Qverview on Underground Storage
of Natural Gas
Donald L. Katz, SPE, U. of Michigan
M. Rasin Tek, SPE, U. of Michigan
Summary
Current Status
Underground storage of natural gas is a mature
industry vital to a gas delivery system. It developed as
a subdiscipline of gas technology with certain additions. This overview treats containment of gas
without migration, monitoring, inventory
verification, retention of well deliverability, practice
and advantages of delta pressure, aquifer behavior,
and compressed air storage.
The underground storage committee of the American
Gas Assn. (AGA) compiles annual statistics for the
industry. 6, 7 Fig. 1 shows the growth of the total
quantity of gas in storage reservoirs and the quantity
of working gas withdrawn in a given year. Table 1
gives AGA statistics on the reservoirs, facilities, and
magnitude of certain parameters. 6 Fig. 2 is the AGA
map showing the location of storage projects.
Although the annual volumes of gas distributed
currently are not increasing and may even decrease in
some areas as a result of conservation, the change
toward a larger fraction of the gas going to
spaceheating has a tendency to increase the need for
storage.
When the expensive synthesis gas from coal and
pipeline-accessible gas from Alaska and Mexico
arrive in the market, storage will become increasingly
important. In the case of synthetic natural gas
(SNG), storage will permit matching a variable
supply to the variable demand of the markets.
A brief history of the technical developments
during the past 40 years is given next. Early field
design procedures were adapted from natural gas
production technology. A series of studies conducted
during the 1950's resulted in (1) practices for more
efficient use of the storage reservoir, (2) assurance
that injected gas remained in the reservoir, and (3)
ways to handle new problems as they arose. Some of
our more recent activities are described in the
following sections.
Introduction
Underground storage is the process which effectively
balances a variable demand market with a nearly
constant supply of energy provided by the pipeline
system. Storage reservoirs are the warehouses to give
a ready supply of gas that can serve a market with
high peak demands in cold weather. The natural gas
simply is injected into underground storage reservoirs when market demand falls below the supply
available from the pipeline. It is withdrawn from the
storage environment to supplement the steady supply
from the pipeline when the demand exceeds the
supply. Through the years, underground storage has
become a mature industry.
For northern climates, storage gas represents
about 20070 of the annual sales - on a cold day,
storage gas may reach 50 to 70% of gas sold. With a
superb record of providing continuous fuel service to
residences, hospitals, and commercial buildings,
underground gas storage has been a vital part of
natural gas distribution systems.
Historically, underground storage (which was
practiced first in 1915) experienced a remarkable
growth starting in 1950, resulting in nearly 7.5 Tcf
(212 x 10 9 m 3 ) of storage in more than 399 pools in
26 states by 1979. Some gas storage literature covering developments over the years are listed in Refs. 1
through 12.
0149·2136/81/0006·9390$00.25
Copyright 1981 Society of Petroleum Engineers of AIME
JUNE 1981
Development of Underground Storage
Historical records show that gas storage began by
allowing depleted gas reservoirs produced in the
winter to be recharged in summer by pipeline gas. As
the intercontinental pipeline systems spread rapidly
in the postwar period, reservoirs were selected and
refurbished for full use as underground storage
reservoirs. 1,2 Typically, a depleted gas field was
943
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YEARS
Fig. 1 - Growth in annual gas storage capacity and gas
usage, AGA data. 6
Fig. 2 - Map locating underground storage projects, AGA. 6
acquired, and the mineral and storage rights were
obtained. Old wells were inspected and upgraded,
plugged wells were investigated, and a development
plan was prepared. Then a number of new wells were
drilled, and a gathering/injection pipeline system was
installed. Usually a compression station was constructed to boost the gas received at pipeline
pressures to field pressures. When withdrawal began,
some reservoirs also would require gas compression
to deliver gas at pipeline pressure when meeting their
late-season market sendout commitments.
Eventually a number of depleted oil fields were
converted to gas storage. Oil recovery was part of the
objective in the early years of operation. 2 Oil in
reservoirs, however, added complications over dry
gas storage fields as a result of liquids in the
well bore, possible enrichment of the gas, and condensate formation in pipelines. Also, gas sometimes
went into solution in crude oil in amounts that made
it difficult to assess the volume of stored gas in the
reservoir.
In the 1950's, aquifer storage was developed by
injecting gas into structures filled with water. Here
water movement and caprock quality became focal
points for research and technical development. 2
Since the advent of aquifer storage, limited amounts
of natural gas have been stored in salt cavities.
Objectives of Engineering
and Design Efforts
There are three primary objectives in designing and
operating storage reservoirs as depicted in Fig. 3.
The first objective is to know the storage capacity
for gas as a function of pressure and, in some cases,
time. This is called verification of inventory. How
much gas will the reservoir hold at the maximum
storage pressure and how much could be produced
when withdrawing gas down to some base pressure?
The quantities, if time dependent, are needed for an
annual storage cycle typically divided into 120 days
for gas withdrawal and + 200 days for gas injection.
Second, a monitoring system is needed to verify
where the gas resides and ensure that losses are not
occurring. This is called retention against migration.
Continuous reservoir pressures observed by key wells
give the reservoir pressure under operating conditions, and closed pressures on all wells in fall
and/ or spring seasons permit volumetric inventory
calculations. A system of observation wells permits
measurements to verify that injected gas is confined
to the designated area and has not migrated away.
The third objective is the ability to develop and
maintain a specified gas delivery rate. This is called
assurance of deliverability. Generally, it is keyed to
TABLE 1 -1979 AGA STATISTICS ON UNDERGROUND GAS STORAGE6
Total capacity, Tcf (m 3 )
Maximum day output, Bcf (m 3 )
Seasonal gas withdrawn, Tcf (m 3 )
Number of storage reservoirs, 26 states
Companies in U.S.
Companies in Canada
Storage compressor stations, hp
Range of storage reservoir pressures, psi (MPa)
Aquifers account for 22% of storage capacity
Aquifers account for 15% of maximum day output
944
7.437 (211 x 109 )
39.7(1.1x109 )
2.057 (58 x 109 )
399
78
5
1,805,000
300 to 4,000 (2.07 to 27.6)
JOURNAL OF PETROLEUM TECHNOLOGY
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the pressure in the reservoir or to inventory. Wells
may lose their deliverability as a result of water
interference or contamination of the sandface.
A series of concepts and procedures have evolved
in gas storage from the background of natural gas
production technology. These are used to illustrate
current engineering practices.
r-- j - -
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PRESSURE. psio
Fig. 4 - Delta pressure in use in gas storage, 1970. 5
Use of Delta Pressures*
Natural gas reservoirs generally are found at
discovery pressure gradients of 0.2 to 0.52 psi/ft (4.5
to 11.8 kPa/m), while the pressure gradient due to
weight of overburden is about 1 psi/ft (22.6 kPa/m).
In several areas, the practice of using a top pressure
above discovery was established for depleted gas
reservoirs converted to storage. Aquifer storage
reservoirs require gas injection at pressures above the
initial value to displace the water when creating the
gas reservoir. In Illinois and Iowa, the delta pressure
above discovery pressure ranges from a small valuee.g., 25 psi (172 kPa) - to about 300 to 400 psi (2069
to 2758 kPa).
In a study of caprocks, Ref. 5 presented the range
of delta pressures used in gas storage reservoirs at
that time (Fig. 4). The larger working gas content and
higher delivery rates obtained because of the high
pressure levels give a dual advantage with only a
moderate increase in risk of gas loss through imperfect well casings or cement. Since the time Fig. 4
was prepared, delta pressures up to 0.75 psilft (17
kPa/m) and actual delta pressure increases to 900 psi
(6.3 MPa) have been used.
142
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Design Concepts
0
o
5
10
15
BcI GAS CONTENT OR PRODUCTION
To illustrate the effects of a high delta pressure,
information set forth in planning the Chester 15
reservoir in Michigan is plotted as p/z vs. content.
Fig. 5 uses production-pressure data and compressibility factors for 0.68 gravity gas at the
reservoir temperature 113 F (318 K). 13 The initial
0
Fig. 5 - Pressurelz vs. gas content at Chester 15 reservoir.
0
·Del1a pressure is defined as maximum storage minus discovery pressure.
JUNE 1981
945
gas content is found at 16.7 Bef (473 X 106 m 3 )
assuming a constant volume reservoir. Using 600 psia
(4.1 MPa) as the pi z value for base condition at the
end of storage [560 psi (3.86 MPa)], the working
storage content with discovery rressure as top
pressure becomes 14.0 Bef (396 x 10 m 3 ).
The reservoir pressure of 3,108 psia (21.4 MPa) at
6,130 ft (1868 m) results in 0.51 psilft (11.5
kPa/m) - a saltwater gradient. Using a 0.7 psilft
(15.8 kPa/m) pressure gradient, the top pressure
would become 4,291 psia (29.6 MPa) and the delta
pressure would be 1,183 psi (8.2 MPa). Fig. 5 shows
how extension of the plz curve increases the gas
content by 3.9 Bef (110 X 106 m 3 ). Thus, the working
storage is increased from 14.0 to 17.9 Bef (396 x 10
to 507 X 106 m 3 ) per cycle. This is a 28070 increase in
working storage. The addition of one well is all that
is required to obtain this added storage capacity
when using delta pressure.
Development of Aquifer Storage Reservoirs
-200S.L
STORAGE RfSERVOIR STRUCTURE
Fig. 6 - Generalized structure map and section for a
developing aquifer gas storage reservoir.14
GAS BuBBLE
'.
'.
INITIAL AQUIFER PRESSURE Po
BuBBLE
1
leo
I11111111111111111111
Degree of Compression of Water
II
DISTANCE ----.
Fig. 7 - Effect of time on pressure distribution in aquifers. 2
Aquifer storage now constitutes about 22070 of the
total gas storage capacity. Blanket water-bearing
sands with anticlinal structure are prospective sites.
Exploratory wells locate the detailed structure and
yield cores for evaluation of porosity, permeability,
and capillary pressure of the prospective storage
zone. Caprock cores are used for similar
measurements and threshold pressure for displacing
water by gas. 2,5
To ensure that no anomalies exist in the caprock
integrity, water-pump tests are conducted to create a
pressure differential across the caprock. Absence of
direct fluid communication is ascertained from water
levels observed in wells completed across the
caprock. 2 ,4 Fig. 6 is a generalized plan and section of
an aquifer with well locations and completions. In
the pump test observation, Well 4 would be used to
observe water levels with pumping injection well
nearby. 14
The time to develop the desired gas-bubble size is
difficult to predict. Fig. 7 illustrates the variation in
pressure gradients in the water as injected gas
compresses the water surrounding it.
The rrocedures developed by Van Everdingen and
Hurst 1 have been extended and applied to water
movement when developing and operating aquifer
storage reservoirs. 3 One of the difficulties in such
relationships is predicting the effective compressibility of the aquifer system. Another concern is
handling the long-time effects for storage reservoirs
after many years of operation.
Pound x Day Concept
A simplified concept called the pound-day concept is
helpful for analysis of repetitive cycles. It involves
using the product of time and the driving force
pressure difference in a cumulative manner for the
periods above and below the initial pressure. For
repetitive storage cycles at constant size of gas
bubble, the sum of pounds force x days above initial
pressure should equal the sum of pounds force x days
below; Fig. 8 illustrates this concept. 2
946
JOURNAL OF PETROLEUM TECHNOLOGY
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TIME
1
I
BASE: WORKING INVENTORY OF GAS
GAS
Fig. 8 - Pound x day concept. 2
Fig. 9 - Pressure cycles on tight storage reservoirs.
For aquifers or converted gas fields with water
drive, a problem may arise when there is not sufficient closure along the caprock. It is well known
that some of the injected inventory proceeds away
from the main bubble, sometimes for large distances
downstructure. 2 Without satisfactory withdrawal
wells to produce gas from thin gas zones, the gas does
not depressurize during the withdrawal cycle. If it
remains at pressures above the original aquifer, it
will continue to press on the water and grow in size.
At some point it may become out of control and pass
a saddle to separate from the main gas body.
Even in tight dry reservoirs, gas can be pushed
farther in 200 days of injection than the distance it
returns in 100 days of withdrawal. It is important to
have all stored gas in responsive communication with
withdrawal wells.
Well 5 monitors the pressure of a shallow water
zone by any stray gas which could migrate through
imperfectly cemented well columns.
These wells, plus careful plans for observing the
entire area, provide the data needed to ascertain that
injected gas is confined.
It has been found that gas may penetrate a deeper
aquifer zone that has a higher permeability then
layers close to the top of the reservoir. Neutron logs
detect any gas accumulation in sands. A survey of a
cased hole below the top layers occasionally finds
such gas in collector zones.
Monitoring Storage Reservoir Aquifers
A generalized aquifer reservoir is used to present
monitoring procedures. 14•16 The possible losses of
gas from the connected gas body through wells or
other means are (1) through imperfect cementing at
casing shoe or opposite any leak in casing joints or
cementing tool, (2) gas displacing water through a
saddle and separating from the gas bubble, and (3)
for aquifers, gas loss vertically through imperfections
in caprock or due to low local threshold pressure
areas.
Referring to Fig. 6, it can be seen that observation
wells are drilled both to locate the structure and to
permit monitoring the location of the gas bubble as it
grows in size.
Wells 2 normally are in water surrounding the gas
bubble; their pressure changes indicate any approach
of the gas phase toward them. Well 3 is such a
monitoring well at the spill point - the highest area
where gas could move laterally by pushing on the
water.
JUNE 1981
Inventory Verification
Each year those responsible for operations must
assure management that the inventory of net stored
gas resides in the reservoir in communication with the
wellbores. Closed-pressure measurements for a
period of 3 to 15 days or more are used for all wells,
normally when at maximum and minimum storage
pressures. For constant pore volume reservoirs for
which the closed pressures are relatively uniform and
stabilized, the use of the pressure-content data relates
the metered production or change in inventory to the
initial content:
change in content PI
Initial content =
-----------
..... (1)
When water movement rates are known to occur
during withdrawal, the volume change of the
reservoir must be used to modify the relationship
accordingly.
For some reservoirs, the key well pressure trace vs.
inventory is used to find whether any change has
occurred from previous years. Pressure content trace
947
G/ W for water
displacement
problem
top of reefs
Fig. 10 - Adjacent reefs connected by water-filled low
permeability dolometic.
is related to the pore volume occupied by the gas. If
the gas bubble is growing in size, the slope becomes
progressively less steep. On the other hand, any
premature readings in pressure surveys before proper
equalization tend to result in a steeper slope in
pressure content lines. Sometimes use of more than
one key well is indicated for proper tracing of inventory pressure relationship. Loss of a finite
amount of storage gas usually results in the plz vs.
inventory line remaining parallel but shifting to the
right on pressure inventory scale.
Accordingly, when water movement occurs and
when operating at positive (pounds x days) pressure
levels, such pressure trace loops move toward higher
inventories with growth of bubble size. Fig. 9
illustrates the behavior of verification of inventory
by repetitive cycles.
When no positive verification that injected gas still
resides in the reservoir can be made by pressure
change calculations, one must resort to a technique
called "watching the barn doors." By observing that
no gas is being lost in likely avenues of escape, one
can be reasonably assured that net injected gas is still
in the reservoir. 14
Occasionally, simulation of production-pressure
behavior of a storage reservoir on a computer is
helpful in inventory verification. Such simulation
techniques start with history match procedures to
obtain proper kh and ¢h distributions before relating
the operating pressures to programmed inventories.
Efforts have been made to establish procedures for
charging off "gas lost and unaccounted for" that
leaves the system through various mechanisms.
Fugitive gas is a popular term for seepage losses at
screw joints, valve stems? and through valves closed
against the atmosphere. 1
A special problem worthy of separate consideration is gas that breaks through water seals
because 0 f nearby pressure sinks. 17
Gas Flow Between Reservoirs
Given two reservoirs, A and B, located in the same
horizon and separated by a water filled saddle (Fig.
10), unequal pressures between the reservoirs can
cause gas in the higher pressured reservoir to displace
the water seal. The process results in gas being
948
transferred from one reservoir to the other - A to B.
Accordingly, selection of a reservoir for storage must
include a survey of the nearby area. If two adjacent
native gas reservoirs are produced with a significant
pressure gradient between them, the lower-pressured
reservoir may have produced some gas originally
present in the other reservoir. Under these circumstances, use of native gas production to evaluate
the storage capacity of either reservoir would result
in error.
A simple relationship has been derived for computing the approximate time for water to displace gas
from the water seal separating reservoirs. It neglects
elevation difference and assumes that gas flows
behind the advancing gas water interface with an
estimated constant gas saturation and effective
permeability in plug-flow fashion.
Constant 79 becomes 5 x 1011 in SI units.
By using typical values for all variables except I, L,
kw' andpi -P2'
Using J-tw =0.80 cp, ¢=0.2, Sg =0.5, J-tglJ-tw =0.01,
and k w I kg = 2, one finds (in field units)
1=6.45 L2/k w (PI -P2)·
Reservoirs separated by 5,000 ft (1524 m) with
permeablity of kw = 1,200 md and a pressure difference of 500 psi (3.45 MPa) are shown to displace
the seal in 269 days. For shorter distances, higher
permeability, or higher pressure differential, time for
displacement can be as low as 4 months. Depleted oil
wells in the basal layer adjacent to reefs occasionally
have received gas. Gas has been shown to transfer
during primary production through a distance of
8,000 ft (2438 m) and in opposite direction during
storage with a reversal of pressure gradient. Should
the saddle be as much as 200 ft (61 m) deep, this only
reduces the effective pressure gradient necessary for
displacement up to 100 psi (689 kPa).
Gas Flow Rate
Once gas has broken through a seal between reservoirs, there is interest in finding the expected range of
flow rates. The linear flow formula for the geometry
of Fig. 10 becomes
k hw
qg = 1.12x 10- 7 ~ (PI 2 -P2 2 ) MMcflD.
LJ-tgzT
............................... (3)
In SI units, the constant is 1.42 x 10 - 15 to give
3
m /s. On the example, using PI = 1,500 psia,
P2 = 1,~00 psia, kg = 100 md, J-tg =0.0135 cp,
T=540 R, L=5,000 ft, hW= 1,000 sq ft, and z (for'
0.6 gravity gas) =0.83, Eq. 3 is solved to give 0.463
MMcflD (0.152 m 3 Is).
JOURNAL OF PETROLEUM TECHNOLOGY
Flow rates between reservoirs separated one mile
(1.6 km) or more have reached 50 MMcflD (16.4
m3/s) with high pressure differentials. Usually rates
of less than 1 MMcflD (0.327 m3/s) are found after
breakthroughs.
- - - - . . , . . - - - .- I- -
Flow tests on individual wells are obtained as in gas
production operations. From gas inventory and/or
reservoir pressure measurements plus deliverability
data, one can predict the field flow at several stages
of the storage cycle. 1,2
Performance of storage reservoirs becomes less
predictable during high withdrawal rates due to
pressure sinks which develop as a result of
heterogeneities.
Another problem of continuing interest relates to
interference by water reaching the well bore. The
presence of water not only reduces the permeability
to gas but also effectively cuts down the bottomhole
pressure drawdown available for gas flow due to
increased density of well fluid. For aquifers, water
interference problems are likely to subside as the gas
bubble thickens with growth in stored gas. Each
reservoir and set of wells must be tested to give
assurance for future years with regard to which well
will have water intrusion at a given stage of the
withdrawal cycle. Deliverability of storage wells after
20, 30, or 40 years of repetitive use decreases as a
result of sandface contamination.
The deliverability of wells in Michigan Stray sand
reservoirs has declined 4.5070 per year due to fines,
salt precipitation, shale sloughing, and oil residues.
Earlier attempts to treat wells removed salt readily
but gave only a slight increase in deliverability.
Recent techniques generally have been successfulincreasing deliverability by as much as 426070. 18 This
was achieved by alternately injecting volumes of (1)
xylene, (2) 3070 HF / 4070 HCI, and (3) 2070 NH4 Cl.
Virtually all the wells that were stimulated maintained the increase in deliverability the following.
year.
48
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Porosity,fra<tion
Fig. 11 - Residual gas
(Gorring).19
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Recoverability of Base Gas
JUNE 1981
o.
12.
~\
In handling financial matters, the subject of recovery
of base gas arises. It is of particular interest not only
for tax write-offs but' for abandonment considerations as well. The total gas content minus the
base gas is considered working gas generally expected
to be available for annual withdrawal.
Permeable, fixed volume reservoirs with little or
no perceptible water movement should produce gas
to a pressure as low as compression costs permit.
However, with use in distribution systems an
economic limit such as 25 to 100 psi (172 to 670 kPa)
would be prudent.
The problems related to recovery occur when water
drive is substantial, with advancing water sealing off
residual gas at its prevailing pressure. This suggests
that for maximum recovery the gas must be produced
as rapidly as possible ahead of the invading water
front. The residual gas left behind the' advancing
water front is the parameter one would like to have to
"g. : - - - : - - , - - - - - - - ,
50
Deliverability of Gas
,\'
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·Storage
Zone
V
TEMPERATURE
Fig. 12 - Temperature and pressure gradients in gas
wells. 20
949
NIGHTTIME BASE
LOAO POWER TO
-,
DRIVE COMPRESSOR
AIR INTAKE
I
I
DAYTIME POWER
- - FROM TURBINE FOR
PEAK LOAD DEMANDS
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COMPRESSOR
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FLOW
REGULATION
PIPELINE
VALVE
TOI FROM STORAGE
REGENERATOR
VENT OF
COMBUSTION
GASES
PRESSURE
LOSSES
GAS FLOWING
IN
WELL BORE
P,.
AIR
STORAGE IN
POROUS MEDIA
OR IN CAVITY
Storage in Salt Cavities
UNSTEADY STATE
WATER MOVEMENT
~/~
~CONFINING
WATER
Fig. 13 - Compressed air cycle for electric power load
leveling. 25
make reliable estimates on the recovery of base gas.
Katz and Coates 2 presented a systematic approach
for implementing this procedure. Gorring's chart 2,19
gives residual gas saturation as a function of porosity
(Fig. 11).
Temperature and Pressure Gradients
in Gas Storage Wells
Underground storage operations invariably include
gas injection. The temperatures in the well during
injection are different than during production. Fig.
12 shows typical depth/temperature curves including
dynamic and short-time closed temperatures. 20 As
injected gas not heated fully in the well bore enters the
porous storage rock, this solid body cools rapidly
because of the intimate contact. At the end of a
storage cycle, a cylinder of cooled storage zone of 50
to 100 ft (15 to 30 m) in radius may exist around the
well. Upon close-in, the wellbore heats to geothermal
gradient relatively quickly, but the storage zone
remains at subgeothermal temperatures until
significant withdrawal has occurred. For reservoirs at
150°F (65°C), cooling may occur as much as 40°F
(22 °C) or so from that indicated by geothermal
gradient.
Subsequently, during the initial withdrawal period
the gas leaves the storage zone at temperatures lower
than geothermal. In due time, however, the flowing
gas at the well bore reaches a temperature closer to
geothermal equilibrium depending on thermal
properties, flow rates, and well geometry.
950
The alternate cooling and heating of the casing
surrounded by cement through the cap rock is
believed to cause occasional deleterious effects on the
cement bond. Apparently a small annular gap
permits dry gas during high-pressure injection
conditions to dehydrate the cement. Eventually,
significant gas movement past the casing shoe may
indicate the need for recementing. Temperature and
noise logs are the tools used in diagnosing such
conditions.
The pressure gradients on Fig. 12 illustrate studies
intended to minimize fuel use to heat gas at the
wellhead before expansion to pipeline levels. Well E
(using a tubing for flow) or Well D (a bottomhole
choke) are alternative operations.
The treatment of temperature and pressure
gradients in underground storage is included in Refs.
21,22, and 23.
Storage of liquified petroleum gases (LPG's) in salt
cavities grew rapidly in the 1950's.24,11 By washing
out a cavity with water, the shape and size of the
cavity is controlled. Normally LPG's are produced
by a head of brine used for displacement.
Around 1960, Southeastern Michigan Gas Co.
initiated natural gas storage in a salt cavern at 2,100
ft (640 m) near Marysville, MI. The brine was
removed and the gas pressure was varied, in contrast
to LPG storage practice. Other gas storage projects
in salt have been developed including the Transco salt
dome storage caverns. 1 Many other fluids including
ethylene, ammonia, calcium chloride solutions, and
crude oil are stored in caverns also.
Absence of Connate Water
in Michigan Reefs
An interesting phenomenon was observed in
southeastern Michigan reefs: stored natural gas did
not become saturated with water during storage. 26
Gas produced after about 60 to 70070 of the reservoir
contents were withdrawn has water content of some 3
Ibm of water/MMcf (48 kg/10 6m 3 ). One explanation was that anhydrite (CaS04) in reef rock
absorbed the connate water in a gypsification process
(CaS04 ·2H 20). An alternative explanation is that
fresh water vaporized and recondensed in dense brine
in the base rock after gas accumulation.
Compressed Air Storage
Electric power systems have a daily peak load with
some variations from a weekly cycle. Their daily
ratio of peak to low load matches that of the annual
gas peak/low load ratio for moderate climates. One
way to use base load power to assist in producing
peaking power with combustion turbines is to
compress the air at ni~ht and store it in an underground reservoir. 11,2 During the day, the air is
withdrawn under pressure and used to burn jet fuel
which powers a generator during peak demand. The
economics and technology are being examined by'
industry and U.S. DOE-EPRI sponsored projects.
One consideration is to store hot air to increase the
JOURNAL OF PETROLEUM TECHNOLOGY
efficiency of the process. Fig. 13 illustrates the
compression storage/power generation system
contemplated using the same types of reservoirs as in
gas storage.
Summary
Gas storage has become a necessary and vital part of
the gas delivery system to the ultimate user. It permits a steady supply of gas to serve a widely fluctuating demand. Much of the technology used is
similar to that used in natural gas production. Some
significant developments, however - especially in
aquifer storage - have raised gas storage technology
to the status of a special subdiscipline.
Nomenclature
h
Kg
Kw
L
P
=
qs
Sw
t
T
W
z
i-tg
i-tw
cf>
=
=
thickness, ft (m)
permeability to gas, md
permeability to water, md
length, ft (m)
pressure, psia (Pa)
gas flow rate, MMcflD at 14.7 psia and 60°F
(m 3 /s at 101 kPa and 15.6°C)
gas saturation, fraction
time, days
temperature, of rC)
width, ft (m)
compressibility factor for gas, dimensionless
viscosity of gas, cp (Pa· s)
viscosity of water, cp (Pa· s)
porosity, fraction
Subscripts
1
first condition
2
second condition
g = gas
w = water
initial
References
1. Katz, D.L., et al.: Handbook of Natural Gas Engineering,
McGraw-Hill Book Co. Inc., New York City (1959) 802.
2. Katz, D.L. and Coats, K.H.: Underground Storage of Fluids,
Ulrich's Books Inc., Ann Arbor, MI (1968) 575.
3. Katz, D.L., et al.: Movement of Underground Water in
Contact with Natural Gas, AGA Monograph on Project No.
31, Arlington, VA (1963).
4. Witherspoon, P.A., Javandel, I., Neuman, S.P., and Freeze,
R.A.: Interpretation of Aquifer Gas Storage Conditions from
Water Pumping Tests, AGA Monograph NS 38, Arlington,
VA (\967).
5. Ibrahim, M.A., Tek, M.R., and Katz, D.L.: Threshold
Pressure in Gas Storage, AGA Monograph, Arlington, VA
(1970).
6. AGA committee on underground storage, Task Group on
Statistics, 29th Annual Report on Statistics, XU0578,
Arlington, VA (1979).
JUNE 1981
7. AGA Committee on Underground Storage, Survey of Underground Gas Storage Facilities in U.S. and Canada, Catalog
No. XU0678.
8. Tek, M.R. and Wilkes, 1.0.: New Concepts in Underground
Storage of Natural Gas, AGA Monograph LOO400, Arlington,
VA (1966).
9. Hardy, H.R.: A Study to Evaluate the Stability of Underground Gas Storage Reservoirs, AGA Monograph Ll9724,
Arlington, VA (1972).
10. Bergman, D.F., Tek, M.R., and Katz, D.L.: Retrograde
Condensation in Natural Gas Pipelines, AGA Monograph
L22277, Arlington, VA (1975).
11. Katz, D.L., and Lady, E.R.: Compressed Air Storage,
Ulrich's Books Inc., Ann Arbor, MI (1976) 244.
12. Gas Technology, Reprint Series, SPE, Dallas (1977) 2, 31.
13. Exhibit H to FERC, Michigan Wisconsin Pipeline Co. (docket
CP-74-316).
14. Katz, D.L.: "Making Good Use of Observation Wells, Proc.,
AGA Transmission Conf., St. Louis (1977) T-251.
15. van Everdingen, A.F., and Hurst, W.: "The Application of
LaPlace Transformation to Flow Problems," Trans., AIME,
186,305.
16. Gas Technology, Reprint Series, SPE, Dallas (1977) 2, 419.
17. Katz, D.L.: "Containment of Gas in Storage Fields," Proc.,
AGA Transmission Conf., New Orleans (1978) T-403.
18. Fogler, H.S., and Crain, E.R.: "Stimulation orGas Storage
Fields to Recover Deliverability," Proc., AGA Transmission
Conf. (1979).
19. Katz, D.L., et al.: "How Water Displaces Gas from Porous
Media," Oil and Gas 1. (1966) 64,55.
20. Gas Technology, Reprint Series, SPE, Dallas (1977).
21. Horne, R.N. and Shinohara, K.: "Wellbore Heat Loss in
Production and InjectionWells," 1. Pet. Tech. (Jan. 1979)
119.
22. Chierici, G.L., Sclocchi, G., and Terzi, L.: "Pressure,
Temperature Profiles and Calculations for Gas Flow," Oil
and Gas 1. (1980) 78, 65.
23. Tek, M.R.: "Design of Storage Fields," Proc., AGA
Transmission Conf., Salt Lake City (1980) T-422.
24. Katz, D.L.: "Outlook for Underground Storage," Northern
Ohio Geological Soc. Fourth Symposium on Salt (1974) 253.
25. Katz, D.L., and Lady, E.R.: "Underground Compressed Air
Storage For Electric Load Leveling," 1. Pet. Tech. (Nov.
1978) 1656.
26. Katz, D.L., and Lundy, C.L.: "Analysis of the Absence of
Connate Water in Michigan Reef Gas Reservoirs," paper
presented at AAPG Regional Meeting, Evansville, IN, Oct. 14,1980.
SI Metric Conversion Factors
E-03
cp x 1*
E-OI
ft x 3.048*
lbf x 4.448 222 E+OO
mile x 1.609 344* E+OO
psia x 6.894 757 E+OO
OR x 5/9
sq ft x 9.290 304* E-02
"Conversion factor is exact.
Pa·s
m
N
=
km
kPa
K
m2
JPT
Original manuscript received in Society of Petroleum Engineers office July
16, 1980. Paper accepted for publication Feb. 19, 1981. ReVised manuscript
received April 9, 1981. Paper (SPE 9390) first presented at the SPE 55th Annual
Technical Conference and Exhibition, held in Dallas, Sept. 21·24, 1980.
951
