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TABLE VII-3
INJECTION WELL POPULATION PROJECTIONS BY STATE FOR
BASE YEAR DECEMBER 31,1979
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
Utah
Florida
Colorado
Montana
Illinois
Michigan
North Dakota
Arkansas
Alabama
Ohio
Kentucky
Nebraska
Indiana
Pennsylvania
West Virginia
New York
Tennessee
Arizona
South Dakota
Nevada
Missouri
Virginia
Totals
Salt Water
Disposal Wells
17,116
1,841
545
1,389
91
256
7
3,136
887
43
22
67
65
5,877
554
42
589
43
5,394
1,069
53
265
2
0
0
0
0
2
0
0
0
39,355
Source: Arthur D. Little, Inc., estimates.
Secondary Recovery
Injection Wells
100,315
Total
34,409
826
14,861
9,648
2,905
3,610
96
1 1 ,977
222
362
46
612
839
5,545
369
346
495
79
48
7,763
277
1,664
2,496
210
444
0
0
0
0
166
0
51,525
2,667
15,406
1 1 ,037
2,996
3,866
103
15,113
1,109
405
68
679
904
1 1 ,422
923
388
1,084
122
5,442
8,832
330
1,929
2,498
210
444
0
0
2
0
166
0
139,670
A _»i n, i .
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THIS SHEET TI} 3E USED FOR SCANNER COPY ONLY
(estimates. Accordingly, projections developed •
! ^r -- -
j utilizing a uniform net growth rate across all
j
\
\ thirty-one oil and gas states were deemed appropraite
t
] for our purposes. Table VII-4 shows a geographic dis-
tribution of injection wells adjusted to reflect overall
national growth in injection well population.
j 6 . Computation of __Increme_n tal Costs for Each
I
i Regulatory Component
\ ~~~"
i Compliance costs were computed for each incremental
sUIC requirement by multiplying the estimated unit cost
j
jby the number of wells estimated to be affected by the
• particular requirement. This set of calculations was
1
j relatively straightforward and involved application of
;the unit cost estimates to the relevant segments of thg
swell population projections for each of the five years
included in our analysis.
7. Summation of Cost Elements
Cost elements for all incremental UIC program require-
ments were then summed to develop a total direct
incremental cost of compliance to the oil and gas
industry for each of the five years included in the
analysis .
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Arthur D Little I
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HIS SHEET TO BE USED FOR SCANNER COPY ONLY
-TS
DL.
Costs have been broadly divided into two groups:
® R s cur r i ng Costs . Those costs, such as the
collection and reporting of monitoring data,
that will be borne each year of the program.
It should be noted that recurring costs will
extend beyond the first five years of the
program.
Non-recurring Costs. One-time-only costs for
complying with the regulations, such as the
replugging of abandoned wells in the area of
review. These costs will extend beyond the
first five years of the UIC program as UIC
permits are issued for new injection wells.
! D. ESTIMATES AND ASSUMPTIONS J
A number of estimates and simplifying assumptions were
developed in order to calculate the estimated cost of *
compliance. These estimates and assumptions are based on our pro-l
1 U .- • .. ^'u *
fessional judgment and our analysis of field data, survey data, publishe
information, and in-depth interviews with administrators I
of state agencies, representatives of the oil and gas _
industry, and officials of industry associations. A *
listing of estimates and assumptions follows.
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JCH5S .'BORDERS INDICATE
LONG DASHES, USE 2 HYPHENS
2!J'_L£~3. -SE A RED PENCIL DOT »
ADL. SPELL OUT COMFANV \«V =
= CiTi MG USERED=eNCIL
WELL POPULATION ESTIMATES AND ASSUMPTIONS
USED FOR COST ANALYSIS
I. ESTIMATED
1. As of December 31, 1976, there were about 127,000
active injection wells (including annular injection!
wells which number 11,400). Current projections
indicate that there will be 140,000 injection wells!
by December 31, 1979.
2. Five thousand new injection wells will be permitted!
each year; 4,000 will be new enhanced recovery injec-
tion wells, while 1,000 will be new salt water disposal
: wells. :
•3. Seventy-five percent of existing enhanced recovery
. injection wells, and 75% of existing salt water disposal
wells (not including annular injection wells) have '
> tubing and packer allowing for annular pressure testing.
\ i
J4. There are about 505,000 oil-producing wells and about
; 135,000 gas-producing wells in the United States.
i
i
5. There are 1.5 million abandoned wells, of which 1.2
million are "of record" (i.e., some information on the
well exists in state files).
D^GE NUMBER l/U-"(
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II. ASSUMED
• A. Injection Wells-General
1. State regulatory agencies implementing the UIC>
'. |
; program will require that all fresh waters of •
j 10,000 ppm TDS or less (higher quality) be pro-
I
; tected by an approved casing and cementing pro-
gram for newly drilled injection wells located
I
' in new injection fields. The program will speci-
\
| fy that:
i
a) Cemented surface casing be set through all
potable water zones--currently used or
future potential; and
b) Cement be present on the outside of all
casing strings where they pass through other
fresh water zones; and
c) Injection zones be isolated from each other
i and from all other zones with cement
above the injection zone (and below the
injection zone as applicable) for all
wells penetrating or passing through any
injection zone.
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"HIS SHEET TO 3E USED FOR SCA^MER COPY ONLY
•73 DRCCORISP '2MCDl = i=D
DOUBLE
1 : INCHES fSCROERS INDICATED'
USE ,:, 1 J. 1 ; \OT
'.VHiTt GUT OP '«_$ = CORRECT'NG
Jj5E 2 HVPHENS
t3S A RED PENCIL COT »
SPELL OUT CCMPAiViY \AYH
USE 3ED PENCIL
4.
5.
The yearly net increase in injection wells will '
i
be less than the total number of new wells per- '
mitted as a result of injection well abandon-
ments in the normal course of operation. The
expected net growth rate is projected to be
2.25% per year for salt water disposal wells,
and 3.5% per year for enhanced recovery injec-
tion wells.
While state programs will undoubtedly become effec-
tive over a span of many months, existing injec-;
tion wells are defined, for analysis purposes, ',
as the projected population of injection wells as
of December 31, 1979. \
Injection Wells-Disposal Operations '
1. Seventeen percent of salt water disposal wells '
do not have cement between the injection zone
and the fresh water zone. One-half of these I
I
wells will be able to present compelling evidence
demonstrating the lack of fluid migration; the
other half, or 8.5%, will be tested for fluid ',
migration along the exterior of the well bore using
a test such as a radioan-t-iv^ j-.y.ac
estimated cost of $1,500 each.
°AGE MA1BER
-------
2. State regulatory agencies will recognize that
a new injection well converted from an existing
producing well may not be able to comply explicitly
!
with the program described above. It is impossible
to add casing strings to an already completed '
well and it may be difficult or even impossible
to squeeze cement in many cases to the extent .
required above. Therefore, state agencies will
require a fluid migration test for all wells '
that cannot demonstrate compelling evidence
either from existing well records or geological
data of the lack of fluid migration.
3. New injection wells (both newly drilled and con-
verted) located in existing injection fields are
required only to comply with state regulations
in effect at the time a Federal UIC program is
promulgated.
\J\\
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HIS SHEET TC 3E USED FOH SCANNER COPY C^ILY
10 -^TGi-i
1?3 DP CO'-RISR 12 \!GOI = iED
CC'JBLc
1": INCHES iBORDERS INDICATED!
US3 ..III ( 'JOT ,_ 1 _ : )
pp-.-^-
'JSc A RED ?5\G!L DOT
SPSL- COT COMPANY N i?-'
USE PED =ENC;L
4. Ten percent of the wells tested for fluid migra-
tion will require remedial action; 9% will require
installing a cement seal at the top of the injeic-
tion zone at an estimated cost of $30,000 each;;
1% will be abandoned and redrilled at a cost of
$150,000 each. No additional cement is requirad
at the fresh water zone.
5. Five percent of existing disposal wells without
a tubing and packer and 1% of existing disposal
i
wells with a tubing and packer tested for leaks,
will have a leak and require squeeze cement to .
i
repair the leak at a cost of $25,000 each.
6. Annular injection wells that do not have cement!
between the injection zone and the fresh water '
zone will cease injection and be used only for
production. Testing and repairing these
annular injection wells is impractical. The ;
i
costs of securing replacement injection capacity
have not been estimated.
°AGE NUMBER
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THIS SHEHT TC 3E JSED FOR SCANNER COPY ONLY
r,i INCHES (BORDERS iNCICATHDi
USE ..\ 1 -l 1 ( M0~ :. " : " }
WHITS OUT OR USE CO PI
USe 2 HYPHENS
USE A RED PENCIL DCT
SPELL. OUT COMPANY M AM
USE RHD PENCIL
1C. Injection Wells-Enhanced Recovery Operations
1 .
2.
3.
Twenty-three percent of existing enhanced recoviery
injection wells do not have cement between the
injection zone and the fresh water zone. One-
-half of these wells will be able to present
other compelling evidence demonstrating the lacJc
of fluid migration; the other half, or 11.5%,
will be tested for fluid migration along the
exterior of the well bore using a test such as
a radioactive tracer at an estimated cost of
$1,500 each.
Ten percent of the wells tested for fluid migra
tion will require remedial action; 9% will require
installing a cement seal at the top of the injec-
tion zone at an estimated cost of $30,000 each;
1% will be abandoned and redrilled at a cost of
$150,000 each.
Seventy-five percent of existing enhanced recovery
wells without tubing and packer and 0.75% of
wells with tubing and packer tested for leaks, will
have a leak and require squeeze cement to repair
the leak at a npst-. n-F $9^,nnn each. I
PAGE -\LMBER
*l
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THIS SHEET TO BE UScD FOR SCANNER COPY ONLY
D
10 PITCH
173 OR COURIER 12 MODIFIED
DOUBLE
T'2 INCHES (BORDERS INOICAT
USE .:> 1 i 1 ( MOT .1 1 .i 1 )
>,'/r>ST= OUT OR •,$£ C
oSE 2 HYPHENS
USE A RED PENCIL D
SPELL OUT COMPANY
USE RED PENCIL
Wells Within Area of Review-General
1 .
2.
3.
4.
The area of review is assumed to be the area :
I
within a one-quarter mile radius of either a I
i
new enhanced recovery injection well or a new '
!
I
salt water disposal injection well. j
The total potential area of review for new
injection wells is broadly defined to include
all wells in and around enhanced recovery opera-
i
tions, and 50% of the wells in and around salt j
water disposal operations; these areas are
assumed to be mutually exclusive,
Oil producing wells are either: (a) in and
around enhanced recovery operations; (b) in and!
around salt water disposal operations; or ;
(c) geographically isolated from either enhanced
recovery operations or salt water disposal
operations . j
i
All gas wells are geographically isolated from
both enhanced recovery operations and salt water
disposal operations and, therefore, not in the '
potential area nf
PiGSMUMBEF
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i HIS SHEET TO 3E UStD FOR SCA^iNSR CC?Y ONLY
DOUBLE
;'2 !NChcS .aO
8.
INDICATED!
."/Hi i = CUT OR USE CCRREC
^SE 2 HYPHENS
t'SE A RED PENCIL DOT *»
SPELL OUT COMPANY NAME
JSE .=?ED PENCIL
6.
7.
I
5. Twenty-five percent of the 1.2 million abandoned
1
wells "of record," are located in geographically
I
isolated "abandoned" fields and, therefore, willl
j
not be located in a potential area of review. !
i
j
i
Abandoned wells are distributed throughout the i
regions in the same proportion as oil producing!
wells. |
i
i
f
Abandoned wells in the area of review for which!
existing records do not show sufficient cement
i
to prevent fluid migration from an injection .
zone to the fresh water zone and for which com-'
pelling evidence of non-migration cannot be prer
sented will be reabandoned. The costs of testihg
for fluid migration are high and results are
not definitive, therefore, it is unlikely a
person would test the well prior to reabandonment.
I
i
!
In general, there is a positive relationship
between the number of producing wells in or
nearby ER projects and the amount of oil produced
from ER methods in any state.
3AGE \LMBE\ljV
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HIS SHEET TO BE USED FOR SCANNER CCPY ONLY
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i E
10 PITCH
' 73 OR COURIER 12 MODIFIED
C 0 U 8 L E
1 2 INCHES BORDERS INDICATED)
USE - 1 i i ( NOT i 1 A, 1 )
C-ANGES. .VH'TE CUT CR uSc CORRECTING TAP!
LUNG DASHES USE 2 HYPHENS
3LLL£'S vSE A RED P£NCJLDO"r "»
AOL SPELL OUT COMPANY MAVIS
•irji-r-iG, JSE^ED PENCIL
9. In general, there is an inverse relationship
between the number of producing wells in SWD
!
projects and the amount of oil produced from EF3
i
methods in any state. I
Wells Within Area of Review-Disposal Operations
1 .
2.
Seven-and-a-half percent of abandoned wells ',
\
penetrating the injection zone will not be able)
to demonstrate either adequate cement or the ;
lack of fluid migration and will require plugging
at an estimated cost of $20,000 each. j
Ten percent of existing producing wells in the i
area of review will not be able to demonstrate i
either adequate cement or compelling evidence '.
i
of the lack of fluid migration between the
injection zone and the fresh water zone. Statei
agencies will allow testing for fluid migration
at producing wells to be conducted during |
scheduled well breakdown. Therefore, the incre-
mental testing cost will be $2,500.
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THIS SHEET TG 3S USED FOR SCANNER COPY ONLY
3.
SPELL GUT COMPANY \
Ninety percent of the 10% of producing wells
without adequate cement will conduct a test for
fluid migration. Ten percent of the tested wel^s
will require squeeze cement at $25,000 each.
Ninety percent will demonstrate no fluid migration
4. Ten percent of the 10% of producing wells in the
area of review will not be able to test or will,
| choose to squeeze cement without testing for
j
. fluid migration at a cost of $25,000 each.
i
.F. Wells Within Area of Review-Ehanced Recovery Operations
: 1. Enhanced recovery is usually a unitized operation
;• where fluid injected through an injection well •
; forces oil toward a pattern of producing wells.':
The operator has an incentive to make sure that;
the injected fluid is not dissipated through
leaks or other nearby wells. Therefore, the
likelihood of producing and abandoned wells near
i
an enhanced recovery well requiring remedial
action is 25% less than for the same wells near,
a disposal well.
AGcDUMBER
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"HIS SHEET TO BE USED FOR SCANNER COPY ONLY
CHAMGES.
LONG DASHES:
3ULL-TS
ADL:
EDITING
WHITE OUT CR USE CCRPcCTI.X
'^SE 2 HYPHENS
USE A RED PENCIL DOT '9
SPELL OUT COMPANY ,\AM5
L-SE RED PENCIL
4 .
2. 5.6% (7.5% x .75) of abandoned wells penetrating
t
the injection zone cannot be shown to have adequate
1
cement and will require plugging.
3. Seven-and-a-half percent (10% x .75) of existinta
I
producing wells in the area of review will not j
be able to demonstrate adequate cement or compeil-
ling evidence of the lack of fluid migration '
between the injection zone and the fresh water \
zone. State agencies will allow testing for !
i
fluid migration at producing wells to be con- '
\
ducted during scheduled well breakdowns. There-
fore, the incremental testing cost will be $2,500,
Ninety percent of the 7.5% of producing wells i
without adequate cement will conduct a test for;
fluid migration. Ten percent of the tested wells
will require squeeze cement at $25,000 each.
Ninety percent will demonstrate no fluid migration
5. Ten percent of the 7.5% of producing wells in
i
the zone of endangerment will not be able to
test and will choose to squeeze cement at $25,000
each without testing for fluid migration.
PAGE MU\iBE\J\\
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THIS SHEET TO 3E USED FOR SCAMNER CC?Y ONLY
'/.-HITE CUT OR USE CO-
uSE 2 HYPHENS
USE A RED PENCIL uO~
SPELL OUT COMPANY \
USE RED PENCIL
! G. Permitting
i
1. UIC permit applications for existing wells will
be reviewed evenly over the first five years
of the UIC program.
2. Permits for new ER wells can be sought in groups
on a project-by-project basis. Accordingly,
based on field interview data, it is assumed th,at
UIC permit applications for new ER injection !
i
wells will average 3 injection wells per applica-
tion . !
rf.
' -i o E M U M B E \|\\
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THIS 3HSET TC 3 = *,.SED FCfl SCANNER COPY CMLY
E • E_XTENT__AND_LIMITAT10 N _0 F ANALYSIS
Cost of compliance projections are the total of the
direct incremental costs to the oil and gas industry
and the incremental costs of administering the UIC
program borne by the various state agencies responsible
for overseeing the control of underground injections.
As such, our analysis is not an economic impact
analysis. The impacts resulting from uneven
distribution of these costs among the oil and gas com-
panies has not been considered; nor have impacts resulti-
ing from potential well closures or loss of production
opportunities due to higher costs of current projects
or reduced incentives for the development of new enhanced
recovery projects been included in this analysis. Our •
i, - - j---..
analysis is strictly a tabulation of those incremental costs to
borne directly both by the oil and gas industry and the
various state regulatory agencies.
=3 \>\\-
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VIII. AREA OF REVIEW '•
?
A. INTRODUCTION
The costs of complying with the area of review require-
ment of the proposed UIC program represent the largest
share of the total costs to injection well operators-- '
over 63%. The area of review requirement is estimated
to cost injection well operators $409 million over a
five-year period. Of this, approximately $315 million
represents the cost of reabandoning improperly plugged
wells, and the remaining $94 million is associated with,1
testing and cementing producing wells.
No other single cost component included in this analysis
has the potential to vary as much as this one. There
are several factors underlying this potential for
variation. One factor is the possibility of higher
costs than those estimated for reabandoning improperly
plugged wells. This issue is discussed in Section F.
I
!
;
•The concept behind the area of review requirement is
that producing and abandoned wells near an injection
.well that penetrate the injection zone have the potential
to become cond-uits for fluid migration. The extent of
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this potential is a function of how the nearby wells ;
were completed or plugged. Potential for leaking is :
also related to other factors such as anticipated '
pressure, fluid volume, and the specific geology and/or:
hydrology of the reservoirs. The emphasis in this
requirement, however, is on the condition of nearby
wells in terms of cementing. Producing wells that were:
considered "adequately" completed at the time of their
I
• ;completion may be considered inadequate by today's
• .regulatory standards and industry practice. Similarly,
'abandoned wells may be considered improperly plugged
• today even though the procedures used for abandonment
_ may have been considered "proper" at the time of
* abandonment.
I
For all new injection wells, the area of review would
| require the review of completion or plugging records of
« _, nearby wells that penetrate the injection zone. Existing
^injection wells are exempted from this requirement.
— ;
• jThe purpose of this review is to identify wells that ;
require action in terms of testing, cementing or reaban-
donment to prevent fluid migration from an injection
•zone to a fresh water zone.
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The requirement provides for two methods of determining
the radius of the area of review: a fixed radius of
not less than a quarter-mile from any new injection weLl
i
ior the calculation of a radius of the "zone of endan-
> i
:gering influence" using an objective equation such as
,a Theis equation. The radius of the "zone of endangering
:influence" could vary from location to location and
|could conceivably have a radius that is less than a
quarter-mile from the injection well. The reason for
, this is that the size of the radius of the "zone of
endangering influence" is derived from a calculation
that is based on formation, fluid flow, and pressure
characteristics. These physical characteristics might
be such that it would be impossible for fluid to flow
beyond a certain lateral distance from the well bore
of an injection well. The maximum lateral distance
might be less than a quarter-mile.
;Arthur D. Little, Inc.'s analysis of the area of review!
requirement is based on a quarter-mile radius of review
and not on the alternative "zone of endangering
influence" formula. The area of review used in this
analysis therefore is the area whose radius is a quarte-r-
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mile around all new injection wells. Producing and •
abandoned wells located within this area would be reviewed
and may require remedial action if they penetrate the
injection zone.
:B. BACKGROUND OF AREA OF REVIEW REQUIREMENT
The analysis assumes that new injection wells will be
placed in existing projects. This assumption is explained
'in Section D and acknowledges that most oil fields that
could be flooded are now under flood and that much of the future
growth in injection wells will come from the expansion
i
of existing projects. The program exempts both existing
ER injection and SWD wells from the area of review
requirement, thus it would appear that producing and
abandoned wells located near existing injection wells
would never be included in an area of review. This is
true only to the extent that existing ER injection or
SWD projects add no new injection wells after state
promulgation of a federally approved UIC program.
j
^
Most of the oil and gas-producing states do not have an
explicit requirement that completion or plugging records
of wells located nearby hydrocarbon related injection
wells be reviewed for the adequacy of cementing. As
discussed in Chapter IV, most states require that
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joperators submit plats that show the location and some-*
*
;times the depth and ownership of nearby wells. It is
i •
'less frequently required that operators provide details;
'on the completion and plugging of these nearby wells.
|
iTwo notable exceptions to this are California and New
i >
.Mexico which both have an area of review requirement
;that includes a tabulation of nearby wells including
•the specific details of their completion or plugging.
\
i
(Generally the operator specifies repair action to the
regulatory agency when the permit is applied for. The
(state agency staff also reviews the completion or plugging
details and repair action, if different than that
specified by the operator, is ordered before permit
issuance. The nature of the repair action is therefore-
preventive in that it is required at the "front-end"
before the injection well or injection project permit
is issued. This position is different from many other
states where the emphasis is on remedial action at the
:time a nearby well becomes a problem.
V.B..R
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^Sc'-^REC.^C'iC ^,'7'^"" "I
GpEuL OL^ CO"'" VV ,A •-
The emphasis in the UIC regulation's area of review ;
requirement is preventative in concept and it is believed
that these regulations also allow for state regulatory
agencies to exercise judgement and reasonableness in
deciding which wells will need to be repaired.
'While most states do not have an explicit requirement
'that the records of nearby wells be reviewed and
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(remedial action taken, this does not mean that operators
•in those states never review nearby wells or take action
^on those that appear to have the potential for leaking.
There are in fact real economic incentives for ER
operators to ensure that the effect of their project
is not dissipated by leaking wells. To maintain or
increase reservoir pressure and drive the oil through
the reservoir, it is important that injected water goes
to and stays in the designated reservoir. The efficiency
of the project is reduced to the extent that injected
.water "leaks" through inadequately cemented producing
| ;
•wells or improperly plugged abandoned wells. This
results in lower oil recovery and a higher than necessary
ratio of cost to revenue.
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!C. ANALYTICAL APPROACH AND LIMITATIONS OF THE ANALYSIS
To estimate the compliance cost of the area of review
requirement, it was necessary to develop estimates on
essentially three separate data components.
1. Number of Wells to be Reviewed
"This component includes estimates of both the number of;
producing wells and the number of abandoned wells that ,
.would be reviewed as part of the area of review require-
\
!ment for an estimated 20,000 new ER injection wells \
and 5,000 new SWD wells projected during the five-year
^analysis period.
2. Percent of Reviewed Wells that Require Remedial
Work
This component includes estimates of the percent of
those producing and abandoned wells that penetrate the
injection zone that would require action prior to permit
issuance. This action would be either testing and/or
cementing in the case of producing wells and reabandon-
ment in the case of improperly plugged abandoned wells.
j ;
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! 3. Unit Costs
This component includes estimates of the unit costs to
comply with the area of review requirement: reviewing
'well records, testing and/or cementing producing wells
and reabandoning improperly plugged abandoned wells.
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iThe derivation of each of these data components is j
;explained in detail in three separate sections of i
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this chapter. However, there are general comments that;
can be made about all three.
Because the proposed area of review requirement is not '
generally required by state regulatory agencies, there
=are only limited data available on which to base the
•estimates of this incremental compliance cost. While
• California and New Mexico have some experience with an
:area of review requirement, these states may not be
| typical of a national experience either because of the
im age and condition of their respective wells or the
regulatory stringency with respect to the enforcement
• of their regulations.
| Many states require that nearby wells be reviewed and
• repaired before permit issuance of industrial disposal
wells. In many cases this area of review has a radius
i
• ^from 2.0 - 2.5 miles. Because of the highly toxic
nature of the materials being disposed of, state
regulatory posture is considerably more stringent than
• it would be in regulating hydrocarbon related injection
wells. So the experience in this area may overs tate
the need for action.
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3 2E USED FOR SCAr
D. ESTIMATED NUMBER OF WELLS IN AREA OF REVIEW
1. General Assumptions for Methodology
Although existing injection wells are exempted from the
area of review requirement, producing and abandoned
wells located nearby these estimated 140,000 existing
injection wells are not necessarily exempted. In fact,,
the majority of existing producing wells are all poten-
tially in the area of review of new injection wells.
]
.One reason for this is that new secondary recovery
•injection wells (the majority of ER injection wells) ar-e
jlikely to be located in existing secondary recovery pro-
j
jects since it is believed that the vast majority of
oil fields that could respond to waterflooding are
currently under flood. The future increase in secondary
recovery activity therefore will come from the expansion
of existing projects by either the drilling of new :
injection wells or the conversion of producing wells
to injection wells.
!For other types of new ER injection wells (i.e., tertiary
'recovery), it is believed that in the main, they too
will be located in fields that are either now under
t
thermal-based tertiary recovery production (i.e., cyclic
or continuous steam projects in California), or under
V3E % 'JVSER
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secondary recovery. There are, of course, exceptions '
to this where tertiary recovery methods will be used
in fields after primary production when secondary
recovery methods are inappropriate.
On the other hand, new SWD wells could be located either
in existing ER projects or in existing primary production
fields (water-driven reservoirs) that depend primarily
on disposal wells to dispose of produced water rather
than on reinjection of produced water for secondary
recovery. It is not known how many existing SWD wells
:are located in ER projects and how many are located in
'primary production fields that produce from water-
driven reservoirs. To accommodate this unknown, a
•simplifying assumption was made that there are no SWD
wells in existing ER projects even though it is known
that they are not mutually exclusive. These fields
producing from water-driven reservoirs shall be
preferred to as "salt water disposal projects" for the
I
jpurpose of this analysis.
While some existing ER projects may not be expanded by
•the addition of new injection wells, it was not part of.
this analysis to identify the number or size of these
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projects. Therefore, it has been assumed that new ER I
[injection wells could be placed anywhere in existing
|ER projects. This assumption means that all producing '
I
:wells presently located in existing ER projects could
•potentially be in an area of review of new ER injection:
wells. Likewise, it has been assumed that new SWD wells
could be located anywhere in existing salt water disposal
"projects" and that the producing wells presently
located in these "projects" might potentially be in an
area of review of new SWD wells.
Based on these assumptions, it was possible to develop
a framework that categorized all existing producing wells
as either (1) in or nearby ER projects, (2) in or near-
by SWD projects, or (3) geographically isolated from
either ER or SWD projects. It was assumed that not
more than 5% of all producing wells were geographically
isolated from either type of injection activity and that
the remaining 95% were in or nearby one or the other.
The location of existing abandoned wells is difficult
if not impossible to ascertain. Abandoned wells were
therefore assumed to be distributed in the same manner
as producing wells with respect to ER projects, SWD
projects, or in geographically isolated areas.
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Arthur D. Little, Inc. was requested to distribute the
compliance costs to ER and SWD well operators. With
respect to the area of review requirement, that meant
estimating how many producing wells would be in the
area of review of new ER injection wells and how many
would be in the area of review of new SWD wells. As
explained, new ER wells will be located in existing ER
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iprojects and new SWD wells will be located in existing
1
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-SWD projects. Therefore, it was first necessary to
estimate how the 505,000 existing oil-producing wells
were distributed. The estimated distribution of oil-
producing wells into either ER or SWD projects was based
on two assumptions:
1. There is a positive relationship between
the number of producing wells in or nearby
ER projects and the amount of oil produced
from ER methods in any state.
2. There is an inverse relationship between
i the number of producing wells in SWD
projects and the amount of oil produced
from ER methods in any state.
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•; 33 USED =CR SCANNER COPY OMLY
... J
JThe first assumption is that in states with a high
I 1
jpercentage of ER oil, there will be a greater number of!
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producing wells in or nearby ER projects than in states;
that have little or no ER oil. This assumption seems
reasonable since there would be a greater number of ER
producing wells in states that produce a greater amount,
of ER oil. The relationship is probably not linear
since it is believed that ER producing wells are less
efficient than primary producing wells. This means
.that if 10% of a state's oil is produced from ER,
.probably more than 10% of its producing wells are
involved in that recovery.
The second general assumption is that in a state with
little or no ER oil production, there will be a large number
of producing wells in or around SWD projects. With fewer
producing wells in or nearby ER projects there will be a
greater need to dispose of produced water through
disposal wells.
2. Number of Producing Wells in Existing ER
Pro jects
The Bureau of Mines published a report in 1977 entitled
Liquid Hydrocarbon Production in the United States,
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' j\jf i ~* i » Jt ~_ ,™\ V^ V~/ J"^ T 'vJ > J IM *
1946-1975 and 1980 Projected, Highlighting Enhanced
Recovery. This report provides information on the
total amount of crude oil produced as well as the
amount of crude oil produced from ER methods on a
state by state basis. These two pieces of information
were used to derive a percent of crude oil production
from ER methods for each state.
As shown in Table VIII-1, each of the thirty-one oil-
producing states was assigned into one of five groups.
The assignment criterion was the percent of the state's;
ER oil production. Each of the five groups was arbi-
trarily defined by some range in percent of ER oil
production. For example, the first group included all
states whose percent of production from ER methods
ranged from 70-100%; the second group included all states
whose percent of production from ER methods ranged from;
50-70% and so on. The fifth group included all states
that had essentially no ER oil production. It should
be remembered that the basis for this methodology was '.
1975 data. The current situation may be different,
but it is believed that it is not significantly
different given the projections for ER oil recovery in
1980 as contained in the Bureau of Mines circular.
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TABLE VI11-1
CLASSIFICATION OF OIL PRODUCING STATES BY PERCENT OF
1975 OIL PRODUCTION FROM ENHANCED RECOVERY1
Group
1
Range in Percent of
Production From
Enhanced Recovery
for Each Group
70-100
50-70
30-50
10-30
0-10
States
Percent of
Production From
Enhanced Recovery
by State2
Alaska (Pre-North
Slope)
Kentucky
Montana
Florida
New York
Wyoming
Illinois
Colorado
California
Alabama
Texas
New Mexico
Oklahoma
North Dakota
Indiana
Pennsylvania
Nebraska
Utah
Missouri
Arkansas
Mississippi
Kansas
West Virginia
Louisiana (Onshore)
Michigan
Virginia
South Dakota
Tennessee
Arizona
Nevada
Ohio
96
87
86
80
79
75
72
68
64
63
61
60
54
50
50
46
44
34
30
28
23
21
21
19
13
0
0
0
0
0
0
Group's Average
Percent of
Production From
Enhanced Recovery3
80
60
40
20
1. Enhanced oil production as defined by the Bureau of Mines: fluid injection methods included are
pressure maintenance, secondary, thermal and tertiary recovery.
2. Percent of enhanced oil production was calculated for each state by dividing total barrels of enhanced
oil production by total barrels of crude oi! production.
3. Each group's average percent of production was calculated as in 2 above. The average percent of
production for each group is also the mid-point for the group's range in percent of production.
Source: Arthur D. Little, Inc., estimates developed from U.S. Department of the Interior. Bureau of Mines
circular 8734: Liquid Hydrocarbon Production in the U.S., 1946-1975and 1980 Projected, High-
lighting Enhanced Recovery, 1977.
l I Ittlo Ir
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i H13 SHEET 7'L- BE USED FOr- .rCA'Vrd:,? COPY C-MLY
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'-•5 : ^ ~t~ *'i':C. _ ~C * •*
cc :;-•- ;c«,:-":
•Having aggregated the states into these five groups, an|
| i
;average percent of ER oil production was calculated for
i
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ieach group. Actual production volumes were used to
:calculate each group's weighted average percent of ER
joil production. Interestingly, the average for each
i
group was also the mid-point of each group's range in
percent of ER production.
;This classification framework permitted two distinct
analyses — first to derive an estimate of the number of :
producing wells potentially in the area of review of
new ER injection wells and secondly, to derive an ',
estimate of the number of producing wells potentially
in the area of review of new SWD wells. Having
established that the potential number of producing
wells that could be in the area of review of new ER
f -injection wells are all the producing wells that are
_ now in or nearby ER projects, this framework aided in
establishing such an estimate. The difficulty in
1
• .estimating the number of such producing wells is that '
many producing fields are multi-zoned; therefore,
| producing wells that are under primary production could,
_ ^conceivably be in or nearby ER projects. Since these
primary producing wells might penetrate an injection
-73JT-
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zone and therefore be included in an area of review re-l
(quirement, they could not be ignored. Based on discussions
with industry in several of these oil-producing states
(mostly states in groups 1 and 2 on Table VIII-1) it
,was possible to estimate the percent of all producing
wells (primary, secondary, tertiary) that are in or
nearby ER projects.
These estimates are shown graphically in Figure VIII-1,
Curve (a). The vertical axis in this figure is the
percent of all oil-producing wells. The horizontal
axis is the percent of oil produced from ER methods.
The slope of Curve (a) is based on a composite of data
estimates and assumptions. The shape indicates that at.
0% ER oil production, there are no producing wells in
or nearby ER projects while at 80% ER oil production,
80% of all producing wells are in or nearby ER projects.
However, the slope of the curve is non-linear since the,-
first ER injection well placed in any given oil field
•would include a disproportionately greater number of
producing wells assuming non-random placement. While
this general slope is probably correct, there is insig-'
nificant data to determine the extent to which this
curve is "bowed". However, in spite of its limitations,
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-a
o
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100
90
80
70
60
50
£ 40
30
20
10
(a) Percent of Oil Producing
Wells in or nearby Enhanced
Recovery Projects
(b) Percent of Oil Producing
Wells in or nearby Salt
Water Disposal Projects1'
_| I i L
10 20 30 40 50 60 70 80
Percent of Oil Produced from Enhanced Recovery
90
100
1
Curve (b) is derived from curve (a) such that their sum = 95% of all producing wells.
Source: Arthur D. Little, Inc., estimates.
FIGURE VIII-1 RELATIONSHIP BETWEEN PERCENT OF ENHANCED RECOVERY OIL PRODUCTION
AND PERCENT OF PRODUCING WELLS IN OR NEARBY ENHANCED RECOVERY
PROJECTS AND (B) IN OR NEARBY SALT WATER DISPOSAL PROJECTS
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it is reasonable and is a constructive framework for
estimating the number of producing wells that could
potentially be in an area of review of new ER injection;
wells .
Curve (a), in Figure VIII-1. was used to calculate the :
number of producing wells potentially in the area of
review. Table VIII-2 shows this calculation. The
percent of all producing wells read from the vertical
axis in Figure VIII-1 appears in the fourth column in
Table VIII-2. The estimated number of producing wells
that could potentially be in the area of review is then;
simply a product of the estimated percent and the actual
number of producing wells in each group.
;From this analysis, there are approximately 315,000
wells or 60% of all producing wells in the United States
that are in or nearby ER projects and therefore poten-
tially in the area of review of new ER injection wells.
j ;
3. Number of Producing Wells in Existing SWD
Proj ects
The same framework used to estimate the producing wells<
in ER projects was used to estimate producing wells in
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TABLE VI11-2
ESTIMATED NUMBER OF OIL PRODUCING WELLS POTENTIALLY IN THE
AREA OF REVIEW OF NEW ENHANCED RECOVERY INJECTION WELLS
State Group
1
2
3
4
5
Total
Group's Average Percent
of Production From
Enhanced Recovery
80%
60
40
20
0
Adjusted for 1978
Total Number
of Oil Producing
Wells in
Each Group
55,554
289,921
40,966
93,441
16,862
496,744
505,000
1. Figure VI11-1, curve A. depicts these estimates graphically.
2. The product of columns three and four.
Source: Arthur D. Little, Inc., estimates.
Estimated %
of Producing
Wells Potentially
in the Area
of Review1
80%
70
60
40
0
Estimated Number
of Producing Wells
Potentially in
the Area of Review2
44,443
202,944
24,579
37,376
0
309,342
314,600
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• SWD projects. The inverse relationship between percent!
i \
!of ER oil production and producing wells located in or j
i
jnearby SWD projects is predicated on the assumption \
', i
I that where there is little or no ER activity, produced '
j S
iwater must be disposed of through SWD wells. This saysj
i j
•that there is a greater dependency on SWD wells in those
states with little or no ER oil production. This
•inverse relationship is depicted graphically in Figure
i
', l
!VIII-1 , Curve (b) . Curve (b) is derived from Curve
(a); so that the sum of the two curves equals 95% of all
',
•producing wells [If X = the percent of producing wells
in or nearby ER projects (Curve a) , 95 - X = the percent
of producing wells in or nearby SWD projects (Curve b).]
•Curve (b) in Figure VIII-1 was used to calculate the
:number of producing wells that are in or nearby SWD
projects (or dependent on SWD wells). Table VIII-3
shows this calculation. The percent of producing wells,
•read from the vertical axis in Figure VIII-1 appears in
i !
!the -fourth column in Table VIII-3. As shown, 95% of
all producing wells located in those states that have
•no ER oil recovery (Group 5) will be dependent on SWD
wells to dispose of produced water. At the opposite
extreme, 15% of all producing wells will be dependent
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TABLE VI11-3
ESTIMATED NUMBER OF OIL PRODUCING WELLS
'DEPENDENT' ON SALT WATER DISPOSAL WELLS
State
Groups
1
2
3
4
5
Total
Group's Average
Percent of
Production from
Enhanced Recovery
60
40
20
0
Adjusted for 1978
Total Number of
Oil Producing Wells
55,554
289,921
40,966
93,441
16,862
Estimated % of
Producing Wells
Dependent on
SWD Wells1
15%
25
35
55
95
496,744
505,000
1. Figure VIII-1, curve 8. depicts these estimates graphically.
2. The product of columns three and four.
Source: Arthur D. Little, Inc., estimates.
Estimated Number
of Producing Wells
Dependent on
SWD Wells2
8,333
72,480
14,338
51,392
16,018
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on SWD wells in those states that have an average of
80% ER oil production (Group 1).
Given this analysis, there are approximately 165,000
producing wells that are dependent on SWD wells. However,
unlike producing wells in ER projects, it is believed
that the density of producing wells around SWD wells
is considerably less than producing wells around ER
injection wells. While it is not known exactly what
that density is, it was assumed that it was about half
that of producing wells around ER injection wells.
Therefore, a second curve was drawn that reflected, for:
every group, 50% fewer producing wells. Both these
curves are shown in Figure VIII-2. Curve (a) is the
percent of producing wells dependent on SWD wells, and
Curve (b) is the percent of producing wells that are
both dependent on SWD wells and potentially in the area.
or review. Using Curve (b) in Figure VIII-2, it was
possible to estimate the number of producing wells that,
would be in the area of review of new SWD wells. Tabled
VIll-4 shows this calculation. There are approximately5
83,000 producing wells that are potentially in the
area of review of new SWD wells, about half the number
of wells dependent on SWD wells.
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'o
D
TJ
O
O
"5
c
to
o
I
100
90
80
70
60
50
40
30
20
10
(a) Percent of Oil Producing Wells
Dependent on SWD Wells
(b) Percent of Producing Wells
in Potential Area of Review
of New SWD Wells (50% less
than curve a)
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10 20 30 40 50 60 70 80
Percent of Oil Produced from Enhanced Recovery
Source: Arthur D. Little, Inc., estimates.
90
100
FIGURE VIII-2
RELATIONSHIP BETWEEN PERCENT OF ENHANCED RECOVERY Ol L PRODUCTION
AND (A ) PERCENT OF PRODUCING WELLS DEPENDENT ON SALT WATER DISPOSAL
WELLS AND (B ) PERCENT OF PRODUCING WELLS POTENTIALLY IN THE AREA OF
REVIEW OF NEW SALT WATER DISPOSAL WELLS
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TABLE VIII-4
ESTIMATED NUMBER OF PRODUCING WELLS POTENTIALLY IN THE AREA OF REVIEW
OF NEW SALT WATER DISPOSAL WELLS
Group's Average
Percent of
State Production from
Groups Secondary Recovery
1 80%
2 60
3 40
4 • 20
5 0
Total
Adjusted for 1978
Total Number of
Oil Producing Wells
By Group
55,554
289,921
40,966
93,441
16,862
496,744
505,000
Estimated % of
Producing Wells
Potentially in the
Area of Review1
7.5%
12.5
17.5
27.5
47.5
Estimated Number
of Producing Wells
Potentially in the
Area of Review2
4,167
36,240
7,169
25,696
8,009
1. These percentages reflect 50% of the estimated 165,324 producing wells dependent on salt water disposal
wells (See Table VIII-3). These estimates are depicated graphically in Figure VIII-2, curve B.
2. The product of columns three and four.
Source: Arthur D. Little, Inc., estimates.
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; 4. Summary of Producing Wells in the Area of
• ' Review of New ER Injection Wells and New
: SWD Wells
;Based on the preceding analysis, 78% or approximately
397,000 producing wells are estimated to be reviewed
as part of an area of review requirement for new
injection wells (Table VIII-5). Of the 78%, 62% or
314,600 wells are included in the area of review of
; new ER wells and 16%, or 82,662 wells are included in
'the area of review of new SWD wells. Based on an
^estimate of 505,000 total oil producing wells, there ;
are approximately 108,000 producing wells that would not
be part of an area of review requirement. These 108,000
wells include 25,000 that were estimated to be the 5%
of producing wells that were geographically isolated
from either ER or SWD activity. The remaining approxi-'
mately 83,000 are estimated to be those producing wells
that are dependent on SWD wells for disposal of pro-
duced water, but unlikely to be reviewed because of the
;lower density of producing wells around SWD wells.
Another way of saying it is that there is a much
greater ratio of producing wells to SWD wells than
producing wells to ER injection wells where the ratio
is sometimes 1 to 1.
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TABLE VI11-5
PRODUCING WELLS POTENTIALLY IN THE AREA OF REVIEW
OF NEW ENHANCED RECOVERY INJECTION WELLS AND NEW
SALTWATER DISPOSAL WELLS
Number of Percent of Wells in
Area of Review of: Producing Wells Area of Review
New Enhanced Recovery
Injection Wells 314,600 62
New Salt Water Disposal Wells 82,662 16
Total Wells in Area of Review 397,2621 78
Wells Not in Area of Review 107,738 22
Total all Producing Wells 505,000 100
1. This estimate reflects the total number of wells that will be reviewed but goes
beyond the five year scope of this cost analysis. The number of producing
wells that will be reviewed by the end of year five of the U.I.C. program are
displayed in Table VI11-8.
Source: Arthur D. Little, Inc., estimates.
A rtki ir Pi I il-Ho In/"
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5. Number of Abandoned Wells in the Area
i
1 of Review
-Estimating the location of abandoned wells is more
difficult than for producing wells. Therefore, it has
•been assumed that abandoned wells are distributed in \
" !
i "
'the same way as producing wells with one exception. Of
the 1.2 million abandoned wells "of record" it is
assumed that 25% or 300,000 wells (as compared to 5%
'of the producing wells) were located in geographically
isolated "abandoned" fields and therefore could not
'possibly be in an area of review. As shown in Table
VIII-5 for producing wells, Table VIII-6 shows for
abandoned wells "of record" the number that are poten-
tially in the area of review of new injection wells.
Sixty-two percent of the 900,000 abandoned wells, or
558,000 abandoned wells are potentially in the area
of review of new ER wells, and 16% of the 900,000, or
144,000 are potentially in the area of review of new
SWD wells.
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TABLE VI11-6
ABANDONED WELLS OF RECORD POTENTIALLY IN THE AREA
OF REVIEW OF NEW ENHANCED RECOVERY INJECTION WELLS AND
AND NEW SALT WATER DISPOSAL WELLS
Number of Percent of Wells in
Area of Review of: Abandoned Wells Area of Review
New ER Injection Wells 558,000 62
New SWD Wells 144,000 16_
Total Wells in Area of Review 702,0001 78
Wells not in Area of Review 198,000 22
Total Abandoned Wells of
Record not in Geographically
Isolated Fields 900,000 100
1. This estimate reflects the total number of wells that will be reviewed but
goes beyond the five year scope of this analysis. The number of abandoned
wells that will be reviewed by the end of the fifth year of the U.I.C. program
are displayed in Table VIII-9.
Source: Arthur D. Little, Inc., estimates.
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! 6. Number of Wells in Area of Review in First
1 Five Years
•Having established the number of total producing and
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'abandoned wells that could potentially be in an area
jof review of new injection wells, it was necessary to
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;estimate how many would be reviewed in each of the
first five years of the program.
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™ 'The total population of producing and abandoned wells
would not all be reviewed during the first five years
(of the program. Based on actual well location and
spacing data taken from maps of seventy-seven fields
in thirteen states, a computer program was designed to
estimate the percent of wells in a total population
jthat would be reviewed in each year given some number
of new injection wells per year. Appendix A of this
report explains in detail how this program was designed,.
The results of the computer program are shown in Table
.VIIl-7. As shown in this Table, if 140,000 new injection
j
jwells were added (equal to the existing number of
injection wells which would be added over 28 years at
5,000 injection wells per year), then 32% of all wells
.would be reviewed given a quarter-mile radius of review.
If the radius of review were a half mile, then 89% of
all wells would be reviewed.
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TABLE VI11-7
PERCENT OF WELLS REVIEWED
GIVEN 5,000 NEW INJECTION WELLS PER YEAR1
Percent of Wells Reviewed
Year
1
2
3
4
5
10
15
20
28
New
Injection Wells
5,000
10,000
15,000
20,000
25,000
50,000
75,000
100,000
140,000
If Radius is
Quarter-Mile
9%
17%
24%
31%
36%
57%
68%
72%
82%
If Radius is
Half-Mile
11%
21%
30%
38%
45%
69%
81%
86%
89%
1. See Appendix A for details on the derivation of these estimates.
Source: Arthur D. Little, Inc., estimates.
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THIS SHEET TQ 3E USED FOR SCAiNNcR COPY 0.VJLY
;Based on this computer program with 25,000 new injectioin
'wells, by the end of the fifth year (5,000/year) an
1
lestimated 36% of the total potential population of well
•would be reviewed. Table VIII-8 shows the number of
;
'producing wells reviewed by the end of the fifth year—>
i
'approximately 113,000 in the area of review of new ER
injection wells and approximately 30,000 in the area of!
ireview of new SWD wells.
.Table VIII-9 shows the number of abandoned wells reviewed
!by the end of the fifth year—approximately 201,000
abandoned wells in the area of review of new ER injection
.wells and approximately 52,000 abandoned wells in the ;
iarea of review of new SWD wells.
Table VIII-10 is a summary of Tables VIII-8 and VIII-9
'showing both producing and abandoned wells in the area
of review of both ER and SWD wells.
E. REMEDIAL ACTION TO NEARBY WELLS i
• 1. Completion and Plugging Practices
.Completion and plugging practices have changed signifi—
i
icantly since the beginning of oil production in this
country. Current regulations require that surface
i= riLMBER
jean
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TABLE VIII-8
PRODUCING WELLS IN THE AREA OF REVIEW
Quarter-Mile Total in
Area of Review of Total Potential Five Years
(36% of potential)1
New ER Injection Wells 314,600 113,256
New SWD Wells 82,662 29,758
Total Wells 397,262 143,014
1. Given a quarter-mile radius and 5,000 new injection wells/year an estimated
36% of all wells potentially in an area of review would be reviewed by the
end of the fifth year.
Source: Arthur D. Little, Inc., estimates.
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TABLE VI11-9
ABANDONED WELLS IN THE AREA OF REVIEW
Quarter Mile Total in
Area of Review of Total Potential Five Years
(36% of potential)1
New ER Injection Wells 558,000 200,880
NewSWDWells - 144,000 51,840
Total Wells 702,000 252,720
1. Given a quarter-mile radius of review and 5,000 new injection wells/year, an
estimated 36% of all wells potentially in an area of review would be reviewed
by the end of the fifth year.
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TABLE VI11-10
PRODUCING AND ABANDONED WELLS TO BE REVIEWED BY THE END OF THE FIFTH YEAR
New ER
Injection Wells New SWD Wells Total
Producing Wells 113,256 29,758 143,014
Abandoned Wells 200,880 51,840 252,720
Total Producing and Abandoned Wells 314,136 81,598 395,734
Source: Arthur D. Little, Inc., estimates.
A -.-U, ,f T^l I ittlo In/-
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THIS SHEET TC 3= USED FOH SCA.NiNER CCPY ONLY
casing be set below the lowest fresh water zone with
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|cement circulated to the surface. Generally, current
regulations require that cement be set across all
producing zones as well as other fresh water zones not
protected by cemented surface casing. However, many ;
wells were drilled and plugged prior to adoption of
jthese standards. For example, some producing wells may
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! not have cement across or above a producing zone becaus-e
jthe zone was thought to be economically infeasible to
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^produce at the time the well was completed. Changes
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tin prices and the technology of secondary recovery,
(however, have made possible the recovery of oil from
'reservoirs that were not economical to produce under
Iprimary production practices.
jln older wells, surface casing was often not set to
'protect fresh water, and in the case of cable tool
'wells, when the well reached total depth, all of the
:outer casings were removed. The casings were not
'cemented because the cementing process had not been '
:invented. Therefore, producing wells whose completion
;was considered adequate at the time the well was
Completed are often considered "inadequately" completed!
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'by today's practices and recovery activity. In addition
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THIS SliEET TO BE USED FOR SCANNER COPY ONLY
". to this, few people imagined pressurizing reserviors
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with gas or water when primary production was the only j
known recovery technique. i
Current plugging regulations require that bottom hole !
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plugs be placed to assure that all oil> gas, and salt '
water will be retained in the producing formation.
Further cement plugs (100-150 feet thick) are required j
at the base of the surface casing with an additional
plug (25-50 feet thick) at the top of the surface
casing. In the past, some wells were plugged by filliag
the well bore with drilling mud and using cedar posts '
or a flat rock at the surface.
•Many wells that have been abandoned since the adoption
jof more rigid state abandonment regulations have been
cut off from 3-10 feet "below plow depth" in recognition
of the surface owner's use of the land for agriculture.
!This practice means that it may be difficult to even
•.locate abandoned wells before remedial action can be
:taken. Frequently there are not markers to show where
an abandoned well is located after it has been cut off,
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and it is necessary to use metal detectors and
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^heavy earth moving equipment to locate and gain access '
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FOR SCA.V'i-ER CCrY O^L -f
•TO" — aB"a~n"d' a'n a1 d1 ~w e i is~
tire
jwell is, it is sometimes necessary to build access roads
(in wetlands or marshy areas) on which to move heavy
equipment and rigs and/or to pay damages to surface ;
owners for access. The variables of well location and :
past abandonment practice can contribute to wide variation
in the cost to reabandon any given well.
Given the pressures required to drive the oil through
the reservoir, inadequately cemented wells may not be
able to withstand the added pressure and could become
'conduits for fluid migration into other producing zones,
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to the surface, or potentially into fresh water zones.
^Based on estimates received from the EPA Regional Offices,
there are 15% or approximately 84,000 oil and gas pro-
ducing wells that do not have surface casing. Table VIII-11
shows these estimates. As shown, there are an estimated
103,000 producing wells or 19% that do not have cement
across zones below the fresh water zone except at the
jproduction zone. Table VIII-12 shows data on the percent
i
of producing wells that either have no cement at zones •
.below the fresh water zone and/or have no surface casing.
.Table VIII-13 shows estimates on the percent of abandoned
we lls that h~a v e fT) no cement below tTFe fresh water zone ;
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TABLE VII1-11
SUMMARY OF U.S. OIL AND GAS PRODUCING WELL COMPLETION PROFILES
Producing wells cemented at the production
zone with surface casing through the fresh
water zone with cement below the fresh
water zone.
Producing wells cemented at the production
zone with surface casing through the fresh
water zone but without cement below the
fresh water zone.
Producing wells without surface casing.
Totals
Total Wells in
Respondent States1
363,116
102,773
84,318
550,207
Total Wells in
Non-Respondent Total Wells in
States United States
89,793
640,000
1. There were seventeen states that provided well completion profile information. The wells represented
by these respondent states are approximately 86% of all U.S. oil and gas producing wells.
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., July 1977.
Arthur D Little. Inc
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TABLE VIII-12
OIL AND GAS PRODUCING WELL COMPLETION PROFILES BY STATE - 1976
Percent of Producing Wells Cemented at the
Production Zone with Surface Casing Through
the Fresh Water Zone that have:
Cement Below the
Fresh Water Zone
100%
70
90
40
N.R.
95
100
40
N.R.
N.R.
100
N.R.
N.R.
25
N.R.
N.R.
N.R.
N.R.
40
<5
100
25
50
14
N.R.
N.R.
N.R.
75
N.R.
100
N.R.
No Cement Below the
Fresh Water Zone
0%
0
10
25
N.R.
0
0
60
N.R.
N.R.
0
N.R.
N.R.
60
N.R.
N.R.
N.R.
N.R.
60
<5
0
60
50
11
N.R.
N.R.
N.R.
25
N.R.
0
N.R.
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
Utah
Florida
Colorado
Montana
Illinois
Michigan
North Dakota
Arkansas
Alabama
Ohio
Kentucky
Nebraska
Indiana
Pennsylvania
West Virginia
New York
Tennessee
Arizona
South Dakota
Nevada
Missouri
Virginia
N.R. = No Response
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., July 1977.
Percent of
Producing Wells
Without
Surface Casing
0%
30
0
35
N.R.
0
0
0
0
N.R.
0
0
N.R.
15
N.R.
N.R.
N.R.
N.R.
0
>75
0
15
0
75
N.R.
N.R.
N.R.
0
N.R.
0
N.R.
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TABLE VIII-13
ABANDONED WELL COMPLETION PROFILE BY STATE - 1976
Percent of Abandoned Wells Plugged Below
Fresh Water Zone With Surface Casing Through
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
Utah
Florida
Colorado
Montana
Illinois
Michigan
North Dakota
Arkansas
Alabama
Ohio
Kentucky
Nebraska
Indiana
Pennsylvania
West Virginia
New York
Tennessee
Arizona
South Dakota
Nevada
Missouri
Virginia
Cement Below the
Fresh Water Zone
90%
70
90
40
N.R.
95
100
90
N.R.
N.R.
100
N.R.
N.R.
10
N.R.
N.R.
N.R.
N.R.
10
<5
100
25
2
10
N.R.
N.R.
N.R.
75
N.R.
99
N.R.
No Cement Below the
Fresh Water Zone
0%
N.A.
10
20
N.R.
0
0
10
N.R.
N.R.
0
N.R.
N.R.
30
N.R.
N.R.
N.R.
N.R.
5
<5
0
35
3
10
N.R.
N.R.
N.R.
15
N.R.
1
N.R.
Without
Surface Casing
10%
28
0
15
N.R.
0
0
0
0
N.R.
0
N.R.
N.R.
35
N.R.
N.R.
N.R.
N.R.
85
N.R.
0
30
95
80
N.R.
N.R.
N.R.
7
N.R.
0
N.R.
IWl 1 IUIJ\JQU
Below the
Fresh Water Zone
0%
2
0
25
N.R.
0
0
0
0
N.R.
0
N.R.
N.R.
25
N.R.
N.R.
N.R.
N.R.
0
N.R.
0
10
0
0
N.R.
N.R.
N.R.
3
N.R.
0
N.R.
N.R. = No Response
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., July 1977.
i ir Pt I it-tip Inr
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THiS SHEET TO 3E USED FOR SCANNER COPY ONLY
1(2) have no surface casing; and (3) are not plugged '
| 4
:below the fresh water zone. Table VIII-14 shows that 8%
|or approximately 90,000 abandoned wells of record are !
jnot plugged below the fresh water zone and do not have j
jsurface casing. There are also approximately 103,000 '
! i
[abandoned wells, or 9% of the total, that are plugged
below the fresh water zone and have surface casing but
do not have any cement across other zones below the fresh
•water zone. It is possible that if abandoned wells
.plugged in this manner penetrated an injection zone,
water could migrate vertically into other zones if not .
a fresh water zone. It is impossible however to estimate
precisely where these higher risk abandoned wells are
located--whether they are geographically isolated, in
.non-productive fields, or in active fields. Another
'important question is whether or not these higher risk
wells are also shallow wells and therefore do not even
penetrate an injection zone. If they are shallow wells,
.then there would be an overall lower cost for reabandon-
ment since shallow wells would probably not pose a threat
in terms of leaking from an injection zone.
2. Abandoned Wells in the U.S.
Table VIII-15 shows the number of abandoned wells from
1959 to 1974. It has been estimated by knowledgeable
industry individuals that the majority of wells abandoned
prior to 1930 are improperly plugged. If this were
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TABLE VIII-14
SUMMARY OF U.S. WELL COMPLETION PROFILES FOR
ABANDONED WELLS OF RECORD
Abandoned wells plugged below the fresh
water zone with surface casing through
the fresh water zone and cemented below
the zone.
Abandoned wells plugged below the fresh
water zone with surface casing through
the fresh water zone but without cementing
below the zone.
Abandoned wells plugged below the fresh
water zone but without surface casing.
Abandoned wells not plugged below the
fresh water zone and without surface
casing.
Totals
Total Wells in
Respondent States1
704,294
102,604
229,941
89,908
1,126,747
Total Wells in
Non-Respondent
States
Total Wells in
United States
73,253
1,200,000
1. There were seventeen states that provided well completion profile information. The wells represented
by these respondent states are approximately 95% of all U.S. abandoned wells of record.
Source: EPA Regional Office estimates as reported to Arthur D, Little, Inc., July 1977.
Arthur D Little. Inc
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TABLE VIII-15
NUMBER OF ABANDONED WELLS IN
THE UNITED STATES, 1859-1974
(Includes Dry Holes)
Years
1859-1890
1891-1900
1901-1910
1911-1920
1921-1930
1931-1940
1941-1968
1969-1974
Abandoned Wells
47,314
40,436
107,758
92,821
161,010
125,706
874,263
198,353
Cumulative
47,314
87,750
195,508
288,329
449,339
575,045
1,449,308
1,647,661
Source: American Petroleum Institute data:
Petroleum Facts and Figures, 1971 Edition;
Annual Statistical Review, 1965-1974.
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THISSHEcT 'C 2£ JStD "OR 3CA-\,McR COPY ONLY
;true, there would be approximately 450,000 improperly
iabandoned wells. However, wells completed prior to
I the 1900's (88,000 wells) are generally no deeper than
j
,2,500 feet and therefore possibly too shallow to be of
|concern. If all these wells are too shallow to be of
:concern, there are still 362,000 that are improperly
|plugged, perhaps located in active fields and penetrate
|an injection zone.
•There are 1,200,000 abandoned wells of record. It has ;
'been assumed that 25%, or 300,000 of these, are in :
.geographically isolated non-productive fields. If all
of these 300,000 wells are among those 362,000 that
were abandoned between 1900 and 1930, there would still.
be 62,000 located in active fields. If this were true,
these 62,000 wells would represent 7% of the estimated
900,000 abandoned wells that are assumed to be in
active fields.
j
! 3. Producing and Abandoned Wells Requiring '
Remedial Action
New Mexico and California have area of review require-
ments that are somewhat comparable to those proposed in,
the UIC program. State regulatory agency orders for
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remedial action are generally based on how many sacks ;
of cement were used and where the cement if located. :
JSince abandoned wells cannot be tested, they are ordere;d
to be reabandoned if there is inadequate cement (as •
i
jshown from the plugging records) to prevent fluid
[migration. In the case of producing wells, testing
:for potential fluid migration is not always allowed.
j
, Producing wells whose completion records show insuffi-
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jcient cement across or above injection zones are
j
.generally ordered to be recemented prior to the
•issuance of a permit for injection. The state regula-
tory posture often requires repair before there is a
problem, not when there a problem. The regulatory
posture may be more stringent in these states than the
posture that either exists now or would be adopted in
:other states after the promulgation of a federal UIC
program. Therefore, experience in these states may
not reflect a national experience.
JThe age and condition of wells in New Mexico and Cali- :
fornia also may not be typical of the national experience.
.There are considerably older producing areas whose
;wells might presumably require more remedial action.
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- , .S E Z =O P £C.-'»,"'; M 5 R C C ? Y C NIV
Based on the experience in these two states, from 6-11%!
of the producing and abandoned wells have required j
either recementing or reabandonment before an injection^
project permit was issued. Arthur D. Little, Inc.
contacted state agency officials and major producers ;
I
•in these two states to discuss their actual experience
:since the area of review requirements have become
:mandatory.
•Many oil and gas producing states do have an area of
review requirement for obtaining permits for industrial,
.disposal wells. Subsurface, Inc. provided data from
five fields in Texas and one field in Louisiana. Table'
.VIII-16 shows that 32% of the producing wells are
•inadequately cemented and 15% of the abandoned wells,
.for which there were records, were improperly plugged.
There were no records for 19% of the abandoned wells.
Because of the location of disposal wells and the
jhighly toxic nature of the disposed fluids, attitudes
toward risk are very different than for hydrocarbon
related injection wells. These estimates are therefore:
'probably higher than if the injection fluids, volume
;and/or pressures were those typical of hydrocarbon
i
related injection wells.
-GS NUMBER
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TABLE VIII-16
PRODUCING AND ABANDONED WELLS NEAR INJECTION WELLS1
Producing Wells
Abandoned Wells
Total
30
26
21
0
1
1
79
Inadequate
Wells
5
20
0
0
0
0
25
Cement
Percent
17%
77
0
0
0
0
32%
Total
162
21
88
8
25
26
330
Inadequate
Wells
g
12
19
3
1
5
49
Plugging
Percent
6%
57
22
38
4
19
15%
No
Wells
29
0
19
2
5
0
62
Records
Percent
18%
0
22
25
20
0
19%
Field
Bill Hill Field
(Jefferson County, Texas)
Clear Lake Field
(Harris County, Texas)
Corpus Christi, Texas
Channel View Field
(Harris County, Texas)
Matagorda County, Texas
Luting, La.
Total
1. Surveys of producing and abandoned wells within 2 1/2 miles of six proposed industrial disposal wells.
Adequacy of cementing or plugging as determined by current state regulations.
Source: Subsurface, Inc., estimates, July 1978.
Arthur P) I \tt\f I
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"-H5 3h£c;~ TO 3E USED FOR iC,--Vi£3 CCPY ONLY
i 4. Percent of Wells Requiring Action for Cost j
] j
Analysis i
, I
j ;
iBased on data received from EPA regional offices, ;
; i
\ 1
-.state regulatory agencies and major and independent !
i !
joil producers, it was necessary to estimate the percent,
j j
i '
jof producing and abandoned wells that would require
iremedial action on a national level.
a. Wells in Area of Review of New SWD Wells '
; It is estimated that 7.5% of all abandoned wells, that
:penetrate the injection zone of new SWD wells, will not:
be able to demonstrate either adequate cement or the
•lack of fluid migration and will require reabandonment..
lit is estimated that 10% of the producing wells in the
area of review of new SWD wells will either have to be
tested or recemented. Of this 10%, 90% will be allowed;
to test for nonmigration and 10% will require recementing
with no testing allowed. Of those 90% that are tested,!
I
jonly 10% will be unable to demonstrate non-migration '
|
lor present compelling evidence (formation characteristics,
etc.) of non-migration. Table VIII-17 shows this
•assumption. There are, therefore, approximately 2% of
;all producing wells in the area of review of new SWD
wells that will require recementing.
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TABLE VIII-17
PRODUCING WELLS IN AREA OF REVIEW OF NEW SWD WELLS
REQUIRING TESTING OR RECEMENT1NG
90%
90%
10%
Percent of Wells
Required to Test
or Recement
9.0% of Wells
Test for Non-Migration
8.1% of Wells
Demonstrate Non-
Migration
10%
0.9% of Wei Is
Recement
10%
1.0% of Wells
Recement with No Test
Source: Arthur D. Little, Inc., estimates.
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b. Wells in Area of Review of New ER :
Injection Wells
It is assumed that wells in ER projects will overall be-
25% less likely to need remedial action as part of an
area of review requirement than wells located in SWD !
projects. This assumption is based on the belief that I
operators of ER projects will have performed more
•remedial repair work to nearby wells. Enhanced recovery
!
,is usually a unitized operation where the operator has ,
\y , an economic incentive to make sure that the injected
;fluid is not dissipated through leaks through nearby
wells. Therefore, the likelihood of producing and
abandoning wells near new ER injection wells requiring '
remedial action is 25% (75% of the experience in SWD
projects) less than for the same wells nearby SWD wells;.
It is estimated that 5.6% (7.5% x .75) of abandoned
wells penetrating the injection zone cannot be shown
;to have adequate cement and will require replugging.
1
J7.5% (10% x .75) of existing producing wells in the :
area of review will require testing and/or recementing.
Of this 7.5%, ,90% will test for non-migration and 10%
•will require recementing without testing. Of those
.tested, 90% will be able to demonstrate non-migration
-AGt .NljMSE
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(or present compelling evidence of non-migration (for-
5
!
jmation characteristics) and 10% will not be able to
demonstrate non-migration and will require recementing
This assumption is shown in Table VIII-18.
F. UNIT COSTS
1. Costs to Review Well Records
In many states, completion and plugging records are
maintained in central files (for example, Texas Rail-
road Commission files of completion and plugging recordls
are kept in Austin, Texas) and not at local district
'offices. Access to these records is not always easy
due to the location of the records and idiosyncracies '.
in filing systems that those unfamiliar to the system
•would be unaware of. The centralization of such records
:would require that an operator in search of a record
either travel to locate the record or seek commercial
assistance to search, locate and copy the record. In
.most cases it would be more economical to have a service
j i
jcompany whose staff is familiar with an agency filing
.system locate and copy required well records.
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TABLE VIII-18
PRODUCING WELLS IN AREA OF REVIEW OF NEW ER WELLS
REQUIRING TESTING OR RECEMENTING
90%
90%
7.5%
Percent of Wells
Required to Test
or Recement
6.8% of We I Is
Test for Non-Migration
6.1% of Wells
Demonstrate Non-
Migration
10%
0.7% of Wells
Recement
10%
0.8% of Wells
Recement with No Testing
Source: Arthur D. Little, Inc., estimates.
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iMost operators have most of the well records for wells
j located on their lease (if they are available or exist;
Lease operators have no legal right to obtain from
I
joffset operators (e.g., operators of contiguous leases)
i
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!
included in an area of review. If producing and
abandoned wells were located on an offset lease, the
operator would have to go to public sources to obtain
well records if the offset operator refused to provide
them.
:It is estimated that on the average it would cost $17
per producing well record and $50 per abandoned well
record to locate and review. It is believed that the
,search for abandoned well records will be more difficult
'and therefore more expensive.
2. Costs to Recement and Test Producing Wells
iThe cost to test existing producing wells for fluid
;migration is estimated to be $2,500 and $30,000 to
1
recement.
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G 3E U3£D FOR
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i ;
jThe costs to reabandon an improperly plugged well ranges
! .
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jfrom an average of $10,000 to $40,000 although there :
s
are occasional excursions up to as much as $500,000 per'
well. The unit cost used in this analysis is $20,000
per well. This figure assumes fairly easy location and
access, little hidden difficulty performing the work,
^and little or no damages paid to surface owners. Tables
;VIII-19 and VIII-20 show cost estimates for well re-
•abandonment obtained by Arthur D. Little, Inc.
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TABLE VIII-19
PROCEDURE AND COST TO RE-ENTER IMPROPERLY PLUGGED AND
ABANDONED WELL AND RE-ABANDON
Procedure:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
Survey and stake location with best possible data available
Try to locate casing with magnetometer or probes.
Dig out and find casing.
Move in and rig up suitable rig.
Drill out plugs using mud weights as were used on original
Circulate hole clean
Pull out and run in with drill pipe open ended.
Set cement plug (150' to 200') above lowest possible zone
.
drilling.
Set plug below base of fresh water and 100' into surface pipe.
Set plug (25'-50') at top of surface pipe.
Cut off casing and install marker.
Percent of
Cost
1.
2.
3.
4.
5.
6.
Total
Estimate:
Surveying and search S1,500-$1 0,000
Road work and location 5,000- 25,000
Rig Cost 72-1 12 hours @$150/hr. 10,800- 16,800
Rig- move in and out 8,000-15,000
Set plugs 3,200- 5,200
Mud and mud materials 4,000- 8,000
S32,500-$80,000
Total
Low
5
15
33
25
10
12
100
Cost
High
13
31
21
19
6
10
100
Source: Subsurface, Inc., estimates, January 1979.
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TABLE VI11-20
ESTIMATED COSTS FOR TYPICAL WELL
RE-ABANDONMENT OF
IMPROPERLY PLUGGED WELLS
Source Estimated Cost
Subsurface, Inc. $32,500-$80,000
Major Oil Producer
S.E. New Mexico $25,000-$ 100,000
Major Oil Producer average of $10,000-$20,000,
West Texas and up to $80,000
Major Oil Producer
West Texas $15,000-$25,000
Major Oil Producer
California $20,000-$40,000
Major Oil Producer
West Texas $50,000
Major Oil Producer
California $50,000
Sources: Representatives of major oil producing companies and
Subsurface, Inc., as reported to Arthur D. Little, Inc.
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G. COMPLIANCE COSTS
The five-year costs for operators of new SWD wells is
as follows:
Item
Review records
on completion
of producing
wells
Review records
on plugging of
abandoned wells
Remedial action
to abandoned
wells
Test and recement
producing wells:
Test (no fluid
migration)
Recement
Number of
Wells
29, 75!
51,840
3 , 888
2 ,678
565
TOTAL
Unit Cost
($)
$1 7
$50
$20 , 000
$ 2 ,500
$30,000
Total Cost ;
for {
Five Years S
($000) !
$505
$2,592
$77,760
$ 6,695
$16 ,950
$104,502
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HiS $;- ::c7 TO 32 US5D FOR 3C VJTiER COPY 0*;!
'The five-year costs for new ER injection well operators!
i
.is as foHows :
Number of Unit Cost
Item
Wells
!* Review records
i on completion 113,256
of producing
we 11s
a Review records
on completion 200,880
\ of abandoned
we 11s
^ Remedial action
to abandoned 11,250
wells
> Test and recement
producing wells:
'• 3 Test (no fluid
migration) 7,645
Recement
1,614
($}
$17
$50
$20,000
$ 2 ,500
$30 ,000
Total Costs
for
Five Years
($000)
$1,925
$10 ,000
$225 ,000
$ 19,112
$ 48 ,420
TOTAL
$304 ,502
,Table VIII-21 provides a detail of the calculation
!of the compliance costs for area of review.
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C5,734
ducing
and
Abandoned
£Ve
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TABLE VI11-21
COMPLIANCE COSTS FOR AREA OF REVIEW
Source: Arthur D. Little, Inc., estimates.
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29,758 Reviewed
2,678 Test/No Migration
30,000
113,256 Reviewed
7,645 Test/No Migration
1,614 Recement
51,840 Reviewed
3,888 Reabandoned
200,880 Reviewed
11,250 Reabandoned
Grand Total
Unit Cost
$
17
2,500
30,000
17
2,500
30,000
50
20,000
50
20,000
Total Cost
($000)
505
6,695
16,950
1,925
19,113
48,420
2,592
77,760
10,044
225,000
409,004
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THIS ShfcET TO 3E 'JSED FOR SCANNER COPY ONLY
ELEW-.T '73 DPCCuRIER ' 2 MCD! = :-K
SF-iC;v;G DOUBLE
\'AHQi\iS '': INCHES J3OPCERS ,rJDi Z\
3QAPH ENDING. USE ll^l i >\OT ^. "! . 1
•A'HITE CUT OR USE CCRRE
LSE 2 HVPHSNS
v>SE A RED PENCIL OCT »
SPELL OUT COMPANY NAV
USE RED PENCIL
CHAPTER IX
EXISTING INJECTION WELLS--TESTING AND REMEDIAL ACTION
A. INTRODUCTION
i
This chapter details the non-recurring costs to industry
for testing and, where necessary, taking remedial action
to existing injection wells. An existing injection well,
as defined in 40 CFR Part 122.3, is any injection well j
in operation prior to the effective date of the state
i
UIC program. While state programs will undoubtedly j
i
become effective over a span of many months, for pur- ,
poses of this analysis, existing injection wells are ;
defined as the projected population of injection wells i
as of December 31, 1979.
At a minimum, the proposed regulations require that each
injection well demonstrate "mechanical integrity." This
requires both a test to verify that there are no leaks •
in the casing and a review of well records to determine;
the adequacy of cement at the injection zone to prevent!
s
fluid migration. The Figure IX-1 details the critical '•
decision path required of each injection well operator. The
analysis in this chapter will determine the costs associated
with each branch of the decision diagram.
PAGE NUMBER
/X-l I