Technical Studies and Evaluations 

for the Second Injection Well 

Alternative at the Paradox Valley Unit

Meeting, July 25-27, 2017

Denver Federal Center

Denver, Colorado 

U.S. Department of the Interior

Bureau of Reclamation

Paradox Valley Unit

Western Colorado Area Office

Grand Junction, CO September 2017

Report from the Consultant Review Board 

EMPSi

3775 Iris Avenue

Boulder, Colorado 80301
Mission Statements

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.

The Department of the Interior protects and manages the Nation's 

natural resources and cultural heritage; provides scientific and other 

information about those resources; and honors its trust 

responsibilities or special commitments to American Indians, 

Alaska Natives, and affiliated island communities.
September 2017 USBR Paradox Valley Unit, Consultant Review Board i

Report on the Second Injection Well Alternative

TABLE OF CONTENTS

Chapter Page

EXECUTIVE SUMMARY.............................................................................................................ES-1

1. RECOMMENDATIONS ..................................................................................................... 1-1

1.1 Recommendation #1 – Ranking of Candidate Well Sites...................................................1-1

1.2 Recommendation #2 – Passive Seismic Monitoring .............................................................1-3

1.3 Recommendation #3 – 3D Seismic Study...............................................................................1-6

1.4 Recommendation #4 – Exploratory Wells.............................................................................1-7

1.4.1 Well Location .................................................................................................................1-7

1.4.2 Drilling Issues – Topography.......................................................................................1-9

1.4.3 Drilling Issues – Hole Size ...........................................................................................1-9

1.4.4 Measurements in an Exploratory Well...................................................................1-10

1.4.5 Measurements while Drilling (MWD).....................................................................1-10

1.4.6 Cuttings and Core.......................................................................................................1-11

1.4.7 Stress Data ....................................................................................................................1-11

1.4.8 Permeability Data ........................................................................................................1-12

1.4.9 Wireline Geophysical Data .......................................................................................1-12

1.4.10 Vertical Seismic Profiling (VSP).................................................................................1-13

1.4.11 An Exploratory Well as a Monitoring Well ..........................................................1-14

1.5 Recommendation #5 – Engineering Design Study for Drilling at Proposed 

Well Sites......................................................................................................................................1-14

1.6 Recommendation #6 – Corrosion Study..............................................................................1-15

1.7 Recommendation #7 – Salt Rheology Study ........................................................................1-15

1.8 Recommendation #8 – Emerging Technologies for Monitoring Post-injection 

Ground Response.......................................................................................................................1-16

1.8.1 Distributed Acoustic Sensing....................................................................................1-17

1.8.2 GPS, InSAR, and Borehole Tiltmeters....................................................................1-17

1.9 Recommendation #9 – Leadville Core Petrophysics.........................................................1-18

1.10 Recommendation #10 – Modeling Study to Evaluate Minimum Distance 

from Fault .....................................................................................................................................1-18

1.11 Recommendation #11 – Model Permeability (or Mobility) and Diffusivity 

near PVU #1 using Early and Recent Injection Pressure History ...................................1-19

1.12 Recommendation #12 – Modeling to Assess Slip along Faults........................................1-21

1.13 Recommendation #13 – Implementing a Modern Approach to Visualization 

and Integration ............................................................................................................................1-22

2. RECLAMATION QUESTIONS TO THE CONSULTANT REVIEW BOARD............................. 2-1

2.1 Question 1. Have appropriate technical criteria for identifying potential 

injection well sites and reservoirs been considered?...........................................................2-1

2.2 Question 2. Are existing geologic and geophysical studies adequate to 

characterize the subsurface structure in the Paradox Valley area at a 

regional scale, for the purpose of identifying potential well sites?....................................2-3

2.3 Question 3. Have potential reservoir formations been characterized 

adequately, including their estimated depth and thickness, spatial extent, 

permeability, porosity, degree of hydrologic isolation from the current 

injection well, and the presence of a suitable confining layer?...........................................2-4

2.3.1 Degree of Isolation from the Current Injection Well ..........................................2-5
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ii USBR Paradox Valley Unit, Consultant Review Board September 2017

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2.3.2 Estimated Depth and Thickness of the Reservoir.................................................2-5

2.3.3 Spatial Extent of the Reservoir...................................................................................2-5

2.3.4 Permeability and Porosity ............................................................................................2-6

2.3.5 Presence of a Suitable Confining Layer....................................................................2-6

2.4 Question 4. Have the sites been characterized adequately, including 

evaluation of probable flow paths and flow barriers, pressure-flow response, 

and the potential for induced seismicity?................................................................................2-6

2.5 Question 5. Has the feasibility of drilling, logging, and completing exploratory 

and injection wells at the proposed sites been evaluated adequately, including 

reasonable consideration of geologic factors, available technologies, risks, 

costs, and benefits?.......................................................................................................................2-7

2.6 Question 6. If existing studies are found to be inadequate, what additional 

studies should be considered, and what issues are they likely to resolve?.....................2-8

2.7 Question 7. Are there other issues, opportunities, or concerns the CRB 

believes are appropriate to raise concerning the evaluation of potential 

second injection well sites for the EIS?..................................................................................2-10

3. REFERENCES.................................................................................................................. 3-1

FIGURES Page

1 Possible New Well Locations...................................................................................................................1-2

2 Seismic Stations and Seismicity.................................................................................................................1-5

3 Regional Faulting and Seismicity. ..............................................................................................................1-9

4 Radial Step-out VSP Characteristics......................................................................................................1-13

5 Pressure vs Time at PVU #1...................................................................................................................1-20

APPENDICES

A Consultant Review Board Members

B List of Material Provided by Bureau of Reclamation

C List of Presentations Made at the CRB Meeting in Denver, July 25-27, 2017
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ACRONYMS AND ABBREVIATIONS Full Phrase

BIF Brine Injection Facility

CRA corrosion resistant alloys

CRB Consultant Review Board

EIS environmental impact statement

km kilometer

m meter

MWD measurements while drilling

PVU Paradox Valley Unit

Reclamation United States Department of the Interior, Bureau of Reclamation

VSP vertical seismic profiling
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EXECUTIVE SUMMARY

The United States Department of the Interior, Bureau of Reclamation 

(Reclamation) convened a formal, independent, external Consultant Review 

Board (CRB) to consider drilling a second injection well for brine disposal in 

Paradox Valley. A second injection well is one of several alternative brine 

disposal methods being considered if Paradox Valley Unit (PVU) well #1 (PVU 

#1) ceases to function, or if a substantial reduction in the current injection rate 

is required to reduce wellhead pressures or induced seismicity to acceptable 

levels. The identified alternative brine disposal methods will be compared in an 

environmental impact statement (EIS), which will be based on numerous 

technical studies and evaluations, including this report. In this report, drilling a 

second injection well is called the Second Injection Well Alternative, and its 

location (currently unspecified) is called PVU #2. 

The CRB was charged with providing an independent peer review of the 

scientific and technical studies that form the basis for the Second Injection Well 

Alternative. The CRB members are listed in Appendix A and a list of materials 

provided by Reclamation is in Appendix B; Appendix C is a list of the 

presentations made at the Denver meeting of the CRB on July 25-27, 2017.

Reclamation also provided a list of seven questions to be addressed by the CRB 

in this report.

The CRB commends Reclamation for their efforts to monitor and document the 

performance and effects of the PVU #1 well, and its relationship to regional 

geology. Particularly noteworthy is the number of peer-reviewed publications by 

Reclamation scientists that describe this scientifically valuable case history of 

induced seismicity. The breadth, thoroughness, and persistence over time of 

these efforts may well be superior to those at any other injection facility, 

worldwide. These efforts, and the scientific studies of contractors providing 

analysis to evaluate the Second Injection Well Alternative, are thorough and 

state-of-the-art.
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After evaluating the available information, all members of the CRB agree that 

the Second Injection Well Alternative remains a viable alternative for brine 

disposal. The CRB also made 13 recommendations (many clearly anticipated by 

Reclamation and its contractors) concerning additional investigations that could 

provide critical information informing decisions concerning the siting and design 

of a second injection well, and improve the likelihood that the well will function 

successfully for many decades.
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CHAPTER 1

RECOMMENDATIONS

1.1 RECOMMENDATION #1 – RANKING OF CANDIDATE WELL SITES 

The proposed well sites along the Dolores River Valley and on

Monogram Mesa are both appropriate for a second injection well

(PVU #2). If additional analysis confirms a Dolores River Valley site is 

viable, it is more desirable because of infrastructure and access 

considerations.

Based on available information, there are two possibly viable locations where 

well sites should be evaluated further as candidate sites for PVU #2. These are

(see Figure 1, Possible New Well Locations):

A. Sites in the Dolores River Valley 1 to 2 kilometers (km) south of 

the current PVU #1 site. These include so-called Brine Injection 

Facility (BIF) surface sites as described in the deep well feasibility 

study (Petrotek Engineering Corporation 2017). Although not 

investigated as a viable candidate in the feasibility study, the 

abandoned Chicago wellsite adjacent to the Dolores River should 

also be considered as a possible surface location for the future 

injection well. To avoid confusion, in this report when we refer to 

the “Dolores River Valley sites” we include both the BIF sites and 

the site near the abandoned Chicago well.

B. Sites on the Monogram Mesa, 25 to 30 km southeast of the current 

PVU #1 site. The deep-well feasibility study assessed two sites here, 

Monogram Mesa 1 and Monogram Mesa 2; however, subsequently 

because of environmental concerns Monogram Mesa 2 was 

removed from consideration as a viable site .

At both sites drilling can reach targets in the Leadville Formation, which 

provides an attractive reservoir for brine disposal. The target areas appear to be 
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Figure 1. Possible New Well Locations. 

Ellipses A and B indicate the two proposed subsurface target location areas for exploratory wells near 

possibly viable locations for the new injection well PVU #2. Location A is south of PVU #1 along the 

Dolores River Valley and location B is on Monogram Mesa. The blue ellipse (labeled EW, for 

“exploratory well”) indicates a possible location for either an exploratory well or a monitoring well.

overlain with salt and lie within the same “new fault block” to the southwest of 

a through-going major boundary fault that seems to be a sealing fault, apparently 

preventing pressure and fluid diffusion from the reservoir associated with PVU 

#1. The Dolores River Valley surface sites will all require directional drilling to 

cross this boundary fault to access the new fault block; for the Monogram Mesa 

sites, a near-vertical well will penetrate the new fault block. 

Other proposed sites are unacceptable based primarily on surface site 

considerations or inadequate reservoir compartment size (e.g., Pinon Ridge).

Whether the Dolores River Valley or Monogram Mesa candidate sites for PVU 

#2 are ultimately acceptable depends on evaluating the properties (thickness, 

porosity, permeability, presence of smaller faults, and state of stress) of the 

Leadville Formation, as it is highly variable both laterally and stratigraphically.

For the Dolores River Valley sites to be acceptable, it must be verified that the 

injection targets for PVU #2 and PVU #1 lie in separate reservoir 

compartments, i.e., that northern boundary fault of the new fault block is a 

sealing fault.
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The Dolores River Valley sites are considered higher risk because their long 

offsets require drilling through the boundary fault and at an angle. These sites 

are also geographically close to clusters of earthquakes associated with the PVU 

#1 well. However, because of their proximity to the PVU #1 well site, the 

surface/logistical advantages of these sites are substantial. These advantages may 

mitigate the higher subsurface risks, which can be evaluated pending some 

additional modeling work to estimate pressurization near the boundary fault

(see Recommendations #10 and #12), and by investigations assessing the impact 

of drilling horizontally farther away from the fault to reach a more desirable 

injection location (3D seismic survey; drilling exploratory wells; modeling salt

rheology; see Recommendations #3, #4, and #7).

The Monogram Mesa 1 site is ranked highest with respect to drilling

considerations (well-bore can be near-vertical) and subsurface characterization 

(site is far from the boundary fault, and far from PVU #1 and the associated 

pressurization of the Leadville Formation). Also, Monogram Mesa 1 is situated 

near the middle of the reservoir compartment, in a location that has been 

virtually aseismic up to the present. However, Monogram Mesa 1 has less 

desirable surface characteristics; surface access is difficult and developing the 

site requires installing a long pressurized pipeline from the brine production 

wells in Paradox Valley. It is also possible that the Monogram Mesa 1 site is 

close to a salt weld; this can be evaluated by a 3D seismic survey and by drilling 

an exploratory well (see Recommendations #3 and #4).

1.2 RECOMMENDATION #2 – PASSIVE SEISMIC MONITORING

If the second injection well is on the Monogram Mesa, seismicity near 

the well site must be monitored beginning at least 2 years before 

injection begins.

Monitoring of earthquake activity prior to injection is essential, as it provides a 

basis for evaluating how/whether injection affects the locations, magnitudes, and 

rate of earthquakes occurring near the well. Stations near to and surrounding

the well site make it possible to identify small-magnitude earthquakes and to 

determine reliable focal depths. 

Seismologists who operate regional networks of seismograph stations and 

produce earthquake catalogs have learned several “rules of thumb” concerning 

what is required to determine accurate hypocentral locations from travel time 

picks:

• Obtaining an accurate location requires incorporating accurate time 

picks for both P and S arrivals. Locations determined with P picks 

only typically have smaller formal errors but much larger systematic 

errors than locations incorporating both P and S times. 
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• Picks for S tend to be inaccurate when determined using verticalcomponent records; this is why installing networks of threecomponent stations is essential.

• Obtaining an accurate epicenter (map location) requires stations 

that “surround” the earthquake, i.e., the earthquake lies within the 

polygonal footprint of the stations providing time picks. A statistic 

that measures this is “azimuthal gap angle,” i.e., the largest angle 

separating two stations providing picks for the event, as viewed 

from the perspective at the epicenter. Typically, epicentral locations 

are considered unreliable if gap angle exceeds 180° (the epicenter

lies outside the footprint of the network), somewhat reliable if the 

gap angle is 120° or less, and very reliable if the gap is 90° or less.

• Obtaining a highly accurate focal depth requires both P and S picks 

from a station situated within a distance approximately 

corresponding to the focal depth. If the nearest station reporting P 

and S is greater than about twice the focal depth, depth 

determinations are often inaccurate. 

• Systematic errors in location are reduced if a very accurate velocity 

model is available for the region where the network detects 

earthquakes, especially within portions of the region where 

azimuthal gaps and station-epicentral distances are too large—this is 

why network operators are always striving to obtain better 

information about P and S velocities. This is exacerbated in 

situations where velocity structure is inhomogeneous; even if the 

structure is well defined and even when sophisticated location

algorithms are used, inhomogeneity greatly increases systematic 

location errors.

Nevertheless, experience shows that for earthquakes with azimuthal gaps less 

than 90° and with nearest stations reporting P and S having event-station 

distances less than the focal depth, locations are highly accurate, even when 

determined using relatively simple location algorithms that utilize a 1D, oftensomewhat-inaccurate velocity structure.

When the PVU #2 site is chosen, we presume it is desirable to locate nearby 

earthquakes with an accuracy comparable to that provided by the current PVU 

seismic network (Figure 2, Seismic Stations and Seismicity). If the second 

injection site is close to the PVU #1 well (within a few km; e.g., one of the 

Dolores River Valley sites), it may be unnecessary to install additional seismic 

stations prior to completing the new well (see Figure 2). However, if the 

second injection site is more than five km from the PVU #1 wellsite (e.g., on 

Monogram Mesa), installing at least three or more new seismic stations is 

essential, and even more are highly desirable.
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Figure 2. Seismic Stations and Seismicity.

Seismic monitoring stations (triangles) and earthquakes located since injection began at PVU #1 up 

through December 2016. Dashed circles mark distances of 5 km, 10 km, 15 km, and 20 km from PVU 

#1. If PVU #2 is at any of the Dolores River Valley sites (near “A” in Figure 1), this network of stations

is adequate to monitor seismicity levels prior to when injection begins. If PVU #2 is on the Monogram 

Mesa (“B” in Figure 1), new stations near the site should be installed at least 2 years before injection 

begins. (Figure reproduced from Block 2017).
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1.3 RECOMMENDATION #3 – 3D SEISMIC STUDY

A regional seismic survey covering viable candidate well sites should 

be completed and interpreted prior to making the tentative site 

choice; then, a more detailed 3D seismic survey should be undertaken 

at the site chosen.

Since the southern new fault block is large and there are two possibly viable

sites within it (A and B in Figure 1), a “regional-scale” seismic survey should be 

performed even before drilling an exploratory well (see Recommendation #4).

This regional-scale survey would need to cover 60 square miles or more to 

encompass both possibly viable sites. Such a 3D seismic survey would be costly, 

but could be designed with a sparse grid of shots and receivers appropriate for 

elucidating structural detail, although lacking the resolution necessary for

detailed reservoir characterization.

These surveys are important because:

• They can assess whether or not the bounding faults have 500 feet 

(ft) or more of offset and are sealing;

• They can determine if the Leadville Formation and salt are of 

adequate thickness to serve as reservoir/seal; 

• They may identify previously unknown sealing faults within the 

interior of the new fault block, leading to compartmentalization that

might reduce well life for PVU #2; and

• Potentially they can identify smaller faults that may be critically 

stressed.

A logical path is to:

• Perform this regional-scale survey; then

• Select a location for an exploratory well; and finally

• Follow up by conducting a high-resolution 3D, three-component 

(3C) survey covering at least 15 square miles, suitable for detailed 

reservoir characterization. This high-resolution survey would 

require dense receiver coverage with sources wherever they can be 

placed within the grid.

There may be an executive decision to conduct a single seismic survey, either 

for reasons of cost, or because the site for PVU #2 has been chosen before any

seismic survey begins. In this case seismic modeling can facilitate the survey 

design. We advocate conducting both surveys in a sequential manner but realize 

it may prove too costly to mobilize and demobilize a high-channel-count crew 

that can operate in the challenging terrain surrounding Paradox Valley.
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1.4 RECOMMENDATION #4 – EXPLORATORY WELLS

An exploratory well at the candidate well site should be completed 

and interpreted prior to making the final site choice for the new well. 

Reclamation should also consider installing one or more monitoring 

wells at appropriate distances (e.g., 2 km and 5 km).

Drilling a single exploratory well or a set of low-cost exploratory wells will 

reduce siting and drilling risks for PVU #2. Exploratory wells can be “slim-hole” 

wells with reduced casing requirements, designed to have as small a diameter as

is feasible, given coring and tool needs during drilling and post-drilling testing

requirements. Exploratory wells cannot be converted to injection wells, but 

they could be equipped as long-term monitoring wells.

1.4.1 Well Location

As explained above, our current knowledge suggests that both the Dolores 

River Valley and Monogram Mesa sites are acceptable locations for a future

injection well, but each has somewhat different characteristics. To reduce risk, 

further technical studies are needed to give a relative ranking of the siting 

options (see Recommendations #3, #5, #7, and #9). The exploratory well 

drilling should only begin after the additional modeling studies of the pressurestress-time response of the new fault block to injection (see Recommendations

#10, #11, and #12). Planning for the execution of the exploratory well can begin 

sooner so that action can be initiated quickly after the additional studies are 

complete.

The number and location of exploratory wells depend on the results of the 

technical studies and the realistic possibility that, because of various economic, 

environmental, and legal issues, siting locations for PVU #2 are further 

constrained. This leads to the following options: 

• If one or the other of these general sites (A and B in Figure 1) is

strongly favored as the site for PVU #2, a first exploratory well 

should be located near this favored site as a primary location.

– In this case, we also recommend considering drilling a 

second exploratory well designed explicitly to become a 

monitoring well. The distance of this monitoring well from

the site chosen for PVU #2 should be determined based on 

consideration of current knowledge concerning seismicity 

and subsurface pressure, and additional diffusional flow 

studies (see Recommendations #10 and #11).

• If both sites A and B remain as options for PVU #2 after the 

technical studies are complete, then we recommend drilling 

exploratory wells at both sites.
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– In this case, if the first exploratory well indicates 

exceptionally favorable conditions, it may not be necessary 

to drill a second exploratory well.

– If the first exploratory well indicates marginal suitability as a 

long-term injection site, the second exploratory well should 

be drilled near to the site of the second option.

– In general, the CRB favors drilling the first well in the 

Dolores River Valley south of the existing PVU #1 site.

• Although the two options above are favored, there is an alternative 

option. The alternative is to drill the first exploratory well in a 

region intermediate between the two sites (e.g., at location EW in 

Figure 1), with the plan to convert this exploratory well to a 

monitoring well. Area EW was chosen because it lies between the 

proposed bottom-well target locations for the Dolores River Valley

sites (A in Figure 1) and the Monogram Mesa sites (B in Figure 1).

Other exploratory well locations closer to either A or B would be 

acceptable.

This exploratory well should penetrate to the base of the sediments. The 

proposed PVU #2 injection targets in the Leadville Formation are all situated

within the large fault-bounded “new fault block” that has these characteristics

(see Figure 3, Regional Faulting and Seismicity.):

• It appears not to have any internal faults with a significant vertical 

offset that could lead to a sealing condition (i.e., all have less than 

the 500 ft offset criterion mentioned by the geological experts; see 

Detournay and Dzik 2017). Internal compartmentalization of the 

new fault block could reduce the well life for PVU #2.

• The strata are generally flat-lying, having dips close to zero.

• The block appears to be separated by at least one sealing fault and 

one partially sealing fault from the current PVU #1 injection location 

in the Leadville Formation, and from the reservoir blocks that take

the PVU #1 injection volumes.

• Within this new fault block there has been no detected induced 

seismicity associated with the current injection at PVU #1. This 

provides support for the assertion that the fault (or faults) to the 

northeast of areas A and B are truly sealing, or indicates that 

critically stressed faults are not present in this area. 

Within this new fault block, if the petrophysical conditions (porosity and 

permeability) of the Leadville Formation are similar to those near the PVU #1

well, the new injection well PVU #2 should be even more effective than PVU #1 

because the new location provides an adequate volume to accommodate longterm injection and dissipate pressure effectively.
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The New Fault-Delineated Block Preferred for PVU #2 Injection

Figure 3. Regional Faulting and Seismicity. 

A geological interpretation of the nature of the faults in the Paradox Valley region combined with the 

seismic hypocenters (black circles). Ellipses A and B indicate the two proposed general subsurface target 

areas for PVU #2: south of PVU #1 along the Dolores River Valley and on the Monogram Mesa,

respectively. The large blue-bordered ellipse indicates that the area (hence volume) in the fault block 

available for unimpeded fluid flow is very much larger than the area accessed by the current PVU #1 well 

(indicated by + symbol). 

1.4.2 Drilling Issues – Topography

The topography may be challenging in the proposed exploratory well area, but 

this will be a slim hole well, not the final injection well. Thus it can be drilled 

from a pad with a substantially smaller footprint than a full-scale injection well, 

and involve a somewhat smaller drilling rig. 

1.4.3 Drilling Issues – Hole Size

A well intended only for exploration purposes can be drilled rapidly because it 

requires a relatively small-diameter hole. In general, the rate of advance is 

linearly proportional to the area of the bottom of a hole, so faster penetration 

is achieved for slimmer holes. In comparison with larger-diameter holes,

smaller-diameter holes have lower mud volume requirements, easier hole 

cleaning, less time for borehole instability issues to develop, and better intrinsic 

stability. The risks affecting holes for an exploratory well are substantially less 
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than those affecting a larger-diameter injection-well hole. In addition, it should 

be possible to eliminate one of the casing strings, reducing hardware and time 

costs.

Once decisions are made concerning the desired testing program, the diameter 

of the exploratory well is fixed by the minimum bottom-hole diameter required 

to perform the tests chosen. Some of these tests must be performed with the 

drill pipe, such as a double packer drill-stem flow test to determine flow 

properties (particularly for the intervals to be perforated) and MiniFracTM stress 

measurements; others are performed on wireline tools.

1.4.4 Measurements in an Exploratory Well

The three major methods of measuring data in a well are:

• Drill-stem permeability tests or MiniFracTM stress measurement 

tests performed at the bottom of the drill string;

• Geophysical logging tool measurements that are performed using 

wireline methods; and

• Vertical seismic profiling (VSP) or similar larger-scale seismic 

measurements that require that the borehole be instrumented with 

a set of geophones. 

There are hybrid methods, such as small-scale stress or permeability testing,

that use geophysical logging tools lowered with a wireline unit, but issues remain 

as to the representativeness of these methods. Conducting step-out VSP 

surveys from the exploratory well may require installation of a string of 

geophones on a wireline in the wellbore for a period of a week or two. During 

the actual drilling of the exploratory well, any method requiring withdrawing the 

bit and lowering a tool is time consuming and tends to slightly increase risk to 

the wellbore, whereas wireline logging is considered safer and is inherently 

more rapid.

1.4.5 Measurements while Drilling (MWD)

Use of MWD methods reduces the need for wireline logging when the well is 

completed, because collecting adequate geophysical data from the upper part of 

the sequence (above the Paradox Salt) provides stratigraphic control. Also, for

the design and operation of PVU #2 the detailed petrophysical properties of the 

overlying strata are not relevant. MWD generally are viewed as being 

geophysical in nature, but here we include broader data needs, such as drilling 

parameters, drilling fluid, and circulation data, and other drilling data (e.g., kicks

and mud loss zones) that will help reduce risk for future PVU #2 well siting and 

installation. 

For example, in addition to geophysical logging while drilling, it is feasible to use 

the penetration data (WOB - weight on bit, RPM – rotation speed, ROP – rate 

of penetration, etc.) to establish first-order correlations to rock strength and 
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other properties. To be useful, these data will need to be reviewed for quality 

control (precision and accuracy). Although penetration information is not 

generally included on the list of parameters of primary interest concerning the 

injectivity of the Leadville Formation, these correlations and relationships 

generally help to assess overall geomechanical conditions. All the information 

from the exploratory well should be reviewed to provide a firm basis for the 

design of the new injection well, and this will also substantially reduce risks for 

the drilling of the PVU #2 well. 

1.4.6 Cuttings and Core

Continuous collection of cuttings samples is standard practice, but coring does 

increase costs and risks for an exploration well. For the proposed wells, the 

interval where core is of highest priority is in the permeable zone in the 

Leadville Formation, as it appears to be the dominant zone that accepts injected 

brine. If a core interval is collected, it should be analyzed for standard 

petrophysical properties (fractures, porosity, permeability, etc.). Cuttings should

also be examined for lithology and texture, and it is possible to do fine-scale 

matrix fabric analysis on cuttings to quantify matrix porosity.

The key objective for these studies on cuttings and cores is to establish an 

estimate of matrix porosity and permeability over the entire vertical extent of 

the target injection zones. Given the small sampling volume and the vertical 

nature of an exploratory well, it is unlikely that the nature and distribution of 

natural fractures can be delineated, especially as the available data indicate that 

porosity is highly variable in the Leadville Formation. This is an important 

statement because fluid flow in the Leadville Formation appears to be fracturedominated, but it is the matrix porosity that governs the fluid storativity of the 

strata in the new fault block. 

Collection of a short core in the salt interval also may prove to be useful. This 

could provide essential information to constrain the proposed salt rheology 

modeling study (see Recommendation #7).

1.4.7 Stress Data

Stress measurements are needed at several depths below the base of the

Paradox Salt in any exploratory well. At this time, we assume that once the salt 

is penetrated (and perhaps cased), adequate time will be available for testing 

programs. A MiniFracTM tool on the drill string can be lowered into the hole to 

measure the value and orientation of the minimum principal stress (assumed to 

be horizontal). 

There are no reliable stress measurements currently available. Thus, collecting 

these data will provide important baseline information for all geomechanical 

modeling, define the fracture gradient explicitly, and provide information about 

which faults might be critically stressed.
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1.4.8 Permeability Data

The traditional method for obtaining realistic permeability data at an appropriate 

scale is to use a double-packer drill-stem test. These tests involve opening a 

packer-isolated interval of the formation and allowing flow into the drill string.

However, it is highly preferred to instead perform injection tests for the 

following reasons:

• Injecting additional fluid (increasing pressure) is more relevant than 

production to the goals of the PVU #2 well.

• Fracture flow sensitivity to pressure changes is high but poorly 

known, so to determine far-field properties there is merit in doing 

injection rather than depletion tests.

• Repeated and different injectivity tests can be performed without 

withdrawing the drill string.

• Injection tests at different relative pressures ΔP and for different 

times can be implemented to obtain data for different volumes. 

• The injection tests can be followed by a step-rate injection test to 

assess the fracture pressure.

Injection tests can be performed at a constant pumping rate or at constant 

pressure; in both approaches, the data can be interpreted to estimate

permeability. The longer the injection test is performed, the larger the volume 

evaluated.

There are wireline methods to estimate permeability, but all wireline methods 

access very small volumes of the formation because of the small contact area of 

the tool. If the dominant flow mechanism is fracture flow, the results will be of 

little use. Because we believe that flow along fractures dominates the 

permeability, we cannot recommend wireline formation-testing methods. 

1.4.9 Wireline Geophysical Data

In addition to the conventional suite of wireline devices (natural gamma, 

resistivity, neutron porosity, caliper, sonic log, etc.), we recommend including

the following geophysical wireline logs:

• FMI – Formation Micro-Imager log for fracture identification in the 

borehole wall;

• Multiple-receiver acoustic log with analysis of back-scattered waves 

to give some idea of the natural fracture frequency and orientations 

near the wellbore;

• Other geophysical logging tools deemed to provide useful 

information on the nature of the Leadville Formation injection 

interval.
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We recommend that Reclamation consult a geophysical logging expert to 

develop a more-informed list of desired logs to meet specific data needs. 

1.4.10 Vertical Seismic Profiling (VSP)

Once an exploration wellbore is available, it is feasible and relatively economical 

to carry out step-out VSP in several directions to more precisely delineate the 

seismic stratigraphy and acoustic properties of the region. The 3D VSP could be 

acquired in conjunction with the 3D, 3C seismic survey to optimize the 

processing and interpretation of both surveys. Collecting VSP data would 

certainly help enhance the resolution of the surface seismic data. The VSP would 

require 3C or 4-C receivers. Although the longer the array the better, it is 

especially important to stage the array near the bottom of the well and to 

straddle the Leadville Formation.

The VSP profile should be developed along a radius (or multiple radii) from the 

wellhead using seismic excitation sites at the surface, with a recording string of 

geophones within the borehole (Figure 4, Radial Step-out VSP

Characteristics.). The surface excitation sites (if vibroseis is utilized) are stepped 

out from the wellhead at pre-designed spacings in a radial direction to create an 

aperture within which acoustic properties and seismic stratigraphy are 

determined. The multiple pathways and shorter travel distances associated with 

VSP profiling, combined with its precise constraints on depth, can greatly 

improve the interpretation of existing seismic data and any 3D seismic surveys 

taken in the future (see Recommendation #3). Better velocity information will 

also improve accuracy of past and future earthquake locations. Hence, the VSP 

data provide another method to reduce risk.

Figure 4. Radial Step-out VSP Characteristics.

(EW = Exploration Well; see Figure 1). Figure redrawn from Campbell et al. (2005).
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1.4.11 An Exploratory Well as a Monitoring Well

The location of the exploratory well is an issue in the decision concerning 

whether to convert it to a monitoring well. If the well is too close to PVU #2

(for example, within 500 meters [m]), it will serve as a useful monitoring well 

for a few years, but then its usefulness will diminish over time when inferring 

what is happening at larger distances (e.g., 2 to 10 km) becomes important.

The CRB therefore recommends considering drilling an exploratory well 

explicitly designed as a monitoring well. This well would be placed at a distance 

of 3 to 6 km (depending on further analysis) to monitor changing conditions

within the far-field; this would provide an important window into the subsurface 

for a considerable length of time. This monitoring well can serve multiple 

purposes, and the following is a list of methods to consider:

• Precision tiltmeter string installation in the upper 2 km of the well 

to determine ground deformation as injection proceeds.

• Placement of geophones at several locations in the well to collect 

microseismic data, greatly constraining the hypocenter location 

uncertainty for induced earthquakes (see Recommendation #2).

• Defining and installing pressure measurement devices to measure 

the pressure development in the strata behind the casing at several 

locations, including the most permeable zone in the Leadville 

Formation. 

This list is not exhaustive; additional functions may be developed for a 

monitoring well based on ongoing and recommended Reclamation studies (see 

Recommendations #8 and #13). Design of this monitoring well can commence 

after completion of the first exploratory well near the preferred site.

1.5 RECOMMENDATION #5 – ENGINEERING DESIGN STUDY FOR DRILLING AT 

PROPOSED WELL SITES

A more thorough engineering design study would help make essential 

choices for drilling the proposed injection well PVU #2, and any 

exploratory or monitoring wells.

We recommend undertaking an engineering design study of specific surface and 

bottom hole locations for the two proposed sites for PVU #2 (A and B in 

Figure 1). This study would evaluate surface location issues as well as 

downhole trajectory concerns, i.e., how wellbore orientation relative to the 

tectonic stress field affects wellbore instability and directional drilling risk. Also, 

the study should consider wellbore trajectory shape, considering various types 

of slant, “S,” deep “J,” or even double-build horizontal geometries if completion 

techniques warrant this. The study should consider needs for specific wellbore 

orientations through any salt section as well as in the target formation.
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For the final two sections of the injection well, a more engineered approach for 

construction is appropriate. The study should consider completion technique, 

well orientation, wellbore construction, directional planning, casing design, 

cementing plan, drilling fluid selection, and wellbore integrity (including well 

control and lost-circulation mitigation).

1.6 RECOMMENDATION #6 – CORROSION STUDY

An engineering study is needed to evaluate the most effective and 

economical corrosion mitigation for the new well.

The corrosion resistant alloys (CRA) used at PVU #1 have functioned well for 

more than 20 years, but they are exceptionally expensive. In the well itself, an 

entire 5-1/2” casing string of Hastelloy C276 has been used down hole. Inconel 

has been used in the high pressure pump and valve train as well as in the piping 

to the wellhead. A steel-based wellhead internally clad in Inconel is in use.

Given the current environmental conditions and the time since the original 

specifications, we recommend initiating a new study of the use of the CRA for 

PVU #2. This will require a reassessment of the current source, concentration, 

and volume of corrosion agents (H2S, CO2, chlorides, oxygen, sulfur, etc.) and 

various environmental conditions such as temperature and pressure throughout 

the system, from source to surface to injection disposal. Various tests will help

determine the longevity and suitability of various corrosion mitigation 

techniques. These could range from the exotic C-276 to plastic coated tubulars

or a chemical inhibition routine.

1.7 RECOMMENDATION #7 – SALT RHEOLOGY STUDY

Reclamation should conduct a study assessing the rate of salt 

movement near the candidate well sites. This is essential information 

for drilling and designing wells.

Because of containment issues, it is a Reclamation imperative that a layer of salt 

overlies the injection zone, and thus any PVU #2 well must penetrate one or 

more salt layers. Salts present a unique challenge in drilling and completion 

operations. These include dissolution and subsequent hole enlargement and the 

converse, deformation from plastic flow (a.k.a. creep) and subsequent hole 

shrinkage. Hole shrinkage can occur fast enough to close off a hole while drilling 

or over time, impose lithostatic loads on casing and cement that cover the salts.

If these loads are not uniformly distributed, this will lead to casing collapse and 

loss of the wellbore (Perez et al. 2008). When drilling around salt bodies, there 

can be rubble zones, leading to wellbore instability, stuck pipe, and lost 

circulation. Localized abnormally high pore pressures may be encountered, and 

local tectonic stresses can arise due to salt intrusion.

Since the proposed lifetime for the proposed PVU #2 well is 50 years, successful 

drilling, completion, and well performance require understanding the expected 
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behavior of the salt zone. Key properties to consider are the creep rate, 

anisotropic stress field, and corrosive properties of the salts. 

When a salt layer overlies or is in direct contact with an injection reservoir 

compartment, the solubility of the salt can be important. Salt comes in many 

varieties, including chlorides, sulfates, and carbonates. Halite (NaCl) is the most 

common; however, there are over 35 types of salts, each with its own 

characteristics. The solubility of the salt depends upon its content. Among 

common salts, CaCl2 is the least soluble salt, MgCl2 and NaCl are of 

intermediate solubility, while KCl is the most soluble salt. Other evaporite 

minerals such as anhydrite, gypsum, limestone, and dolomite may bound or be 

intermixed with salt bodies. Water content is a strong driver of creep behavior,

and temperature has a significant effect as well (Urai and Shi-Yuan 2016).

The data collected from exploratory wells and from the literature can provide

input for the many salt models that have been proposed by investigators, thus 

informing the planning for the design and performance of the proposed PVU #2 

injection well. Most salt models basically assume that salt is a homogenous 

material, but this is seldom a legitimate assumption—most salt bodies are highly 

inhomogeneous. This can lead to incorrect conclusions regarding the 

characteristics and subsequent behavior of the salt. For example, creep has been

shown to be four orders of magnitude different than predicted (Urai and Kukla 

2004). Extensive data are available for many salt areas around the world. Some 

of the United States Department Of Energy National Laboratories, such as 

Sandia National Laboratory, have made studies on salt movement for projects, 

such as nuclear waste storage. In addition, Respec Inc. (www.respec.com) may 

have data for purchase. There may be data available for the Paradox Valley; 

however, the CRB does not have any information regarding that.

Thus, as noted in the Cuttings and Core section of Recommendation #4, we 

recommend that as exploratory wells are drilled, that the salt layer above the 

injection zone should be cored and analyzed to determine its material and 

chemical properties. These data will significantly reduce uncertainties for the 

results of the proposed modeling.

1.8 RECOMMENDATION #8 – EMERGING TECHNOLOGIES FOR MONITORING POSTINJECTION GROUND RESPONSE

Various emerging technologies should be considered to evaluate and

integrate existing data concerning the Paradox Valley operation.

The unconventional is fast becoming the conventional as we consider

approaches to reservoir characterization and management. We recommend 

that a comprehensive plan for monitoring be included in the design of the 

exploratory wells, injection well PVU #2, and any monitoring wells. The highest 

priority should be to obtain data from multiple methods for proxy sensing of 

fluid pressure and movement of injected fluids. The propagation of the pressure 

field can be observed indirectly by monitoring ground deformation and changes 
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in subsurface physical properties. Monitoring the pressure wave through the 

deformation and acoustic emissions fields provides a management tool for 

making decisions about changing rates of brine injection. The sensing methods 

we suggest include several recently developed technologies. Scoping 

computations should be made to assess their viability before deployment.

1.8.1 Distributed Acoustic Sensing

Installing fiber-optic cable behind casing in the exploratory well and the injection 

well makes it possible to perform repeat VSP surveys (Miller et al. 2016).

Monitoring velocity structure in the near-field environment with fiber-optic 

cable is being used in the hydrocarbon industry and in demonstration projects 

for carbon sequestration (Daley et al. 2013).

Fiber-optic cable is also being deployed in horizontal trenches at kilometer scale 

in demonstration projects for carbon sequestration (Freifeld et al. 2016; Yavuz 

et al. 2016) and geothermal reservoir monitoring (Feigl and PoroTomo Team 

2017). A kilometer-sized array that encircles the proposed PVU injection well 

could be used as a seismic monitoring network. The horizontal geometry of the 

near-surface cable combined with a vertical cable in the exploration hole could

be used for highly accurate location of induced earthquakes within the array 

boundary. In addition, the array could monitor seismic velocity changes using

active-source or ambient-noise tomography.

1.8.2 GPS, InSAR, and Borehole Tiltmeters

Ground uplift in response to injection at 4.8-km depth is highly muted. 

Nonetheless, calculations suggest that several centimeters of deformation have 

occurred over 25 years of injection at PVU #1 (Detournay and Dzik 2017), 

although this uplift was below the level of detection in the PVU InSAR study 

(Besana-Ostman 2016).

Anticipating the desire to calibrate future geomechanical models means 

collecting baseline ground deformation data prior to and following injection at

the new well. Installation of borehole foundations for an array of permanentstation GPS stations would provide real-time deformation monitoring. Installing 

permanent corner reflectors for InSAR could be considered along with its 

tradeoffs in construction cost and spatial-temporal resolution.

Borehole and shallow tiltmeters have sensitivities of 5-10 nanoradians and are

used elsewhere for hydrocarbon reservoir monitoring. This sensitivity is 

sufficient to record solid earth tides. The comprehensive plan should assess 

whether borehole tiltmeter technology is appropriate for monitoring the fluidpressure front associated with PVU #2. This can be achieved through forward 

modeling using a mathematical formulation similar to that described by

Detournay and Dzik (2017) in their report provided to Reclamation, or by using

the methods of Dusseault and Rothenburg (2002). Given the depth of the 

pressurization process within the Leadville Formation, the tilt modeling should 
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focus on predicting both the maximum tilts expected as well as the optimum 

locations for shallow-tiltmeter installation.

If a string of borehole tiltmeters is installed in a monitoring well, tiltmeters 

closer to the source of deformation will experience larger-magnitude tilt signals.

However, the presence of the tiltmeter string does restrict access to the lower 

part of the monitor borehole.

We recommend installing tiltmeter arrays at near-surface sites if the modeling 

shows this approach is feasible. These are typically placed in 10-m-deep 

geotechnical boreholes. If the array is placed properly it will be useful for

calibrating the coupled geomechanics model (see Recommendation #12), 

thereby increasing the value of this modeling, and increasing the usefulness of 

the pressure-monitoring data as well.

1.9 RECOMMENDATION #9 – LEADVILLE CORE PETROPHYSICS

Laboratory analysis of existing Leadville cores could provide useful 

bounds on porosity, permeability, faulting, and seismic velocities.

We recommend performing a core analysis study to evaluate properties of the 

Leadville Formation in the vicinity of the injection well. This analysis would 

evaluate the heterogeneity within the Leadville and may also help constrain the 

velocity model used for earthquake location. Petrophysical measurements on a 

few cores will help to establish relationships between Vp/Vs, anisotropy,

porosity, and permeability. Upscaling from core to well log to seismic scales 

provides essential information as geological/geophysical investigations move 

toward a dynamic reservoir characterization phase (see Recommendation #12). 

1.10 RECOMMENDATION #10 – MODELING STUDY TO EVALUATE MINIMUM DISTANCE 

FROM FAULT

Geomechanical modeling could help assess the effects of distance 

from injection to sealing faults.

For the PVU #2 injection well, the proposed Dolores River Valley sites (near A 

in Figure 1) are relatively close to the PVU #1 well and to the supposedly 

impermeable sealing fault that bounds the new fault block and is situated 

between PVU #1 and the Dolores River Valley drilling target locations. Prior to 

finalizing the bottom-hole location, we recommend undertaking an investigation 

to assess whether the proximity to this fault affects the performance of PVU #2.

The distance between the injection target for PVU #2 and the supposedly

impermeable fault influences the pore pressure and also the stress acting on the 

fault. Two questions to address are:

• What are the pore pressure change and the pore-pressure-induced 

stress change that will cause the sealing fault to slip? While the 

bounding fault is not expected to be critically stressed—based on 
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what we currently know about regional stress and earthquakes in 

the region—it is nonetheless worthwhile to assess the factor of 

safety against a slip event, given plausible pore pressure and stress 

change caused by injection.

• What is a safe distance from the fault for injecting the brine?

While limited subsurface data make for considerable uncertainty concerning the 

presence, location, and orientation of faults/fractures within the new fault 

bounded block, geomechanical modeling in conjunction with probabilistic fault 

slip analysis can help assess risks associated with induced seismicity near

potential well locations, especially at nearby bounding faults (e.g., Walsh and 

Zoback 2016). 

Note that a pore pressure discontinuity is expected across the fault due to 

injection from PVU #1, even if the fault is not a perfect hydraulic barrier.

A preliminary recommendation is to carry out a back-of-the-envelope 

calculation to estimate the critical pore pressure change and the minimum safe

distance between the injection point and the fault. This preliminary estimation of 

the critical pore pressure on the fault would ignore any poroelastic stress 

change. It simply relies on making assumptions about the orientation of ShMax, 

the ratio ShMin/ShMax, and the orientation of the fault, and then calculating the 

pore pressure that will cause slip on the fault. The safe distance between the 

fault and the injection point can be deduced from a simple pore pressure field 

calculation using a singular source and its image on the other side of the fault. 

This safe distance will be a function of the injection rate history, the hydraulic 

properties of the reservoir, and the critical pore pressure change.

When these preliminary calculations are complete, a more elaborate 

geomechanical analysis that accounts for non-uniform poroelastic stress changes 

can be performed using fairly standard numerical simulation software. The

preliminary scoping calculations will also serve to determine size of the region 

to be modeled in more detail.

1.11 RECOMMENDATION #11 – MODEL PERMEABILITY (OR MOBILITY) AND DIFFUSIVITY 

NEAR PVU #1 USING EARLY AND RECENT INJECTION PRESSURE HISTORY

A geomechanical model of the region within a few kilometers of the 

well can provide important information about reservoir properties.

Permeability (or mobility) and diffusivity are the two critical reservoir 

parameters that control the magnitude and evolution of the induced pore 

pressure. Indeed, the magnitude of the pore pressure at a given location and 

time is inversely proportional to the mobility, while the diffusivity affects the 

propagation of the diffusion front. For the reservoir affected by the PVU #1 

well, estimates of large-scale values for the diffusivity have been inferred from 
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the migration of the front of seismic activity and are broadly consistent with 

large-scale values of diffusivity estimates in other reservoirs. 

There remains, however, significant uncertainty concerning the values of the 

permeability/mobility. The only direct measurements available to estimate the 

permeability are the surface injection pressures measured at PVU #1. Numerical 

simulations using a large-scale model (covering 22 years and 40 km X 56 km x 

7.5 km) are able to match the observed pressure from about 2000 to the 

present by adjusting the permeability and assuming the impermeability of the 

faults with more than 500 ft offset (see Figure 5, Pressure vs Time at PVU #1). 

Figure 5. Pressure vs Time at PVU #1. 

For the PVU #1 injection well, comparison of measured surface injection pressures (blue) and pressures 

calculated from a course-scale geomechanical reservoir model (red). The modeling covers the interval 

from late 1991 (0 sec) to December 2016 (almost 8x108 sec). Note that measured and calculated 

pressures disagree over the early period, suggesting that the model poorly represents either the nearwell environment, or that this environment has changed over the time. (Figure reproduced from

Detournay and Dzik 2017)
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However, the injection pressure measured during the period from the start of 

the injection to 1999 is not well matched by that model. This inconsistency 

provides an opportunity to obtain additional information about the global 

permeability and the topology of the reservoir in a region around PVU#1 at a 

“medium” scale ranging from hundreds of meters to kilometers. This analysis 

will also provide information on how skin or diffusivity changes with time. The 

analysis now available suggests that permeability near the well increases 

significantly over time due to pore pressure increase, cooling, and/or chemical 

reactions.

We therefore recommend conducting pore pressure modeling at this medium 

scale to evaluate permeability and topology of the reservoir, including the 

possibility that near-well permeability has changed over time. Initial scoping 

analysis could be performed with a 2D model at the expense of assuming that 

the head in the Leadville Formation does not depend on the depth. These 

preliminary calculations could be complemented by 3D diffusion computations.

1.12 RECOMMENDATION #12 – MODELING TO ASSESS SLIP ALONG FAULTS

Construct a comprehensive, 20-km-scale, geomechanical model that 

includes stress, poroelasticity, and slip along faults.

Numerical simulations at a ~25 year, 10-20 km scale using modern 

geomechanical software can provide new insights constraining the in-situ stress 

within Paradox Valley region, the geomechanical properties of the Leadville 

Formation and of confining layers, as well as the strength of the faults 

intersecting the reservoir. King et al. (2017) reports estimates of the regional 

scale in-situ stress based on Anderson faulting theory. Moreover, Detournay 

and Dzik (2017) evaluate the risk of seismic events by assessing a safety factor

based on the stress and the pore pressure fields (both a combination of initial 

fields and injection-induced fields) computed using 3D geomechanical software. 

However, in both calculations the induced stress (either poroelastic or elastic)

is based solely on the linear response of the rock formations. Thus, the 

calculations do not account for possible slip on overstressed faults and the 

subsequent readjustment of the stress field.

A first recommendation is to carry out a simplified calculation, similar in some 

ways to that reported in King et al. (2017), but accounting for the poroelastic 

stress and assuming uniaxial strain in the reservoir—a reasonable hypothesis in 

view of the large lateral extent of the Leadville Formation (Marck et al. 2015). In 

that case, the local change in the horizontal stresses Δσh and ΔσH is 

proportional to the pore pressure change ΔΔ induced by fluid injection with 
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Δσh = ΔσH ≃ ΔΔ/2, approximately1, while the vertical stress σv remains 

unchanged.

Along normal faults, σ1 = σv and σ3 = σh. Because of poroelastic effects, not 

only the mean effective stress s = (σ1 + σ3 − 2 )/2 is changing but also the 

stress deviator q = (σ1 − σ3)/2. Thus, perturbations in stress and pore 

pressure due to the fluid injection are stable or unstable depending not only on 

the magnitude of the perturbations relative to the initial conditions, but also on 

the ratio Δ /Δ itself, which is a function of Poisson’s ratio ν and the Biot 

coefficient α. Namely, a necessary condition for the fault to slip is that

Δ /Δ < sinφ ( Δ , Δ < 0), where φ is the friction angle of the fault 

(Rudnicki 2011). Neglect of poroelastic effects is equivalent to assuming that

Δ = 0, in which case the necessary condition is always satisfied. In other 

words, because of the stabilizing effect associated with a poroelastic stress 

change (resulting in Δ < 0), the initial conditions are actually closer to critical 

than would be deduced from interpreting a normal slip event without taking

poroelasticity into account. 

Along strike-slip faults, σ1 = σH and σ3 = σh. Here Δ = 0 and the above 

necessary condition for slip is always met. Nevertheless, poroelastic effects have 

a stabilizing effect since then Δ ≃ −ΔΔ/2 (see footnote 2), rather than 

Δ = −ΔΔ if injection-induced stresses are neglected.

We further recommend developing a geomechanical simulation model at the

~25 year, 10-20 km scale that accounts for both poroelastic stresses and for 

stress changes resulting from slip along overstressed faults. Because the pore 

pressure induced by injection is essentially governed by the classical diffusion 

equation, owing to the weak mechanical-to-hydraulic coupling in this class of 

problems, the induced pore pressure field ΔΔ(x,t) need only be computed 

once. The induced stress and displacement fields and possible slip can then be 

calculated at suitable (probably variable) time intervals, chosen to accommodate 

periods of large pore pressure change. Such an approach would considerably 

reduce the computational burden inherent in performing such large-scale 

computations.

1.13 RECOMMENDATION #13 – IMPLEMENTING A MODERN APPROACH TO 

VISUALIZATION AND INTEGRATION

This includes the application of software for visualization and 

geomechanical modeling.

We commend Reclamation for their efforts sustained over more than two 

decades to characterize regional geology, hydrology, and tectonics, and to safely 

manage the injection operations at PVU #1. Their efforts over more than 25 

 1 Under uniaxial strain conditions, Δ = 2η , where the poroelastic stress coefficient η = α(1 − 2ν)/2(1 − ν), 

with ν is Poisson’s ratio and α is the Biot coefficient. The range of η is [0, 0.5], but typically η ≃ 0.25. Rudnicki 

(2002) discusses corrections to account for the geometry of the underground reservoir into which fluid is injected.
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years to monitor and accurately locate earthquakes may well be superior to 

those at any other injection facility, worldwide. The collected seismicity data 

have been hugely useful for constraining these scientific characterizations.

However, we recommend that Reclamation consider implementing a more 

modern, integrated system for data analysis and reservoir management. Using 

modern visualization tools to allow for a perspective based on reservoir 

dynamics and geomechanics, the earthquake data should be integrated with 

stratigraphic information, hydrological data, 2D and 3D seismic data, a tectonic 

structural model, and a geomechanical model such as that described in 

Recommendation #12. This integrated model will change over time as data 

accumulate (3D and 4D seismics, earthquake hypocenters, and pressure 

information measured at monitoring wells). 

The project must shift in this direction. It is not possible to eliminate risk but it 

can be well-managed, providing the modeling is executed properly and the right 

monitoring data are collected to inform the model. This project can be a 

showcase demonstrating how a proactive, integrated program of monitoring

(Recommendation #8), modeling (Recommendations #10, #11, and #12), and 

management pays dividends with respect to managing the reservoir and 

mitigating the risk associated with deep-well injection.
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CHAPTER 2

RECLAMATION QUESTIONS TO THE 

CONSULTANT REVIEW BOARD

2.1 QUESTION 1. HAVE APPROPRIATE TECHNICAL CRITERIA FOR IDENTIFYING 

POTENTIAL INJECTION WELL SITES AND RESERVOIRS BEEN CONSIDERED?

As noted above, the CRB commends Reclamation personnel and their

consultants for their combined research efforts investigating technical issues 

associated with the Second Injection Well Alternative in the Paradox Valley 

region–PVU #2. Generally the depth of technical analysis is excellent, the 

interpretations are logical, and the documentation is exhaustive (see Appendices 

B and C). These studies have served to eliminate several potential sites for PVU 

#2, and reduce the risks associated with siting of PVU #2 in comparison to what 

was known at the time of the 2015 external review panel report (Consultant 

Review Board 2015).

To further reduce development risks, Reclamation should obtain more detailed

geological and geophysical information about the remaining sites to assess 

whether they provide the necessary access to the Leadville Formation in a 

location having favorable permeability and porosity conditions within it. In 

particular, for long-term disposal well performance, four major criteria must be 

satisfied: 

1) Adequate porosity for the storage of anticipated volumes of brine; 

2) Adequate permeability permitting access to the reservoir and its 

storage capacity; 

3) Sufficient volumetric extent of the reservoir to allow injection for 

prolonged periods of time without excessive pressure build-up at a 

regional scale; and

4) Sufficient overlying salt thickness to serve as a top seal.
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These four criteria are not all independent, but they are distinct. For example, 

even if permeability and porosity are adequate, the Piñon well sites are rejected 

because of too intense compartmentalization, leading to a risk of inadequate 

reservoir volume if the bounding faults are found to be sealing.

To reduce the degree of uncertainty, at local scales the geological model needs 

refinement, particularly to determine the fault block structure, to confirm the 

presence of salt, and to assess whether fault offsets are sufficient to be sealing.

Also, reducing uncertainty concerning the geographic distribution of thickness, 

porosity, and permeability in the Leadville Formation (and deeper strata) is 

needed. Together, this additional information will further reduce the risks 

associated with choosing and developing a site for PVU #2.

To reduce uncertainty the CRB recommends undertaking two major efforts

prior to drilling PVU #2:

• Of highest importance is the execution of a high-resolution 3D

seismic survey over a limited area to constrain the vertical and 

lateral distribution of porosity in the injection interval below the 

Paradox salt, as well as to more precisely examine the lateral 

heterogeneity (Recommendation #3).

• Also important is the drilling of one or more exploratory wells (also 

called “biopsy wells” or “strat wells”) to the base of the Cambrian 

sediments below the Leadville Formation (Recommendation #4).

Logging with modern logging tools in these wells will help evaluate

the nature of natural fractures in the target injection strata. Analysis 

of new and existing cores through the porous and permeable 

section of the Leadville Formation will provide more quantitative 

information concerning permeability and porosity (matrix vs. 

fracture; Recommendation # 9). 

In addition to reducing uncertainty associated with the suitability of the Leadville 

Formation disposal interval for PVU #2, these efforts will provide the following 

additional benefits:

• Reducing risks associated with the design, drilling, and completion of

PVU #2;

• Allowing the refinement of the velocity model for locating 

earthquake hypocenters and determining focal mechanisms;

• Providing more accurate measurements for determining principal 

stress orientations and minimum horizontal stress values; and

• Locate smaller, potentially seismogenic faults/fractures.
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2.2 QUESTION 2. ARE EXISTING GEOLOGIC AND GEOPHYSICAL STUDIES ADEQUATE TO 

CHARACTERIZE THE SUBSURFACE STRUCTURE IN THE PARADOX VALLEY AREA AT A 

REGIONAL SCALE, FOR THE PURPOSE OF IDENTIFYING POTENTIAL WELL SITES?

The CRB recognizes that substantial progress has been made toward 

synthesizing regional geological and geophysical data to identify potential 

injection well sites for PVU #2. However, additional data are needed to aid in 

characterizing the target reservoir for injection:

• The application of emerging technologies for data collection and the 

application of modern integrated analysis/visualization techniques 

will make it possible to obtain the most comprehensive information 

possible using both existing data and any new data 

(Recommendations #8 and #13).

• There is a need to conduct detailed core studies of existing cores 

collected from the Leadville Formation (Recommendation #9). The 

core data will also facilitate the interpretation of the seismic data 

and sonic logs (see below).

• Before making final site selection among the alternatives in the 

southern new fault block (see Figure 1 and Recommendation #1), 

we recommend performing a “regional” 3D seismic survey, but it 

must be designed to cover 60 square miles or more to encompass 

the two alternative target well sites (Recommendation #3). Such a

3D seismic survey is costly, but it can be designed with a sparse grid 

of shots and receivers. This design would constrain details of 

subsurface structure (stratigraphic thicknesses and presence of 

faults), but may not be effective for detailed reservoir 

characterization.

• We also recommend performing a higher-resolution 3D seismic 

survey at the site chosen for PVU #2 to provide needed information 

concerning reservoir characterization and completion of the well 

(Recommendation #3). Most valuable would be a nodal 3C seismic 

survey encompassing at least 15 square miles in the vicinity of the 

preferred site. A nodal seismic recording system is a cableless 

system, where data are recorded at each station without cabling to 

a central recording system. Individual stations are known as "nodes".

This survey should be designed to incorporate a large number of 

multicomponent receivers while placing shot points or vibrating 

points wherever they can be placed. The survey may have to use 

both vibrators and heli-portable drills to provide adequate 

subsurface coverage. Analysis of both compressional and converted 

shear waves recorded by multicomponent receivers will provide 

enhanced reservoir characterization of the fault and fractures in the 

vicinity of the target well site. A logical path may be to do the large 

regional survey first, select the location for an exploratory well (see 
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below), then conduct a high-resolution 3D, 3C survey for detailed 

reservoir characterization. 

The regional 3D survey will enable characterization of porosity and 

the fracture density in the Leadville Formation. Porosity is critical to 

provide storage capacity for the injected brine. The Leadville

Formation is a karst reservoir; it is very heterogeneous and 

extensively fractured. The high-resolution survey will provide detail

concerning the reservoir characteristics of the Leadville Formation

in the vicinity of the preferred candidate site for PVU #2. 

Multicomponent seismic data allow for better porosity

discrimination than do compressional seismic data alone. Azimuthal 

velocity studies of compressional and converted shear wave data 

can provide information concerning stresses in the subsurface and 

concerning the presence of fractures that provide the major control 

on permeability within the Leadville Formation and the Basement 

intervals. 

• The seismic survey should be conducted in conjunction with drilling 

one or more “exploratory” wells (Recommendation #4). Following 

completion of drilling we recommend:

– Logging with a cross-dipole sonic log or “sonic scanner;” 

– Acquiring 3D VSP data that will provide high-resolution 

seismic imaging in the vicinity of wells’ bottom-hole 

locations, especially in the vicinity of the anticipated PVU #2

injection well; and

– Instrumenting exploratory wells with fiber-optic cable for

permanent, long-term monitoring purposes (see 

Recommendation #8). This monitoring system could also

involve a surface array of multicomponent nodal receivers.

That is, a subset of the receivers used in the seismic survey

could provide a “sparse array,” but the more dense nodal 

array and VSP data would constrain a velocity model

precisely. Ultimately, as time passed this would provide the 

basis for a 4D survey that would dynamically characterize 

the reservoir during the initial “pressure up” period of the 

PVU #2 injection well.

2.3 QUESTION 3. HAVE POTENTIAL RESERVOIR FORMATIONS BEEN CHARACTERIZED 

ADEQUATELY, INCLUDING THEIR ESTIMATED DEPTH AND THICKNESS, SPATIAL 

EXTENT, PERMEABILITY, POROSITY, DEGREE OF HYDROLOGIC ISOLATION FROM THE 

CURRENT INJECTION WELL, AND THE PRESENCE OF A SUITABLE CONFINING LAYER?

If the PVU #2 well is drilled into the new fault block near either sites A or B in 

Figure 1, the reservoir formations that will be pressurized by brine injection 

are compartments of the Leadville Formation located south of a supposedly

sealing boundary fault (designated as Fault A in Figure 3) situated just to the 
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south of PVU #1. On the basis of existing data these formations have been 

characterized adequately. The available information includes 2D seismic 

reflection data (collected during various campaigns conducted prior to 1985, but 

recently reprocessed), logs from oil and gas wells drilled in the area, 

aeromagnetic and gravity data, and earthquake data (Block 2017; King et al.

2017). 

However, these reservoir formations are highly heterogeneous, and there is a 

paucity of data regarding reservoir properties. Thus, the degree of confidence in 

the current characterization depends on various issues:

2.3.1 Degree of Isolation from the Current Injection Well

We are generally confident that the reservoir formations south of Fault A are

hydraulically isolated from the PVU #1 injection well. Fault A appears to be an 

impermeable barrier as shown by three independent pieces of information: an 

offset of at least 500 ft deduced from the reprocessed 2D seismic surveys (Excel 

Geophysical Services 2016), the virtual absence of earthquakes south of fault A 

over the period of injection at PVU #1 well (Block 2017), and the generally 

successful match since 2000 between observed injection-pressures and 

numerical modeling simulations that assume fault A is impermeable (Detournay

and Dzik 2016; see also Figure 5). 

2.3.2 Estimated Depth and Thickness of the Reservoir

The estimation of reservoir depth and thickness is based mainly on the 

interpretation of seismic reflection data, well logs, and a gravity survey.

However, there is significant uncertainty in these estimates for several reasons:

the heterogeneity of the reservoir at the scale of the spacing between the 2D 

seismic lines, uncertainty concerning the seismic velocities used to interpret the 

seismic survey so as to constrain depth and formation thickness, and the quasiabsence of wells that have pierced the Leadville Formation within several miles 

from the potential well injection locations. Most of the existing wells are located 

along the southwest boundary of the area of interest. For example, the 2017 2D 

Seismic report on detailed site interpretation quotes depth errors for the 

Leadville Formation ranging from about 100 m to 450 m (Excel Geophysical 

Services and International Reservoir Technologies 2017).

2.3.3 Spatial Extent of the Reservoir

Based on the 2D seismic interpretation (Figure 3), there is reasonable 

confidence that the spatial extent of the reservoir in the new fault block is not 

locally compartmentalized. Although the 2D survey provides a reasonable 

preliminary basis for targeting this block for PVU #2 injection, further 

investigation is needed in the form of a 3D seismic survey at the preferred site, 

first at a coarse scale and then with subsequent refinement (Recommendation 

#3).
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2.3.4 Permeability and Porosity

Little is known concerning the permeability and porosity for the relevant 

geographic regions within the Leadville Formation, i.e., those regions in the new 

fault block that will be pressurized by injection of brines at PVU #2. There are 

no direct measurements of the permeability while the porosity data, inferred 

from wells logs, mainly pertain to wells that are close to the southwest 

boundary of the area of interest.

2.3.5 Presence of a Suitable Confining Layer

The salt layer appears to cover the relevant region of the Leadville Formation,

but its characteristics are incompletely constrained by the 2D seismic survey.

Thus, uncertainty remains concerning both the extent and thickness of the salt

layer.

2.4 QUESTION 4. HAVE THE SITES BEEN CHARACTERIZED ADEQUATELY, INCLUDING 

EVALUATION OF PROBABLE FLOW PATHS AND FLOW BARRIERS, PRESSURE-FLOW 

RESPONSE, AND THE POTENTIAL FOR INDUCED SEISMICITY?

Sites have been well characterized given the available information, especially 

with respect to surface conditions, drilling complexities, major faults, and 

potentially sealing faults as inferred from the seismic reflection and 

microearthquake data. Information from PVU #1 and other wells suggests that 

flow paths are confined to portions of the Leadville and the upper basement 

where the porosity/permeability has been enhanced by fractures. Interpretation 

of available seismic reflection data suggests that reservoir compartments are 

bounded by flow barriers that are faults having 500 ft or more offset, where the 

Leadville are juxtaposed against salt. 

The absence of seismicity to the south of the fault just south of PVU #1 

supports this interpretation. The general spatial/temporal pattern of 

microearthquakes surrounding PVU #1 is consistent with a pressure-flow front

in the Leadville Formation moving radially away from the injection point except

in regions where it is restricted by a sealing fault. Wherever the front reaches a 

critically stressed fault it can induce microearthquake activity. 

However, it would be valuable to obtain more detailed information concerning

the hydrological properties of the Leadville Formation and basement rocks in 

the vicinity of sites A and B in Figure 1, the proposed injection zones (see 

Recommendation #1):

• Potential flow paths can be verified by well log/core analysis in an 

exploratory well (see Recommendation #4). 

• A higher-resolution 3D seismic survey over the proposed injection 

zone will help assess whether faults are sealing, transparent, or 

leaky (Recommendation #3). Wellhead pressure curves for PVU #1 

are well matched by both a simple radial diffusion model with 

negative skin and by a flow model containing compartmentalization 
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provided by two sealing faults. It is thus reasonable to assume that 

the proposed injection zones in the new fault block (sites A and B in 

Figure 1) will respond in a similar fashion, i.e., that the fluids 

injected at PVU #2 into the new fault block would not communicate 

across the supposed sealing fault and communicate with PVU #1’s 

reservoir compartment.

• The 2D seismic reflection data available at present are unable to 

resolve the faults or fracture networks on which seismicity occurs; 

moreover, the larger faults that are identified from these data are 

aseismic. Since both the proposed injection zones to the south of 

PVU #1 (A and B in Figure 1) are currently aseismic, it is unknown

whether or not critically stressed faults are present—a higherresolution 3D survey might be able to detect potentially 

seismogenic faults. However, high-angle strike-slip faults are difficult 

to identify by interpreting seismic reflection data or data collected 

in exploratory wells (see below). Collecting and interpreting 4D and 

3C seismic data may make it possible to monitor the pressure 

compartmentalization within the reservoir and to confirm that wells 

PVU #1 and PVU #2 are isolated from one another.

• Drilling one or more exploratory wells to allow associated log/core 

analysis will help confirm that the PVU #1 well and the target

injection zone for PVU #2 have similar flow properties (see 

Recommendation #4). Drilling these wells will provide valuable 

information on the injectivity at the proposed site and the volume

of the injection compartment.

• Additional modeling of the early injection history of PVU #1 can

provide insight into the development/causes of enhanced 

permeability (thermal effects, hydrofracture, and reactivated 

fractures) near the wellbore as well as determine when the injection 

at the PVU #1 well first interacted with the supposedly sealing

boundary faults (see Recommendation #11). It is also possible that 

seismicity above or below the Leadville Formation is induced both 

by pore pressure and also by poroelastic stress changes. Additional 

analysis/modeling could determine if poroelastic effects are

important (see Recommendation #12).

2.5 QUESTION 5. HAS THE FEASIBILITY OF DRILLING, LOGGING, AND COMPLETING 

EXPLORATORY AND INJECTION WELLS AT THE PROPOSED SITES BEEN EVALUATED 

ADEQUATELY, INCLUDING REASONABLE CONSIDERATION OF GEOLOGIC FACTORS,

AVAILABLE TECHNOLOGIES, RISKS, COSTS, AND BENEFITS?

Reclamation and their consulting team have performed a commendable 

preliminary technical evaluation of the feasibility for the drilling, logging, and 

completion for wells at the proposed sites. With the information available to 

them at the time of their report, the consulting team performed a reasonable 

review of the risks, costs, and benefits with the level of detail and uncertainty 
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requested by Reclamation, and arrived at reasonable conclusions concerning

their ranking of the six proposed wells for suitability as a site for PVU #2.

There are some gaps that should be considered for future analysis:

• Reclamation should consider drilling one or more low-cost 

expendable exploratory-only wells (see Recommendation #4).

These wells would not ever be considered as potential sites for

injection well PVU #2; however, if in a useful location, they could be 

converted to a long-term monitoring well. These wells should be 

designed to use the least amount of casing feasible with the minimal 

hole size needed for any core retrieval, wireline logging, logging 

while drilling (LWD) logging, mini-frac, and pressure tests. The

drilling information that accrued from these wells would also be 

useful for reducing uncertainties in the engineering design for an 

injection well, should a site nearby be selected.

• We recommend undertaking a study targeting more specific surface 

and bottom hole locations for the two proposed sites (A and B in 

Figure 1; see Recommendation #5). These would consider surface 

issues as well as evaluate concerns about downhole trajectories.

The completion technique used for the exploratory, monitoring, 

and final injection well will drive these well designs.

• For the two final areas of interest (A and B in Figure 1), 

Reclamation should develop a more comprehensive engineered 

approach for the construction of an injection well (see 

Recommendations #5, #6, and #7). Careful attention to these issues 

prior to drilling of any well is likely to significantly reduce costs, 

improve the performance of the well in operational mode, and 

reduce the possibility of well failures over both short-term (1 year) 

and long-term (decadal) time scales.

2.6 QUESTION 6. IF EXISTING STUDIES ARE FOUND TO BE INADEQUATE, WHAT 

ADDITIONAL STUDIES SHOULD BE CONSIDERED, AND WHAT ISSUES ARE THEY 

LIKELY TO RESOLVE?

Prior to final site selection decisions concerning disposal alternatives for 

Paradox Valley brines, we urge Reclamation to seek additional expert technical 

review explicitly incorporating financial analysis of the various sites. The CRB 

was asked to assess technical issues related to the Second Injection Well 

Alternative—specifically issues related to choosing the site for and completing 

PVU #2. Although the CRB was not presented with a detailed financial analysis 

or asked to make decisions incorporating costs (and no member of the CRB is 

expert in this realm), our preconceived notions about these issues inevitably

influenced our recommendations in this report. Recommendation #1 provides 

one example of this: the CRB favors the Dolores River Valley surface sites for 
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PVU #2 because of perceived infrastructure costs; however, in the absence of 

cost considerations the Monogram Mesa sites are clearly superior. 

The 13 Recommendations of the CRB (see above) and our answers to 

Questions 1-5 are quite specific concerning the limitations (and strengths) of 

existing studies. These recommendations fall into two categories:

• Recommendations that Reclamation staff or their contractors 

clearly anticipated; i.e., recommendations that already have been 

suggested in the materials in Appendix B or during the oral 

presentations listed in Appendix C. In some cases the CRB has 

expanded or enhanced what had previously been suggested. These 

anticipated recommendations address:

– Ranking of candidate wells (Recommendation #1);

– Undertaking 3D seismic survey(s) (Recommendation #3);

– Drilling exploratory and monitoring well(s)

(Recommendation #4); and

– Undertaking a more comprehensive engineering design 

study at proposed well site(s) (Recommendation #5).

• Recommendations from the CRB that were not implied or explicitly 

mentioned in Reclamation reports or presentations. These possibly

unanticipated recommendations address:

– If a surface site on the Monogram Mesa is chosen, installing 

and operating seismic stations for at least 2 years prior to 

commencing injection at PVU #2 (Recommendation #2);

– Undertaking a design analysis of corrosion-resistant 

materials appropriate for all facility components in contact 

with brine at the proposed PVU #2 facility 

(Recommendation #6);

– Undertaking a study focusing on anticipating salt movement 

in the Paradox Salt formation at candidate well sites 

(Recommendation #7);

– Developing a program that employs various newly emerging 

technologies for monitoring well performance 

(Recommendation #8);

– Analyzing existing cores collected from the Leadville 

Formation to provide better information concerning 

porosity, permeability, faulting, and seismic velocities, and 

the variability of these parameters (Recommendation # 9);

– If a Dolores River Valley surface site is chosen, undertaking 

a modeling study to assess how proximity to the supposedly
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sealing boundary fault may affect well feasibility, design, and 

bottom-hole location for the PVU #2 well. This study 

should be informed by published information collected at 

existing wells concerning salt composition/rheology and/or 

by reanalysis of existing salt samples collected at these wells

(Recommendation #10);

– Undertaking a modeling study evaluating pressure-volume 

data collected over more than two decades at PVU #1, with 

the objective of better understanding porosity, permeability, 

and their variation over time within the Leadville Formation

(Recommendation #11);

– Developing a comprehensive 20-km-scale 3D geomechanical 

model that aims to match data collected over the past 25 

years to inform management decisions and predict the 

response to future injection (Recommendation #12); and 

– Implementing a comprehensive program utilizing modern 

visualization software that integrates data collection, data 

management, interpretation, and geomechanical modeling

(Recommendation #13).

2.7 QUESTION 7. ARE THERE OTHER ISSUES, OPPORTUNITIES, OR CONCERNS THE CRB

BELIEVES ARE APPROPRIATE TO RAISE CONCERNING THE EVALUATION OF 

POTENTIAL SECOND INJECTION WELL SITES FOR THE EIS?

We urge Reclamation to take a very long-range view (50-100 years) as they 

evaluate strategies for disposing of Paradox Valley brines. The fault-bounded 

block to the south of PVU #1 is very large—substantially larger than the faultbounded block into which PVU #1 currently injects—with potentially much 

greater capacity than the PVU #1 injection zone. Moreover, available 

information suggests the new block is hydrologically isolated from the current 

injection zone. This new fault-bounded block is sufficiently large that it is 

plausible that both the Dolores River Valley and Monogram Mesa locations 

could be utilized for injection in sequence over a 50-100 year period. This is 

important, because the need to dispose of Paradox Valley brines will certainly 

persist over this time interval and longer.

Two areas (Dolores River Valley and Monogram Mesa) have been identified as 

generally viable locations for a second injection well. Based on current 

information, the Dolores River Valley area is favored over the Monogram Mesa 

area. However, additional information is needed prior to drilling a second 

injection well. Especially important are the 3D seismic data needed to verify the 

structure of the reservoir and the presence of the top seal (salt), and to 

determine whether bounding faults are sealing. 3D seismic data can also 

improve estimates of porosity (and thus capacity for injection) of the Leadville

Formation. Exploratory wells are needed to verify the porosity within the 

Leadville Formation and to measure both in situ stress and pore pressure.
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Additional modeling and engineering analysis will also help to determine the best 

well location and completions method.

The CRB discourages Reclamation from selecting one location over another 

prematurely. Rather, we encourage the BoR to pursue a careful workflow with 

multiple decision points that utilizes new information as it is obtained, and does

not lose sight of very long-range project objectives.

Finally, if Reclamation ultimately decides NOT to pursue the Second Injection 

Well Alternative, the CRB recommends that for a minimum of 4 years after 

injection ceases at PVU #1, operation of the Paradox Valley seismic network

must continue, and monitoring pressure, etc., in the PVU #1 well and any 

available monitoring wells must also continue. There are three reasons for this:

• Past experience indicates that induced earthquakes may persist for 

several years following the cessation of injection, and sometimes 

these include the largest events associated with an injection project. 

• If at some future time, even 20 or 30 years hence, a decision is 

made to install a second injection well in Paradox Valley, the data 

collected in the years following shutdown of PVU #1 could be 

essential for understanding the size and transport properties of 

reservoirs in Paradox Valley and surrounding regions, and thus 

informing the design for a future well.

• The earthquake data collected, and the technical analyses performed 

since the 1980s for the PVU project, are comprehensive and 

remarkable, especially because they span an interval prior to 

injection and continue throughout the injection process. Continuing 

data collection will allow future scientific researchers to utilize these 

data and draw conclusions that may reduce risks and costs 

associated with future efforts to dispose of liquid brines in the 

Paradox Valley, and worldwide as well.
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CHAPTER 3

REFERENCES

Besana-Ostman, G. 2016. Identification of Deformation in Paradox Valley using InSAR. Technical 

Memorandum TM-85-833000-2016-16. US Bureau of Reclamation, Denver, Colorado.

Block, L. V. 2017. Trends of Induced Seismicity and Pressures Following the 2013 Change in Injection 

Operations at the Paradox Valley Unit, Colorado. Technical Memorandum TM-85-833000-2017-

10. US Bureau of Reclamation, Denver, Colorado. 

Campbell, A., F. Fryer, and S. Wakeman. 2005. “Vertical seismic profiles—more than just a corridor 

stack.” Leading Edge, doi:10.1190/1.1993259.

Consultant Review Board. 2015. Report from the Consultant Review Board On Paradox Valley Unit – MASIP / 

Induced Seismicity Meeting No. 1. Meeting held January 28-31, 2015, in Grand Junction, Colorado 

for the Bureau of Reclamation. 

Daley, T. M., B. M. Freifeld, J. Ajo-Franklin, S. Dou, R. Pevzner, V. Shulakova, S. Kashikar, et al. 2013. 

“Field testing of fiber-optic distributed acoustic sensing (DAS) for subsurface seismic 

monitoring.” The Leading Edge 32:699-706.

Detournay, C., and E. Dzik. 2017. Geomechanical and Flow Modeling for Paradox Valley Unit Study for 

USBR: Summary Report. ITASCA Consulting Group, Inc. Prepared for Bureau of Reclamation,

Minneapolis, Minnesota. 

Dusseault, M.B., and L. Rothenburg. 2002. “Deformation analysis for reservoir management.” Oil & Gas 

Science and Technology - Revue de l'IFP (Institut Français du Petrole) 57(5): 539-554.

Excel Geophysical Services. 2016. Data Processing Report: Paradox Valley Unit, Colorado and Utah, 

Phase 2. Prepared for Bureau of Reclamation, Greenwood Village, Colorado. 

Excel Geophysical Services and International Reservoir Technologies, Inc. 2017. Paradox Valley Unit 2D 

Phase 3 Seismic Report, Detailed Site Interpretation. Prepared for Bureau of Reclamation, 

Paradox Valley, Colorado.
3. References

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Feigl, K. L., and PoroTomo Team. 2017. “Overview and preliminary results from the PoroTomo Project 

at Brady Hot Springs, Nevada: Poroelastic tomography by adjoint inverse modeling of data from 

seismology, geodesy, and hydrology.” Proceedings, 42nd Stanford Geothermal Workshop, 

Stanford University, Stanford, California. Stanford University, Stanford, California, February 13-

15, 2017, SGP-TR-212.

Freifeld, B. M., R. Pevzner, S. Don, J. Correa, T. M. Daley, M. Robertson, K. Tertyshnikov, et al. 2016. 

“The CO2CRC Otway Project deployment of an areal distributed acoustic sensing network

coupled with permanent rotary sources.” 78th EAGE Conference & Exhibition 2016, Vienna, 

Austria, 30 May – 2 June 2016.

King, V. M., C. K. Wood, and V. M. Block. 2017. Integrated Subsurface Geologic Model, Paradox Valley, 

CO. Bureau of Reclamation Technical Memorandum 85-833000-2017-15. Paradox Valley, 

Colorado. 

Marck, J., A. Savitski, E. Detournay. 2015. “Line source in a poroelastic layer bounded by an elastic 

space.” International Journal for Numerical and Analytical Methods in Geomechanics 39(14):1484–

1505, doi: 10.1002/nag.2405.

Miller, D. E., T. M. Daley, D. White, B. M. Freifeld, M. Robertson, J. Cocker, and M. Craven. 2016. 

“Simultaneous acquisition of distributed acoustic sensing VSP with multi-mode and singlemode 

fibre optic cables and 3C- geophones at the Aquistore CO2 storage site.” CSEG Recorder special 

edition on DAS/Borehole Geophysics, accepted for publication.

Perez, M.A., R. Clyde, P. D’Ambrosio, R. Israel, T. Leavitt, L. Nutt, C. Johnson, and D. Williamson. 2008. 

“Meeting the subsalt challenge.” Oilfield Review, Autumn. Pp. 32-45.

Petrotek Engineering Corporation. 2017. Deep Well Appraisal and Feasibility Study. Final report 

prepared for Bureau of Reclamation, Littleton, Colorado.

Rudnicki, J. W. 2002. “Alteration of regional stress by reservoirs and other inhomogeneities: Stabilizing 

or destabilizing?” In Proc. 9th Int. Congr. Rock Mechanics Vol. 3, (G. Vouille and P. Berest, editors). 

Paris, August 25-29, 1999. Pp. 1629-1637. Balkema, Rotterdam. 

______. 2011. Mechanics of Crustal Rocks, Volume 533 of Courses and Lectures of the International Centre 

for Mechanical Sciences (CISM), chapter in Eshelby’s Technique for Analyzing Inhomogeneities in 

Geomechanics, pp. 43-72. Springer.

Urai, J. L., and P. A. Kukla 2014. “Rheological contrasts in salt and their effects on flow in salt.”

Geophysical Research Abstracts 16, EGU 2014-8788-1.

Urai, J .L., and L. Shi-Yuan. 2016. “Rheology of rock salt for salt tectonics modelling.” Petroleum Science

13:712-724.

Walsh, R., and M. Zoback. 2016. “Probabilistic assessment of potential fault slip related to 

injectioninduced earthquakes: Application to north central Oklahoma, USA.” Geology 44.

doi:10.1130/G38275.1.
3. References

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Yavuz, S., B. M. Freifeld, R. Pevzner, K. Tertyshnikov, A. Dzunic, S. Ziramov, V. Shulakova, et al. 2016. 

“Kinemetrics EPI ES-T buried DAS and geophone arrays: Preliminary results from CO2CRC 

Otway project.” 78th EAGE Conference & Exhibition 2016, Vienna, Austria, 30 May – 2 June 

2016.
3. References

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Appendix A

Consultant Review Board Members

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APPENDIX A

CONSULTANT REVIEW BOARD MEMBERS

Cliff Frohlich, Ph.D. – Board Chair 

Induced Seismicity Expert

Associate Director, Institute for Geophysics, University of Texas at Austin

Thomas L. Davis, Ph.D. 

Exploration Geophysics Expert

Professor of Geophysics, Colorado School of Mines (Ret.)

Emmanuel Detournay, Ph.D. 

Geomechanical Modeling Expert

Professor, Department of Civil Engineering, University of Minnesota

Maurice B. Dusseault, Ph.D., P.Eng.

Deep-Well Underground Waste Disposal Expert

Professor of Geological Engineering, Department of Earth and Environmental 

Sciences, University of Waterloo

Alfred Eustes, III., Ph.D., P.E. 

Petroleum Engineering Expert

Associate Professor, Petroleum Engineering Department, Colorado School of 

Mines

Jeffrey Nunn, Ph.D. 

Petroleum Geology Expert

Chevron Energy Technology Company

Herbert Wang, Ph.D. 

Rock Physics Expert

Professor of Geophysics, Department of Geoscience, University of Wisconsin –

Madison
A. Consultant Review Board Members

A-2 USBR Paradox Valley Unit, Consultant Review Board September 2017

Report on the Second Injection Well Alternative

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Appendix B

List of Material Provided by Bureau of Reclamation

September 2017 USBR Paradox Valley Unit, Consultant Review Board B-1

Report on the Second Injection Well Alternative

APPENDIX B

LIST OF MATERIAL PROVIDED BY BUREAU OF 

RECLAMATION

Reclamation provided the following documents to the CRB for consultation 

during their independent scientific review. This is not a list of literature cited in 

this report; that is included in Chapter 3, References.

Author unknown. 2016. Plate 1. Leadville Stratigraphic Cross Section A-A’. 

Besana-Ostman, G. 2016. Identification of Deformation in Paradox Valley using 

InSAR. Technical Memorandum TM-85-833000-2016-16. US Bureau of 

Reclamation, Denver, Colorado. 

Block, L. V. 2017. Trends of Induced Seismicity and Pressures Following the 

2013 Change in Injection Operations at the Paradox Valley Unit, 

Colorado. Technical Memorandum TM-85-833000-2017-10. US Bureau 

of Reclamation, Denver, Colorado. 

Block, L.V., C. K. Wood, W. L. Yeck, and V. M. King. 2014. “The 24 January 

2013 ML 4.4 earthquake near Paradox, Colorado, and its relation to 

deep well injection.” Seismological Research Letters 85: 609-624.

doi:10.1785/0220130188.

______. 2015. “Induced seismicity constraints on subsurface geological 

structure, Paradox Valley, Colorado.” Geophysical Journal International 

200:1172–1195. doi:10.1093/gji/ggu459. 

Consultant Review Board. 2015. Report from the Consultant Review Board On 

Paradox Valley Unit – MASIP / Induced Seismicity Meeting No. 1. Meeting 

held January 28-31, 2015, in Grand Junction, Colorado for the Bureau of 

Reclamation. 
B. List of Material Provided by Bureau of Reclamation

B-2 USBR Paradox Valley Unit, Consultant Review Board September 2017

Report on the Second Injection Well Alternative

Detournay, C., and E. Dzik. 2017. Geomechanical and Flow Modeling for 

Paradox Valley Unit Study for USBR: Summary Report. ITASCA

Consulting Group, Inc. Prepared for Bureau of Reclamation, 

Minneapolis, Minnesota. 

Dewan, J. T. 1987a. Letter from Dewan representing Dewan & Timko, Inc. 

International Petroleum Consultants to Ken E. Davis Associates, June 

22, regarding BOR Paradox Valley Test Well #1; letter concerns logging 

of the Intermediate Hole (14,505 to 2,020 ft.) of BOR Paradox Valley 

Injection Test Well # 1.

______. 1987b. Letter from Dewan representing Dewan & Timko, Inc. 

International Petroleum Consultants to Ken E. Davis Associates, August 

20, regarding BOR Paradox Valley Test Well #1; letter concerns logging 

of the Liner Hole (15,950 to 14,050 ft) of BOR Paradox Valley Injection 

Test Well # 1.

______. 1988a. Letter from Dewan representing Dewan & Timko, Inc. 

International Petroleum Consultants to Ken E. Davis Associates, January 

27, regarding BOR Paradox Valley Test Well #1; letter concerns log 

interpretation.

______. 1988b. Letter from Dewan representing Dewan & Timko, Inc. 

International Petroleum Consultants to Ken E. Davis Associates, April 

18, regarding BOR Paradox Valley Test Well #1; letter concerns 

mechanical properties log problem.

______. 1988c. Letter from Dewan representing Dewan & Timko, Inc. 

International Petroleum Consultants to Jim Bundy of Ken E. Davis 

Associates, July 20, regarding BOR Paradox Valley Test Well #1; letter 

discusses ability of salt layers to act as confining layers. 

Dunn, C. S. 1987. Letter from Dunn representing Fenix & Scisson, Inc. to 

Project Construction Engineer, Bureau of Reclamation, July 2, regarding 

Test Results - Internal Casing Test and Open Hole Leak-off Test No. 1. 

Contract No. 6-CC-40-03250, Injection Test Well No. 1, Paradox 

Valley Unit, Colorado River Basin Salinity Control Project. 

EDCON-PRJ, Inc. 2016. Data Acquisition and Processing of a High-Resolution 

Aeromagnetic Survey Paradox Valley, Colorado and Utah. Report 

prepared for Bureau of Reclamation, Lakewood, Colorado. 

Excel Geophysical Services. 2016. Data Processing Report: Paradox Valley Unit, 

Colorado and Utah, Phase 2. Prepared for Bureau of Reclamation,

Greenwood Village, Colorado. 
B. List of Material Provided by Bureau of Reclamation

September 2017 USBR Paradox Valley Unit, Consultant Review Board B-3

Report on the Second Injection Well Alternative

Excel Geophysical Services and David List Consulting, Inc. 2016. Paradox Valley 

- Geologic Support for Seismic Data Interpretation Phase 2 Report. 

Prepared for Bureau of Reclamation, Paradox Valley, Colorado.

Excel Geophysical Services and International Reservoir Technologies, Inc. 2016. 

Paradox Valley Unit Seismic Data Interpretation Phase 2 Report. 

Prepared for Bureau of Reclamation, Paradox Valley, Colorado. 

______. 2017. Paradox Valley Unit 2D Phase 3 Seismic Report, Detailed Site 

Interpretation. Prepared for Bureau of Reclamation, Paradox Valley, 

Colorado.

Fenix & Scisson, Inc. 1987a. Computer Processed Interpretation, Mechanical 

Properties. August 1987. Montrose, Colorado. 

______. 1987b. Computer Processed Log, Mechanical Properties. June 1987. 

Montrose, Colorado. 

Flak, L. H., and J. H. Brown. 1990. “Case history of an ultradeep disposal well in 

western Colorado.” SPE Drilling Engineering, pp. 39-44.

doi:10.2118/17222-PA.

Hickman, S. 2003. Letter from Hickman to Kenneth Mahrer and John Ake of 

Bureau of Reclamation, May 7, concerning Paradox well breakout 

analysis. 

King, V. M. 2017. Compilation of Well Data in the Vicinity of Paradox Valley, 

CO. Technical Memorandum 85-833000-2017-14. Bureau of 

Reclamation, Paradox Valley, Colorado. 

King, V. M, L. V. Block, W. L. Yeck, C. K. Wood, and S. A. Derouin. 2014. 

“Geological structure of the Paradox Valley Region, Colorado, and 

relationship to seismicity induced by deep well injection.” Journal of 

Geophysical Research: Solid Earth 119. doi:10.1002/2013JB010651.

King, V. M, L. V. Block, and C. Wood, 2016. “Pressure/flow modeling and 

induced seismicity resulting from two decades of high-pressure, deepwell brine injection, Paradox Valley, Colorado.” Geophysics 81, B119-

134. doi: 10.1190/GEO2015-0414.1.

King, V. M., C. K. Wood, and V. M. Block. 2017. Integrated Subsurface Geologic 

Model, Paradox Valley, CO. Bureau of Reclamation Technical 

Memorandum 85-833000-2017-15, Paradox Valley, Colorado. 

Petrotek Engineering Corporation. 2017. Deep Well Appraisal and Feasibility 

Study. Final report prepared for Bureau of Reclamation, Littleton, 

Colorado.
B. List of Material Provided by Bureau of Reclamation

B-4 USBR Paradox Valley Unit, Consultant Review Board September 2017

Report on the Second Injection Well Alternative

Wintermoon Geotechnologies, Inc. 2016. Interpretation Report: Data 

Enhancement, Map-based Interpretation, and Integrated 2D Modeling; 

Paradox Valley High-Resolution Aeromagnetic Survey. Prepared for 

Bureau of Reclamation, Glendale, Colorado. 

______. 2017. Final Report: Aeromagnetic Interpretation: 3D Modeling. 

Paradox Valley High-resolution Aeromagnetic Survey. Prepared for 

Bureau of Reclamation, Glendale, Colorado.

Yeck, W. L, L. V. Block, C. Wood, and V. M. King. 2015. “Maximum magnitude 

estimations of induced earthquakes at Paradox Valley, Colorado, from 

cumulative injection volume and geometry of seismicity clusters.”

Geophysical Journal International 200:322–336. doi:10.1093/gji/ggu394. 
Appendix C

List of Presentations Made at the CRB Meeting in 

Denver, July 25-27, 2017

September 2017 USBR Paradox Valley Unit, Consultant Review Board C-1

Report on the Second Injection Well Alternative

APPENDIX C

LIST OF PRESENTATIONS MADE AT THE CRB

MEETING IN DENVER, JULY 25-27, 2017

1. Paradox Valley Unit EIS Alternatives Studies, Introduction. US Bureau of 

Reclamation.

2. Compilation of Well Data. US Bureau of Reclamation.

3. Geology. David List. 

4. Paradox Valley Unit Seismic Data Interpretation. Project Overview by John 

F. Arestad, Ph.D.

5. Consultant Review Board (CRB) Meeting Paradox Bain Gravity and 

Aeromagnetics Interpretation. Michal Ruder, Wintermoon Geotechnologies, 

Inc. 

6. Identification of Deformation in Paradox Valley using InSAR. US Bureau of 

Reclamation.

7. Integrated Geologic Model. US Bureau of Reclamation.

8. Paradox Valley Project, Geomechanical and Flow Modeling, Verification 

Tests, Results for Biotcoefficient < 1, and Detailed Results. Christine 

Detournay, Ed Dzik, Itasca Consulting Group, Inc.

9. Deep-Well Drilling Appraisal and Feasibility Study, Paradox Valley Unit. 

Lewis Wandke, P.E.; Hal Demus, M.S.; Ken Cooper, P.E.; Petrotek 

Engineering Corporation. 

10. Integrated Geologic Model In Situ Stress. US Bureau of Reclamation.
C. List of Presentations Made at the CRB Meeting in Denver, July 25-27, 2017

C-2 USBR Paradox Valley Unit, Consultant Review Board September 2017

Report on the Second Injection Well Alternative

11. Seismicity and Pressures Following the 2013 Change in Injection Operations 

at the Paradox Valley Unit. US Bureau of Reclamation.

12. Seismicity Constraints on Geologic Structure. US Bureau of Reclamation. 

13. Paradox Valley Unit EIS Alternatives Studies, Site Selection. US Bureau of 

Reclamation.