U.S. Department of the Interior 

Bureau of Reclamation November 2015 

Technical Memorandum TM-85-833000-2014-45 

Considerations in Raising the 

Maximum Allowable Surface 

Injection Pressure (MASIP) at 

Paradox Valley 

Colorado Basin Salinity Control Project, 

Paradox Valley Unit, Colorado 

Upper Colorado Region 
Mission Statements

The mission of the Department of the Interior is to protect and 

provide access to our Nation’s natural and cultural heritage and 

honor our trust responsibilities to Indian Tribes and our 

commitments to island communities.

The mission of the Bureau of Reclamation is to manage, develop, 

and protect water and related resources in an environmentally and 

economically sound manner in the interest of the American public.
BUREAU OF RECLAMATION 

Technical Service Center, Denver, Colorado 

Seismology, Geomorphology, and Geophysics Group, 85-

833000 

Technical Memorandum TM-85-833000-2014-45 

Considerations in Raising the Maximum 

Allowable Surface Injection Pressure 

(MASIP) at Paradox Valley 

Colorado Basin Salinity Control Project, 

Paradox Valley Unit, Colorado 

Upper Colorado Region 

 

 

 

Peer Review Certification 

This report has been reviewed and is believed to be in accordance with the service 

agreement and standards of the profession. 

Peer reviewed by: 

iii

Contents

Page

1 Introduction ......................................................................................................................................... 1

2 Project Background ............................................................................................................................ 5

2.1 PVU Injection History .................................................................................................................... 5

2.1.1 Phase I (July 22, 1996 - July 25, 1999) ................................................................................ 5

2.1.2 Phase II (July 26, 1999 - June 22, 2000).............................................................................. 5

2.1.3 Phase III (June 23, 2000 - January 6, 2002)......................................................................... 5

2.1.4 Phase IV (January 7, 2002 – January 24, 2013) .................................................................. 6

2.1.5 Phase V (April 17, 2013 – Present)....................................................................................... 6

2.2 Injection Pressures........................................................................................................................ 8

2.3 Geology ......................................................................................................................................... 9

3 MASIP Calculations ..........................................................................................................................15

3.1 Relevant PVU Well Logging........................................................................................................15

3.1.1 Intermediate Hole Logging (14,050-2,020 ft; upper Leadville - Cutler):..............................15

3.1.2 Liner Hole Logging (15,950-14,050 ft) (Precambrian – upper Leadville):...........................19

3.2 Evaluation of the Confining Layer ...............................................................................................21

3.3 MASIP Calculations ....................................................................................................................23

3.4 Requirements to increase the MASIP.........................................................................................26

4 Induced Seismicity............................................................................................................................27

4.1 Plan View Evolution of Induced Seismicity .................................................................................27

4.2 Vertical Extent of Induced Earthquakes......................................................................................32

4.3 Effects of Increasing the MASIP .................................................................................................41

4.3.1 Induced Seismicity and its Relation to Pore Pressure ........................................................41

4.3.2 Maximum Earthquake Magnitude .......................................................................................42

5 Conclusions.......................................................................................................................................49

6 References.........................................................................................................................................51

Tables

Page

Table 1 - From King et al. (2014). Stratigraphy at the PVU well.................................................................11

Table 2 - Calculated stress gradients given different surface injection pressures, following the 

methodology in the 2004 EPA permit. Depths and formations correspond to those evaluated in the 2004 

permit. .........................................................................................................................................................25
iv

Figures

Page

Figure 1 - Location of the deep injection well at Reclamation’s Paradox Valley Unit in western Colorado..2

Figure 2 - Location of the Paradox Valley Unit brine extraction wells and PVU Injection Well #1. ..............3

Figure 3 - Schematic diagram of Paradox Valley Injection Test Well No. 1. ................................................4

Figure 4 – From Block et al. (2015a). Daily average injection flow rate (top), daily average surface 

injection pressure (middle), and daily average downhole pressure at 14,100 ft (4.3 km) depth (bottom) 

during PVU injection operations.................................................................................................................... 7

Figure 5 - Daily average wellhead pressures (green) and 20-day centered moving average (black) for end 

of phase IV and beginning of phase V (November, 2012 – October, 2014). The injection well was shut in 

for nearly 3 months following a ML 4.4 induced earthquake on Jan. 24, 2013. Injection resumed on April 

17, 2013, with a reduced flow rate and shorter, more frequent shut-ins. .....................................................8

Figure 6 – (Top) Location of geologic cross section B-B’. (Bottom) Cross Section B-B’ digitized and 

modified from Bremkamp and Harr (1988) and taken from King et al. (2014). There is no vertical 

exaggeration. ..............................................................................................................................................10

Figure 7 – Casing and cementing details of PVU Injection Well #1. ..........................................................16

Figure 8 – (a) Fracture closure pressure in Paradox salt and (b) Minimum effective confining differential 

as a function of Poisson’s ratio. ..................................................................................................................23

Figure 9 – From Block et al. (2015a). (Top) Daily average injection flow rate. (Bottom) Scatter plot of 

earthquakes with M ≥ 0.5 and depth < 8.5 km (relative to the ground surface elevation at the injection 

wellhead), plotted as a function of date and distance from PVU Injection Well #1. Each circle represents a 

single earthquake, with the width of the circle scaled by the event magnitude. .........................................29

Figure 10 – From Wood et al. (2015). Maps showing the geographical distribution of shallow seismicity 

recorded in the Paradox Valley area from 1991 through 2000: (top) injection tests, 1991-1995 (bottom) 

long-term injection, 1996-2000. All detected earthquakes less than 8.5 km deep (relative to the ground 

surface elevation at the injection wellhead) are included. Dashed circles show distance from the town of 

Paradox.......................................................................................................................................................30

Figure 11 - From Wood et al. (2015). M aps showing the geographical distribution of shallow seismicity 

recorded in the Paradox Valley area from 2001 through 2014: (top) long-term injection, 2001-2008 

(bottom) long-term injection, 2009-2014. All detected earthquakes less than 8.5 km deep (relative to the 

ground surface elevation at the injection wellhead) are included. Dashed circles show distance from the 

town of Paradox. .........................................................................................................................................31

Figure 12 – Previous Page. From Block et al. (2015b). Map showing epicenters of earthquakes occurring 

in the near-well region of induced seismicity, color-coded by hypocenter elevation (center), and cross 

sections showing distinct vertical offsets of hypocenters (top and bottom). Only a-quality hypocenters from 

the event relative location are included. The labels ‘W’, ‘X’, and ‘Y’ on the map identify abrupt lateral 

changes in hypocenter elevations. Two northwest-striking normal faults interpreted from the hypocenter 

elevation patterns are shown. Our interpreted base of the Paradox salt and top of the Precambrian (solid 

black lines) and the interpreted top of the Leadville formation from Katz and Carroll (1984) (dashed blue 

line) and Bremkamp et al. (1984) (dashed red line) are shown in each cross section. A simplified geologic 

section at the PVU wellbore is included at upper right for reference. Note the color-scale used in this plot 

and those in Block et al. (2015b) are distinct from those in the following figures.......................................35

Figure 13 - Map of earthquakes near the PVU injection well. Earthquakes within 0.1 km of the transect 

(black dashed line) are selected and colored by elevation (see legend). The temporal evolution of depth 

sections along this transect are shown in Figure 14...................................................................................35

Figure 14 – Time and depth evolution of earthquakes from the cross section delineated in Figure 13. 

Earthquakes are colored by elevation (depth), as in Figure 13. All earthquakes previous to each time 

window are shown as gray dots..................................................................................................................36

Figure 15 - Map of earthquakes near the PVU injection well. Earthquakes within 0.1 km of the transect 

(black dashed line) are selected and colored by elevation (see legend). The temporal evolution of depth 

sections along this transect are shown in Figure 16...................................................................................37
v

Figure 16 - Time and depth evolution of earthquakes from cross section delineated in Figure 15. 

Earthquakes are colored by elevation (depth), as in Figure 15. All earthquakes previous to each time 

window are shown as gray dots..................................................................................................................38

Figure 17 - Time and depth evolution of focal mechanisms. Time windows include: (a) 1991–1992; (b) 

1993–1994; (c) 1995–1999; (d) 2000–2001; (e) 2002–2005; (f) 2006–2014. The strike of the preferred 

fault plane is shown as a solid line, colored by elevation (see legend). (See Block et al. (2015b) for details 

of the focal mechanism analysis.)...............................................................................................................39

Figure 18 – Earthquake waveforms recorded on the vertical component at station PV16. These 

earthquakes occur in a small cluster and span a range of depths. The black line denotes the bottom of the 

salt formation at the well. While there is some change in the P-S time between events, there are no clear 

distinct arrivals which could be attributed to secondary phases (e.g., reflections off the salt formation). ..40

Figure 19 - from Block et al. (2014) (a) Injection downhole pressure data averaged over daily, 6-month, 

18-month, and 30-month time periods, (b) occurrence of induced seismicity as a function of time and 

magnitude within 5 km of the injection well, and (c) at distances of 5–10 km from the well. In the seismicity 

plots, the area of each circle is scaled by the number of events in a given quarter-year and magnitude 

range. The low seismicity rate in the smaller magnitude bins from mid-2005 to mid-2007 in the bottom plot 

is believed to be due to an unusually large number of offline stations. ......................................................44

Figure 20 – from King and Block (2015). Seismicity time-distance plots of all shallow (depth < 8.5 km) 

events with magnitude ≥ 0.5 occurring in the vicinity of the PVU injection well. Seismic triggering fronts for 

the first two significant injection tests are overlaid. The triggering fronts were computed using a 1-D linear 

pressure diffusion model and a hydraulic diffusivity of 0.20 m2

/s. ..............................................................45

Figure 21 - From Yeck at el. (2015). (a) Flow rate as a function of the cumulative injected volume. The 

gray line shows the flow rate during the injection tests (1991 - 1995), while the black line shows the flow 

rates during long-term injection (1996 – 2013). (b) Observed maximum magnitude PVU-induced 

earthquakes as a function of the cumulative injected volume. Least squares fit shown in black, with 95% 

confidence interval (black dashed) and 95% prediction interval (gray dashed). ........................................46

Figure 22 - From Yeck at el. (2015). Maximum crack radius and maximum earthquake magnitude as a 

function of time for the A) Nearwell, B) Northwest, and C) Southeast clusters. Observed maximum 

magnitudes through time are shown as crosses and stars.........................................................................47

1

1 Introduction

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

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

Basin Salinity Control Program (CRBSCP). The Colorado River Basin Salinity Control Act of 

1974 authorized the PVU for construction (Public Law 93-320; amended in 1984 as Public Law 

98-569). The objective of the PVU is to reduce the salt load of the Colorado River. The Dolores 

River, a tributary of the Colorado River, picks up nearly 185,000 metric tons of salt annually 

from natural brine groundwater inflow in the Paradox Valley. Because Paradox Valley overlies a 

salt anticline, groundwater in the valley has a salt concentration nearly eight times that of ocean 

water. Currently, the PVU diverts up to 90 percent of Paradox Valley brine inflow from entering 

the Dolores River. Subsurface brine flow is intercepted by the pumping of shallow extraction 

wells located along the river (Figure 2). The extracted brine is collected and filtered at a surface 

treatment facility, piped 3.6 miles (6 km) to a facility at the edge of the valley, and injected into a 

15,900-ft (4.8-km) deep injection well (PVU Injection Well #1) for long-term disposal. The 

injection well disposes of brine in a narrow target zone over the lowest 1,700 ft (500 m) of the 

borehole. Mississippian-age limestone takes the majority of injected brine. The in-situ formation 

water is brine and is therefore not considered a source of potable water. Details on the PVU 

project background, purpose, and benefits appear in Reclamation’s environmental assessment 

(Bureau of Reclamation, 1997) as well as the Environmental Protection Agency (EPA) injection 

well permit fact sheet (Environmental Protection Agency, 1997). Figure 3 shows a schematic of 

the well, including the injection intervals. 

PVU has injected brine more or less continuously since 1996, using between one and three 

constant-rate pumps. In recent years, the wellhead pressure obtained in response to the applied 

flows has increased. The trend of injection pressures from 2009 to 2012 suggested that the 

maximum allowable surface injection pressure (MASIP) could be reached within a few years. 

The MASIP, specified in PVU’s operating permit from EPA, was designed to prevent injected 

brine from breaching a confining layer of salt that lies above the injection target zone and thus 

prevent contamination of shallow, potentially potable groundwater. In response to a local 

magnitude (ML) 4.4 induced earthquake, the flow rate was reduced in early 2013, and maximum 

injection pressures subsequently decreased. Pressures are expected to gradually increase, even at 

the reduced flow rate, and may eventually reach the current MASIP. If this occurs, the volume of 

brine injected annually would need to be further reduced, decreasing the efficiency of operations 

and making PVU less economically viable.

As a long-term solution, Reclamation is currently evaluating other salinity control alternatives, 

such as a new injection well or evaporation ponds. While these projects may allow the PVU to 

continue to operate in the long-term, the design and implementation of a salinity control 

alternative requires considerable time. Therefore, in the interim, a short-term solution may 

become necessary. This report summarizes background information relevant to any consideration 

of whether an increase in the MASIP could be a viable short-term solution to the increasing 

injection pressures in PVU Injection Well #1. Information presented in this report includes PVU 

injection history, local geology, geophysical well logging data from the PVU injection well, a
2

review of the analyses used to design the current MASIP, and a discussion of the possible effects 

of an increased MASIP on future induced seismicity. 

Figure 1 - Location of the deep injection well at Reclamation’s Paradox Valley Unit in western Colorado.
3

Figure 2 - Location of the Paradox Valley Unit brine extraction wells and PVU Injection Well #1.
4

Figure 3 - Schematic diagram of Paradox Valley Injection Test Well No. 1.
5

2 Project Background

2.1 PVU Injection History

Reclamation began long-term (near-continuous) injection at PVU in 1996, following a series of 

injection tests conducted between 1991 and 1995. The operational parameters for long-term 

injection have been changed four times, either in response to large magnitude earthquakes, or in 

an effort to improve injection economics. These injection phases are briefly summarized below. 

More detailed descriptions of the injection history are available in other Reclamation reports 

(Block et al., 2015a; King and Block, 2015). Plots of the daily average injection flow rate, 

surface injection pressure, and downhole pressure (at a depth of 14,100 ft (4.3 km)) throughout 

the history of PVU injection operations are shown in Figure 4.

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

During the initial phase of long-term injection, PVU injected at a nominal flow rate of 345 gpm 

(~1306 l/min), at about 4,950 psi (~34.1 MPa) average surface pressure. To maintain this flow 

rate, PVU used three constant-rate pumps, each operating at 115 gpm. When the surface pressure 

approached the MASIP of 5000 psi, PVU shut down one or two injection pumps, thus reducing 

the injection rate and allowing the injection pressure to drop. These shutdowns occurred 

frequently and lasted for minutes, hours, or days. The shutdowns resulted in an overall average 

injection rate for phase I of ~300 gpm (1136 l/min). The injectate during phase I was 70% 

Paradox Valley Brine (PVB) and 30% fresh water.

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

Following ML 3.6 and ML 3.5 induced earthquakes in June and July, 1999, PVU altered injection 

to include a 20-day shutdown (i.e., a “shut-in”) every six months. The injection pressure and 

flow rate were the same as during phase I. 

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

Immediately following a local magnitude (ML) 4.3 earthquake on May 27, 2000, PVU shut down 

injection operations for 28 days. On June 23, 2000, PVU resumed injection with two pumps 

rather than three. This change decreased the injection flow rate by 33% compared to earlier 

phases, to 230 gpm (~871 l/min). Accounting for the two 20-day shut-ins per year, the average 

injection flow rate was approximately 205 gpm (776 l/min), a decrease of about 32% compared 

to phase I. The 70:30 ratio of brine to fresh water and the biannual 20-day shutdowns were 

maintained.
6

2.1.4 Phase IV (January 7, 2002 – January 24, 2013)

In 2001, Reclamation re-evaluated whether dilution of PVB with fresh water prior to injection 

was still necessary. After this review, Reclamation decided to begin injecting 100% PVB to 

increase the amount of salt disposed of with the reduced injection rate initialized in Phase III. 

Injection of 100% PVB began on January 7, 2002 and has been maintained since. The same 

reduced injection rate as in phase III (230 gpm) and biannual 20-day shutdowns were 

maintained.

In 2004 the MASIP was raised to 5350 psi. The MASIP was raised to ensure the economic 

operation of the well. No new data were acquired in order to raise the MASIP, but instead the 

previous limit of 5000 psi was reevaluated and considered to be well below the previously 

calculated injection pressure required to breach the confining salt layer (6106 psi). These

calculations are documented in section 3.

2.1.5 Phase V (April 17, 2013 – Present)

Following a ML 4.4 induced earthquake on January 24, 2013 (Block et al., 2014), Reclamation 

halted injection and reevaluated the seismic hazard associated with PVU operations. Analyses of 

the seismic and injection data indicated that the potential for inducing large felt events might be 

reduced by decreasing the long-term average injection pressures (Block and Wood, 2009; Wood 

et al., 2015). Pressure-flow modeling indicated that reducing the flow rate would reduce 

wellhead pressures, and forward modeling was used to determine an appropriate flow rate (Wood 

et al., 2015). In addition, the pressure-flow modeling indicated that changing the injection well 

shut-in schedule to have shorter, more frequent shut-ins would result in a lower average wellhead 

pressure, compared to the biannual 20-day shut-ins previously used. Injection was resumed on 

April 17th, 2013. The nominal flow rate was reduced to 200 gpm with weekly 18-hour shut-ins. 

The average flow rate during Phase V has been 178 gpm.
7

Figure 4 – From Block et al. (2015a). Daily average injection flow rate (top), daily average surface injection 

pressure (middle), and daily average downhole pressure at 14,100 ft (4.3 km) depth (bottom) during PVU 

injection operations.
8

Figure 5 - Daily average wellhead pressures (green) and 20-day centered moving average (black) for end of 

phase IV and beginning of phase V (November, 2012 – July, 2015). The injection well was shut in for nearly 3 

months following a ML 4.4 induced earthquake on Jan. 24, 2013. Injection resumed on April 17, 2013, with a 

reduced flow rate and shorter, more frequent shut-ins.

2.2 Injection Pressures

The surface and downhole injection pressures at PVU Injection Well #1 vary considerably over 

time (Figure 4). After the injection flow rate was decreased by one-third in mid-2000, both the 

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

slowly recover. When the injectate was subsequently changed from a 70% brine-30% fresh water 

mix to 100% brine (January 2002), the increased density of the 100% brine injectate resulted in 

an immediate increase in the downhole pressure of about 300 psi (Figure 4). By mid-2003, the 

downhole pressure had reached the same value as prior to the mid-2000 decrease in injection 

flow rate. The surface injection pressure, in contrast, did not reach the pre-2000 value (just under 

5000 psi) until mid-2010 (Figure 4). This distinction between the slow increase in surface 

injection pressure and rapid increase in downhole pressure is important when considering that 

the MASIP is designed to prevent the breach of confining layers and therefore it is the downhole 

pressure, not the injection pressure, which is most relevant. 

During injection phase IV (2002-2013), the maximum surface and downhole pressures gradually 

increased, while the daily average injection flow rate and composition of the injectate remained 

nearly constant. Short-term fluctuations in injection pressure (for example, in 2004 and late 
9

2005-early 2006) appear to be the result of variation in the frequency and length of shut-ins, both 

scheduled and unscheduled. 

Due to the long shut-in and reduced flow rate following the January 2013 ML 4.4 event, the 

surface injection pressure dropped significantly. Since injection operations resumed in April 

2013, surface injection pressure has been slowly increasing, with the rate of increase declining 

over time (Figure 5). The maximum daily average surface injection pressure reached in phase V

to date (2013-July 2015) was ~ 4788 psi, reached in November 2013, after an unusually long 

injection cycle. Although the injection pressures are expected to continue to gradually increase, 

the rate of increase should further diminish over time (King and Block, 2015).

2.3 Geology 

Paradox Valley is located in the northeastern part of Paradox Basin. Rapid subsidence of 

Paradox Basin during the Mississippian, Pennsylvanian, and Permian Periods (~350 - 250 Ma) 

accommodated marine intrusion and resulted in the inter-fingering of marine deposits, including 

evaporates, and terrestrial material shed from the nearby (Uncompahgre) uplifted areas to the 

northeast (McClure, 2003). The Paradox fold and fault belt, situated in the northern portion of 

the Paradox Basin, contains several northwest-striking diapiric salt-cored anticlines. These saltcored anticlines developed as a result of plastic flow of the Pennsylvanian-age Paradox 

stratigraphic unit. The Paradox unit consists of as much as 85% halite and, according to Huntoon 

(1988), its deformation is “best imagined as a viscous liquid that can flow in response to imposed 

stresses”. Subsequent dissolution of salt beneath the crests of some of the anticlines resulted in 

down-faulting and the development of grabens, or salt valleys (Gutiérrez, 2004, Nuccio and 

Condon, 1996). Paradox Valley developed as a result of structural collapse along the crest of one 

of these salt-cored anticlines and is bounded by nearly vertical normal faults.

Paradox Valley and the surrounding mesas contain rocks spanning Precambrian to midCretaceous time (>570 to approximately 90 Ma) (Block et al., 2012). The Precambrian basement 

rock consists of granite, schist, gneiss, and pegmatite. Overlying the Precambrian rock is a series 

of sedimentary units deposited primarily in marine or near shore environments. These layers 

include sandstones, siltstones, shales, conglomerates, limestones, dolomites, and evaporates 

(Block et al., 2012). A geologic cross section from King et al. (2014), through the injection well 

and approximately perpendicular to Paradox Valley, is presented in Figure 6. PVU Injection 

Well #1 is sited on the Triassic-age Chinle Formation. The stratigraphy of the underlying 

formations is described in Table 1. Depths of geologic units encountered in this well are included 

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

Descriptions of the rock units are taken from several sources (see footnote no. 2 in the table). 

Further details of the local geology can be found in Block et al. (2012) and King et al. (2014). 

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

(Bremkamp and Harr, 1988). The Leadville formation was selected due to its relatively high 

permeability, largely the result of an extensive system of fractures in the rock. The upper 

Precambrian was originally considered a secondary injection target, and some of the Cambrian 

and Devonian units were also considered to have some injection potential (Bremkamp and Harr, 

1988). PVU Injection Well #1 contains several perforated zones spanning the interval from the 
10

Leadville formation to the Precambrian (Figure 3). However, early flow profiles indicate that the 

Leadville formation accepts the majority of fluid (Envirocorp, 1995), and over time the deeper 

perforations have been covered with fill from precipitation of sulfur in the wellbore (Subsurface 

Technology, 2001). The overlying Paradox salt formation is the primary confining layer.

Figure 6 – (Top) Location of geologic cross section B-B’. (Bottom) Cross Section B-B’ digitized and modified 

from Bremkamp and Harr (1988) and taken from King et al. (2014). There is no vertical exaggeration.
11

Table 1 - From King et al. (2014). Stratigraphy at the PVU well.

Stratigraphic 

Unit

Depth1 Description2

CRETACEOUS3 (145-65 Ma)

Mancos Shale Above 

elevation 

of 

wellhead

Dark gray to black, soft, fissile marine shale 

with thin sandstone beds at various horizons.

Dakota 

Sandstone

Friable to quartzitic fluvial sandstone and 

conglomeratic sandstone with interbedded 

carbonaceous nonmarine shale.

Burro Canyon 

Fm.

Fluvial sandstone and conglomerate interbedded 

with lacustrine siltstone, shale, and mudstone, 

and thin beds of impure limestone.

JURASSIC (205-145 Ma)

Morrison Fm. Above 

elevation 

of 

wellhead

Fluvial and lacustrine shale, mudstone, and 

sandstone; local thin limestone beds.

Summerville Fm. Sandy shale and mudstone of terrestrial origin.

Entrada 

Sandstone

Fine- to medium-grained, massive, and crossbedded eolian sandstone; basal few feet may 

consist of red siltstone and fine-grained 

sandstone and is sometimes referred to as the 

Carmel Formation.

Navajo 

Sandstone

Fine-grained, cross-bedded eolian sandstone.

TRIASSIC (255-205 Ma)

Kayenta Fm. Above 

elevation 

of 

wellhead

Irregularly interbedded fluvial shale, siltstone, 

and fine to coarse-grained sandstone.

Wingate 

Sandstone

Fine-grained, massive, thick-bedded and 

prominently cross-bedded eolian sandstone.

Chinle Fm. 0 (at 

surface)

Siltstone interbedded with lenses of sandstone 

and shale, limestone-pebble and shale-pellet 

conglomerate, with lenses of grit and quartzpebble conglomerate near base. Terrestrial 

depositional environment.

Moenkopi Fm. 390 Sandy shale/silty sandstone with some 

conglomerate present. Marine and terrestrial 

depositional environment.

PERMIAN (298-255 Ma)

Cutler Fm. 1,140 Fluvial arkose and arkosic conglomerate, with 

some sandy shales; deposited in alluvial fans.

PENNSYLVANIAN (322-298 Ma)

Hermosa Group 

– Honaker Trail 

Fm.: Upper 

Honaker Trail

La Sal

8,313

12,006

Limestone/sandstone/siltstone; deposited in 

marine conditions.

Limestone/dolomite; some silty limestone, 

oolitic limestone, and algal limestone present.
12

Lower Honaker 

Trail

12,082 Limestone/sandstone/siltstone; deposited in 

marine conditions.

Hermosa Group 

– Paradox Fm.:

Ismay

1st Main Salt

2nd Main Salt

Base Salt –

Lower Paradox

12,350

12,839

13,104

13,497

13,566

Resulted from intermittently closed marine 

environment.

Limestone, stacked algal carbonate mounds and 

other shallow-water carbonates and dolomites.

Dolomite/salt; intermittently closed marine 

environment.

Salt/anhydrite/shale; intermittently closed 

marine environment.

Shale/anhydrite/(minor) limestone; 

intermittently closed marine depositional 

environment.

Hermosa Group 

– Pinkerton Trail 

Fm.

13,693 Shales/anhydrites/siltstone/(minor) limestones; 

dark colored shales, limestone formed by 

marine invasion.

Molas Fm. 13,944 Shale/siltstone/claystone; regolith/soil (terra 

rosa) de-veloped on the karst surface of the 

Leadville formation after a period of extensive 

weathering and erosion.

MISSISSIPPIAN (355-322 Ma)

Leadville Fm. 13,984 Limestone/dolomite. Lower unit 

(Kinderhookian-age) stromatolitic dolomite, 

lime mudstones, pelletal lime mudstones; 

deposited in intertidal to subtidal environments. 

Upper unit (Osagean-age) fossiliferous pelletal 

and oolitic limestone, and lime and dolomitic 

mudstone.

DEVONIAN (416-355 Ma)

Ouray Fm. 14,400 Limestone—lime mudstone, pelletal lime 

mudstone and skeletal limestone that is locally 

dolomitized; formed in quiet-water marine 

environment.

Elbert Fm. 14,440 Sandstone/shales/shaly dolomites.

McCracken Fm. 14,607 Sandstone with occasional interbeds of sandy 

dolomite; transgressive depositional 

environment.

Aneth Fm. 14,681 Dolomite/shale; dense, argillaceous sequence.

CAMBRIAN (540-488 Ma)

Lynch Fm.:

Upper Lynch 

Shale

Lynch Limestone

Lower Lynch 

14,763

14,835

14,928

Sandstone/interbedded shale, dolomite, 

limestone.

Limestone.

Shale.
13

Shale

Muav Fm. 14,988 Limestone.

Bright Angel Fm. 15,103 Shale.

Ignacio Fm. 15,246 Sandstone, sometimes referred to as quartzite; 

transgressive depositional environment.

PRECAMBRIAN (>540 Ma)

Precambrian 15,446 Described regionally as granitic rock with welldeveloped northwest and northeast orthogonal 

fracture systems; identified in PVU Injection 

Well #1 as moderately metamorphosed dioritegabbro schist.

1

Depths are taken from the geologic drill log of PVU Injection Well #1 (Harr, 1988). Depths are 

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

2

Descriptions are taken from: Bremkamp and Harr (1988), Campbell (1981), Doelling (1988),

Williams (1964), and Nuccio and Condon (1996).

3

Ages from Walker and Geissman (2009).

15

3 MASIP Calculations

In this section, we summarize information from several early PVU reports relevant to the MASIP 

calculations for PVU Injection Well #1. Calculations documented in the existing reports rely 

heavily on interpretations of geophysical well logs from the injection well. A brief summary of 

the geophysical well logs from the injection well, with emphasis on those logs that provide data 

directly relevant to the MASIP calculations, is provided in section 3.1. In section 3.2, we 

summarize calculations that were performed prior to completion of the PVU well and injection 

testing to assess the confining ability of the Paradox formation. We also examine the dependence 

of that analysis on the plasticity of the Paradox salt. Next, we review the MASIP calculations 

documented in the injection permit from EPA (section 3.3). Lastly, we review the criteria that 

must be met if Reclamation were to seek approval for an increase in the current MASIP for the 

PVU injection well (section 3.4).

3.1 Relevant PVU Well Logging

Open-hole logging was performed in the injection well in three stages as the borehole was 

drilled: (1) after drilling the shallow hole (90 ft – 2012 ft) (Dewan, 1987a), (2) after drilling the 

intermediate hole (2020 ft – 14050 ft) (Dewan, 1987b), and (3) after drilling the deepest portion 

of the well, referred to as the liner hole (14050 ft - 15950 ft) (Dewan, 1987c; Dewan, 1988a). 

These stages correspond to progressively decreasing borehole diameter (Figure 7). Final well 

logs, composed of a composite of these individual runs, were constructed after all open-hole 

logging was completed (Dewan, 1988b). 

Logging from the intermediate and liner holes provides data for the MASIP calculations. These 

two stages span most of the borehole, including the Paradox Salt, considered the major confining 

layer, and the Leadville formation, the primary injection target reservoir. Descriptions of the 

acquisition and processing of the geophysical logging data from these two sections of the 

borehole are presented below. These descriptions, including the qualitative evaluations of the 

data quality and the results derived from the data processing, are taken from the relevant original 

well log reports. We did not re-evaluate the geophysical well logging data or perform additional 

analyses of the data when writing this report.

3.1.1 Intermediate Hole Logging (14,050-2,020 ft; upper Leadville - Cutler):

Open-hole logging of the intermediate hole (14,050 – 2020 ft depth) was performed by 

Schlumberger and documented by Dewan (1987b). All descriptions of the field-recorded and 

computed well logs presented in this section are summarized from Dewan (1987b). 
16

Figure 7 – Casing and cementing details of PVU Injection Well #1.

Field Recorded Logs:

Schlumberger performed four successful well log runs in the intermediate portion of the well:

Run 1: Dual Laterlog (DLL), Microspherically Focused (MSFL), Dual Caliper, Gamma 

Ray (GR)

Resistance of the tool to being pulled up the well, as evidenced by multiple periods of increased 

tension on the wireline, were experienced between 12,470 ft and 11,527 ft during this run. The 

arms of the caliper logging tool were closed between ~11,527 ft and ~10,000 ft because of the 

difficulty with getting the tool through this section of the hole. These problems occurred above

the major salt layer and therefore did not affect data in the region of greatest interest. Dewan 

(1987b) found the borehole to be significantly out-of-round, typically 12 1⁄2" in one direction and 

14"-16" in the other. The deep laterolog resistivity curve (LLD) indicated highly resistive salt 

beds; the shallow curve (LLS) was not useful because of the effects of large borehole diameter 

and salt-saturated drilling mud. Dewan (1987b) considered the gamma ray curve to be good for 

correlation and indicative of some zones rich in potassium minerals. The MSFL was only 

recorded across the lowest 500 ft of the intermediate hole (~13,550 – 14,050 ft depth) because of 

tool damage. 
17

Run 2: Borehole Compensated Sonic (BHC), GR

Dewan (1987b) reported the quality of the sonic log from this run to be excellent, excluding 

short sections at 13,455 ft and 8,610 ft where abnormally large borehole washouts caused cycle 

skipping. A sonic-derived porosity, φ , was calculated using the following equation:

φ = − 0.625 1 / ( t t ma ) (1)

where t is the sonic slowness (μsec/ft) and ma t is the matrix slowness, set to 49 μsec/ft, 

considered appropriate for limestone. Since the actual lithologies are variable, the sonic porosity 

log is only approximate and is most accurate for the limestone sections. This relation does not 

hold for salt formations, in which a salt porosity of zero was assumed (Dewan, 1987b). 

Run 3: Digital Sonic, GR

This run recorded complete sonic waveforms from 12,986 to 14,050 ft. The sonic logger 

consisted of 10 receivers spaced at 6" intervals. The quality of the sonic log was considered 

excellent. Compressive and shear velocities were calculated from this record. 

Run 4: Stratigraphic High-Resolution Dipmeter (SHDT), GR

This run had many mechanical issues, including the logging tool sticking in the hole and the 

winch breaking. The quality of the run was therefore poor, but still good enough to extract 

structural dip at depths below 10,500 ft. 

Computed Logs:

The digital sonic data from run #3 was processed using a slowness-time-coherence (STC) 

algorithm. Computed compressive and shear slownesses were used to calculate Poisson’s ratio 

using the following relation:

2

2

2

0.5

1

s

p

s

p

t

t

t

t

μ

        −         =         −        

(2)

where μ is Poisson’s ratio (dimensionless), p t is the compressional-wave slowness (μs/ft), and 

st is the shear-wave slowness (μs/ft) (Dewan, 1987b). 

A sonic-derived density was calculated from the BHC sonic log using the equation
18

52.8 1.63 t ρ = + (3)

below 9,300 ft and the equation

57.2 1.61 t ρ = + (4)

above 9,300 ft, where ρ is the density (g/cm3

) and t is the compressional-wave slowness (μs/ft). 

The density calculations were considered appropriate for carbonates below 9,300 ft and 

appropriate for sandstones above 9,300 ft (Dewan, 1987b). Areas with a resistivity greater than 

20,000 ohm-m and slowness greater than 54 μs/ft were considered salt, and the density for these 

areas was set to 2.16 g/cm3. Densities were also calculated from a BHC sonic log acquired in the 

surface hole below 240 ft depth and merged with the results from the intermediate hole. To 

extrapolate the density log to the ground surface, a density of 2.4 g/cm3 was assumed above 240 

ft.

The calculated densities were used to compute the overburden pressure P0 as a function of depth. 

An extra 1,000 ft of overburden was added to the pressure calculations due to the fact that the 

well bottom is 1,200 ft laterally offset from the wellhead location, below a large mesa. The extra 

overburden was assumed to have a density of 2.4 g/cm3

. The intermediate hole bottom (14,050 ft

depth) overburden pressure was calculated to be 16,400 psi, which corresponds to an overburden 

pressure gradient of 1.167 psi/ft. Pore pressure PP was also calculated assuming the water 

column extended 1,000 ft above the ground surface at the wellhead using a pore-pressure 

gradient of 0.442 psi/ft (Dewan, 1987b). 

These results, combined with the calculated Poisson’s ratio, were used to calculate the fracture 

closure pressure ( FPCL ) as a function of depth:

FP mP P m CL o p =+ − (1 ) (5)

where m = − mm (1 ) . The fracture closure pressure is the fluid pressure required to open a 

preexisting fracture in the rock. Horizontal stress was assumed isotropic. The fracture initiation 

pressure ( FPIN ), the pressure required to initiate fracture of intact rock, was then computed as a 

function of depth following:

2 FP FP P IN CL p = − (6)

These calculations assumed no tensile strength in the rock and no incremental invasion of fluid 

during fracturing and were therefore considered conservative (Dewan, 1987b). Calculations 

accounting for tensile strength were also computed, but Dewan (1987b) considered the results 

from those calculations to be less reliable than the results presented here. Fracture closure and 

initiation pressure gradients were computed by dividing FPCL and FPIN by the depth. The results 
19

indicated FPIN gradients ranging from 0.8-1.2 psi/ft through most of the depth interval from 

14,050 to 13,000 ft. FPCL gradients were 0.6-0.8 psi/ft in the same interval. The salt fracture 

closure and initiation pressure gradients were calculated to be 0.72 psi/ft and 0.97 psi/ft,

respectively. The computed fracture closure and initiation pressure curves are included on the 

mechanical properties log (Dewan, 1988b).

3.1.2 Liner Hole Logging (15,950-14,050 ft) (Precambrian – upper Leadville):

The liner hole section spans the upper Leadville formation through the Precambrian basement

(15,950 to 14,050 ft depth). The well logging performed in the liner hole was more extensive 

than that performed in the intermediate hole. In addition to the same types of logs as acquired in 

the intermediate hole, the following additional logs were acquired in the liner hole: litho-density, 

compensated neutron, spectral gamma ray, borehole televiewer, and a suite of geochemical logs 

(Dewan, 1987c). According to Dewan (1987c), the quality of the logs in this portion of the 

borehole was sub-par as a result of borehole washouts. Tool malfunctions and the need to ream 

or clean out the borehole several times because of ledges encountered in the hole also caused 

difficulties and resulted in some logs being acquired with multiple runs to cover the entire depth 

range desired. In all, 13 well logging runs were completed by Schlumberger. These individual 

runs are documented in Dewan (1987c).

The analyses performed on the well logs from the liner hole largely focused on identifying high 

porosity injection intervals (Dewan, 1988a). As for the intermediate borehole, fracture initiation 

and closure pressure gradients were also computed, and these data partially form the basis of the 

MASIP calculations. Below we summarize information presented in the original well logging 

interpretation report for the liner hole (Dewan, 1988a). We have not performed any additional 

review or analyses of the well logging data or results.

Field Recorded Logs:

Dual caliper logs, run above a depth of 15,320 ft, indicated that the borehole was oblong. The 

minimum borehole diameter was generally close to the 8.5" bit size, while the maximum well 

diameter ranged from 10" to over 20". This suggested to Dewan (1988a) that substantial tectonic 

stresses were present at these depths. 

A combined dual laterolog – micro-spherically focused well log was run to obtain information on 

formation porosities. The laterolog deep resistivity curve (LLD) was the only reliable curve

obtained and was used to calculate formation porosities. The shallow laterolog and MSFL curves

were unreliable due to borehole washouts and pad standoff. The LLD curve was considered a 

good indicator of porosity given the absence of shale and hydrocarbons (Dewan, 1988a). 

Porosity (φ ) was estimated using the resistivity measured from the LLD, Rlld , using the 

equation:

0.15

Rlld φ = (7)
20

 

The results indicated porosities of 1% to 5% (with average values of 2% and 3%) in two 

intervals in the upper and middle Leadville formation. A few zones with comparable porosity 

were found below the Leadville, but according to Dewan (1988a) the presence of shale may have 

biased the results. 

A litho-density- (LDT) – compensated-neutron (CNL) - GR log also experienced problems as a

result of borehole washouts and borehole eccentricity. As a result, Dewan (1988a) considered the 

data unreliable over about one-third of the depth range logged. In the reliable sections, the

density and neutron logs indicated porosities of 0% to 6% (with averages of 4% and 5%) in the 

same two upper-mid Leadville intervals identified from the LLD log. Areas of comparable 

porosity in deeper formations identified from these logs corresponded less closely to those

observed in the LLD log; however, both sets of logs indicated intervals in the upper Precambrian 

with porosities of about 2% to 5%.

An 8-receiver digital sonic log was also acquired and used to derive porosity. In general, Dewan 

(1988a) considered the P- and S-wave slowness measurements to be good, with the exception of 

a few washed out intervals. Porosity (φ ) was calculated using the relation: 

f =− − (tt t t ma f ma ) /( ) (8)

where t is the recorded P-wave slowness (μs/ft), ma t is the slowness of the matrix, assumed to be 

47.6 μs/ft in limestone, and f t is the fluid slowness, assumed to be 190 μs/ft. Calculated 

porosities agreed broadly with those derived from the LLD and LDT-CNL logs, suggesting 

porosities of ~2% in the upper-mid Leadville and ~3% in some upper Precambrian intervals. 

Fractured areas were suggested based on a decrease in shear-wave amplitudes. Generally these 

intervals were small (< 20 ft), and their validity was questionable (Dewan, 1988a). 

A borehole televiewer log was run, but the images contained high-amplitude signals as a result of 

the ellipticity of the well. Interpretations from formation microscanner, stratigraphic dipmeter, 

and geochemical logs were either used as quality control or as input to the computed logs. 

Computed Logs:

Because of the roughness of the borehole, the structural dip data showed a lot of scatter in both 

magnitude and direction. However, Dewan (1988a) considered the structural dip to be well 

resolved from 14,740 to 15,230 ft depth. Combining this information with the dip log from the 

intermediate borehole, Dewan (1988a) concluded that the structural dip is largely constant in the 

bottom 2500 ft of the well, with formations dipping about 5° to the northeast. 

A fracture identification log (FIL) was also computed from the dipmeter data. The FIL log 

indicates three fractured zones, two in the upper-mid Leadville and one in the upper 

Precambrian. These intervals correspond to depths identified as having a few percent porosity by 

the laterolog deep resistivity, density, neutron, and sonic logs. The fractured zones within the 

Leadville appear to coincide with the presence of dolomite (Dewan, 1988a). 
21

The 8-receiver digital sonic log was processed using an STC algorithm. Despite the poor 

borehole conditions, Dewan (1988a) considered the P- and S-wave velocities to be reliable over 

most depths. The V V P S ratios were reported to range from 1.6 to 2.0, with the exception of a 

few intervals where the computed V V P S was as high as 2.2 (Dewan, 1988a). The anomalously 

high V V P S values are not confirmed by the truck-processed sonic log and may not be robust.

A mechanical properties log was computed following a similar procedure as for the intermediate 

hole. A difference in these computations was the use of bulk density computed from the LDT log 

rather than from the sonic log. At some depths, large borehole washouts biased the LDT log and 

resulted in an anomalously low computed density value. To compensate for this problem, the 

density was set to 2.4 g/cm3 at any depth where the computed density was below that value. 

Overburden pressure (psi) was then calculated as a function of depth z (ft) using the equation:

( ) ( ) ( )

14,050

14,050 0.433

z

P z P o o = + ρ z dz ∫ (9)

where Po (14,050) is the overburden pressure calculated from the intermediate hole logging at 

14,050 ft depth (~16,500 psi), ρ is the bulk density (g/cm3

) from the LDT log in the liner hole, 

and 0.433 is a factor needed to convert units (Dewan, 1988a). Pore pressure (psi) was calculated 

as a function of depth z (ft) with the equation:

( )

14,100

6,160 psi 0.442 psi/ft

z

P z p= + dz ∫ (10)

where 6,160 psi is the pore pressure directly measured by a drill stem test at 14,100 ft depth and 

0.442 psi/ft is the assumed gradient for the formation water. FPIN and FPCL were calculated as 

for the intermediate hole (assuming no tensile strength in the rock and no incremental invasion of 

fluid during fracturing). Above 14,650 ft depth (in the Leadville and underlying Devonian units), 

computed FPIN gradients were similar to those measured in the intermediate hole, ranging from 

0.8 to 1.1 psi/ft. In some sections below 14,650 ft depth containing more siliceous materials, 

FPIN gradients were as low as 0.5 psi/ft. FPCL gradients were generally ~0.3 psi/ft less than the 

FPIN gradients. FPIN was recalculated accounting for tensile strength, but Dewan (1988a) 

considered those calculations to be less reliable than the calculations using zero tensile strength.

3.2 Evaluation of the Confining Layer

Prior to completion of the PVU injection well, the confining ability of the Paradox salt was 

evaluated to ensure that vertical fractures in the target injection formations would not propagate 

through the confining layer. According to Dewan (1988c), once the injection zone was broken 

down, the critical factor that controlled vertical fracture propagation was the difference in closure 
22

pressures between the injection interval and the overlying or underlying formations. In the case 

of PVU, Dewan (1988c) considered this to be the difference between the closure pressure of the 

Leadville formation (14,080 – 14,350 ft) and that of the overlying salt section of the Paradox 

formation (13,140 – 13,600 ft). The closure pressures computed from the geophysical well log 

data were used as estimates of the minimum horizontal stresses in these formations. 

Relying on the computed mechanical properties log, Dewan (1988c) found that the minimum 

horizontal stresses ( FPCL ) in the Leadville formation ranged from 9,000 to 11,000 psi 

(corresponding to gradients of 0.65 – 0.8 psi/ft). The salt was determined to have similar

calculated minimum horizontal stresses of 9,000 to 10,000 psi (gradients of 0.7-0.8 psi/ft) on the 

mechanical properties log. However, Dewan (1988c) stated that due to the ability of the salt to 

creep, the minimum horizontal stress in the salt is equal to the overburden pressure (i.e., an 

isotropic stress state in the salt layer equal to the lithostatic stress should be assumed). Dewan

(1988c) argued that since the mechanical properties log was computed from measurements 

recorded at 20 khz, the salt did not have adequate time to creep, which resulted in 

underestimating the minimum horizontal stress. Instead, Dewan (1988c) suggested the use of the 

overburden pressure at the depth of the salt, 14,500 psi (computed from geophysical logs in the 

intermediate hole), as the minimum horizontal stress for the salt. Therefore, according to Dewan 

(1988c), the minimum difference in the closure pressures between the Leadville and salt 

formations was 3,500 psi (14,500 psi – 11,000 psi). 

Next, Dewan (1988c) computed the effective confining differential ( ECD). The ECD takes into 

account the pressure difference from the hydrostatic head in the two zones. Dewan (1988c) 

computed the hydrostatic head difference (HHD) between the Leadville and salt to be ~400 psi (

(14, 200 ft. 13,300 ft. 0.46 − ×) psi/ft). Hence, Dewan (1988c) determined the ECD to be ≥ 3,900 

psi. 

In response to concerns about the assumption that the horizontal stress in the salt is equal to the 

overburden pressure, various experts in the field were consulted (Dewan, 1988d). The consensus 

was that the assumption of isotropic stress in the salt was correct, and therefore the minimum

ECD value of 3900 psi was considered valid (Dewan, 1988d).

Dewan (1988d) suggested that the fracture propagation modeling in use at that time (using the 

FracHite computer program by Schlumberger) be performed assuming a range of Poisson ratios 

in the salt in order to understand the sensitivity of the results on the assumption of isotropic

stress. This work does not appear to have been completed. However, it is possible to evaluate the

sensitivity of the ECD calculation on the assumption of isostatic stress in the salt. Substituting

the values used by Dewan (1988c) (overburden pressure in salt = 14,500 psi, depth of salt = 

13,300 ft, pore pressure gradient = 0.46 psi/ft) into equation (5), we calculate the fracture closure 

pressure in the Paradox salt as a function of Poisson’s ratio (Figure 8a). Subtracting the largest 

closure pressure value for the Leadville (11,000 psi) and adding the HHD value given above 

(400 psi) then provides a minimum estimate of the ECD as a function of Poisson’s ratio (Figure 

8b). The results show that if the Poisson’s ratio of the salt is less than ~0.33, the minimum 

estimate of ECD is less than or equal to zero. This demonstrates that the confining ability of the 

salt, as evaluated using differences in fracture closure pressures, is highly dependent on the 

assumption that the state of stress in the salt is isotropic (i.e., Poisson’s ratio is close to 0.5).
23

Figure 8 – (a) Fracture closure pressure in Paradox salt and (b) Minimum effective confining differential as a 

function of Poisson’s ratio.

3.3 MASIP Calculations

Prior to determining the appropriate MASIP, the surface injection pressures required to open preexisting fractures within the Leadville were examined. Due to the fact that the permeability of 

the Leadville is largely the result of a well-developed fracture system rather than primary 

porosity (Bremkamp and Harr, 1988), it was deemed advantageous to inject at downhole 

pressures above the Leadville fracture closure pressure so that preexisting fractures would be

opened (Environmental Protection Agency, 1997). EPA calculated the corresponding injection 

pressure at the ground surface (accounting for friction loss in the well tubing), referred to as the 

maximum surface injection pressure ( MSIP), following the equation:

MSIP F( gradient 0.433 psi/ft ) fric = − × +∆ SG d p (11)

where Fgradient is the fracture closure pressure gradient in the Leadville formation (0.685 psi/ft), 

SG is the specific gravity of the brine (1.167), d is the depth to the top perforation (14,080 ft), 

and fric ∆p is the friction loss in the well tubing (psi) from the ground surface to the top 

perforation (Environmental Protection Agency, 1997). The value 0.433 psi/ft comes from a 

typical pressure gradient of fresh water. 

The MSIP was computed using values of fric ∆p estimated by Envirocorp, Reclamation, and EPA.

EPA estimated a frictional loss of 915 psi, assuming a loss of 65 psi per 1000 ft (Environmental 

Protection Agency, 1997). Reclamation’s estimated frictional loss was nearly an order of 

magnitude smaller, 135 psi, which was calculated using the equation:
24

1369.38 fric

SG Q

p

2 × ∆ = (12)

where SG is the specific gravity of the PVU brine (1.167) and Q is the injection flow rate (400 

gallons/minute) (Environmental Protection Agency, 1997). Envirocorp calculated a similar 

frictional loss of 111 psi for a flow rate of 400 gallons/minute following the equation:

2

5

0.03112 0.433 fric brineLQ p f d

∆ = r (13)

where rbrine is the density of the brine in g/cm3, L is the tubing length (14,080 ft), Q is the 

injection flow rate (400 gal/min), d is the inner diameter of the tubing in inches, and f is a 

dimensionless friction factor given by:

10

1 2.51 2log f 3.7 12 d R f

  ε = − +  

 

(14)

(Envirocorp Services and Technology Inc., 1995; Environmental Protection Agency, 1997). R is 

the Reynold’s number (dimensionless), and ε is the pipe roughness in feet. The resulting MSIP

values are: 3445 psi (EPA), 2655 psi (Reclamation), and 2644 psi (Envirocorp) (Environmental 

Protection Agency, 1997).

In an EPA injection permit, a maximum allowable surface injection pressure is established to 

ensure that injection pressures remain low enough to prevent the propagation of new and existing 

fractures vertically through the confining layer and into formations that contain underground 

sources of drinking water. This permitted limit on the surface injection pressure, the MASIP, was 

calculated for PVU Injection Well #1 considering the estimated fracture initiation pressure 

gradient for the confining Paradox salt, 0.97 psi/ft (from Dewan 1987b). The 0.97 psi/ft value 

relied on Poisson’s ratios and densities derived from the sonic well log in the intermediate hole 

and assumed no tensile strength in the formation (section 3.1.1). This gradient can be related to 

surface injection pressure by considering first that P PP f sh = + , where Pf is the downhole fluid 

pressure, Ps is the surface injection pressure and Ph is the hydrostatic pressure. The hydrostatic 

pressure can be calculated by 0.433psi/ft Ph = ×× d SG , where d is the depth of the injection 

interval in feet, SG is the specific gravity of the injectate (1.167 for pure brine), and 0.433 psi/ft

is the assumed hydrostatic pressure gradient of the formation water. The pressure gradient is 

given by:

0.433psi/ft f S

gradient

P P SG d F

d d

+ ×× = = . (15)

Solving for surface injection pressure gives:
25

PS gradient = − ×× (F 0.433psi/ft SG d ) . (16)

Using 13,140 ft as the depth to the first main Paradox salt member (depth not corrected for 

borehole deviation), a pressure initiation gradient of 0.97 psi/ft, and a specific gravity of 1.167, 

EPA computed the corresponding surface injection pressure to be 6106 psi (Environmental 

Protection Agency, 1997). Because no friction loss in the tubing was included in the above 

computation, a surface injection pressure of 6106 psi is a conservative estimate of the surface 

pressure required to initiate fracturing in the confining layer (i.e., the actual value accounting for 

friction loss would be higher). Based on the above analyses, EPA originally placed the MASIP 

for the PVU injection well at 5000 psi (Environmental Protection Agency, 1997). 

In 2004, the permitted MASIP was increased to 5350 psi. This value was based on the same 0.97 

psi/ft fracture initiation gradient as when the 5000 psi MASIP was selected. A pressure of 6106 

psi was still considered necessary to breach the confining salt, and therefore an injection pressure 

of 5350 psi was considered low enough to prevent a breach of the confining layer 

(Environmental Protection Agency, 2004). The emphasis in this analysis was the stress gradient 

(pressure gradient) applied at the base of the salt for a given surface injection pressure, as 

compared to the 0.97 psi/ft fracture initiation pressure gradient for the salt confining layer. With 

a surface injection pressure of 5350 psi, the stress gradient at the base of the salt was calculated 

to be 0.8977 psi/ft (using equation 16). Following the same procedure, we calculated the stress 

gradient at the base of the salt given an increase in the MASIP. Given an MASIP of 5500 psi, the 

stress gradient at the base of the salt is calculated to be 0.9108 psi/ft (Table 2), within ~6% of 

0.97 psi/ft pressure initiation gradient. If the MASIP were raised to 5800 psi, the resulting 

gradient at the base of the salt would be 0.933 psi/ft, within ~ 4% of the calculated pressure 

initiation gradient in the salt.

Table 2 - Calculated stress gradients given different surface injection pressures, following the methodology in 

the 2004 EPA permit. Depths and formations correspond to those evaluated in the 2004 permit. 

Formation

Depth of 

Formation 

Base 

(feet)

Stress 

Gradient at 

5000-psi 

Surface 

Injection 

Pressure

Stress 

Gradient at 

5350-psi 

Surface 

Injection 

Pressure

Stress 

Gradient at 

5500-psi 

Surface 

Injection 

Pressure

Stress 

Gradient at 

5800-psi 

Surface 

Injection 

Pressure

Top Perforation 14080 0.862 psi/ft 0.8866 

psi/ft

0.8972 

psi/ft

0.9185 

psi/ft

Molas 14024 0.863 psi/ft 0.8887 

psi/ft

0.8988 

psi/ft

0.9202 

psi/ft

Pinkerton Trail 13894 0.864 psi/ft 0.8891 

psi/ft

0.8999 

psi/ft

0.9214 

psi/ft

Lower Paradox 

Carbonate

13731 0.870 psi/ft 0.8962 

psi/ft

0.9072 

psi/ft

0.9290 

psi/ft

Salt 13606 0.874 psi/ft 0.8977 

psi/ft

0.9108 

psi/ft

0.9329 

psi/ft
26

The fracture initiation pressure gradient of 0.97 psi/ft at the base of the salt was calculated from 

geophysical well logs and is only an estimate. This value was calculated from sonic logs using 

assumed density-velocity relationships (section 4.1). No error analysis has been performed for

these calculations and therefore the uncertainty of the 0.97 psi/ft estimated value is unknown. 

Also, the plasticity of the salt was not taken into account in these calculations.

The analyses included in the EPA permits to determine the MASIP only considered the fracture 

initiation pressure in the salt, not the fracture closure pressure. However, if the plasticity of the 

salt causes the stress within this confining unit to be isotropic as discussed in the previous 

section, then the fracture closure pressure gradient within the salt is equal to the overburden 

pressure gradient of ~1.1 psi/ft (Dewan, 1988c), higher than the 0.97 psi/ft fracture initiation 

pressure gradient used in the permits. A recent consultant review board (CRB) convened by 

Reclamation to review these MASIP calculations agreed that the salt should be considered to 

have an isotropic/lithostatic stress state and suggested re-computing fracture closure pressures 

using the overburden pressures (vertical stresses) (Wang et al., 2015). Hence, the CRB

considered the fracture gradient value of 0.97 psi/ft used in the original calculations to be 

unrealistically low for evaluating the confining ability of the salt and hence considered the 

current MASIP for PVU Injection Well #1 to be conservative (Wang et al., 2015).

3.4 Requirements to increase the MASIP

In the 2011 EPA reauthorization of the well (Environmental Protection Agency, 2011), the EPA 

allowed for the possibility to increase the MASIP subject to four analyses:

i. An analysis of the adequacy of the injection equipment, well head, and downhole 

tubulars to withstand the proposed maximum allowable surface injection 

pressure.

ii. An analysis of the potential for adverse seismic activity if injection pressures are 

increased.

iii. An analysis of the continued adequacy of the confining zones, including 

information on the potential vertical fracture growth in the confining layers as a 

result of an increase in injection pressure.

iv. A demonstration made by performing a step rate injection test, using fluid 

normally injected, to determine both the instantaneous shut-in pressure and the 

formation breakdown pressure. 

An analysis of the adequacy of the injection equipment was previously performed in order to 

increase the MASIP to 5350 psi (Environmental Protection Agency, 2004). The details of the 

pressure ratings of specific parts of the injection system are detailed in the 2004 EPA permit. In 

addition, future seismicity rates were evaluated in terms of the excess energy from fluid injection 

as a function of time (Environmental Protection Agency, 2004), although those analyses have 

since been superceded by more recent work. A detailed, up-to-date look at the seismic history of 

the PVU and its relationship to injection operations is provided in subsequent sections. 
27

4 Induced Seismicity

Seismicity has been induced in the vicinity of the PVU injection well since the initial injection 

tests. Although the majority of the seismicity has been of small magnitude, several dozen felt 

events have occurred, including three earthquakes with ML of 4.0 or greater. A major concern for 

increasing the MASIP is the potential for PVU to induce large-magnitude events more 

frequently, for the maximum magnitude of induced earthquakes to increase, or for the induced 

seismicity to migrate closer to populated areas. Below we review the lateral and vertical 

expansion of the induced seismicity, including an examination of the seismicity very close to the 

well and what it suggests about the effectiveness of the confining layer. We then evaluate how an 

increase in the MASIP might influence future induced seismicity, based on previous analyses of 

the seismicity data and its relation to injection parameters.

4.1 Plan View Evolution of Induced Seismicity 

More than 6,000 shallow earthquakes (locating less than 8.5 km (27,900 ft) deep with respect to 

the ground surface elevation at PVU Injection Well #1) have been recorded in the vicinity of 

Paradox Valley since PVU injection operations began in 1991 (Block et al., 2015a). No such 

shallow earthquakes were detected in six years of seismic monitoring prior to the start of 

injection operations. Earthquakes were first detected 4 days after the start of the initial injection 

test into PVU Injection Well #1 in July, 1991 (Block et al., 2014; Block et al., 2015a). The first 

earthquakes occurred very close to the injection well. As injection continued, earthquakes 

continued to occur close to the well but also began occurring at increasing distances from the 

well. At present, earthquakes have occurred up to ~18 km from the injection well (Figure 9). 

The geographical distribution of induced seismicity over time is illustrated in the series of maps 

from Wood et al. (2015), presented in Figure 10 and Figure 11. The rate of geographical 

expansion of seismicity has varied over time, but generally the maximum distance of induced 

earthquakes from the well has increased. The rate of expansion was highest during the later 

injection tests (1991-1995) and the early phase of continuous injection (1996-2000) (Figure 10). 

In mid-2000, when the PVU injection flow rate was decreased by about 33% in response to a ML

4.3 induced earthquake, the geographical expansion of seismicity slowed, and the spatial extent 

of the near-well area (< ~5 km from well) and Northwest (NW) seismicity cluster (6-8 km NW 

of well) largely stabilized (Wood et al., 2015). While new clusters of seismicity appeared along 

the edges of northern Paradox Valley in the years following the reduction in flow rate, seismicity 

rates there were very low (Wood et al., 2015). 

This relatively stable period lasted until 2009. Five induced earthquakes of magnitude 2.5 or 

greater occurred in 2009. This was the highest annual rate of M 2.5+ earthquakes in five years, 

and the second highest rate since the injection flow rate was reduced in mid-2000 (Wood et al., 

2015). A distinct group of earthquakes developed in 2010 about 6 km southeast of the injection 

well, the southeast (SE) cluster. While the first detected SE-cluster event occurred in 2004, with 
28

two additional events recorded in 2008 and 2009, beginning in 2010 the SE cluster experienced 

increasing rates of seismicity (Wood et al., 2015).

Seismicity rates within the northern-valley area have also changed in recent years. During each 

year from 2000 (when the northern valley seismicity was first detected) to 2009, between two

and 33 earthquakes were recorded. In 2010, the rate increased markedly: 557 northern-valley 

earthquakes were recorded, with the majority occurring in a single swarm lasting just 16 days

(Block and Wood, 2011). Northern-valley seismicity rates remained elevated during 2011, with 

113 earthquakes recorded (Block and Wood, 2012), but declined back to pre-2010 rates during 

2012, with just 10 events recorded (Block and Wood, 2013).

Beginning in mid-2010, several shallow earthquakes have been detected beneath the floor of 

Paradox Valley. Three earthquakes were detected in 2010; two in 2011; five in 2012, five in 

2013, and four in 2014 (Block et al., 2015a). No earthquakes were detected beneath Paradox 

Valley in the 25 years of seismic monitoring prior to 2010 (Block and Wood, 2011). If the 

maximum magnitude of these earthquakes were to increase substantially, they would be of 

particular concern due to the fact that some of them are as close as ~1.7 km to the town of 

Paradox (Figure 11). However, the largest of the earthquakes that has occurred to date beneath 

Paradox Valley has a duration magnitude of 1.4, which is well below the magnitude threshold for 

human detection of ~M 2.5.
29

Figure 9 – From Block et al. (2015a). (Top) Daily average injection flow rate. (Bottom) Scatter plot of 

earthquakes with M ≥ 0.5 and depth < 8.5 km (relative to the ground surface elevation at the injection 

wellhead), plotted as a function of date and distance from PVU Injection Well #1. Each circle represents a 

single earthquake, with the width of the circle scaled by the event magnitude.
30

Figure 10 – From Wood et al. (2015). Maps showing the geographical distribution of shallow seismicity 

recorded in the Paradox Valley area from 1991 through 2000: (top) injection tests, 1991-1995 (bottom) longterm injection, 1996-2000. All detected earthquakes less than 8.5 km deep (relative to the ground surface 

elevation at the injection wellhead) are included. Dashed circles show distance from the town of Paradox.
31

Figure 11 - From Wood et al. (2015). Maps showing the geographical distribution of shallow seismicity 

recorded in the Paradox Valley area from 2001 through 2014: (top) long-term injection, 2001-2008 (bottom) 

long-term injection, 2009-2014. All detected earthquakes less than 8.5 km deep (relative to the ground surface 

elevation at the injection wellhead) are included. Dashed circles show distance from the town of Paradox.
32

4.2 Vertical Extent of Induced Earthquakes

Although the injection interval is relatively narrow in the PVU wellbore, induced earthquakes

near the well span a depth range exceeding 2 km (Figure 12). As the structure of the subsurface 

is poorly constrained, it is not definitively known in which formations earthquakes are occurring. 

Block et al. (2015b) mapped subsurface geology and faults using relatively-relocated

hypocenters (Figure 12). This analysis relied on the assumption that the majority of earthquakes 

occur within or near the Leadville formation. The presence of normal faults was inferred by 

abrupt lateral offsets in earthquake depths (Figure 12). 

The depth range of earthquakes closest to the injection well, where pore pressures are expected 

to be the highest, can be used to evaluate the effectiveness of the confining layer. Earthquakes 

within a few hundred meters of the well span a depth range of roughly 500 m (Figure 13 to 

Figure 16). The depths of these earthquakes appear to correspond approximately to the base of 

the Leadville formation to just above the top of the Paradox salt formation, based on the known 

formation depths in the PVU wellbore and assuming horizontal layers. If the formations are not 

vertically offset by faults, then many of these earthquakes appear to be occurring at depths 

shallower than the base of the confining Paradox Salt formation (~ -2.65 km below sea level at 

the well) (Figure 13 to Figure 16). The shallowest earthquake having a robust relativelyrelocated hypocenter occurs at an elevation of -2.27 km, above the top of the Paradox Salt 

confining layer at the well. While the errors in relative earthquake locations are small (< ~50 m), 

absolute locations likely have larger errors (>100 meters) and can shift a few hundred meters 

depending on the velocity model used. Therefore, there is relatively large uncertainty in the 

absolute hypocenters of these earthquakes that complicates direct comparison with the known 

stratigraphy at the well.

Possible interpretations of these shallow earthquakes include:

• The Paradox Salt has not acted as an adequate confining layer.

• There are structures (faults) in the immediate vicinity of the well that vertically 

offset reservoir formations.

• Shallow earthquake depths are the result of absolute earthquake location errors.

• These earthquakes are triggered by mechanisms different than pore-pressure 

alteration.

The shallow earthquakes began in May 1992 during injection testing, when pressures at the well 

were relatively low (3694 psi surface pressure, 10,539 psi down-hole pressure; Figure 4). Cross 

sections through these events over time show that the shallower events began during the same 

time period as the deeper events, and that the events initially occurred within two depth intervals 

separated by an aseismic zone (Figure 14 and Figure 16). While the shallow (> -2.65 km 

elevation) earthquakes occurred throughout injection testing and long-term injection, they have 

not substantially expanded vertically or horizontally since 1993-1994 (Figure 14 and Figure 16).

These observations suggest that the shallow earthquakes are not related to vertical fracturing 

through the Paradox Salt formation. If the confining layer had been breached, the breach would 

likely have occurred when injection pressures were high, the hypocenters of the early events 

would likely have migrated from greater depths to shallower depths over time, and earthquakes 
33

would likely have continued to expand vertically and laterally at shallow depths during longterm injection. 

Most of the shallow events near the well occur on or near a single northeast-trending epicenter 

lineation. In addition, many deeper events occur immediately north of this lineation, while few 

earthquakes occur immediately south of it (Figure 12). This epicenter pattern suggests that the 

shallow events may be occurring on a fault that vertically offsets target injection formations. In 

addition, the azimuths of both the fault planes inferred from earthquake focal mechanisms and 

epicenter lineations of the shallow events are different from those of the nearby deeper events 

(Figure 17), further suggesting a structural explanation for the occurrence of the shallow events.

In reference to the vertical extent of earthquakes near the PVU injection well, a consultant 

review board convened by Reclamation in January, 2015, suggested an analysis of the 

waveforms of the shallower and deeper events (Wang et al., 2015). The presence of a discrete 

subsurface salt layer can result in distinct secondary seismic phases due to reflection and phase 

conversion off of the salt formation (e.g., Kraaijpoel and Dost, 2013). Preliminary examination 

of earthquake waveforms does not show easily recognizable secondary phases (Figure 18). It is 

expected that these secondary phases would move out as a function of earthquake depth. Thus 

far, no such secondary phases have been observed. This preliminary examination has been 

performed on multiple distinct coeval earthquake clusters. These observations suggest that there 

is not a distinct seismic discontinuity which separates these earthquakes spanning a range of 

depths. Still, a detailed analysis, possibly incorporating waveform modeling, may better resolve 

the depths of these earthquakes relative to the geologic structure. 
34
35

Figure 12 – Previous Page. From Block et al. (2015b). Map showing epicenters of earthquakes occurring in 

the near-well region of induced seismicity, color-coded by hypocenter elevation (center), and cross sections 

showing distinct vertical offsets of hypocenters (top and bottom). Only a-quality hypocenters from the event 

relative location are included. The labels ‘W’, ‘X’, and ‘Y’ on the map identify abrupt lateral changes in 

hypocenter elevations. Two northwest-striking normal faults interpreted from the hypocenter elevation 

patterns are shown. Our interpreted base of the Paradox salt and top of the Precambrian (solid black lines) 

and the interpreted top of the Leadville formation from Katz and Carroll (1984) (dashed blue line) and 

Bremkamp et al. (1984) (dashed red line) are shown in each cross section. A simplified geologic section at the 

PVU wellbore is included at upper right for reference. Note the color-scale used in this plot and those in 

Block et al. (2015b) are distinct from those in the following figures. 

Figure 13 - Map of earthquakes near the PVU injection well. Earthquakes within 0.1 km of the transect

(black dashed line) are selected and colored by elevation (see legend). The temporal evolution of depth 

sections along this transect are shown in Figure 14. 
36

Figure 14 – Time and depth evolution of earthquakes from the cross section delineated in Figure 13. 

Earthquakes are colored by elevation (depth), as in Figure 13. All earthquakes previous to each time window 

are shown as gray dots. 
37

Figure 15 - Map of earthquakes near the PVU injection well. Earthquakes within 0.1 km of the transect 

(black dashed line) are selected and colored by elevation (see legend). The temporal evolution of depth 

sections along this transect are shown in Figure 16.
38

Figure 16 - Time and depth evolution of earthquakes from cross section delineated in Figure 15. Earthquakes 

are colored by elevation (depth), as in Figure 15. All earthquakes previous to each time window are shown as 

gray dots.
39

Figure 17 - Time and depth evolution of focal mechanisms. Time windows include: (a) 1991–1992; (b) 1993–

1994; (c) 1995–1999; (d) 2000–2001; (e) 2002–2005; (f) 2006–2014. The strike of the preferred fault plane is 

shown as a solid line, colored by elevation (see legend). (See Block et al. (2015b) for details of the focal 

mechanism analysis.)
40

Figure 18 – Earthquake waveforms recorded on the vertical component at station PV16. These earthquakes 

occur in a small cluster and span a range of depths. The black line denotes the bottom of the salt formation at 

the well. If the salt layer were also at this depth at the location of this seismicity cluster, we would expect to 

see secondary phases on the waveforms related to reflection of seismic energy off the salt interface. While 

there is some change in the P-S time between events, there are no distinct arrivals which could be attributed 

to secondary phases (e.g., reflections off the salt formation). 
41

4.3 Effects of Increasing the MASIP

Injection parameters can have substantial impact on the characteristics of seismicity induced near 

an injection well. Empirical correlations reviewed in this section suggest that both the rates and 

magnitudes of events occurring within ~5 km of the PVU well are influenced by temporal 

variations in average injection pressure. The increase in maximum earthquake magnitude over 

time correlates both with cumulative injected fluid volume and with the spatial expansion of 

seismicity clusters, which in turn are related to the injection flow rate and the propagation of 

pore pressure perturbations introduced at the injection well. At PVU, injection parameters have

been altered several times in an effort to reduce the occurrence of large-magnitude earthquakes. 

Reduction in flow rate and increased injection well shut-in time following large-magnitude 

earthquakes in 1999-2000 and 2013 resulted in substantially decreased seismicity rates (Block 

and Wood, 2009; Block et al., 2015a). Based on the relation between injection parameters and 

induced seismicity observed to date, substantial increases in average injection flow rates and/or 

injection pressures, such as might occur in association with an increase in the MASIP, are likely

to have a noticeable adverse impact on future induced seismicity. Below we briefly review the 

relation between injection parameters and induced seismicity observed at PVU.

4.3.1 Induced Seismicity and its Relation to Pore Pressure

Block and Wood (2009) compared seismicity rates and magnitudes with four injection 

parameters: injectate volume, injection flow rate, down-hole pressure, and percent injection time. 

Down-hole pressure exhibited the best correlation with seismicity occurring within 5 km of the 

well. During early injection operations (1996 – 2000), seismicity rates and magnitudes correlate 

well with short-term (≤ 6-month) averages of down-hole pressure. In contrast, later operations 

correlate with long-term (18-month to 30-month) averages of down-hole pressure (Figure 19). 

Higher average pressures correlate with increased seismicity rates and the occurrence of 

earthquakes with M ≥ 2.5. Block and Wood (2009) did not observe similar correlations with 

seismicity in the Northwest Cluster, possibly because of the greater time required for pore 

pressure changes to propagate to greater distances and the decreased amplitude of the pressure 

perturbation with distance. 

Even though a correlation between rates and magnitudes of distant induced seismicity and downhole pressure is not apparent, it is likely that far-field reservoir pressurization is occurring (King 

and Block, 2015). This is supported by the fact that induced earthquakes have been occurring at 

greater distances over the lifetime of the well (Figure 10 and Figure 11). The renewed spatial 

expansion of the induced seismicity observed from 2009-2012 (Figure 11) correlates with 

increasing average injection pressures during this time period (Figure 19). Of particular note is 

the January 2013 ML 4.4 earthquake that occurred 8.2 km northwest of the injection well. This 

earthquake was the first large (> ML 4) earthquake occurring outside of the near-well region 

(Block et al., 2014). In addition, recent analysis indicates that the initial onset of induced 

seismicity as a function of distance from the well is consistent with a model of simple 1-D pore 
42

pressure diffusion (Figure 20), suggesting that pore pressure increase plays a major role in 

triggering of seismicity induced by PVU injection.

Given the relation between injection/pore pressure and induced seismicity discussed above, 

increased average injection pressures would be expected to lead to increased seismicity rates and 

increased likelihood of events with M ≥ 2.5. In addition, seismicity may expand into previouslyaseismic areas if these areas experience pore pressure increases sufficient to cause slip on 

preexisting fractures. These effects are related to local pore pressures, which respond to injection 

pressures applied at the well over substantial periods of time (months to years). Therefore, 

increased injection pressures that are only sustained for short periods of time (days to weeks), 

and are balanced by extra injection well shut-in time (such as might occur during short-term 

reservoir stimulation) would not be expected to substantially affect the induced seismicity, 

expect that occurring very close to the well.

4.3.2 Maximum Earthquake Magnitude

Following the January 2013 ML 4.4 earthquake, Reclamation performed a detailed analysis of the 

estimated maximum earthquake magnitudes that PVU injection could induce (Yeck et al., 2015). 

The analysis was performed following two distinct methodologies. First, observed maximum 

magnitude earthquakes were compared to the cumulative injected volume of brine (Figure 21). 

This work shows that the logarithm of the cumulative injected volume is linearly related to the 

observed maximum magnitude earthquake. The second methodology relies on the size of 

individual clusters of earthquakes (Figure 22). Under the assumption that earthquakes delineate 

areas of pore-pressure alteration sufficient to cause shear slip and that earthquake rupture must 

remain confined within these clusters, estimated magnitudes were calculated based on the 

maximum fault size that could be contained in each cluster. This analysis shows that the rapid 

expansion early in the history of each cluster agrees well with the trend of observed maximum 

magnitudes over time. The results also indicate that there can be delays of several years between 

the time a cluster reaches a threshold for a given magnitude and the occurrence of such an event. 

Both analyses indicate that the estimated maximum earthquake magnitude increased rapidly 

during early injection operations and has remained fairly constant since about 2000.

Changes in injection operations in response to a higher MASIP could influence the rate of 

increase of maximum earthquake magnitude. This effect is likely to be minor, except possibly for 

events occurring within small earthquake clusters. If injection flow rates were increased, the

cumulative injected fluid volume would increase at a faster rate, and therefore maximum 

earthquake magnitudes predicted with the cumulative volume model would also increase at a 

faster rate. However, since the increase in predicted earthquake magnitude is related to the 

logarithm of the cumulative injected volume, the absolute increase in estimated maximum 

earthquake magnitude would still be small. Maximum earthquake magnitudes predicted by the 

cluster model would only increase if pressure perturbations large enough to cause shear slip 

expand to larger areas – i.e., the seismicity clusters grow in size. The sizes of the near-well 

cluster and NW cluster have remained fairly constant since 2000, despite the increased average 

injection pressures during 2009-2012. Stratigraphy and faulting may be limiting their potential 

for growth. Because the rate of maximum magnitude increase is greatest when a seismicity 

cluster is small, maximum magnitude estimations for small clusters would be affected by an 

increase in cluster size much more than the larger seismicity clusters. Hence, it seems that the 
43

only substantial change in maximum earthquake magnitude in response to increasing the MASIP

would occur if currently-small seismicity clusters experience spatial expansion from increasing 

pore pressures. If increased injection pressures are sustained for long periods of time (months to 

years), then earthquake magnitudes in small seismicity clusters distant from the well (such as 

those in the northern Paradox Valley area) could increase. Because of the long time delays for 

pore pressure propagation to these areas, this potential increase in cluster size and maximum 

earthquake magnitude may not be observed for several years.
44

Figure 19 - from Block et al. (2014) (a) Injection downhole pressure data averaged over daily, 6-month, 18-

month, and 30-month time periods, (b) occurrence of induced seismicity as a function of time and magnitude 

within 5 km of the injection well, and (c) at distances of 5–10 km from the well. In the seismicity plots, the 

area of each circle is scaled by the number of events in a given quarter-year and magnitude range. The low 

seismicity rate in the smaller magnitude bins from mid-2005 to mid-2007 in the bottom plot is believed to be 

due to an unusually large number of offline stations.
45

Figure 20 – from King and Block (2015). Seismicity time-distance plots of all shallow (depth < 8.5 km) events 

with magnitude ≥ 0.5 occurring in the vicinity of the PVU injection well. Seismic triggering fronts for the first 

two significant injection tests are overlaid. The triggering fronts were computed using a 1-D linear pressure 

diffusion model and a hydraulic diffusivity of 0.20 m2

/s.
46

Figure 21 - From Yeck at el. (2015). (a) Flow rate as a function of the cumulative injected volume. The gray 

line shows the flow rate during the injection tests (1991 - 1995), while the black line shows the flow rates 

during long-term injection (1996 – 2013). (b) Observed maximum magnitude PVU-induced earthquakes as a 

function of the cumulative injected volume. Least squares fit shown in black, with 95% confidence interval 

(black dashed) and 95% prediction interval (gray dashed).
47

Figure 22 - From Yeck at el. (2015). Maximum crack radius and maximum earthquake magnitude as a 

function of time for the A) Nearwell, B) Northwest, and C) Southeast clusters. Observed maximum 

magnitudes through time are shown as crosses and stars. 

49

5 Conclusions

The current MASIP, 5350 psi, was selected based on a calculated 6106 psi surface injection 

pressure threshold necessary to fracture the confining salt layer. Since the time of these initial 

calculations, little subsequent analysis has been performed in regards to the confining ability of 

the Paradox Salt formation. Therefore, with the analyses performed to date, 6106 psi remains the 

best estimate for the surface injection pressure necessary to fracture the salt. The uncertainty in

this calculated limit is unknown and may warrant further investigation. In addition, the 

subsurface has been altered since the initiation of injection at the PVU, and potential effects of 

changing subsurface conditions on the confining ability of the salt have not been evaluated.

Increasing average wellhead pressures in response to an increase in the MASIP would likely lead 

to adverse changes in the seismicity induced by injection. Based on patterns observed to date, an 

increase in average surface injection pressures would likely lead to increased seismicity rates and 

likelihood of felt events (M ≥ 2.5), at least in the near-well area. Increased pressures could cause 

seismicity to spread to regions that were previously aseismic, as was observed in 2009-2012 

when wellhead pressures were high. Sustained increased injection pressures could potentially

cause pore pressures to increase sufficiently to cause seismicity clusters to grow and thereby 

increase maximum earthquake magnitude within the clusters. Seismicity clusters which are 

currently small (and to date have only experienced events with small magnitude) may be the 

most susceptible to these effects. 

51

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Block, L., and Wood, C., 2011, 2010 Annual Report, Paradox Valley Seismic Network, Paradox 

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