t::::: 

r~::: 

FINAL REPORT 

DEEP WELL INJECTION OF BRINE 

PARADOX VALLEY UNIT 

prepared for 

UNITED STATES DEPARTMENT OF INTERIOR 

BUREAU OF RECLAMATfON 

Denver, Colorado 

Aprll1982 

WilliAMS BROTHERS ENGINEERING COMPANY·· 

A Resource Sciences Company 

RESOURCE SCIENCES CENTER • TULSA, OKLAHOMA 74177 
...... 

··--

-···· 

---

\p· \::: WIEC-691 

1 Executive Summary 

1.1 Conclusions 

1.2 Recommendations 

2 Introduction 

2.1 Location of Project Area 

2.2 Previous Investigations 

2.3 Objective, Phase I 

2.4 Scope of Work, Phase I 

2.5 Conclusion, Phase I 

2.6 Objectives, Phase II 

2.7 Scope of Work, Phase II 

3 Geology 

3.1 Major Geologic Features 

and Data 

3.2 Stratigraphy and Nomenclature 

3.3 Precambrian 

3.4 Paleozoic 

3.41 Cambrian 

3.42 Ordovician-Silurian 

3.43 Devonian 

3.44 Mississippian 

3.45 Pennsylvanian 

3.46 Permian 

3.5 Mesozoic 

3.51 Triassic 

3.52 Jurassic 

3.53 Cretaceous 

i 

Base 

1-1 

1-1 

1-2 

2-1 

2-1 

2-1 

2-3 

2-4 

2-5 

2-5 

2-6 

3-1 

3-1 

3-3 

3-8· 

3-8 

3-8 

3-10 

3-10 

3-11 

3-13 

3-14 

3-15 

3-15 

3-17 

3-18 
L .. \ 

WBEC-1181 

38 Gpy

4 Hydrology 

4.1 Ground Water 

4.2 Surface Water 

4.3 Water Quality 

4.31 Ground Water 

4.32 Surface Water 

5 Potential Disposal and Confining Formations 

5.1 Disposal Formations 

5.11 Devonian (Elbert and Ouray) 

5.12 Mississippian {Madison and Leadville) 

5.13 Permian {Cutler) 

5.2 Confining Formations 

5.21 Overlying Confining Formations 

5.211 Molas 

5.212 

5.213 

Pinkerton Trail 

Paradox Formation (Evaporite Beds) 

5.214 Hermosa Group 

5.22 Underlying Formations 

5.221 Cambrian 

5.222 Precambrian 

6 Reservoir Properties and Deep Well Performance 

6.1 Reservoir Properties 

6.11 Thickness 

ii 

323 

4-1 

4-1 

4-8 

4-8 

4-8 

4-11 

5-1 

5-1 

5-5 

5-9 

5-10 

5-10 

5-10 

5-11 

5-13 

5-13 

5-17 

5-17 

5-17 

5-18 

6-1 

6-1 

6-1 
-····· ...... 

Injected Brine 

6.22 Displacement Mechanism 6-5 

6.23 Variations in the Radius of the 6-5 

Frontal Edge 

6.231 Influence of Dispersion 6-6 

6.232 Fault Barriers 6-8 

6.233 The Uncompahgre Uplift 6-9 

6.234 Mississippian-Molas 6-9 

Paleokarstic Interface 

6.24 Drill Stern Test Data, 6-10 

Exploration Wells 

6.241 Continental, Well No. 1 Scorup 6-11 

6.242 Union, 1-0-30 Ortho Ayers 6-11 

6.25 Pressure Wave Front, 100 Years 6-12 

7 Evaluation of Existing Petroleum Exploration 

Wells for Use as Injection Wells 7-1 

7.1 Chicago Corporation, No. 1 Ayers 7-1 

7.2 Union Oil Company, No. 1-0-30 Ayers 7-1 

7.3 Jack Grynberg, No. 33-3 Martin Mesa 7-5 

7.4 Continental Oil Co. Well No. 1 Scorup 7-6 

7.5 Other Wells 7-6 

8 Recommended Rework of Continental Well, 8-1. 

Scorup No. 1 

WBEC-1181 iii 
9.3 Characterization of the Well Field Brine 95 

9.31 Suspended Solids, Chemical Analyses 9-5 

First Group, March 3, 4, 1981 

9.32 Suspended Solids, Chemical Analyses 

Second Group, May 21, 22, 1981 

9.33 Hazardous Waste Analyses 

9.331 Brine Samples 

9.332 Suspended Solids 

9.34 Radioactivity Analyses 

9.341 Filtered Brine 

9.342 Unfiltered Brine 

9.343 Suspended Solids 

9.344 Conclusions 

10 Surface Treatment Facilities 

10.1 Injection Plant Location 

10.2 Surface Treatment Plant 

11 Impact of Deep Well Injection on the 

WEIEC-&111 

Local Environment 

11.1 History 

11.2 Biological Impacts 

11.3 Economic and Social Conditions 

11.4 Water Resources 

11.5 Water Quality 

11.6 Land Use 

11.7 Unavoidable Adverse Effects 

11.8 Short and Long-Term Environmental Uses 

11.9 Disposal Formations 

iv 

9-8 

9-10 

9-10 

9-10 

9-13 

9-15 

9-16 

9-16 

9-16 

10-1 

10-1 

10-1 

11-1 

11-1 

11-2 

11-3 

11-4 

11-5·· 

11-5 

11-5 

11-6 

11-6 
-······ 

11.12 Conclusion$ 

12 Potential Problems of Injecting the 

Well Field Brine 

12.1 Installing the System 

12.11 Excessive Drilling Costs 

12.12 Low Injectivity 

12.13 Local Opposition 

12.2 Operating the System 

12.21 Plugging of the Cartridge Filters 

12.22 Corrosion Problems 

12.23 ·power Outages 

12.24 Seismic Activity 

12.25 Closure of Continental Well, Scorup No. 1 

13 Seismic Activities 

13.1 Public Concern 

13.2 Lisbon Valley Injection Well 

13.3 

13.4 

13.5 

Induced Seismicity 

Paradox Valley Conditions 

Seismic Monitoring 

14 Injection Well Test Program 

15 Bibliography and References 

v W BEC-6111 

119 

12-1 

12-1 

12-1 

12-1 

12-1 

12-2 

12-2 

12-2 

12-2 

12-3 

12-3 

13-1 

13-1 

13-3 

13-4 

13-4 

13-5 

14-1 

15--·1 
f·· , r·.·:· 

31 

3-2 

3-3 

3-4 

3-5 

3-6 

3-7 

3-8 

4-1 

4-2 

4-3 

5-1 

5-2 

5-3 

5-4 

5-5 

Wlf:C-691 

Paradox Anticline, Stages of Development 32 

Reconnaissance Scale Map of Paradox Valley 3-4 

Geologic Map of Paradox Valley 3-5 

Explanation and Symbols for Figure 3-3 3-6 

Regional Geological Cross Section of 3-7 

Paradox Valley 

General Stratigraphic Column 3-9 

Paradox Valley 

Tectonic Index Map of Paradox Basin 3-20 

(Salt Anticlines) 

Tectonic Map of Paradox Basin Area 3-24 

Brine - Fresh Water Interface 4-2 

Potentiometric Map of the Mississippian 4-4 

Formations 

Cross Section of Well Field, Showing 4.-6 

Fresh-Brine Interface 

Isopach Map of Devonian - Paradox Basin 5-2 

Structure Map - Paradox Basin (Devonian) 5-3 

Isopach Map of Mississippian - Paradox 

Basin 

Structure Map - Paradox Basin 

(Mississippian) 

Site Specific Structure Map · 

vi 

5-4 

5-6 

5-7 
5-7 

5-8 

5-9 

5-10 

6-1 

7-1 

7-2 

7-3 

7-4 

9-1 

10-1 

10-2 

10-3 

13-1 

WlfC-691 

Potentiometric Map of the Pennsylvanian 

Pinkerton Trail 

Isopach Map, Top Salt to Base Salt 

Paradox Formation 

Potentiometric Map of the Paradox Member 

of the Pennsylvanian Hermosa Formation 

5-14 

5-15 

5-18 

Isopach of Total Cambrian Rocks 5-20 

Injected Brine Frontal Movement vs. Time 6-8 

Chicago Corp. Exploration Well No. 1 Ayers 7-3 

Union Oil co. Exploration Well No. 1-0-30 7-4 

Ortho Ayers 

Jack Grynberg Exploration Well No. 33-3 7-7 

Martin Mesa 

Continental Oil Exploration Well No. 1 7-8 

Scorup-Somerville-Wilcox 

Changes in Suspended Solids Concentrations 9-9 

Resulting from Shutdown and Startup of the 

Brine Wells 

Location of Brine Well Field and Proposed 10-2 

Injection System 

Detailed Topographic Map of Project Area 10-3 

Process Flow Diagram No. 4 10-5 

Seismic Map Paradox Valley 13-6 

vii 
4-2 

4-3 

4-4 

5-l 

6-1 

6-2 

7-1 

9-1 

9-2 

9-3 

9-4 

9-5 

y 

Chemical Analysis of Waters from Several 4-12 

Deeper Formations 

Chemical Analysis of Mississippian Brines 4-13,14 

Chemical Analysis of Dolores River Water 4-15 

Summary, Potential Formations for Brine 5-8 

Disposal, Paradox Valley Area 

Estimated Gross and Net Thickness, 6-3 

Mississippian and Devonian Formations 

Radius of Injected Brine Bubble, Minimum 6-5 

and Dispersed Travel Distances 

Summary of Existing Petroleum Exploration 7-2 

Wells, Paradox Valley, Montrose County, 

Colorado 

Analysis of Brine Samples 9-6 

Suspended Solids Content, Brine Wells ~n 9-7 

the Well Field 

Hazardous Waste Analysis, Filtered and 9-11 

Unfiltered Well Field Brine 

Hazardous Waste Analysis, Suspended Solids 9-12 

from Well Field Brine 

Radioactivity Analysis, Filtered, 9-14 

Unfiltered Brine and Suspended Solids 

viii 
vicinity of the brine well field in the Paradox Valley 

have the desired characteristics for satisfactory 

long-term disposal of the brine. 

o Formations above the Mississippian and Devoniqn, 

notably the Hermosa Paradox Member, a massive salt 

formation interbedded with other facies, provide a 

- positive barrier to upward brine migration. 

r::: 

f····· 

o With a properly engineered installation and 

appropriate operation, the injected brine will . remain in the designated disposal formations 

with no breakthrough to the surface or to fresh 

water zones. 

o The required number of disposal wells to inject the 

specified brine rate of 900 gpm cannot be established 

until the first well is completed and tested. The 

limited information available indicates that one 

well may have sufficient capacity for the entire 

900 gpm rate. 

o There is a possibility that the wellhead pressure 

will increase faster than the calculated rate, 

1-1 
,.-· 

~ ······ 

c::::: 

r:::. 

I····· 

r::::: 

1.2 

o A second well, drilled on the southwest side of the 

faul~would penetrate the Mississippian and Devonian 

at a total depth of only 9000 feet. 

o The proposed brine disposal system can be operated 

indefinitely with no significant negative impact on 

the environment. No change in seismic activity in 

the area is anticipated; however, if an increase does 

occur, the recommended monitoring program will permit 

early detection. 

RECOMMENDATIONS 

o Plans should be made immediately for installation of 

the disposal well system. Because o:f the escalation 

of drilling and other oil field related costs, delay 

of the program will result in a signi£icant cost 

increase. 

0 A contract should be negotiated with the landowner 

to provide purchase or long-term lease of the 

Continental Well, Scorup No. 1. 

o Assuming a satisfactory lease or purchase agreement 

for the Continental well, the surface casing in this 

1-2 
( ' ...... 

c: ... [ .. i ..... . 

!·······l 

[._ ...... 

... 

installed along the pipeline right-of-way between 

the brine field and the well. This is an optional 

item. If preferred, the two-week injection test 

can be performed prior to installing the filter system. 

o Additional well requirements, if any, should be 

determined by evaluation of the two-week injection 

test. 

o A network of eight sensitive seismometers should be 

installed in the project area as soon as possible 

to obtain baseline seismic data. 

0 If the wellhead pressure buildup in the first well 

during the first few years is faster than expected, 

consideration should be given to drilling a second 

well on the southwest (the uplift) side of the major 

fault near the Chicago Corporation No. 1 Ayers well. 

1-3 
WlfC-691 

The study area of Paradox Valley is located in Montrose 

County of southwestern Colorado just east of the 

Colorado-Utah State line in Township 47 North and Range 

18 West (Figure 2-1). The valley is trenching northwestsoutheast to the Utah Border and has several hundred 

feet of rock walls rising on either side. The Dolores 

River cuts through these walls and flows to the northeast toward the Colorado River. 

The project area is served from the east and west by 

State Highway 90, from the east by State Highway 145, 

and from the north and south by State Highway 141. 

Communities in the Paradox Valley include the small 

farming towns of Paradox (population 200) and Bedrock 

(population 80) • The nearest commercial center is Moab, 

Utah, 60 miles to the northwest of Bedrock. 

2.2 PREVIOUS INVESTIGATIONS & DATA BASE 

All available sources of potentially usable information 

on geologic, hydrogeologic and related subjects on or 

adjacent to the study area were reviewed. References 

are listed in Section 15 of this report. 

2-1 
I 

I 

:r: \~ ,a: 

~ :;:) '\% (.) 

\ 

~ROSE 

1

_ ... MIGUEL CO. 

I 

I 

Source- Bureau of Reclamation (9) 

t 

I 

DRY CREEK BASIN 

e Existing Oil Exploration Wells 

A A:-----· Location of Cross Section 

Scale of Miles 

0 ' • 

Figure 2-1 

Location Map of Paradox Valley Unit Project Area 

W8EC-6il 2-2 
!. ..... 

WltC-6tl 

of various oil companies and results of drill stem tests 

as compiled by Petroleum Information Corporation, 

Midland, Texas. 

The most significant work in the study area is in the 

four volumes of "Colorado River Basin Salinity Control 

Project, Paradox Valley Unit" prepared by the Bureau of 

Reclamation in 1978. 

Additional information was obtained by physical 

inspection of the area and from analysis of water and 

suspended solids samples taken from the well field. 

2.3 OBJECTIVE, PHASE I 

The Dolores River, during its course across the valley, 

receives approximately 200,000 tons of salt annually 

from the surfacing of highly saline groundwater and 

carries this load to its confluence with the Colorado 

River. The salt content of the Colorado River is 

deleterious to irrigation and other usages. The economic 

value of the removal of 1 mg/1 of salt from the Colorado 

River is reported to be $472,000 per year, based upon. 

January, 1981 prices. (Additional comments: Section 11.3). 

To cope with this salt problem, a system of intercepting 

and collecting this brine using a well field has been 

2-3 
WIEC-H I 

o Evaluate the hydrogeologic conditions. 

o Evaluate the selected rock formations which are 

to be used as a disposal zone. 

o Assess the impact of deep well injection on the 

local environment. 

o Prepare feasibility level construction cost 

estimates of the brine treatment, pumping, well 

drilling and other associated operating and 

maintenance cost. 

2.4 SCOPE OF WORK, PHASE I 

The scope of work was defined as follows: 

o Collect and evaluate all available geologic, 

hydrogeologic, geophysical and engineering data 

in the study area. 

o Conduct a surface and subsurface geologic 

reconnaissance of the Paradox Valley and vicinity. 

o Determine geological structure and hydrologic 

conditions. 

2-4 
possible use as injection wells. 

o Assess the impact of deep well injection on the 

local environment. 

o Identify the potential problems in injecting the 

Paradox Valley brine. 

o Prepare feasibility level construction cost 

estimates of the brine treatment, pumping, well 

drilling, pipeline, and other required facilities 

and associated operating and maintenance cost. 

o Prepare a final report that includes all conclusions 

and recommendations. 

2.5 CONCLUSION, PHASE I 

It was concluded upon completion of the Phase I study that 

deep well disposal of the Paradox brine is technically 

and economically feasible. Approval to pro cede with the 

Phase II effort was received May 7, 1981. 

2.6 OBJECTIVES, PHASE II 

0 Design a test program. 

0 Design injection facilities and equipment. 

2-5 
WIIC-1 

p

o Prepare design and drilling specifications for 

drilling of a new well or rehabilitation of an 

existing well that would be used as the injection 

well. 

o Specify an injection rate for the testing program. 

0 Design the pipeline and facilities that will 

transport the brine from the existing well field 

pipeline system to the injection test site. 

o Design a treatment system if applicable. 

o Design the injection well head, injection pumping 

system and connection to treatment system. 

o Design methods and procedures that will be followed 

for the actual injection testing. 

o Design and specify an appropriate environmental 

monitoring program which can be used during the 

injection testing. 

o Furnish a complete handbook of interpretation 

methods specifically formulated for the injection 

testing and environmental monitoring program. 

2-6 
WlfC-1 

2-7 
WBEC-IPI 

trough on the northeast side adjacent to the Uncompahgre 

Uplift. Rocks of Mississippian age have about 16,000 feet 

of structural relief between the Uncompahgre Uplift and · 

the trough. The structural relief between the shallower, 

southwest part of the Paradox Basin and the deep trough is 

about 9,000 feet. About 16,000 feet of Pennsylvanian, 

Permian and lower-to-middle Triassic beds fill the trough 

and pinch out abruptly against the Uncompahgre front, 

which forms the northeast margin of the basin. Younger 

beds of Mesozoic age that extend from the basin across the 

front are flexed and broken in a complexly faulted monocline at the front. 

Paradox Valley lies along one of five major salt anticlines 

present in the Paradox Basin. The valley was formed by 

the erosion of faulted and uplifted formations exposing a 

residual gypsum cap. Figure 3-1 illustrates the development of the valley. The emergence of distant mountains on 

each side of the area placed lateral pressures on the 

intervening sedimentary formations, resulting in warping 

and fracturing along weak zones. Consequently, a deeply 

buried layer of salt began to flow upward into the fractured area, creating an anticline. The crest of the anticline has gradually collapsed as a result of the fracturing. 

The Dolores River, combined with other erosional forces, 

worked to remove the collapsing materials and give the 

valley its present form. 

3-1 
..... ~·., .... _., ....... ""~,..,, ., ....... 1 ..... 

~ ... ..... .. .. . 

EARLY STAGE 

PRESENT STAGE 

FIGURE 3-1 PARADOX ANTICLINE STAGES OF DEVELOPMENT 

Source: Reference (9) 

3-2 

·.· 
Paradox Valley anticline by the Continental Oil, Well No. 1 

Scorup. 

Pennsylvanian and Permian beds of the Paradox Valley are 

composed of marine evaporites and carbonates. About half 

of the total volume of these beds in the deep part of the 

basin consists of salt and minor interstratified carbonate 

and clastic rocks of the Paradox member o£ the Hermosa 

formation. 

The Triassic, Jurassic and Cretaceous formations crop 

out in and around a series of northwest trending faulted 

anticlines. Figure 3-2 is a reconnaissance scale map 

showing the location of the brine well field and five of 

the exploratory oil wells which have been drilled in the 

area. 

Figure 3-3 shows the general geology of the area. Symbols 

for the interpretation of Figure 3-3 are displayed on 

Figure 3-4. A regional geologic cross section of the 

Paradox Valley area is shown on Figure 3-5. 

3. 2 STRATIGRAPHY AND NOMENCLATURE 

Stratigraph relationships in the Paradox Basin are complex. 

The same formation or equivalent stratigraphic unit will 

3-3 
-=e-=-

...... c..... 

PH 

PH O 

ll 

"1 

wl I 

I 

J 

... .. ,-, 
3.3 PRECAMBRIAN 

Rocks of Precambrian age exposed on the Uncompahgre Plateau 

are predominantly granite gneiss and a variety of massive 

granite, pegmatite, and subordinate micaceous schist (43). 

The Precambrian rocks exposed on the Uncompahgre Uplift 

may not be representative of the Precambrian rocks under 

the deep part of the Paradox Basin. 

3.4 PALEOZOIC 

3.41 Cambrian 

No Cambrian rocks crop out within the Paradox Valley 

or Paradox Basin region. Several deep wells have 

penetrated the sequence, providing a regional picture 

of the Cambrian environment. In the San Juan Mountains 

of southwestern Colorado, the Ignacio quartzite is 

exposed forming the basal formation of the Cambrian. 

The Ignacio is considered to be of late Cambrian age (14). 

Barnes (2) suggested that the quartzite may be late 

Devonian in age. These rocks record the earliest 

marine invasion of the area during Pa1eozoic time (13). 

It is believed that the weathered Ignacio quartzites, 

3-8 
w 

I 

\0 

::. 

Wlli/\MSilROT

·=*-'= 

.. c......... 

GEOLOGIC TIME UNITS 

AGE I SYSTEM 

CENOZOIC QUATERNARY 

CRETACEOUS 

JURASSIC 

MESOZOIC 

TRIASSIC 

PERMIAN 

PENNSYLVANIA

PALEOZOIC MIIIIIIIPPIAN 

DEVONIAN 

SILURIAN 

ORDOVICIAN 

CAMBRIAN 

PRE·CAMBRIA

SOURCE: COLORADO GEOLO

,. ... 

- ( -Aii i 
controversial. Some geologists believe that they were 

not deposited in this area. 

3.43 Devonian 

Rocks of Devonian age have been encountered in several 

wells in the Paradox Basin. The earliest rocks deposited in the Devonian age have been named the Aneth 

formation. The formation consists of dense, darkcolored sandy dolomite, generally argillaceous and 

containing numerous interbeds of dark gray shale. The 

shales are gray-green and brown, and some are carbonaceous ( 3 6) . 

The Aneth sediments represent an early phase of 

deposition by the encroaching post-Cambrian Cordilleran 

Seas. A portion of these segments may have been eroded 

by a minor retreat of the sea. The formation is found 

in the Aneth-Bluff fields of San Juan County, Utah, 

but it is not known whether it is present in the Paradox 

Valley area. 

The age of the overlying Elbert formation is late . 

Devonian (36). In the Paradox Valley area, the Elbert 

consists of the lower McCracken Sandstone member and 

an upper member which is sandy, thin-bedded, and has 

3-10 
formation. The depositional change from the Elbert 

to the overlying Ouray formation, from sandy dolomite 

to clean limestone, seems to be gradational. 

The Ouray is a dark brown, light gray, dense limestone 

often oolitic, locally dolomitized and massive, composed of micrite, pelleted micrite, and skeletal material 

suggesting a quite water marine environment of deposition (1). 

3.44 Mississippian 

The Mississippian consists of four members. From top 

to bottom these are: 

o Thin-bedded, very fine graned limestone 

and chert beds. 

o Thick-bedded, massive limestone ranging from 

aphanitic (very fine grained) to· coarse 

grained, largely crinoidal. 

o Alternating thin limestone and chert beds_. 

o A thick-bedded unit composed of limestone 

and some dolomite. 

3-11 
gg

in thickness from 300 feet to 400 feet in the Paradox 

Valley area. It unconformably overlies the Devonian 

in some places. The Leadville is similar to the Ouray 

formation in that it is light colored, dense and sometimes oolitic. The zone is usually porous and permeable 

in part and contains oil and gas in same areas. Several 

wells have been drilled through this formation in Paradox 

Valley. None of them showed presence of oil and gas. 

The Madison limestone constitutes the dolomite phase. 

It consists of a massive dolomite which is tan, brown, 

gray and occasionally pink. Its texture is coarsely 

crystalline to finely sucrosic. The section usually 

exhibits both granular and vugular porosity. It is 

often cherty, and in some areas thin beds of l~estone 

appear near the top. It is a clean dolomite. Thin 

shales that appear here and there are very local in 

nature. Most of the oil and gas shows of the Mississippian in the Paradox Basin have been found in the 

dolomite phase. The porosity in the dolomite phase 

of the Mississippian is widespread and is generally 

scattered throughout the section. 

After the deposition of this phase of the Mississippian, 

the surface was deeply eroded and the red soils of the 

Molas (Pennsylvanian) were deposited. 

3-12 
fairly deep soil cover formed (24). This Paleokarst 

surface is overlain by the beds of fluvial conglomerate 

of the Molas formation. 

The Molas is a clastic red bed sequence of reddishbrown to variegated siltstone, red shale, calcareous 

sandstone and some gray-to-reddish limestone lentils. 

The basal part of the formation is comprised of boulders 

and cobbles. The formation is considered to be the 

result of reworking the underlying limestone regolith. 

The thickness varies from a few feet to over 150 feet. 

In the Paradox Valley area, it is 50 to 60 feet thick. 

The Hermosa formation can be divided into three main 

units; the Lower Hermosa, known as Pinkerton Trail 

formation, the Paradox·members, and the Upper Hermosa, 

known as a Honaker Trail. 

The Pinkerton Trail is the lowest formation of the 

Hermosa group. This formation is a fine .to mediumgrained, crystalline, fossiliferous marine limestone, 

interbedded with gray, silty shales and anhydrite. The 

thickness varies from a few feet to 195 feet in the 

Paradox Basin. In the Continental Scorup well of·. 

Paradox Valley, only 41 feet of Pinkerton Trail was 

encountered (Laterlog in cover pocket). 

3-13 
r·.-

~::::: 

The Honaker Trail formation is the uppermost member 

of the Hermosa group. In general, it is a sequence of 

interbedded limestone, shales and sandstones of marine 

and fluvian origin. 

The Pennsylvanian-Permian Rico formation is composed 

predominantly of red-buff to blue-gray, dense to 

calcarenitic marine limestone, reddish-brown siltstone 

and limey sandstone. The facies lie conformably on 

and intertongue with Honaker Trail strata below. 

3.46 Permian 

Permian stratigraphy in the Paradox Basin is characterized by the interfingering of sediments, mostly lightcolored sandstones and red beds, that grade into one 

another from source areas in opposite directions. 

Permian rocks appear to grade conformably upward from 

Pennsylvanian strata adjacent to the Uncompahgre Uplift •. 

The entire basin was eroded prior to the deposition of 

Triassic tocks. Folding, parallel to the trend of the 

Uncompahgre, took place in the eastern part of the 

area as a result of salt flowage within the Paradox 

member of the Hermosa formation. The resulting 

3-14 
to finegrained arkosic sandstone, coarse red and pin~ 

arkosic granite wash, micaceous silty shale and tan, 

finely crystalline limestone (31). The arkosic material 

is poorly sorted, forms cross-bedded layers and lenses 

and consists of quartz, fresh feldspar, dark minerals, 

and pebbles of granite, gneiss, schist and quartzite, 

the material derived from the Precambrian crystalline 

rocks. The base of the Cutler, when recognizable, is 

called the Rico formation and is placed at the top of 

the fossiliferous limestone bed. This represents the 

transitional bed between the Hermosa and Cutler 

formation. 

The formation thickness varies widely because of the 

nature of their deposition. The formations have a 

maximum known thickness of 13,000 feet. The three 

wells drilled in the Paradox Valley area encountered 

3,500 to 4,500 feet of Cutler formation. Carter and 

Craig estimated some 9,000 feet of Cutler to be on 

the flanks of the Paradox Valley. 

3.5 MESOZOIC 

- 3.51 Triassic 

The Triassic system of the salt anticline region 

consists, in ascending order, of the Moenkopi formation, 

3-15 
Gypsum Valley, and Dolores anticline. In most of 

the region, it rests unconformably on the Cutler 

formation. The Moenkopi is divided into three 

units (47). The lower unit consists of pale, reddishbrown sandy siltstone to silty sandstone with thin 

gypsum bed and abundant scattered medium-to-coarse 

quartz grains. The middle unit consists of pale red 

and pale reddish-brown cross-stratified sandstone 

and conglomerate and interstratified reddish-brown 

siltstone. The upper unit consists of a homogeneous 

sequence of horizontally-laminated to thick-bedded, 

pale, reddish-brown and light brown siltstone containing veinlets of white gypsum. The thickness of 

all three units of the Moenkopi are between 200 and 

1,000 feet. 

The Chinle formation crops out throughout the Salt 

Anticline and Uncompahgre Plateau regions, except 

where it is absent locally on the crest of some of 

the anticlines. 

The Chinle formation consists dominantly_ of reddishbrown siltstone and sandstone. A thin discontinuous 

coarse sandstone and conglomeratic sandstone layer is 

present at the base of the formation in most of the 

region. The thickness of Chinle ranges between 200 

and 750 feet. 

3-16 
pg 

valleys. The formation consists of fine-grained, 

orange-red, tan-to-white sandstone. It is considered 

to be largely an eolian deposit composed of dune sand. 

The Kayenta lies conformably over the Wingate and is 

composed of bedded fluvial red sand, silt and limestone. 

The thickness of Kayenta ranges from 60 to 320 feet. 

The Navajo is the uppermost formation of the Glen 

Canyon group and lies conformably on the Kayenta. It 

consists of fine-grained, well sorted, light buff, 

gray-to-white sandstone. 

3.52 Jurassic 

The lithology of overlying Entrada is generally red, 

buff and orange, horizontally-bedded sandstone. It 

grades laterally, westward in Utah, into a red, earthy 

siltstone. The thickness of formation ranges from 

40 to 200 feet. 

The Summerville formation is red siltstone and claystone, evenly interbedded with thin beds of white·, 

very fine sandstone. The formation is about 75 feet 

thick and pinches out in many places along the crests 

of the anticlines. 

3-17 
y, 

Morrison in this area ranges from 600 to 800 feet. 

3.53 Cretaceous 

The Burro Canyon formation is a basal conglomerate, 

unconformably overlying the Morrison formation. In 

general, the Burro Canyon consists of a gray-to-brown 

conglomerate or conglomeratic sandstone, fine-to-verycoarse grained, subrounded to subangular. The thickness 

of the formation is about 150 feet in the Paradox area. 

The Dakota sandstone unconformably overlies Burro 

Canyon. The Dakota formation is often separated 

into three different lithologies. The basal member 

consists of medium-to-fine grained sandstone with 

some conglomeratic lenses. The middle unit consists 

of thin-bedded carbonaceous siltstone and coal, and 

the uppermost unit is defined as a silty, thin-bedded 

sandstone. Total thickness of the Dakota is about 

150 feet. 

3. 6 CENOZOIC 

3.61 Quaternary 

Alluvial deposits fill most of the Paradox Valley floor 

and are composed of talus, piedmont and alluvium. They 

3-18 
belt of the northeastern Paradox Basin (Figure 3-7). The 

area is dominated by northwesterly-trending folds and faults 

which are commonly staggered and in places broadly curved. 

Most of the folding and piercement probably occurred before 

Triassic time, and the degree of compression and flowage 

of salt was much greater than appears superficially. 

Flowage of the salt began as early as the time of deposition of the upper part of the Hermosa formation (20). The 

stratigraphy and structure of younger Paleozoic beds 

flanking the salt cores reflect the upwelling of salt 

from the area peripheral to the cores. During the earlier 

stage of the collapse, portions of the crest of the anticlines dropped, as grabens, as much as several hundred 

feet. These grabens may have formed during relaxation of 

stresses that caused the folding. 

Rise of the salt continued through Triassic and Jurassic 

times, as did the topographic expression of the piercements (Figure 3-3). By the end of the Jurassic time, salt 

flowage appears to have ceased and the anticlines were 

gradually buried in Morrison time. In late Cretaceous 

and early Tertiary times, folding and faulting occurred 

again following closely along the lines of the deeply 

buried salt anticlines and piercements. 

3-19 
,., 

/ ~ 

z 

.., 

2 

::> 

z 

Q 

2 

------~-- ~·· .... 

I 

r----

FIGURE 3-7 

MONTI'i~S£ 

COUN'7T 

-· •••te• 

=._. 

TECTONIC INDEX MAP OF PARADOX BASIN SHOWING SALT ANTICLINES AND 

LIMITS OF SALINE FACIES AND POTASH IN THE PARADOX MEMBER OF THE 

HERMOSA FORMATION (FROM HITE, 1961). 

WBEC-681 3-20 
~····· 

these cell-like plugs and composite masses are probably 

connected at depth to a low ridge of salt that is continuous 

for the length of the anticline. 

At the northwest end of the Paradox Valley, the structural 

features of the faulted anticline are even more complex, 

where the laccolithic, igneous intrusives form the La Sal 

Mountains. The alignment of late Paleozoic salt intrusives 

with the south mountain group of igneous intrusions in the 

La Sal ?-1ountains indicates this group was intruded along 

a zone of previous structural activity. 

Drill hole information indicates that there is a general 

rise or subsurface ridge of the Paradox member extending 

along the middle of the Paradox Valley. 

The three structurally distinct units in the Paradox Valley 

anticline are characterized by the types of structural 

feature developed during collapse of the crest of the anticline. There is 1) a unit at the southeast end of the 

anticline where the crest has downsagged to form a structural 

basin, 2) a large central unit occupying most of Paradox 

Valley where the crest has collapsed by downfaulting, and 

3) a unit at the northwest end of the valley that collapsed 

by both downsagging and downfaulting. Mesozoic rocks are 

preserved in the downsagged crest of the anticline at either 

3-21 
a structural basin. The basin is bordered on its northwest 

end by northeast trending faults. The northeast and southwest sides of the basin are bordered by anticlines between 

which a syncline formed because of sagging of the crestal 

part of the Paradox Valley anticline. 

The central structural unit of the Paradox Valley anticline, 

the largest and most complex of the three units, appears to 

have a salt core from which a number of cupolas rise. 

Numerous closely spaced faults on both sides of the valley 

cut the rocks into long narrow slivers trending parallel to 

the length of the valley. Southwest of the Dolores River, 

grabens have formed back from the rims on both sides of the 

valley. Several northeast-striking transverse faults cut 

the northwestern part of the central unit. Because the 

Paradox beds were partly intrusive into the core of the 

anticline, stratigraphic relations vary considerably in 

the central structural unit. 

The northwest structural unit of the Paradox Valley anticlineconsists of downwarped and faulted rocks that dip valleyward. 

The northeast flank of the anticline below Carpenter Ridge· 

is highly faulted, and fault blocks are commonly downdropped 

toward the valley. 

3-22 
~ ..... 

including the Paradox Valley. 

The two most significant structural features affecting the 

disposal well operation are the pinchout of the Mississippian 

to the northeast (the Uncompahgre Uplift) and the major 

fault about 4 miles southwest of the brine well field. Both 

features will tend to cause wellhead injection pressure to 

increase somewhat faster than they would in an isotropic 

formation. They also will have some effect on the shape 

of the injected brine bubble. 

3.8 GEOPHYSICAL WORK 

Several companies conducted geophysical work in the general 

vicinity of the project area. Geodata and North American 

Exploration Company (NAE) were contacted to determine what 

geophysical records were available for Township 47 North, 

Range 18 West. In Section 8, where the Continental well 

is located, Continental ran both 100 percent (on tape) and 

Common Depth Points (CDP). The CDP offers more coverage 

by utilizing more shots and receptors. NAE and Texaco 

conducted CDP in Sections 7, 8, 17 and 18. 

Cost of these data varies from $850 per mile for Texaco's 

CDP to $1150 per mile for Conoco's CDP, each requiring a 

ten-mile minimum. The 100 percen~ tape data sells for 

$45 a shotpoint. 

3-23 
t •.•. 

t:: 

. I.) ;; 

i"O:I 

0 • .... g I.) : 

.... 

"" .. . 

i 

D 

Fl.gure 3-8 

TECTONIC MAP OF PARADOX 

3-24 

... "' ... . .... 

... 

... 

... 

.... 

' 

BASIN AREA 

'>-, 

e 

. 

... 

.. 

... 

..... 

.... • 
WlfC_...,I 

.• 

In consideration of the $10,000 to $25,000 cost of obtaining 

the information for the necessary cross sections and the 

small probability of obtaining a good isopach, decision was 

made to not purchase the data. 

Samples of the available data were obtained, and subsequent 

analysis confirmed that construction of an accurate isopach 

was improbable. 

The investigation was of considerable value for another 

reason: additional data were obtained regarding the major 

fault which was known to exist about 4 miles southwest of 

the Continental well. 

The reconnaissance quality seismic map supplied to us from 

Geodata Corporation, combined with data from other sources, 

indicates that the major fault which traverses the area 

between the Chicago Corp. No. 1 Ayers well and the Union 

Oil Co. No. 1-0-30 Ayers well has a displacement of about 

6,000 feet. Therefore, depth to the top of the Mississippian. 

on the upthrow side of the fault will be about 9,000 feet. 

The four-mile distance to this area is a negative factor, 

but it may be an appropriate area to drill an additional 

well if excessive pressure buildup is encountered in the 

Project Area after long-term operation of the 15,000 foot 

disposal well(s). 

3-25 
The Dolores River has deposited alluvia over the Paradox 

member of the Hermosa formation. The alluvial deposits 

are stratified, varying from fine, poorly graded sand to 

clay-filled gravels just above the residual gypsum cap. 

The Paradox member of the Hermosa formation underlies the 

entire valley and is exposed in the eastern part as gypsum 

hills extending along the axis of the anticline. Along 

the river, this member lies below the alluvial deposits. 

Two types of shallow groundwater zones are identified in 

the Project area. The fresh water zone overlies a heavy 

brine water zone. An artist's concept of the brinefreshwater interface with and without the well field in 

operation is shown in Figure 4-1. 

Brine groundwater, which apparently underlies all of the 

Paradox Valley at varying depths, surfaces in and near 

the Dolores River channel in two areas extending from the 

middle of the valley, downstream to the river's exit from 

the valley. The depth to brine appears to increase 

upstream and west of the river, where the brine zone 

is approximately 100 feet deep. To the east of the 

river along the valley floor, the top of the brine layer 

is at about the same level as the river and extends up 

to 50 feet beneath the surface. It is estimated that 

the brine flow to the river varies from 0.2 to 2.1 cfs 

and averages 0.8 cfs (9). 

4-1 
r 

t 

t. 

i• ' 

·-

\ • ... \a '"' ."-' •••• 

..... 

~ 

""' 

WITHOUT 

WELL FIELD 

~.,, .:=. ~ ,.,, ··~ 1,.,, WITH 

~ ,,,,;; WELL FIELD ,,, - "' 'fl$- ~ ' If/ ~...,. 

GYP SUM and SALT ~ ~\I q/ ~I ,S ~ 

Figure 4-1 

BRINE- FRESHWATER INTERFACE 

Colorado River Basin Salinity Control Project 

Paradox Volley Unit, Colorado 

(from Final Environmental Statement BOR 3-20-79 

4-2 
salt core and thereby becomes brine.. The predominance 

of sodium chloride in the brine indicates that the source 

of the salt is in the halite-rich salt core. 

The possibility that brine may be derived from deep sources 

below the Paradox member is negligible because salt beds 

have a low hydraulic conductivity and could not transmit 

the water at a significant rate. 

The Mississippian Leadville formation is the only significant deep aquifer in the area (30). A potentiometric map, 

Figure 4-2, indicates that the brine movement in the 

project area is northwestward. The potentiometric surface 

apparently is influenced by the regional dip which slopes 

to the southwest (23). The Leadville is overlain by Molas 

and Pinkerton Trail formation which is predominantly shale. 

This shale formation forms an effective barrier between 

the Paradox member and the Leadville formation. 

The discharge areas from the Mississippian are from 

the canyon walls along the Little Colorado River in 

Northeastern Arizona approximately 220 miles from the 

project area. Brine pressure wave calculations indicate 

that the pressure wave will advance only 83 miles from 

the project area after 100 years of disposal at the rate 

4-3 
.r:.. 

I 

.r:.. 

r ........... 

I ,....._ /··"' ,-·- 1 I I 
feet of fresh water. Heads are conventionally given in 

feet of fresh water to facilitate comparisons between 

various aquifers in a region. The water presently in the 

Mississippian and Devonian has a specific gravity of 

about 1.18. This combined with a pressure of 6500 psi 

in the Continental well at a depth of 14,780 feet {9730 

feet sub sea level) results in a potentiometric head of 

2,982 feet for the Mississippian brine versus 5,270 feet 

for fresh water. 

The specific gravity of the brine from the well field is 

about 1.164, resulting in a potentiometric head of 3,157 

feet. The difference in the potentiometric head of the 

injected brine and the elevation of the well collar will 

assist the injection. This "free" available head will 

be: 5050 feet - 3157 feet ·or 1893 feet. The available 

head of 1893 feet x 0.5044 psi/ft. is equal to 955 psi 

which will assist the injection pumps. The pressure at 

_the wellhead of the injection well will be less than zero, 

i.e., "on vacuum" when the disposal rate is less than that 

required to fill the well to the surface. 

A fresh water zone overlies the brine in western Paradox 

Valley with a hydraulic gradient toward the river. 

Figure 4-3 is a cross section of the well field showing 

4-5 
·-

•:oo 

·-· I•• 

--

..... 

- 

- lit I 

--t 

- 

ALLUVIIIII 

_,_ 

-

: II :: 1r 

-i " 

. 

' 

-· 

_ , , ..... .. "'· 

- 

: I I 

--.,. 

-·-•·- 

... - 

OIOO • 

....

.,, ... 
also contributes to the river flow as seeps and springs. 

The combined fresh water and brine flows make a total 

contribution to the river of 1.5 to 4 cfs (9). 

Recharge to these aquifers is from precipitation, runoff 

from the La Sal Mountains, irrigation return flows from 

western Paradox Valley, and seepage from ~st Paradox 

Creek. 

Recharge to the brine is probably from the most distant 

recharge sources, circulating across the top of the dome 

where the more soluble salts have been leached, thus 

creating a permeable zone. The fresh water originates 

from nearer recharge sources. 

Available data are inadequate to evaluate the deep bedrock 

aquifers. However, the oil well drilling and drill stern 

tests indicate that the Ouray and Elbert formations of 

Devonian age, the Leadville limestone of ~ssissippian age, 

and the Cutler sandstone of Permian age contain brine water. 

These formations are not considered as a source of water 

supply because of their extensive depth and poor. water 

quality. Sandstone of Jurassic and Cretaceous age are. 

either eroded or seem to be dry in the Paradox Valley area. 

4-7 
From its headwaters to the southeast of the project area, 

the river flows in a southwesterly direction and then turns 

to flow in a northwesterly direction to its confluence with 

the Colorado River near Cisco, Utah. Under normal conditions, the flows in the Dolores River are relatively low 

from July through March and high in April, May and June. 

The average annual flow of the river at Bedrock was 300,000 

acre-feet for 1972 through 1976 (9). For the same period, 

the average annual flow of the Dolores across the Paradox 

Valley was 313,000 acre-feet (9). The increase in the 

flow is due to the tributary inflow from the West and East 

Paradox Creeks and groundwater inflow from springs and 

seeps. 

West Paradox Creek originates on the eastern side of the 

La Sal Mountains. East Paradox Creek originates at the 

eastern end of Paradox Valley. Both empty into the 

Dolores River at the brine well field. 

4.3 WATER QUALITY 

4.31 Groundwater 

The groundwater quality of shallow aquifers in Paradox 

Valley ranges widely from brine to saline to fresh 

water. The brine water has a density of 1.164 and 

4-8 
three different shallow aquifer zones of the project 

area shows that most of the irrigation wells in 

Paradox Valley can be classified as slightly to 

moderately saline with total dissolved solids (TDS) 

values ranging from 1,400 to 3,500 mg/1 (8). 

The subsurface brine has a salt content range of 

230,000 to 296,000 mg/1 (TDS). A gamma radiation 

measurement with detection sensitivity of 0.47 x 

10-12 ci/ml found no indication of the presence of 

gamma-emitting radioisotopes. Similarly, no 

indication of alpha or beta radiation was found (8). 

More extensive radioactivity test results are shown 

in Section 9.34. 

Analysis of samples collected from seeps which flow 

into the Dolores River indicate a total dissolved 

solids content of 220,000 rng/1 (9). Table 4-1 

presents the results of the ~cal analysis by 

the Bureau of Reclamation of brine from wells in 

the well field. This sample had a slightly higher 

TDS concentration of 258,000 mg/1 (9). Hydrogen 

sulfide content was 74 mg/1 when the sample was .kept 

under pressure and not exposed to the atmosphere. 

Oil content was 1 mg/1. Results of additional 

4-9 
Constituent 

Calcium 

Magnesium 

Sodium and Potassium 

Chloride 

Sulfate 

Bicarbonate 

TDS 

pH 

Iron 

Strontium 

Zinc 

Manganese 

Nickel 

Copper 

Lithium 

Sulfide 

Oil in Water 

4-10 

Total (mg/1) 

1,340 

1,720 

105,000 

165,000 

5,590 

120 

258,000 

7.9 

2.4 

2.3 

.62 

.37 

.23 

.22 

.13 

74.4 

1 
Several basic criteria were used to select the potential 

disposal formations. The formations which have the 

following characteristics were considered as potential 

disposal formations: 

o A thick injection interval with adequate porosity 

and permeability and large areal extent. 

o Overlying and underlying confining beds sufficiently 

thick and impermeable to confine waste t~ the 

injection interval. 

o A relatively simple geological structure. 

o Formation water in the disposal formation of no 

value, i.e., not potable and not suitable for 

municipal, agricultural or industrial use. 

Utilizing the above criteria, the Devonian, Mississippian 

and Permian formations were selected as potential disposal 

formations. 

Figure 5-l is an isopach map of the Devonian and Figure S-2 

is a structure map showing the contours on top of the 

Devonian. Figure 5-3 is an isopach pf the Mississippian 

5-l 
• PROJECT AREA 

i 

i/ 

( 

i 

. r-./ ~~ 

I 

.I 

f 

f 

0 X 

I 

l 

i 

• 

CONTOUR INTERVAL 

= 100 FEET 

,,.,, 

----.. 

Figure 5-l Isopach Map of Devonian - Paradox Basin 

S-2 Modified from A.W. Neff & S.C. Brown 

' 
l 

• PROJECT AREA ELEVATION - 4 9 4 0 TO 50 3 0 FEET 

ELEVATION OF THE TOP OF 

DEVONIAN • -10,000 FEET 

( 

r 

i 

! 

'--- 1 

DATUM TOP OF DEVONIAN 

CONTOUR INTERVAL 

= 1000 FEET 

,!. ---·-·· 

.FIGURE 5-2 STRUCTURE MAP - PARADOX BASIN 

S-3 Modified from A.W. Neff & S.C. Brown 
• PROJECT AREA 

v L-., 

) 

I 

! 

THICKNESS OF MISSISSIPPIAN 

IN PROJECT AREA = 30 0 FEET TO 4 00 FEET 

CONTOUR INTERVAL 

= 50 FEET 

,,.,,,. ---

Figure 5-3 Isopach Map of Mississippian - Paradox Basin 

WBEC-at\ 5-4 

Moclified from A.W. Neft l S.C. Brown 
r --

• 

WIEC-6fl 

are presented in Figures 3-5 and 3-6 in Section 3 of this 

report. 

The Ordovician and Silurian formations probably are not 

present in this area. This cannot be confirmed until deeper 

drilling is completed. Rocks younger than Permian were not 

considered for disposal because they are above the valley 

floor. Other formations of Paleozoic generally do not have 

the basic reservoir properties. Table 5-l shows formations 

which were considered for disposal. 

5.11 Devonian (Elbert & Ouray) 

The Elbert is reported as a gray, crystalline arenaceous 

sandstone with some dolomite and a few thin shale beds. 

Porosities of 15 and 20 percent and permeabilities of 

500 to 800 millidarcies have been reported (47). 

The upper portion of the Ouray formation is a tan-tocream, dense, lithographic limestone. In the lower 

portion of the Ouray, the limestones become a medium 

crystalline rock, with associated intercrystalline 

porosity. The porous portion of the Ouray contained 

condensate and gas in the Lisbon area. Several te_sts 

of the Devonian section in the Paradox Basin show it to 

be very porous in some places. However, these quartzitic 

sandstones and limestones are expected to be less porous 

than the Mississippian rock above the Ouray. 

s-s 
.. 

I· 

...... , -···· 

.L.J<'------·+ 

r 

i 

~ 

Jl. I 

I 

t I 

I 

I 

I 

i 

I 

I 

l DATUM TOP OF MISSISSIPPIAN 

• PROJECT AREA ELEVATION • 4940 to 5030 FEET 

ELEVATION OF THE TOP OF 

MISSISSIPPIAN • -9660 FEET 

CONTOUR INTERVAL 

= 1000 FEET 

, : ---- • • r I • 

FIGURE 5-4 STRUCTURE MAP - PARADOX BASIN 

Modified from A.W. Neff I S.C. Brown 

5-6 
Rl9W 

T48N 

T47N 

Jl. 

t 

T47N 

T46N 

Rl8W R17W 

Datum, Top of ~ssissippian 

Contour Interval 

= 200 Feet 

Figure 5-5 

SITE SPEOl''IC S'I'RI.ClURE MAP 

5-7 
= n i 

l11 

I 

(X) 

Formation 

Cutler Per

Leadville Mi

& Madison 

Ouray 

Elbert 

Dev
formations was estimated for the location at the Continental 

well. 

Water samples from locations in the Paradox Basin show a 

dissolved solids content of 30,000 to 84,000 mg/1; however, 

it is expected to be higher at the Continental well location. 

5.12 Mississippian {Madison & Leadville) 

The undifferentiated Madison and Leadville formations 

consist of fractured carbonates; tan, brown and gray, 

coarsely crystalline to finely sucrosic texture with 

granular and vugular porosity. The formation is considered as a blanket-type reservoir with fairly 

consistent porosities and permeabilities. The neutron 

curves of well logs iri the area indicate good porosities and thickness of the Mississippian. Porosities 

of 30 to 40 percent and a permeability of 1,000 

millidarcies have been recorded (47). 

The areal extent of the formation is widespread, 

attaining the greater thickness to the northwest 

(Figure 5-3). The thickness in the project area 

ranges from 300 feet to 400 feet and the depth from 

14,000 to 14,600 feet (Figure 5-4). 

5-9 
{Table 4-2) • 

5.13 Permian {Cutler) 

The Cutler formation is 3,500 to 9,000 feet thick and 

consists of interbedded, coarse, red, pink, brown conglomerate to fine-grained arkosic sandstone and arkosic 

granite wash. The formation is 200 to 1,000 feet deep 

and widely distributed in the Paradox Valley. The 

great thickness of the formation is an attractive 

feature. 

The overlying Moenkopi and Chinle formation, consisting 

of shale and siltstone, probably are sufficiently thick 

and impermeable to act as confining beds for the Cutler 

formation. The water samples obtained from the Cutler 

formation indicate 5,000 to 16,000 mg/1 of dissolved 

solids. Federal EPA regulations require a dissolved 

solids content of more than 10,000 mg/1, so the Cutler 

formation waters are too fresh for EPA approval of 

the Cutler as a disposal formation. 

5.2 CONFINING FORMATIONS 

5.21 Overlying Confining Formations 

The proposed Mississippian and Devonian injection 

5-10 
WlfC-.fl 

The wells drilled to or through these aquicludes 

in the vicinity of the project area were exploratory 

wells for oil and/or gas; therefore, drill stern 

tests and core analyses were not run so quantitative 

permeability and porosity figures are not available. 

However, qualitative geological information, available from various sources, is included herein. An 

isopach map of the Pennsylvanian System is shown on 

Figure 5-6. 

5.211 Molas Formation 

The Molas formation lies immediately above 

the Mississippian and forms the basal redbed 

unit of Pennsylvanian time. Merrill and 

Winar (1958) divided the Mo1as into three 

members: 

o An upper transported marine unit of wellstratified calcareous shale, siltstone, 

and sandstone, fossiliferous in the upper 

part. 

0 A middle transported non-marine unit of 

silt-mudstone, sandstone, and conglomerate. 

5-11 
t u 

- • ~-~ , . 

• . KAll£if\B 

uPt-}rr . 

Figure 5-6 

0 ~A DO 

PROJECT AREA 

Isopach map. Pennsylvanian System. Four Corners area (after Peterson, 1959). 

Edge of Paradox basin evaporites are shown by stippled band. Arkose belt on 

east side of basin grades rapidly westward to salt and black shale facies. 

5-12 
--1 

5.212 Pinkerton Trail 

The Molas formation is overlain by the Pinkerton Trail, a marine sequence of predominant 

limestones and interbedded shales. The shales 

are silty and range from light to dark gray, 

while the major limestone bed is gray crystalline and medium to fine grained (47}. 

The low potentiometric gradient within this 

unit is indicative of low transmissivity. 

Figure 5-7 is a potentiometric map of the 

limestone aquifer. Data are lacking in the 

immediate project area. 

5.213 Paradox Formation (Evaporite Beds) 

The evaporite beds of the Paradox formation 

consists of halite, potash and other evaporite 

minerals, are dense and have low permeability. 

The evaporites found in the central portion 

of the Paradox Basin grade 1aterally into a 

arkosic elastic section near the major uplifts in the east and into carbonates to ~he 

southwest. Figure 5-8 is an isopach map of 

the salt formation. The deposition of this 

unit was cyclic and 30 to 40 separate cycles 

can be distinguished. Hite (26} found brine 

5-13 
f ...... 

c .. 

W8EC-III 

I OHfUI• -..u•v•t •till PUT 

0 10 ~ :10 10 .ICI-U 

1 . ,·~ I ' l ____ )'", ! '. ·' ·-·--- -·-·- ...&.--·-: ~--

Figure 5-7 

Potentiometric map of the Pennsylvanian Pinkerton Trail 

Limestone aquifer. Datum is sea-level. 

5-14 
Figure 5-8 

AL T TO BASE SALT 

ADOX FORMATION 

1,-, .. ·:•:;;1 EDGE ANHYDRITE 

LLl...U EDGE SALT 

rz:2t SHELF' CARBONATES 

'----PROJECT AREA 

)/. 

ex. t 

Isopach map, Paradox salt, showing relationship with 

' age-equivalent shelf carbonates. 

5-15 
movement in the Paradox formation (53}. Investigation of the hydrodynamics of the 

Paradox Basin Region showed that the potentiometric head of geologic units below the 

evaporites are unaffected by the surface 

hydrology. This further establishes the 

evaporites as being an impervious fluid 

barrier. 

The injection well site is located on the 

Paradox Valley anticline where the evaporites 

beds are nearly 14,000 feet thick. Thus, in 

the immediate project area where the rise 

information pressure due to injection of the 

brine will be highest, upward migration of 

fluids will be blocked by a massive impervious evaporite formation. 

Most drill-stem tests have indicated low 

permeabilities and limited reservoir conditions. In salt anticlines, abnormally high 

shut-in pressures are somet~s encountered; 

however, the return of fluid pressure after 

release, is extremely slow. ~hese abnormally 

high pressure zones are best explained as 

the result of salt flowage and deformations 

within the interbeds which transfers part of 

5-16 
5.22 

The undifferentiated Hermosa group consists 

of carbonate reefs and banks, shale, siltstone, 

anhydrite and sandstone. Laterally, the carbonate reefs of the undifferentiated Hermosa 

group grade into the evaporite rock of the 

Paradox formation. 

~orosity development in the undifferentiated 

Hermosa group is largely restructed to the 

carbonate reefs and banks within the unit. 

Locally, the pores have been filled with 

calcite and anhydrite, resulting in greatly 

reduced permeabilities (12), (34). 

UNDERLYING CONFINING FORMATIONS 

5.221 Cambrian 

The proposed injection zone is underlain by 

part of the Cambrian formations. The Silurian 

and Ordovician deposits normally found beneath the Devonian are most likely not present 

in the Paradox Valley area. The Ignacio formation is present and is comprised of quartzite, quartzitic sandstone, and friable sandstone. With the exception of fracture zones, 

the unit is of low porosity and permeability. 

5-17 
'. 

r· 

! ... 

'-······ 

U""tt••~tr~IIIVAINrtfflf 

D 1D 20 :10 .00 IOMliS 

l -e.'; .. t::JO.to.. ·• j IPI/.'t~&a&-1 ... : 't' - ,._,_ -l..unl 

'\ r..1u i 

v--.. 

' 

" ,..,..&.1-n.lc •wf..a 

""""' ht-u-crt.c •.rt.ce ( ............. ,, .. ,, ----- -·-·-·-· 

Figure S-9 

Potentiometric map of the Paradox Member of the Pennsylvanian 

Hermosa Formation. Datum is sea-level. 

5-18 
r····· 

Cambrian rocks (Ignacio, Bright_Angel Shale, 

Mauv Limestone, and Lynch Dolomite). Indicated thickness is about 450 feet in the 

Project Area. 

5.222 Precambrian 

The Precambrian is a heterogeneous complex 

of metamorphic and igneous rocks. Subsurface 

control is quite limited but in general the 

porosity and permeability are quite low. 

These formations are excellent confining 

zones preventing the downward movement of 

fluid. 

5-19 
I 

j_ 

,.r 

ISOPACH 0~ TOTAL, CAMB"IAN l'tOCKS 

..... e •JUliOIDM I I I I I I 

Figure 5-10 

Isopach of Total Cambrian Rocks 

5-20 
6.1 RESERVOIR PROPERTIES 

Information on the properties of the targeted disposal 

reservoirs at the Continental well location is limited. 

The three characteristics needed for prediction of 

injection well performance, formation thickness, 

permeability, and porosity are not known. Data from 

nearby areas were used to obtain best estimates. The 

estimate for formation thickness is believed to be 

the most accurate of the three. 

6.11 Thickness 

The Laterlog (enclosed in pocket in Final Report 

Draft, October 1981) from the Continental well 

indicates that 274 feet of Mississippian formation 

was drilled and that drilling was stopped before 

reaching the bottom of the Mississippian. As 

reported in Section 5, the expected gross thickness of the Mississippian is 300 to 400 feet. 

A gross thickness of 350 feet was used for our 

well performance calculations. A gross thickness 

of 200 feet.was used for the Devonian. 

6-1 
WIEC--691 

6.12 

The gross thickness was discounted heavily in 

estimating the net thickness. Log data indicate that approximately 22 percent of the 

Mississippian is porous so a net thickness of 

120 feet was used for the combined Mississippian 

and Devonian. 

Porosity 

Porosity cannot be determined in the Continental 

well but an average of about three percent was 

indicated by the sonic log from the Union well. 

It should be noted that limestones and dolomites 

with a relatively low porosity of three percent 

can have very hig~ injection capacities because 

of extensive fracture porosity which is not 

detectable with the sonic log. 

The indicated porosity of three percent is considerably less than the 30 to 40 percent reported 

in the Feasibility Study by Frank Turner. Considering all available data and our experience 

elsewhere with the Mississippian, we are esti~ 

mating a porosity of eight percent. Accuracy 

of this estimate does not significantly affect 

6-2 
r 

\ 

6.13 

Permeability 

Insufficient data are available to determine 

permeability so an accurate injection rate vs 

pressure relationship cannot be established. 

However, to permit some reasonable predictions 

of injectivity, permeabilities of 100 millidarcies to 500 millidarcies were assumed. The 

actual permeability of the deepened Continental 

well probably will be bracketed by these two 

assumed values. 

6.2 EXPECTED DEEP WELL PERFORMANCE 

6.21 Radius of Frontal .Edge of Injected Brine 

An estimate of the minimum travel distance of 

the injected brine was calculated by assuming· 

the injected brine will occupy a vertical 

cylinder centered on the injection well. The 

height of the cylinder is the effective (net) 

thickness of the formation receiving the brine. 

The properties of the disposal formations are 

shown in the following table. 

6-3 
Ouray & Elbert ( Devonian) 200 44 8 

Total for Injection 

Interval 550 120 8 

For the purposes of these calculations the formations are assumed to be of equal permeability 

and therefore each will accept an equal volume 

of injected brine per vertical foot of effective 

thickness. 

The Paradox brine injection rate is 900 gpm or 

63.24 million cubic feet a year. 

The following formula was used to calculate the 

minimum travel distance: 

r = J 1T~~ 

r: radial distance of the injected brine front 

in feet 

v: volume of injected waste in cubic feet. 

h: effective thickness of the injection formations 

in feet 

cf>: average porosity of the injection formations 

6-4 
wife ..... ., 

6.23 

Devonian formations are filled with brine (except 

in isolated areas of "highs" where occasional small 

pockets of hydrocarbons could be present.) Injection 

of well field brine requires displacement of an equal 

volume of Mississippian-Devonian brine radially 

outward from the injection well. 

The disposal formation brines and the disposal 

formation rock have a slight degree of compressibility. Estimated combined value £or the reservoir 

is 7 x 10- 6 per psi of increased pressure. Although 

this compressibility factor is small, the available 

volume for brine storage is very large because of the 

enormous volume of the disposal formation. 

Variations in the Radius of the Frontal Edge 

Actual position of the frontal edge of the injected 

brine bubble may be similar to the minimum radial 

calculations at some positions around the disposal 

well. However, in most locations around the circumference the actual edge will be more or less than 

the theoretical minimum. The three factors which 

may cause changes in the minimum circumference of 

the frontal edge are the influence of dispersion, 

fault barriers, or other discontinuities of the 

disposal formation such as the Uncompahgre Uplift. 

6-5 
tions in formation porosity and channeling through 

zones of higher permeability or fractures result in 

some "pockets" of formation brine (connate water) 

being bypassed. A standard equation for estimating 

the increase in travel distance due to dispersion is: 

= r + 2.3 

r: minimum radial distance of travel, feet 

rd: radial distance of travel with dispersion, 

feet 

D: Dispersion coefficient, 65 feet for 

limestones 

The calculated travel distances after adjustment 

for dispersion are presented in Table 6-2 along 

with the minimum radii. 

The minimum travel distance and travel distance 

after adjustment for dispersion are plotted with 

respect to time on Figure 6-1, "Injected Brine 

Frontal Movement vs. Time". 

6-6 
~--···· 

5 yr 316.2 X 106 3' 2 3 8. 1,055 4,293 

10 yr 632.4 X 10 6 4,579 1,255 5,834 

25 yr 1,581. X 106 7,240 1,578 8,818 

so yr 3,162. X 106 10,239 1,876 12,115 

100 yr 6,324. X 10 6 14,481 2,231 16,712 

* Assuming isotropic conditions 

6.232 Fault Barriers 

There are several major faults in the northeastern 

part of the Paradox Basin, some within a few miles 

of the Project Area. The effect on the shape of 

the injected bubble of salt water is expected to be 

minimal because, as. indicated in Figure 6-1, it will 

take about 35 years for the dispersed bubble to 

reach a radius of two miles. Some distortion of 

the circular shape of the bubble will occur as the 

advancing pressure wave encounters a fault barrier. 

Radius of the pressure wave will be considerably 

larger than the radius of the injected bubble. 

Meaningful calculations of the distortion would 

require that a detailed study be made to dete~mine 

the exact distance, strike and dip angles of all 

faults in the vicinity of the Project Area. Purchase 

and detailed study of several (possibly all) of the 

seismograph traverses would be required. 

6-7 
13 

....= 

"-

012 

0 

0 

II 

1--

z 

0 

a: 10 

"-

I.&J 

z 9 

0::: 

CD 

0 

L\J 8 

1-

(.) 

I.&J 

-, 

z 7 

"-

0 6 

/ / 

/ 

v / v 

v 0-- MINIMU f.t RADI s / 

/ / 

v 

/ v / / 

v / 

I / 

/; v 

en 

::l 

0 

ct 5 

a: 

·4 

I I 

/; I 

INJECT I< ~N RATE :gQQG 'M 

II 

y 3 

2 

- .. 

! .... 

0 10 20 30 40 50 60 70 80 90 

TIME, YEARS 

INJECTED BRINE FRONTAL MOVEMENT VS. TIME 

FIGURE NO. 6-1 

6 8 -
shape of the bubble will be flattened on that side 

after the pressure wave reaches it. 

6.234 Mississippian - Molas Paleokarstic Interface 

The paleokarstic interface at the top of the 

Mississippian formation and the bottom of the Molas 

formation was examined to determine its influence 

on the injection pressures and flow of the injected 

brine. Logs from the Continental well and Union 

well indicated that the upper zone of the Mississippian has several thin layers of low permeability 

which effectively separate the permeable zone of 

the Mississippian from the paleokarstic bottom of 

the Molas. 

The well completion plan calls for the casing to be 

set and cemented in place through the upper zones 

(74 feet into the Mississippian) which would prevent 

direct injection of brine into the upper zones. 

A worst case evaluation of these upper zones was 

done by assuming these highly permeable and porous 

zones are open directly to the well bore. 

The first step was to calculate pressure rises for 

brine injection based on a composite formation 

6-9 
WMC-691 

a porosity of 20 percent evaluated in combination 

with 120 net feet of Mississippian and Devonian 

with 100 md permeability and 8 percent porosity. 

This resulted in 43 percent of the 900 gpm of brine 

injection entering the high permeability, high 

porosity upper zone. The high porosity greatly 

offsets the thinness of the zon~ but the minimum 

100-year bubble still would have a relatively large 

radius of 29,400 feet or 5.6 miles. Since these 

calculations are based on the zone having direct 

communication with the well bore (highly unlikely) 

no additional work to account for fingering was done. 

The actual volume of brine entering the upper zone 

would probably be significantly less than indicated 

in this worst case calculation. 

6.24 Drill Stem Test Data, Exploration Wells 

When the oil exploratory wells were drilled in the 

project area, drill stem tests were run on two of the 

wells. Objective of the tests was to detect the 

presence of oil or gas,so they are. not detailed enough 

to give reliable permeability data. However, they 

were of some benefit in evaluating the reservoirs. 

The limited available data are as follows: 

6-10 
t··· 

+ 

:. 

WIIC-691 

consisted of 4,950 feet of water cushion and 

8,500 feet of salt water. Formation pressure 

ranged from 3,440 to 6,400 psi. The one-hour 

shut-in pressure was 6,510 psi and the hydrostatic pressure was 8,760 psi. 

6.242 Union, 1-0-30 Ortho Ayers 

Interval from 14,114 to 14,200 feet (86 feet) 

was tested. Tool opened with a weak blow, 

increasing to 12 inches in five minutes. After 

a one-hour shut-in, it opened with a weak blow 

which increased to 12-inches then decreased 

slightly at the end of two hours. Shut-in time 

was four hours. Water cushion recovery was 

4,150 feet and recovery of salt water was 6,680 

feet. Total dissolved solids content was 

200,000 ppm at the top and 137,000 ppm at the 

bottom. 

Initial hydrostatic pressure was 7,674 psi. 

Initial flowing pressure was 2,245 to 2,558 psi. 

Initial shut-in pressure was 6,220 psi and final 

flowing pressure was 2,558 to 5,318 psi. Final 

shut-in pressure was 6,201 psi. Final hydrostatic pressure was 7,710 psi and the bottom 

hole temperature was 229° F. 

6-11 
approximately 220 miles from the site of the proposed 

injection well(s). 

There is at least one partial fault barrier which will 

lengthen the pathway of the pressure wave from the 

injection well(s) to the Little Colorado River. On 

the other hand, the pinch-out of the Mississippian 

formation at the Uncompahgre Uplift northeast of the 

injection well(s) will cause the pressure wave to 

move faster toward the Little Colorado River. There 

is not sufficient subsurface geological information 

to determine which of these opposing conditions will 

have the strongest influence. If they are assumed to 

be approximately equal, the following table which is 

for isotropic conditions will apply. 

After 100 Years of Injection at 900 s:em 

Assumed Radius of Edg:e of Pressure Wave 

Permeability, md Feet Miles 

100 280,000 53 

200 390,000 74 

300 440,000 83 

500 600,000 114 

1000 890,000 169 

6-12 
l ... :. 

r::: 

r .::: 

i·· r······ 

t.:··· 

....... 

t .. 

WltC--691 

mately four miles of the brine well field. Locations and 

depths of these wells are shown on Figure 3-2. A summary 

of the pertinent data for each of the four wells is shown 

in Table 7-1. 

7.1 

7.2 

CHICAGO CORPORATION, NO. 1 AYERS 

The Chicago Corporation well was drilled to 6860 feet. 

A schematic cross section of the well is shown on 

Figure 7-1. This abandoned well has 527 feet of 

9 5/8-inch surface casing cemented in with 4.0 sacks of 

cement. The small diameter of this surface casing 

would restrict the diameter of the long string of 

casing to 7 inches and the tubing diameter to 4 1/2 

inches. Friction loss in this small tubing would be 

about 3000 psi for only one-half of the required flow 

rate (450 gpm). Therefore, utilization of this well 

is not feasible. 

UNION OIL COMPANY, NO. 1-0-30 AYERS 

The Union well was drilled to an attractive depth of 

14,400 feet. However, plugging records show that· 

1,182 feet of cemented 9 5/8-inch casing was left in 

7-1 
WlfC-691 

mately four miles of the brine well field. Locations and 

depths of these wells are shown on Figure 3-2. A smmnary 

of the pertinent data for each of the four wells is shown 

in Table 7-1. 

7.1 CHICAGO CORPORATION, NO. 1 AYERS 

The Chicago Corporation well was drilled to 6860 feet. 

A schematic cross section of the well is shown on 

Figure 7-l. This abandoned well has 527 £eet o£ 

9 5/8-inch surface casing cemented in with 40 sacks of 

cement. The small diameter of this sur£ace casing 

would restrict the diameter of the long string o£ 

casing to 7 inches and the tubing diameter to 4 1/2 

inches. Friction loss in this small tubing would be 

about 3000 psi for only one-half of the required flow 

rate (450 gpm). Therefore, utilization o£ this well 

is not feasible. 

7.2 UNION OIL COMPANY, NO. l-0-30 AYERS 

The Union well was drilled to an attractive depth of 

14,400 feet. However, plugging records show that 

1,182 feet of cemented 9 5/8-inch casing was left in 

7-1 
. \.: : l : 1 =. H 1 

G 

n 

I 

e 

-..! 

I 

N 

Company & 

Well Numbe

Chicago 

Corporation 

No. 1 Ayers 

Union Oil 

No. 1-0-30 

Ayers 

Continental 

No. 1 Scorup 

Somerville- 

Wilcox 

Jack Grynber

No. 33-3, 

Hartin Mesa 

GL • Ground 

KB • Kelly B
Distance to Brine Well Field: 4 Miles Elevation 5,000' G L Land: Patented 

·0 

. 527', 9%", 40# N-80,40 SX 

._ 

w 

w 5,000 

llo. 

10,000 

6,860 TO . 

Figure 7-1 

Chicago Corp. Exploration Well tl Ayers 

7-3 
, ..... . 

E 

..... 

f

····· . 

! 

.... 

..... ~ ..... 

t . 

, __ :-.-.. 

( .... 

~--··· 

t 

5,000 

10,000 

15,000 

WBEC-611 

40 sx. 1,975'- 2,025' 

Mississippian 

14,042' - 14,384' 

Thickness 342' 

12W' Hole 

8,956'- 9,006' 

40SX 

25 sx 10,150' - 10.200' tllfllt~12:~~·1o,188', 9%" 40#~43.5# 

350SX 

IJI11 12,875' - 12,925' 25 sx 

L/II 13,150'-13,200' 25SX 

25 ~X 13,580'- 13,630' fZZJZZJ~ 

50 sx 13,990'- 14,090' ~~~ 

14,400' TO 

Figure 7-2 

Plugged & Abandoned 

4-12-71 

Union Oil Co. Exploration Well tl-0-30 Ortho Ayers 

7-4 
\ 

\ 

l 

t 

WlfC--.91 

The 4-mile distance from the well field to the Union 

well is another negative factor for use of the Union 

well. Schematic cross-section of this plugged and 

abandoned well is shown in Figure 7-2. 

7.3 JACK GRYNBERG, NO. 33-3 MARTIN MESA 

The status of the Grynberg well as plugged and abandoned is shown in Figure 7-3. The relatively shallow 

total drilled depth of 7,289 feet makes it less 

attractive than the Continental well. However, if a 

second well is needed, it should be considered as an 

alternative to drilling a new well near the injection 

plant. The cost for drilling a new well should be 

compared with the costs for reworking the Grynberg 

well which include deepening to the Precambrian, 

installing a pressure pipeline from the injection 

plant to the well and the additional electrical costs 

for pumping the brine through the longer line to the 

Grynberg well. 

Estimated cost of re-entering the Grynberg well is 

included in the cost estimate report. 

7-5 
i·:::: 

F~ I .. r······ 

, .... 

t··:_: 

I···· t···· 

7.5 

WIEC-1 

It is the deepest of the four wells (15,000 feet) 

and it has large enough pipe in the hole to permit 

installation of a satisfactory tubing size (7-inch 

tubing in 9 5/8-inch casing). The condition of 

this well when plugged and abandoned is shown in 

Figure 7-4. 

It is concluded that the Continental we~l, Scorup 

No. 1, should be re-entered, cleaned out and completed 

as a test well for brine disposal. 

OTHER WELLS 

Records indicate that there are four small diameter 

shallow holes of unspecified origin in the area. 

These shallow holes (less than 6000 feet) are located 

in sections 6, 18, and 19 of T47N Rl8W and are not 

suitable wells for re-entry. 

7-6 
I 

' 

.... 

w 

w 

""' 

Distance to Brine Well Field: 2 Miles , Elevation 4,960' GL 

4,972' KB 

0 

5,000 

10,000 

15 SX@ Surface with Marker 

17'h" Hole 700 SX 

75 sx 2,600 ·- 2,700' 

(Stabilizer P lug) 

50 sx 4,800' - 4,950' 

so sx 5,690' - 5,840' 

75 sx 6,450 • - 6,600' 

7,2 89' TO 

12" 900 Series 3,000 WP 

13%" and 9 %" csg hd. 

was used. 

Figure 7-3 

j 

I 

7 

I 

Land: Federal 

321' 

13%' I K54.5-55# 

290~ 390 75SX 

10.5 ppg Salt Base 

Mud in Hole 

(Between Cement 

Plugs) · 

Plugged and 

Abandoned 5-14-75 

Jack Grynberg Exploration Well 133-3 Martin Mesa 

7-7 
t···· 

.. 

1&1 

1&1 

&1. 

5,000 

10,000 

15,000 

Squeezed 180 SXS 

Salt Cement to 

1,000 psi + 20' on 

top of retainer 

(Cemented in and o 

of Surface csg 

1,080' - 1 ,450') 

ut 

Cored In tervals 

13,194' -13, 241' - Mississippian 

·14,726- 15,000 

~ (274') . 14.643' -14 

14,939'- 15 

,689'. 

,000'-

I 

I 

Salt Cement 

60 - 70% Salt, 

700' - , 2,300' 

40- 50%Salt 

I 

ss 

SH Set Dry Hole 

Marker 12-27-58 

Plugged & 

Abandoned 

Continental Oil 

15,000' TO 

Figure 7-4 

Exploration Well #1 Scorup-Somerville-Wilcox 

WIIEC-611 7-8 
, ...... . 

WlfC-691 

\ 

Re-entry and completion of the Continental well instead of 

drilling a new well is recommended. However, this recommendation is contingent upon the surface casing in this 23-year 

old well being in good condition. There is a possibility of 

severe wear and/or severe corrosion. The condition of this 

casing should be determined prior to installing any of the 

pipeline or surface treatment systems. Recommended procedure 

is as follows: 

o Drill the top cement plug and the lower cement plug 

to the bottom of the surface casing using a small 

oil-field pulling unit with a power swivel. 

o Run a casing inspection tool to determine condition 

of the 13-o/8 -inch casing. 

o If casing condition in the Continental well is satis~ 

factory, move out the pulling unit and move in a deep 

well rig to re-open the hole and drill to the Precambrian. 

Test the Mississippian and lower sedimentary formations 

by injecting brine with portable pumps for two weeks. 

If the permeability is high enough to permit injection 

of 900 gpm of brine into an affordable number of 

injection wells, complete the Continental well and, 

if needed, drill a second well. 

8-1 
permeability is high enough to permit injection of 

900 gpm of brine into an affordable number of 

injection wells, complete this first well, drill the 

additional well{s) if needed, and install the surface 

system. 

Drilling prognosis and specifications for materials for 

drilling and completing the disposal wells are included 

in the Engineering Design Package. 

8-2 
Successful long-term deep well disposal of the brine 

requires: 

o prevention of plugging of the disposal formations 

with suspended solids, and 

o adequate corrosion control to prevent excessive 

loss of exposed equipment, i.e., pipeline, pumps, 

valves, filter shells and the deep well tubing. 

Plugging problems usually are the more serious of the 

two. Some types of severe plugging can result in loss 

of the well. Severe corrosion typically requires replacement of exposed equipment, i.e., pumps, well tubing, etc., 

but not the loss of the well. 

Causes of well plugging include the following: 

(a) excessive suspended solids which plug the well bore, 

0 organic matter or clays, silts, precipitates, 

including iron sulfid~, calcium or magnesium 

carbo~ates, barium or calcium sulfates, etc., 

which are present in the brine_as it is pumped 

from the well field, 

9-1 
WIEC--..91 

(b) precipitation of minerals within the disposal 

formations, 

(c) reactions between the injection fluid and clays in 

the disposal formation. 

Item (c) is not expected to be a problem in this brine 

disposal system. Clay dispersion and swelling typically 

occur in certain conditions where fresh water rather than 

brine is being injected into sandstone containing 

montmorillonite. These conditions will not be present 

in this system. 

Item (b) requires some consideration. There will be a 

significant rise in temperature of the brine as it moves 

down the tubing and into the disposal formation. Chemical 

analysis indicates that the two concerns are precipitation 

of calcium sulfate or calcium carbonate. The solubility 

of c~lcium carbonate decreases with increased temperature 

The solubility_ of calcium sulfate increases with increased 

temperature to about 95° F then decreases with additional 

temperature rise. 

The temperature rise will be accompanied by an increase in 

pressure to more than 7,000 psi. These large pressure 

9-2 
WlfC--691 

operational problem. It can be prevented around the well 

bore by injecting a few thousand gallons of clean fresh 

water as a buffer before any of the well field brine is 

injected. This will displace the Mississippian brine from 

the well bore area. 

Item (a) is significant in this disposal system. An 

investigation of the suspended solids concentrations from 

various wells in the well field was made by collecting the 

suspended solids on Millipore filters. The adherent 

characteristics of the iron sulfide (with traces of oil) 

present in the brine will cause plugging of the disposal 

formations if not removed prior to injection. 

Hydrogen sulfide content of the brine is another contaminant 

requiring specific design features. Hydrogen sulfide causes 

excessive corrosion of mild steel when subjected to longterm exposure. Reports from the well field operations 

indi~ate that 316 stainless steel provides satisfactory 

service. 

The pipelines, pumps, well tubing, bottom joint of the 

casing and all other equipment exposed to the brine is 

designed for corrosion protection. Materials specified 

are plastic, plastic coated steel or 3~6 stainless steel. 

9-3 
9.2 SUSPENDED SOLIDS LIMITATIONS 

Plugging problems with suspended solids are a result of 

accumulated deposition of solids in the disposal formation. 

Particle size, cohesiveness, etc., affect the degree of 

plugging. Although plugging severity is not a linear function 

of suspended solids concentration, for practical purposes 

it can be assumed that a suspended solids concentration of 

1.0 mg/1 for one month will cause damage that is similar 

to that caused by a concentration of 30 mg/1 for one day. 

From an operational viewpoint it is desirable to reduce 

the suspended solids content to as near zero as poss~ble; 

however, cost effectiveness is a factor. The recommended 

diatomaceous earth filter installation is expected to 

reduce the suspended solids content several tenths of a 

mg/1. i.e., from 0.8 mg/1 to 0.1 or 0.2 mg/1. Even less 

than 0.1 mg/1 may be achieved with use of optimum filter 

aid n.aterial. 

Based on present knowledge of solids characterization, it 

is believed that satisfactory long term brine disposal will 

be achieved if the average suspended solids content is 

reduced to 0.3 mg/1 or less. 

9-4 
brine field were collected and examined. Type HA 

Millipore filters with a pore size of 0.45 micron were 

used so virtually all of the suspended solids were 

trapped on the filters. An analysis was run on brine 

samples from some of the wells and on some of the 

removed suspended solids. 

Tests for total sulfide in the brine samples 

(Table 9-1) showed a range of <1 to 82 mg/1. Tests 

for precipitated iron on the Millipore filter papers 

(Table 9-2) indicated a range of less than .01 mg/1 

to 0.28 mg/1. The precipitated iron probably was 

present as iron sulfide at the time of sampling. 

Acid insolubles on the filter papers ranged from 

0.02 mg/1 to 1.28 mg/1. The larger differences 

in suspended solids from well-to-well plus evidence 

that startup and shutdown of the wells increased .the 

suspended solids content indicated that additional 

• testing would be advisable. 

Preliminary conclusion was that the concentrations 

of suspended solids in the unfiltered water were 

sufficiently high that the total volume of su~pended 

solids entering a well would cause increased pressures 

due to plugging. 

9-5 
....... 

;--···· 

~-···· 

....... 

''--

.... 

•···· 

,. 

....... 

....... 

....•.. 

--

...... 

·----·· 

....... 

Assigned Laboratory No: 

Date Received: 3/9/81 Date Reported: 3/24/81 

~(~c~on~fr.1~~==~n~g~)----

Sample Identification: Listed Below 

Test Results* 

811521 811522 811523 811524 

Well No., Sample No. 3W/tl 3W/12 3WI/3 4W 

Filter II 1,365 1,366 1, 354 1,353 

pH, units 5.8 6.3 5.7 5.8 

Total Sulfide 71 82 69 82 

m-Alkalinity as CaC03 236 234 240 234 

811525 811526 811527 811528 

7W IE SE/11 5Efl2 

Filter II 1,367 1,357 1,361 1,362 

pH, units 6.6 6.5 5.6 5.5 

Total Sulfide 15 12 71 55 

m-Alkalinity as Caco3 150 180 206 -206 

811529 811530 811531 811532 

5Efl3 8E#1 8EII2 8E/13 

Filter fl 1,529 1,530 1,531 1,532 

pH, units 6.2 5.5 6.3 5.6 

Total Sulfide 66 76 <1 <1 

m-Alkalinity as Caco3 200 216 216 214 

*The above results were obtained by APHA Standard Methods, 

14th Ed., EPA Methods for Chemical Analysis of Water ·and 

Wastes and/or ASTM Standards, unless otherwise indicated. 

Results are in milligrams per liter unless otherwise indicated 

9-6 
::a: 

OJ 

1'1 

n ;I 

\0 

I 

-...) 

!; :· 

Well Sample 

No. No. 

lE 1* 

lE 2 

SE 1 

SE 2 ' 

SE 3 

8E 1 

BE 2 BE 3 

3W 1 

3W 2 

3W 3* 

4W 1 

7W 1 

*Less than 0.01 

**Sample taken im
WltC ...... 91 

temporary disposal pond. Sampling point was where 

Well 7-W connects to the line. Results of the 

Millipore suspended solids tests are plotted on 

Figure 9-1. 

Average concentration of suspended solids during 

continuous well operation was 0.8 mg/1. This is 

equivalent to 260 pounds per month of dry solids 

or 1000 pounds per month of solids with 75 percent 

moisture. 

Shutdown of the wells because of power outages 

averages 4.4 times per month. Calculations based 

on the test results indicate that the increased 

suspended solids load caused by startups is only 

36 pounds per month of solids with 75 percent moisture. 

It is concluded that the suspended solids load caused 

by startups is relative insignificant but that the 

load during constant operation of 1000 pounds per 

month will necessitate installation of efficient 

filters. 

9-8 
•...... 

.... 

······· 

...... 

~---·· 

•······ 

.... 

: 

..... 

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FIGURE 9-1 CHANGES IN SUSPENDED SOLIDS CONCENTRATION 

RESULTING FROM SHUTDOWN AND STARTUP OF BRINE WELLS 

9-9 
WlfC-691 

Williams Brothers Engineering Company, 

May 21, 1981, at the pipeline through which 

the composite brine flows to the temporary 

disposal pond. 

Results are shown in the laboratory report, 

Table 9-3. Concentrations of all of the eight 

elements tested are below the Federal EPA 

limits specified for hazardous waste classification. It is concluded that the brine 

from the well field is not a hazardous waste 

and requires no special handling precautions. 

9.332 Suspended Solids 

A sample of suspended solids was analyzed for 

hazardous waste determination. Sample consisted of the suspended solids which were 

collected on 43 Millipore filters by BOR 

personnel in August, 1981. All of the papers 

were combined into one sample thereby obtaining 

sufficient sample weight to obtain definitive 

results. 

Results of analysis of the acid extractions of 

the composite sample are shown in Table 9-4. 

All test results were below.the specified limits. 

9-10 
Assigned Laboratory No: 812506 and 812508 

Date Received: 5/28/81 Date Reported: 

Sample Identification: See Belov 

Test Results* 

Cone of EP Toxicity Extract 

812506 - #2, Pipeline TW 5-21-81 8:30-9:30 AM #1 Millipore E. Well- 1E- 8E 

812508 - fr4,Pipeline 7W 5-21-81 10:45 AM 15°C #2 Millipore Filtrate, all vells 

dovn about one hour earlier 

Silver Chromium Lead Cadm.i um Barium Arsenic Selenium 

812506 

0.17 0.13 1.1 0.27 0.25 < 0.03 < 0.001 

812508 

0.16 < 0.05 0.97 0.30 0.25 < 0.03 < 0.001 

... EPA Limits 

5. 0- ;: .o 5.0 1.0 100. 5.0 l.O 

7/7/81 

Filtered 

Unfiltered 

Mercury 

< 0.0001 

< 0.0001 

0.2 

*The above results were obtained by APHA Standard Methods, 

14th Ed., EPA Methods for Chemical Analysis of Water and 

Wastes and/or ASTM Standards, unless otherwise indicated. 

Results are in milligrams per liter unless otherwise indicated. 

9-11 
Date Received: Date Reported: 9-9-81 

Sample Identification: DOl, Bureau of Reclamation, 

Paradox Valley #4611, Millipore Filters (Suspended Solids) 

Test 

Hazardous Waste 

EP Toxicity 

Arsenic as As 

Selenium as Se 

Barium as Ba 

Total Chromium as Cr 

Cadmium as Cd 

Lead as Pb 

Silver as Ag 

Mercury as Hg 

EPA Limits, 

(Federal Regisber) 

5.0 

1.0 

100. 

5.0 

1.0 

5.0 

5.0 

0.2 

Results* 

.08 

< .001 

< .14 

0.1 

0.76 

0.4 

0.1 

.003 

*The above results were obtained by APHA Standard ~~thods, 15th Ed., 

EPA Methods for Chemical Analysis of Water and Wastes.and/or ASTM 

Standards, unless otherwise indicated. Results are in milligrams 

per liter unless otherwise indicated. 

9-12 
Composite brine samples for radioactivity analysis 

were collected May 21 and 22, 1981. Samples of 

suspended solids collected at that time were not of 

sufficient volume for radioactivity tests. Additional 

suspended solids samples were collected during the 

subsequent two-month period ending July 21, 1981. 

Both brine and suspended solids were analyzed by 

Eberline Laboratories in Albuquerque. 

Test results for the filtered brine, the unfiltered 

brine and the suspended solids are compared in 

Table 9-5 with permissible limits set by the Federal 

EPA. The permissible limits used by the Colorado 

Department of Health and those published in the 

Nuclear Regulatory Commission's Title 10.- Energy, 

Chapter 1 are identical with those set by the 

Federal EPA. 

' Where there is a mixture of more than one radionuclide in water, the limiting values are determined 

by the following procedure from the Notes at the end 

of Part 20, Appendix B, Title 10 - Energy, Chapter 1, 

Nuclear Regulatory Commission: 

"If the identity and concentration of each 

radionuclide in the mixture are known, the 

limiting values should be derived as 

9-13 
•···· 

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~-···· 

.. 

. .. 

.. 

•.... 

....... 

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yp

, 

SarnJ2le Anal:;tsis J2Ci/liter ECi/li ter micro Ci/ml 

#2509 U-234 1.1 ± 0.5 30,000 3 X 10-s 

Filtered U-235 0.00 ± 0.25 30,000 3 X lo-s 

Brine U-238 0. 74 ± 0.4 8 40,000 4 X lo-s 

3100 ml Th-228 0.00 ± 0.52 7,000 7 X 1o-6 

Th-230 -0.06 ± 0.18 2,000 2 X l0-6 

Th-232 -0.15 ± 0.21 2,000 2 X 1o-6 

Ra-226 13 ± 3 30 3 X 1o-a 

Ra-228 17 ± 2 30 3 X 10-8 

#2512 U-234 0.31 ± 0.41 30,000 3 X lo-s 

Unfiltered U-235 -0.16 ± 0.18 30,000 3 X lo-s 

Brine U-238 0.6 7 ± 0.43 40,000 4 X 1o-s 

3100 ml Th-228 0.00 ± 0.50 7,000 7 X 1o-6 

Th-230 0. 30 ± 0.19 2,000 2 X lo-6 

Th-232 0.06 ± 0.17 2,000 2 X 1o-6 

Ra-226 13 ± 3 30 3 X l0-8 

Ra-228 11 ± 2 30 3 X 1o-8 

ECi/gram pCi/gram micro Ci/ml 

Solids U-234 0.0071 ± 0. 00 20 30 3 X lo-s 

462 .. 9• U-235 0.0003 ± 0.0005 30 3 X lo-s 

(Includes U-238 0.0066 ± 0.0009 40 4 X lo-s 

filter Th-228 0.0028 ± 0.0018 10 1 X 10-S 

papers) Th-230 0.0090 ± a. oo 32 30 3 x lo-s 

Th-232 0.0062 ± 0.0026 40 4 X lo-S 

Ra-226 0.0064 ± 0.0019 30 3 X lo-s 

Ra-228 0.0020 ± 0.0093 30 3 X lo-s 

9-14 
"EXAMPLE: If radionuclides A, B, and C are 

present in concentrations CA, CB, and Cc, 

and if the applicable MPC's are MPCA,and MPCB, 

and MPCc respectively, then the concentrations 

shall be limited so that the following relationship exists: 

"For purposes of this note, a radionuclide 

may be considered as not present in a mixture 

if (a) the ratio of the concentration of that 

radionuclide in the mixture (CA) to the 

concentration limit for that radionuclide 

specified in Table II of Appendix 'B'. (MPCA) 

does not exceed 1/10, (i.e. CA/MPCA ~ 1/10) and 

(b) the sum of such ratios for all the radionuclides considered as not present in the 

mixture does not exceed 1/4 i.e. 

9.341 Filtered Brine 

Results for filtered brine sample No. 2509 

were evaluated using the above procedures. 

The value for the results for the filtered 

brine sample was 1.00006. Following the 

~-~,~-"~1~---------------------------- . 9-15 
WlfC-691 

9.342 Unfiltered Brine 

9.343 

Results for the unfiltered brine sample 

No. 2512 were analyzed in the same manner 

as those for the filtered sample and the 

value was found to be less than 1.0. Therefore the unfiltered brine sample also is 

classified as a non-radioactive waste. 

Suspended Solids 

Results for the insoluble solids were 

similarly evaluated and the value was 

below 1. The value actually was zero 

because all components were less than 1/10 

and their summation was less than 1/4, so 

all components were dropped leaving a 

value of zero. Therefore, the suspended 

solids are classified as a non-radioactive 

waste. 

9.344 Conclusions 

Comparison of the results of tests for each 

of the eight isotopes with the EPA limits 

9-16 
Likewise, when all eight isotopes are considered together, using the prescribed NRC 

formula, results for each of the filtered 

and unfiltered brine and suspended solids 

samples indicate a non-radioactive classification. 

9-17 
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11.1 HISTORY 

Paradox Valley has been identified as a significant 

contributor to the salinity of the Colorado River. 

The Bureau of Reclamation is conducting a basin~ide 

program to reduce salinity levels in the Colorado 

River system. 

Title II of the Colorado River Basin Salinity Control 

Act (Public Law 93-320) of June 24, 1974, authorized 

the Secretary of the Interior to construct, operate 

and maintain the Paradox Valley Unit. The implementation 

of measures to control this source of salt should reduce 

the annual salt inflow by an average of 180,000 tons 

and lower the salinity of the Colorado River by 

approximately 18.2 milligrams per liter (mg/1) at 

Imperial Dam near Yuma, Arizona (9). 

Th• inflow of salt into the river has been substantially 

reduced by drilling a field of wells into the brine 

.zone on both sides of the Dolores River and pumping 

brine groundwater from the wells to lower the interface 

between the relatively fresh groundwater and the underlying brine. The brine currently is pumped to a 

temporary disposal pond. This section addresses the 

impacts of the proposed installation and operation of 

a deep well disposal system. 

11-1 
~-­ L 

G 

L ... 

construction would be prolonged due to the arid climate, 

as would revegetation of native grasses and shrubs. 

Inasmuch as the pipeline from the well field to the 

Continental well will follow the road right-of-way, 

damage to vegetation will be minimal. 

,_.., 

Aquatic habitat of the Dolores River is dependent on 

stream flow. During periods of low flow, salt concentrations are high enough to be toxic to fish and 

invertebrates. Reduction in the salt levels in the 

Dolores River will significantly benefit the aquatic 

biota by eliminating toxic levels of brine and thereby 

enhancing species diversity and abundance of aquatic 

organisms. 

Temporary disturbance of wildlife habitat will occur 

during the pipeline construction and wel1 drilling 

operations. Because of the arid climate, restoration 

~f.this habitat will be slow, but no permanent 

destruction of habitat is anticipated. The reduction 

of brine in the Dolores River will resu1 t in increased 

growth of riparian vegetation, principa11y tamarisk, 

and will consequently provide a higher productivity 

within the riparian community. 

Populations of game and non-game birds could be 

temporarily reduced during the construction activities: 

11-2 
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project area for possible impacts on threatened and en

dangered plant and animal species. No rare or endangered 

species of plants exist within the project area. The 

Colorado River squawfish and the humpback chub are found 

in the Colorado River only and constitute the only 

threatened or endangered fish species found within the 

range of project impact. FWS has determined that no 

negative impact is expected on these species as a result 

of decreased flow, and a beneficial impact is possible, 

due to improvement in water quality. 

Threatened or endangered wildlife within the project area 

consists of one active peregrine falcon aerie and use of 

the area during winter by the northern bald eagle. FWS 

has determined that the proposed project will not adversely 

impact the falcon or its critical habitat. No adverse 

impact on the northern bald eagle is foreseen. The 

ultimate increase in riparian vegetation along the 

Dolores River due to decreased salt levels will benefit 

both species by enhancing hunting areas and increasing 

prey populations. 

11.3 ECONOMIC AND SOCIAL CONDITIONS 

The improvement of the water quality resulting f~ this 

brine interception operation would have a positive 

economic benefit in the lower Colorado Basin. 

11-3 
L .. t···· 

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, ..... . ....... 

c::. 

jected increases in salinity levels~ Projected benefits of 

the removal of 1 mg/1 of salt as measured at Imperial Dam is 

reported to be $472,000 per year, based upon January 1981 

prices (Project value: $8,590,000 per year). 

The influx of construction workers would increase the number 

of personnel in the area for a short period, probably for 

less than one year. In the long term, the project would 

have essentially no impact on population- The expenditures 

of the unit construction would temporarily stimu1ate the 

economy of the area and of nearby commercial areas. Reclamation experience with similar projects indicates that most 

of the direct employment would be filled by workers from 

outside the area. Most of the indirect employment would 

occur in nearby commercial-centers and would be filled by 

residents of those areas. 

11.4 WATER RESOURCES 

__ , 

Based on a pumping rate of 2 cfs, the unit would deplete 

the lower Dolores and Colorado Rivers by a maxi~ of approximately 1,450 acre-feet annually. This is less than 0.5 

percent of the average annual stream flow of the Dolores 

River. Effects of this depletion would be most noticeable 

during late summer and early fall when stream flow frequently 

falls below 5 cfs. During spring high flows, the depletion 

effect would be negligible. 

11-4 
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heavy metals also would occur. The-disposal system would 

have no effect on concentrations of nutrients or coliform 

bacteria. It would also have no significant effect on the 

turbidity in the long term. 

11.6 . LAND USE 

11.7 

Additional land required for the deep disposal well system 

is minimal. The well field already exists, and the pipeline 

would be installed along the existing road right-of-way. 

Land surrounding the existing Continental well would be 

purchased or leased. Land for the filtration system and 

pump station will be adjacent to the pipeline, resulting in 

a minimum of disruption of present land usage. 

UNAVOIDABLE ADVERSE EFFECTS 

The permanent pipeline to the disposal well would be buried 

so it would not create any permanent detrimental visual 

effects. The Continental well is located on a small hill. 

The wellhead will not be visible from the county road. 

The injection plant and filter system will be installed 

in a sparsely populated area. 

The influx of construction workers would affect social 

conditions by increasing the demand fo·r motels/apartments 

and eating facilities for the construction period. 

11-5 
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not present any significant options. 

These benefits would include the additional job 

opportunities and the stimulation of the local economy 

during the ·construction period. Short-term loss would 

consist of the temporary clearing of some wildlife 

habitat for the pipeline. The most significant benefit 

would be the improved economic condition in the Lower 

Color~do Basin that would result from the reduced 

salinity. 

Another significant gain from the improved water quality 

would be the enhancement of fish and aquatic habitat 

in about 70 miles of the lower Dolores River. 

11.9 DISPOSAL FORMATIONS 

Because of its extensive size, massive thickness and 

noted porosity, the Mississippian formation and possibly 

some underlying formations will provide a sui table subsurface reservoir for per.manent storage of the brine. 

The .depth of the formation is a favorable factor, since 

it is far below and adequately isolated £~m all fresh 

waters. Natural brines have been stored in the 

Mississippian limestone for more than 300 million years. 

11-6 
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well disposal system presents the least disruption and 

damage to the area. The closed circuit design will 

give the environment an excellent chance of recovery 

and re-establishment. This system can be designed to 

have minimal negative aesthetic effects on the 

surrounding area. 

11.10 WELL DESIGN 

Design and installation of the well is being engineered 

to conform with requirements as set forth in the 

"Underground Injection Control Plan" (OIC) under the 

1974 Safe Drinking Water Act. Conformance with all 

other requirements of the Federal EPA and all applicable 

regulatory agencies in the State of Colorado will assure 

safe installation and operation. 

11.11 MONITORING FACILITIES 

11.111 Brine 

The brine is not a hazardous waste; however, 

large leaks would be detrimental to surface 

vegetation. The brine supply tank. could be··. 

moved farther from the plant and surrounded 

by a containment dike; however, this is typically 

done only for hazardous wastes, flammable 

liquids, etc. 

11-7 
- · serious damage occurs to .the surrounding area. 

r.····. f-

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11.112 Hydrogen Sulfide 

A fixed-location hydrogen sulfide detector 

will be installed at a strategic location in 

the injection plant area. The alarm instrument 

has the capacity for the addition of five more 

detectors if desired. 

There could be slight seepages of hydrogen 

sulfide from the top of the brine reserve tank. 

However, at the 30-foot height, there will be 

adequate dispersion before it reaches the 

ground to prevent dangerous concentrations 

to personnel. 

The only other areas of concern are when 

personnel enter the empty vessels, i.e., the 

brine supply tank, the filter shells or the 

precoat mixing tanks. Each empty vessel 

should be adequately vented and tested for 

hydrogen sulfide content prior to entering. 

11-8 
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or leak should occur. 

o Any adverse impacts upon the flora and fauna of the 

area will be of short-term duration and in most 

respects the ultimate impact upon the environment 

will be beneficial because of decreased river 

salinity. 

11-9 
.... 

\ .... 

...... 

WR.LIAMS 1' MRS ENGINEERING COMPANY - . 

4611 

SECTION 12 

POTENTIAL PROBLEMS OF INJECTING 

THE WELL FIELD BRINE 

12.1 I STALLING THE SYSTEM 

1 .11 Excessive Drilling Costs 

lj.l2 

I 

I 

I 

I 

1Ll3 

Excessive drilling costs could be encountered 

because of problems in cleaning out the plugged 

Continental well, lost mud circulation, etc. 

The biggest risk will be the possibility of the 

drill bit not following the old hole in the 

Hermosa Paradox (salt) member. Accurate 

quantification of this risk is not possible. 

Low Injectivity 

Encountering lower than expected injectivity 

capacity because of less than expected disposal 

formation thickness, or lower permeability would 

necessitate the drilling of two or more wells. 

Available information indicates that one or 

two wells will provide the required capacity. 

Local Opposition 

Severe opposition by local individuals or citizen's 

groups sometimes creates a hostile political 

environment. BOR's credibility image and local 

12-1 
WUIAMS ,TIERS ENGINEERING (()MPI\NY 

• 

4611 

A Rnou~ Scienen ComPMY 

12.12 

C I 

I 

receptivity to a 

seem to be good. 

expected. 

deep disposal well installation 

Severe opposition is not 

OrERATING THE SYSTEM 

1~.21 

I 

' 

I 

' 

I 

Plugging of the Cartridge Filters 

Plugging of the cartridge filters can result 

from improper operation of the precoat filters. 

Selection of optimum cycle times and precoat 

materials plus good operator training will 

reduce cartridge filter problems. 

12.22 Corrosion Problems 

I 

~2.23 

I 

I 

Corrosion problems can occur because of higher 

than expected corrosion rates, poor performance 

of corrosion resistant alloys or failing of 

protective coatings. Monitoring the system 

with representative corrosion coupons and 

setting up a routine inspection program should 

provide good control of corrosion problems. 

Power Outages 

Power outages will cause loss of the precoat 

material from the filter leaves. Recoating has 

been determined to be less expensive than 

providing a standby circulating pump. 

12-2 
WR11AMS1Tl£RS ~lNG IIJMPANY 

Ruourc. Sc,.ncu eom,_ny 

4611 

' I 

I 

1~.24 ! 

Stopping and starting injection into the 

disposal well(s) will not be detrimental. 

Although continued power outages will be an 

operational inconvenience, they will not prevent 

successful operation of the system. 

Seismic Activity 

Increased seismic activity resulting from the 

disposal operation is not expected. If it 

should commence, the continuous monitoring 

program will provide early detection thereby 

preventing any serious problems. 

12.25 Closure of Continental Well, Scorup No. 1 

An accurate determination of the degree of deformation of salt into the hole is not possible. 

The vertical stress near the bottom of the salt 

zone is significantly greater than required for 

inelastic flow under uniaxial loading. 

At greater depths, the salt formation will 

exhibit some closing after 23 years. The drilling 

fluid left in the hole will significantly reduce 

the amount of closure provided it cannot escape 

into fractures or other porous formations. It 

typically causes the hole axis to be weaker than 

the surrounding formation. 

12-3 
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The general public often has serious concerns about deep 

well injection operations, especially in the Rocky Mountain 

areas. This is a justifiable concern which stems largely 

from the publicized efforts of the U. s. Army to dispose 

of chemical wastes into a disposal well at the Rocky 

Mountain Arsenal near Denver. This disposal well system 

had some unique characteristics that were different from 

the other 70,000 disposal wells which are being operated 

satisfactorily throughout the nation. These differences 

should be carefully noted. The history of that well is 

as follows: 

0 The well was completed in a manner that resulted 

in injection of the waste fluids into the fractures 

of Precambrian crystalline rocks at a depth of 

11,936 feet. 

o Injection of fluids began March 8, 1962, and 

continued intermittently until February 20, 1966. 

0 

0 

The number of earthquakes within five miles of the 

disposal well showed a sharp increase during the 

four-year period of disposal well operation. 

Most of the qualified investigators concluded that 

the disposal well operation caused the increased 

earthquake activity. 

13-1 
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dispose of the waste liquid into the fractures of a nonporous zone. The fractures provided a formation permeability of only .029 millidarcies. Injection wells 

typically are completed in formations which have permeabilities of 10 to 2000 millidarcies. These permeable, 

sedimentary formations, unlike Precambrian rocks, provide 

tremendous volumes for storage. 

Residents of Colorado may also be aware of the earth 

tremors near Rangely which have been linked to the waterflooding of the Rangely oil field by Chevron Oil Company. 

This secondary recovery-project began in 1958. Earth 

tremors have been occurring in the vicinity of the oil 

field at least since 1962 when the seismological observatory was installed. The USGS recorded earth tremors at a 

frequency of about one per day between 1969 and 1972. The 

earth tremors occur along a pre-existing, pre-stressed 

fault. The injection zone is the Weber sandstone member 

of 'the Mesa Verde formation. 

A test to determine the pressure necessary to fractUre 

the Weber sandstone indicated a bottom-hole pressure of 

4750 psi at breakdown. Laboratory data in tests by 

Raleigh, Healy and Bredehoeft (36) indicated a pore 

pressure of 3730 psi would reduce the effective normal 

stress sufficiently to induce slippage. The pore pressures 

in the seismically active part of the reservoir were 

4000 psi during times of high activity. The pore pressure 

13-2 
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It is concluded that the swarm of earth tremors at Rangely 

was related to the injection-induced pressurization of the 

oil bearing formation. The investigation indicated that 

this occurred because the fluids were injected along the 

fault plane of a pre-existing fracture that was pre-stressed 

to a level of near-slippage. 

13.2 LISBON VALLEY INJECTION WELL 

The disposal well in Lisbon Valley (approximately 20 miles 

southwest of Paradox Valley) is of seismic interest. This 

well has been in operation for 16 years using wellhead 

injection pressures of 800 to 2500 psi. Cumulative 

injection is about one billion gallons. The well is 

close to one major fault. The zone of injection is 

partially confined by faults. The Mississippian disposal 

zone is overlaid by the same massive salt formation that 

is present in the Paradox Valley. 

Records for the area through 1978 (after l3 years of well· 

operation) show no increased seismic activity in th~ Lisbon 

area. Data show that the operation of this well at high 

pressures near a major fault have not affected the seismic 

stability of the area. 

13-3 
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13.4 

WBEC-6111 

stresses necessary for failure in order £or seismicity 

to be induced". Induced seismicity was defined as the 

artificial occurrence of earthquakes caused by reservoir 

impoundment, fluid injection, mine excavations or underground explosions. 

It is concluded that injection of fluids into disposal 

wells cannot cause increased seismic activity unless there 

is an existing pre-stressed fault that will be lubricated 

by the fluid. Furthermore, the magnitude of the prestressed forces must be close to the level required to 

cause slippage. 

PARADOX VALLEY CONDITIONS 

Structural geologic conditions in the Paradox Valley are 

as follows: The proposed Paradox Valley well will penetrate more than 14,000 feet of salt dome before reaching 

the targeted injection formations. The outcrop o£ the 

salt dome is more than 2-1/2 miles long at the surface 

and increases in size with depth. It is more than five 

miles at 5050 feet of depth (sea level). This massive 

salt dome has excellent seismic buffer characteristics. 

Salt exhibits elastic behavior at a depth of several ·. 

hundred feet but becomes inelastic at depths greater 

than several thousand feet (37). This property can be 

better visualized if one considers the formation process 

13-4 
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New fractures, or movements along existing fractures, in 

the injection zone will diminish to zero displacement in 

the salt as the salt deforms. Furthermore, if any seismic 

activity were triggered in the Mississippian or Devonian 

formations as a result of the injection of brine, the 

shock waves would be dampened as they pass up through 

the massive salt formation. 

The injection of brine into the Mississippian and Devonian 

formations with one or two proposed Paradox Valley injection 

wells is not expected to increase the seismic activity above 

the microseismic level which now exists. This conclusion 

is based on the fact that: (1} existing evidence indicates that the area is seismicly stable {Figure 13-1}; 

therefore, the formations probably are not pre-stressed 

to the degree that would result in induced seismicity 

and (2) the lateral extent of the disposal formations is 

large enough to preclude the buildup of sufficient pore 

pressure to induce slippage. The proposed minifrac test 

will establish the maximum injection pressure that can 

be used without risking induced seismicity. 

13.5 SEISMIC MONITORING 

WBEC-ttl 

The proposed Paradox Valley disposal wells were discussed 

with Dr. James Dieterich, Program Coordinator forEarthquake 

13-5 
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Stress measurements should be made on a section of 

core from the disposal zone(s). 

Test injection pressures should be increased to 

provide a minifracture of a small section of the 

disposal formation. 

If the disposal formation can be artificially 

fractured, an impression packer should be run to 

measure the magnitude and direction of the fracture(s). 

Sensitive seismometers should be installed as soon 

as possible in an 11-location network, thereby 

providing a base line record of seismic activity 

in the area. Continued operation of the seismometers 

during the test injection period and during the·first 

few years of disposal operation will provide early 

detection of artificially induced earth tremors if 

they should occur. 

The installation of seismometers is the most important of 

the four recommendations. The onset of seismicity would be 

detected immediately. Injection operations· could then be 

reduced or stopped, thereby preventing a significant buildup 

of seismic activity. 

13-7 
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13-8 
for an injection well test program. The piping and instrument 

diagram, engineering specifications and recommended materials 

for the test program are included in the separate Engineering 

Package. 

Evaluation of available data on permeability of the potential 

disposal formations, the Mississippian and Devonian, indicate 

a probable range of 100 to 500 millidarcies. From an operational viewpoint, this is a very wide range. If the permeatility is 100 millidarcies, wellhead pressures eventually 

will increase to about 1200 psi; however, at 500 millidarcies, 

one well would still be accepting 900 gpm with a vacuum at 

the wellhead after 30 years of operation. 

It is apparent that the pressure requirements for the pipeline, 

pumps,etc. are extremely sensitive to the formation permeability. 

Inasmuch as the formation permeability cannot be determined 

until brine is pumped into the well, it is recommended that 

the well be drilled, tested and results evaluated before the 

permanent brine injection system is installed. This recommendation is most important for the high pressure portion of the 

system, i.e., the injection pumps and motors and the high 

pressure line from the injection plant to the injection well (s) • 

General plan for the test injection program is as follows: 

o Drill to the Precambrian following the drilling prognosis 

as shown in the Engineering Package. Complete in the 

Mississippian and all lower permeable formations. 

14-1 
W C_.,l 

o Lay a temporary line from the brine well field to the 

injection well (or from the plant site if the low 

pressure pipeline is already installed) • 

o Lower two Amerada-type pressure l::x::rrbs into the injection 

well to a depth of about 2500 feet (It must be below 

the static fluid level) • A two-week clock should be used 

in the pressure bombs, a pressure recorded at the wellhead. 

o Install a temporary high pressure injection pump at the 

wellhead. Install a second temporary low pressure pump 

at the plant site (or the well field), if needed, to 

transfer 200 gpm of filtered brine to the injection well, 

high pressure pump. If the permanent filters are not 

installed and operational, rent temporary cartridge 

filters from an oil-field acidizing service company. 

o Test inject for two weeks at a constant rate of 200 gpm, 

recording the pressure changes down hole and also at the 

wellhead if the wellhead is pressured (it may be on 

vacuum for the entire two-week period) • 

o Remove the pressure bombs. Determine that satisfactory 

data have been recorded before dismantling the test 

equipment, i.e., the temporary pumps and pipeline. 

14-2 
, py gg

to carry 900 gpm could be laid to the injection well. 

This would permit injection of the entire 900 gpm 

of filtered brine, after the injection test, while the 

permanent, high pressure portion of the system is 

being constructed. 

The foregoing recommended procedures provide a good compromise 

between earliest possible completion of the brine injection 

system and minimum risk of installing equipment that is 

improperly sized. 

Additional information on the injection tests is shown in the 

Handbook for Injection Testing. 

14-3 
2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

Basin Region. IAPG Guidebook to the Geology of the 

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1780-1791. 

Bechtel National Inc., 1980, Regional Environmental 

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Memorial Institute Office of Nuclear Waste Isolation 

(ONWI) • 

Bechtel National Inc., 1980, Environmental Characterization 

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Draft, Prepared for Battelle Memorial Institute Office of 

Nuclear Waste Isolation (ONWI) • 

Bergstrom, Robert E., 1968, Feasibility of Subsurface 

Disposal of Industrial Wastes in Illinois, Illinois 

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Boegli, W.J. and Schiller R.W., 1977, Pilot Plant Studies 

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Volume 1 and 2, Sponsored by AAPG, u.s.G.S. and International Association of Hydrological Sciences. 

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Bureau of Reclamation, Colorado River Basin Salinity 

Control - Paradox Valley Unit Final Environmental 

Statement, March 20, 1979. 

15-1 
12. 

13. 

14. 

15. 

16. 

17. 

18. 

19. 

20. 

Choquette, P.W. and Traut, J.D., 1963, Pennsylvanian 

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Cooley, M.E., Akers, J.P., and Stevens, P.R., 1964, 

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SUbsurface Waste Injection in the United States, Fifteen 

Case Histories, u.s. Department of the Interior Bureau 

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of Subsurface Disposal of Uravan Mill Waste Effluents 

in a Disposal Well, Unptib. Report for Union Carbide 

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and Early Growth of the Paradox Valley and Gypsum Valley 

Salt Anticlines, Colorado, USGS, Professional Paper 

No. 400-B. 

21. Fitzsimmons, J. Paul, 1963, Precambrian of the Four Corners 

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Shelf Carbonates of the Paradox Basin. 

C-691 15-2 
and New Mexico, Chemical Geology, v. 4, p. 263-294. 

24. Havenor, K. and Pye, W.D., 1958, Pennsylvanian Paleogeography of Arizona, New Mexico Geological Society Guidebook, 

9th Field Conference. 

25. Healy, J.M., RUbey, w.w., Griggs, D.T. and Raleigh, C.B., 

1968, The Denver Earthquakes, American Association for 

the Advancement of Science. 

26. Hite, R.J., 1969, Stratigraphy of the Saline Facies of 

the Paradox Member of the Hermosa Formation of Southeastern Utah and Southwestern Colorado, Four Corners 

Geo 1. Soc • Guidebook • 

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25 p. 

28. Kelley, Vincent c., 1957, Tectonics of the Region of the 

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29. Koeing, L., 1964, Ultimate Disposal of Advanced-Treatment 

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30. Konikow, L.R. and Bedlinger, M.S., 1975, Evaluation of 

Hydrogeologic Aspects of Proposed Salinity Program in 

Paradox Valley, Colorado, U.S.G.S., Lakewood, Colorado. 

31. Kunkel, Robert P., 1958, Permian Stratigraphy of the 

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Geology of Sinbad Valley Anticline. Four Corners 

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38. Parker, J. Wm. and Roberts, J. W., 1963, Devonian and 

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C--1 15-4 
48. u. s. Department of Commerce, 1971, Waste Disposal in 

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