U.S. Department of the Interior 

Bureau of Reclamation 

Technical Service Center November 2012 

Technical Memorandum No. 86-68330-2012-27 

Review of Geologic Investigations 

and Injection Well Site Selection, 

Paradox Valley Unit, Colorado 
 Mission Statements 

 The mission of the Department of the Interior is to protect 

 and provide access to our Nation’s natural and cultural 

 heritage and honor our trust responsibilities to Indian 

 Tribes and our commitments to island communities. 

 The mission of the Bureau of Reclamation is to manage, 

 develop, and protect water and related resources in an 

 environmentally and economically sound manner in the 

 interest of the American public. 

Review of Geologic Investigations

 and Injection Well Site Selection,

Paradox Valley Unit, Colorado

TABLE OF CONTENTS

1.0 Introduction............................................................................................................................... 1

2.0 Project Background................................................................................................................... 3

2.1 Paradox Valley Unit...................................................................................................... 3

2.2 Feasibility Studies......................................................................................................... 3

2.3 PVU Injection History .................................................................................................. 5

2.3.1 Phase I (July 22, 1996 - July 25, 1999) ........................................................ 7

2.3.2 Phase II (July 26, 1999 - June 22, 2000) ...................................................... 7

2.3.3 Phase III (June 23, 2000 - January 6, 2002) ................................................. 7

2.3.4 Phase IV (January 7, 2002 - present)............................................................ 7

2.4 Injection Pressures ....................................................................................................... 9

2.5 Consideration of a Second Injection Well .................................................................. 10

3.0 Geology................................................................................................................................... 10

3.1 Regional Geology ....................................................................................................... 10

3.1.1 Geologic Setting ......................................................................................... 10

3.1.2 Faults and Joints.......................................................................................... 11

3.2 Local Geology............................................................................................................. 13

3.2.1 Paradox Valley Morphology....................................................................... 13

3.2.2 Stratigraphy................................................................................................. 13

3.3 Early PVU Geologic Investigations............................................................................ 14

3.3.1 Development of Structural Geologic Models ............................................. 14

3.3.2 Reservoir Characterization ......................................................................... 39

3.4 Additional Information ............................................................................................... 41

3.4.1 Well Data .................................................................................................... 41

3.4.2 Seismic Reflection Data.............................................................................. 42

3.4.3 Induced seismicity ...................................................................................... 42

4.0 Injection Well Site Selection .................................................................................................. 50

4.1 Criteria for Site Selection ........................................................................................... 50

4.2 Proposed Sites from Previous Studies ........................................................................ 52

5.0 Discussion............................................................................................................................... 57

6.0 References............................................................................................................................... 59

Paradox Valley Geologic Well Data ............................................................................. Appendix A
LIST OF TABLES

TABLE 1: Paradox Valley Stratigraphy. .................................................................................... 15

TABLE 2: Wells providing data for original PVU geophysical interpretations........................... 19

TABLE 3: Porosity of the Leadville Formation measured in local and regional wells................ 40

LIST OF FIGURES

FIGURE 1: Location of the deep injection well at Reclamation’s Paradox Valley Unit in western 

Colorado.......................................................................................................................................... 1

FIGURE 2: Location of the Paradox Valley Unit brine extraction wells 

and PVU Injection Well #1............................................................................................................. 2

FIGURE 3: Locations of existing deep petroleum exploration wells in the Paradox Valley area. 5

FIGURE 4: Schematic diagram of Paradox Valley Injection Test Well No. 1. ............................. 6

FIGURE 5: Daily average injection flow rate, daily average surface injection pressure, and daily 

average downhole pressure at 4.3 km depth during PVU injection operations.............................. 8

FIGURE 6: Map showing the location and major features of Paradox Basin.............................. 11

FIGURE 7: Locations of seismic reflection lines and deep wells used in early PVU geophysical 

studies. .......................................................................................................................................... 18

FIGURE 8: Structural contour maps of the top of the Cutler formation. ..................................... 21

FIGURE 9: Structural contour maps of the top of the Paradox formation. .................................. 22

FIGURE 10: Structural contour maps of the top of the Leadville formation. .............................. 24

FIGURE 11: Isopach maps of the Paradox formation massive salt member. .............................. 26

FIGURE 12: Isopach maps of the Leadville formation................................................................ 27

FIGURE 13: Isopach map of Leadville intervals having greater than 5% porosity. .................... 29

FIGURE 14: Locations of cross sections A-B and A-C from Katz and Carroll (1984) and cross sections X-X’ and Y-Y’ from Bremkamp et al. (1984). .................................................................... 30

FIGURE 15: Cross section X-X’ from Bremkamp et al. (1984). ................................................. 31

FIGURE 16: Cross section Y-Y’ from Bremkamp et al. (1984). ................................................ 32

FIGURE 17: Cross section A-B from Katz and Carroll (1984). .................................................. 33

FIGURE 18: Cross section A-C from Katz and Carroll (1984). .................................................. 34

FIGURE 19: Regional structural contour map of the top of the Leadville Formation................. 35

FIGURE 20: Cross sections A-A’, B-B’, and C-C’ from Bremkamp and Harr (1988). .............. 36

FIGURE 21: Regional contour map of hydrostatic pressure within the Leadville Formation. .... 38

FIGURE 22: Location of a local well that has been drilled to the depth of the Leadville formation 

since the 1980’s, and the locations of two additional seismic reflection lines that were purchased 

by Reclamation in 2004. ............................................................................................................... 43

FIGURE 23: Scatter plot of earthquakes having M >= 0.5 and locating less than 8.5 km deep, plotted as a function of date and distance from PVU Injection Well #1, and plot of the daily average 

injection flow rate. ........................................................................................................................ 44

FIGURE 24: Maps showing the spatial distribution of shallow seismicity recorded in the Paradox 

Valley area over time: (a) injection tests, 1991-1995 (b) continuous injection,1996-2000 (c) con-
tinuous injection, 2001-2008 (d) continuous injection, 2009-2012. ............................................ 46

FIGURE 25: Contour map of hydrostatic pressure within the Leadville formation and predicted 

area of least resistance to fluid movement and pressure rise from injection into PVU Injection Well 

#1, and epicenters of shallow earthquakes interpreted to be induced by fluid injection into PVU Injection Well #1.............................................................................................................................. 48

FIGURE 26: Locations of potential sites for an injection well, proposed by Katz and Carroll 

(1984), Bremkamp et al. (1984), and Harr (1989)........................................................................ 53
1

1.0 Introduction

The Bureau of Reclamation (Reclamation) operates a deep injection well at Paradox Valley in 

western Colorado (Figure 1), as part of the Paradox Valley Unit (PVU) of the Colorado River 

Basin Salinity Control Program (CRBSCP). Paradox Valley, overlying a salt anticline, is a major 

contributor to the salt load of the Colorado River. The Dolores River, a tributary of the Colorado, 

picks up about 205,000 short tons (185,000 metric tons) of salt annually from natural brine 

inflows as it crosses Paradox Valley. PVU was authorized for construction by the Colorado River 

Basin Salinity Control Act of 1974 (Public Law 93-320; amended in 1984 as Public Law 98-569). 

Figure 1: Location of the deep injection well at Reclamation’s Paradox 

Valley Unit in western Colorado.

Castle

Valley

La Sal

Mtns.
2

The purpose of PVU is to divert up to 90 percent of the Paradox Valley brine inflows from entering the Dolores River, where they would substantially degrade water quality. Subsurface brine 

flows are intercepted by long-term pumping from a field of shallow extraction wells located along 

the river (Figure 2). The extracted brine is then collected and filtered at a surface-treatment facility, piped about 3.6 miles (6 km) to an injection facility at the edge of the valley, and finally 

injected into a 15,900-ft (4.8-km) deep injection well for long-term disposal. The injection well is 

designed to dispose of brine deep underground, confined to a narrow target zone extending over 

only the lowest 1,700 ft (500 m) of the borehole. Within this target zone, most of the injected 

brine is taken up by a subhorizontal formation of Mississippian-age limestone. The in-situ formation water in the injection zone is already brine, and therefore is not considered to be a potential 

source of potable water.

Deep-well brine injection at PVU has occurred more or less continuously since 1996, a duration 

of more than 16 years. Over this period, the maximum injection pressures required to dispose of 

the annual volume of diverted brine have gradually increased and within the next several years are 

Figure 2: Location of the Paradox Valley Unit brine extraction wells and 

PVU Injection Well #1. 

Wray

Mesa
3

projected to reach the maximum allowable surface injection pressure (MASIP) specified in Reclamation’s operating permit from the U. S. Environmental Protection Agency (EPA). The MASIP 

limit is designed to prevent injected brine from breaching a confining layer of salt that lies above 

the injection target zone, thus preventing contamination of shallow, potentially potable groundwater. Should the MASIP limit be reached, shut-ins of the injection well would be required to allow 

time for near-well pressures to dissipate, which reduces the operational efficiency and benefits of 

the project.

One of the long-term options under consideration for addressing the problem of increasing injection pressures is to drill a second injection well in the same general area, which would prolong the 

operational life of the existing well by allowing a reduction in the average annual injected volume 

of brine for each well. In order to fully evaluate this option, the most promising site locations for 

a potential second injection well must be identified, and feasibility and costs determined.

This report reviews existing geologic and geophysical studies that are relevant to site selection for 

a second injection well. Much of this work was done in the 1980’s, prior to siting the first injection well, although some studies are more recent. This report is intended to provide a roadmap to 

these early PVU investigations, and to lay the foundation for determining what additional studies, 

if any, are now needed to identify and characterize suitable sites for a second injection well.

2.0 Project Background

2.1 Paradox Valley Unit

The Paradox Valley Unit (PVU) is located in western Montrose County approximately 55 miles 

(89 km) southwest of Grand Junction, CO and 10 miles (16 km) east of the Colorado-Utah border 

(Figure 1). The Dolores River, a tributary of the Colorado River, flows from the southwest to the 

northeast across Paradox Valley. The valley was formed by the collapse of a salt-cored anticline 

(Cater, 1970). Due to the presence of the salt diapir underlying Paradox Valley, and groundwater 

inflow from the La Sal Mountains at the northwest end of Paradox Valley, there are a series of diffuse brine springs which discharge highly saline water (0.26 kg/l of dissolved solids - more than 

seven times the 0.035 kg/l salinity of ocean water) into the Dolores River. PVU is designed to 

divert highly saline groundwater flows from entering the Dolores River and degrading water quality downstream. To do this, brine is extracted from nine shallow wells located within the valley 

along the river (Figure 2). The extracted brine is collected and filtered at a surface treatment facility, piped southwest about 3.6 miles (6 km), and then injected at high pressure into a deep disposal 

well located along the Dolores River, approximately 0.9 miles (1.5 km) southwest from the margin of Paradox Valley, near the town of Bedrock, Colorado (Figure 2). Details on the PVU project 

background, purpose, and benefits are provided in Reclamation’s environmental assessment 

(USBR, 1997) as well as the EPA injection well permit fact sheet (EPA, 1997).

2.2 Feasibility Studies

An initial study to assess the feasibility of deep well injection for brine disposal was made in 1975 

by Turner, who identified the Mississippian-age limestone formations present in the area, specifically the Leadville formation, as having the best reservoir and aquifer characteristics of the formations considered. Turner recommended that consideration be given to rehabilitating existing, 
4

abandoned oil and gas exploration wells as brine disposal wells, and he identified several candidate wells in the area. Additional feasibility and environmental studies were completed in 1978 by 

Reclamation (USBR, 1978), with recommendations made to further refine the feasibility of disposal by deep-well injection, and make preliminary cost estimates. A report by Williams Brothers 

Engineering (Williams Brothers, 1982) evaluated available geologic, geophysical, hydrogeologic, 

and engineering data for the area, assessed potential reservoir properties, evaluated the potential 

for re-use of existing petroleum wells for deep-well injection, prepared an initial design for a 

complete brine diversion system, assessed the impact of deep well injection, and made preliminary cost estimates. The Williams Brothers (1982) report recommended re-entry and completion 

of the Continental Scorup No. 1 well, located within Paradox Valley, as the primary injection 

well, and the Chicago No. 1 Ayers well (located about 1.9 miles (3 km) southwest of Paradox Valley) as a potential second well (see Figure 3 for locations of these wells). The report discussed 

available seismic reflection data from several geophysical data brokers, but based on a review of 

sample data decided that the data quality was inadequate to provide a good isopach map of either 

the Mississippian- or Devonian-age formations. The sample and reconnaissance data provided by 

the geophysical brokers apparently was sufficient to verify the existence of a major northweststriking fault between the Chicago No. 1 Ayers and Union No. 1-0-30 Ayers wells that vertically 

offset the Leadville formation with about 6,000 ft (1,800 m) of throw.

The Scorup No. 1 well apparently was deemed to be impractical for re-use as an injection well, 

and preliminary technical specifications were developed in 1982 or 1983 to drill a 15,500-ft (4.7 -

km) deep new well for deep injection at a nearby location within Paradox Valley. This well would 

have required drilling through nearly 15,000 ft (4.6 km ft) of salt. Two reports reviewing these 

plans were prepared in 1983. The first, by the consulting firm OGS Associates (Goins and Flak, 

1983) recommended against using an injection well location that would require drilling through 

more than about 9,000 ft (3,000 m) of salt due to salt collapse and other completion problems. 

Goins and Flak (1983) also noted several criteria that should be considered, including reservoir 

size and permeability, proximity to the brine extraction field, and injecting at sufficiently high 

pressures to cause fracturing and avoid plugging of formation permeability by suspended solids 

and precipitates. A second review report by the firm OTS, Inc. (Klementich, 1983) noted the difficulty and cost of drilling through massive salt formations, and instead recommended drilling in a 

location where no more than 500 ft (150 m) of salt would be encountered.

By 1985, plans had focused on drilling a new well within the immediate vicinity of the Union 

Otho Ayers No. 1 well (Figure 3), which would have the benefits of having a known lithology, 

having a relatively thin (250 to 500 ft; 76 to 152 m) confining layer of salt over the injection zone, 

and avoiding the problems of drilling through deep salt. These plans were reviewed by the consulting firm of Ken E. Davis Associates (Davis, 1995), who noted the variable and relatively low 

matrix permeability of the Leadville formation, and that more than one disposal well might be 

required. Davis (1985) also deemed it essential that the disposal well be hydraulically fractured.

PVU Salinity Control Well No. 1 (originally, Paradox Valley Injection Test Well #1) was completed in 1987 to a total depth of 15,900 ft (4.8 km). A schematic diagram of the well is shown in 

Figure 4.The well was built to EPA Underground Injection Code (UIC) Class I standards (“Isolate 

hazardous, industrial and municipal wastes through deep injection”), but was permitted by EPA as 

a Class V disposal well (“Manage the shallow injection of non-hazardous fluids”). The well pene-
5

trates Triassic- through Cambrian-age sedimentary rock layers and metamorphic Precambrian 

basement. Based on interpretation of core and log data, the Mississippian Leadville carbonate was 

selected as the primary injection zone and the upper Precambrian as a secondary zone (Bremkamp 

and Harr, 1988). 

2.3 PVU Injection History

Between 1991 and 1995, PVU conducted a series of 7 injection tests, an acid stimulation test, and 

a reservoir integrity test. The purpose of these tests was to qualify for a permit for long-term injection from EPA. Continuous injection of brine began in July, 1996, after EPA granted the permit. 

Since continuous injection began, PVU has instituted and maintained three major changes in 

Figure 3: Locations of existing deep petroleum exploration wells in the Paradox Valley area.
6

Figure 4: Schematic diagram of Paradox Valley Injection Test Well No. 1.
7

injection operations. Each change was invoked to mitigate the potential for unacceptable seismicity or to improve injection economics. These injection phases are described below. Plots of the 

daily average injection flow rate, surface injection pressure, and downhole pressure (at a depth of 

14,100 ft (4.3 km)) throughout the history of PVU injection operations are shown in Figure 5.

2.3.1 Phase I (July 22, 1996 - July 25, 1999) 

During this initial phase of continuous injection, PVU injected at a nominal flow rate of 345 gpm 

(~1306 l/min), at about 4,950 psi (~34.1 MPa) average surface pressure. This corresponds to 

approximately 11,800 psi (~81.4 MPa) downhole pressure at 14,100 ft (4.3 km) depth. To maintain this flow rate, 3 constant-rate pumps were used with each operating at 115 gpm. The surface 

pressure on occasion approached the wellhead pressure safety limit of 5,000 psi. At these times 

PVU would shut down one or two injection pumps, reducing the injection rate and allowing the 

pressure to drop a few hundred psi, before returning to three-pump injection. These shutdowns 

occurred frequently and lasted for minutes, hours, or a few days. Maintenance shutdowns lasted 

for one to two weeks and, in mid-1997, a 71-day shutdown was needed when replacing the operations contractor. The shutdowns resulted in an overall average injection rate for phase I of ~300 

gpm (1136 l/min). The injectate during phase I was 70% Paradox Valley Brine (PVB) and 30% 

fresh water.

2.3.2 Phase II (July 26, 1999 - June 22, 2000) 

Following two magnitude M 3.5 induced earthquakes in June and July, 1999, PVU augmented 

injection to include a 20-day shutdown (i.e., a “shut-in”) every six months. Prior to these events, it 

was noted that the rate of seismicity in the near-wellbore region (i.e., within about a 2-km radius 

from the wellbore) decreased during and following unscheduled maintenance shutdowns and during the shutdowns following the injection tests of 1991 through 1995. It was thought that the biannual shutdowns might reduce the potential for inducing large-magnitude earthquakes by allowing 

extra time for the injectate to diffuse from the pressurized fractures and faults into the formation 

rock matrix. When injecting during this phase, the injection pressure and flow rate were the same 

as during phase I.

2.3.3 Phase III (June 23, 2000 - January 6, 2002) 

Immediately following a M 4.3 earthquake on May 27, 2000, PVU shut down injection operations 

for 28 days. During this shutdown period, PVU evaluated the existing injection strategy and its 

relationship to induced seismicity. PVU decided to reduce the injection flow rate in order to 

reduce the potential for inducing large-magnitude earthquakes. On June 23, 2000, PVU resumed 

injection using two pumps rather than three. This change decreased the injection flow rate by 33% 

compared to earlier phases, to 230 gpm (~871 l/min). The 70:30 ratio of brine to fresh water and 

the biannual 20-day shutdowns were maintained.

2.3.4 Phase IV (January 7, 2002 - present) 

Beginning with continuous injection operations in 1996, PVU diluted the injectate to 70% PVB 

and 30% Dolores River fresh water. A geochemical study had predicted that if 100% PVB were 

injected, it would interact with connate fluids and the dolomitized Leadville limestone at down-
8

Injection Flow Rate

0

50

100

150

200

250

300

350

400

Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09 Jan-11

Injection Flow Rate (gpm)

Downhole Pressure

10800

11000

11200

11400

11600

11800

12000

12200

Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09 Jan-11

Downhole Pressure (psi)

Surface Pressure

3000

3500

4000

4500

5000

Jan-91 Jan-93 Jan-95 Jan-97 Jan-99 Jan-01 Jan-03 Jan-05 Jan-07 Jan-09 Jan-11

Surface Pressure (psi)

injection tests

continuous

injection,

 early period

continuous injection,

later period

Phase I II III IV

Figure 5: Daily average injection flow rate (top), daily average surface 

injection pressure (middle), and daily average downhole pressure at 14,100 ft 

(4.3 km) depth (bottom) during PVU injection operations.
9

hole (initial) temperatures and pressures, and that PVB would then precipitate calcium sulfate, 

which in turn would lead to restricted permeability (Kharaka, 1997). During October 2001, with 

the decreased injection volume discussed above, the injectate concentration question was reconsidered. Temperature logging in the injection interval recorded substantial near-wellbore cooling, 

indicating that if precipitation occurred, it would not be near the wellbore perforations where 

clogging would be a concern. Further discussions indicated that, if precipitation occurs, its maximum expected rate is ~8 tons of calcium sulfate per day. To put this amount into perspective, 

injecting at ~230 gpm, assuming a density of 8.33 lbs/gal, results in a daily injection of ~1380 

tons. The maximum expected precipitate is ~0.6% of the daily injection mass.

After considering this new information, the decision was made to begin injecting 100% PVB, in 

order to increase the amount of salt disposed of with the reduced injection rate initialized in phase 

III. Injecting 100% PVB began on January 7, 2002, following the December-January 20-day 

shutdown, and has been maintained since. The same reduced injection rate as in phase III (230 

gpm) and biannual 20-day shutdowns have been maintained. The only noticeable affect of the 

change to 100% PVB injectate has been increasing bottom hole pressure because of the increased 

density of 100% PVB (by about 5%) over the 70% PVB : 30% fresh water mix.

2.4 Injection Pressures

The surface and downhole injection pressures at PVU Well #1 have varied considerably over time 

(Figure 5). After the injection flow rate was decreased by one-third in mid-2000, both the surface 

and downhole injection pressures dropped by approximately 800 psi and then began to slowly 

recover. In January, 2002, the injectate was changed from a 70% brine : 30% fresh water mix to 

100% brine. The increased density of the 100% brine injectate compared to the former mix 

resulted in an immediate increase in the downhole pressure of about 300 psi (Figure 5, lower 

plot). By mid-2003, the downhole pressure had reached the same value it was prior to the mid2000 decrease in injection flow rate (about 11,800 psi). The surface injection pressure, in contrast, 

did not reach it’s pre-2000 value of just under 5000 psi until mid-2010 (Figure 5, middle plot).

Since 2002, the daily average injection flow rate and composition of the injectate have remained 

nearly constant. There have, however, been significant variations in the frequency and length of 

injection well shut-ins. Since mid-1999, the injection well has operated under an official schedule 

of two 20-day shut-ins (or shut-downs) each year, when injection ceases, and continuous injection 

otherwise. However, several additional shut-ins of varying lengths have occurred over the years, 

usually for required equipment maintenance or repairs. While many of these extra shut-ins were 

short, some were of significant duration. For example, a prolonged shut-in of more than two 

months occurred in late 2005 to early 2006 after a tank explosion. Between mid-December, 2008, 

and mid-December, 2009, approximately 75 shut-down days occurred rather than the nominal 40 

days per year. These additional days were due to a change from a winter-summer shut-in schedule to a spring-fall schedule and to additional shut-down time required when upgrading surface 

equipment at the injection wellhead. When significant extra injection well shut-downs occur, the 

maximum injection pressures tend to fluctuate. In contrast, when the official injection schedule is 

maintained for a sufficient period of time, the maximum injection pressures tend to increase consistently during each successive injection cycle (such as in 2002-2003 and 2010-2012).
10

2.5 Consideration of a Second Injection Well

The maximum allowable surface injection pressure (MASIP) currently permitted for PVU Injection Well #1 is 5,350 psi. The highest daily average surface injection pressure recorded to date for 

this well is 5,100 psi, reached in March, 2012. Since 2009, the maximum surface injection pressure has been increasing at a rate of roughly 100 psi per year. If the current rate of pressure 

increase continues, the MASIP will be reached in 2014 or early 2015. To prevent the injection 

pressure from exceeding the current MASIP, the volume of brine injected annually would need to 

be reduced. This could be accomplished by either decreasing the daily average injection flow rate 

or increasing the annual number of injection well shut-down days. In either case, the efficiency of 

injection operations would decline and PVU would become less economically viable.

Reclamation is considering whether to request an increase in the MASIP for PVU Injection Well 

#1 from EPA. However, even if such an increase is pursued and granted, it will only postpone the 

need to address the increasing injection pressures for a few additional years. A longer-term solution is required. The installation of a second injection well is among the solutions being considered. While other options are being evaluated, Reclamation has decided to move forward with the 

analysis required to determine the optimal location of a potential second injection well. 

3.0 Geology

3.1 Regional Geology

3.1.1 Geologic Setting

Paradox Valley is located in the northeastern part of Paradox Basin—an elongate northwestsoutheast trending structural basin which extends from eastern Utah into western Colorado, 

within the Colorado Plateau region (Figure 6). Rapid subsidence of Paradox Basin during the 

Mississippian, Pennsylvanian, and Permian Periods (~350 - 250 Ma) accommodated marine intrusion and resulted in the interfingering of marine deposits, including evaporates, and terrestrial 

material shed from the nearby (Uncompahgre) uplifted areas to the northeast (McClure et al., 

2003). 

The northern part of Paradox Basin, known as the Paradox fold and fault belt, contains several 

northwest-striking diapiric salt-cored anticlines. These salt-cored anticlines developed as a result 

of plastic flow of the Pennsylvanian-age Paradox stratigraphic unit. The Paradox unit consists of 

as much as 85% halite and is best imagined as a viscous liquid (Huntoon, 1988). Subsequent dissolution of salt beneath the crests of some of the anticlines resulted in downfaulting and the development of grabens, or salt valleys (Nuccio and Condon, 1996; Gutierrez, 2004). Paradox Valley 

developed as a result of structural collapse along the crest of one of these salt-cored anticlines and 

is bounded by nearly vertical normal faults. 
11

3.1.2 Faults and Joints

The tectonic history of northern Paradox Basin is complex, as are the resulting fault and joint patterns. This region contains both deep basement faults, possibly originating as long ago as the Precambrian (> 540 Ma) (Baars and Stevenson, 1981), and as recent as Tertiary (65 - 2 Ma) surface 

faults. Sets of joints or fractures are present in both the older and younger rock units. Although 

these joints are often sub-parallel to the faults, the developmental relationship of the fault and 

joint patterns is not always clear (Grout and Verbeek, 1998). Varying and sometimes conflicting 

interpretations of the tectonic development and relationships of the observed structural features of 

the Paradox fold and fault belt have been published. Here we present an overview of the major 

regional fault and joint patterns observed rather than a detailed tectonic history.

0 10 20 30 40 MILES

0 10 20 30 40 50 60 KILOMETERS

111 110 109 108 107

39°

38°

37°

Colorado

River

Green River

Dolores River

UINTA BASIN

PICEANCE BASIN

112° 110° 108°

40°

36°

38°

SAN JUAN

BASIN

SAN JUAN

MOUNTAINS

Abajo

Mountains

Center

La Plata

Mountains

Ute Center

Mountains

Center

Henry

Mountains

Center

Monument

Uplift

Defiance

Uplift

Wilson

Center

Rico

Mountains

Center

ND

UD

San Rafael Swell

UT CO

NMAZ

Uncompahgre Uplift

Salt

Valley

Fisher

Valley

Valley Sinbad

Paradox

Valley

Gypsum

Valley Dolores

Valley

Lisbon

Valley

Gibson

Dome

Lockhart

SD Springs

Kane

Moab

Valley

Spanish Valley

Pine

Ridge

Castle

Valley

La Sal

Mountains

Center

APPROXIMATE

BOUNDARY

OF

PARADOX

BASIN

EVAPORITES

Colorado

Plateau

Paradox

Basin

San

Juan

Mts

UT CO

AZ NM

Circle

Cliffs

Uplift

Figure 6: Map showing the location and major features of Paradox Basin. 

Paradox Valley is located near the northeastern edge of Paradox Basin. Figure taken from Grout and Verbeek, 1998. 
12

Buried Faults

Parallel, northwest-trending, steeply-dipping normal faults are present in the basement and buried 

Paleozoic rock units of the Paradox fold and fault belt. The presence of these basement faults contributed to the formation of the northwest-trending diapiric salt anticlines (Baars and Stevenson, 

1981; Friedman et al., 1994; Grout and Verbeek, 1998). Although some vertical movement 

occurred on these faults during the early Paleozoic (Baars and Stevenson, 1981), activity along 

the faults greatly increased during the Mississippian Period, when Paradox Basin began rapidly 

subsiding. Significant activity continued on these faults into the Permian Period, and possibly into 

the Triassic Period. The faults may have been reactivated as late as the Tertiary (Verbeek and 

Grout, 1998; Doelling et al., 1988). The faults having the largest vertical displacements generally 

have their downthrown sides to the northeast, resulting in a deepening of Paradox Basin toward 

the northeast (Doelling et al., 1988). In the vicinity of Paradox Valley, these northwest-trending 

basement faults occur on the northeast flank of the Wray Mesa-Sneffels structural high trend and 

are referred to in early PVU geology reports as the Wray Mesa fault system (Bremkamp and Harr, 

1988). 

Northeast-trending fault zones are also present in the basement and buried Paleozoic rocks of 

northern Paradox Basin. According to Barrs and Stevenson (1981), these features, along with the 

northwest-trending basement faults described above, originated as conjugate shear zones during 

the Precambrian. While significant vertical movement occurred on the northwest-trending faults 

during the late Paleozoic (described above), the northeast-trending faults appear to have accomodated mainly strike-slip movement. These northeast-trending, subsurface basement lineaments are 

not as well-mapped or as well-understood as the northwest-trending faults. It is not known 

whether each of these features consists of a wide shear zone, a single wrench fault, or a series of 

en echelon strike-slip faults (Hite, 1975). Some of the northwest-trending basement faults are offset by northeast displacement (Hite, 1975), indicating activity along the northeast features at least 

subsequent to the late Paleozoic. The laccolith complex of the La Sal Mountains, which is located 

just northwest of Paradox Valley and divides the Paradox Valley - Castle Valley anticlinal structure in two (Figures 1 and 4), may be located at the intersection of the anticline with one of these 

northeast-trending fault zones (Friedman et al., 1994).

Surface Faults

Many relatively young normal faults are present at the surface in Paradox Basin. Some of these 

faults may be the result of tectonic extension during the Tertiary, while others are clearly related 

to salt dissolution and collapse of overlying strata (Doelling et al, 1988). Regardless of the cause 

of the fault formation, the faults generally trend northwest-southeast, parallel to the salt anticlines 

and underlying basement normal faults. Salt diapiric movement, salt dissolution, and the lowering of salt valley floors is ongoing (Friedman et al., 1994).

Extensional, northeast-trending, high-angle faults with predominantly vertical offset have also 

been mapped at the surface in northern Paradox Basin. According to formation cutting relations, 
13

these faults were active sometime from Jurassic to Pleistocene time, in strata between the salt section and the surface (Friedman et al., 1994).

Joints

Several widespread, extensional joint sets are present across central Paradox Basin. Grout and 

Verbeek (1998) classify these joint sets into two major systems, one that evolved during the Permian Period (300 - 255 Ma) and another system of Tertiary and younger age (< 65 Ma). In addition, a system of Carboniferous-age joint sets is present in Mississippian and older rocks along the 

eastern margin of Paradox Basin. Regardless of age, each system consists of joint sets striking 

from northwest to northeast. Strikes of the Paleozoic-age joint sets, which are likely to be present 

in the sub-salt rock units in the vicinity of Paradox Valley, are reported as: N62W, N27W, N19W, 

N18E, and N64E (measured from outcrops near Telluride, Colorado, approximately 75 miles 

southeast of PVU; Grout and Verbeek, 1998). In the Lisbon Valley area in eastern Utah (Figure 6), 

these joint sets are perpendicular to bedding, indicating that they formed prior to the major anticline-building episode in the late Permian to early Triassic (Grout and Verbeek, 1998). Strikes of 

the Tertiary-age joints range from N85W to N62E. The majority of these joint sets are vertical, 

regardless of bedding dip.

3.2 Local Geology

3.2.1 Paradox Valley Morphology

Paradox Valley is approximately 25 miles (40 km) long and generally 2.5 to 4.5 miles (4.0 to 7.2 

km) wide. The valley has a relatively flat floor enclosed by steep sandstone walls. Elevations 

within the valley vary from approximately 4900 to 5600 ft (1500 to 1700 m) above mean sea level 

(amsl). Elevations along the valley rim are approximately 6200 to 6900 ft (1900 to 2100 m) amsl, 

while elevations rise to over 11,800 ft (3600 m) in the La Sal Mountains just northwest of Paradox 

Valley.

Rivers in the Paradox Basin flow parallel and perpendicular to the northwest-trending salt anticlines. In Paradox Valley, the Dolores River flows across strike near the town of Bedrock, Colorado (Figure 2). West Paradox Creek, a small tributary, enters the Dolores River within the valley 

from the northwest.

3.2.2 Stratigraphy

Paradox Valley and the surrounding mesas contain rocks spanning Precambrian to mid-Cretaceous time (>570 to approximately 90 Ma). The Precambrian basement rock consists of granite, 

schist, gneiss, and pegmatite. Overlying the Precambrian rock is a series of sedimentary units 

deposited primarily in marine or near shore environments. These layers include sandstones, siltstones, shales, conglomerates, limestones, dolomites, and evaporites.
14

A stratigraphic column of the Paradox Valley area is presented in Table 1. PVU Injection Well #1 

is sited on the Triassic-age Chinle Formation. The stratigraphy of the underlying formations 

shown in Table 1, down to the Precambrian basement rock, is taken from the geologic well log of 

this borehole (Harr, 1988). Depths of geologic units encountered in this well are included in the 

table and are relative to the local ground surface elevation of 4996 ft (1523 m). Descriptions of the 

rock units are taken from several sources (see footnote no. 2 in the table). The overlying stratigraphy, including the Triassic-age Wingate sandstone to the Cretaceous-age Mancos shale, was taken 

from a geologic map of the Moab Quadrangle produced by the U.S. Geological Survey (Williams, 

1964). Not all rock units may be present in the immediate vicinity of Paradox Valley. The Jurassic-age Morrison Formation generally tops the cliffs surrounding Paradox Valley, while the Cretaceous-age Burro Canyon and Dakota Formations are present at the higher elevations of the mesas. 

A remnant of the Mancos shale is present just beyond the southeastern end of the valley. The 

floor of Paradox Valley consists of Quaternary alluvial and eolian deposits overlying the diapiric 

Paradox (salt) formation. 

The Mississippian Leadville formation is the primary target reservoir for PVU brine injection, due 

to its sedimentary and structural characteristics. The Leadville formation consists of limestone 

and dolomite layers that are fractured, faulted, and contain karst features. The lower Leadville formation (Kinderhookian-age) is stromatilitic dolomite, lime mudstones, and pelletal lime mudstone deposited in intertidal to subtidal environments. The upper Leadville formation (Osageanage) contains fossiliferous pelletal and oolitic limestone, and lime and dolomitic mudstone (Doelling et al., 1988). The upper Leadville underwent uplift and erosion after deposition, resulting in 

karst-type weathering and the formation of a terra rossa type regolith on the surface. Terra rossa

is a red clay soil that forms on the surface of limestone bedrock. Under oxidizing conditions, iron 

oxide forms in the clay, giving the soil a red-orange color. This karstic portion of the Leadville is 

not considered a potential reservoir due to the concentration of fines infilling the karst features 

(Bremkamp et al., 1984). 

3.3 Early PVU Geologic Investigations

Early in the PVU project, geologic and geophysical studies were performed to better understand 

the local geologic structure and stratigraphy, to characterize potential reservoir formations, and to 

determine optimal sites for proposed injection wells. The most detailed of these studies were performed in the 1980’s. Very little geologic or geophysical investigation has been performed by 

PVU since that time, and therefore the results from these early studies still comprise the most 

comprehensive geologic interpretation currently available to Reclamation. 

3.3.1 Development of Structural Geologic Models

Prior to the selection of the site for the current PVU injection well, geophysical interpretations 

were performed for Reclamation by two groups of consultants using deep seismic reflection and 

well log data (Katz and Carroll, 1984; Bremkamp et al. 1984). The study area was located southwest of central Paradox Valley, where the Dolores River enters the valley. These investigations 

utilized 15 single-fold seismic reflection lines recorded in 1961 by Empire Geophysical (lines 
15

Table 1: Paradox Valley Stratigraphy. 

Stratigraphic Unit

Vertical 

Depth to 

Top of Unit 

In PVU 

Well #1 

(ft)1

Description2

CRETACEOUS

Mancos Shale above

elevation of 

wellhead

Dark gray to black, soft, fissile marine shale with thin 

sandstone beds at various horizons

Dakota Sandstone Yellowish-brown and gray friable to quartzitic fluvial 

sandstone and conglomeratic sandstone with interbedded gray to black carbonaceous nonmarine shale

Burro Canyon Fm. White, gray, and light-brown fluvial sandstone and 

comglomerate interbedded with green and purplish 

lacustrine siltstone, shale, and mudstone, and thin beds 

of impure limestone

JURASSIC

Morrison Fm. above 

elevation of 

wellhead

Fluvial and lacustrine shale, mudstone, and sandstone; 

local thin limestone beds

Summerville Fm. Red, gray, green, and brown sandy shale and mudstone 

of terrestrial origin

Entrada Fm. Orange, buff, and white, fine- to medium-grained, 

massive, and cross-bedded eolian sandstone; basal few 

feet may consist of red siltstone and fine-grained sandstone and is sometimes referred to as the Carmel Formation.

Navajo Sandstone White, grayish-yellow, gray, and pale orange-pink, 

fine-grained, cross-bedded eolian sandstone

TRIASSIC

Kayenta Fm. above

elevation of 

wellhead

Irregularly interbedded fluvial red, buff, gray, and lavender shale, siltstone, and fine- to coarse-grained 

sandstone

Wingate Sandstone Reddish-brown, buff, and grayish-orange, finegrained, massive, thick-bedded, and prominently 

cross-bedded eolian sandstone

Chinle Fm. 0 (at surface) Siltstone- red to orange-red, with interbedded red finegrained sandstone, shale, clay-pellet conglomerate 

containing limestone pebbles; conglomerate, and few 

thin beds of gypsum occur locally at base; terrestrial 

depositional environment.

Moenkopi Fm. 390 Sandy shale/silty sandstone- brown, bedded, often ripple marked, some conglomerate present. Marine and 

terrestrial depositional environment.
16

Stratigraphic Unit

Vertical 

Depth to 

Top of Unit 

In PVU 

Well #1 

(ft)1

Description2

PERMIAN

Cutler Fm. 1140 Sandstone/conglomerate- red to purple arkose, fluvial, 

with some sandy shales; deposited in alluvial fans

PENNSYLVANIAN

Hermosa Group -

Honaker Trail Fm.:

Upper Honaker Trail 8313 Limestone/sandstone/siltstone- deposited in marine 

conditions

LaSal 12006 Limestone/dolomite- some silty limestone, oolitic 

limestone, and algal limestone present

Lower Honaker Trail 12082 Limestone/sandstone/siltstone- deposited in marine 

conditions

Hermosa Group - 

Paradox Fm.: 12350 Resulted from intermittently closed marine environment

Ismay 12839 Limestone- stacked algal carbonate mounds, and other 

shallow-water carbonates and dolomites.

1st Main Salt 13104 Dolomite/salt- intermittently closed marine depositional environment

2nd Main Salt 13497 Salt/anhydrite/shale- intermittently closed marine depositional environment

Base Salt - Lower 

Paradox

13566 Shale/anhydrite/(minor) limestone- intermittently 

closed marine depositional environment

Hermosa Group - 

Pinkerton Trail Fm. 13693 Shales/anhydrite/siltstone/(minor) limestones- dark 

colored shales, limestone formed by marine invasion

Molas Fm. 13944 Shale/siltstone/claystone- regolith/soil (terra rosa) 

developed on the karst surface of the Leadville formation after a period of extensive weathering and erosion.

MISSISSIPPIAN

Leadville Fm. 13984 Limestone/dolomite- lower unit (Kinderhookian -age) 

stromatilitic dolomite, lime mudstones, pelletal lime 

mudstones; deposited in intertidal to subtidal enviroments. Upper unit (Osagean-age) fossiliferous pelletal 

and oolitic limestone, and lime and dolomitic mudstone. 
17

1

 Depths were taken from the geologic drill log of PVU Salinity Control Well #1, by C. L. Harr. Depths 

are relative to the ground surface elevation (4996 ft) and have been corrected for borehole deviation.

2

 Descriptions were taken from: Bremkamp et al., 1988; Campbell, 1981; Doelling et al., 1988; 

Williams, 1964; and Nuccio and Condon, 1996.

Stratigraphic Unit

Vertical 

Depth to 

Top of Unit 

In PVU 

Well #1 

(ft)1

Description2

DEVONIAN

Ouray Fm. 14400 Limestone- lime mudstone, pelletal lime mudstone 

and skeletal limestone that is locally dolomitized; 

formed in quiet-water marine environment

Elbert Fm. 14440 Sandstone/shales/sandy dolomites

McCracken Fm. 14607 Sandstone- with occasional interbeds of sandy dolomite, product of marine transgression

Aneth Fm. 14681 Dolomite/shale- dark colored, dense, argillaceous 

sequence 

CAMBRIAN

Lynch Fm.:

Upper Lynch Shale 14763 Sandstone/interbedded shale, dolomite, limestone

Lynch Limestone 14835 Limestone

Lower Lynch Shale 14928 Shale

Muav Fm. 14988 Limestone

Bright Angel Fm. 15103 Shale

Ignacio Fm. 15246 Sandstone, sometimes referred to as quartzite; transgressive depositional environment

PRECAMBRIAN

Precambrian 15446 Described regionally as granitic rock with well-developed northwest and northeast orthogonal fracture systems; identified in PVU Injection Well #1 as 

moderately metamorphosed diorite-gabbro schist 

(Bremkamp 1988)
18

136, 131, 103, 340, 135, 102, 347, 197, 225, 127, 286, 132, 130, 137, and 139) (Figure 7). These 

data were reprocessed for Reclamation by Western Geophysical in 1984. Additionally, three 12-

fold seismic lines recorded in 1982 by Seisport Exploration were acquired by Reclamation and 

used in the studies (Lines 8, 204, and 208A, Figure 7). In both data vintages, the quality decreases 

greatly in thick salt sections. Data quality also decreases in areas overlain by unconsolidated 

material such as in valley bottoms. Logs from nine wells were used as control points for formation 

depth and velocity (Figure 7). Only six of the wells, however, penetrated the Paradox salt member 

and Leadville formation (Table 2). 

Figure 7: Locations of seismic reflection lines and deep wells used in early PVU 

geophysical studies.

Wray

Mesa
19

The investigators created structural contour maps of the top of the Cutler formation, massive salt 

member of the Paradox formation, and Leadville formation, and isopach maps for the Paradox 

salt member (including the underlying Pinkerton Trail and Molas formations) and Leadville formation. Contours from the maps of Katz and Carroll (1984) and Bremkamp et al. (1984) were 

digitized and are overlaid on the local topography and other geographical features in Figures 8 to 

12. Fault traces and well locations were also digitized from the drawings and are included in the 

figures.

In comparing the geophysical interpretations from the two groups of investigators, we found not 

only significant differences in the interpreted contours, but also some significant differences in the 

elevations of the geologic formations reported for the wells. In order to investigate these discrepancies, we compared the geologic well data from the contour maps to well log data available from 

the Colorado Oil and Gas Conservation Commission online database (http://cogcc.state.co.us/

1 Official name is the name listed in the Colorado Oil and Gas Commission Database

Table 2: Wells providing data for original PVU geophysical interpretations

OPERATOR YEAR

DRILLED

OFFICIAL 

WELL 

NAME1

NAME 

USED IN 

EARLY PVU 

REPORTS

TOTAL 

DEPTH (ft)

DEEPEST

FORMATION 

REACHED

Chicago 

Corp. 1950 Otho Ayers #1 none 6,860 Penn.-UpperHermosa

Continental 

Oil Co. 1958

Scorup

Somerville 

Wilcox #1 

Conoco No. 1 ~15,000

Miss.-Leadville

(did not penetrate 

entire formation)

Shell Oil Co. 1961 Wray Mesa 

Unit #1 Shell No. 1 11,268 Precambrian

Shell Oil Co. 1961 Wray Mesa 

Unit #2 Shell No. 2 11,593 Cambrian

Miami Oil 

Co. 1962 Coyote Wash Unit #1 Miami 10,650

Miss.-Leadville

(did not penetrate 

entire formation)

Pure Oil Co. 1963 Wray Mesa 

Unit #3 Pure No. 3 11,301 Devonian?

Union Oil Co. 1971 Otho Ayers 

#1-0-30

Union or 

Unocal 14,400 Devonian-Ouray

Grynberg 

Petroleum 

Co.

1975

Wild Steer 

Unit Federal 

#32-24

Grynberg 9,533 Penn.-Upper

 Hermosa

Grynberg 

Petroleum 

Co.

1975

Federal Wild 

Steer Unit 

#32-15

Grynberg 7,814 Penn.-Upper

 Hermosa
20

cogis, data retrieved Sept. 25, 2012). Depths to the geologic formations of interest were found in 

the database for all wells except for the Pure Oil Wray Mesa Unit #3 well, although in some cases 

only partial information is available. Tables comparing the elevations and thicknesses of the geologic units of interest in the wells, as reported by Katz and Carroll (1984), Bremkamp et al. 

(1984), and the Colorado Oil and Gas Commission database are included in Appendix A. The 

major findings are summarized in the discussions of the contour maps below.

 

A seismic reflector for the Cutler formation was not discernible and therefore the structure of the 

Cutler formation was interpreted from the limited well data alone. Both groups interpreted the 

Cutler formation as generally dipping toward the southwest, although inferred details of the structure are different (Figure 8). The well data used by Katz and Carroll match that listed in the Colorado Oil and Gas Commission database much better than the data used by Bremkamp et al. The 

differences between the Katz and Carroll Cutler formation well elevation data and the Colorado 

Oil and Gas Commission database range from 0 to 189 ft; the median absolute difference for the 

five wells compared is 12 ft. The differences between the Bremkamp et al. well data and the Colorado database range from 10 to 434 ft; the median absolute difference for the seven wells compared is 243 ft. Neither interpretation, however, takes into account the 426-ft elevation difference 

in the top of the Cutler formation between the Chicago Corp. Otho Ayers #1 and Union Otho 

Ayers #1-0-30 wells reported to the Colorado Oil and Gas Commission (Appendix A). (These two 

wells are located approximately 1.6 km apart along the Dolores River, slightly southwest of PVU 

Injection Well #1.)

Significant problems were found with the top-of-salt contour map produced by Katz and Carroll 

(Figure 9, lower map). They report an elevation of 1628 ft for the top of the Paradox salt member 

in the Conoco Scorup #1 well in the center of Paradox Valley, whereas Bremkamp et al. used a 

value of 4414 ft. These elevations correspond to depths of 3416 and 630 ft below local ground 

surface, respectively. The elevation of the top of the salt in this well is not reported in the Colorado Oil and Gas Commission online database. However, the geologic map of the area indicates a 

thin layer of Quaternary alluvial and eolian deposits underlain by the Paradox member of the Hermosa formation at this site (Williams, 1964). In PVU Injection Well #1, there is about 750 ft from 

the top of the Paradox formation to the top of the main salt member. Hence, the depth of the Paradox salt member at the location of the Conoco Scorup #1 well very likely should be only a few 

hundred ft, as indicated by Bremkamp et al., not the 3400 ft used by Katz and Carroll. Another 

elevation value used by Katz and Carroll for their interpretation of the top of the salt also appears 

to be grossly incorrect. They used an elevation of -4049 ft for the Shell Wray Mesa Unit #1 well. 

Bremkamp et al. apparently did not have elevation data for the top of the salt in this well, and neither is any value reported in the Colorado online database. However, extrapolating from the elevation for the top of the Hermosa group reported in the online database and assuming that the 

thickness of the upper Hermosa group is similar to that reported in PVU Injection Well #1 gives 

an estimated elevation of the top of the salt of -7148 ft in the Wray Mesa Unit #1 well. This is 

more than 3000 ft deeper than the value used by Katz and Carroll. It is possible that Katz and Carroll applied the elevation data of -4049 ft to the incorrect well, since a similar value (-4149 ft) was 

used by Bremkamp et al. for the Pure Oil Wray Mesa Unit #3 well to the southwest. In any case, 

the discrepancies apparent in the Katz and Carroll well data used in their geophysical interpretation leads us to discount their contour map for the top of the Paradox salt member and rely instead 

on that produced by Bremkamp et al. Besides the major salt diapir underlying Paradox Valley, 
21

Figure 8: Structural contour maps of the top of the Cutler formation. Contour 

values are elevations in feet relative to mean sea level. Contour interval is 100 

ft. Two interpretations are shown, from Bremkamp et al. (1984) (top) and Katz 

and Carroll (1984) (bottom).

Structural Maps of the Top of the Cutler Formation

Wray

Mesa

Wray

Mesa
22

Figure 9: Structural contour maps of the top of the Paradox formation. Contour values are elevations in feet relative to mean sea level. Contour interval is 

variable. Two interpretations are shown, from Bremkamp et al. (1984) (top) 

and Katz and Carroll (1984) (bottom).

Structural Maps of the Top of the Paradox Salt Member

Wray

Mesa

Wray

Mesa
23

Bremkamp et al. mapped two other distinct salt features: a diapiric feature centered at the Shell 

Wray Mesa Unit #2 well and a pillow-type feature to the southeast which does not pierce the overlying geologic units (Figure 9, upper map).

The well control data used by the two groups of investigators for mapping the top of the Leadville 

formation are consistent with each other and with data from the Colorado Oil and Gas Commission database (where available), with the exception of the elevation of the top of the Leadville formation indicated for the Conoco Scorup #1 well in the center of the valley. The value used by 

Katz and Carroll (-9698 ft) differs from the value indicated by the online database (-9682 ft) by 

only 16 ft, whereas the value used by Bremkamp et al. (-9946 ft) differs by 264 ft. This discrepancy does not cause a significant flaw in Bremkamp et al.’s structural interpretation of the top of 

the Leadville formation, however. It does indicate that the throw across the fault interpreted by 

Bremkamp’s group to lie just southwest of the Conoco Scorup #1 well to be greater than indicated 

on their map and correspondingly the dip of the Leadville formation in the fault block containing 

the Conoco Scorup well to be somewhat steeper than indicated (Figure 10, upper map). (No seismic reflection data were available across Paradox Valley, and Bremkamp et al. inferred the location and throw across this fault based on seismic reflection data southwest and northeast of the 

valley and on the depth of the Leadville formation in the Conoco Scorup #1 well.)

Despite the fact that the two groups of investigators interpreted the same seismic reflection data 

and used nearly the same well control data, their structural interpretations of the top of the Leadville formation have significant differences. Both interpretations indicate a structural high on 

Wray Mesa where the Leadville formation was eroded, as indicated by the absence of the Leadville formation in the Shell Wray Mesa Unit #1 and #2 wells. They also both indicate a structural 

high to the southeast, across the Dolores River canyon from Wray Mesa. However, Bremkamp’s 

group indicates an elevation of approximately -5100 ft for this structural high (Figure 10, upper 

map), whereas Katz and Carroll indicate an elevation of about -4400 ft (Figure 10, lower map), a 

difference of 700 ft. In general, Bremkamp et al. indicate that, on the northeast side of the two 

structural highs mentioned above, the Leadville formation dips toward the northeast. Katz and 

Carroll’s structural interpretation is more convoluted. For example, just northeast of the area 

where the Leadville formation is eroded on Wray Mesa, Katz and Carroll show the Leadville dipping toward the southwest rather than toward the northeast as in Bremkamp et al.’s interpretation. 

Significant differences are seen in the interpreted dip of the Leadville formation in the immediate 

vicinity of PVU Injection Well #1 also. For example, Bremkamp et al. show no significant change 

in depth of the Leadville formation immediately southeast of the well (where you can follow the -

9000-ft elevation contour). In contrast, Katz and Carroll show the Leadville formation shallowing 

substantially in the same area southeast of the well, to an elevation of less than -8000 ft. Similar 

differences can be seen to the northwest of the injection well; Katz and Carroll show the Leadville 

shallowing by more than 1000 ft along the same path where Bremkamp et al. indicate a constant 

elevation of -9000 ft. While both groups of investigators show northwest-trending faults 

downthrown to the northeast, there are non-trivial differences in the locations, trends, and throws 

of the faults. In addition, Bremkamp et al. indicate a northeast-trending fault that is absent in Katz 

and Carroll’s interpretation. Katz and Carroll indicate an additional northwest-trending fault in 

this location instead, downthrown to the southwest rather than to the northeast. Bremkamp’s 

group also indicates a fault in the center of Paradox Valley that is absent from Katz and Carroll’s 
24

Figure 10: Structural contour maps of the top of the Leadville formation. 

Contour values are elevations in feet relative to mean sea level. Contour interval is variable. Two interpretations are shown, from Bremkamp et al. (1984) 

(top) and Katz and Carroll (1984) (bottom).

Structural Maps of the Top of the Leadville Formation

Wray

Mesa

Wray

Mesa
25

interpretation. Such significant differences between two independent interpretations of the same 

data suggest that the data were of marginal quality.

Bremkamp et al.’s Paradox salt member isopach map indicates that salt thickness locally ranges 

from over 14,000 ft in the center of Paradox Valley to less than 500 ft (Figure 11, upper map). 

Variations in salt thickness are mainly due to the presence of the main salt diapir underlying Paradox Valley and the two smaller features discussed previously. Because of the incorrect well data 

incorporated into Katz and Carroll’s interpretation of the top of the Paradox salt member, discussed above, their salt isopach map is also flawed (Figure 11, lower map). 

The thickness of the Leadville formation was not resolvable through the seismic reflection data 

and was interpreted from well data and structural elevation changes of the top of the Leadville 

formation. (Katz and Carroll assumed that the Leadville formation was eroded at an elevation of -

4200 ft, based on information from well logs.) Data from two local wells that penetrated the entire 

Leadville formation, two wells that partially penetrated the Leadville formation, and two wells 

that indicated the absence of the Leadville suggest that the thickness of the Leadville formation 

ranges from 0 ft (completely eroded) to about 340 ft. However, the two groups of investigators 

infer very different trends of Leadville thickness in areas without well control (Figure 12). 

Bremkamp et al. (1984) show a thinning of the Leadville formation along an inferred northwesttrending post-Leadville horst (Figure 12, upper map), while Katz and Carroll show only local 

thinning and erosion on Wray Mesa. We consider the well data to be too sparse to make a reliable 

isopach map for the study area and therefore do not give much credence to either interpretation.

In additional to the structural maps discussed above, Bremkamp et al. (1984) also created an isopach map of the thickness of Leadville formation with greater than 5% porosity (Figure 13). The 

porosity values were computed solely from sonic logs from 3 boreholes and a neutron well log 

from an additional hole. Two of these boreholes, the Conoco Scorup #1 well and the Miami Oil 

Coyote Wash Unit #1 well, only partially penetrated the Leadville formation and therefore only 

provide a lower limit on the Leadville thickness with greater than 5% porosity. Two other boreholes indicate an absence of the Leadville formation.

With the exception of the results from the Conoco Scorup #1 well in the center of Paradox Valley, 

the thickness of the Leadville exhibiting greater than 5% porosity ranges from 0 ft (where the 

Leadville is eroded) to 31 ft (Figure 13). In contrast, the porosity values computed from the 

Conoco Scorup #1 well indicate 86 ft of 5% or greater Leadville porosity (and this is a lower 

limit, since the entire Leadville formation was not penetrated by this well). Bremkamp et al. 

(1984) attribute this variability to the thinning and weathering of the Leadville along their inferred 

horst southwest of Paradox Valley. Karst-type weathering along such an elevated feature would 

result in infilling of voids in the Leadville formation with shale and clay, reducing porosity. It is a 

little disconcerting that the single well showing an anomalously thick section of 5% or greater 

porosity within the Leadville formation in this analysis is also the single well for which porosities 

were computed from a neutron geophysical well log rather than a sonic log. It is not known 

whether differences in the two log analysis methods used could have contributed to the difference 

in the porosity results. However, according to a later report (Harr, 1989), the higher porosity values computed for the Conoco Scorup #1 well are supported by core and drill stem testing data 

from that well. Porosity values later derived from analysis of the sonic log acquired in PVU Injec-
26

Figure 11: Isopach maps of the Paradox formation massive salt member. The 

mapped interval also includes the underlying Pinkerton Trail and Molas formations, which are approximately 420 ft thick at the PVU Injection Well #1. Contour 

values are thicknesses in feet. Contour interval is variable. Two interpretations are

shown, from Bremkamp et al. (1984) (top) and Katz and Carroll (1984) (bottom).

Isopach Maps of the Paradox Salt Member

Wray

Mesa

Wray

Mesa
27

Figure 12: Isopach maps of the Leadville formation. Contour values are thicknesses in feet. Two interpretations are shown, from Bremkamp et al. (1984) (top) 

and Katz and Carroll (1984) (bottom).

Isopach Maps of the Leadville Formation

Wray

Mesa

Wray

Mesa
28

tion Well #1 also show anomalously high values, indicating 86 ft of 5% or greater porosity 

(Bremkamp and Harr, 1988). 

In addition to the maps shown above, Katz and Carroll (1984) and Bremkamp et al. (1984) each 

included two cross sections in their reports. The locations of these cross sections are shown on the 

map in Figure 14. Cross sections X-X’ and Y-Y’, from Bremkamp et al. (1984), are shown in Figures 15 and 16, respectively. Cross sections A-B and A-C, from Katz and Carroll (1984), are presented in Figures 17 and 18. As with the structural contour and isopach maps, significant 

differences in the geologic models constructed by the two groups of investigators are apparent in 

the cross sections. For example, the crest of the Paradox Valley salt anticline is much deeper on 

Katz and Carroll’s cross sections than on Bremkamp et al.’s cross sections. As discussed previously, we believe that Katz and Carroll used incorrect elevation data for the top of the Paradox salt 

member in the Conoco Scorup #1 well in the center of Paradox Valley. Additional striking differences between the two interpretations are seen by comparing cross sections X-X’ and A-B. These 

cross sections both transect the Conoco Scorup #1 and Union Otho Ayers #1-0-30 wells (Figure 

14) but show significantly different structural interpretations between the wells. On cross section 

A-B, Katz and Carroll indicate that the fault bounding Paradox Valley to the southwest extends to 

the ground surface (Figure 17) whereas Bremkamp et al. show the fault terminating in the salt 

layer (cross section X-X’, Figure 15). Katz and Carroll interpret approximately 3200 ft of throw 

across this fault (at the depth of the Leadville formation), whereas Bremkamp et al. indicate about 

1400 ft of vertical offset across the fault. As mentioned previously, Bremkamp et al. infer the 

existence of a fault beneath the Paradox Valley salt anticline (Figure 15). Katz and Carroll do not 

show a fault beneath Paradox Valley, but rather show the deep rock units dipping toward the 

southwest (Figure 17). Hence, the two groups of investigators constructed very different geologic 

models to satisfy the limited well data and (apparently marginal) seismic reflection data available.

After drilling PVU Injection Well #1, William Bremkamp and Clarence Harr prepared a second 

report titled ‘Area of Least Resistance to Fluid Movement and Pressure Rise’ (Bremkamp and 

Harr, 1988). This report contains a regional map of the structure of the top of the Leadville formation, which covers a much greater area than the map from their 1984 report (Figure 19). The 

report also contains three interpreted cross sections (Figure 20). The Leadville formation structural map was created using the previously obtained seismic data, all well data available at the 

time, and Bremkamp’s ‘recall memory’ of the area. 

By assuming a vertical pressure gradient of 0.44 psi/ft within the Leadville formation (based on 

drill stem testing in PVU Injection Well #1 and the nearby Union well) and assuming that fluid 

could not pass faults where the fracture zones (i.e. Leadville and upper Precambrian) are not juxtaposed, a map showing contours of hydrostatic pressure within the Leadville formation and the 

area of least resistance to fluid movement and pressure rise within the Leadville formation from 

fluid injection into PVU Injection Well #1 was created (Figure 21). Pressure changes due to variations in topography were not accounted for in this analysis, and the hydrostatic pressure contours 

simply conform to elevation changes in the mapped top of the Leadville formation (from Figure 

19). 

Fluid was projected to travel to the northwest and southeast, bounded within a two-mile-wide corridor between northwest-trending impermeable faults. Bremkamp and Harr believed that the 
29

Figure 13: Isopach map of Leadville intervals having greater than 5% porosity. Contour values are thicknesses in feet. Contour interval is 10 ft. Contours 

and fault traces were digitized from drawing no. 8, Bremkamp et al., 1984.

Isopach Map of Leadville Intervals Having Greater Than 5% Porosity

Wray

Mesa
30

Figure 14: Locations of cross sections A-B and A-C from Katz and Carroll 

(1984) and cross sections X-X’ and Y-Y’ from Bremkamp et al. (1984). The 

locations of the seismic reflection lines and well control used in the geophysical

interpretations are included for reference. See section 4.2 for descriptions of 

proposed injection well locations A through G. 
31

Figure 15: Cross section X-X’ from Bremkamp et al. (1984). The location of 

the cross section is shown on the map in Figure 14.

X’ X
32

Figure 16: Cross section Y-Y’ from Bremkamp et al. (1984). The location of 

the cross section is shown on the map in Figure 14.

Y’ Y
33

Figure 17: Cross section A-B from Katz and Carroll (1984). The location of 

the cross section is shown on the map in Figure 14.
34

Figure 18: Cross section A-C from Katz and Carroll (1984). The location of 

the cross section is shown on the map in Figure 14.
35

Figure 19: Regional structural contour map of the top of the Leadville Formation. Contour values are elevations in feet relative to mean sea level. Contour interval is 500 ft. Contours, and fault traces were digitized from drawing 

no. 1, Bremkamp and Harr (1988).

Regional Structural Map of the Top of the Leadville Formation
36

Figure 20: Cross sections A-A’, B-B’, and C-C’ from Bremkamp and Harr (1988). The locations of t
37

Figure 20, continued.
38

Figure 21: Regional contour map of hydrostatic pressure within the Leadville 

Formation. Contour values are pressures in pounds-per-square-inch (psi). 

Contour interval is 440 psi, except for the 6,320 psi contour. Pressure contours 

were digitized from drawing no. 2, Bremkamp and Harr (1988). Fault traces 

were digitized from drawing no. 1, Bremkamp and Harr (1988).

Hydrostatic Pressure within the Leadville Formation
39

injectate would remain within this corridor during an estimated 100-year lifetime of the injection 

well. The authors noted that although injected fluid would be contained within this corridor, the 

pressure rise would extend past the corridor into the northwest and southeast “fan shaped” areas 

beyond Paradox Valley. The limit of the zone of least resistance to pressure rise associated with 

injection into the Leadville formation is defined to the northeast by the hydrostatic pressure contour of 6,320 psi (Figure 21). Bremkamp and Harr (1988) do not explain why a value of 6,320 psi 

was chosen to define the extent of the zone of least resistance to fluid flow and pressure rise. 

According to the map, the hydrostatic pressure within the Leadville formation at PVU Injection 

Well #1 was approximately 6,100 psi (prior to injection). Given the hydrostatic pressure gradient 

of 0.44 psi/ft, the 6,320 psi contour represents a difference of 500 ft in the elevation of the Leadville formation.

While a corresponding map was not constructed for injection into the upper Precambrian, 

Bremkamp and Harr (1988) indicate that the pattern of fluid flow and pressure rise in the Precambrian would be similar to that in the Leadville.

3.3.2 Reservoir Characterization

The characteristics of potential reservoir formations in the Paradox Valley area were examined 

through the use of well log data, drill stem testing (DST), and the examination and testing of 

cores. Early investigations utilizing information from preexisting wells considered the Mississippian (Leadville) formation as the most likely target reservoir for brine disposal, but also considered the Devonian (Elbert, McCracken, Ouray) and Permian (Cutler) formations as potential 

targets (Turner, 1975; Williams Brothers, 1982). The Mississippian Leadville formation demonstrated the best reservoir characteristics during the initial testing of PVU Injection Well #1 

(Bremkamp and Harr, 1988). Bremkamp and Harr (1988) also classified the Precambrian as a target reservoir, based on the porosity and fracturing observed in that formation in PVU Injection 

Well #1. Bremkamp and Harr’s (1988) descriptions of potential reservoir formations, based 

largely on observations in PVU Injection Well #1, are summarized below. 

Mississippian Leadville

Throughout most of Paradox Basin, the Leadville formation has excellent reservoir characteristics. In the Paradox Valley area, however, portions of the Leadville were severely eroded during 

Pennsylvanian uplift (such as under Wray Mesa, Figure 10). Not only was the thickness of the 

Leadville decreased along the structural highs, but the porosity was also reduced when solution 

cavities that formed during uplift filled with shales and clays. Areas of dolomitization directly 

below these weathered sections generally have the best reservoir characteristics. Effective porosity improves with the degree of dolomitization. The complexity of structural relief present during 

weathering and dolomitization make the reservoir characteristics of the Leadville formation in the 

Paradox Valley area variable and difficult to predict. 

Bremkamp and Harr (1988) compiled log-derived porosity data from eight wells to characterize 

the regional porosity of the Leadville formation. Bremkamp et al. (1984) includes porosity values 

from one additional well (from the map in Figure 13). The combined data are presented in Table 

3. (The Lisbon Oil Field wells included in the table are located approximately 27 miles southwest 

of PVU Injection Well #1.) The variation of Leadville porosity is apparent from the table, espe-
40

Table 3: Porosity of the Leadville Formation measured in local and regional wells, taken from 

Bremkamp et al. (1984) and Bremkamp and Harr (1988). 

Well Name

Thickness of 

Leadville 

(ft)

Distance 

from PVU 

Inj. Well #1 

(km)

Feet of 3% 

or greater 

porosity

Feet of 5% 

or greater 

porosity

Feet of 10% 

or greater 

porosity

PVU Injection 

Well #1 416 0 164 86 2

Union 

Otho Ayers

No 1-0-30

340 0.12 33 7 0

Conoco-Scorup

Somerville 

Wilcox #1 

264+ 4.6 118 86 31

Pure Oil -Wray 

Mesa Unit #3 279 10.4 not reported 31 not reported

Pure No. C-92 

Lisbon 459 43.5 67 4 0

Union No. B624 Lisbon 430 43.5 250 98 0

Union No. C93 Lisbon 404 43.5 163 107 11

Union No. B815 Lisbon 460 43.5 247 99 37

Union No. D89 Lisbon 508 43.5 313 187 33
41

cially when comparing porosity values at PVU Injection Well #1 with those from the Union-Ayers 

well, located only 400 ft (0.12 km) away. The Leadville interval in PVU Injection Well #1 has 164 

ft with 3% or greater porosity while the Leadville interval encountered in the Union well contains 

only 33 ft of the same. Leadville porosity in PVU Injection Well #1 is intermittent throughout the 

Leadville formation, which is considered atypical (Bremkamp and Harr, 1988). 

The low porosity of the Leadville makes it an inadequate reservoir when considering intermatrix 

porosity alone. Hydrologic permeability is greatly increased due to the presence of an extensive 

fracture field related to the Wray-Mesa fault system. At PVU Injection Well #1, 182 ft of Leadville core was recovered. Twenty-seven percent of the core contained open fractures, and hairline 

fractures were present throughout the recovered core. Dominant fracture inclinations ranged from 

65 to 85 degrees. Analysis of microscanner image, fracture identification, and sonic waveform 

borehole logs also indicate significant intervals of fracturing within the Leadville formation. 

Precambrian Schist

The permeability of the Precambrian schist penetrated by PVU Injection Well #1 is controlled by 

both the porosity and the presence of fractures. Based on analysis of sonic log data, the upper Precambrian schist at this site was estimated to have 42 ft with 3% or greater porosity and 30 ft with 

5% or greater porosity. Fractures observed in 30 ft of recovered core show dips ranging from 22 to 

65 degrees. Those with 55 degrees dip and near common azimuth were dominant. The microscanner image, fracture identification, and sonic waveform borehole logs indicate fracturing over a 

150-ft interval of the upper Precambrian. (15,500 - 15,650 ft depth). Bremkamp and Harr (1988) 

considered the upper 191 ft of Precambrian as a viable injection zone.

Devonian-Cambrian

Reservoir characteristics of the Devonian and Cambrian formations in northeastern Paradox 

Basin are generally poor. However, due to the presence of fractures in the Devonian Ouray formation and the top of the Devonian Elbert formation in PVU Injection Well #1, Bremkamp and Harr 

(1988) considered these formations to be potential reservoirs locally. Combined they contain 14 ft 

of 5% or greater porosity in PVU Injection Well #1. The Devonian McCracken and Cambrian 

Ignacio formations do have some favorable porosity and fracture characteristics, but they were 

considered to have low storage volume potential.

3.4 Additional Information

Little additional geologic or geophysical information has been gathered by Reclamation since the 

early PVU studies were performed. The limited additional well data and seismic reflection data 

that have been obtained are discussed briefly below. In addition, the spatial pattern of seismicity 

induced by injection into PVU Injection Well #1 is presented, for comparison to Bremkamp and 

Harr’s (1988) predicted pattern of fluid flow and pressure rise.

3.4.1 Well Data

A search of the Colorado Oil and Gas Commission well database (http://cogcc.state.co.us/cogis, 

June, 2012) revealed only one borehole that has been drilled to the depth of the Leadville formation in the vicinity of Paradox Valley since the initial PVU geologic investigations were per-
42

formed in the 1980’s. The location of this borehole is shown in Figure 22. The well was 

completed in 2008, to a total depth of 14,421 ft. The reported depth at which the hole encountered 

the top of the Leadville formation has been converted to elevation with respect to sea level for 

comparison to Bremkamp and Harr’s (1988) interpreted top-of-Leadville contours. The interpreted contours and observed Leadville elevation in the new borehole are shown in Figure 22. The 

2008 well encountered the Leadville formation at an elevation of 8501 ft below sea level. This 

strongly suggests that the buried fault which Bremkamp and Harr extrapolated to lie just west of 

this borehole should actually locate east of the well, so that the borehole lies on the upthrown side 

of the fault. The thickness of the Leadville formation encountered in this well is not reported in 

the Colorado Oil and Gas Commission online database. However, the depth interval between the 

top of the Leadville formation and the top of the McCracken formation is reported as 554 ft. 

Assuming that the Devonian Ouray and Elbert formations have the same thickness here as in PVU 

Injection Well #1 (207 ft) gives an estimated thickness of the Leadville formation of 347 ft. This 

is a little less than the ~400-ft thickness estimated by Bremkamp et al. (1984), but the trend is 

consistent with their interpreted thickening of the Leadville formation along the edge of the valley 

(Figure 12, upper plot).

3.4.2 Seismic Reflection Data

The rights to two additional seismic reflection lines were purchased by Reclamation in 2004 (Figure 22). These lines have been processed but no geologic interpretation of them has been documented. We have not found any evidence that they have been tied to the lithology, or that the 

locations and throws of faults have been interpreted from them. Interpretation of these lines would 

help evaluate the accuracy of Bremkamp and Harr’s (1988) interpreted top-of-Leadville contours 

and faults in the areas the lines transect. They are available for further studies if the additional 

information they may provide is deemed useful for siting a second injection well.

A preliminary search of seismic reflection data available for purchase has shown that there are 

many existing 2-D seismic reflection datasets in the Paradox Valley area, both across the valley 

itself and on the surrounding mesas. These data were acquired between the early 1960’s and mid1980s. Folds range from single- to 24-fold. Data acquired with either dynamite or vibroseis 

sources are available. To date, none of the available reflection lines have been reviewed by Reclamation for data quality.

3.4.3 Induced seismicity

More than 5,800 shallow earthquakes (locating less than 8.5 km (27,900 ft) deep with respect to 

the ground surface elevation at PVU Injection Well #1) have been recorded in the vicinity of Paradox Valley since PVU injection operations began in 1991. No such shallow earthquakes were 

detected in six years of seismic monitoring prior to the start of injection operations. 

Earthquakes were first detected 4 days after the start of the initial injection test into PVU Injection 

Well #1 in July, 1991. The first earthquakes occurred very close to the injection well. As injection 

continued, earthquakes continued to occur close to the well but also began occurring at greater 

and greater distances from the well. The expansion of seismicity away from the well over time is 

seen in the upper plot of Figure 23. This graph shows the recorded earthquakes with computed 
43

Figure 22: Location of a local well that has been drilled to the depth of the 

Leadville formation since the 1980’s (yellow circle), and the locations of two 

additional seismic reflection lines that were purchased by Reclamation in 2004 

(yellow lines). The elevation, relative to mean sea level, at which the well 

reached the top of the Leadville formation is plotted next to the well symbol, for 

comparison to the interpreted top-of-Leadville contours of Bremkamp and Harr 

(1988).
44

0

2

4

6

8

10

12

14

16

18

Jan-85 Jan-87 Dec-88 Dec-90 Dec-92 Dec-94 Dec-96 Dec-98 Dec-00 Dec-02 Dec-04 Dec-06 Dec-08 Dec-10

Distance from Well (km)

all shallow earthquakes

events with M >= 2.5 and < 3.0

events with M >= 3.0 and < 3.5

events with M >= 3.5

0

50

100

150

200

250

300

350

400

Jan-85 Jan-87 Dec-88 Dec-90 Dec-92 Dec-94 Dec-96 Dec-98 Dec-00 Dec-02 Dec-04 Dec-06 Dec-08 Dec-10

Injection Flow Rate (gpm)

Figure 23: Upper plot - scatter plot of earthquakes having 

and locating less than 8.5 km deep (relative to the ground surface elevation at 

the injection wellhead), plotted as a function of date and distance from PVU 

Injection Well #1. Each circle represents a single earthquake, with the width of 

the circle scaled by the event magnitude. The lower plot shows the daily average injection flow rate.

magnitude  0.5
45

duration magnitude of M 0.5 or greater, locating less than 8.5 km (27,900 ft) deep, plotted as a 

function of date and distance from the injection well. Each circle on the graph represents one 

earthquake, and the width of the circle is scaled by relative earthquake magnitude. The lack of 

shallow seismicity detected during six years of pre-injection seismic monitoring and the temporal-spatial evolution of shallow seismicity since the start of injection operations demonstrated in 

Figure 23 strongly suggest that these shallow earthquakes have been induced by PVU fluid injection.

The spatial distribution of induced seismicity is presented in more detail in the series of maps 

shown in Figure 24. By the end of the injection tests in 1995, earthquakes were occurring 3 to 4 

km (1.9 to 2.5 miles) from the injection well (Figure 24a). This area of induced seismicity immediately surrounding the injection well has historically been called the “primary zone” of induced 

seismicity, but is also referred to as the “near-well” region. In 1997, a few months after the start of 

continuous injection, earthquakes began occurring 6 to 8 km (3.7 to 5.0 miles) northwest of the 

injection well (Figure 24b). This cluster of induced seismicity is called the “secondary zone” of 

induced seismicity, or the “northwest (NW) cluster”. In mid-2000, earthquakes were first detected 

12 to 14 km (7.5 to 8.7 miles) from the injection well, along the northern edge of Paradox Valley 

(Figure 24b). Several distinct clusters of earthquakes have occurred along the northern edges of 

the valley since 2000 (Figure 24c,d). The earthquakes occurring in all of these clusters are 

referred to as “northern valley events”. An earthquake was first detected about 6 km (3.7 miles) 

southeast of the injection well in 2004 (Figure 24c), but the seismicity rate in this area markedly 

increased beginning in 2010 (Figure 24d). This tight group of earthquakes is referred to as the 

“southeast (SE) cluster”. In recent years, a few isolated earthquakes have been detected in previously aseismic areas, including in the center of Paradox Valley (Figure 24d).

The spatial distribution of induced seismicity does not necessarily indicate the pattern of flow of 

injected fluids. As suggested by Bremkamp and Harr (1988), an increase in pore pressure may 

occur far from the location of the injectate, as in-situ groundwater is displaced. Furthermore, the 

emplacement of large quantities of injectate can cause local subsurface stress conditions to 

change, and such changes may induce earthquakes in areas that are not necessarily experiencing 

direct changes in pore pressures from fluid injection.

Although the relationship between the flow of injected fluids and associated pressure rise of insitu groundwater and the occurrence of induced seismicity is complex, the pattern of induced seismicity is the only indication we currently have for where subsurface conditions have been 

affected by fluid injection. A comparison of the pattern of induced seismicity and the predicted 

“area of least resistance to fluid movement and pressure rise” in the Leadville formation, from 

Bremkamp and Harr (1988), may shed some light on the consistency of the seismicity and the 

geologic/hydrologic model. Such a comparison is presented in Figure 25, which shows the seismicity superimposed on Bremkamp and Harr’s contours of Leadville hydrostatic pressure and 

zone of predicted fluid flow and pressure rise. Bremkamp and Harr did not make a comparable 

map of predicted fluid flow and pressure rise from injection into the Precambrian, but they stated 

that the pattern would be similar to that mapped for the Leadville formation.

Bremkamp and Harr (1988) predicted that the fluid injected into the Leadville formation from 

PVU Injection Well #1 would be confined to a two-mile-wide, northwest-southeast-trending cor-
46

Figure 24: Maps showing the spatial distribution of 

shallow seismicity recorded in the Paradox Valley area 

over time: (a) injection tests, 1991-1995 (b) continuous 

injection,1996-2000 (c) continuous injection, 2001-2008 

(d) continuous injection, 2009-2012. All detected earthquakes locating less than 8.5 km deep (relative to the 

ground surface elevation at the injection wellhead) are 

included.

(a)

(b)

NW cluster

near-well

zone
47

(c)

(d)

northern-valley

 events

SE cluster

Figure 24, continued.
48

Figure 25: Contour map of hydrostatic pressure within the Leadville formation and predicted area of least resistance to fluid movement and pressure rise 

from injection into PVU Injection Well #1, from Bremkamp and Harr (1988) 

(drawing no. 2), and epicenters of shallow earthquakes interpreted to be 

induced by fluid injection into PVU Injection Well #1. (Fault traces were digitized from drawing no. 1, Bremkamp and Harr, 1988).
49

ridor bounded by impermeable faults. The majority of the seismicity occurring on the southern 

side of Paradox Valley lies within these fault boundaries, with the exception of a cluster of earthquakes occurring near the complex intersection of faults located 3.4 km southwest of the injection 

well (Figure 25). The general lack of seismicity outside of these fault boundaries supports 

Bremkamp and Harr’s interpretation that these faults are impermeable to fluid flow through the 

Leadville formation, although details of the intersection of faults to the southwest of the well may 

not be correct. 

Bremkamp and Harr also predicted that the pressure rise associated with fluid injection would 

extend into the “fan-shaped” areas wrapping around the northwestern and southeastern ends of 

Paradox Valley (Figure 21). There is less resistance to fluid flow and pressure rise toward the 

northwest, since the Leadville formation becomes shallower in that direction and therefore the 

hydrostatic pressure decreases. Based on this prediction, the occurrence of seismicity at the northwestern end of Paradox Valley is not unexpected. However, most of the shallow earthquakes 

occurring along the northern edges of Paradox Valley lie outside the boundaries of Bremkamp and 

Harr’s “area of least resistance to fluid flow and pressure rise” (Figure 25). The outline of this 

region of least resistance to pressure rise is based on the depth and dip of the Leadville formation, 

the locations and throws of faults, and a hydrostatic pressure boundary value of 6,320 psi (see section 3.3.1). The geologic model was extrapolated by Bremkamp and Harr from limited well and 

seismic reflection data. The available seismic reflection data did not extend to the areas of seismicity occurring around the northern edges of Paradox Valley, and there are no known wells that 

penetrate the Leadville formation in the vicinity of the northern-valley seismic zones (Figure 25). 

Hence, there are no apparent data points to constrain the geologic model at the northern end of 

Paradox Valley. Furthermore, Bremkamp and Harr (1988) do not explain why the hydrostatic 

pressure contour of 6,320 psi was chosen to define the extent of the zone of least resistance to 

pressure rise, and therefore the value appears to be somewhat arbitrary. Based on the limited geologic data available, it is possible that an equally acceptable geologic/hydrologic model could be 

constructed that would include the northern valley seismicity within the area of Leadville (and 

Precambrian) pressure rise from fluid injection into PVU Well #1. Additional deep seismic reflection data and/or well data at the northern end of Paradox Valley would be needed to better constrain the hydrologic model in this area.

Several earthquakes that have occurred beneath central Paradox Valley since 2010 coincide with 

the location of the mid-valley fault mapped by Bremkamp and Harr (Figure 25). These earthquakes locate within the Precambrian basement. (Most occur at elevations between -3.6 and -6.5 

km (-11,800 to -21,300 ft), although the largest earthquake recorded to date, a M 1.4 event, 

locates somewhat deeper at -8.2 km (-26,900 ft) elevation.) While it is possible that changing 

conditions related to PVU fluid injection has caused slip on this basement fault, the earthquakes 

recorded to date do not provide sufficient-quality data to compute focal mechanisms and determine the orientation of the source fault(s).
50

4.0 Injection Well Site Selection

4.1 Criteria for Site Selection

Site selection for a second well is dependent on several criteria, both geological and logistical. 

Geological criteria include the characteristics of the reservoir formation (e.g., thickness, spatial 

extent, depth, porosity, permeability, chemical composition, and fracture gradient), the 

characteristics of the confining layer (e.g., thickness, fracture gradient, composition, and 

integrity), anticipated flow paths and barriers for the injected fluid, the estimated reservoir 

capacity, and the degree of confidence in the geophysical and geological interpretations for the 

site. Logistical considerations include the distance and elevation difference between the 

extraction field and the injection well, drilling difficulty level, the anticipated longevity of the 

well, and access issues. Additional constraints include the hydrologic and stress/pore-pressure 

isolation from the existing injection well.

Reservoir Properties

The Mississippian Leadville formation has been identified as the primary objective reservoir in 

the region (e.g., Bremkamp and Harr, 1988; Harr, 1989). The porosity of the formation is regionally variable, and the amount of Leadville porosity data in the immediate vicinity of Paradox Valley is limited (Table 3). Furthermore, Leadville porosity can vary over very short distances (such 

as between PVU Injection Well #1 and the Union Otho Ayers No 1-0-30 well, Table 3). 

Bremkamp et al. (1984) considered it necessary for a portion of the Leadville formation to have a 

porosity of 5% or greater in order to initiate injection and allow fluid to reach fractures not 

directly connected to the borehole. While proximity to well data can provide some information on 

the potential porosity characteristics at a proposed second well site, the possibility of significant 

variation in characteristics over short distances means that Leadville porosity characteristics may 

not be known confidently prior to drilling a well. 

As intermatrix porosity of the Leadville is low, much of the rock’s permeability is supported 

through the presence of fractures. The Leadville formation contains a fracture field associated 

with the northwest-trending Wray-Mesa Fault system. Cores from PVU Injection Well #1 show 

extensive fracturing while the fracture system is less pronounced at the Conoco Scorup #1 well. 

The permeability at each site was interpreted to be nearly equal (Harr 1989), illustrating the 

importance of both fractures and porosity in creating an adequate reservoir. 

The underlying Precambrian schist also may act as a reservoir. The upper 65 ft of schist at 

Injection Well #1 had 42 ft of 3% or greater porosity. Fractures were also present in the cores but 

to a lesser extent than in the Leadville formation. 

In choosing a site for a second injection well, it will be essential that the proposed reservoir can 

sustain injection over its lifetime (at least 25 years). To accurately estimate the capacity of the 

reservoir, it likely will be necessary to evaluate fundamental reservoir characteristics such as the 

intermatrix porosity of the rock, the degree of fracturing, the reservoir layer thickness, and the 

location and offsets of faults. While the total storage space available is largely determined by 
51

porosity, fractures, and the volume of the formation, the geometry of the subsurface rock units 

and buried faults will likely control the pattern of fluid flow. Accurate measurement of the 

porosity, degree of fracturing, and thickness of the Leadville formation likely can be determined 

only from well data, while the depth and dip of formations and location and offsets of faults 

possibly can be interpreted from high-quality deep seismic reflection data. 

Confining Layer Thickness and Integrity

A crucial aspect in choosing an injection site is the assurance that the injected brine will remain 

confined at depth. The impermeability and plastic behavior of the Paradox formation salt makes it 

an excellent confining layer. At least 250 ft of salt is necessary in order to safely confine the 

injected brine (Bremkamp et al. 1984, Katz and Carroll, 1984). While a thicker layer of salt is a 

better barrier, the difficulties in drilling and maintaining a well increase in thick salt sections. An 

extremely thick salt section has the potential for damage or collapse of the well over time. 

Hydrologic and Pore-Pressure Separation from Injection Well #1

As the main goal in drilling a second injection well is to allow for the further injection of brine 

without exceeding the maximum allowable surface injection pressure, it is necessary that the 

reservoir accessed by the second well be hydrologically separated from that of PVU Injection 

Well #1. Control of induced seismicity, which is related to incremental changes in pore pressure, 

also requires separation from the effects of the existing well and reservoir. The local subsurface 

geology and hydrology (e.g., as mapped from well logs and deep seismic reflection data in 

Bremkamp and Harr, 1988) and the spatial distribution of earthquakes induced by fluid injection 

to date will both need to be considered when evaluating the separation of proposed well sites from 

the previously-injected reservoir. 

Confidence in Subsurface Geologic Interpretation

Site selection depends on our understanding of the subsurface geologic structure and reservoir 

characteristics. Confidence in subsurface geologic and geophysical interpretations largely relies 

on the proximity of direct measurements (wells) and the availability of good-quality deep seismic 

reflection data. Unfortunately, the number of existing wells that penetrate the Leadville formation 

in the vicinity of Paradox Valley is very limited. The quality of available seismic reflection data is 

highly variable, with the better-quality data often acquired on the surrounding mesas, at higher, 

less-desirable elevations for an injection well site. Hence, limiting site selection to areas with 

existing high-quality subsurface data significantly reduces the flexibility in locating a second 

injection well. Acquiring additional subsurface information, such as from deep seismic reflection 

data recorded with modern acquisition techniques, may increase the flexibility of the site selection 

process, but at a significant cost.

Logistics and Cost Concerns 

Many factors contribute to the logistics involved in drilling and operating a new brine disposal 

well. For example, the elevation of a selected site relative to the extraction wells and the distance 

from the extraction wells play a large role in the cost involved in injecting waste water over the 
52

well’s lifetime. A second injection well site ideally would be located close to the extraction wells, 

with a minimum elevation difference. If directional drilling allows access to new reservoirs from 

existing surface facilities, then costs could be reduced by using preexisting infrastructure (e.g. 

pipelines and roads). 

The depth to the reservoir formation and the thickness of the overlying confining layer also play a 

large role in the logistics of drilling and the longevity of the well. The cost of drilling and 

completing the well increases with total well depth. Thick salt layers can cause difficulties in both 

drilling and maintaining a well. The plastic nature of salt may cause a well to collapse. 

4.2 Proposed Sites from Previous Studies

Several potential injection well sites were proposed during early PVU studies (Bremkamp et al., 

1984; Katz and Carroll, 1984). Investigators largely relied on existing well data when evaluating 

sites, both because of the variable and often marginal quality of the available seismic reflection 

data and because of the variability of the reservoir characteristics of the Leadville formation. The 

location of PVU Injection Well #1 was selected largely due to its proximity to the Union Oil Co. 

#1 well, which allowed for accurate interpretation of the subsurface geology and eased logistics of 

creating a new well. The Union well showed adequate salt thickness to confine injected brine (270 

ft) and demonstrated favorable reservoir qualities. (See Davis (1985) for an engineering review of 

PVU Injection Well #1 site selection.) 

Most of the potential injection well site locations documented in early PVU reports were proposed prior to the site selection and drilling of PVU Injection Well #1 (Bremkamp et al., 1984; 

Katz and Carroll, 1984). One report, written after the completion of PVU Injection Well #1, specifically details the benefits of a site proposed for the location of a second injection well (Harr, 

1989). This latter study employed similar criteria for site selection as the earlier studies, with the 

exception of the additional criterion of hydrologic isolation from the target reservoir of the first 

injection well. Besides the location chosen for PVU Injection Well #1, seven additional sites were 

suggested in these reports. The same location was sometimes proposed by more than one group of 

authors. A combined list of the proposed sites documented in three cited PVU reports is given 

below; site locations are shown in (Figure 26). 

Site A

(Bremkamp et al., 1984 - location #2; Katz and Carroll, 1984 - well #2)

Latitude and Longitude: 38.282 N, 108.895 W

Elevation: 5020 ft

Salt Thickness: 1400 - 1500 ft

Depth to Leadville: 12,450 ft

Leadville Thickness: ~ 300 - 325 ft

Two groups of consultants recommended this site as a potential location for the initial PVU injection well. The site is located approximately 3/4 mile (1.2 km) south of PVU Injection Well #1. It 

has a thicker salt layer and a shallower depth to the Leadville formation than PVU Well #1. A 
53

Figure 26: Locations of potential sites for an injection well, proposed by 

Katz and Carroll (1984), Bremkamp et al. (1984), and Harr (1989). See text 

for a description of each proposed location.
54

normal fault in the basement and Paleozoic rocks with between 1000 and 2600 ft of throw (downfaulted toward PVU Well #1) lies between this site and PVU Injection Well #1 (Bremkamp et al., 

1984; Katz and Carroll, 1984). While Bremkamp et al. (1984) considered it unlikely that fluids 

would migrate through the Leadville formation across this fault, seismicity induced by injection 

into PVU Well #1 routinely occurs at this site. Hence, it must be considered highly unlikely that 

this site is hydrologically isolated from PVU Well #1.

Site B

(Bremkamp et al., 1984 - location #3; Harr, 1989; Katz and Carroll, 1984 - well #6)

Latitude and Longitude: 38.337 N, 108.877 W

Elevation: 5040 ft

Salt Thickness: 13,750 ft

Depth to Leadville: ~ 14,760 ft (Katz and Carroll 1984)

Leadville Thickness: ~250 ft (Katz and Carroll 1984)

This site lies in the center of the Paradox Valley salt anticline, near the Conoco Scorup Somerville 

Wilcox #1 well. This location was proposed in all reports detailing potential injection well sites, 

including a report specifically promoting it as a second injection site (Harr, 1989). The site was 

considered to have the best reservoir characteristics of all of the proposed sites based on gammaray neutron logs, drill stem test (DST) data, and limited core data from the Conoco well. Prior to 

the drilling and testing of PVU Injection Well #1, the porosity of the Leadville formation 

observed from the Conoco well was much higher than that seen in the rest of the area. This site 

would have been considered the preferred choice for the initial PVU injection well if it were not 

for the difficulties in drilling and maintaining a well in a 14,000-ft section of salt. The report by 

Harr (1989) details the reservoir characteristics of this site, as well as suggested procedures to 

successfully drill the well through the salt section. 

Site B is separated from PVU Injection Well #1 by a salt-filled graben (cross section B-B’, Figure 

20) and is removed from most of the seismicity induced by injection into PVU Well #1. However, 

clusters of shallow seismicity that are likely related to fluid injection into PVU Well #1 (based on 

spatial and temporal seismicity patterns) occur roughly 8 to 13 km northwest of this location 

within the same fault block, as interpreted by Harr and Bremkamp (1988) (Figure 26). (Isolated 

earthquakes within Paradox Valley, most of which have occurred within the last two years, locate 

at much closer distances.) There are no apparent deep seismic reflection or well data to constrain 

Harr and Bremkamp’s interpreted locations of faults and depths to the Leadville formation at the 

northwest end of Paradox Valley. Given the uncertainty in the geologic interpretations, it is not 

possible to state definitively whether site B is hydrologically isolated from the seismicity occurring at the northwest end of Paradox Valley. Based on the interpreted shallowing of the Leadville 

formation to the northwest, fluid injected into the Leadville formation at site B would be expected 

to migrate toward the induced seismicity at the northwest end of Paradox Valley. 

Site C

(Bremkamp et al., 1984 - location #4)

Latitude and Longitude: 38.270 N, 108.932 W

Elevation: 5060 ft
55

Salt Thickness: 250 ft

Depth to Leadville: ~ 12,500 ft

Leadville Thickness: 100 - 250 ft?

This site is located along the Dolores River, about 4.8 km southwest of PVU Injection Well #1. 

Prior to the completion of PVU Well #1, Bremkamp et al. (1984) suggested this site as a potential 

location for a second injection well to increase the total reservoir capacity of PVU. Site C lies to 

the west of a fault that Bremkamp et al. interpreted as being impermeable to fluid flow within the 

Leadville formation. Hence, the geologic interpretation indicates that the Leadville formation at 

site C is hydrologically isolated from injection into the Leadville at PVU Injection Well #1. A 

small number of earthquakes induced by fluid injection into PVU Well #1 locate at this site.

Unfortunately, the thickness of the Leadville formation at this site is not well constrained. 

Bremkamp et al. (1984) report a conservative estimate of 100 ft for the thickness of the Leadville 

formation at this site, but the Leadville isopach map of Katz and Carroll (1984) indicates a thickness of 250 ft at this location. According to the geophysical interpretation of Bremkamp et al. 

(1984), the thickness and reservoir quality of the Leadville formation was decreased along a structural high in this area, due to erosion, karst weathering, and infill of voids with shale and clay.

Site D

(Katz and Carroll, 1984 - well #3)

Latitude and Longitude: 38.304 N, 108.891 W

Elevation: 5050 ft

Salt Thickness: 250 ft

Depth to Leadville: 13,850 ft 

Leadville Thickness: 300 ft

This site lies on the southern boundary of Paradox Valley along the Dolores River, approximately 

3/4 mile (1.2 km) north of PVU Injection Well #1. The thickness of the salt section here is uncertain. The salt section is likely thinner here than at PVU Injection Well #1, but Katz and Carroll 

(1984) state that the overlying Hermosa shale would likely form an adequate seal for injection 

into the Leadville formation. They also suggest that faulting occurring 1/4 mile (0.4 km) to the 

northeast may enhance reservoir quality by “fault-associated fracturing”. If the geologic interpretation of Harr and Bremkamp (1988) is correct, this location lies in the same fault block as PVU 

Well #1, and therefore the Leadville formation at this location is not hydrologically isolated from 

fluids injected into PVU Well #1. The occurrence of seismicity induced by injection into PVU 

Injection Well #1 at site D supports this geologic interpretation. 

Site E

(Katz and Carroll, 1984 - well #4)

Latitude and Longitude: 38.326 N, 108.932 W

Elevation: 5350 ft

Salt Thickness: 200 ft

Depth to Leadville: 13,350 ft 
56

Leadville Thickness: 300 ft

This site lies on the southern boundary of Paradox Valley, about 4.5 km northwest of PVU Injection Well #1. As with site D, the thickness of the salt layer here is uncertain but likely to be inadequate, and Katz and Carroll (1984) argue that the lower Hermosa shale would form an adequate 

seal. The depth to the Leadville formation is expected to be a few hundred ft less here than at site 

D. Although Wray Mesa faults may enhance reservoir characteristics at this location (Katz and 

Carroll, 1984), the geologic interpretation is less well-constrained here than at most other proposed sites because of greater distances to seismic reflection and well control points. According to 

the geologic interpretation of Bremkamp and Harr (1988), this proposed location lies in the same 

fault block as PVU Injection Well #1 and is not hydrologically isolated from it. However, induced 

seismicity has not been observed at site E; the nearest induced earthquakes locate about 1 km 

away.

Site F

(Katz and Carroll, 1984 - well #5)

Latitude and Longitude: 38.290 N, 108.992 W

Elevation: 6982 ft

Salt Thickness: 3,026 ft

This site is located near the Shell Oil Wray Mesa Unit #2 well, 8.6 km west of PVU Injection Well 

#1. The Leadville formation is fully eroded at this location. Katz and Carroll (1984) propose 

considering an injection well at this site utilizing the lower Cutler and upper Hermosa formations 

as the target reservoir. Logs from the Wray Mesa Unit #2 well show 300 ft of clean sand with 

likely high permeability. The proposed target reservoir lies above the Paradox salt. Katz and Carroll (1984) do not mention what the proposed confining layer would be, although an earlier report 

indicates that the overlying Moenkopi and Chinle formations may act as sufficient confining layers (Williams Brothers, 1982). The distance of this site from the extraction wells and the site’s 

high elevation would make the logistics of developing an injection well at this location difficult.

Site G

(Katz and Carroll, 1984 - well #7)

Latitude and Longitude: 38.262 N, 108.905 W

Elevation: 6500 ft

Salt Thickness: 1000 ft

Depth to Leadville: 12,200 ft (Katz and Carroll 1984) 

Leadville Thickness: 350 ft

This site is located about 3.9 km south of PVU Injection Well #1. The thickness of the salt layer 

and depth to the Leadville formation make this site a potential candidate. Katz and Carroll (1984) 

claim that the seismic reflection data are good in this area, lending increased reliability to the subsurface geologic interpretation. However, there is no well control for the interpreted thickness of 

the Leadville formation in this area. Katz and Carroll (1984) estimated a thickness of 325 to 350 

ft for the Leadville formation at this location, but Bremkamp et al. (1984) interpreted a thickness 
57

of only ~150 ft at this site (Figure 12). Furthermore, the high elevation of the site and the distance 

from the extraction wells makes this site logistically undesirable. For this reason, it was Katz and 

Carroll’s (1984) last choice of their seven proposed locations for an initial PVU injection well. 

Site G lies just outside the zone of seismicity induced in the vicinity of PVU Injection Well #1. It 

locates in a small fault block, as interpreted by Harr and Bremkamp (1988) (Figure 26). The 

hydrologic connectivity of the Leadville formation between this fault block and adjoining blocks 

has not been evaluated. 

5.0 Discussion

The majority of the injection well site locations proposed in the 1980’s are not favorable for the 

location of a second PVU injection well. Sites A, D, and E lie within the northwest-southeasttrending fault-bounded corridor of fluid flow from PVU Injection Well #1, as predicted by 

Bremkamp and Harr (1988) and corroborated by the pattern of induced seismicity (Figure 25). 

Hence, fluid injected into the Leadville or Precambrian formations at these locations would 

almost certainly not be hydrologically isolated from the reservoirs accessed by PVU Injection 

Well #1. 

Sites F, C, and G lie along an inferred old structural high where the Leadville formation was 

eroded and weathered, according to Bremkamp et al. (1984). The Leadville formation is completely eroded at site F and is of unknown thickness and porosity characteristics at sites C and G. 

The unknown lateral extent of the proposed Cutler formation reservoir at site F, as well as the 

site’s high elevation, lead us to discount this proposed location. The potential thinning and weathering-related reduced porosity of the Leadville formation at sites C and G, along with the lack of 

well data to provide reliable reservoir characterization data, make drilling at these locations a considerable risk. The complex, and perhaps not correctly understood, fault geometries in this area 

also raise the question of the spatial extent of potential reservoirs. Further investigations would 

need to be performed before choosing to drill a deep injection well at sites C or G.

Site B, located in the center of Paradox Valley close to the Conoco Scorup No. 1 well, remains a 

potentially viable option. Reservoir characteristics in this area are favorable and it is close to the 

extraction well field. Two issues should be addressed, however, before a decision is made to 

install a second PVU injection well at this proposed location. First, the long-term stability of the 

wellbore in the 14,000-ft section of salt must be thoroughly evaluated. A high degree of confidence in the long-term stability of the wellbore must be obtained before proposing the costly 

installation of an injection well at this location. Second, the hydrologic isolation of this location 

relative to clusters of seismicity located 8 or more km to the northwest should be considered.

Documented opinions on the feasibility of drilling and maintaining an injection well through the 

thick salt diapir within Paradox Valley vary. Goins and Flak (1983) state that installing a 15,500-ft 

disposal well within Paradox Valley is “impractical due to problems completing thru deep salt, 

high fracturing pressures, and excessive well cost”. They further state that, “The deepest salt can 

be completed thru with good well life is approximately 11,000 ft” and, “Ideally, a location should 

be picked so that salt is no deeper than 9000’ to further reduce the risk of salt collapse and well 

cost.” Klementich (1983) provides similar comments, “It is possible, but extremely difficult and 

very costly, to drill nearly 15,000’ of massive, laterally loaded, salt beds, equip the well for per-
58

manent injection and expect a useful life of twenty plus (20+) years. ... It would be more logical to 

drill a well “off structure” where only approximately 500’ (plus or minus) of salt would be 

encountered.” Despite these initial arguments against locating an injection well within Paradox 

Valley, by 1988, preliminary designs were made for a second injection well at site B. Flak and 

Ables (1988) present a well design and cost estimate for installation of an injection well at this 

location, with an expected project life of “100 years minimum”. In 2003, Reclamation hired Subsurface Technology, Inc. to review plans for installation of an injection well at or near site B, 

including the Flak and Ables (1988) report. This review resulted in a letter from Subsurface Technology stating that, “the technology is available to successfully drill, complete, and operate a second well below 14,000 ft of salt” and that “Subsurface generally agrees with the basic design 

considerations that were proposed in 1988 ... It would appear that we have a good basis for the 

design and implementation of a second well to penetrate the fault block below the salt diapir” 

(Bundy, 2003). The engineering considerations of installing an injection well through the salt diapir have not been revisited since this 2003 review.

The hydrologic isolation of site B relative to clusters of seismicity located 8 or more km to the 

northwest is not well understood. Based on the interpreted shallowing of the Leadville formation 

to the northwest, however, fluid injected into the Leadville formation at site B would be expected 

to migrate toward the seismicity at the northwest end of Paradox Valley. Although the northernvalley seismicity appears to be related to injection of fluid into PVU Injection Well #1, based on 

temporal and spatial seismicity patterns (Figure 23), it is not consistent with the geologic and 

hydrologic model constructed by Bremkamp and Harr (1988). As discussed in section 3.4.3, no 

apparent data were available to constrain the original geologic model at the far northwest end of 

the valley. It may be advisable to obtain additional deep seismic reflection data between site B and 

the northwest end of Paradox Valley. This would allow a better understanding of the geologic 

structure along the potential flow path of fluid injected at site B (allowing for an estimate of the 

reservoir capacity), and may shed light on the hydrologic connectivity of site B to the seismicallyactive areas at the northwest end of the valley.

Recent informal discussions within Reclamation have included considering drilling a second 

injection well into the deepest fault block beneath Paradox Valley, located immediately northeast 

of the fault block containing PVU Injection Well #1 (see cross sections, Figure 20). Early investigators did not recommend installing an injection well in this deep fault block, presumably 

because of the increased cost associated with drilling to the additional depth that would be 

required. The scarcity of optimum site locations for a second injection well, however, has raised 

the question of whether drilling into the deep fault block should be reconsidered. Extremely little 

induced seismicity has located within this block, suggesting that the Leadville and Precambrian 

target reservoirs within this block are hydrologically isolated from those being utilized by PVU 

Well #1. If modern directional drilling techniques could be used, the wellhead for the second 

injection well could potentially be located close to PVU Injection Well #1. This would allow 

many of the surface facilities already in place to service the first injection well to also be used to 

support the second well, thereby reducing the cost of the project. In addition, directional drilling 

would greatly decrease the thickness of salt that the well would penetrate, compared to drilling a 

vertical well within the salt anticline underlying Paradox Valley. To date, no engineering evaluation has been performed to determine the feasibility of the directional drilling. If the directional 

drilling were deemed feasible and this proposed location were to be pursued, it may be advisable 
59

to acquire additional high-resolution deep seismic reflection data to better define the deep geologic structure at the boundary between the fault blocks.

Alternative sites that may be considered are on the northern side of Paradox Valley, where the 

Dolores River exits the valley, or within the Dolores River valley slightly farther downstream. An 

injection well in this area would be close to the extraction well field, with a minimal elevation difference. A well in this vicinity could penetrate either the upthrown fault block on the northern side 

of Paradox Valley or the northern-most fault block underlying Paradox Valley (see cross section 

B-B’, Figure 20). Based on the very limited seismic reflection data available to early investigators 

in this vicinity (small segment of line 204, Figure 7), Bremkamp and Harr (1988) estimated an 

elevation of about -11,000 to -12,000 ft for the top of the Leadville formation in this area (see contours on Figure 22). This interpretation corresponds to a depth of approximately 16,000 to 17,000 

ft, relative to the local ground surface within the Dolores river valley. Bremkamp and Harr (1988) 

show an anomalously thin layer of salt in the upthrown fault block on this side of Paradox Valley 

(section B-B’, Figure 20), but given the very limited data available at the time, it is doubtful that 

this thickness is well-constrained. No deep well data are available in this area to constrain the 

thickness of the salt, the thickness of the Leadville formation, or the reservoir characteristics 

(porosity and fracturing) of the Leadville or Precambrian formations. The acquisition of additional deep seismic reflection data, either through purchase or field acquisition, is highly recommended prior to proposing an injection well in this area. Also, a well is this area would be located 

less than 5 km away from an active cluster of northern valley seismicity (Figure 25). A better 

geologic/hydrologic model between the areas of northern valley seismicity and PVU Injection 

Well #1 and between the northern valley seismicity and any proposed well sites in this vicinity 

would be desirable.

6.0 References

Baars, D. L., and G. M. Stevenson, 1981, Tectonic Evolution of Western Colorado and Eastern 

Utah, in Western Slope Colorado, New Mexico Geological Society Thirty-Second Field 

Conference Guidebook, p. 105 - 112.

Bremkamp, W., and C.L. Harr, 1988, Area of least resistance to fluid movement and pressure rise, 

Paradox Valley Unit, Salt Brine Injection Project, Bedrock, Colorado, unpublished report to the 

U.S. Bureau of Reclamation, 39 pp.

Bremkamp, W., Harr, C.L. and O.E. Prather, 1984, Geophysical interpretation- Seismic data, Paradox Valley Unit, Montrose County, Colorado, unpublished report 3-C3-40-0146B to the U.S. 

Bureau of Reclamation, 14 pp.

Bundy, J., 2003, Review of Plans and Recommendations for Installation of Second Paradox Valley Brine Injection Well, Subsurface Project 60D5433, Subsurface Technology, Inc., unpublished 

letter to Andy Nicholas, Bureau of Reclamation, 7 pp. 
60

Campbell, J. A., 1981, Summary of Paleozoic stratigraphy and history of western Colorado and 

eastern Utah, in Western Slope Colorado, New Mexico Geological Society Thirty-Second Field 

Conference Guidebook, p. 81 - 87.

Cater, F. W., 1970, Geology of the Salt Anticline Region in Southwestern Colorado, Geological 

Survey Professional Paper 637, 80 pp.

Davis, K. E., 1985, Design of Well and Surface Facilities, Paradox Valley Unit, Phase I Task 

1.(b), Engineering Review of Geophysical Interpretation and Wellsite Selection, Ken E. Davis 

Associates project no. 10-442, unpublished report 4-CA-40-01660 to the Bureau of Reclamation, 

55 pp.

Doelling, H.H., Oviatt, C.G., and P.W. Huntoon, 1988, Salt deformation in the Paradox Region: 

Utah Geological and Mineral Survey, Utah Department of Natural Resources, Bulletin 122, 57 pp.

EPA, 9997, U.S. Environmental Protection Agency, Fact Sheet, Application for Reauthorization 

of an Underground Injection Control Permit for a Class V Well, EPA I.D. No. CO5108-00647, 

MArch 11, 1997, 46 pp.

Flak, L. H., and G. L. Ables, 1988, Scope Well Design and Preliminary Cost Estimate, Paradox 

Valley Injection Test #2, O’Brien-Goins-Simpson & Associates, unpublished report to the Bureau 

of Reclamation, 12 pp.

Friedman, J. D., Case, J. E., and S. L. Simpson, 1994, Tectonic Trends of the Northern Part of the 

Paradox Basin, Southeastern Utah and Southwestern Colorado, as Derived from Landsat Multispectral Scanner Imaging and Geophysical and Geologic Mapping, in Evolution of Sedimentary 

Basins - Paradox Basin, U. S. Geological Survey Bulletin 2000-C, p. C1 - C30. 

Goins, W. C., Jr., and L. H. Flak, 1983, Concerns Involving Paradox Valley Deep Disposal Well 

Project, O’Brien-Goins-Simpson & Associates, Inc., unpublished report to the Bureau of Reclamation, 10 pp.

Grout, M. A., and E. R. Verbeek, 1998, Tectonic and Paleostress Significance of the Regional 

Joint Network of the Central Paradox Basin, Utah and Colorado, in Laccolith Complexes of 

Southeastern Utah, Time of Emplacement and Tectonic Setting - Workshop Proceedings, U. S. 

Geological Survey Bulletin, 2158 p. 151-166.

Gutierrez, F., 2004, Origin of the salt valleys in the Canyonlands section of the Colorado Plateau, 

Evaporite-dissolution collapse versus tectonic subsidence, Geomorphology, vol. 57, p.423-435.

Harr, C. L., 1988, Final Geological Well Report, Bureau of Reclamation Injection Test Well No. 

1, Paradox Valley, Montrose County, Colorado.
61

Harr, C. L., 1989, Proposed Location for Injection Well No. 2, Paradox Valley Unit Salt Brine 

Injection Project, Bedrock, Colorado, unpublished report 4-CA-40-01660 to the Bureau of Reclamation, 27 pp.

Hite, R. J., 1975, An Unusual Northeast-Trending Fracture Zone and Its Relations to Basement 

Wrench Faulting in Northern Paradox Basin, Utah and Colorado, in Four Corners Geological 

Society Guidebook, 8th Field Conference, Canyonlands, p. 217 - 223

Huntoon, P. W., 1988, Late Cenozoic gravity tectonic deformation related to the Paradox salts in 

the canyonlands area of Utah, Utah Geological and Mineral Survey Bulletin 122, p. 81 - 93.

Katz, L. and R. Carroll, 1984, Geophysical Interpretation of Seismic Data; Paradox Valley Unit, 

Utah Geophysical, Inc., unpublished report 3-CS-40-0146A to the Bureau of Reclamation, 21 pp.

Kharaka, Y. K., Ambats, G., Thordsen, J. J., and R. A. Davis, 1997, Deep well injection of brine 

from Paradox Valley, Colorado: Potential major precipitation problems remediated by nanofiltration, Water Resour. Res., v33(5), p. 1013-1020.

Klementich, E. R., 1983, Part I Analysis of Technical Specifications for Deep Well Drilling, Completion, and Testing, Paradox Valley Unit, Colorado River Basin Salinity Control Project, Oil 

Technology Services, Inc., unpublished report 3-PG-40-10000 to the Bureau of Reclamation, 9 

pp.

McClure, K., Morgan, C.D., Chidsey, T.C. Jr., Eby, D.E., and P. Scott, 2003, Utah and Colorado: 

Targets for increased oil production and reserves using horizontal drilling techniques: Utah Geologic Survey Contract No. DE-2600BC15128, Deliverable 1.1.2 Regional Paradox Formation 

Cross Sections, Blanding sub-basin, Utah and Colorado, 29 pp.

Nuccio, V.F., and S.M. Condon, 1996, Burial and thermal history of the Paradox Basin, Utah and 

Colorado, and petroleum potential of the Middle Pennsylvanian Paradox Basin: USGS Bulletin, 

report B, 2000-0, p. 01-041. 

Turner, F. P., 1975, Feasibility Study of Brine Disposal by Deep Well Injection, the Paradox Valley Unit, Colorado, River Basin Salinity Control Project, Bureau of Reclamation internal report, 

48 pp.

USBR, 1978, U.S. Bureau of Reclamation, Paradox Valley Unit, Definite Plan Report, Colorado 

River Basin Salinity Control Project, 91 pp.

USBR, 1997, U.S. Bureau of Reclamation, Paradox Valley Unit, Supplemental Definite Plan 

Report/Environmental Assessment, 37 pp.
62

Williams, P. L., 1964, Geology, structure, and uranium deposits of the Moab Quadrangle, Colorado and Utah; Miscellaneous Investigations Series Map I 360, U. S. Geological Survey, Dept. of 

the Interior.

Williams Brothers Engineering Company, 1982, Final Report: Deep Well Injection of Brine, Paradox Valley Unit, unpublished report no. 4611 to the Bureau of Reclamation, 136 pp.
Appendix A 

Paradox Valley Geologic Well Data

The following tables present a comparison of geologic data for nine wells located in and near Paradox Valley, Colorado. Data from these wells were used for the geophysical interpretations discussed in the main body of this report (section 3.3.1). The data included in the tables were taken 

from three sources: the online database maintained by the Colorado Oil and Gas Conservation 

Commission (COGIS: Colorado Oil and Gas Information System at http://cogcc.state.co.us/

cogis), Bremkamp et al. (1984), and Katz and Carroll (1984). 

Table A-1 contains a comparison of geologic elevation well data from the three sources. Elevations are given for the top of the Cutler formation, top of the Paradox formation salt member, and 

top of the Leadville formation. Table A-2 contains a similar comparison for geologic unit thickness values. This table contains data for the thickness from the top of the Paradox salt member to 

the top of the Leadville formation and the thickness of the Leadville formation. Not all wells penetrated all formations, and not all sources provided data for each item in the tables. However, for 

most of the items, a comparison can be made between at least two of the sources. Since the online 

Colorado Oil and Gas Commission database (COGIS) is considered to be the most reliable source 

of data, the differences between the data from Bremkamp et al. (1984) and Katz and Carroll 

(1984) and the online database are listed when possible.

The values printed in bold face - two values for the top of the Paradox salt member in Table A-1 

and one value for the salt thickness in Table A-2 - indicate data that appear to be grossly incorrect. 

These data are discussed in section 3.3.1. All of the grossly incorrect values came from Katz and 

Carroll (1984).

 
Table A-1: Elevations for the top of the Cutler formation, Paradox formation salt member, and Leadville 

formation in wells drilled in and near Paradox Valley, Colorado.
Well Name Source

Thickness (ft) Difference from COGIS Database Thickness (ft) Difference from COGIS Database

CO Oil &Gas Commission (COGIS) not available > 274

Bremkamp et al. (1984) 14362 > 267 -7

Katz and Carroll (1984) 11231 not used

CO Oil &Gas Commission (COGIS) 3052 top salt to top Elbert

Bremkamp et al. (1984) 3056 4

Katz and Carroll (1984) 3026 -26

CO Oil &Gas Commission (COGIS) 979 >174

Bremkamp et al. (1984) not used >174 0

Katz and Carroll (1984) not used not used

CO Oil &Gas Commission (COGIS)

Bremkamp et al. (1984) 374 290

Katz and Carroll (1984) 420 279

CO Oil &Gas Commission (COGIS) 864 342

Bremkamp et al. (1984) ~800 -64 340 -2

Katz and Carroll (1984) 864 0 342 0

Otho Ayers #1-0-30 

(Union Oil)

Scorup Somerville 

Wilcox #1

(Conoco #1)

geologic well log not available

Leadville eroded Wray Mesa Unit #2 (Shell #2)

Leadville Thickness Top-of-Salt to Top-of-Leadville Thickness 

Coyote Wash Unit #1 

(Miami Oil)

Wray Mesa Unit #3 

(Pure Oil)

Table A-2: Thicknesses for the top-of-salt to top-of-Leadville interval and Leadville formation, in wells drilled in and near Paradox Valley, Colorado.