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30
8 25
3
O
ฃ 20
0}
O
15
O
to
i 10
X
01
New-Field Wildcats
01
1962
1967
1972
1977
Source: American Association of Petroleum Geologists.
FIGURE 11-6 EXPLORATORY WELL SUCCESS RATE, 1962-1977
Arthur D Little Inc
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THIS SHEET TO 3E USED FOR SCANNER COPY ONLY
independents heavily focused in wildcat exploration
|
the integrated majors involved in development and pro-
I
jduction.
(The overall number of participants in the industry has j
1 !
jbeen variously estimated at between 5,000 and 10,000, ;
!
j i
Sbut we believe that the lower number is more representa-
l
i
jtive of the active companies. About 1,500 of these have
(entered the industry since 1971, and new ventures are
i
istill being formed at an active rate. It is estimated
!
i
'that about 300 companies have sufficiently broad stock
{ownership to be described as "public" companies.
i
)
JBased on evidence obtained from the annual Department
|
!
jof Commerce surveys, as well as other industry data, it: has
been estimated that the majors and independents now share
[exploration expenditures about equally. However, be-
jcause of their longer historical involvement in the
industry and also their tendency to take over or parti-
cipate in development of properties from the independents,
'the majors control a significantly higher fraction,
about 67%, of proven oil and gas reserves.
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jln terms of numbers of wells drilled, the independents
Ishow clear dominance, accounting for about 90% of the
jtotal exploratory wells drilled and over 75% of the
i
idevelopment wells drilled in 1977. (See Table II-6.)
I
s
'These ratios not only illustrate the significance of the
independents' role, particularly in exploratory efforts,
but also suggest that the average cost of the wells drilled
(by independents is significantly less than that of the
j
Swells drilled by the majors inasmuch as the overall
j
'spending levels are judged to be identical. This is
partly accounted for by the majors' recent activity in
i
'high-cost exploration and development projects offshore-
and in Alaska. ;
i
.Because the independents have maintained an aggressive
pace of exploratory efforts in recent years, they appear
,to be holding about a level reserve position overall
whereas the total U.S. reserves have been declining.
Even though the majors have been expending similar amounts
jfor exploration activities, their overall yield from
;this effort has not been as sizable as the reserve
.additions achieved by the independents with their greater
emphasis on onshore programs.
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TABLE 11-6
MAJOR/INDEPENDENT SHARE OF EXPLORATORY AND DEVELOPMENT WELLS
DRILLED, 1971-1977
(percent of welts)
1971 1974 1975 1976 1977
Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev. Exp. Dev.
Majors 12 24 11 25 9 21 8 20 10 21
Independents 88 76 89 75 91 79 92 80 90 79
Total 100 100 100 100 100 100 100 100 100 100
Source: Oil and Gas Journal, October 23, 1978.
Arthur P)
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10 PITCH
; 73 OR COURIER 12 .MODIFIED
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i "_ INCHES (BORDERS INDICATED)
(VHITE OUT OR USE CORRECTING TAPE
iJSc 2 HYPHENS
^SS. A RED PENCIL DOT *
SPELL OUT COMฐA:\'Y
USE RcD PENCIL
III. UNDERGROUND INJECTION ACTIVITY IN
THE UNITED STATES
A. INTRODUCTION
There are three generic types of hydrocarbon-related
injection activity enhanced oil recovery, disposal
of produced water and hydrocarbon storage (Table III-l)!
I
i
Enhanced oil recovery includes secondary recovery and
tertiary recovery injection processes, even though the
term "enhanced oil recovery" is generally used by the
]petroleum industry to refer only to tertiary recovery
i
j processes.
,-The contribution of secondary recovery processes to
total U.S. oil production is over 50%. The contribution
jof tertiary recovery processes, on the other hand, is
jstill small--approximately 5% of U.S. production. Of ]
\
the total contribution to U.S. production from tertiary)
recovery processes, 90% is attributable to the thermal-
based processes and 10% to the miscible and chemical !
i
processes (Table III-l).
JThis chapter focuses on secondary recovery injection ;
I
activity, the thermal-based tertiary recovery processes!,
"and inj ection for produced water disposal. '
3AGc NUMBER
4-
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TABLE IH-1
PURPOSES AND PROCESSES OF HYDROCARBON-RELATED
SUBSURFACE INJECTION ACTIVITY
I. Enhanced Oil Recovery
A. Secondary Recovery/Pressure Maintenance Methods
1. Water Injection
2. Gas Injection
8. Tertiary Recovery Methods
1. Thermal Recovery Processes
Hot Fluid Injection (Cyclic and continuous steam, hot water, hot gas)
In-Situ Combustion
2. Miscible Recovery Processes
Gas (C02, flue, N2, etc.) injection
Hydrocarbon (LPG, high pressure gas) injection
3. Chemical Recovery Processes
Polymer/Surfactant Injection
Polymer Injection
Alkaline Injection
II. Disposal of Produced Water (including annular injection)
111. Hydrocarbon Storage
A. Crude Oil
B. Natural Gas
C. Liquefied Petroleum Gases
Source: Arthur D. Little, Inc.
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10 PiTCH
173 OR COURIER 12 UOOI-iED
DOUBLE
T'; INCHES 'BORDERS l\DiOATฃOi
uSE '. 1 :. I I ,',OT _ 1 ;j M
-.:HA,\GES, VVMTE OUT OR USE CORRECTING TAPE
JG DASHES USE 2 HYPHENS
3LLLETS USE A RED PENCIL DOT 3ป
AOL: SPELL OUT COMPANY NAVE
ECl-'NG USE RED PENCIL
j The overwhelming majority of enhanced oil recovery welljs
are of the secondary recovery type. The contribution >,
i
and extent of secondary recovery activity in the United)
States is discussed in Section F of this chapter. The
thermal-based tertiary recovery processes are of
particular significance to the state of California and
are discussed in Section G.
j Related to the growth of secondary recovery activity
i
jhas been the growth in produced water disposal. Sub-
i
j
jsurface disposal of increasingly large volumes of
jfluids has resulted from the increase in secondary
recovery activity, natural water drives in many oil
'fields, and restrictions on surface discharge. The
i
'disposal of produced water is discussed in Section H.
;The fluid injection processes associated with secondary!
!
! i
(and tertiary recovery as well as produced water disposail
apply almost entirely to oil fields and not gas fields.;
These activities are best understood in the context of i
jreservoir characteristics and their effect on oil
i
: recovery.
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B. RESERVOIR CHARACTERISTICS
Accumulations of oil and gas occur in underground for-
mations called reservoirs or "traps." Far from being
pools of liquid, these reservoirs are rock formations
|
that have sufficient porosity to hold the oil and gas j
and yet sufficient permeability to allow the oil and
gas to be transmitted through it. These reservoir rock
formations are generally composed of sands, sandstone,
limestone, or dolomite.
The oil and gas accumulations are contained in these
reservoir rocks as a result of the juxtaposition of
other different geologic formations that seal the reser
voir rock "trapping" within it the oil and gas. These .
"sealing" formations are sometimes called cap rocks ;
and are generally composed of clays and shales which
have much lower porosity and permeability than the
reservoir rock.
i
Oil and gas traps are of various types including anti- ;
clinal traps, dome and plug traps, fault traps, and
traps formed by uncomformities. The majority of U.S.
reservoirs are anticlinal traps as shown in Figure III-
1. The reservoir rock usually contains both oil and
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Gas/Oil Transition Zone
Oil/Water Transition
Source: Modern Petroleum Technology, Fourth Edition.
FIGURE 111-1 EXAMPLE OF AN ANTICLINAL ACCUMULATION OF OIL AND GAS
Arthur D Little In
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-Y,-=iV<=!TErt SETT'rj
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USE A RED PENC! L 30T
gas as well as water. As in Figure III-l, the total !
Igas content sometimes exceeds that which can be held in
f i
iSolution with the oil such that a free gas cap forms in)
ithe upper level of the reservoir rock structure. Under
this gas cap, in the middle level, is oil with gas in
solution. Sealing the reservoir rock is an impermeable
cap rock that traps the oil and gas in the reservoir
i
!
jrock. The lower level of the reservoir in an anticlinal
i
jtrap, is typically connected to water-bearing rock for-
smations called aquifers. Other types of traps may not
ibe connected to aquifers but rather are sealed on all
I
|sides by non-porous sealing formations or they may have
the same oil/gas/water relationships as anticlinal traps,
i
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jbut in different structural or stratigraphic conditions.
i
When oil is produced from an anticlinal trap, there are
several natural sources of reservoir energy that "drive
jthe oil through the pores of the reservoir rock to the
'producing wells. First, when there is a free gas cap,
the gas expands as the pressure falls because of pro-
duction and will displace oil produced from wells lower;
on the anticlinal structure. This energy drive is
called a "gas-cap-drive."
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Second, as oil is produced, the gas that is in solution
Iwith the oil escapes from the oil and expands as the ;
ipressure in the reservoir is reduced. This phenomenon '
is called "dissolved-gas-drive" and is less effective
jthan a "gas-cap-drive" in moving the oil. ,
i
[A third source of reservoir energy is a natural "water-1
^ :drive." Where aquifers are connected to reservoir rocks,
S;the water in the aquifers will move up the structure
i
;as the oil is produced from the reservoir. These ;
'natural energy sources initially have the effect of
maintaining enough primary reservoir pressure to drive ,
fl
ithe oil and/or gas through the reservoir and up the
IB iproducing wells without using artificial lift mechanisms
'These primary energy sources become increasingly less
I -effective over time, however, and the reservoir pressure
declines. The rate of pressure decline depends on the
~ .production rate as well as on many other factors that
f | vary from reservoir to reservoir. It can, in part, be ,
i
jarrested by injecting gas or water or both into the
j
!
ireservoir thereby prolonging "natural" flow.
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One consequence of producing fields with active natural^
water drives or of implementing large scale water injecj-
tion programs is that considerable volumes of water cans
i
be produced with the oil. This water, often high in
salt content, must be (1) reinjected into the producing;
i
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formation, (2) injected into another formation, or (3) }
i
disposed of in some manner which is environmentally andi
economically acceptable. !
C. OIL RECOVERY: PRIMARY, SECONDARY, AND TERTIARY i
PRODUCTION
The primary energy of "gas-cap-drive," "dissoIved-gas-
drive," and "water-drive" in the reservoirs themselves
is far from sufficient to recover all of the original
oil discovered in the reservoir. The extent to which
the original oil in the reservoir can be recovered
through primary production depends on the extent of
these primary energy sources as well as other factors.
Of the three primary energy sources, water-drives are
the most effective. Under highly favorable conditions,,
oil recoveries in water-driven reservoirs have reached
50% of the original oil in place. However, all
reservoirs are not connected to massive water drives,
and on average, only 15-25% of the original oil in
p..l_a_ce can .._be.._r_e..q_Qjyr.g..r_sd_ b..y using only primaryrreae rv.n.i,fc .
energy and artificial lift methods.
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Secondary recovery, i.e., water and/or gas injection,
typically yields another 15-20% of oil originally in
place. On average, the cumulative oil recovery after
primary and secondary methods is about 30-45% of the
original oil, thus leaving 55-70% in place.
While it is technically feasible to recover even more
of the oil remaining after primary and secondary
production, the costs of doing so rise considerably.
The average cost of a barrel of water used in secondary
:recovery injection is 4ฃ. The cost of an equivalent volume
of co used in tertiary recovery injection is
$2.50-$3.50/barrel--a per-barrel increase in cost of
|over 6,000%. Though less CO is used than water for
;any given project, the costs are still significantly
, higher.
As indicated earlier, the current contribution of
-tertiary recovery methods to enhanced oil recovery is
(extremely small. Its eventual contribution depends on \
improvements in technology and raw material availability
(chemicals) and on increases in oil prices that would
provide sufficient economic incentives for oil field
operators to undertake the risks involved.
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TYPE'.",
PAF'-i.J
RITER SETTING 10 PITCH
ELEMENT 1 73 0ซ COURIER '2 MODIFIED
SPACING- DOU3L5
MARGINS. V-, .NCHES 3CRDERS INDICATED'
JRAPH ENDING L-SS -, 1,1 1 ' 'MOT i. 1 - ' )
CHANGES: WHITE OUT OP USE CORRECT \'G TAPE*
LONG DASHES' USE 2 HYPhEMS 1
3ULLETS: USE A RED =ENCiL DOT ป 1
ADL SPELL OUT COMPANY NAME
EDITING- USE RED PENCIL ,
The potential contribution of tertiary recovery methods
to enhanced oil recovery is considerable, however. It
is estimated by some experts that an additional 20-30%
of the oil remaining in the reservoir after primary and
secondary production can be recovered through tertiary
methods.
D. INJECTION WELL POPULATIONS AND VOLUMES OF FLUID
INJECTED
At the request of Arthur D. Little, Inc., the EPA
Regional Offices distributed a survey to gather information
from officials of state oil and gas regulatory agencies
in June, 1977. The survey solicited, among other things
{injection well population data as of December 31, 1976.
Specific information was requested on the number of
"secondary recovery wells," "disposal wells," and pro-
ducing wells with "annular injection at an oil or gas
production well."
Based on the survey, there were an estimated 127,300
!
I
injection wells in active use at year-end, 1976. Of :
these, about 90,500 were secondary recovery wells,
25,400 were fluid disposal wells, and 11,400 were
producing wells with annular injection. (See Table III-2)
\ -> r* \ s 4 i *v ,1 o c o i
-* u c .N U iVi o t n . ;.
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TABLE 111-2
NUMBER OF OIL AND GAS RELATED INJECTION WELLS BY STATE
AS OF DECEMBER 31,1976
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
Utah
Florida
Colorado
Montana
Illinois
Michigan
North Dakota
Arkansas
Alabama
Ohio
Kentucky1
Nebraska
Indiana
Pennsylvania
West Virginia
New York
Tennessee
Arizona
South Dakota
Nevada
Missouri
Virginia
Totals
Salt Water
Disposal Wells
13,000
1,570
500
1,300
85
238
6
2,900
800
41
20
61
60
2,500
404
40
541
40
47
1,000
50
198
2
0
0
0
N.R.
2
0
0
0
25,405
Secondary
Recovery
Injection Wells
31,051
745
13,4002
8,700
2,620
3,255
87
10,800
200
326
41
552
757
5,000
333
312
446
71
43
7,000
250
1,500
2,251
190
400
0
N.R.
0
0
150
0
90,480
Producing Wells
with
Annular Injection
11,409
Total
3,000
153
10
0
0
2
0
35
30
0
1
2
0
3,000
115
0
10
1
5,000
0
0
50
0
0
0
0
N.R.
0
0
0
0
47,051
2,468
13,910
10,000
2,705
3,495
93
13,735
1,030
367
62
615
817
10,500
852
352
997
112
5,090
8,000
300
1,748
2,253
190
400
0
N.R.
2
0
150
0
127,294
N.R. - No Response.
1. Kentucky estimated only a single total of 8,000 injection wells. Based on the proportion of SWD and ER
injection wells in nearby Appalachian states, Arthur D. Little, Inc. estimates that approximately 1,000 are
salt water disposal and 7,000 are secondary recovery injection wells.
2. Includes approximately 10,000 cycle and continuous steam injection wells.
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., June 1977.
Arthur H I iff IP
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SPACING
MARGINS.
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10 PITCH
173 OR COURIER 12 MODIFIED
DOUBLE
i INCHES;3OR3=RS INDICATE
USE i 1,1 1 i NOT 1 ; 1 )
WHITE OUT OR USE CORRECTING '
USE 2 HYPHENS
USE A RED PENCIL DOT ป
SPELL OUT COMPANY ">;A\-F
USE RED PENCIL
'APE
In addition to injection well population data, the statje
agencies provided information on their respective 1976
total volumes of fluid injected at secondary recovery \
1 wells, disposal wells, and at producing wells with
annular injection.
Table III-3 presents the state-by-state estimates of
fluid volume as reported to Arthur D. Little, Inc. Of
the 19.9 billion barrels of water injected in 1976,
I
jll.3 billion barrels were injected at secondary recovery
iwells; 8.4 billion barrels at disposal wells; and 0.2
s
(billion barrels at producing wells with annular injection.
;Approximately 60% or 11.1 billion barrels of injected
i
I fluids were injected in only three states--Texas,
I
(California and Kansas.
jA summary of the individual state data on injection
\
jwell populations and total fluid volumes by type of
injection, activity is presented in Table III-4. Dis-
posal wells, which represent only 20% of all the injec-
tion wells, accounted for 42% of the total volume of
fluid injected in 1976. Secondary recovery wells, on
|the other hand, which represent 71% of all injection
i
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jwells, accounted for 57% of the volume of injected fluids.
PAGE NUMBER
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TABLE 111-3
VOLUME OF FLUIDS INJECTED AT OIL AND GAS RELATED INJECTION WELLS
(million barrels/year)
State
Texas
Louisiana
California
Oklahoma
Wyoming
New Mexico
Alaska
Kansas
Mississippi
Utah
Florida
Colorado
Montana
Illinois
Michigan
North Dakota
Arkansas
Alabama
Ohio
Kentucky1
Nebraska
Indiana
Pennsylvania
West Virginia
New York
Tennessee
Arizona
South Dakota
Nevada
Missouri
Virginia
Salt Water
Disposal
3,796
716
560
365
99
132
<1
1,241
254
28
22
29
25
730
117
0
162
18
2
39
3
58
<1
3
0
0
N.R.
<1
0
0
0
Secondary
Recovery
3,148
251
1,512
635
493
250
92
840
15
78
95
161
131
384
24
34
43
21
<1
91
36
1,095
1,825
2.0
29
0
N.R.
0
0
<1
0
Annular
Injection
<1
71
0
0
0
0
0
<1
1
0
<1
0
0
110
0
0
0
0
<1
0
0
2
0
<1
0
0
N.R.
0
0
0
0
Total
6,944
1,038
2,072
1,000
592
382
93
2,082
270
106
118
190
156
1,224
141
34
205
39
4
130
39
1,155
1,826
6
29
0
N.R.
<1
0
<1
0
Totals
N.R. No Response.
8,402
11,287
189
19,878
1. Kentucky's data reflecting total fluid volume were broken out by looking at known ratios of neighbor-
ing states.
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., June 1977.
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TAB LEI 11-4
U.S. INJECTION WELL
POPULATION AND INJECTION VOLUMES AS OF DECEMBER 31, 1976
Number of
Wells
90,480
25,405
1 1 ,409
127,294
Percent
71%
20
9
100%
Volume of
Fluid Injected
(MMbbls/yr)
11,287
8,402
189
19,878
Percent
57%
42
1
100%
Average
Volume of
Fluid Injected
Per Well
(Bbl/yr)
124,746
330,722
16,566
156,158
Type of Injection
Secondary Recovery
Fluid Disposal
Annular Injection
Total
Source: EPA Regional Office estimates as reported to Arthur D. Little, Inc., June 1977.
Arthi irDLittle.il
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AOL SPELL OUT COMPANY NAME
12'"":,'3 USE PSO 3 = >.C!L.
Produced water disposal wells, on the average, receive
jalmost three times as much fluid per well as secondary
recovery wells. Annular injection at producing wells
'accounted for only 1% of the total volume of injected 1
j j
!fluids.
E. REGULATORY ELEMENTS j
j
jThe activities of the oil and gas industry have long j
j
been, although not always, overseen by state regulatory!
i
j
agencies. Injection activity has not been exempted |
i
from regulatory guidelines and enforcement. Since the !
beginning of oil production in this country, several
I
factors have contributed to changes in state regulatory;
policy and industry practice.
Early practices with respect to well completions,
abandonment procedures, and surface discharge of produced
water were undoubtedly careless and are certainly not |
jcondoned today. The growing awareness of environmental)
deterioration caused by the discharge of produced wate:
into surface waters and open pits, the increasing
scarcity of subsurface water in some U.S. regions, and
the relationship of industry practice to the potential
'.detriment of these natural resources have all contributed
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USt2 HYPHENS -- j
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USE RED ?E\CiL
to the establishment of regulatory agencies and their
increasingly stringent 'policies.
It is widely believed that pollution problems arising to-
s I
day are largely attributable to early industry practice.
For example, the use of open pits--so called "evaporation
pits"--that were used for surface discharge of producedj
i i
isalt water have been known to create pollution problems}
j
30 years after a pit was covered. As the salt slowly
leaches through the ground, it contaminates underground
fresh water sources. The disposal of salt water, eitheir
i
into surface waters or disposal pits has largely been j
prohibited. Where there are exceptions to this, there {
i
is usually either no subsurface fresh water aquifer that
i
j
could possibly be contaminated; or the surface water
that the produced water is disposed into is a brine
lake; or the produced water is of high enough quality
that it can be used for agricultural uses such as
|
jirrigation or livestock watering.
The extent and nature of current state regulatory pro- ,
grams generally reflect each state's specific needs for
the protection of surface and underground water. By
and large, there are underground fresh water aquifers
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TTING 10 PITCH
MENT 173 OR COURIER 12 MODIFIED
OM: DOUBLE
^G.'.'S 1 'i INCHES :aGR3ERS INDICATED-
o.\o LSE :.!:,! {.JOT i. 1 A 1 j
CHANGES: WHITE OUT OR USE CORRECTING TAP
G DASHES. USE 2HVPHENS
BULLETS USE A RED PENCIL DOT ป
ADV.. SPELL OUT COMPANY NA.VE
c^iTiNG USE 3ED Pi=\C!L
I that are closer to the surface than the oil-producing
reservoir. In arid states, these fresh water aquifers
are virtually the only source for drinking water,
irrigation, livestock watering, and industrial use.
In the West and Southwest, there is insufficient rain-
fall to either replenish the underground fresh water
acquifer or provide alternative water supplies. In
i
I these areas, there is a critical need to protect the \
i
acquifers from degradation. In other states, however, j
I
ithere are, and continue to be, vast sources of fresh I
! i
jwater. Louisiana is a case in point. There is abundant
i j
rainfall and underground fresh water is available in many
parts of the state down to a depth of nearly 3000 feet.j
These vast sources of fresh water are in sharp contrast!
i
to the situation in those states where the Ogallala :
aquifer is the primary fresh water source and whose ;
overall thickness is in the 200-300 foot range. The
Ogallala aquifer is also slowly being drawn down by \
domestic, agricultural and industrial use due to the t
I
i
lack of adequate rainfall. j
Each state's climate, geology, surface, and underground!
water conditions have played an important role in the
establishment of individual state regulatory policies
covering oil and gas industry activity.
PAGE NUMBER
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Gouge on Injection tubing
Wellhead
Gauge on tubing-casing annulus
Fresh water zone (^$$
'ttw&^^
Confining layer
:':::::::&:::::::::::::::::::::j injection zone !&:&:':$
Surface casing
Annul us (positive pressure)
Cementing stage collar
Cement
Production casing
Injection tubing
Perforations
Confining layer
Source: Arthur D. Little, Inc.
FIGURE 111-2 INJECTION WELLS
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.NG 10 PITCH
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ING DOUBLE
.'-Ja 1 . INCHES (BORDERS i'i
CHANGES WHITE OUT OR USE CORRSCT^G TA?
G DASHES: USE 2 HYPHENS
BULLETS USE A RED PENCIL DOT
AOL: SPELL OUT COMPANY NAME
e^'Tc.'MG USE P50 PENCIL
F. SECONDARY RECOVERY INJECTION
1. Historical Perspective |
I
As discussed in Section B on Reservoir Characteristics,!
the primary energy in the reservoir diminishes over i
s
i
time as oil and/or gas are produced. The technology j
to mitigate the effect of this declining reservoir j
pressure has been around since the early 1900's and ;
became economically attractive and fairly widespread '
during the period of the mid-1950's to mid-1960's.
\
t
t
In the early stages of a reservoir's life, it is some- ;
times desirable to inject water or gas to maintain '
pressure. Initially, gas was often the preferred
injection fluid for the purpose of pressure maintenances
because it was readily available, and (prior to the
early 1970's) because of its low cost, its use as a
i
secondary recovery injection fluid also increased. ;
However, in the recent past, the increasing cost of !
gas has reduced its use both for pressure maintenance |
S
and for secondary recovery. i
:The difference between pressure maintenance and secondary
Recovery is more one of timing and intent rather than
^technique. Pressure maintenance projects typically i
PAGE NUMBER
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THIS SHEET TO BE USED FOR SCANNER COPY ONLY
TYฐEV.DI ".AT'
CHANGES-
LONG DASHES
BALLETS.
VOL.
WHITE OUT OR L-Sc CO"-
USE 2 HYPHENS
USE A RED PEViCit. DOT
SPELL OUT COMP&NY ',
USE RED PET-iCiL
inject gas early in the oil field's life to maintain
or retard the decline of the reservoir pressure. This
may be followed by water injection (while maintaining
)gas injection) to help further retard pressure decline
and to physically displace the oil toward producing
wells. The results of pressure maintenance and
secondary recovery efforts are reflected in the fact
that only 20% of U.S. crude oil production was achieved
t
through these methods in 1955, whereas today, it is oveir
!
! 50%.
The growth of secondary recovery projects as well as
their attendant contribution to enhanced oil recovery
will be considerably more modest in the future. Approxi-
mately 75% of all reservoirs are conducive to secondary!
recovery techniques (production of some reservoirs <
requires going from primary directly to tertiary methodls)
r
However, it is estimated that the vast majority of thesie
are currently under flood.
2. Secondary Recovery Injection Activity
In actual practice, it is difficult to distinguish
ibetween secondary recovery and pressure maintenance
'injection activities since secondary recovery is often
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DOUBLE
'' INCHES .3OPDEHS INDICATE:
US- '.111 { \O~ _ 1 : " }
CHANGES:
_QNG DASHES-
BULLETS.
&DL
WHITE OUT OR USE
USE 2 HYPHENS
USE A RED PENCIL DOT
SPELL OUT COMPANY \
USE StO PENCIL
RRECTING TAP
begun before oil recovery rates reach the lower limits
experienced when pressure maintenance alone is utilized;.
Secondary recovery, also referred to as waterflooding ,
involves the injection of water into the producing
i
formation or reservoir to force oil to flow toward the i
producing wells. Figure III-2 depicts a typical injectiion
well where the "injection zone" is the producing zone.
The water is injected under pressure which is sufficient
jto drive the oil through the reservoir but not so great;
i
jas to fracture the rock formation. Injected water,
I
jwhich has relatively efficient displacement characteristics,
can raise a reservoir's pressure quickly, typically in
six months to a year.
While waterflooding increases the amount of oil that isi
produced from a. reservoir, it also increases the amount!
of water that is produced. In some of the older !
jsecondary recovery areas, the percentage of produced
I i
jwater has increased to 70-80% of the total volume of j
'.water and oil produced. The oil produced from any
field becomes increasingly more "wet" as the secondary
recovery project proceeds. Depending on the total volume
.of produced water, the water is either reinjected into
'AGE NUMBER
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THIS SHEET TO BE USED FOR SCANNER COPY ONLY
10 PITCH
173 OR COURIER 12 ,ViOD!Ff=D
DOUBLE
r.j INCHES !BO"OERS ;,\Di"AT
USE i 1 l 1 ( -;OT _ : .. 1 }
CHANGES: WHITE OUT OR USE CORRECTING TAPE
LONG DASHES: USE 2 HYPHENS
5uL'_E~S USE A RED PEMCIL OGT *
OL. SPELL. Q'JT COMPANY NJ.VE
;3!T"'MC USE =>EO ?=,\C;L
reservoir and/or disposed of through disposal wells
into non-producing formations.
3. Injection Well Population
In 1976, Texas had over 31,000 secondary recovery
injection wells, over one-third of the U.S. total.
California had approximately 13,500 injection wells of
which about 9,000 were cyclic and continuous steam
wells. Kansas and Oklahoma had respectively 11,000
I and 9,000 secondary recovery injection wells. These
I
four states together had over 70% of the secondary
recovery wells in the U.S.
PAGE NUMBER
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'HIS SHEET TO 3ฃ USED FOR SCANNER COPY ONLY
ER SETT
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TliiS SHEET TO BE USED FOR SCAMMER COPY OiNILY
Is- ;H. PRODUCED WATER DISPOSAL ACTIVITY
] 1. Historical Perspective
i
'In secondary recovery projects, produced water is
generally reinjected into the reservoir. Sometimes
ithe volume of produced water may exceed that which is
I
s
{required for secondary recovery and disposal wells are
i
jused to dispose of unwanted produced water. In areas J
'where there is little or no secondary recovery activity,
iall produced water must be disposed of by injection j
;through disposal wells. In areas where there are massive
s
[water-drives, there is less need for secondary recovery*
".injection and a far greater need for disposal. This isf
/
i.
^particulary true along the Texas and Louisiana Gulf Coast,
\
\
i i
'While it is not a very widespread practice, some produced
water is disposed of by annular injection at producing
wells. In this type of situation, salt water is disposed
'of through the annulus between the long string and the
.tubing. The disposal zone is shallower than the pro-
I '
iducing zone in this case. The risks of contamination i
|
jare far greater with annular injection because of the
i
greater potential for casing failure. Because of this,,
'most state regulatory agencies discourage annular
injection and permit the practice only when there are
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10 PITCH CHANGES: WHITE OUT OR t_Sc CORRECTING TAP
173 OR COURIER 12 MOOTED '-0\G DASHES. USE 2 HYPHENS
DOUBLE 3UL-ET3 USE A RED PENCIL DOT ป
': NCHcS '3ORDSPS INDICATED! *3'~ SPELL OUT COMPANY \~Vฃ
j5E :. I .i 1 ( r,G~r : 1 \ 1 / --''"" v~ USE RED PENCIL
t very small volumes of water being injected under littls
1
or no pressure. In an effort to phase out this practice,
I many states revoke a well's permit for annular injection
1 i
j )
; when the well is shut in for a workover. This is !
i i
< i
especially true if there is inadequate or no cement j
above the injection/disposal zone. j
1 i
Because produced water is generally high in saline
J <
j content, produced water disposal wells are commonly i
I !
I referred to as salt water disposal wells. There are a I
i !
j few exceptions to this, where the produced water is of,
i !
| a higher quality and usable for some non-potable
| ;
{ purposes.
1 The disposal of salt water is an operating cost of pro-
1
! ducing oil that provides no economic returns (except to
; contract disposal operators) . One way of lowering the .'
i
i
| overall cost of salt water disposal is to select a
i
j disposal formation that will accept the water under
j
vacuum. The best disposal formations are generally ;
j pressure-depleted salt water aquifers or older producing
i
j reservoirs. When water can be injected under vacuum,
the operator does not have the added cost of pumping
1 that would be required if pressure were needed to inject
the water.
;MBER
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THIS SHEET TO BE USED FOR SCANNER COPY ONLY
TYPEWRITER SETT'NG
ฃL=V)f=,VT
1 73 OP COURIER 12 MODIFIED
DOUBLE
-2 ..NCHES iSQRCERS INDICATED)
CHANGES. VJHiTE OUT OR USE CORRECTING TAPE
LONG DASHES: USE 2 HYPHENS |
3ULL5TS. USE A RED PENCIL OOT J
AOL: SPELL OUT COMPANY N a IV! 5
= ~-iTp;G USE RED 3ENCIU
V
Disposal wells are often converted producing wells and
are most often operated by the leaseholder. If the
lease is large enough, and there are either no producing
i 1
; j
j wells that could be converted to disposal wells or no j
i i
suitable zones available, the leaseholder may contract
out the disposal of the lease's unwanted produced water
j
to a contract disposal operator. In this case, there i
I
are usually gathering lines that collect water from
tank batteries and pipe it to collection terminals ;
where it is chemically treated before disposal. Efforts
are made to construct the water gathering system such '.
that it operates by gravity rather than pressure flow,
thereby again reducing operating costs. ,
2. Salt Water Disposal Well Population
Based on state agencies data, there were approximately.
25,500 salt water disposal wells and 11,500 annular \
injection wells as of December, 1976. Texas had 13,000, swD well
or over 50%, of the U.S. SWD well total. (See Table ' ITT-2 . )
Kansas and Illinois had respectively 2,900 and 2,500
salt water disposal wells. Louisiana and Oklahoma
each had approximately 1,500 salt water disposal wells.'
These five states together accounted for almost 85% of
. .-._ -... _ _ __ - - --- -. -...;.__ !--.._.. .. ..... _. -. - "--.. ' -" ' ' ._ -.--_..-._...'
the total number of salt water disposal wells.
NUMBER
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VBITERSETTING
ELEMENT
SPACING-
10 PITCH
173 OR COURIER 12 WOO'PI ED
DOUBLE
1'j INCHES (BORDERS INDiCAT
CHANGES. WHITE DLP" OR USE CORRECTING TAP!
3NG DASHES.
3ULLETS
ADL
~~-!~!fiG
USE 2 HYMENS
USE A a = Q PENCIL ~Q
SPELL GO"*" ;OVVi'.Y
USE r=3 ฐE-;C!_
CHAPTER IV
DESIGN AND CONSTRUCTION OF INJECTION PROJECTS
A. INTRODUCTION
This and the following chapter on injection well opera-
tions are designed to provide the information base from
which the incremental cost of compliance will be esti-
mated. This information base is composed of a:
ป statement of current state regulatory requirements
> profile of current injection operations, and
5 summary of current industry practices.
In June 1977, two surveys were distributed by Arthur D.
I
Little, Inc. as a first attempt at developing
i
Ithis data base. The first, mailed under a cover letter
from the Interstate Oil Compact Commission (IOCC) , was
sent to the appropriate state agencies and requested
information on current state regulatory practices
governing oil and gas injection wells. Responses were
received from all 31 of the states. The second survey
was mailed directly by Arthur D. Little, Inc. to the
EPA Regional Offices and requested that each office
respond to questions, with the assistance of individual
AGc NUMBER
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THIS SHEET TO 3E USED FOR SCANNER COPY ONLY
;ซITER SET
NG 10 PITCH
ฃNT' 173 OR COURIER 12 MODIFIED
GA3. 1 'i INCHES :80RO;HS l
o:.-!G USE _ 1 il ; \.;r
CHANGES: WHITE OUT OR USE CORRECTING TAPE
_ONG DASHES. USE 2 HYPHENS
BULLETS USE A RED PENCIL DOT *
OL, SPSLL GOT COMPANY \AM~
="":'-',^G USE ?ED PENCIL
istate agencies, on the profile of current injection
operations in each state. Data were to include total
number of injection wells, construction profile, level
jof fresh water protected, and estimated number of pro-
ducing and abandoned wells within the, then half-mile,
radius of review. Wherever hard data were not availabl
best estimates were requested from knowledgeable source
within each state. Examples of these two questionnaire
are included in the Appendix.
j
i
'Following extensive analysis of the data supplied from
i
|the two questionnaires, EPA concurred with Arthur D.
Little, Inc. that additional information was needed on
i
current industry practices. Particularly needed was a
better determination of the extent to which existing in-
jdustry practices exceeded the regulatory requirements
1
Jin each state. To obtain these data, Arthur D. Little,
I ;
Inc. conducted in-depth field interviews with injection
well operators, oil field service companies, oil well
drilling contractors, and state regulatory agencies.
Interviews were conducted in October and November of
1978. Over 70 personal field calls were conducted in
all major oil producing regions of the country. Data
summarizing these field calls are included in Table IV-1 .
\ ^
GE NUMBER
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Percentage of SW
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cocj t-O -JO H5coO
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cu
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*-*
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3
o
00
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THIS SHEET TO 3E USED FOR SCANNER COPY ONLY
10 PITCH
173 GR COURIER !2
DOU3L5
CHANGES. WHITE OUT OR USE CORRECTING TAPS
-ONG DASHES. USc 2 HYPHENS
3U(_,_ET3' USE A RED PENCIL DC"r 9
ADL SPELL OUT COMPANY %i,\:E
ED,-V!G USE RED 3EMC;>_
The major oil producing areas in the continental United
States are shown in Figure IV-1.
Data in this and subsequent chapters are displayed,
i
wherever possible, by region in order to detail the i
isignificant differences in practices from one part of
i 1
{the country to another. It is primarily these differences
'which make the calculation of an "average" cost of com-s
Ipliance both difficult and meaningless. As shown in
this report, the older, more fully exploited oil fieldsi
!
in the country (such as those in the Illinois Basin and.
j
JAppalachia) have the highest potential cost of compliance
as well as the least economic resource to cover compliance
i
jcost.
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SB. EXISTING STATE REGULATORY REQUIREMENTS
I 1. Background - i
Regulation of underground injection operations followed!
the same basic guidelines set by regulation of oil pro--
duction. State supervision of oil production developed;
in response to questionable production practices which, in
some cases, damaged the value of rights of adjoining
PAGE i\U,MSeR
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cc
3
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IT
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TYPEWRITER SETTING-
EL
10 PITCH
173 OR CCLRiE
DOUBLE
r, INCHES so*
'A'HITE OUT OR L-SE CORRECTING
USE 2 -ivDHE;->S
-SE A ^EC PENCIL -C~ *
S'JE;.L. GUT COVP VIY }ฃ.:.=
landholders. Uncontrolled production sometimes
i
burdened the market with a glut of oil, thus depressing!
|
prices. State regulatory programs, usually administereja
}
by an oil and gas commission, brought a certain measures'
of stability to production operations by supervising
drilling practices and establishing production quotas, j
&
both to protect leaseholders and to limit production toj
(maximum sustainable yields.
As injection operations developed in association with
toil production, the state oil and gas agencies assumed
responsibility for regulating the new technologies. ini
eight producing states (Texas,
California, Alaska, Kansas, Pennsylvania, West Virginia!,
JNew York, and Maryland) responsibility for regulating
I
(underground injection operations is -also vested in the state
j
Jenvironmental or health agency. However, for the most
part, regulation of underground injection is clearly
the responsibility of the oil and gas agency.
t
2. Permitting
!
'Oil and gas agencies have extended the permit process
\
jused with exploration and production wells to underground
[injection. A permit for operation of an underground ;
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CHA,ซ,G33, ,'/H!T= OUT OR USE COFPECTiMG TAPE
3 -A3HE5. USE 2 HYPHENS
(injection well is required in all 31 oil producing
|
jstates. Through this permit mechanism, the states en-
force minimum standards for the design, planning, and
j
construction of injection wells. These state standards!
are summarized in this chapter. State standards for j
monitoring injection wells after they are in operation j
j
and a discussion of the state resources invested in the
permitting and surveillance of underground injection
'
operations are detailed in Chapter V.
'in most states, a permit must be issued prior to drilling
an injection well for secondary recovery or brine dis- !
posal. Most states require that the well be completed
(within a fixed period of time after the issuance of a
j
(permit to drill. The last column in Table IV-2 lists
j
the duration of the drilling permit. In Texas, for
example, the permit to drill is valid for 180 days whil.e
in Louisiana, the drilling must begin within 90 days of:
issuance, but the permit is then valid for the life of '
i
t
the well. i
jonce an injection well is completed within the conditions
(of a permit, a second permit for operation is issued
iand is generally valid for the life of the well. Ex-
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TABLE IV-2
EXPIRATION PERIODS FOR INJECTION WELL PERMITS
Permit to Operate
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
Enhanced Recovery
None
None1
None
None
None
None
25 Months
1 Year
None
N.R.
N.R.
None
None
1 Year
None
None
None
90 Days1
None
None
None
1 Year
N.R.
N.R.
N.R.
N.R.
None
90 Days1
None
None
None
Salt Water Disposal
None
None1
None
None
None
None
25 Months
1 Year
None
N.R.
N.R.
None
None
1 Year
None
None
None
90 Days1
None
None
None
1 Year
N.R.
N.R.
5 Years
N.R.
None
90 Days1
None
None
None
Permit to Drill
180 Days
None
1 Year
None
90 Days
90 Days
25 Months
None
6 Months
N.R.
180 Days
120 Days
90 Days
1 Year
1 Year
1 Year
90 Days
1 Year
180 Days
1 Year
180 Days
1 Year
1 Year-Shallow Wells
90 Days-Conservation Wells
120 Days
6 Months
90 Days
90 Days
90 Days
None
180 Days
None
N.R. - No Response.
1. Operations must commence within 90 Days; permit then valid for life of the well. One 90-Day extension
may be granted.
Source: Arthur D. Little, Inc./lnterstate Oil Compact Commission, Survey of State Agencies, July 1977.
Arthur D Little, Ii
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LONG DASHES. USE 2 -'YRNE^S
3U-LSTS uSE A = = C Pc.NCiL OOT *
'captions are Illinois, Indiana, and Kansas, which requiire
I
Ian annual renewal of injection permits.
I
|
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! 3. Requirements for Injection Well Operating Permits
I I
The following material on injection well permit requiref-
1 i
i |
ments reflects state requirements in effect at the time
of the Arthur D. Little, Inc./IOCC survey in June 1977.j
i
State requirements for well design and construction have
j
been increasing over time. Since the date of this survey,
some states (e.g., Kentucky) have proposed or promulgated
i
new regulations in anticipation of a federal underground
i
injection control program. Because of this evolution ;
in state requirements, it is important to note that: ;
The requirements cited here do not govern
all injection wells currently operating;
projects pre-dating the regulation in effect
in June 1977 may have been designed, con-
structed, and permitted under a lower set
of standards. In general, state programs ;
have "grandfathered" the design and con-
struction of existing injection wells when
the new regulations were adopted.
'-GEDUMBER
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10 -ITCH
173 GR COUR.ER 12 MODIFIED
DCU3L=
1 - INCHES ioORDEPS INDICATED')
' '" 1 ' ' : V.:>r ^ 1 A 1 )
CHANGES,
MC DASHES
BULLETS
WHITE OUT OR USE CORRECTING TAPE
USE 2 HYPHEMS
USE A RED PENCIL DOT <
SP3LL OUT COMPANY NAM =
J3H 3ED PENCIL
o State requirements for new wells will be
more stringent in some states as a result
of regulations enacted since July 1977.
a. Review of Nearby Wells
To provide an indication of the possible implications
of the proposed injection project, states require appli-
cants to review and provide data on the area where in-
jection will occur. This requirement, usually referred
Jto as the "area of review," varies from state to state.
(State regulations specifying the area of review are
jshown in Table IV-3. States usually require the appli-
icant to submit a plat showing nearby wells within a
I
(specified radius. This radius is shown in the left-
hand column of Table IV-3. While a radius of one-half '
jmile is most common, Kansas requires a review only to
the limit of the applicant's lease for enhanced recovery
injection wells while Florida requires an across-the-
board 1.5-mile radius of review.
The effort invested in developing information for a permit
application is determined by the type of information
'required as well as by the radius of the area of reviewi.
i
Table IV-3 summarizes the data which must be shown in
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THIS SHEET TO BE USED FOR SCANNER COPY ONLY
10 PITCH
173 OR COURIER 12 VIODIFIED
DOUBLE
1', INCHES i SOLDERS INDICATED!
CHANGES: WHITE OUT OR USE CORRECTING TAPE
;.NG DASHES. USE 2 HYPHENS
BULLETS' USE A RED PENCIL DOT *
AOL. SPELL GUT COMPANY NAME
SITING 'J3E R2O PENCIL
the required plats. There is no uniformity in state
requirements. The majority of states require the applij-
cant to locate all wells associated with hydrocarbon
production (including abandoned wells) within the area
of review and identify the owner. Not every state which
requires this information requires the applicant to list
the depth of the well shown, the age of the wells, or
any details on the construction, completion, or abandon;-
i
ment. Most states do not require the applicant to identify
J
*
iwater wells within the area of review.
Many parties, such as nearby landowners, adjoining ;
! j
jhydrocarbon producers, farmers or families whose wells I
! i
may be contaminated, and public water supply agencies ,
(drawing from an aquifer penetrated by an injection well!,
j ';
\
ihave an interest in the effect of the proposed injection
operations. To allow these parties to comment on pro-
posed injection projects, some states have incorporated!
a public hearing in the permit review process. Table IV-4
details current requirements in the oil producing states.
For states that allow an administrative review, a permit
[may be approved only by the appropriate agency staff.
jstates which require a hearing are designated in the
jtable. In many states, the director of the oil and gasi
^GE NUMBER
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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
TABLE IV-4
REVIEW PROCESS FOR PERMIT APPLICATON
Enhanced Recovery Wells
Admin. Review1
*
Admin. Review
Admin. Review
Hearing
Hearing
Admin. Review Following Hearing
Both
Both
Both
Both
Hearing
Either
Admin. Review & Site Visit
Either
Hearing
Hearing
Admin. Review1
*
Hearing
*
None
Hearing
Admin. Review
Both
#
Hearing
N.R.
Admin. Review
Either or Both
Salt Water Disposal Wells
Admin. Review
*
Admin. Review
Admin. Review
Hearing
Either
Admin. Review
Both
Both
Both
Both
Admin. Review
Either
Admin. Review & Site Visit
Either
Admin. Review
Hearing
Admin. Review1
*
Admin. Review2
*
None
Hearing
Admin. Review
Both
*
Hearing
N.R.
Admin. Review
Either or Both
1. Hearing held only if objections are received and deemed valid.
2. Hearing may be required in certain cases.
N.R. - No Response.
* Response to question unclear.
Source: Arthur D, Little, Inc./lnterstate Oil Compact Commission Survey of State Agencies, July 1977.
Arthur D Little, Inc.
-------
THIS SHEET TO BE USED FOR SCANNER COPY ONLY
10 PITCH
!73 OR COURIER 12 MODIFIED
DOUBLE
1'j INCHES (BORDERS INDICATED!
USE il 1 A 1 ( \ ~)T .1 " 1 )
CHANGES: WHITE OUT OR USE CORRECTING TAPE
.ONG DASHES. USE 2 HYPHENS
3ULLET3- USE A RED PENCIL DOT ป
ADL. SPELL OUT COMPANY \|A\5 =
SDi~V.G USE RED PENCIL
jagency has the option of convening a hearing if the j
application is controversial or if additional information
is required. In Ohio, for example, the applicant must
notify adjoining landholders of his application for an
injection permit. A public hearing may be called if an
objection is raised by one or more of the abutters.
b. Construction of New Injection Wells
Most states have specified certain minimum re-
}
quirements for the construction of newly permitted wells.
These construction requirements are summarized in
Table IV-5. Although most states require cemented surface
casing through the fresh water zone, the definition of
fresh water varies so significantly from state to state
that the level of fresh water currently protected by
existing state requirements is undeterminable. The
state definition of fresh water along with the attendant
!regulatory language is detailed in TabJ.e IV-6 . The facrt
jthat most states require cement at the injection zone
PAGE MUMBc,"
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