APPENDIX A

NEW SALT WATER DISPOSAL WELLS

16


Table C-7

EXPECTED VALUE OF BREAK-EVEN PRODUCTION
NECESSARY TO COVER THE INCREMENTAL COST OF COMPLIANCE
FOR AN EXISTING SALT WATER DISPOSAL WELL

Event Combination Expected Value of Production (bbl/day)

ae SI7bb1 $27ob1

la, lb 0.12 x 10-1 0.25 x 10-1

le, 2a, 2b 0.37 x 1o-t 0.75 x 1o-t

3a, 3b

2c, 3c 0.47 x 1072 0.94 x 10-2

ld 0.48 x 10-2 0.95 x 10-2

2d, 34 o.44 x 10-2 0.87 x 1072

le 0.25 x 1072 0.49 x 1072

2e, 3e 0.22 x 10-2 0.44 x 10-2
Total 0.67 x 1lo-1 0.14

at $4/pb1

39,355 wells x 0.67 x 10-1 bbls/day = 2637 bbls/day
at $2/bb1

39,355 wells x 0.14 bbls/day = 5510 bbls/day

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DATE:

SUBJECT:

FROM:

TO:

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY

September 19, 1979

Potential Production Impacts from the
Underground Injection Control Regulations

Lif <f

Alan Levin, Director / af ft
RES te ep
State Programs Division” Cetra

Regions I - X Libraries

Attached is a copy of the subject document. As indicated in the
September 11, 1979, Federal Register the comment period on this
document which provides supporting data for the reproposed

Underground Injection Program Regulations, extends to October 12, 1979.
Please make this document available for public inspection and copying
in the same manner as the reproposed regulations and the other
supporting documents.

Attachment

EPA FORM 1320-6 (REV. 3-76)


PRODUCTION IMPACT ANALYSIS FOR CLASS II WELLS

A. Introduction

This section contains an analysis of the potential
impact of the proposed Underground Injection Control (UIC)
Regulations on production. The regulations could conceivably
affect production in one of the following four ways:

(1) by increasing the capital investment and operating
and maintenance costs for a new oil lease such that the
decision to drill is changed.

(2) by increasing the operating and maintenance cost
on existing producing and injection wells such that the
economic life of these wells is shortened.

(3) by imposition of remedial costs on existing wells
such that the economic life is shortened.

(4) through lost production due to additional downtime
of producing wells to comply with UIC regulations.

The Proposed Regulations

The focus of this analysis will include Items 1, 2, and
3 because all potential production impacts will become
evident in one or several of these ways. Item 4 is unlikely
to occur because compliance with the regulations will take
place during normal downtime. Therefore, this analysis will
approach new injection wells and existing injection well
issues separately. The narrative will include a step-by-
step review of the analysis for new enhanced recovery wells.
Appendix A will contain the analytical decision trees and
corresponding tables for new salt water disposal wells
without the narrative since the approach is basically the
same for both types of wells. Appendices B and C will
contain analyses for existing secondary recovery and salt
water disposal wells respectively.

There are some differences between the approaches used
for new injection wells and those for existing injection
wells. The reason for these differences is that the "area
of review" concept in the regulations is applicable only to
new wells. This concept takes into consideration abandoned
and producing wells within the area of review of a new
injection. This requirement seeks to assure the mechanical
integrity of wells within the area of review to prevent the
possibility of the migration of injected fluids into potable
water aquifers. The decision tree analysis for new injection
wells reflects relevant probabilities, explained in detail
below, for abandoned and producing wells within the area of
review of new injection wells.


APPENDIX C

EXISTING SALT WATER DISPOSAL WELLS


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Table A-7

EXPECTED VALUE OF BREAK-EVEN PRODUCTION
NECESSARY TO COVER THE INCREMENTAL COST
OF COMPLIANCE FOR A NEW SALT WATER DISPOSAL WELL OPERATION

Event Combination Expected Value of Production (bbl/day)

ee 347bb1 $27bd1
2a, 5a 0.33 x 10-1 0.66 x 10-1
4a 0.36 x 10-2 0.72 x 10-2
2b, 5b 0.70 x 1072 0.13 x 10-1
4p 0.43 x 10-3 0.85 x 10-3
2d, 5a 0.41 x 10-1t 0.81 x 10-1
ha 0.21 x 1072 o.41 x 10-2
2e, 5e 0.28 x 10-2 0.55 x 10-2
le 0.14 x 10-3 0.27 x 10-3
3a 0.50 x 1072 0.10 x 10-1
2c, 5e 0.16 x 10-1 0.32 x 10-1
3b, Ye 0.11 x 10-2 0.22 x 10-2
ef, 3d, 5f 0.22 x 10-2 0.43 x 10-2
3e 0.32 x 10-4 0.63 x 10-4
ug 0.80 x 10-4 0.16 x 10-3
3c 0.16 x 10-3 0.31 x 10-3
3f 0.13 x 1074 0.26 x 10-4

Total 0.12 0.23
at $4/bb1

5000 wells x 0.12 bbl/day

600 bbls/day
at $2/bb1

5000 wells x 0.23 bbl/day

W

1150 bbls/day

rm


Table A-3

Path Probabilities for Each Event Combination
for New Salt Water Disposal Wells

Event Combination Path Probability
1 -
2a 234
2b -20 x 10-1
2e -54 x 10-2
2d .22 x 10-1
2e .13 x 1072
or 234 x 10-3
3a -43 x 1072
3b 225 x 1073
3¢ .67 x 10-4
3d .27 x 1073
3e .16 x 10-4
3f -16 x 10-5
Na .38 x 10-1
Ub .23 x 1072
He .61 x 1073
4a 225 x 10-2
Ye .15 x 107-3
up 239 x 10-4
5a 49
5b -29 x 10-1
5e -78 x 1072
5d -31 x 10-1
5e .19 x 1072
5f -49 x 10-3

Note: Totals may not add to 1.00 due to rounding.


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Table 7

EXPECTED VALUE OF BREAK-EVEN PRODUCTION
NECESSARY TO COVER THE INCREMENTAL COST OF
COMPLIANCE FOR A NEW ENHANCED RECOVERY
WELL OPERATION

Event Combination Expected Value of Production (bbl/day)
$4/bb1 $2/bb1
2a,5a 0.16 x lowl 0.33 x 10-L
4a 0.34 x lo72 0.68 x 1072
2b,5b 0.60 x lo-2 0.11 x lo-l
4b 0.45 x 1073 0.89 x 1o73
2d,5a 0.40 x lo-l 0.79 x lo-l
4d 0.43 x 1072 0.45 x 1072
2e,5e 0.28 x 10-2 0.56 xX 10-2
4e 0.15 x 10-3 0.30 x 1lo-3
3a 0.60 X 1072 0.12 x lo-t
2c,5¢ 0.15 x lo-l 0.31 x lol
3b,4c 0.12 x lo72 0.25 xX lo-2
3d 0.60 x 1073 0.12 x 1072
2£,5£ 0.16 x 1072 0.32 x 1072
3e,4f 0.12 xX lo73 0.25 x 1073
3c 0.18 x 1073 0.36 xX 1073
3£ 0.15 x 1074 0.31 x 1074
Total 0.95 x lo-1 G.19
@ $4/bbl

20,000 wells X 0.95 x lo7l bbls/day = 1900 bbls/day
@ $2/bb1

20,000 wells X0.19 bbls/day = 3800 bbls/day

14


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Table B-6

BREAK-EVEN PRODUCTION LEVELS AND TOTAL
PROBABILITIES OF EVENT OCCURRENCES FOR
EXISTING ENHANCED RECOVERY WELLS

(DOLLARS )
Break-Even Production

Event Total Probabilities of (bbl /day)
Combination Event Occurrences*® $4/bb1 $2/bb1

la,lb 67 0.53 x 107? 0.11 x 10-1

le,2a,2b 30 0.06 0.12

2¢ .26 x lot 0.11 0.22

1d .78 x 10-2 1.14 2.28

2d .26 x 10-2 1.20 2.39

le .86 x 1073 5.48 10.95

2e .29 x 1073 5.53 11.06

* May not add to 1,00 due to rounding.


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Key variables in the analysis include the costs of
compliance, oil production associated with an injection
well, and profitability per barrel of oil produced. The
Arthur D. Little study Cost of Compliance ~ Proposed
Underground Injection Control Program - Oil and Gas Wells,
June 1979, was the source of much of the data for this
analysis. The following tables in the report were used:

° total cost of compliance--Table XIV-1

° average production levels--Table II-3

° average number of producing wells per injection
well--Tables VIII-8, VIII-9, and VIII-10

These tables provide data on the unit cost of compliance per
well and total cost to the oil industry over the first

five years of the program. The analysis of production

impacts includes a probabilistic approach to identify the

set and associated frequency of wells faced with a combination
of factors which potentially affect production. Separate
probability distributions are included for the cost of
compliance for injection wells, producing wells and abandoned
wells.

(2) Fixed Cost Per Injection Well

Table XIV-1 of the ADL report lists the total cost
to the oil and gas industry for licensing new injection
wells. Costs can be divided into a fixed and probabilistic
component. Fixed costs are borne by all new injection wells
as well as existing salt water disposal wells and include
the following items:

Table 1
FIXED COST PER INJECTION WELL
New New Salt Existing
Secondary Water Salt Water
Recovery Disposal Disposal
Permit application $367 $620 $240
Review completion records on
producing wells 17 17
Review records on completion
of abandoned wells 50 50
Total $434 $687 $240

The review of records on the completion of producing and
abandoned wells is to ascertain from existing documentation
whether these wells are constructed in such a way that they


The proposed regulations contain distinctions between
two specific types of injection wells: salt water disposal
and enhanced recovery. A further differentiation is made
between new and existing injection wells. Within the new
enhanced recovery category, there are newly drilled wells
and converted producing wells. These distinctions are
clearly needed to recognize the differences in construction
characteristics between types of wells and the evolving
technological methods for construction. Construction
characteristics and operational practices are the variables
which determine the degree of safety assured for drinking
water aquifers through which these wells penetrate. The
area of review is only applicable to new injection wells;

recovery wells and salt water disposal wells will be treated
separately.

An additional note is added on a procedural difference
between existing salt water disposal wells and existing
enhanced recovery injection wells. Existing enhanced recovery
wells are administered by rule and existing salt water disposal
wells are administered by permit. Permitting is considered
a fixed cost for purposes of analysis. Therefore a fixed
cost is attributed to the existing salt water disposal wells
but there are no fixed costs shown for existing secondary
recovery wells.

The analysis as described above is developed in two
parts. The new enhanced recovery wells are analyzed in
detail with accompanying narrative to demonstrate the method-
ology and its application. Corresponding tables and results
without the narrative are contained in Appendicies A, B, and
C for new salt water disposal wells, existing enhanced
recovery wells, and existing salt water disposal wells since
the methodologies applied are essentially the same.

B. Methodology
(1) Overview

The decision to close a production well or to
discontinue production is usually a financial decision. It
can be viewed as a capital budgeting problem. Simply stated,
is the return on investment worth the costs? Several different
technical approaches are typically used to make this decision
such as payback period, return on book value or discounted
cash flow. The discounted cash flow model, however, is
recognized as the most comprehensive and technically correct
approach and is used as the basis for the analysis in this
section. A production well is predicted to close when the
present value of the stream of future profits from operations
is less than the present value of the cost of compliance
with the UIC regulations. In other words, the operator will
discontinue production when profitability is less than
alternative investment opportunities.

nr


the break-even production for these two event combinations
at a profitability level of $4 per barrel is .33 x 10-1 (.82
x 0.04). Another perspective is that 320 operations (0.16 x
10-1 x 20,000) will each require break-even production of
0.02 barrels per day.

Weighting calculations are performed for each event
combination at both $2 and $4 per barrel profitability levels.
The expected values of additional production requirements
for each event combination are added to obtain the expected
value of additional production for each new enhanced recovery
well operation. At $2 per barrel, the expected value is 0.19
barrels of oil per day. This expected value includes not only
the costs for the new enhanced recovery injection wells
constructed within the first five years of the program provides
3800 barrels of oil per day. This approach is followed in
Appendix A for new salt water disposal wells, Appendix B for
existing enhanced recovery wells, and Appendix C for existing
salt water disposal wells.

Another way of looking at this calculation is the following.
The probability, from Table 6, of event combinations 3b and 4c,
for example, is 0.001 and the break-even production at $4/bb1
is 1.25 bbl/day. We would expect that event combination to
impact 0.001 x 20,000 = 20 new enhanced recovery wells. Some
of those wells would have an associated production of less
than 1.25 bbl/day and would close down. The remainder would
have an associated production greater than 1.25 bbl/day and
would therefore be able to cover the additional costs (including
return on investment) and would remain in operation. Thus, for
each of the 20 impacted wells, the production loss would be
either zero (if production is greater than 1.25 bbl/day) or some
amount less than 1.25 bbl/day. The estimate of 20 x 1.25 = 24
bbi/day production loss is thus an over-estimate of the actual
production loss.

The calculations performed above have also been made for
new salt water disposal wells, existing enhanced recovery wells,
and existing salt water disposal wells. The results of the
calculations are presented in Appendices A, B, and C. The
total impact computed through this methodology is presented in
the Executive Summary.


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Arthur D Little


Table A-5

BREAK-EVEN PRODUCTION LEVELS FOR
SALT WATER DISPOSAL WELLS

Event Probability Present Value Break-even

Combination of of Incremental Production

(Ficure3&4) Occurrence* Cost Stream (obi /day)

$4 od $27ob1

1 -- -- - -
2(a) 234 565 0.04 0.08
2(b) 20 x 1lo-l 1,865 0.13 0.26
2(c) 54 x 10-2 17,465 1.22 2.43
2(d) 22 x 1lo-l 10,965 0.76 1.52
2(e) 13 x 10-2 12,265 0.86 1.71
2(f) 34 x 10-3 27,865 1.94 3.87
3(a) 42 x 10-2 16,945 1.18 2.36
3(d) 25 x 10-3 18,245 1.27 2.54
3(¢) 67 x 10-4 33, 845 2.35 4.70
3(d) 27 x 10-3 27,345 1.94 3.87
3(e) 16 x 10-4 283645 1.98 3.95
3(r) 43 x 10-5 ayes 3.08 6.15
4(a) 38 x io-l 1,345 0.10 0.19
4p) 223 x 1072 2,645 0.19 0.37
Ye) -61 x 1073 18,245 1.27 2.54
4(a) 25 x lo-e 11,745 0.82 1.63
Ye) 15 x 10-3 13,045 0.91 1.81
u(r) 39 x 10-4 28,645 1.99 3.98
5(a) 49 565 0.04 0.08
5(o) 229 x lo-l 1,865 0.13 0.26
5(e) .78 x 1072 17,465 1.22 2.43
5(d) 31 x lo-l 10,965 0.76 1.52
5(e) .19 x 1072 12,265 0.86 1.71
5(f) -49 x 107-3 27,865 1.94 3.87

*Total may not add to 1.00 due to rounding.


5177

800R79101

POTENTIAL PRODUCTION IMPACTS
FROM THE

UNDERGROUND INJECTION CONTROL REGULATIONS

Environmental Protection Agency
Office of Drinking Water
Washington, D.C.

July 1979



Table 3

PATH PROBABILITIES FOR EACH EVENT COMBINATION
FOR NEW ENHANCED RECOVERY WELLS

Event Combination Path Probability*

1 ~

2a +32

2b 19 x 1072
2c 251 x 107°
2a .21 x 1o7t
2e -12 x 10-2
ar .32 x 1073
3a -50 x 1072
3b 29 x lou}
3¢ 78 x 10-4
3a -32 x 1073
3e .19 x 10-4
3f .50 x 10-5
Ya 45 x 10-1
4b 27 x 10-2
he -71 x 1073
hq 128 x 107°
he .17 x 10-3
ue -45 x 107
5a +50

5b .30 x 1071
5c .79 x 1072
5a -32 x lo7t
Se .19 x 1072
5f -51 x 1073

*May not total to 1.00 due to rounding.


newly drilled enhanced recovery well will be required to

only report its mechanical integrity is 1.00. This probability
reflects the assumption that newly drilled wells are less
likely to have problems than converted producing wells. This
specific set of "branches" or "events" have been coded

number 2 shown to the right on Figure 1.

The next step is to account for the probabilities of
event combinations affecting producing and abandoned wells
within the area of review, recognizing that this concept is
only applicable to new injection wells. This is accomplished
by extending branch number 2 by all branches in Figure 2.
The branches on Figure 2 are coded "a" through "f" shown to
the right. For example, branch number 2 on Figure 1 is
extended by branch number a on Figure 2. This extension
indicates that the probability that an abandoned well is
located within the area of review and does not require
remedial action is .94. The estimated cost of no remedial
action is $0. The next extension is the probability that
producing wells located within the area of review require no
testing is .93. Therefore the probability of the event
combination coded 2a is calculated by multiplying together
the individual probabilities. That is:

Newly drilled ER wells ~37
Report mechanical integrity only 1.00
An abandoned well in the area of

review requires no remedial action 294
A producing well in the area of

review requires no test -93
EVENT COMBINATION PROBABILITY +32

The event combination codes for Figures 1 and 2 and
their respective probabilities calculated by the methods
shown above are presented in Table 3. Scientific notation
is used to obtain two significant digits for extremely small
probabilities.

(2) Total Cost of Compliance for Event Combination

Each event combination shown in Figures 1 and 2 and
probabilistically shown in Table 3 has a cost associated
with it. The first cost is the fixed cost reflected in
Table 1. The second type of cost is the probabilistic cost
shown in Table 2. The third cost is the additional operating
and maintenance, or in this analysis, monitoring costs
associated the implementation of the proposed regulations.


Table B-5

BREAK-EVEN PRODUCTION LEVELS FOR EXISTING

ENHANCED RECOVERY WELLS

$2/bb1

O.11 x
0.11 x
0.12
2.28
10.95

Event Probability Present Value Break-even Production
Combination of of Incremental (bb1/day )
Fig. B-1&B-2 Occurrence* Cost Stream $4/ob1

la 58 76 0.53 x 107-2

lb .86 x 10-1 76 0.53 x 1072

le .78 x 10-1 856 0.06

ld .78 x 10-2 16,456 1.14

le .86 x 10-3 78, 856 5.48

2a “19 4 845 0.06

2b -29 x 107 845 0.06

20 .26 x 10-1 1,625 0.12

2d .26 x 1072 17,225 1.20

2e .29 x 1073 79,625 5.53

*May not add to 1.00 due to rounding.

nm
co

1o-1
10-1


Table B-4

COSTS OF COMPLIANCE FOR EXISTING ENHANCED
RECOVERY WELLS FOR SPECIFIC EVENT COMBINATION

(dollars)

Event Tax* Tax Total

Comb. Variable Adjusted Operation & Adjusted Present
Code Costs(V) Vari Csts Maintenance O & M Value

la 4o 21 28 55 76
1b 40 2l 28 55 76
le 1,540 801 28 55 856
ld 31,540 16,401 28 55 16,456
le 151,540 78,801 28 55 78,856
2a 1,520 790 28 55 845
2b 1,520 790 28 55 845
ec 3,020 1,570 28 55 1,625
ed 33,020 17,170 28 55 17,225
2e 153,020 79,570 28 55 79,625

*No fixed costs accrue to existing enhanced recovery wells under
the reproposed regulations.


protect nearby potable water aquifers from contamination.
This documentation includes the amount of cement used, depth
of surface casing and data on other construction techniques.

The probabilistic items are those requirements with
which the injection well operator may be out of compliance.
A well that is leaking injection fluid into surrounding
aquifers may require a cement squeeze to prevent further
leakage. An abandoned well that is the source of fluid
migration may require remedial action such as plugging.
These probabilistic items with their probabilities and unit
costs are shown in Table 2.

Table 2
PROBABALISTIC COSTS
(over 5 years)

Cost Per Fraction of
Injection Well Affected Wells

Well Testing Costs /1 $ 1,500 0.250
Remedial Action on

Injection Wells 30,000 0.001
Plug Abandoned Wells 20,000 0.009

Squeeze Cement Plug in
Producing Wells 30,000 0.003

JL Includes test of mechanical integrity, fluid movement
_ along exterior of an injection well or producing well in
the zone of endangerment. A maximum of one test per

injection well is assumed.

Cc. Enhanced Recovery Wells
(1) Decision Tree Analysis

An enhanced recovery operation may incur costs
from more than one requirement placed upon it by the UIC
program. Thus, all combinations of requirements and associated
probabilities were computed. Figure 1 shows the decision
tree from the Arthur D. Little report used to calculate the
probabilities. Each branch of Figure 1 is extended by the
decision tree in Figure 2 to account for abandoned and
producing wells.

The probability of occurrence of a specific set of
event combinations is determined by following the appropriate
limbs of the decision tree. For example, starting with
Figure 1, the probability that a new enhanced recovery well
is newly drilled is .37 based on 20,000 new enhanced recovery
wells over five years. Further, the probability that a


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Table C-5

BREAK-EVEN PRODUCTION LEVELS FOR
EXISTING SALT WATER DISPOSAL WELLS

$2/bb1

0.
-48 x lo-t
.16
32
279

16
-16
26
243
.10

48 x qo-1

16
-16
26
~42

(dollars)

Event Present Break-even Production
Combination Probability Value of (bbi/day)
Figures of Incremental
C-1 & C-2 Occurrence Cost Stream $4/ob1l

la 44 346 0.24 x 10-1

1b -45 x 10-1 346 0.24 x lo-l

le 41 x 10-2 1,126 0.78 x lo~1

ld «41 x 10-72 16,726 0.16

le -45 x 10-3 79,126 5.49

2a 2o4 1,126 0.78 x 107-2

2b 25 x lo-l 1,126 0.78 x 1o~1

2c 22 x 10-1 1,890 0.13

2d 122 x 10-2 17,490 1.22

2e 225 x 1073 79,890 5.54

3a 15 1,126 0.78 x 10-1

3b .15 x 10-1 1,126 0.78 x 1071

3e ~14 x 1o-t 1,890 0.13

34 14 x 10-2 17,490 1.21

3e -15 x 10-3 79,890 5.35

.10


Table C-6

BREAK-EVEN PRODUCTION LEVELS AND TOTAL PROBABILITIES OF
EVENT OCCURRENCES FOR EXISTING SALT WATER DISPOSAL WELLS

(dollars)
Break-even Production

Event Total Probabilities of (ob1/day)
Combination Event Occurrences* $4/ob1 $2/bb1
la, lb 49 0.24 x lo-1 0.48 x 10-1
le, 2a, 2b,

3a, 3b AT 0.78 x 10-1 0.16
2c, 3c .36 x 10-1 0.13 0.26
ld w41 x 1072 1.16 2.32
2a, 3d .36 x 1072 1.22 2.43
le -45 x 1073 5.49 10.99
2e, 3e -40 x 10-3 5.54 11.10

*May not equal 1.00 due to rounding.


APPENDIX B

EXISTING ENHANCED RECOVERY WELLS


SUMMARY TABLE

PRODUCTION IMPACTS FROM THE UNDERGROUND
INJECTION CONTROL REGULATIONS
(BASED UPON THE FIRST FIVE YEAR COST ESTIMATES)

Production
(barrels/day)
New
Enhanced Recovery Wells 1900
Salt Water Disposal Wells 600
Existing
Enhanced Recovery Wells 4300
Salt Water Disposal Wells 2600
9400

The methodologies of capital budgeting and discounted cash

flow applied in this analysis make use of decision tree
analysis and profitability distributions to account for the
possibility of various types of testing and remedial action
that may be required of an operator by the proposed regulations.

The revenue, cost of production and cash flow scenarios
which support the profitability assumptions used for this
analysis were based upon work by Arthur D. Little, Inc., and
are included in their preliminary analyses of the UIC program.
The data on well populations, remedial actions and testing
regimes are included in their report of June 1979. Their
preliminary work provides examples of historical lease
profitability and cash flow analysis during the year 1976
for various locations around the country including south
Louisiana, west Texas, east central California, Wyoming, and
Appalachia. Arthur D. Little, Inc.'s work further provides
examples of lease profitability and cash flow analysis
forecasts for the year 1981. Their report has provided much
insight into types of cost impacts that may be felt by the
industry. This awareness has been reflected in the proposed
regulations and in the impact analysis.

aii


The rate of return used in this application of the formula

was based on the report 1976 Profitability of Selected Major
Oil Company Operations by the Committee on Finance, United
States Senate 95th Congress. Preliminary work by Arthur D.
Little, Inc., indicates that profitability levels for oil

vary from $0.93 per barrel for non-stripper production to
$4.97 per barrel for stripper production. This analysis
includes the use of $2 and $4 per barrel based on an arbitrary
selection that is representative of the range of profitability
historically.

An assumption was made that each production year averaged
360 days. For event combination 2a, for example, the break-even
production required would be 0.02 barrels per day. The results
of these calculations are listed in Table 5.

An additional step was used to establish the relationship
between the incremental production levels required to break-
even and the probability that an operator would be faced
with event combinations that require such additional production.
Table 6 presents the data that shows this relationship. The
break-even production levels are arrayed in ascending order
for $4 and $2 per barrel profitability levels. The "total
probabilities of event occurrences” column is taken from
Table 5. For example, event combination 2a used before
requires break-even production of 0.02 and 0.04 barrels per
day at $4 and $2 per barrel profit level respectively. Event
combination 5a also requires break-even production of 0.02
and 0.04 barrels per day. Therefore the probabilities of 2a
and 5a are added (.32 + .50 = .82) to obtain the total
probability (.82) that an operator would incur cost of
compliance requiring additional production of 0,02 and 0.04
barrels per day. The probability is extremely low (.50 x
10-5) that an operator would incure incremental cost that
would require additional production of 3.05 barrels per day
at $4 per barrel profit level.

(4) Expected Value of Production Impacts

Since an exhaustive array of possible event combina-
tions are depicted in Figures 1 and 2 for new enhanced recovery
well operations, their probabilities represent "expectations"
that these events will in fact occur. The break-even produc-
tion computed by the above formula represents production levels
necessary to cover the cost of occurrences of each event
combination. The next step in the analysis then is to deter-
mine the number of operations that may be impacted and to
weight these Break-even production levels by the probability
of occurence. The results of these calculations are shown in
Table 7. For example, the probability that an operator will
be faced with additional production of 0.04 barrels per day at
$4 per barrel is .82. Event combinations 2a and 5a would be
responsible for such an increase. The "expected value” of


Table 6

BREAK-EVEN PRODUCTION LEVELS AND TOTAL PROBABILITIES
OF EVENT OCCURRENCES FOR NEW ENHANCED RECOVERY WELLS

Break-even Production

Event Total Probability of (bb1/day )
Combination Event Occurrences $4/ob1 $2/bdb1
2a, 5a 82 0.02 0.04
Ha -45 x 10-1 0.07 0.15
2b, 5b -49 x 10-1 0.11 0.22
io .27 x 1072 0.16 0.33
2d, 54 -53 x 10-1 0.74 1.49
hq .28 x 1072 0.80 1.59
2e, Se .31 x 1072 0.83 1.66
He .17 x 1073 0.89 1.77
3a .50 x 1072 1.16 2.32
2c, 5e -13 x 1lo-1 1.19 2.39
3b, 4e .10 x 1072 1.25 2.50
3d +32 x 10-3 1.88 3.76
or, oF .83 x 1073 1.92 3.83
3e, ur .64 x 10-4 1.97 3.94
3c .78 x 1074 2.33 4.66
3f 250 x 1079 3.05 6.11


EXECUTIVE SUMMARY

The potential of Underground Injection Control Regulations
to reduce current production levels of oil has been analyzed
through the application of capital budgeting and discounted
cash flow models. The models used contain some of the tools
that an investor may apply for deciding the merits of a
specific investment alternative. The question that these
models attempt to answer may be stated accordingly: "Is the
return on the investment worth the cost?". An investor may
use these techniques to analyze the future revenues that may
be expected from a given investment opportunity. The expected
revenue stream may then be compared with the expected cost
stream to estimate the Return on Investment (R.O.I.). When
the revenue stream exceeds the cost stream (including taxes)
by a margin equal to or greater than that of other investment
alternatives then the investor's decision will probably be
to undertake the investment alternative.

This analysis contains several simplifying assumptions
so that the complexities of oil production activities and
processes can be managed in a more logical and rational
manner. Most of the assumptions used are contained in the
report Cost of Compliance Proposed Underground Injection
Control Program — Oil and Gas Wells, June 1979, prepared by
Arthur D. Little, Inc. Several additional assumptions are
made in this phase of the analysis and they are described in
the narrative in detail.

The analysis indicates that less than 9400 barrels of
oil per day or about one-tenth of one percent of total
annual domestic production would potentially be affected by
implementation of requirements in the UIC regulations. This
amounts to approximately nine-tenths of one percent of total
stripper production. The summary table below presents
production impacts by type and category of injection well
based on the program characteristics during the first five
years. As explained in the text, the methodology produces
an upper limit on the actual impact. Moreover, as the price
of petroleum products increases through the activity of
government and markets, including the possibility of price
decontrol, the impact of the program will be further reduced.

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Table A-6

BREAK-EVEN PRODUCTION LEVELS AND TOTAL PROBABILITIES
OF EVENT OCCURRENCES FOR NEW SALT WATER DISPOSAL WELLS

Event Total Probabilities of Break-even Production
Combination Event Occurrences* (bb1/day)

SU7bd1 $2760 1
2a, 5a .83 0.04 0.08
4a -38 x 1o-t 0.10 0.19
2b, 5b 49 x 10-1 0.13 0.26
te) .23 x 10-2 0.19 0.37
2d, 5a -53 x 1o-1 0.76 1.52
ua -25 x 1072 0.82 1.63
2e, 5e 232 x 10-2 0.86 1.71
Ye -15 x 10-3 0.91 1.81
3a -43 x lo-e2 1.18 2.36
2c, 5e .13 x lo-t 1.22 2.43
3b, Ho .86 x 10-3 1.27 2.54
ef, 3d, 5f -1l x 10-¢ 1.94 3.87
3e .16 x 10-4 1.98 3.95
ug .39 x lo-4 1.99 3.98
3¢ .67 x 10-4 2.35 4.70

3f -43 x 107-5 3.08 6.15

nm
nO


PREFACE

The following analysis was performed to estimate the
potential impact of the State Underground Injection Control
Programs on operators of Class II wells. The proposal of
the regulations (44 Federal Register 23,758, April 20, 1979)
included an estimate of 12,000 barrels of oil per day that
could potentially be affected by promulgation. After this
figure was published, significant interest was shown in the
12,000 barrels per day figure and in the methodology employed
for its derivation. Therefore, EPA decided to prepare in
succinct form a description of the methodology and its
application. Development of this description led to refine-
ments in application of the models used. These refinements
led to a reduction in the potential impact estimates from
12,000 barrels per day to 9,400 barrels per day.

This analysis contains approaches frequently used and
recognized in engineering and economic estimating procedures.
They provided a way of managing and reviewing the complex
issues of oil production. EPA welcomes comments on this
analysis including those which could improve the models and

their applications.


Table B-7
EXPECTED VALUE OF BREAK-EVEN PRODUCTION

NECESSARY TO COVER THE INCREMENTAL COST OF
COMPLIANCE FOR AN EXISTING ENHANCED RECOVERY WELL

Event Combination Expected Value of Production (bbl/day)

ST7od1 S2/ooi

la, 1b 0.36 x 10-2 0.74 x 10-2
le, 2a, 2b 0.18 x 10-1» 0.36 x 10-1
2¢ 0.29 x 10-2 0.60 x 10-2
1d 0.90 x 107? 0.18 x 10-1
24 0.31 x 10-2 0.62 x 10-2
le 0.47 x 10-2 0.94 x 10-2
2e 0.16 x 10-2 0.32 x 10-2

Total 0.43 x 10-1 0.93 x lo-l

at $4/ob1

100,315 wells x 0.43 x 10-1 bbl/day

4314 bbls/day

at $2/bb1

100,315 wells x 0.93 x 10-1 bbl/day 9329 bbls/day

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These costs are reflected in Figures 1 and 2 as unit
costs or costs per well. Using event combination 2a above
the costs include

Fixed Costs (F) (from Table 1) $434
Variable Costs (V) (Probabilitstic

Costs from Figure 1) 25

Total (V&F) $459

Tax Adjustment (48%) - 220

Tax Adjusted Total $239

Tax Adjusted Operation & Maintenance $55

(Annually - $28
Present value 10%, 5 yrs =
$28 x 3.7907 = $106.14
T.A. = $106.14 - ($106.14 x .48) = $55]

TOTAL PRESENT VALUT OF $294
INCREMENTAL COST FOR EVENT
COMBINATION 2a.

Table 4 presents these costs for each event combination
code reflected in the decision trees on Figures 1 and 2.
The corresponding tables as noted above are presented in
Appendices A, B, and C for new salt water disposal wells,
existing enhanced recovery wells and existing salt water
disposal wells.

(3) Break-even Analysis for New Enhanced Recovery Wells

The next step in the analysis is to find the minimum
daily production necessary for an operator to break-even when
faced with additional cost to comply with the proposed
regulations. The break-even point is a function of several
variables including profitability per barrel of oil produced,
the present value of the event combination that occurs, the
number of days per year that the project will operate and the
rate of return to the operator. Current production levels
are maintained at optimum levels by the operator given existing
production constraints.

The break-even production level necessary to cover the
cost of compliance shown in Table 4 for a given event combina-
tion and reflected in Figures 1 and 2 is calculated by the
following formula:

Break-even Production = PV.?r

T .P

where:
PV

present value of the incremental cost of
compliance (Table 4)

P = profit per barrel

T = time period over which the additional
production would occur

r = rate of return to the operator.

re)


Table 5

BREAK-EVEN PRODUCTION LEVELS FOR
ENHANCED RECOVERY WELLS

Event Probability Present Value Break-even

Combination of of Incremental Production

(Figuresl&2) Occurrence Cost Stream (bbi/day)

(dollars) $4/bb1* $27bb1*

1 -- -- - -
2(a) 232 294 0.02 0.04
2(b) -19 x 1o-1 1,594 0.11 0.22
2(¢) .51 x 1072 17,194 1.19 2.39
2(a) 221 x 1o7t 10,694 0.2 1.49
2(e) .12 x 1072 11,994 0.83 1.66
2(f) .32 x 10-3 27,594 1.92 3.83
3(a) -50 x 10-2 16,674 1.16 2.32
3(b) 229 x 10-3 17,974 1.25 2.50
3c) .78 x 1074 33,574 2.33 4,66
3(4) 632 x 1073 27,074 1.88 3.76
3(e) .19 x 10-4 28,374 1.97 3.94
3(f) -50 x 10-5 43,974 3.05 6.11
4(a) “45 x lo-l 1,074 0.07 0.15
4(b) +27 x 10-2 2,374 0.16 0.33
4(e) 71 x 1073 17,974 1,25 2.50
4(a) .28 x 1076 11,474 0.80 1.59
4(e) +17 x 107 12,774 0.89 1.77
4Cf) -17 x 107 28,374 1.97 3.94
5(a) 50 294 0.02 0.04
5(b) -30 x 10-1 1.594 0.11 0.22
5(c) -79 x 1072 17,194 1.19 2.39
5(d) .32 x 1071 10,694 0.74 1.49
5(e) -19 x 10-2 11,994 0.83 1.81
5(f) .51 x 10-3 27,594 1.92 3.83

*Assumed profitability levels based on studies by Arthur D.
Little, Inc.

12