaceous siltstone
and sandstone with minor amounts of shale and conglomerate.
Quartz and feldspar are the most abundant minerals present.
Hydrothermal alteration in both the Salt Lake Formation
and the Raft River Formation has resulted in: replacement
of the primary calcite by silica; fracture filling by secondary
calcite? clay mineral alteration; and the emplacement of
secondary minerals, i.e., biotite and muscovite, and pyrite
and other sulfides. Calcite fills the fractures, and the
silica forms a "caprock" above the geothermal reservoir.
The Salt Lake Formation unconformably overlies part of
the Precambrian rock assemblage. The metaaediments and
adamallite basement rocks in the basin appear flat lying
17

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with no major identifiable structures based on reflection
seismic surveys. Low-angle faults have probably thinned or
erased the units, with movement related to that seen in the
Raft River Range. The upper part of the stratigraphic
section seen in the Raft River Range, Cambrian through
Mississippian units, are absent in this part of the valley.
Hydrogeology
Ground water in the basin occurs in both unconfined and
confined conditions in the poorly consolidated sediments of
the Salt Lake Formation, the sands and gravels of the Raft
River Formation, and Recent alluvial deposits. Recharge to
these aquifers results directly from local precipitation and
from infiltration of surface water and irrigation runoff.
Depth to the water table in the basin varies from the surface
to 100 feet (Figure 4).
The shallow aquifers are considered phreatic, although
some wells reveal locally confined conditions. Nearly all
water encountered below 990 feet (300m) is confined. Piezo-
metric levels in these deeper aquifers in the geothermal
area range from 100 feet (30m) to more than 330 feet (100m)
above land surface. Because of the increase in head with
depth, each aquifer is probably recharged in part by upward
leakage from underlying aquifers through fractures. This is
especially evident in the geothermal area, where wells as
shallow as 390 feet (120m) tap hot water. Nearly all irriga-
18

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Tifi
s
K
The Narrows
. v .*^CwmC5^S&- 
-------
tion wells in the area show some thermal and chemical evidence
of upward leakage from the geothermal resources.
Water levels in the shallow aquifer near the Raft River
have declined over the past 30 years due to extensive irriga-
tion pumping. Analysis of five years of water level data
from USGS-2 (a 787 feet [240m] deep core hole) verified this
trend. Two years of ground-water records from the monitor
wells are inconclusive for long-term trends.
Seasonal water-level changes are apparent in several
monitor wells. A water-level high occurs in early spring,
reflecting shallow recharge. Water levels decline between
mid-spring and the end of the irrigation season. A steady
water-level rise then occurs as a result of the termination
of irrigation pumping.
Geological Structure
The geologic structure of the Raft River Basin near the
KGRA has been studied extensively using geophysical techniques,
surface geological mapping, and aerial photography. The
gross structure, as defined by gravity techniques, is a
downdropped basin with steep normal faults inferred at the
range fronts. The principal faults exposed at the surface
which lie in a north-trending zone on the west side of the
valley are called the Bridge Fault Zone and Horse Well Fault
Zone. South of Sheep Mountain the fault zone widens to the
west and distributes vertical displacement between a series
20

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of normal faults trending slightly east of north. Surface
dip of the faults is 60 to 70. An early interpretation of
the Bridge Fault Zone shows continued steep dips to depth,
displacing the metasediments and quartz monzonite basement
(Figure 5a). A later interpretation infers a shallowing of
dip with depth, flattening to parallel the bottom of the
Tertiary sediments, with no displacement of the basement
(Figure 5b). Covington (1976) postulates that movement on
the concave upward faults produced many near vertical open
fractures near the base of the Tertiary sediments.
The Bridge and Horse Well Fault Zones are terminated
north of the Raft River by a poorly understood geologic
structure called the Narrows Zone. This structure trends to
the northeast across the basin and is thought to be a basement
shear associated with a large regional feature called the
Humboldt Zone. The Narrows Zone is inferred by a compilation
of anomalous data from geophysical surveys that suggest
major changes occurring in a northeast trend.
The geothermal system in the Raft River Basin occurs at
the intersecion of the Narrows Zone and the Bridge Fault
Zone. Hydrothermal water is believed to circulate to depth
along basement fractures, possible along the southwest
extension of the Narrows Zone, then rises at the intersection
of the two major structures where it spreads laterally into
the Tertiary sediments. Upward leakage through fractures in
21

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A Jim Sage
/Sheep
Mountain	A
Quaternary Sediments.
Tertiary
Lavas
Mountains
Tertiary Sediments
-.Tertiary Sediments,,
v Adamellite
Level
Precambrian Adamellite
-1000
Undifferentiated
Paleozoic and
Precambrian Rocks
Figure 5a. An Early Interpretation of the Bridge
Fault Zone (from Dolenc et al, 1981).
/Tertiary
Rhyoiite Bridge
Horse Weil
Fault Zone
Raft River valley
RRGE-1
Quaternary Sediments
_ 1500
fc 1000
-v '
'l * 1*1
Metasediments

Precambrian Adamellite
& Paleozoic
Rocks 

Figure 5b. A Later Interpretation of the Bridge
Fault Zone (from Dolenc et al, 1981).
22

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the Salt Lake Formation provides hot water to the shallow
hot wells in the valley (Crook and BLM wells). No evidence
of a local heat source is apparent.
23

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REVIEW COMMENTS
Note: 1) Structural and stratigraphic basin
2)	Unconsolidated surface alluvium and Pleistocene
Raft River Formation
3)	Consolidated Tertiary Salt Lake Formation
4)	Basement and metasediment rocks
5)	Faulting and fracturing in Tertiary and basement
rock
6)	Seismic risk in Raft River Valley
7)	Structural analysis
1)	The Raft River Valley is a structural and strati-
graphic basin with a significant thickness of sedimentary
rock. Although major synclinal basins are geologically more
favorable sites for deep well injection, the Raft River
Valley appears to have an acceptable thickness of sedimentary
rock over an areal extent suitable for the geothermal project,
Because this geological-complex basin and range area is
surrounded by impermeable igneous and metamorphic rock, the
reserve capacity to receive volumes and injected wastes is
considered small and must be calculated (Figure 6).
2)	The shallow ground-water aquifers in the Raft
River Valley consists of the surface alluvium and the Raft
River Formation. These unconsolidated sand and gravel units
are classified underground sources of drinking water (USDW)
and must be protected from any contamination under the
24

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to
U1
8
. 0^0

LEGEND
'MM Unfavorable under
all conditions
W Generally unfavorable but may hove
W N limited use under restricted conditions
Favorable under
controlled conditions
* Disposal Wells
+ Abandoned or plugged Disposal Wells
Figure 6. Site Suitability for Deep Well Injection
(from Reeder et al, 1977).

-------
provisions of the UIC program. Mapping of the various
aquifer and confining zones is difficult due to their lenticular
nature. The determination of the groundwater flow direction
is extremely important in assessing the contamination potential
of any injection well and may be difficult due to seasonal
fluctuations of the water levels.
3) The Salt Lake Formation is the proposed injection
zone. This formation consists of about 2,500 feet of alter-
nating injection zones and impermeable confining zones.
Suitable disposal zones are those with proper injectivity
and storage capacity characteristics. Detailed geologic and
engineering studies in the study area are necessary to
determine the following geologic parameters of a suitable
disposal zone:
a.	Reservoir uniformity - Abrupt changes in lithology
and mineralogy may lead to reduced porosity,
hydraulic conductivity, or other reservoir character-
istics related to storage capacity or transmissivity.
This affects the volume, rates , and pressure
build-up of fluid injection.
b.	Suitable areal extent - Needed to take injected
fluids in sufficient quantity to make a disposal
project a mechanical and economic success. An
injection zone having severely limited areal
extent will show aggravated pressure build-ups
near the points of constriction due to boundary
effects.
c.	Substantial thickness - Relates directly to the
volume of reservoir available for injection. The
maximum available thickness in an injection zone
should always be an objective of disposal system
planning. RRGI-6 and RRGI-7 injection wells are
completed in about 1,800 feet of the porous and
fractured Salt Lake Formation. This thickness is
suitable for the injection volume of the geothermal
26

-------
project. Areal changes in thickness must be
determined.
d.	Porosity and hydraulic conductivity - Relate
directly to available volume and indirectly to the
injection rate at reasonable pressure. Any changes
in these parameters would have an impact on the
pressure build-up in the injection zone. Porous
and fractured injection zones of the Salt Lake
Formation have a high porosity, about 20 to 30 percent.
Any formation lower than ten percent porosity is
considered questionable as to its use as an injection
zone. The hydraulic conductivity of the Salt Lake
Formation injection zones is also suitable for the
proposed injection volume and injection rate at
the site.
e.	Low formation pressure - Allows the operation
margin at which fluids can be injected into the
reservoir without causing fracturing. Too high
initial pressure may limit the intake rate and
operating life of the well, and increase operating
costs. The fracture pressure gradient of the
injection zone shall be determined or calculated
by the permit applicant. Besides stimulation
tests, the maximum wellhead pressure shall not
exceed the calculated maximum injection pressure
in order to prevent new fractures or propagate
existing fractures in the injection zone.
f.	Salinity of formation and injection water - OIC
regulations require that the minimum salinity of
water in the injection zone is 10,000 mg/1. Water
with a salinity of less than 10,000 mg/1 can be
used in the Raft River Valley for stock watering,
irrigation of certain crops and use as a protective
buffer. In the geothermal project, injected water
from the production well actually has a lower
salinity than the injection zone water which may
cause clay swelling, reducing porosity and causing
injection failure. The salinity and other chemical
characteristics of the injection zone water and
injected water must be known and submitted by the
permit applicant.
g.	Adequate overlying confining layers - Vertical
confinement of injected waste is very important
for the protection of USDWs. Several tuff and
tuffaceous siltstone layers in the upper part of
the Salt Lake Formation may act as overlying
confining zones. Although not automatically
21

-------
required under UIC regulations, a desirable permit
condition for many operations may be the prior
field determination of porosity and hydraulic
conductivity of each confining stratum. This data
would assist in the evaluation of a confining
layer's adequacy.
4)	Confining pressure in the basement geothermal
production zone is greater than the injection zone pressure
causing an upward leakage of fluid. In most cases, the
salinity of water and the hydrostatic head increases with
depth. Occasionally, a fresh water zone may be beneath a
possible injection zone. An underlying confining layer is
of major importance in such a case.
5)	The faulting and fracturing in the Tertiary and
basement rock should be of major concern. Although fracturing
in the basement rock provides a flow path for geothermal
water, it also acts as a contamination pathway from the Salt
Lake Formation injection zone into the water-bearing Raft
River Formation. An increased water level in observation
wells during injection into RRGI-4 determine that the hydraulic
connection exists between the shallow aquifer system and the
injection zone in the west-central part of the project site.
A proposed injection well (RRGI-4) was deepened and converted
into a production well (RRGP-4) because of the extensive
fracture system encountered in the well. Injection testing
and the development of an extensive monitoring system must
be performed to confirm any hydraulic relationship between
the injection zone and USDW(s).
28

-------
LEGEND
POSSIBLE DAMAGE
NONE
MODERATE
Figure 7. Seismic Risk Areas of the United States
(from Algermisen, 1969).

-------
6)	Seismic risk should be considered in the planning
of deep well injection systems in Region X. Figure 7 illustrates
the seismic risk areas of the United States. Note the high
seismic risk values present in the Raft River area and most
of Region X. The overall injection system, including surface
treatment plant, well casing construction, fail safe devices,
and monitoring systems should be designed and constructed
related to the degree of seismic risk assigned to the site
area. The possibility for induced seismic activity from
local pressure changes in the geothermal production and
injection zones prompts the need for a continuing microseismic
study at the Raft River Geothermal Project area.
7)	Two structural interpretations of the Raft River
Valley are included in this case study. The results of
geophysics and deep well drilling support the latter interpre-
tation. The permitting authority must have a workable
knowledge of the structural geology surrounding a proposed
injection site. This involves a comprehensive literature
investigation and the acquisition of available geophysical
and well data. Any questionable structural geology concept
should be investigated, particularly if the site is in a
complex geologic setting.
30

-------
IV. WELL CONSTRUCTION AND COMPLETION TECHNIQUES
Wells RRGI-6 and RRGI-7 were designed to inject spent
geothermal fluid into the intermediate depth Salt Lake
Formation. This zone between 2,000 and 3,500 feet was
chosen in order to minimize the occurrence of contamination
of near-surface ground water, prevent the cooling of production
aquifers and to reduce well cost. Each well was designed
for completion options: deepening and casing, or deepening
with directionally drilled legs.
Drilling and Construction Summary of Well RRGI-6
Prior to drilling, 100 feet (34m) of 20 inch diameter
surface casing was set and cemented using a 2-1/2:1 cement-
sand ratio. A 17-1/2 inch hole was drilled to 2,030 feet
(619m) and logs were run (Table 1). While trying to run the
13-3/8 inch intermediate (54.4 lb/ft) casing, it stuck at
1,522 feet (215m). Circulation did not alleviate the problem.
Oil and pipe lax were used to lubricate the pipe which
allowed the casing to move downhole to a depth of 1,698 feet
(517m). At this point, the 133/8 inch casing was cemented
using Class-G cement with gel and silica flour. During
cementing, a significant amount of returns were lost.
Drilling proceeded to a total depth of 3,8 58 feet using a
12-1/4 inch bit and was completed open hole. A core was
taken between 2,290 and 3,035 feet with 30 feet recovery
(Figure 8).
31

-------
Table 1. Logs Run on RRGI-6 (from Dolenc et al, 1981).
DATE
TYPE
DEPTH (FT)
4/16:4/17/78
Compensated Neutron
Dual Induction (focused)
Acoustllog
Temperature
Caliper
Epilog
100-2017
90-2020
100-2011
4-2016
38-2018
120-2020
4/30/78
Differential Temperature
Acoustllog
Dual Induction (focused)
Dens1log-Neutron
1660-3782
1700-3773
1700-3784
1700-3789
5/8/78
Epilog
2000-3790
32

-------
pt Ground level (elevation 1468 m)
- Hole diameter 66 cm
^ Casing diameter 50 cm set to 32 m
Depth
(m)
100
200
300
400
Casing diameter 34 cm set to 514 m
500
Hole diameter 44 cm
600
Hole diameter 31 cm
TD 1172 m
1100
Not drawn to scale
Figure 8. Well Construction of RRGI-6 (from Miller
and Prestwich, 1979a).
33

-------
An eight-hour injection test was run on the well immedi-
ately after total depth was reached. Following the testing,
the well was airlifted to clean and develop the well, and to
remove injected fluid in order to collect formation-water
quality samples. After the well recovered, a small artesian
flow was maintained.
Mud logging services were conducted during the entire
drilling of the well to monitor drilling fluid, cuttings
return and fluid temperature. From the mud logging service,
the formations were encountered at the following drilled
depths:
Alluvium	Surface
Raft River	580 feet (177m)
Salt Lake	1,280 feet (390m)
Drilling and Construction Summary of Well RRGI-7
The drilling and construction of RRGI-7 is similar to
RRGI-6. A 20-inch surface casing was set at 150 feet (46m)
and cemented with plant-mix concrete. Drilling began with a
17-1/2 inch bit using a low-solids mud. Bit plugging problems
developed upon entering gravel sections. Drilling proceeded
to 2,054 feet (610m) and the hole was logged (Table 2).
After logging, 13-3/8 inch casing was run to a depth of
2,044 feet (623m) and cemented with Class-G cement, gel and
silica flour. The blowout prevention equipment (BOPE) was
attached to the well and pressure tested before drilling out
34

-------
Table 2. Logs Run on RRGI-7 (from Dolenc et al, 1981).
DATE
TYPE
DEPTH (FT)
7/31:8/3/78
Epilog
150-3800
7/23:7/25/78
Acoustllog
Differential Temperature
Caliper
Compensated Neutron
Dual Induction (focused)
Dens1log
Acoustllog
Compensated Neutron
Differential Temperature
160-2055
100-2054
10-2016
160-2050
150-2052
2049-3798
2050-3800
2050-3789
2050-3800
11/14/78
High Resolution Temperature
34-3801
8/1/78
Dual Induction
2050-3789
35

-------
the casing shoe. The hole was then reentered with a 12-1/2-inch
bit and drilled to a total depth of 3r888 feet (1,172m) with
open hole. At 3,828 feet, a 30-foot core was cut with a
19-foot recovery (Figure 9). The hole was cleaned and logs
were run from total depth to the casing shoe. Several
short-term airlift flow tests and injection tests were
conducted to stimulate the reservoir, and remove all injected
water and cuttings.
Mud logging service was performed during the entire
drilling of the well. Prom the mud logging service, the
formations were encountered at the following drilled depths:
Alluvium
Surface
Raft River
510 feet (155m)
Salt Lake
1,180 feet (360m)
36

-------
Ground level (elevation 1480 m)
Hole diameter 66 cm
Casing diameter 50 cm set to 41 m
Depth
(m)
100
Casing diameter 34 cm set to 619 m
200
Hole diameter 44 cm
300
400
500
600
Hole diameter 31 cm
1100
TD 1172 m
1200
Not drawn to scale
Figure 9. Well Construction of RRGI-7 (from Miller
and Prestwich, 1979b).
37

-------
REVIEW COMMENTS
Notes 1) Selection of intermediate depth disposal
2)	Cemented surface casing
3)	Casing lubrication on RRGI-6
4)	Cemented intermediate casing
5)	Geophysical logs
6)	Open hole completion - no tubing or packer
7)	BOPE and Injection Testing
8)	Mud logging service
9)	Depths of USDW(s)
1)	Two geologic and one economic factor were considered
in the selection of using the intermediate zone for disposal.
Injection into this zone will minimize ground-water contamina-
tion into the surface alluvium and Raft River Formation, the
primary sources of ground water in the area. Deep injection
below the intermediate depth zone may cool the geothermal
heat source and is more costly for drilling and well construc-
tion. An increase in formation pressure at depth would also
require a higher injection pressure system. The above
reasons for intermediate-depth injection into the Salt Lake
Formation are valid and reasonable.
2)	In both wells, the surface casing has been cemented
to prevent any surface contamination from migrating down the
annulus. Injection between the well bore and casing is
38

-------
prohibited in all classes of existing and new injection
wells.
3)	During the construction of RRGI-6, lubricating
agents were used on stuck casing. These lubricants can pose
a contamination potential in the well and surrounding area.
The exact amount of lubricant and its chemical composition
used in the well should be known.
4)	The intermediate casing must be cemented beneath
the lowermost formation containing a USDW. The casing in
both injection wells is of standard weight and size used in
the petroleum industry, and is designed for the life expectancy
of the well. The American Petroleum Institute (API) approved
Class-G cement is a basic cement intended for use to 8,000 feet
depth (2,438m) and at high temperature of 200F (93C). The
cement can be modified with accelerators or retarders to
meet a wide range of temperature conditions. Additives were
mixed into the Class-G cement to increase strength, temperature
rating and decrease porosity. Information about types of
cement and its properties may be obtained from Halliburton
Services, Duncan, Oklahoma.
5)	Numerous resistivity and porosity logs were run in
each well before casing was set and cemented. Their purpose
was to identify USDWs, injection zones, geothermal production
zones and the fresh-saline water interface. Conventional
interpretive techniques were used in the upper sedimentary
39

-------
rock units; however, these techniques were found unreliable
in the dense igneous rocks. Further discussion on borehole
geophysical analysis is located in Section V of this report.
Question:	Can you identify logging methods required
by the UXC program and not performed
according to this case study? A cement
bond, temperature or density log was not
performed after cementing to evaluate
the bonding between the formation and
the casing. Any one of the three above
logs is required for all new injection
welis.
6)	Both Class V injection wells were open hole completion
beneath the intermediate casing. Tubing and packers were
not used in the completion of the wells which is in accordance
with UIC requirements. Class I (except noncorrosive municipal
wells) and II wells require tubing and a packer while Class III
wells are exempt from this construction requirement.
7)	The only known mechanical integrity testing performed
on either injection well was a casing pressure test daring
BOPE operations on RRGI-7. Further mechanical testing of
the injection wells may be conducted by monitoring the
annulus pressure after completion of the well. Results of
such testing should be submitted to the permitting authority
periodically.
To monitor for the presence of fluid channels between
the casing and well bore, a temperature or noise log should
have been run. The volume of cement necessary to fill the
annulus between the casing and well bore should be calculated
40

-------
and compared to the amount used in the well construction.
Cementing records may demonstrate that adequate cement had
been pumped behind the casing. However, the records may
bear little or no relationship to the quality of the cement
bonding due to borehole diameter deviations.
8)	Although not required by UIC regulations, a mud
logging service provides valuable petrophysical and lithologi-
cal subsurface data. Logs aid in determining the thickness
and depth of USDW(s) and confining zones.
9)	The base of the lowermost USDW has not been defined
and submitted by the permit applicant. No fresh-saline
water interface map is included in the report. According to
UIC regulations, this significant information must be determined
by water sampling or geophysical log analysis and submitted
with the additional permit information.
41

-------
V. WELL LOGGING AND TESTING
Borehole Geophysical Analysis
Introduction
Due to the nature of the project and the subsurface
environment encountered, the primary interest attached to
the borehole geophysical program was to delineate fractured
intervals. Because of the variety of rock types (sedimentary,
metamorphic, igneous), the presence of alteration products
and the variability of fracturing, conventional interpretive
techniques were found to be unreliable. As an example, the
log responses to igneous and metamorphic lithologies made it
impossible to determine porosities and permeabilities.
Therefore, major efforts were performed to use the various
interpretive techniques to identify fractures using indicators
from the logs, to record characteristic log responses, and
to then attempt to define and understand the geologic factors
causing these log responses. By cross plotting the various
rock types, matrix parameters were able to be determined.
These techniques resulted in determining the relevant data
necessary to assess a geothermal reservoir and potential
injection zones. These methods should be very useful in
other injection well applications where igneous and metamorphic
environments are encountered.
The Logging Program
The basic suite of logs that were run on each well
included: induction, acoustic, density, neutron, caliper,
42

-------
the spontaneous potential (SP) curve, and temperature. Logs
run on Wells 1, 4, 5, 6, and 7 were digitized and stored on
magnetic tape.
Induction Log
The induction log is used to measure the resistivity of
a formation; values are expressed in ohm-meters. The dual
induction log measures three depths of investigation: the
shallow reading curve measures the resistance of the invaded
zone around the borehole. The deep induction curve measures
the entire formation resistivity and must be corrected for
borehole size, fluid resistivity, and tool stand-off. The
medium induction curve is essentially the same as the deep
induction curve but is focused to respond to shallower
depths.
The dual induction log indicates the presence of fractures
if values obtained from the shallow induction curve are less
than those from the deep induction curve. The shallow
induction curve is a vertically focused, short spaced resis-
tivity instrument that may respond to thin-bedded formations
and/or to vertical fractures when they are filled with
filtrate of resistivity lower than that of the formation.
The deep induction log reads horizontal conductivity which
is presented in the induction log as resistivity. As a
result, the presence of fractures in the wall of a borehole
43

-------
might be detected if the shallow induction curve indicates
less resistivity than the deep induction log.
The major drawback to the use of this logging instrument
in massive igneous and metamorphic environments is that the
natural formation resistivity is usually very high. The
high resistance causes the dual induction curves to saturate,
and accurate resistivity readings cannot be obtained. In
these instances, the dual laterlog resistivity instrument
should be used.
SP Curve
The SP method is used to measure natural formation
potential and is used to distinguish between sand and shale
and to also qualitatively identify porosity and permeability.
With the SP as one aid, the resistivity of formation waters
can also be determined.
While igneous and metamorphic rocks do not generally
display a self-potential, the SP can be used qualitatively
to determine the presence of fractures. The SP curve tends
to hachure when a fractured interval is encountered, where
each spike most likely corresponds to a streaming potential
effect caused by mud filtrate invasion into the fractures.
44

-------
Acoustic, Density# Neutron Logs
These logs are used to identify the porosity and lithology
of a formation. In addition, the use of the litho-porosity
cross-plot interpretive technique can also determine the
presence of vuggy and/or fractured zones. This technique
was originally used to help interpret formations with complex
lithologies, handling data from density, neutron, and acoustic
logs simultaneously. By analyzing these logs, two porosity-
independent parameters, M & N, can be determined using the
following equations:
M = -			 x 0.01
Pb - Pf
(0)f ~ 0N
N =	1
Pb Pf
In the cross-plot of M versus N, each mineral is repre-
sented by a unique point regardless of porosity. For complex
lithologies, the position of the data points on the M-N plot
helps identify the various minerals in the formation and the
approximate percentage of each. Figure 10 presents the
locations of prevalent minerals at the Raft River site. The
major drawback to the use of these logging instruments in
igneous and metamorphic environments is that porosities and
permeabilities are difficult, if not impossible, to determine.
45

-------
1.9
2.0
o Sulfur
o Salt
2.1
2.2
o.
2.3
o
o
E
o>
Quartz
Monzonite N
in
c
0)
2 2.5
-10
3
CO
X3
2.6
Q.
Elba Quartzite y^>
2.7
-5
2.8 - Langbeinite
Poly halite
-10
2.9
Modified from Schlumberger
-15
Schist
3.0
( CNL)cor Neutron Porosity Index, p.u.
(Apparent limestone porosity)
"figure 10. Bulk Density-Porosity Plot from Schlumberger
Modified to Show Raft River Rock Types (from
Dolenc, 1981).
46

-------
Other Borehole Tools/Miscellaneous Indicators
for Fracture Detection
Other borehole logs, such as the borehole televiewer
and the temperature log, can also be used to detect possible
fractures. The borehole televiewer takes an acoustic picture
with a rotating ultrasonic scanner. The log inspects the
borehole and evaluates the formation as it reveals induced
and natural fractures and/or vugs. This borehole log is
currently in the experimental stage with commercial models
expected in the near future.
Temperature logs were used extensively in interpreting
fractures at the Raft River site. The temperature log, run
under nonequilibrium conditions, also provided useful informa-
tion about the characteristics and location of the production
zones. Finally, traditional indicators of fracturing during
drilling operations included: drilling rate, mud circulation
data, drill cuttings data, and rock strength.
Tables 1 and 2 indicate the various borehole geophysical
logs run in each injection well.
Injection Zone Testing
Pump and Injection Tests
Pump and injection testing have been conducted at most
of the Raft River exploration, production, and injection
wells. This testing used electric-powered submersible and
turbine shaft pumps, restricting the discharge rates to the
47

-------
design limitations of the particular pump. This prohibited
the high production and injection rates required for operating
the 5MW(e) power plant during the testing. It was typical
to measure drawdown/recovery in a production well by using
a bubbler tube and surface gauge and build-up/fall-off by a
wellhead gauge. To reduce thermal shock in the transit
pipeline, most wells discharged through the pipeline prior
to starting the pump test. Wellhead pressure rose and then
stabilized as a function of wellbore fluid density. Thus,
"initial" cold or hot wellhead pressures are of questionable
value. No recovery was accomplished before starting the
higher discharge rate pump test.
Well testing, with the primary goal of reservoir evalua-
tion, were conducted for greater than 500 hours duration of
pumping and injecting. Recovery data were obtained for a
much shorter period of time due to wellbore fluid density
changes. Data were obtained in as many observation wells as
possible. However, many observation wells were under artesian
conditions and had poorly regulated discharge rates for
various reasons.
Numerous injection tests at reservoir temperatures, and
a few at cooler-than reservoir temperatures were conducted.
No reservoir parameters could be calculated from the cool
water injection tests due to the short duration and discharge
rate control problems. The potential effects of injecting
48

-------
cooler water should be determined, as the 5MW(e) power plant
will cool the injection fluid. However, injection of cool
water was used successfully for delineating production
zones. Pressure buildup curves and disposal zone parameters
determined in RRGI-6 and RRGI-7 are summarized in Figures 11
and 12 and Tables 3 and 4.
49

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1800
1600
1400
2 1200
1000
S 800
Injection Wll RRGI-6
600
400
Tim* (min)
Figure 11. Pressure Buildup During Injection Test of
Well RRGI-6 (from Dolenc et al, 1981).
50

-------
2200
~ 1900
3 1750
g 1600
Injection Well RRGI-7
Time (min)
Figure 12. Pressure Buildup During Injection Test
of Well RRGI-7 (from Dolenc et al, 1981).
51

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Table 3. Summary of Well RRGI-6 Parameters
(from Dolenc et al, 1981).
Date
Q
(L/i)
0/,10
(L//k?a)

T,
(m'l
1
fa)
Type
01/10/79
44.2
0.39
1.6
X
104
2.1
X
IO-4
Injection
(wellhead)
01/10/79
44.2
0.40
1.7
X
10*
2.1
X
io-4
Injection
(610 *)
03/10/79
37.8
0.34
1.4
X
10*
1.8
X
io-4
Injection
03/10/79
37.8
0.27
1.1
X
10*
1.4
X
IO"4
Recovery
05/16/79
40.4
0.34
1.4
X
10A
1.8
X
IO-4
Injection
05/16/79
40.4
0.24
1.0
X
10*
1.3
X
10~3
Recovery
05/16/80
45.7
0.29
1.2
X
104
1.5
X
IO-4

08/19/80
56.8
0.28
1.2
X
10*
1.5
X
IO"4
Injection
08/19/80
56.8
0.24
1.0
X
10*
1.3
X
io-4
Recovery
52

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Table 4. Summary of Well RRGI-7 Parameters
(from Dolenc et al, 1981).
Sate
Q
(L/a)
Q/,10
(L/a/kPa)
Kh
(*D*n)
Ta
C.2/.)
Tvoe
08/10/79
39.1
O.SO
2.1 s 10*
2.6 x 10^*
Injection
08/10/79
39.1
0.35
1.3 x 10*
1.9 x 10"*
Recovery
08/11/79
28.4
0.48
2.0 x 10*
2.6 x 10"*
Injection
08/11/79
26.4
0.33
1.4 x 10*
1.7 x 10"*
Recover >-
08/11/79
28.4
0.39
2.5 x 10*
3.1 x 10"*
Injection
(1130 a)
08/11/79
28.4
0.37
1.6 x 10*
2.0 x 10"*
Recovery
(1130 )
10/15/60
63
0.73
3.2 x 10*
4.0 x 10-*
Injection
08/19/80
60
0.23
1.0 x 10*
1.2 x 10"*
Injection
08/19/80
60
0.32
1.2 x 10*
1.6 x 10-*
Recovery
09/10/80
36.S
0.30
ft*

M
O
*>
1.3 x 10"*
Recovery
53

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REVIEW COMMENTS
In the following discussion of injection test interpreta-
tion, a textbook injection test and an injection test of
well RRGI-7 will be interpreted. The equation used to
determine formation transmissivity is Jacobs equations
T = 2,3 Q/41> A h
Any consistent units can be used in the above equation. The
change in head is measured in one log cycle.
First Case
3
An injection test was run at 75 gpm (14,434 ft /day)
for 25 hours. The plot of the pressure buildup data from
the injection test is given in Figure 13. After converting
3
galIons/minute into ft /day where one cubic foot equals
7.481 gallons and psi into feet (psi x 2.31), the above
equation equals:
T(ft2/day) = 2.3 (14,434 ft3/day)/4TT (2136 ft water head change)
= 1.24 ft2/day
The injection test can further be used to determine the
formation storage coefficient from:
S 	2.25 T	(dimensionless)
where:
t	= Intercept of extraploated test curve
 with time axis in days.
r = radius of well bore in feet.
54

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1900 -

1000-
w
THIS PORTION Of CUItVE
not usable roft analysis
soo-

TIME - HOURS
A*  Kltii
A IM I  I
Figure 13. Plot of Pressure Buildup Data from an
Injection Test of the Mt. Simon Formation
in Ohio (from Everett, 1980).
55

-------
In Figure 13, t = 0.2 2 hour (0.0042 days) and
S(dimensionless) = 2.25(1.24 ft^/day)(0.0092 days)/(0.396)
= 0.16
Note that the storage coefficient calculation defines
"r" as the wellbore radius as opposed to an observation
point radius. Typical field studies usually never attempt
to estimate the storage coefficient on the basis of observations
taken at the injection/pumping well during a constant rate
test. The step-drawdown test, which allows estimations of S
when using only one well, is considered not as accurate as a
two-we11 test.
Well RRGI-7
The injection test duration of well RRGI-7 was 3 5 hours
at an injection rate of 60 L/sec. The injected fluid was
from well RRGE-1 at reservoir temperature (150C). Using
Figure 12), the change in head (Ah) over one log cycle is
determined to be 240 kPa. For fresh water at 20C, the kPa
value can be converted into meters of head change by dividing
the kPa value by 9.807; however, the conversion for steam is
approximately 2.6 since steam is about one-fourth of the
specific weight of water. After changing liters/sec into
3	3
m /sec (1 m = 1,000 liters), we obtain:
T = 2-3<-06>/4Tr (92)
-4 2,
=1.2 x 10 m /sec
56

-------
Note that hydraulic conductivity is a temperature
dependent parameter since it is a function of the density
and viscosity of the fluid moving through a formation.
Hence, the hydarulic conductivity value determined by injection
or pump testing a formation with fluid at one temperature
will differ to the value obtained with a quite different
temperature fluid. For the geothermal case study, a higher
hydraulic conductivity value would be obtained when testing
with hot geothermal waters than would be obtained when
testing with cooled waters. The higher conductivity value
so obtained would lead to smaller calculated pressure build-
ups and areas-of-review.
57

-------
VI. AREA OF REVIEW CALCULATIONS
Potential Injection Formulation
The pressure response of each well to production, or
injection in that well and each of the other wells that
penetrate the same zone of the reservoir were tested.
Pressure response at the end of one year and three years of
8 5 percent usage is predicted for the assumed flow rates as
indicated in Table 5.
Pressure response in each well, due solely to that
well's use in production or injection of geothermal fluids,
was obtained from the reservoir testing data. The listed
values represent the worst case response prediction made for
each well for the specific time period and pumping rate.
The pressure response in Table 5 that reflects inter-
ference between wells were calculated at different radii
from:
Q , ,4Ts .
s = 4 ff" T	2 )
r s
This is the nonequilibrium or Theis equation of pressure
response at any point as a function of reservoir properties
3
and flow rate. In this equation: Q is flow rate (L /T): T
2
is reservoir transmissivity (L /T); S is the storage coefficient
of the reservoir (dimensionless); r is the distance from the
58

-------
Table 5. Predicted Pressure Response (kPa) at the end of 1 Year (t1)
and 3 Years (t ) of Operation, at 85% Usage, in Each Well
(from Dolenc et al, 1981).
URGE-1		RRCE-?			RRCE-3	 	RRCP-4	 	RRCP-5
Hell
Q
(L/a)
Radiua
(In)
<1
*3
Radiua
(k)
<1
<3
Radiua
(ka)
<1
<3
Radiua
(ka)
<1
l3
Radiua
(k>)
ll
l3
RRCE-I
76
0
3222"
3379*
1.21
295
342
1.86
258
305
0.48
374
421
0.76
335
382
RRCE-J
63
1.21
244
283
0
9800"
10 100"
2.22
201
240
1.66
222
261
1.89
212
252
RRGE-3
44
1.86
149
177
2.22
140
168
0
5716"
6308*
1.31
167
194
2.35
138
165
RRCP-4

0.48


1.66


1.31


0


0.69


RRCP-5
Total
63
246
0.76
277
3892
RRGI-6
317
4156
1.89
212
10 447
RRGI-7
252
10 862
2.35
197
6372
236
7089
0.69
284
1047
226
1102
0
1690a
2375
1760*
2559
Veil
Q
(!./)
Radiua
(tat)
41
<3
Radiua
( km)
*1
l3









RRGI-6
12 3
0
3883s
3990"
0.49
339
378









RRCI-7
123
0.49
339
378
0
3 984*
4 064*









Total
246

4222
4368

4 323
4 442









i. Wortt cue observed.

-------
flowing well to the point at which s is to be found (L); t
is the time, measured from the start of pumping, when s is
desired (t). When these inputs to the equation for s are in
consistent units, the pressure response at a distance r
after a given time t, will be obtained in units of length;
i.e., pressure response is given in height of a column of
water. Pressure in height of water can easily be converted
to true pressure units of weight per unit volume if the
specific gravity of water at the temperature of interest is
known.
Interference testing is an injection test method where
the pressure response from a production/injection well is
measured in some distant observation well(s). Data collected
from an inactive observation well produce data unavailable
by other techniques. The data is not thermally affected and
can be used to calculate the average transmissivity of a
large aquifer volume. However, if the observation wells are
under artesian conditions, as in the Raft River testing
area, the data may be erroneous. Transmissivity values were
obtained by taking a geometric mean of the transmissivity
estimated from interference testing. As a result, T  1.3 x
-3 2	-3 2
10 m /s in the production zone and T = 2.6 x 10 m /s in
the injection zone. No information is available to estimate
-4
the storage coefficient, so S = 1 x 10 was assumed. The
apparent temperature of the production zone, 132C, leads to
60

-------
3
a specific gravity of 58.81 lb/ft . Injection fluids are
anticipated to be 66C and thus gives a specific gravity of
61.19 lb/ft3.
Within the production zone, the greatest amount of
pressure drawdown will occur in RRGE-2 where, after three
years of 8 5 percent usage, pressure will have decreased by
10,862 kPa. The least amounts of pressure drawdown will
occur in the vicinity of wells RRGE-1 and RRGP-5; pressure
in RRGP-5 will decrease 2,559 kPa and pressure in RRGE-1
will decrease 4,156 kPa. Note that the assumed production
program does not include production at RRGP-4; this is
because of low flow capabilities identified during testing.
Thus, the 1,102 kPa pressure decrease shown for RRGP-4
results exclusively from production at other wells.
Pressure buildup in the injection zone is fairly uniform
because both injection wells are assumed to flow at the same
rate. Since there are only two wells and they flow at the
same rate, the interference effect of each well on the other
is assumed to be identical.
61

-------
REVIEW COMMENTS
Note: 1) Errors in pressure response equation.
2)	Usage of the modified Theis equation.
3)	Fracture pressure calculation.
1)	Several errors exist in the given pressure response
equation of this case study. Since accurate results are
obtained for Table 5, the errors appear to be typographic in
nature. The pressure response equation should be listed as:
Q . ,2.25Tt.
s ~ 4TTT ln( 2o
r o
This equation is actually Jacobs equation measuring the
change in head pressure. A small "r" value and large "t"
value are required to obtain a small well function "u" value
so that the series terms in the Theis equation becomes
negligible after the first two terms.
2)	The UIC program's modified Theis equation for
calculating the radius of endangering influence is a rearranged
Jacob equation with variables concerning the specific gravity
of the injection zone fluid and hydrostatic head difference
between the injection zone and USDW zone. The modified
Theis equation is given below:
r = (2.25 kHt/S 10X)1/2
where
x = 4TTkH (hw - hfao SpGb)/2.3 Q
62

-------
and
h = hydrostatic head of USDW measured from
the base of the lowest USDW.
h, = observed original hydrostatic head measured
from the base of the lowest USDW.
SpG, = specific gravity of fluid in the injection
zone.
In the Raft River Valley, the shallow aquifer system is
unconfined although some wells are locally under confined
conditions. Nearly all water encountered below the base of
the Raft River Formation (990 ft) is confined. Piezometric
levels in the deep aquifers and injection zones range from
100 feet (30m) to more than 330 feet (100m) above the land
surface. The modified Theis equation may be used in the
Raft River project area only if the hydrostatic head of the
lowermost USDW zone is higher than the injection zone's
hydrostatic head. However/ in most areas of the Raft River
Valley, the head value increases with depth. Because the
radius of influence is that portion of the aquifer which is
affected by pressure changes, any injection in the Raft
River Valley would increase the flow potential between the
injection zone and USDW. The radius of the influence would
be a finite value representing a distance beyond which
pressure changes resulting from injection would no longer be
discernable. In addition, the fracturing in the Salt Lake
Formation distorts the general Theis assumptions that the
63

-------
formation is isotropic and homogenous. The permitting
authority should know the applicability and limits of the
modified Theis equation.
3) The maximum wellhead injection pressure must be
calculated to prevent the formation of new fractures and
propagation of existing fractures in the injection zone.
Besides stimulation injection, it is prohibited to exceed
the maximum injection pressure in an injection operation.
The fracture gradient of the injection zone must be determined
and used in the injection pressure equation given below:
P = (X - 0.433 Sg)d
m
where
P^ = injection pressure (psi)
X = fracture gradient (psi/ft)
Sg = specific gravity of injection fluid (unitless)
d = injection depth (ft)
Significantly, in most cases, the fracture gradient of
the confining zone is higher than the potential injection
zone fracture gradient. The injection zone and confining
zone fracture gradients should be determined by the permitting
authority if no value is submitted by the permit applicant.
The permit applicant must determine or calculate the fracture
pressure of the injection formation for new Class I, II
and III wells.
64

-------
VII. GEOTHERMAL FLUID CHARACTERISTICS AND
COMPATIBILITY TESTS
In order to determine the potential for injection
problems arising from suspended solids and chemical precipi-
tates, filter studies were carried out to determine the
quantity and size distribution of suspended solids in well
water samples, and batch experiments were run to determine
the potential of chemical precipitation occurring during
mixing of injected fluids from several different wells and
with the native formation fluid. As injection was to occur
into a fracture dominated zone, an incompatible reaction
between the injection fluids and formation matrix was not
expected to be a problem.
Water Chemistry
As each of the geothermal wells were completed, it was
developed, tested for its yield, and water samples were
collected for chemical analysis. Additional samples were
collected from the wells during pump tests or during production
runs. Seven monitoring wells were also drilled to determine
water levels and the changes in ground water in the vicinity
of the project. Water quality data are shown in Table 6.
All the deep geothermal wells have sodium chloride type
waters, based on the predominant cation and anion in terms
of milliequivalents per liter (meq/1). The sodium concentra-
tions range from 83 to 99 percent of the cations, and chloride
65

-------
Table 6. Selected Physical and Chemical Data from the Raft River
Project Wells (from Dolenc et al, 1981).
Ch*ical Concentrations	Calculated
(w	
Depth Depth Tr.pgrature Conductivity <2 42 ( + hco~ so"2 - - sin, flo
Well	tn)	()	( C)	(>	 pH Ca Kg Sr Ha K	Li 	3 4 CI F	 	2	V Maj^Kj^C
CcotMratl
ftGK-l
1521
1105
141
2
R00
7. 3
56
0.6
1.4
455
14
1.6
41
36
776
7.9
121
148
173
HRCP-2
194
1209
144
2
500
7.1
42
0. 1
1.2
441
38
1 . 1
41
S3
7o8
8.7
131
153
18 1
RRGE-3
1789
129.1
149
8
000
6.9
224
0.5
5.2
1194
105
3. 1
44
60
2260
4.9
158
164
187
KRCP-4
1654
10S4
142
4
OSO
7.2
86
--
6.4
753

3.1
42

1400
6 . 3
104
136
--
*RGP-5
1497
1019
135
2
700
7.5
41
O. 1
1.2
484
31
1.6
35
40
BOO
7.2
133
154
169
RRCI-6
1176
509
71
10
BOO
7.2
171
1.4
8.0
2 200
32
5.1
73
60
3640
5.7
94
114
114
HRGl-7
1195
623
78
12
000

350
1.5

2200
--

32
64
4000
4.9
83
127
--
Monitor
o\
OS
Ktf-1
399
369

11
400
7.6
215
0.4
6. 3
2200
30
3.7
25
66
3680
3.4
80
125
110
KV-2
174
154
106
4
400
7.4
125
0.5
3.6
looo
25
2.5
26
57
1740
5.4
86
130
128
HW-3
159
140
71
6
200
7.5
155
6.1
1.9
1400
65
3.0
47
60
2460
5.4
60
111
160
mr-4
305
225
98
7
BOO
7.7
160
0.6
1.4
1520
31
1.7
27
53
26 10
5.6
67
116
121
WW-5
152
124
29
2
200
7.6
107
25
0.9
280
14
0. 3
120
27
 610
0.6
34

--
HW-6
305
274
44
7
600
7. 3
207
2.4
1.4
1570
56
3. 1
50
73
2270
4.9
85


Htf-7
152
140
35
2
300
7.6
95
20
0.9
33J
14
0.6
125
33
650
1.1
40

~ -
0SG8 Monitor



















USG8-1
3 36
	
28
7
400
7.8
2 30
2.5
1. 7
1500
2O0
0.9
100
45
2800
3.2
B5
--

USGS-2
243
64
55
1
960
7.7
51
4.0
0. 1
170
34
6.6
216
55
520
2.5
88
HO
182
USCS-3
4 34
60
89
5
90O
7.7
57
0.5
2.0
1270
14
1.7
77
54
2040
4.8
54
105
103
Other Ceothersialb


















Bf.MC .
126
_ _
91
3
OOO
7.4
* I
0.7
1.5
S77
21
1.4
49
65
890
7.6
74
120
144
CROOK
165

97
5
BOO
7.7
130
0.8
2.8
1020
32
2.6
34
56
1750
6.2
86
127
138
Private
15S-26C
2 3ABD1
1SS-26B
2 3DODI
110
70
29
42
4 5O0
3 900
7.6
7.1
97
104
5.0
8.0
766
644
20 1.9
16 1.1
155
169
96 1270 5.1
5 7 1100 4.5
61
SB
a.	Depth to botto of caslnq or to first perforation*.
b.	Teaipcrature Measured at surface.
c.	This well was drilled In the l<*?0's and is called the Bridqe well by Mir MSGS.
d.	This well previounty owned by Crank, and in referred to by that nae In earlier publication*.

-------
concentrations vary from 92 to 99 percent of the anions.
The waters are all low in alkalinity, ranging from 26 to
60 mg/1 as CaC02. A high level of variation was noted in
dissolved solids concentrations between the wells.
Wells RRGE-1, 2, and RRGP-5 are similar in the content
of dissolved solids, temperature, and chemical character.
Contents of dissolved chemical species are relatively low,
with specific conductivity ranging from 2,500- 2,800 umhos.
These wells have the highest fluoride levels, greater than
7 mg/1 in all three.
Wells RRGI-6 and 7 have very high dissolved solids
concentrations, predominantly sodium and chloride, and are
relatively low in fluoride, having 5.7 and 4.9 mg/1 for
RRGI-6 and 7, respectively. The temperature of these wells
is much lower than that of the others; RRGI-6 is one half
the temperature of RRGE-3.
Wells RRGP-3 and RRGP-4 are the wells along the Bridge
Fault in the central valley. Well RRGE-3 has maintained the
highest temperature of all the production wells, approaching
300P (149C).
Water Compatibility Test
Experiments were conducted at two temperatures to
simulate two injection scenarious: at 68F (20C) to simulate
injection of water from holding ponds, and at 158F (70C)
to simulate injection of water directly from the power
67

-------
plant. Water samples were collected from RRGE-1, 2, 3,
RRGP-5, and RRGI-6 and filtered through 0.45a membrane
filters to remove any suspended solids. Mixtures were
prepared by mixing all possible combinations of well water
samples. A final sample volume of one liter was made up of
equal portions of each water in the mixture. Control samples
of unmixed water from each well were also included. As
samples could not be collected from RRGP-4 and RRGI-7, they
were not included in the analysis.
After 24 hours at 68F (20C) or 158F (70C), the
mixtures were filtered through tared 0.45u filters, and the
filters were dried at 203F (95C) for one hour. Residue
and filter were then weighed on an analytical balance to
determine the amount of residue.
The quantity of precipitate expected in the mixed
samples, assuming no synergistic effects, was calculated by
summing the products of the solids formed in control samples
multiplied by fraction of the sample in the mixture. If
there are no synergistic effects of mixing, the measured and
calculated amounts of precipitate should be equal. Results
of the actual versus calculated values are shown in Table 7.
If a significant positive or negative difference resulted
between the actual and calculated values, an enhancement or
inhibition of precipitate formation would be indicated. For
the 25 mixtures held at 68F (20C), the average difference
68

-------
Table 7, Water Compatibility for Geothermal Wells RRGE-1,
RRGE-2, RRGE-3, RRGP-5 and RRGI-6 (from
Dolenc et al, 1981).
Samples Collected Through A Condensor
Temperature 20C	Temperature 70C

Calculated
Actual
Calculated
Actual
Sample Mixtures
(mg/l)
(B/L)
(mg/L)
(mg/L)
1

0.6
...
0.0
2

1.2
...
0.0
3

2.4
...
0.5
5
---
0.1
...
0.0
6

4.1
...
2.4
1-2
0.9
0.1
0.0
0.0
1-3
1.5
1.1
0.3
0.0
1-5
0.4
1.1
0.0
0.0
1-6
2.4
0.9
1.2
0.0
2-3
1.8
0.5
0.3
0.0
2-5
0.7
0.2
0.0
0.0
2-6
2.7
2.6
1.2
1.2
3-5
1.3
0.1
0.3
0.0
3-6
3.3
3.6
1.5
a
5-6
2.1
2.3
1.2
0.6
1-2-3
1.4
1.9
0.2
0.0
1-2-5
0.6
0.7
0.0
0.0
1-2-6
2.0
1.2
0.8
0.0
1-3-5
1.0
0.7
0.2
0.0
1-3-6
2.4
1.6
1.0
0.0
1-5-6
1.6
1.6
0.8
0.0
2-3-5
1.2
...
0.2
0.0
2-3-6
2.6
0.0
1.0
0.0
2-5-6
1.8
1.1
0.8
1.2
3-5-6
2.3
1.5
1.0
1.0
2-3-5-6
2.0
2.5
0.7
0.2
1-3-5-6
1.8
0.9
0.7
0.0
1-2-5-6
1.5
2.6
0.6
0.0
1-2-3-6
2.1
1.7
0.7
0.5
1-2-3-5
1.1
0.0
0.1
0.0
1-2-3-5-6
1.7
0.7
0.6
0.0
Meanb

1.25

0.19
Standard deviation^

0.94

0.39
Sample s1zeb

25
...
25
a.	Missing sample
b.	Of mixtures only
69

-------
was -0.44 rag/1 with a 95 percent confidence interval from
-0.78 to -0.10 mg/1. There is a significant inhibition
effect due to mixing, with mixed waters producing an average
of about 0.4 mg/1 less precipitated solids than expected
from the amount of solids precipitated from the unmixed
waters.
Examination of the amounts of solids precipitated from
the unmixed samples showed that RRGE-1, 2, and RRGP-5 produce
relatively little precipitate. Wells RRGE-3 and RRGI-6
produced from two to three times as many solids as the other
wells. Hot waters injected into RRGI-6 directly from the
power plant could be expected to form about 0.2 mg/1 of
solids on the average.
Based upon these experiments, it was concluded that
mixing of water from wells RRGE-1, 2, 3, RRGP-5, and RRGI-6
did not result in incompatibility problems. In fact, the
mixing of waters from these wells appeared to inhibit precipi-
tate formation. Samples held at 158F (70C) showed signifi-
cantly less precipitate formation than those held at 68F
(20C). Therefore, it was concluded that injecting water
directly from the plant could minimize the formation of
precipitates. Even with only 0.2 mg/1 of chemical precipitates
formed, 2.2 kg/day (4.8 lbs/day) of solids would be injected,
assuming an average flow of approximately 7,564 L/m (2,000 gpm).
70

-------
Filter Studies
Studies were also conducted to determine the amount and
particle size distribution of the suspended solids in the
geothermal waters. In addition to determining the potential
for clogging the reservoir, an analysis of the particle size
distribution also permitted the sizing of the filter screens
for the injection system. Particle size distributions were
determined for water samples from RRGE-2 and RRGE-3. Total
solids were monitored during two additional tests.
The filtering apparatus used in the tests consisted of
a series of stainless steel filters in the following sizes
and orders 230, 140, 90, 60, 15, and 2u. A 0.4 5u membrane
filter was also used. The 230 and 140u filters were used in
only one test. For determining total suspended solids, the
2.0u filter was used alone. The filter screens were placed
in stainless steel filter holders and from 20 to 100 liters
of water passed through the series. The filters were dried
at 220F (105C) for three hours and weighed on an analytical
balance to determine the quantity of suspended solids.
The distribution of particle size shows that almost all
of the particles from the well water samples are less than
90u in diameter. Curiously, more particulate matter originated
in the distribution system when compared with the wells.
The particulate matter from the pipelines generally exceeds
90u grain size.
71

-------
To test for temporal effects, RRGE-2 was tested for
total suspended solids once every 24 hours for five days
during an injection test of RRGI-6. There was a generally
increasing trend in solids form 0.17 mg/1 the first day to
just over 1 mg/1 on the fifth day. The concentrations were
in the same range as an earlier test, but due to the limited
duration of the test, it was impossible to predict the
eventual steady-state solids concentration. Suspended
solids were determined during a fourth test when water from
a holding pond near RRGE-1 was injected into RRGI-7. The
average concentration of suspended solids in this water was
34.8 mg/1, much higher than that produced from either RRGE-2
or 3.
In RRGE-3, 3 5.5 percent of the suspended solids ranged
between 2.0 and 15.Ou in grain size. About 94 percent of
the solids measured before injection into RRGI-4 apparently
were picked up in the pipeline network. Without removal of
these suspended solids, approximately 800 kg (1,764 lbs) per
day would be injected into the receiving formation. Even
with the installation of 90u filters, however, approximately
245 kg (540 lbs) of solids per day would be injected, assuming
an average flow of 7,564 L/m or 2.9 mgd. The ultimate
impact of this suspended solids loading on the receiving
formation could not be determined based on the testing
completed. A possible mitigating factor to the contribution
of the pipeline would be to periodically flush the lines to
remove the particulate matter.
72

-------
REVIEW COMMENTS
Note: 1) Chemistry of production well and injection well
formation fluids
2)	Water compatibility testing of injection fluids
with formation fluids and matrix, and confining
zone matrix
3)	Preinjection treatment requirements
4)	Special injection practices
1) The chemical characteristics of a waste fluid and
the injection zone fluid and mineralogy are extremely important
in determining the suitability of the waste for subsurface
disposal. Although the UIC regulations do not state any
requirements for wastewater compatibility studies, the
permit applicant must submit information on the chemical
analysis of the waste and formation fluids to the permitting
authority.
All the geothermal wells contain formation water with
less than 10,000 mg/1 TDS which designates the production
zones as potential underground sources of drinking water
(USDW). However, these aquifers are exempted from a USDW
classification due to their geothermal energy-producing
characteristics. The chemical constituents in the formation
water are primarily sodium and chloride with small concentra-
tions of calcium and sulfate. The permitting authority
should be aware of the potential for geothermal waters to be
classified as a hazardous waste. Some geothermal wastes,
73

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such as those from the Imperial Valley, California, could be
classified as hazardous in one or more categories of pH,
radioactivity and EP toxicity. Chemical analysis of the
Raft River geothermal waters should evaluate the geothermal
waste against hazardous waste criteria.
2) An extensive water compatibility test was conducted
on the waste and injection zone fluids at the Raft River
project. Accurate experiments were performed on wastewater
from low temperature holding ponds and high temperature
power plant wastewater. All combinations of well water
samples were mixed and studied. Filter studies were also
conducted to estimate the amount of injected suspended
solids into the reservoir.
An incompatible reaction of the waste and injection
formation fluids is not expected to be a problem due to
their similar composition and properties. However, reservoir
and injection conditions should be simulated for accurate
compatibility results.
The reactions between noncompatible fluids cause the
formation of precipitates which decrease the porosity and
hydraulic conductivity of the reservoir. These precipitates
are typically:
1)	precipitation of alkaline earth metals (calcium,
barium, strontium and magnesium) as relatively
insoluble carbonates, sulfates, orthophosphates,
fluorides and hydroxides;
2)	precipitation of metals such as iron, cadmium,
zinc and chromium as insoluble carbonates, hydrox-
ides, orthophosphates and sulfides; and
74

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3) precipitation of oxidation-reduction reaction
products.
(Selm and Hulse, 1960)
Corrosion or scale inhibitors used in the well annulus may
also cause the formation of precipitates.
Although the injection zones exhibit a fracture dominated
porosity which decreases the precipitate formation potential,
a compatibility test between the injection fluids and formation
matrix should be conducted. The injection of corrosive or
acidic fluids into incompatible formations may result in
adverse environmental and health conditions such as an
explosive build-up of carbon dioxide generated between the
injected fluid and formation rock. Similarly, injection of
compounds yielding oxygen as breakdown products could clog
the formation with iron and manganese oxides and injection
of less saline water, as in the Raft River Geothermal Project,
could result in clay swelling which may clog the formation.
In addition, compatibility testing of the injected water
with the confining zone should be conducted. Chemical
reactions could occur between the injected water and the
confining zones which could reduce their ability to confine
the waste fluid.
3) The preinjection mixing of well waters actually
inhibited the formation of precipitate. It was also discovered
wastewater from the power plant reduces precipitate formation.
75

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Filtering is necessary to remove suspended solids in the
injection water to help prevent reservoir plugging.
4) A proposed injection procedure must be submitted
to the permitting authority for review. This procedure plan
would include any pretreatment requirements and special
injection practices such as pressure and volume rates,
filtering, and additives.
76

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VIII. MONITORING WELL PROGRAM
The Raft River monitoring well program was designed to
evaluate and predict the impact of geothermal development on
the intermediate ground-water aquifers. Seven intermediate
monitoring wells (MW-1 through MW-7), drilled in 1978, are
located near the geothermal production and intermediate
depth injection wells. The depth and location of each well
was designed to detect any response to geothermal injection
before a response is noticeable at irrigation or domestic
wells. The wells were drilled to varying depths designed to
ensure that short- and long-term effects could be made. The
locations of the monitoring wells and their relationship to
the production and injection wells are shown on Figure 1.
Table 8 summarizes the characteristics of the monitoring
wells at the project site.
The monitoring wells are equipped with continuous
reading water level recorders. MW-1 and MW-2 have digital-
readout quartz pressure transducers installed at the wellhead
for monitoring wellhead pressure. MW-3 through MW-7 have
standard water level recorders. Water samples for chemical
analyses are collected each quarter with either a submersible
pump or downhole samplers to detect changes in water chemistry
caused by geothermal development.
General Ground-Water Trends and Test Responses
Water levels in the shallow aquifer near the Raft River
have declined over the past 30 years due to extensive irrigation
77

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Table 8. Monitoring Well Summary
(from Dolenc et al, 1981).
Well
Number
Ground
Level
Elevation
(ft/m)
Ground-Water
Level
Elevation
(ft/m)
Well
Depth
(ft/m)
Bottom Hole
Temperature
(P/C)
TDS
(ppm)
MW-1
4839/1475
4940/1506
1309/339
	
6270
MW-2
4820/1469
4859/1481
570/174
221/106
5190
MW-3
4829/1472
4780/1457
501/153
160/ 71
4300
MW-4
4816/1468
4810/1466
1000/305
207/ 97
4370
MW-5
4810/1466
4741/1445
499/152
82/ 28
1229
MW-6
4820/1469
4747/1447
1000/305
111/ 44
4820
MW-7
4836/1474
4757/1450
499/152
95/ 35
1380

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pumping. In addition, analysis of five years of water level
data from USGS-2 (790 feet) suggests that there has been a
corresponding decline in shallow groundwater levels in the
injection area. Two years of ground-water records from the
monitoring wells are inconclusive to support this trend.
Seasonal water level changes are apparent in several of
the monitoring wells. A rise in water levels occurring in
the spring appear to result from shallow recharge. These
levels tend to drop during the period from mid-spring to the
end of the irrigation season. With the termination of
irrigation pumping, however, the following annual fluctuations
have been noted:
Wei 1	Seasonal Fluctuation (m)

1979
1980
MW-1

2.07
MW-2

2.60
MW-3
2.44
1.83
MW-4
3.05
2.10
MW-5
5.98
4.76
MW-6
2.84
2.04
MW-7
2.74
2.16
Individual Monitoring Well Responses
Water level responses at MW-1 and MW-2 indicate direct
hydraulic connection with the geothermal resource. The
lowered water levels indicate a direct relation to geothermal
79

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production activity rather than injection or irrigation
pumping. The continued production of geothermal fluids in
this area could result in a decrease in local upward geothermal
fluid leakage. This decrease would result in declining
water levels in MW-lf MW-2, and the BLM and Crook wells. On
the basis of the responses noted to date, it is not expected
that injection activities will have any effect in this area.
MW-3, MW-5, MW-6 and MW-7 appear only to respond to
seasonal fluctuations and irrigation pumping. The magnitude
of the response varies, apparently due to the varying distances
from the irrigation wells. Geothermal fluid production or
injection is not expected to have any significant effects in
this area.
MW-4 responds rapidly to geothermal injection activities.
The nature of the hydraulic communication is postulated to
be via soft-sediment fractures. Fracture injection activities
are expected to cause water levels in MW-4 to continue to
rise. Unfortunately, due to the lack of sufficient data on
the nature of these shallow fractures, it is impossible to
predict the total expected impact of injection activities on
the shallow aquifer system.
Specific recommendations have been developed to attempt
to better understand the nature of the monitoring well
responses to geothermal fluid production and injection
activities. In order to minimize the variables affecting
80

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the response interpretations, future production and injection
testing should be conducted during the months of December
through March to eliminate the effects of irrigation pumping
on the shallow aquifers. In addition, quarterly chemical
analyses and temperature logging of all monitoring wells
will be conducted to more precisely define the effects of
geothermal production and injection activities on the shallow
aquifer system.
81

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REVIEW COMMENTS
Note: 1)	Evaluation of only intermediate depth aquifers
2)	Location of monitoring wells
3)	Water sampling on a quarterly basis
4)	Response of MW-4
5)	Further recommended testing
1) The monitoring well program evaluates and samples
only the intermediate depth zone. No monitoring wells were
constructed within the surface alluvium aquifers. Although
upward leakage from the injection zone could be detected in
the monitoring wells, a defect in the casing or cement near
the surface may allow injected fluids to migrate into the
upper aquifer undetected. Because information on the monitoring
well construction and completion methods has not been obtained
in this case study, an evaluation on the design of the
monitoring wells and the efficiency of the monitoring system
cannot be completed. The number, location, and construction
of monitoring wells shall be based on several criteria
including location of USDWs, affected population, injection
well density and the proximity of the injection location to
drinking water withdrawal areas, and must be approved by the
permitting authority.
According to UIC regulations, only Class III injection
wells are required to have a monitoring well program unless
82

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required for other classes by the EPA. If injection occurs
into a formation containing less than 10,000 mg/1 TDS as in
the Raft River case, monitoring wells must be completed into
the injection zone and into any USDW(s) above the injection
zone. Injection into a formation containing water of greater
than 10,000 mg/1 TDS requires no monitoring wells in the
injection zone.
2)	To advise in the design of a monitoring well
program, several questions must be answered about the location
of the monitoring wells:
a.	Are the monitoring wells sited downgradient
from the injection zones? The direction of
ground-water flow must be known to determine
the downgradient direction.
b.	Do any upgradient monitoring control wells
exist? What effect will injection have on
the direction of ground-water flow?
c.	Are the monitoring wells sited to evaluate
both porous media flow and fracture flow in
the intermediate zone?
d.	What is the proximity of the injection well
and monitoring wells to domestic and public
water supply wells? Does the monitoring
program delineate an area to be protected?
e.	Does the location of the monitoring wells
create an early warning detection system?
3)	Ground-water sampling for water quality determina-
tions are taken on a quarterly basis at the Raft River site
in accordance with the UIC regulations. However, the UIC
regulations for Class III wells state that semi-monthly
83

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monitoring of fluid levels in the injection zone and chemical
parameters to determine water quality are required.
4,5) Increased water levels in MW-4 to geothermal
injection activities indicate a hydraulic communication via
fractures in the Salt Lake Formation. The permitting authority
should suggest further investigations on the fracture systems
in the injection zone and USDW(s). Shallow monitoring wells
should be sited near the MW-4 to monitor the impact of
injection on the upper Raft River and surface alluvium
aquifer system.
84

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IX. SUMMARY
Deep well injection of most types of nonhazardous and
hazardous waste is a safe method of waste disposal if the
systems are properly located, designed, operated and regulated.
The planning and operation of an effective injection system
is a multidisciplinary effort involving geological, engineering,
chemical, biological and legal expertise. Detailed geologic
investigations must be conducted at each injection system
site. A reservoir so chosen will have the capability to
store and contain injected waste. Proper well design and
construction is necessary to adequately handle the injected
waste and protect any source of uncontaminated water.
Operating limitations must be established for every well to
ensure that the limits of the equipment and the reservoir
are not exceeded. Research is needed to provide the physical,
chemical and biological effects of injection into subsurface
zones. Finally, industry should be familiar with the UIC
program to ensure proper implementation of construction,
operation, monitoring and reporting requirements.
This case study of the Raft River Geothermal Project
injection system is intended to advise the permitting authority
of important injection well technology and UIC concepts
through the evaluation of individual elements of the project.
Although only a portion of the available documentation of
this project was presented in this manual, the selected
85

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information provided a sufficient background to discuss many
technical and regulatory criteria of an injection well
system.
The assessment of the contamination potential of Class V
wells is an important issue facing the permitting authority.
Because the Raft River geothermal wells are Class V wells,
this manual should be of primary assistance to a permit
writer. In general, the main concern of a Class V well
assessment is whether injection occurs into or above a USDW.
A well which injects into or above a known and used USDW
should be closely monitored for adverse environmental effects.
Additional considerations for assessing the contamination
potential of a Class V well includes the nature and volume
of injected fluids, proper construction specifications, the
compatibility of injected fluids with the formation fluids
and matrix, and the well density in a specific area.
In conclusion, to aid the permitting authority in the
acquisition and review of required data for an injection
well system, application checklists for Class I, II, and III
wells are provided in Appendix B.
86

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REFERENCES
Algermisen, S. T. 1969. Seismic Risk Studies in the United
States, Fourth World Conference on Earthquake Engineering
(Santiago, Chile, January 14, 1969); Preprint, lOp.
Covington, H. R. 1976. Deep Drilling Data, Raft River
Geothermal Area; USGS Open-File Report 76-66 5.
Dolenc, M. R. et al. 1981. Raft River Geoscience Case
Study; EG&G Idaho, EGG2125, Volume 1, 145p.
Everett, L. G. 1980. Groundwater Monitoring; General
Electric Company, Schenectady, NY, 44Op.
Miller, L. G. and S. M. Prestwich. 1979a. Completion
Report: Raft River Geothermal Injection Well Six (RRGI-6)-
U.S. Department of Energy, IDO-10083, 12p.
Miller, L. G. and S. M. Prestwich. 1979b. Completion
Report: Raft River Geothermal Injection Well Seven
(RRGI-7); U.S. Department of Energy, IDO-10084, 12p.
Reeder, L. R. et al. 1977. Review and Assessment of Deep
Well Injection of Hazardous Wastes; EPA-600/2-77-029a
Volume 1, 187p.	'
Selm, P. R. and B. T. Hulse. 1960. Deep Well Disposal of
Industrial Wastes"; Chem. Eng. Prog., Volume 56, No 5
pp 138-144.	* '
Walker, E. H. et al. 1970. The Raft River Basin as of 1966:
A Reappraisal of the Water Resources and effects of
Groundwater Development; USGS and Idaho Department of
Water Resources Water Information Bulletin No. 19.

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APPENDIX A
CONVERSION FACTORS

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CONVERSION FACTORS
Length:
1 meter1.0936 yards
3.2808 feet
--39.370 inches
1 foot0.3048 meter
1 mile1.6094 kilometers
5,280 feet
1 kilometer0.62137 mile
Areas
1 cm20.1550 in2
1 in2--6.452 cm2
1 m210.764 ft2
1 ft2929.0 cm2
1 acre43,560 ft2
2.471 acres
2
1 hectare10,000 m,
 4,047 m
1 mi22.590 km2
--640 acres
Volume:
3
1 m 1,000 liters
35.314 ft3
--264 gal (U.S.)
1 ft -28.320 liters
7.481 gal (U.S.)
1 gal3.785 liters
1 acre foot43,560 ft3
3,259 x 105 gal
--1,234 m3

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APPENDIX B
PERMIT APPLICATION CHECKLISTS

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Page 1 of 5
UIC CLASS I INJECTION WELL APPLICATION CHECKLIST
NEW	 OR EXISTING	
(For Existing Well Actual Data Shall Be Used in Lieu of "Proposed",
"Expected", "Planned", Etc.)
APPLICATION NO. 			
APPLICANT		
STATE/COUNTY		
REVIEWED BY		
DATE	
Justification
1.	Treatability studies of alternative methods of waste disposal
2.	Indicate whether this waste is currently being produced
3.	Current method of disposal
4.	Manufacturing processes
5.	Products
Well Location
1.	Plant location map
2.	Well location in relation to plant and survey lines
3.	Surface ownership map
4.	Waiver from subsurface owner
5.	Area of review with basis
Water Well Data
1.	Water well map (plant and adjacent property).
2.	Tabulation of water well data
	 a. Oepth
	 b. Water level
	 c. Owner
	 d. Chemical analyses
3.	Piezometric map of the water table using wells from C.l
4.	Base of usable quality water (USDW)

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Page 2 of 5
Artificial Penetrations
1.	Map showing all artificial penetrations within study area, along
with name and location of all surface bodies, springs, mines,
quarries, and other pertinent surface features including
residences and roads with the scale equal on D.l and C.l.
2.	Tabulation of artificial penetrations
	 a. Operator
	 b. Lease or owner
c.	Distance
	 d. Well construction data
	 1) casing
	 2) setting depth
	 e. Cementing data
	 f. Well number
g. Plugging data for abandoned wells
	 h. Corrective actions
3.	Mineral permit/drilling permit
4.	Schematic sketches of penetrations
5.	Other subsurface disposal operations in the area (names, distance
from the proposed well, injection interval)
6.	Hydrologic implications of proposed subsurface disposal
operations to existing injection operations
Geology
1.	USGS topographic map
2.	Regional geology
	 a. Surface geologic map
b. Cross-sections
	 c. Structural contour map
3.	Local geology
	 a. Cross-sections with log control, geologic units and
lithology from surface to lower confining zone or major
structure
b. Description of upper and lower confining strata
(lithology, permeability, etc.)
	c. Description of faulting, Uneatlons, and fracturing In
the area
d.	Depositional, structural and tectonic history of the
area
	e. Lithology of all units overlying Injection zone
	f. Hydrology of all units overlying Injection zone
	 g. Structural contour map of Injection zone
	 h. Isopach map of the injection zone (each one, if more
than one)

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Page 3 of 5
Characteristics of Injection Interval - For existing well provide
results of all and any tests relating to the following:
1.	Depth
2.	Porosity
3.	Perneability
4.	Temperature
5.	Reservoir pressure or hydrostatic head
6.	Fluid saturation and chemical characteristics of formation and
formation fluids
7.	Location, extent and effects of faulting, fracturing, and/or
solution channels
8.	Fracture gradients or formation breakdown pressure (show
calculations and methods used)
9.	Piezometric surface map or static fluid level and regional
gradient
Characteristics of Waste Streams - For existing well provide
historical data and sampling frequencies
1.	Description of chemical and physical characteristics
2.	Analysis of final waste stream
3.	Analysis of individual waste streams and percentage of total
waste volume
4.	Toxicity and degradability rates and levels
5.	Compatibility of final waste stream, formation, confining zone and
formation fluids at expected pressures and temperature
6.	Corrosion tests on all materials to be in contact with waste
fluids including long string casing
7.	Volume of the waste
	 a. Percentage of each stream to total effluent
	 b. Average and maximum injection rates
	 c. Monthly and yearly volume
	 d. Anticipated life of the project
Proposed Well Completion (all materials must be new unless *>proved bv
Department)	J
1.	Total depth
2.	Type of completion (including perforating or screen settina
depths)
3.	Surface casing: size, type, weight, grade and setting depth
4.	Long string casing: size, type, weight, grade and setting depth
5.	Liner or other casing: size, type, weight, grade and setting
depth	3
6.	Number and location of centralizers, scratchers, etc.

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Yes _
_ No	
Yes
No
Yes
~ No
Page 4 of 5
	 7. Logging program
a.	deviation checks (frequency)
b.	surface casing; open hole
i) resistivity
ii) spontaneous potential		 	
iii) caliper	Yes	No	
c.	surface casing; cased hole
i) cement bond log	Yes	No	
ii) temperature or density	Yes	No	
d.	intermediate or long string casing; open hole
i) resistivity	Yes	No	
ii) spontaneous potential	Yes	No	
iii) gamma ray	Yes	No	
i v) porosity	Yes	No	
v) fracture finder logs	Yes	No		
e.	intermediate or long casing; cased hole
i) cement bond log	Yes	No	
ii) temperature or density	Yes	No	
	 8. Proposed bottomhole testing and coring
9. Cement program (for all casing strings)
	 a. Service company recommendations plus studies to
determine suitability of selected cements
b.	Volumes including percent excess (to surface + 20%
excess)
c.	Types of cement and additives
d.	Slurry weights and yields
	e. Cementing equipment (guide shoes, float collars, O.V.
tools, etc.)
10. Proposed well stimulation program
	11. Description of proposed injectivity tests
	12. Size and type of tubing and setting depth
		13. Size and type of packer and proposed setting depth
	14. Diagramatic sketch of well
	15. Diagramatic sketch of wellhead facilities including annulus
monitoring system
I. Surface Installations (must meet requirements from application
instructions)
1.	Description of injection pressure and volume monitoring system
2.	Description of annulus monitoring system
3.	Filter types and location including capacity and capability
4.	Description of injection pumps including type and capacity

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Page 5 of 5
	 5.	Detailed description of pretreatment processs and facilities
	 6.	Flow diagram with each waste stream identified
	 7.	Plat of plant showing all waste flow lines and pre-injection
system
	 8.	Tank size, capacity, and construction materials
	 9.	Plans for disposal of sludges or solids
	10.	Emergency storage facilities
J. Injection Well Operation
	 1. Expected maximum and average injection pressures
	 2. Formation pressure increase calculations
	 3. Minimum fluid front calculations including dispersion of injected
fluids
	 4. Provisions for insuring proper well maintenance, mechanical
integrity, and qualifications of personnel who will supervise
well operation
	 5. Proposed well abandonment procedure in the event of well failure
of expiration of the life of the project (including plugging and
abandonment cost estimate)
	 6. Existing operating permit
K. Other
	 1. Contingency plan and description of facilities to cope with well
failures or shut-in. If one well system is used, then a minimum
of 30 days above ground storage system is necessary
REMARKS AND COMMENTS OF REVIEWER:

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Page 1 of 3
UIC CLASS II INJECTION WELL APPLICATION CHECKLIST
NEW	CONVERSION
APPLICATION NO.
APPLICANT 	
STATE/COUNTY __
REVIEWED BY 	
DATE
Well Location
1.	Plant location map
2.	Area of review and basis
3.	Number, name, location of:
producing wells
	 injection wells
abandoned wells
	 dry holes
water welIs
4.	U553T topographic map or map showing bodies of waters, mines,
quarries, residences, roads, faults, surface features
Penetrations
1.	Tabulation of wells penetrating injection zone within area of
review
2.	Tabulation of wells penetrating formations affected by
injection pressure(s) greater than fracture pressure
3.	Corrective actions
Operating Data
1.	Average and maximum daily rate of injection
2.	Average and maximum daily volume of injection
3.	Average and maximum injection pressure

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Page 2 of 3
4.	Demonstration of mechanical integrity
5.	Waste stream physical and chemical analyses and characteristics
~ 6.	Source of sample(s)
" 7.	Monitoring of injection fluids, pressures, volumes, rates
Geology-Hydrology
1. Geological data on injection zone, including lithology, name,
thickness, depth, permeabi1ity, porosity
_ 2. Geological data on confining zone, including lithology, name,
thickness, depth, permeability
3.	Geologic-hydrologic name of all underground sources of drinking
water (USDWs) affected
4.	Depth of base(s) of USDWs
5.	Faults
6.	Chemical nature of formation fluids and materials
Well Construction/Completion
1.	Schematic or other appropriate drawings of surface and subsurface
construction details
2.	Total depth and/or plug-back depth
3.	Type of completion, packer, packerless, etc.
4.	Surface casing: size, type, weight, grade, depth
5.	Long string casing: size, type, weight, grade, depth
6.	Liner or other casing size, type, weight, grade, depth
7.	Centralizers location, etc.
[ 8.	Cementing quantities, class
" 9.	Hole size
10.	Tubing-packer: size, type, weight, grade, depth
Well	Logs/Surveys
1.	Deviation checks
2.	Surface hole (open)	electric and caliper logs
' 3.	Surface casing cement bond, temperature
4.	Intermediate - long string hole (open) - electric, porosity,
gamma ray, fracture	finder
5.	Intermediate - long	string casing cement bond, temperature
Reservoir Properties
1.	Formation pore (fluid) pressure
2.	Estimated fracture pressure
3.	Proposed formation testing
' 4. Proposed stimulation program

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Page 3 of 3
H.	Contingency Plans
	 1. Shut in
	 2. Failure
I.	Plugging and Abandonment
	 1. Plan
	 2, Performance bond or other assurance of financial responsibility
REMARKS AND COMMENTS OF REVIEWER:

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Page 1 of 4
UIC CLASS III INJECTION WELL APPLICATION CHECKLIST
NEW 	 OR EXISTING 	
(For Existing Well Actual Data Shall Be Used in Lieu of "Proposed",
"Expected", "Planned", Etc.)
APPLICATION NO. 		
APPLICANT 		
STATE/COUNTY 			
REVIEWED BY 	
DATE 	
A.	Justification
	 1. Treabability studies of alternative methods of waste disposal
	 2. Indicate whether this waste is currently being produced
		 3. Current method of disposal
	 4. Manufacturing processes
	 5. Products
B.	Well Location
	 1.	Plant location map
	 2.	Well location in relation to plant and survey lines
	 3.	Surface ownership map
	 4.	Waiver from subsurface owner
	 5.	Area of review with basis
C.	Water Well Data
	 1. Water well map (plant and adjacent property)
	 2. Tabulation of water well data
	 a. Depth
	 b. Water level
	 c. Owner
	 d. Chemical analyses
	 3. Piezometric map of the water table
	 4. Base of usable quality water (USDW)

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Page 2 of 4
Artificial Penetrations
1.	Map shoving all artificial penetrations within study area, along with
name and location of all surface bodies, springs, mines, quarries, and
other pertinent surface features including residences and roads with
the scale equal on D.1 and C.l.
2.	Tabulation of artificial penetrations
	 a. Operator
	 b. Lease or owner
	 c. Distance
	 d. Well construction data
	 1) casing
2) setting depth
	 e. Cementing data
	 f. Well number
	 g. Plugging data for abandoned wells
h. Corrective actions
3.	Mineral permit/drilling permit
4.	Schematic sketches of penetrations
5.	Other subsurface disposal operations in the area (names, distance from
the proposed well, injection interval)
6.	Hydrologic implications of proposed subsurface disposal operations to
existing injection operations
Geology
1.	USGS topographic map
2.	Regional geology
a. Surface geologic map
	 b. Cross-sections
	 c. Structural contour map
3.	Local geology
	a. Cross-sections with log control, geologic units and lithology
from surface to lower confining zone or major structure
	 b. Description of upper and lower confining strata (lithology,
permeability, etc.)
	 c. Description of faulting, llneationa, and fracturing in the
area
	 d. Depositional, structural and tectonic history of the area
	 e. lithology of all units overlying injection zone
	 f. Hydrology of all units overlying injection zone
	 g. Structural contour map of injection zone
	 h. Isopach map of the injection zone (each one, if more than
one)

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Page 3 of 4
F.	Characteristics of Injection Interval - For existing well provide results
of all and any tests relating to the following:
	 1. Depth
2. Porosity
	 3. Permeability
4.	Temperature
5.	Reservoir pressure or hydrostatic head
6.	Fluid saturation and chemical characteristics of formation and formation
fluids
7.	Location, extent, and effects of faulting, fracturing, and/or solution
channels
8.	Fracture gradients or formation breakdown pressure (show calculations
~ and methods used)
9.	Piezometric surface map or static fluid level and regional gradient
G.	Characteristics of Injection Fluid - For existing well provide historical
data and sampling frequencies:
1.	Description of chemical and physical characteristics
2.	Volume of injected fluid
	 a. Average and maximum injection rates
	 b. Monthly and yearly volume
	 c. Anticipated life of the project
H.	Injection Fluid Changes
	 1. Expected changes in injection fluid movement
		 2. Native fluid displacement
	 3. Direction of injected fluid movement
I.	Proposed Well Completion
	 1. Total depth
2. Type of casing and tubing
	 3. Type of completion (including perforating or screen setting depths)
	 A. Logging program
	 a. Deviation checks (frequency)
	 b. Geophysical logs
	 1) resistivity
	 2) spontaneous potential
	 3) caliper
	 4) cement bond
	 5) temperature
	 6) density
	 5. Cement program (for all casing strings
	 a. Types of cement and additives
	 b. Volumes Including percent excess
c. Cement waiver

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	 6. Proposed well stimulation program
7. Diagrammatic sketch of well
J. Design of Monitoring Well System
Chemical Analysis
______ a. Injection zone fluid
	 b. USDW
Map of mining area and collapse structures
Map of potential catastrophic collapse area
Subsidence surveying
Subsidence control methods and calculations
Monitoring well construction
	 a. Total depth
	 b. Type of casing and completion
Environmental concerns
a. Affected population
	 b. Proximity of Injection operation to drinking water withdraw
points
	 c. Injection well density
K. Injection Well Operation
	 1. Expected maximum and average injection pressures
	 2. Formation pressure increase calculations
	 3. Minimum fluid front calculations includingdispersion of injected
fluids
	 4. Proviions for insuring proper well maintenance, mechanical integrity,
and qualifications of personnel who will supervise well operation
	 5. Proposed well abandonment procedure in the event of well failure of
expiration of the life of the project (including plugging and abandon-
ment cost estimate)
_____ 6. Existing operating permit
L. Other
	 1. Contingency plandand description of facilities to cope with well
failures or shut-in.
	 2. Performance bond or other assurance of financial responsibility
REMARKS AND COMMENTS OF REVIEWER:
1.
2.
3.
4.
5.
6.
7.

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