CONCERNS INVOLVING 

PARADOX VALLEY DEEP 

DISPOSAL WELL PROJECT 

Revised: 

Prep a red by: 

July 7, 1983 

W.C. Goins,Jr. 

Larry H. Flak 

O'Brien-G~ins-Simpson & Associates. Inc. • 6720 Sands Point • Suite 201 • Houston, Texas 77074 • (713) 270·1190 
3) Fracturing 

4) Seismic Events 

5) Faults 

6) Specifications 

7) Location 

8) Testing/Completion 

The fo 11 owing are the major recommendations presented at the June 15, 1983 

meeting that are based on our knowledge of deep well drilling, completion and 

testing. 

1) Hire an experienced drilling engineering consulting firm to prepare a 

detailed 11 Well Plan 11 , outline bid areas, prepare bid specifications, 

review submitted bids and supervise the implementation of the 11 Well 

Plan 11 • 

2) A location should be selected where salt will not be encountered deeper 

than 11 ,ooo•. 

3) Determine if the target reservoir at this location has sufficient area 

extent to meet long term injection requirements. 

4) Design the disposal system to inject at fracture pressure. This will 

remove the need for filters. 

5) Ideally, precede with temporarily abandonment after determining reservoir fracture pressure, permeability and fluid chemistry. Design and 

order the injection tubing and surface facilities based on this data. 

Disposal of Paradox Valley Brine thru an injection well is viable with good 

engineering design, review and implementation. This project should not be taken 

lightly. OGS represents over 150 years of oilfield experience distributed between 8 individuals. To our knowledge no injection well has ever been designed 

to inject nearly saturated brine be low deep salt at high rates with minimum 

system maintainance and long well life. 

A great deal of technology was presented at that meeting. This information is 

detailed in the following report. 
achieving a completely cemented annulus can be very difficult.2 Most casing 

strings fail opposite salt sections because of a poorly cemented annulus. The 

most severe salt loading situation is point loading. When cement placement 

results in only a partial sheath around casing, salt moves into the uncemented 

portion o~ the·annulus and loads only~ small portion of the casing. 2 With all 

the forces concentrated on a small area of the casing, the pipe fails. Even 

completely cemented pipe can fail due to point loading. Salt has been known to 

move in a non-uniform manner. If the movement of salt occurs preferentially in 

one direction then non-uniform loading occurs. A completely cemented annulus 

may not be enough to resist directional salt movement. Directional salt movement results in another form of point loading. The results of point loading are 

devastating. In fact, no currently manufactured casing string is strong enough 

to resist point loading in its purest form. The final type of casing failure is 

one of salt movement induced bending moments. Salt is often interbedded with 

limestones and dolomites. Hole diameter is enlarged in the salt sections and 

near gauge in limestones. As salt moves into the wellbore after pipe is set, 

the salt tends to bend pipe around limestone ledge. This can lead to restrictions in the pipe, weakened pipe and ultimately failure. 

Faced with these salt movement problems there are some procedures that must be 

followed to avoid casing failure~ 

1. Drill a gauge hole thru salt. Avoid hole washout to assist in proper 

cementation. 

2. Design the casing string with 1.0 psi/ft. collapse design and high tensile efficiency. 

I 

3. Cement annulus between pipe and salt with salt saturated cements. 

Design cement placement techniques to maximize annular cement fillup. 

4. To overcome risk of casing failure due to point loading or cementing 

problems run a scab liner cemented within the primary casing string to 

get double casing string protection opposite salt sections. 

Using 8-1/2" internal drift diameter casing as· the primary casing string, the 

deepest that salt could be drilled and completed thru with good well life would 

be approximately 11,000' without use of very exotic pipe. Example: (9-7/8" 62.8 

ppf S-105 BTC, Collapse = 11010 psi, Burst = 10520 psi, Joint Strength = 

1,437,000 lbs). 
materials. 

Stainless materials are available that are completely resistant to corrosion and 

should be used in the injection string. The major difficulty in material selection is caused by the very high salinity of the brine. Many of the stainless 

steel materials resist corrosion because of a durable oxide on the steel's surface. This oxide can be eroded away by the high salinity brine and this exposes 

a surface that will corrode very fast as there is no oxygen in the system toreestablish the oxide. 

The brine must be kept nearly oxygen free to prevent corrosion of 

carbon steels and some types of stainless steels. The produced brine must be 

rna i nta i ned at pressures in excess of atmospheric pressure to prevent air entrapment 

from the producing wellhead to the injection wellhead. Chemical oxygen scavenging (sodium sulfite type or ammonium bisulfate type) may be necessary if the 

dissolved oxygen content of the brine is in excess of .05 ppm where it is in 

contact with carbon steel. Amine- type film forming corrosion inhibitor injection may be required if carbon steel is used in the tubing string or if surface 

piping needs additional protection. 

The major forseen injection problem will be scale deposition. There will be 

scale deposition problems in surface piping systems and in downhole tubulars 

without chemical scale inhibition. Scale formation in water injection systems 

contributes to formation plugging, flow restriction, equipment corrosion~ and 

the survival of corrosive bacteria under the deposits. The main deposits will 

be calcium sulfate and calcium carbonate scales. Scaling tendency should be 

controlled by o.~plication of suitable scale inhibitor (ex., phosphate ester) 

that will act on the scale crystals while they are still microscopic and thereby 

prevent further growth. Iron sulfide can be a problem if anaerobic sulfatereducing bacteria (SRB) are present in the produced brine. Microbiological iron 

sulfide scale could be a problem if SRBs are present. SBR control will require 

continous chlorination with use of a hypochlorite generator and batch treatments 

of biocide chemicals (aldehyde and/or amine types) on probably a monthly schedule. Internal plastic coating of the injection well tubing should be investigated. Internal coating will not prevent corrosion, but helps to prevent scale 

deposition due to its "slickness". · 

We have indicated the possible scale problem areas. The Bureau of Reclamation 

will need to fully study this problem and get exact treatment recommendations. 
The basic problem with designing to pump at low pressures without fracturing is 

that formation permeability is too easily plugged. If not by suspended solids 

carried thru the filters, plugging can occur by calcium carbonate, calcium 

sulfate, iron oxide, or iron sulfide scale products and by chemical precipitates 

formed from the interaction of injected brine with reservoir fluids. 

The formation receiving the injected brine is a very effective filter. As in 

surface system, if the designer wants to filter at high rates with minimum 

pressure drops, he increases the size of the filter. We accomplish this 

downhole by establishing a fracture. If we assume that 200' ·vertical feet of 

permeability is exposed in a 8i 11 diameter hole, the flow area works out as 445 

sq.ft. If a fracture is established extending 200' out from this wellbore the 

flow area is increased over 125,664 sq.ft. or 2.9 acres! This fracture does not 

inti a 11 y extend 200 • but increases in 1 ength as the fracture face is p 1 ugged 

and the injection pressure increases to maintain the required injection rate. 

The 2.9 acres calculation only exhibits the tremendous increase in flow area 

when fracturing occurs. The injection system must be designed to pump at the 

required rate at fracture extension pressures if long term injection is 

required. 

No surface filtration will be needed due to the tremendous increase in flow area 

when fracturing occurs and because of the naturally low tot a 1 suspended· so 1 ids 

content of the Paradox Valley Brine. This will decrease surface facility cost 

and greatly reduce maintenance problems. Filter systems generally require more 

maintenance tha\ other surface equipment. The Bureau of Reclamation would also 

be saved the trouble of disposing of filter media solid waste. 

SEISMIC EVENTS 

Hydraulic fracturing does not cause earthquakes. Changes in reservoir pressure 

and/or temperature due to fluid withdrawal or injection may have caused slight 

seismic events in some very limited cases. Nearly every oilfield in the world 

either produces water with the oi 1 that must be reinjected for pressure maintainence, or disposed of in a seperate reservoir.Many oilfields require water 

injection from some extraneous water source for waterflood operations or 

pressure maintainence. Many of these oil reservoirs are traps caused by natural 

faulting. In California many hydrocarbon reservoirs are traps formed by faults 
series of slight movements may have been beneficial in reducing the chance of a 

major fault movement/earthquake. 

It is recommended that a study by carried out to mitigate concern over the risk 

of earthquakes caused by injection. The study should consist of the following: 

1. Place seismometers at the proposed Paradox Valley Brine disposal site to 

investigate present seismic activity and to establish an activity baseline. 

2. Re-investigate the seismic history near or at Chevron 1 s Rangley Field. The 

field has been produced for over 30 years. The last published analysis of 

seismic activity was in mid 1971. What has happened since that time? What 

has happened to the reservior pressure since that time? What are the magni- t~de of these seismic effects? 

FAULTS 

There is a misconception that natural. faults could act as leak paths for 

injected fluids. Natural faults are normally sealed (non-permeable). This is 

particulary true for geologically old faults, as these faults are sealed by 

diagenic processes over time. If faults were not sealed, the oil industry would 

not find oil or gas trapped in structures formed by faulting where the fault is 

the impermeable boundry the contained the hydrocarbon within the structure. 

Hydrocarbons are less dense than formation brines and migrate up structure until 

trapped by a impermeable boundry. Many of these boundries are faults. 

Exploration methods for hydrocarbons tend to look for a fault that might form a 

trap and to pla~~ a well very near the fault to get in the best structural position within the possible reservoir. Natural micro fractures which improve permeability and increase reservoir size also occur near major natural faults. In 

many areas, the oil industry attempts to get close to the fault to maximize the 

chances of intercepting a naturally fractured reservoir. 

SPECIFICATIONS 

There are no common industry standards that detail sufficiently how one would 

drill a deep disposal well thru salt in the Paradox Valley to inject a nearly 

saturated brine. The worst possible mistake would be to let some low-bid 

contractor drill such a well on a loose specification where undetailed steps are 

left up to the contractor's whim. Far too many things will impact the utility of 

the well. 
g 

7. Well Contra l 

B. Formation Evaluation 

9. Lo~ation Design 

10. Logistics 

11. Safety 

12. Rig Selection 

13. Completion 

14. Testing 

15. Surface Facilities 

This elaborate specification is what the petroleum industry calls a "Well Plan". 

Following this "Well Plan", unless well conditions indicate that some changes are 

necess_ary, is something harrmered into dri 11 i ng personne 1 a 11 throughout their 

careers. 

Enforcement of the procedural guidelines established in the 11 Well Plan" should 

be left up to knowledgeable personnel in employ of the operator (i.e.: Bureau 

of Reclamation) who had association with the planning. 

To reduce drilling costs and provide for competative bidding~ certain conmon 

activities should be identified in the "Well Plan" and then bids let t6 perform 

that service. For example, each string of casing run must be cemented. There 

are companys that perform this service. Give them the part of the 11 WeH Plan" 

that outlines cementing procedure, cement chemistry and volume to set up the bid 

spec. As volumes of cement that will be actually required are hard to estimate, 

ask for a unit fOSt bid. Set up a detailed specification for required type of 

drilling rig and ask for a straight "Daywork" bid. This is necessary if the 

Bureau of Reclamation wants to control operations, but competatively bid the 

work. Every activity can be detailed to the point that a bid specification can 

be issued and cornpetative bids returned to the satification of both parties. 

LOCATION 

Initial plans were to drill a 15500' disposal well at the brine well site. This 

is impractical due to problems completing thru deep salt, high fracturing 

pressures and excessive well cost. A new well location needs to evaluated with 

consideration to the following: 
This location should be picked so that a large reservoir is encountered below 

sa 1 t. This reservoir should encompass sever a 1 thousand acre/ft. so that brine 

injection will not quickly increase reservoir pore pressure to the point that 

wellhead injection pressures exceed economic design levels. Reservoir calculations can be made to better define the required reservoir size. 

The reservoir should have a reasonable amount of permeability. The required 

amount of permeability is very hard to define. The required magnitude of permeability is reduced by designing to inject at fracturing pressures as previously discussed. Some amount of permeability is required so that· brine can 

leak-off from the fracture into the reservoir. This magnitude will probably in 

the range of 1 - 10 md. Injection into non-permeable rock wi 11 induce two 

continuously lengthening vertical fractures orientated 180° apart, radiating 

from the well bore. This fracture growth wi 11 continue unti 1 the rate of leakoff exceeds injection rate to the point that internal fracture pressure drops 

below fracture extension pressure. Picking a location near a large natural 

fault will tend to increase the chances of locating good reservoir permeability 

due to natural micro fractures. 

The brine injection well needs to be reasonably close to the brine field. Pump 

horsepower is used in frictional pressure drop to the injection well. 

Construction costs and maintaince costs increase. As corrosion and scaling 3re 

a problem, longer pipelines will require greater chemical and maintenance expenditures. · 

With these parameters in mind, it is recommended that the Bureau of Reclamation 

investigate cur~ently available seismic data to determine possible injection 

well sites. Use Continental's- #1 Scorup-Sumerville-Wilcox well as a lithology 

correlator as well as other offsets. Salt is a very good seismic reflector 

because of its low density (2.17) in respect to carbonates or shales (over 2.5). 

Once prospective areas are 1 ocated further definition (if required) .can be done 

with new seismic work. 

TESTING/COMPLETION 

After dri 11 i ng to tot a 1 depth, certain tests should be performed to better 

design the injection tubing and pumping plant. 

Drillstem tests should be done to evaluate formation permeability and sample 

reservoir fluids. These fluid samples should be checked for compatability with 

the injection brine. 
0.65 1.0 psi/ft. Unless the rocks are tectonically stressed, the gradient 

should be approximately 0.65 psi/ft. Many areas in the Rockies are tectonically 

stressed and have higher corresponding fracture gradents. This variation is 

great enough to significantly effect injection system design. Overdes i gn to 

meet any condition would require designing for a 1.0 psi/ft gradient. This 

would greatly increase tubing, piping and pump plant costs. 

per footage payment for drilling plus the costs normally assumed by the owner? 

' Also, due to the risk involved in drilling through a salt dome to a depth of 

approximately 15,500 feet, review the design of the well for completion and 

operation, which of the above payment methods wou 1 d a company be inc 1 i ned to 

build in the most contingencies? 

Provide your comments/recommendations relative to the adequacy of the specification to produce the successful completion of a deep well hole. 

We are including information compiled on the geology aspects and request the 

geology section be returned with you analysis. 

Your analysis is requested on or before June 15, 1983. 

Our point of contact is Beverly Karinen at (801) 524-5541.