Questions to the CRB 

Paradox Valley Unit – Second Injection Well Location 

Consultant Review Board (CRB) Meeting No. 1, December 16-19, 2012 

Grand Junction, Colorado 

1. Are existing studies adequate to determine the feasibility and optimum location of 

a second injection well? 

2. Regarding the technical criteria considered by the existing studies for evaluating 

second injection well sites: 

a. Are the identified criteria appropriate and sufficient? 

b. Is their relative importance identified and correctly evaluated? 

c. Should additional or alternative criteria be considered? 

3. Regarding the data and approach considered by the existing studies, and their 

applicability to finding a suitable site for a second injection well: 

a. Are the existing geologic and geophysical studies adequate to reasonably 

characterize the local geologic structure? 

b. Do existing seismic reflection data provide sufficient resolution and areal 

coverage? 

c. Does information from existing wells provide sufficient stratigraphic 

control for interpreting the subsurface geologic structure? 

d. Have characteristics of potential reservoir formations adequately been 

considered, such as ultimate capacity, fracture and flow properties, 

pressure limits, and availability of suitable confining layers? 

4. Do the existing studies and documentation adequately consider the feasibility of 

drilling and maintaining the structural integrity of a second injection well? Have 

available technologies been considered fully, such as directional drilling, 

horizontal drilling, or methods for drilling and completing a well through thick 

sections of salt? 

5. If existing studies are found to be inadequate, what additional studies should be 

considered, and what are their likely relative benefits and costs? 

6. Are there other issues, opportunities, or concerns the CRB believes are 

appropriate to raise concerning the determination of an optimum location for a 

second injection well? 
Recommendation Sub‐Recommendations Benefit 

Determine whether there is any ellipticity in the production casing developed

through the Paradox Salt interval above the Leadville.

Determine if there is any shear distortion indicating slip along any bedding plane

interface between lithologies.

Determine if there is any other distortion of connections or casing that would

indicate that the hydraulic integrity of the cased wellbore could be impaired in

the future (10‐20 years).

Assess other issues such as the corrosion state of the Hastalloy and the CYS 95

casing, the presence of any scale or other debris, etc.

Perform a cement bond log of the production casing, and an assessment of well

integrity.

See if the production casing shows good bond integrity. If possible, evaluate 

significant current leakage of saline injectant upward behind the casing of the 

Perform a walk‐away VSP. Combined with microseismic data, can help refine stratigraphic model and po

higher porosity and permeability, and could also help locate the cross‐cutting 

greater precision in the NW‐SE directions, or the locations of the normal fault

the SW and NE of the PVU #1 well.

Consider installing a high‐T wall‐locking triaxial borehole accelerometer array

into the PVU #1 well .

Collect the decay of microseismic activity as the pressure gradually equilibrat

commencement of the shut‐in period, which combined with VSP, can help ref

model and possibly identify zones of higher porosity and permeability.

Execute behind‐the‐casing logs in sections of the production casing where it is

considered appropriate and valuable.

Assess the strata for any changes in the near‐wellbore environment; characte

other formations.

Perform spinner flow surveys. Find out in which intervals the formation is taking the fluid, and how much. K

profile will give insight into the potential injectivity of a second well, which co

decide where to place a horizontal well injection section to achieve maximum 

Determine if there is merit to obtaining a temperature profile in PVU #1 after a

period of non‐injection.

Could provide information about where fluid is entering the formation. Could 

indicate the degree of reservoir cooling that has taken place (which helps to h

Second Injection Well Site Selection CRB ‐ Recommendations following Dece

Evaluate the condition of the existing wellbore

Acquire additional reservoir

data in the existing wellbore

There has been no entry into the hole since 2001, so there is little information 

condition of the well. Early detection of developing problems that may event

would mean that mitigation actions could be planned in advance, or bear on 

needed. Furthermore, if such effects are detected, it may have implications fo

design of a potential second injection well.
Recommendation Sub‐Recommendations Benefit 

Clean out bottom‐hole junk. May open up the lower horizons. If opening up the lower horizons opens new 

injection capacity may be sustained while the rate of pressure increase is red

If considered desirable, and this must be assessed by experts once the workover

is partially underway, perform hydraulic fracture stimulation and the placement

of high strength proppant. Additional perforations may also be considered.

Increase the injectivity of the PVU #1 well.

Consider re‐completing the PVU #1 well with an inclined section directed in an

appropriate azimuthal direction.

Intersect a greater length of permeable rock, and perhaps intersect an adjace

northeast or to the southwest) that remains partially hydraulically isolated; in

capacity of the well and therefore decreasing the rate of pressure build‐up.

Assess whether inter‐formational leaking of saline injectant is taking place

through the Union Well pathway (up or around the casing or in the damaged

rock zone surrounding the wellbore). If there is evidence that the Union Well is a

conduit for saline injectant migration into other zones, rectify the situation by an

appropriately executed sealing program.

Ensure that injected brine remains confined below the Paradox salt.

See if there has been any borehole deformation or other evidence of salt

mobilization.

Such evidence would indicate concern for a second well location around the P

Assess the temperature change and the stress state in the Leadville Formation. Provide a data point to help constrain any reservoir modeling or other calcula

Perform wireline geophysical logs for open‐hole logging. Velocity log would help constrain the velocity model used to locate induced e

logs (such as density, natural gama, resistivity) would help constrain the subs

Perform a walk‐away VSP in the Union Well in conjunction with collecting 6‐12

months of microseismic data during continued injection into PVU #1.

Develop more refined stratigraphic model, which will be of great value in dec

the completed zone of the injection well (assuming the Union Well is not dee

a kick‐off point) because they will more clearly delineate the fault block struc

additional insight as to the pressure condition of the surrounding blocks. If th

deemed suitable as a kick‐off point, help choose the optimum trajectory for t

and the best locations for perforations.

Evaluate whether the Union Well could be re‐habilitated and re‐completed as a

second injection well, and if so, evaluate the use of the Union Well as a deviated

injection well accessing a region of the surrounding rock mass that is currently

not experiencing significant effects from the PVU #1 injection activity, and could

take a sufficient volume of saline injectant. If the adjacent blocks are already

subject to pressure increases, consider a sidetrack from the Union Well involving

a horizontal well segment to access the strata in the vicinity of the Conoco Well

(under the salt diapir).

Retrofiting an existing well for a second injection well may reduce drilling cos

injection well near the existing pumping plant eliminates the need to constru

facility, thereby reducing initial installation cost and long‐term PVU operating 

If drilling the second well is considered to be the best alternative, convert the

Union Well into a monitor well for pressures in several horizons (e.g. above the

salt) as well as installation of geophysical instrumentation (e.g. downhole

accelerometers).

More precisely delineate the locations and evolution of induced seismicity; he

flow and stress evolution.

Re‐enter the Union Well

Perform a workover of the

existing wellbore
Recommendation Sub‐Recommendations Benefit 

Perform pressure‐time analysis on PVU #1 pressure build‐up data and the

pressure fall‐off data dating back from the beginning of injection and done on all

the high quality data since that time.

Determine whether there is a strong mechanical skin effect, whether the pres

sealing faults can be identified and verified, and whether the flow regime has 

evaluate whether the gradual pressure‐build up is indeed a far‐field pressuriz

more related to near‐field flow impairment processes that might be rectified 

Consider a careful analysis of the pressure decay after a shut‐in for several days

or weeks (a well‐test expert should be consulted in this regard). Determine if

this information is valuable enough to warrant a shut‐down of PVU #1 for a

period of (for example) three weeks while carefully monitoring the pressure

decay and the alterations in the microseismic response.

Understanding the pressure response of the far‐field and how it affects the m

level (magnitude, frequency, location, and motion) may give quantitative insi

propagation of the pressurized region.

Analyze the microseismic data using tomographic techniques to refine the 3D

velocity model, which would in turn refine the microseismic locations .

Obtain insight into whether adjacent faults are sealing or non‐sealing, refine t

throws so that more guidance to future drilling can be given, locate zones of h

through detailed analysis of the seismic attributes of a superior seismic mode

decision on which direction to drill a deviated wellbore.

Assess the spatial and magnitude evolution of the microseismic data in terms of

the probability of length flow paths (distant pressurization phenomena).

Provides insight about far‐field pressurization of the reservoir, which is releva

increasing injection pressures at the well.

Provide images that allow the assessment of the time and space migration of the

microseismicity, tied to the stratigraphy as much as possible. Pseudo 3‐D images

with microseism magnitude (size of bubble) location and time (color coded)

could be developed.

Visual aid for interpretation of induced seismicity.

Consider performing more in‐depth study of core and drill cuttings. Potentially identify additional permeable zones for injection. Use for calibrat

regional stress analysis?

Consider re‐analysis of existing seismic reflection data, but only if these data are

enhanced through the addition of supplementary data such as a tomographic

analysis of the microseismic data, and perhaps some new seismic information

such as Vertical Seismic Profiling (VSP) data near the PVU #1 well.

Modern analysis techniques may improve the quality of the seismic reflection 

improve the accuracy of the subsurface geologic models.

Develop a simple volume balance model. Inputs to this model would be average

porosity, location of assumed sealing faults (and hence areal extent of fluid

displacements), displacement efficiency of the invading fluid, assumptions as to

the vertical extent of the sweep, and so on.

Study (estimate) the lateral extent of the zone that has been invaded by injec

Perform some simple convective heat transfer calculations. Estimate the volume of rock that might have been cooled because of the low

injection water. This can then be compared to the assumed thickness of the L

is taking brine, and a few simple thermoelastic calculations can be done.

(Not strong recommendation) Consider commissioning a geomechanics

simulation expert to carry out some preliminary (first‐order) calculations of the

changes in the poroelastic stress field arising from the increased pressure and

the convective‐conductive heat transfer effects around PVU #1, assuming that

the BoR injection block is sealed to the NE and SW by bounding faults and that

pressure transmission and flow is dominantly to the NW and SE.

Although this will be a rough model, it may, in combination with the microsei

refined stratigraphic model from the VSP, microgravity survey, and other acti

changes taking place in the stress fields and therefore the evolution of the mi

Request an opinion of a reservoir engineer as to the feasibility of a simple (single‐

phase flow) reservoir simulation of the PVU #1 injection geo‐system at depth.

Estimate the spatial extent of brine intrusion into the reservoir and pressuriza

Analyze existing pressure‐flow

data

Analyze existing earthquake

data

Analyze other PVU data
Recommendation Sub‐Recommendations Benefit 

Perform a microgravimetric survey. Could provide more detail on the distribution of salt because of the sharp den

between salt and the other lithologies at depth; help extend the value of the 

borehole information and help identify superior targets for the trajectory of a 

Union Well side‐track.

Perform an aeromagnetic survey. Provide better constraints on the locations and throw of the faults at depth; h

of the existing seismic and borehole information and help identify superior ta

of a second well or a Union Well side‐track.

Evaluate other nearby well locations for possible installation of downhole

accelerometers arrays.

Would improve depth constraints on earthquake locations and provide additi

velocity model.

High‐resolution 3‐D seismic reflection survey is not likely to give a great deal of

additional structural information because of the rugged topography ‐ NOT

recommended.

Likely to have small benefit and high cost. 

Examine drilling logs and records of the nearest offset wells (at least the Union 1‐

0‐30 and the Conoco wells, perhaps also the Chicago 1) for any evidence of lost

circulation, drilling problems, or other information that could be valuable.

Assess conditions at depth and the approach to future drilling at a selected si

Examine other plugged and abandoned wells in the region for possible re‐entry

and use, including the possibility of deepening the existing wellbore, drilling a

deviated well from an intermediate depth, and horizontal section installation for

the injection portion to increase injectivity (only if other options deemed

unsuitable)

May reduce drilling costs. Also, if the existing well was previously drilled thro

formation, then we would have apriori information about the reservoir chara

location. This would reduce the risk of selecting a site with poor reservoir pot

Examine Lisbon Oilfield, where there exist far more detailed structural data and

geological studies, for geologic analogues

May aid in the geologic interpretation of the existing well, seismic reflection, 

A better understanding of the subsurface geology would be beneficial for the 

second injection well.

Seek ways of reducing surface facilities costs and avoiding duplication of surface

facilities, such as locating a second well‐head nearby so that short‐distance

pipelining of pressurized brine can be used, and so on.

Reduce the cost of a second injection well.

Down‐grade injection sites that would increase the induced seismicity level near

to populated areas in terms of suitability.

Reduce seismic risk to local population.

If a second injection well is deemed necessary but the Union Well cannot be re‐

used, the second well should be drilled relatively close to PVU #1 and deviated

laterally to intersect the most appropriate fault blocks and high permeability

zones as delineated by the additional investigation activities that have been

recommended.

The drilling and wellhead can be located close to existing facilities, create a lo

disturbance in the region, reduce NEPA and land management costs, and be e

Long‐term PVU expenditures would be lower for maintaining one injection fa

Deviated and horizontal trajectories from existing wellbores are likely to be

considerably less costly than new wells.

reduce cost.

Evaluate existing area well &

geologic data

Recommendations for site

selection criteria

Perform new geophysical

surveys
Recommendation Sub‐Recommendations Benefit 

Develop a comprehensive ROAD MAP, based in part on this report and on input

from the experienced professionals of the BoR.

Would help to make most effective decisions and lead to a final site selection 

focus on tasks providing greatest benefit to site selection process. Aid in coo

among different groups.

Implement a semi‐quantitative cost‐benefit approach. Evaluate the cost‐benefit

of gravimetric, aeromagnetic, and related geophysical surveys in the context of

refinement of the geological models for site selection of the second well .

Assess what actions are the most likely to reduce uncertainty incrementally a

series of logical steps.

Recommendation Sub‐Recommendations Benefit 

Consider installing a designed row of groundwater wells that can inject fresh

water.

Create barriers to flow through the reduction of hydraulic head and, in the lo

flow rate by increasing the magnitude of the sink, therefore contributing to th

the salt at depth, which could result in less saline water to inject and delay th

additional deep drilling activity is required.

Fully evaluate alternatives to second well, including evaporation ponds and land

use, pumping or diverting fresh groundwater to reduce deep saline dissolution

rates, solar desalination to generate fresher water, or some optimized

combination of these alternatives.

Reduce the continued injection rate demands on PVU #1 well.

Perform a detailed hydrological study of the Paradox Valley to the northwest of

the Dolores River, including modeling to allow sensitivity analyses and impact

assessment.

Assess the possibility of reducing the amount of saline brine coming into the s

redirection and pumping, by groundwater management using shallow wells a

Evaluate the option of increasing the injection pressure limit in PVU #1 by

perhaps 1000 psi .

This would effectively extend the life of the well for a number of years, given 

there is a reasonable possibility that the increased pressures will have favorab

effects on the available flow paths by increasing the transmissivity of fracture

of increased pore pressures and lowered effective stresses.

Consider the merits of filtering to 3 micrometer particle size. Reduce cost. 

Recommendation for well

completion

Consider the possibility of using new casing materials such as carbon‐fiber

reinforced plastics instead of hyper‐expensive metal alloys.

Reduce the cost of a second injection well. 

Continue to perform forward‐looking probabilistic analyses of the evolution of

seismicity magnitude and location.

Assess the impact of injection on the local community and land use. 

View PVU as a long‐term experiment (applied science project) and consider

undertaking more explicit cooperation with appropriate research organizations

and universities .

Use PVU's activities to train highly qualitifed personnel for the scientific comm

become a case study for future seismic methods and modeling methods. PVU 

template and case history with ramifications for other areas. Leverage the va

and long‐term analyses.

Recommendations for

injection operations

Rcommendations for data

analysis

Evaluate alternatives to

increasing injection capacity

Approach to site selection

ADDITIONAL RECOMMENDATIONS (OUTSIDE SCOPE OF CRB):
Second Well Site Investigation Flowchart

STEP 1: Determine whether the pressure build-up in PVU well #1 is due primarily to 

near-wellbore flow impairment or far-field reservoir pressurization.

STEP 2A: Evaluate the condition of 

PVU injection well #1 to determine 

whether a work-over is feasible and 

is likely to produce long-term 

benefit.

near-wellbore flow 

impairment

far-field reservoir 

pressurization

STEP 2B: Determine whether there 

is a nearby fault block that has not 

experienced significant 

pressurization and can take a 

sufficient volume of injectate. If a 

fault block is identified, assess the 

associated seismic risk and drilling 

options.

workover is not 

feasible

or sufficiently 

beneficial

STEP 3: Look for a second well site 

location at a significant distance 

from PVU Injection Well #1.

nearby isolated fault block 

cannot be identified or does 

not have sufficient capacity, 

or injection into the identified 

block adversely affects the 

seismic hazard
Second Well Site Investigation Roadmap 

STEP 1: Determine whether the pressure build-up in PVU Well #1 is 

due primarily to near-wellbore flow impairment or far-field reservoir 

pressurization. 

Recommended actions: 

1. Perform simple pressure-flow modeling of existing PVU injection data. (Look for 

evidence of: a strong mechanical skin effect, and changes in the skin effect over time; 

changes in the flow regime over time (infer presence of impermeable faults); changes in 

permeability over time.) 

2. Analyze the spatial and magnitude evolution of induced seismicity over time. (Look 

for evidence of: lengthy flow paths; far-field pressurization; impermeable faults; 

hydraulic connectivity between the upper Leadville and lower target intervals - is there 

evidence that fluid is still getting into the lower target intervals even though the lower 

perforated zones are blocked within the wellbore?) 

Work to date: 

Substantial analyses relevant to whether the pressure build-up in the injection well is due 

to near-wellbore flow impairment or far-field pressurization have been performed. The 

results of these analyses indicate that the increasing injection pressure is most likely not

due primarily to near-wellbore flow impairment, but rather represents the far-field 

reservoir response to the applied flow rates. 

The pressure-flow modeling completed to date suggests that the gradual increase in 

injection pressure is simply a result of injecting into a low-permeability reservoir for an 

extended period of time. Modeling of the pressure-flow data from the last 10 years shows 

no indication that the flow regime has changed in recent years or that a strong mechanical 

skin effect has developed over time. In addition, correlation of the occurrence of induced 

earthquakes with long-term trends in injection pressure suggests that pore pressures are 

considerably elevated to at least a distance of 2 km from the injection well, where the 

majority of the largest-magnitude (M3.5+) events occur. 

Spatial-temporal analyses of the induced seismicity data suggest that pore pressure 

changes may propagate relatively quickly along a network of pre-existing faults from the 

injection well to distances of several km from the well. The onset of seismicity 6 to 8 km 

northwest of the injection well (in the NW cluster) soon after the start of continuous 

injection (July 1996) suggests that a relatively high-permeability flow path may exist 

from the vicinity of the injection well to the northwest. The occurrence of the local 

magnitude ML 4.4 earthquake 8 km northwest of the well in January 2013, as well as the 

significant decline in seismic activity in that area a few months after injection was 

suspended following the earthquake (and then resumed at a reduced flow rate), suggest 

that the hydraulic connectivity between the injection well and the NW cluster has become 
stronger over time. The increased occurrence rates in distant seismicity clusters (SE 

cluster and northern-valley clusters) and the occurrence of shallow seismicity (~5 to 6 km 

deep) beneath central Paradox Valley observed in recent years also imply that far-field 

reservoir conditions are changing. 

The distribution of earthquake hypocenters in the near-well area (within 4 km of the well) 

shows that the earthquakes occur over a depth range exceeding one kilometer. Substantial 

seismicity occurs both several hundred meters below and several hundred meters above 

the elevation of the perforated zones in the Leadville formation in the injection well. The 

vertical distribution of the seismicity appears to be largely controlled by the locations of 

northwest-trending normal faults, with the earthquakes generally becoming shallower 

toward the southwest away from the well. In addition, the hypocenters appear to be 

distributed along near-vertical pre-existing faults that may allow vertical propagation of 

pore pressure across sub-salt formations. Assuming that the locations of the induced 

earthquakes have some correspondence with the distribution of pore pressure increase 

and fluid flow, these analyses suggest that blockages in the injection well across the 

deeper perforated zones are not preventing fluid from reaching the deeper target 

formations. 

Proposed near-term tasks: 

The pressure-flow modeling should be finalized. Results from the pressure-flow 

modeling and earthquake analyses relevant to the determination that the injection 

pressures are due to far-field reservoir response should be documented, either in separate 

reports or in a combined technical memorandum. 
STEP 2A: If the pressure build-up is due primarily to near-wellbore 

flow impairment, evaluate the condition of PVU injection well #1 to 

determine whether a work-over is feasible and is likely to produce longterm benefit. 

Recommended actions: 

1. Examine all relevant reports to determine known conditions within the wellbore. 

2. Determine whether the risk of re-entering the wellbore to further assess borehole 

conditions is acceptable. 

 

If risk of wellbore re-entry is acceptable: 

3. Enter the wellbore and assess conditions to determine whether a work-over of the well 

is advisable – is the wellbore in good enough condition to last another 10 to 20 years? 

(Look for ellipticity or distortions of casing; run cement bond log; assess corrosion state 

of casing and degree of scaling.) 

 

If wellbore is in sufficiently good condition to last another 10 to 20 years: 

4. Perform further surveys to determine whether a work-over is likely to be beneficial – 

can near-well flow impairment be identified? (temperature log; spinner flow survey; 

geophysical borehole logs)

If surveys indicate near-wellbore flow impairment, consider improving the nearwell flow by doing one of the following: 

5a. Cleaning out the lower section of the borehole; performing hydraulic fracture 

stimulation and possibly the placement of high strength proppant.

OR 

5b. Re-completing the lower section of the borehole, possibly with an inclined section to 

intersect a greater length of permeable rock. If this option is chosen, then additional 

surveys should be considered to better define the nearby stratigraphy and determine the 

optimum location for the new bottom of the borehole prior to re-completion (vertical 

seismic profiling (VSP) survey; passive microseismic survey with borehole 

accelerometer array; analyses of core samples). 

Follow-up: Monitor pressure over time to determine whether a second injection well is 

still needed. 

Work to date: 

A report written subsequent to the last borehole evaluation, performed in 2001, has been 

reviewed (Subsurface, 2001). This report indicates a diameter restriction in the borehole 

casing in the upper Leadville, at and below a depth of 14,138 feet. A review of logging 

attempts from 1988 to 1994 indicates that the borehole diameter below this depth became 

progressively smaller with time, to less than 4.25 inches in 1994 (Subsurface, 2001). A 

caliper survey run in 2001 indicates a second potential casing restriction above the 

Leadville Formation, at a depth of 14,043 ft. However, the presence of a magnetic marker 
at this depth may have biased the results. The report also indicates lost tools in the 

borehole and sulfur filling the hole up to 14,070 feet depth. At the time of the last 

borehole entry in 2001, only the upper Leadville Formation perforations were clear and 

not covered with fill. Risk of performing any type of borehole surveys near the depth of 

the Leadville is considered very high, as the loss of additional tools in the borehole could 

cause further blockage of the perforated zones. Since no other salinity control measure is 

currently in place, a loss of production in PVU Well #1 in the near future would be very 

detrimental to the project. 

Proposed near-term tasks: 

None. Based on the analyses completed to date (described under STEP 1), we do not 

believe that the pressure increase in the injection well is due primarily to near-wellbore 

flow impairment. Hence, a work-over of the well to increase injectivity is not likely to 

produce substantial long-term benefit. In addition, because of the condition of the 

borehole, the proposed borehole surveys and potential work-over procedures would also 

pose substantial risk to current operations. The borehole investigations proposed above 

may be re-considered at some later date after an alternative salinity control measure is in 

place, the pressures in the injection target formations in the vicinity of PVU Well #1 have 

had sufficient time to decline, and additional injection into this well is being considered. 
STEP 2B: If the pressure build-up is due primarily to far-field 

pressurization, or a work-over of the existing well is not feasible,

determine whether there is a nearby fault block that has not 

experienced significant pressurization and can take a sufficient volume 

of injectate. 

Recommended actions: 

1. Analyze earthquake data using tomographic techniques. Use the earthquake locations 

and associated velocity model to enhance the subsurface geologic interpretation from 

seismic reflection and well data. 

2. Re-process existing PVU seismic reflection data and/or purchase additional seismic 

reflection data, if considered beneficial based on the results of the earthquake analysis. 

Field acquisition of additional seismic reflection data, which would be considerably more 

expensive than purchasing existing data, should only be considered after existing datasets 

have been reviewed. Acquisition of new seismic reflection data may be considered if: the 

existing data are of poor quality and data acquired with newer methods are expected to 

have substantially improved quality; the existing data do not extend to areas of interest; 

the microgravimetric and aeromagnetic data proposed in item 3 below do not provide 

adequate subsurface information.. 

3. Determine if microgravimetric and/or aeromagnetic data are likely to enhance the 

subsurface geologic models and, if so, collect and analyze such data. 

4. Perform a simple volume balance model to estimate the lateral extent of the zone that 

has been invaded by brine. 

5. Perform simple conductive heat transfer calculations to estimate the volume of rock 

that has been cooled. 

If one or more nearby fault blocks that have not experienced significant 

pressurization have been identified: 

6. Calculate initial, rough estimates of the identified fault block(s) reservoir volume, and 

evaluate whether the anticipated volume is sufficient to make injection into any of the 

identified blocks economically viable. The initial estimates of reservoir volume would be 

calculated using the final subsurface geologic interpretation from the geophysical 

methods described above and assumed ranges of potential reservoir thickness and 

effective porosity. Economic viability would also need to be defined; a proposed viability 

threshold might be 25 to 30 years of near-continuous injection at flow rates comparable 

to those attained in the current well. 

7. Evaluate the seismic hazard associated with injecting into the identified fault blocks. 

[Would new seismicity likely be induced closer to or farther from populated areas? Could 

a geographical expansion of the seismically-active area increase the probability of 
inducing a larger magnitude earthquake (if, for example, injection were to be alternated 

between a new, relatively nearby second well and the existing well at some point in the 

future)?] 

If injecting into the nearby fault block(s) is judged to be economically viable and 

would not substantially increase the seismic hazard: 

8. Assess strategies for drilling into the identified fault block(s), and drill an 

exploration well and/or the second injection well if an acceptable drilling strategy 

can be implemented. 

Initially, an exploration well is needed to determine local reservoir characteristics in the 

targeted fault block. Because of the spatial variability in Leadville porosity, fracture 

permeability, and thickness, the initial estimate of reservoir capacity determined in step 6 

would contain substantial uncertainty. Evaluation of the reservoir capacity would need to 

be refined after an exploration well is drilled into the targeted fault block(s) and 

geophysical well logs, core samples, and flow test data are analyzed. If tests performed in 

the exploration well confirm the presence of a good reservoir formation for brine 

disposal, then either this well could be completed as the second PVU injection well, or a 

separate well could be drilled for long-term injection. 

Many factors would need to be considered when assessing strategies for drilling the 

exploration and long-term injection well(s). These include land use and access, and the 

relative costs, risks, and benefits of vertical and diagonal drilling methods. The CRB 

specifically recommended, if possible, installing the wellhead for the second injection 

well near the current pumping plant, using one of the following drilling strategies: 

 Re-completing the lower section of PVU Injection Well #1, diagonally drilling to 

access the identified adjacent fault block(s). In this scenario, PVU will only have 

one injection well rather than two. 

 Re-entering the Union well and re-completing the lower section, diagonally 

drilling to access the identified adjacent fault block(s). 

 Drilling a new well in the near vicinity of the current injection well and pumping 

plant, and diagonally drilling to access the identified adjacent fault block(s). 

Installing the wellhead near the current pumping plant would eliminate the need to 

construct a second pumping plant, which would reduce both initial installation cost and 

long-term operating cost. It would also greatly simplify the Environment Impact Study 

process. Potential drawbacks might include: complications with drilling through 

pressurized rock; increased cost and complications associated with drilling diagonally 

(rather than vertically); and potentially reduced reservoir capacity compared to locating a 

second injection well at a greater distance from the first well. Reclamation would need to 

hire experts in drilling methods to evaluate these and alternative drilling strategies for the 

exploration and injection well(s). 
Work to date: 

We have been analyzing the earthquake data using tomographic techniques since the mid1990s. Methods have been gradually improved over the years, to refine the subsurface 

velocity models and improve the earthquake hypocenter estimates. We have used the 

spatial distribution of earthquake hypocenters in the near-well area and NW and SE 

clusters to infer the locations of NW-trending normal faults. Recent analysis of the 

hypocenters also indicates that the NW-trending normal faults may be offset by a major 

shear zone south of the injection well. If this interpretation is correct, then there may be 

fault blocks southeast of the well that have not experienced substantial pressurization and 

may be potential targets for a second injection well. Additional work is in progress to try 

to improve the spatial resolution of the subsurface velocity models (computed from the 

earthquake data) and determine whether the presence of the interpreted shear zone can be 

confirmed by analysis of the velocity structure. In addition, surface seismic reflection 

lines, some already owned by Reclamation and some available for purchase, have been 

identified that may help confirm this geologic interpretation. 

Proposed near-term tasks: 

Complete the high-resolution velocity analysis using the induced seismicity data. 

Evaluate whether re-processing and/or purchasing of selected existing surface seismic 

reflection lines is beneficial. An expert on seismic reflection data processing may need to 

be consulted to evaluate the quality of the existing datasets prior to making a decision. 

After analyses of the earthquake and seismic reflection data are complete, determine 

whether acquisition of microgravimetric and/or aeromagnetic data is advisable. Results 

from the earthquake analysis and seismic reflection analysis may help judge whether 

additional confirmation of the subsurface geologic interpretation is needed. Also, insights 

gained from analysis of the existing earthquake and reflection data may aid in 

determining the acquisition parameters of the gravity and/or magnetic surveys. Because 

experience with these types of methods is limited within Reclamation, one or more 

experts on these methods would likely need to be retained to evaluate their costs and 

benefits and to aid in design of the surveys. 

The simple volume balance and heat transfer calculations proposed by the CRB 

(recommended actions 4 and 5 above) could be performed at any time. Simple volume 

balance calculations have been done by PVU in the past and could be updated fairly 

easily. Simple heat transfer calculations could also be done in-house at relatively small 

expense. 

Evaluation of the seismic hazard associated with drilling into adjacent fault blocks (action 

7) should be addressed through a consultant review board process. A CRB is already 

planned for later this fiscal year for reviewing the seismic hazard associated with PVU 

fluid injection, and this would be an appropriate topic to include in that review. 
STEP 3: If a nearby fault block that has not experienced significant 

pressurization cannot be identified, or if it is determined to have 

insufficient reservoir volume, or if pressurizing it would adversely 

impact the seismic hazard, look for a second well site location at a 

greater distance from PVU Injection Well #1. 

Recommended actions: 

1. Review existing well and seismic reflection data in SE Paradox Valley for usefulness. 

(SE Paradox Valley has lower population than NW Paradox Valley and has not 

experienced induced seismicity from PVU Injection Well #1.) 

2. Consider whether acquiring microgravimetric and/or aeromagnetic data is likely to 

provide additional constraints for selecting the well site and, if so, collect and analyze 

such data. 

3. Drill an exploration well. Acquire geophysical well logs, perform core analysis, and 

perform injection flow tests to assess reservoir quality in the new well. 

If reservoir quality is good: 

4. Acquire new surface seismic reflection data and possibly vertical seismic profiling 

(VSP) data in the vicinity of the exploration well. These surveys should aid in estimating 

the capacity of the proposed reservoir (by identifying the locations of sealing faults, for 

example), to verify that the new well will have an acceptable lifespan. Results from these 

surveys could also potentially be used to optimize the bottom hole location prior to 

completing the well. 

Work to date: 

A potential site for a second injection well has been identified in East Paradox Valley 

approximately 6 miles southeast of the existing injection well. The site was chosen by 

virtue of its proximity to the brine well field and being private land, with no geologic or 

other considerations. Additional geologic and geophysical data collection and analysis of 

this site would be required. 

Proposed near-term tasks: 

Acquire existing or new geophysical data and analyze to aid in determination of 

suitability of the potential site in East Paradox Valley mentioned above. Geophysical 

methods that might be useful include microgravimetric, aeromagnetic, and seismic 

reflection surface surveys. 
References 

Davis, Ken E., 1988, Justification Not to Reenter Union Oil Company’s 1-0-30 Otho 

 Ayers Well, Montrose County, Colorado, Contract No. 4-CA-40-01660, Paradox 

 Valley Unit, Phase II, Task 2(c), KEDA Project No. 10-1086, Ken E. Davis 

 Associates, Inc., Houston, Texas, 8 pp.

Dusseault, M. B., Davis, T., Eustes III, A. W., Nunn, J., 2013, Assessment of a Potential 

 Second Injection Well Site in the Paradox Valley Unit Saline Water Disposal 

 Project, The Bureau of Reclamation Paradox Valley Unit, Atkins Project No., 

 10003079, 37 pp. 

Subsurface, 2001, Report of Operations, United States Department of the Interior, 

 Bureau of Reclamation, Montrose County, Colorado, Subsurface Project No. 

 60D5207, Subsurface Technology, Inc., Houston, Texas, 17 pp. 

Wood, C., King, V., Block, L., and Yeck, W., 2013, The ML 4.4 Earthquake of January 

 24, 2013, Near Paradox, Colorado, and Implications for Near-term Injection 

 Operations (Draft), Technical Memorandum No. TM-86-68330-2013-12, Bureau 

 of Reclamation, Denver, Colorado, 125 pp.