Gas Storage in Aquifers and Salt Caverns

7/27/2019 Gas Storage in Aquifers and Salt Caverns

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Aquifer and Salt caverns


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Storage in Depleted Oil Reservoirs

Most natural gas-storage projects make use of gas reservoirs.This practice is usually desirable when gas reservoirs can befound at all desired location. When none is available, othertypes of reservoirs are used.

The practice of using depleted oil reservoirs for gas storage isbecoming popular because of added motivation of recoveringsubstantial quantities of oil that otherwise might beunrecoverable.

Complete gas repressing and repeated gas cycling ofreservoirs of highly volatile oil may be an economical

secondary recovery practice even though gas storage is notthe main objective.


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Large recoveries are expected from reservoirs of this type

because gas cycling vaporizes oil and the amount of

vaporization is related to the volatility of the oil. Oil vaporized

in the reservoir will be produced and recovered as condensate

or as natural gas liquids in a gas processing plan.

Gas storage in oil reservoirs has benefits over storage in other

types of enclosures. Gas can be safely stored to pressures at

least as high as the virgin reservoir pressure without possible

leakage. Secondary oil recovery may result, reducing the costof producing the oil. Finally, most wells in oil fields can take

and deliver gas.


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The conversion of an oil reservoir to gas storage usuallyrequires the use of additional field processing equipment andother operational facilities, reworking, and recompletion of allwells.

The surface facilities generally include wellhead heaterseparators, tank batteries, central separators, and other

processing equipment not common to dry gas operations. Inaddition to the high pressure gas system for injection andwithdrawal of gas from the gas cap, a low-pressure gas systemfor gathering separator gas is required.

The rich gas withdrawn from the reservoir as well as all

separator gas is passed through a gas plant to remove liquidhydrocarbons so that lean gas will be delivered into the salesline or re-injected back into the reservoir.


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The storage capacity increases with time because more spacebecomes available for storing gas as the liquid hydrocarbonsare produced. The liquid hydrocarbons are produced both bydisplacement and by vaporization into the injected lean gas

with subsequent production as components of a rich gas. Calculating system deliverability is much the same as for a dry

gas system. The primary difference is the improvement in theper welldeliverability with time as the result of increasingreservoir gas saturation .

Because of the saturation gradient that exists across thereservoir in such projects, the deliverability of the individualwells may vary greatly, with the deliverability of wells in thegas cap being higher than that of wells in the oil zone.


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Storage in Aquifers

Only if a depleted gas or oil reservoir is unavailable orunsuitable would consideration be given to using a water-bearing structure or aquifer as a storage medium.

Tests would have to be conducted to determine the suitabilityof such a structure to hold gas without leakage to overlying orunderlying formation.

The need to drill all the necessary wells results in a higherinvestment per unit of volume of gas stored.

Most of the following requirements must be satisfied for aproperly designed aquifer storage:

1. There should be a large enough layer of water bearing rock toaccommodate a worthwhile volume of gas.

2. The rock should have a porosity that enables water to beforced out by gas at a reasonable pressure and the rate atwhich gas can be withdrawn should be suitable.


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3. The structure of the layer should preferably be dome

shaped

4. the aquifer should be closed on all sides.

5. There should be a suitable layer of completely impermeablerock above the aquifer layer.

6. And the aquifer should be situated in a continuous, un-

faulted layer of rock.


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Exploring for Aquifer Storage Reservoirs

In exploring for aquifer storage reservoirs, geologists use

surface geology, coal structure maps, shallow structure tests,

oil and gas tests, water wells, geophysical data (seismic,

gravity, magnetic), and test holes in potential storage aquifer

(core analyses, drill stem tests, pump or swab tests.

When a trap is found, the geologist must also test the cap rock

above the reservoir to determine whether gas will leak

through it. Special core analyses are conducted to determine

the permeability and threshold pressure of the cap rock. Since the cap rock may leak through fractures, core analyses

are supplemented with analyses of water sample.


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A difference in composition of the waters above and below

the cap rock is supposed to indicate that there is no

communication across the cap rock.

Some geologists and engineless have used the observed head

difference between aquifers as an indication of absence of

fractures in the cap rock.


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Pumping tests (Fig. 1) are used to test cap rock. Water ispumped. out of the proposed storage aquifer and the waterlevel in an observation well in a porous zone above the caprock is observe. The acid test of a cap rock is to inject gas into

the storage reservoir and watch for it in observation wells inan aquifer above the cap rock (Fig. 2).

If all tests indicate that the cap rock is tight, gas injectionshould start gradually and let the pressure rise about 100 to200 psi above the virgin reservoir pressure. The pressure

gradient should be kept at less than 0.65 psi/ft of depth,preferably at less than 0.55.


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Fig. 1 Pumping test for cap rock (after

Bond)


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Fig. 2 Testing cap rock by injecting gas

(after Bond)


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Growth of Storage Bubble

When gas flows through a porous., water-saturated rock, itdoes not displace all of the water from the pores of the rock.Even after a large volume of gas has been injected, the rockstill contains a residual water saturation.

This residual water saturation varies from about 15 to 30% ofthe pore space in typical aquifers; it must be taken intoaccount when an estimate is made of the amount of gas in agiven volume of aquifer rock.

As relatively dry gas is cycled into and out of the aquifer,, thewater in the rock around the well evaporates. As the rock

dries out. it develops a greater capacity for gas; thepermeability of the rock to the gas also increases, resulting inhigher injection and withdrawal rates in the operating wells.


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Consider an ideal aquifer that has the same rockproperties throughout. Further., assume that thereservoir is isotropic that is , it has the samepermeability in all direction.. For this hypothetical

reservoir, one would expect that when gas wasinjected into a well in such an aquifer,, the gas woulddisplace water uniformly in all directions and form abubble with a circular interface between the gas andwater. The storage bubble is a gas-saturated zone

surrounded by a doughnut of compressible water-saturated rock, with a layer in between where gasand water flow in the same direction (Fig. 3).


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In practice, however, no aquifer has such ideal uniformproperties. Generally, the permeability of the rock varies withdepth; also, the horizontal permeability is usually greater thanthe vertical permeability. The result is that gas that is first

injected into such an aquifer preferentially flows into thezones of high permeability.

Later, gas rises into the rock above these permeable zones,while water trickles down into them because of gravity.Gradually, the entire space around the well becomes filled

with gas to some degree to form a bubble with more or lessuniform saturation of gas and water (Fig. 4). This may takemany month., depending on the permeability andhomogeneity of the aquifer..


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Fig. 3 Flow regions in and around a gas

storage bubble (after Bond)


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Consider the storage of natural gas in an aquifer.. Supposeinitial pressure, thickness of reservoir, radius of gas bubble,permeability of storage rock, and porosity of storage rock areknown. The storage bubble grows at a constant rate ew; that

is. water is displaced at the rate ew.

The aquifer is assumed very large in comparison to thestorage bubble. How will the reservoir pressure change withtime as gas is injected?


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This can be found in the following manner.

First, the dimensionless time (tD) is calculated:

(1)


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Fig. 4 Gas wafering during initial

injection in aquifer [after Katz and Coats]


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From pD-tables (Table 13.1), the value of the

dimensionless pressure (pD) is found thatcorresponds to this value of tD. Finally, the

reservoir pressure p is calculated from:

(2)


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Table (13-1)


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On the other hand, suppose a bubble is of known thicknessand radius. Gas will be injected into the bubble whilemaintaining the pressure in the bubble at a pressure (p)greater than the initial pressure p0 in the aquifer.

The amount of water displaced during a given period of gasinjection will be calculated. The cumulative water influx(efflux) We in terms of QD, dimensionless water influx (efflux),is given by:

(3)


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The procedure is to calculate tD from Eq. (1). Then from QD-tables (Table 13.2) the value of QD that corresponds to thisvalue of tD is determined. Finally, the value of QD is inserted inEq. (3) to give We. This procedure helps estimate how thebubble will grow as gas is injected into the reservoir.

In these calculations, an infinitely large aquifer has beenassumed. If the aquifer is enclosed (for example, a sand lensessurrounded by shale), it is called a limited aquifer. Thetreatment of the problem is the same, but different values of

QD are used.


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.1Example.

p0 = 900 psia , h = 100 ft , rb = 2,000 ft ,k = 500md ,c = 6 X 10-6 psi-1

= 0.16 , = l cp ,ew = 60,000 ft3 pore volume/day

Solution

Calculate the reservoir pressure at 30, 60, 120, 180 and 300 daysafter initiation of gas injection. Assume the aquifer to be infinite in

extent and that its performance can be approximated by the radial

mode.

Solution:The dimensionless time for a value of time t in days is given by Eq.

(1):


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(2)


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Operation of Aquifer Storage Reservoirs

The flow lines from the injection wells are connected to acompressor station, itself connected to the gas supply line.The gas bubble formed as gas is injected through wells on thecrest of the structure gradually extends in all direction, forcingthe water back. As it expands and reaches the base of furtherwells, these are brought into operation and gas is pumpeddown them, increasing the rate of injection.

In order to confine the gas within predetermined limits,

observation wells are drilled round the perimeter of the areato be used. These are similar to the operational wells but nogas is pumped into or with drawn from them.


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Their purpose is to determine when the interface betweenthe gas and water has reached the predetermined perimeter

of the storage. Fig. 5 shows the storage as it is being filledwith the gas-water interface not yet as far as the observationwells.

The initial filling will necessarily be slow since the water, beingmore viscous than the gas, can only be forced back slowly.

Once the storage is full, however,, gas can be withdrawn andinjected relatively quickly.

Furthermore, once the bubble is established at its fullestextent,, withdrawal of gas with consequent lowering ofpressure inside the bubble does not result in appreciablemovement of the water backward into the gas storagebecause of gas's greater mobility. Therefore, once the storageis established, withdrawal and refilling give rise only torelatively small changes in the physical extent of the gasbubble in the storage.


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Aquifer Behavior

A blanket water-bearing sand with impermeable top and

bottom that extends over many miles is often described as an"aquifer." When wells are drilled into an aquifer and water is

produced, the water in the sand flows to the well because of the

pressure reduction. It may take years for water production to

lower the pressure significantly some 10 miles from the well,

since the capacity of the sand is large and the expansibility of the

water and porous medium in the area around the well provides

the water.

When gas is stored in an aquifer, gas pressure in the reservoir

must be maintained higher than the original water pressure to

force any water out into the aquifer. During the initial injection

of gas into a water well, pressures from 100 to 300 psi above the

water reservoir may be required to start gas entering the porous

rock. Once gas has started flowing, the usual flow considerations


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Storage in Salt CavitiesThe success of solution mined cavities is evident by the

increasing number and size of the cavities being built. Cavernstorage of hydrocarbons such as propane and ethylene hasbecome a generally accepted practice. Recent advances insolution mining techniques for developing these caverns haveenabled a more diversified use of salt for underground

storage. Three factors should be considered in selecting a storage

cavern to be created by solution mining:

1. a sufficient salt thickness at adequate depth,

2. an adequate supply of fresh water for salt leaching

(solutioning, and3. a means of brine disposal.)


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A cavity in salt is normally created by controlled injection offreshwater, and subsequent removal of salt brine generatedby solutioning.

The salt brine is either pumped or flowed to the surface. A

concentric arrangement of different diameter casings isinstalled into the salt and is used to pump the fresh water intothe cavern and remove the brine.

Utilizing cavities which were created in salt formations bymeans of solution mining for hydrocarbon storage was first

conceived in Germany during World War I (Allen). Now, use ofsuch caverns is wide spread throughout Canada and theUnited States.


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The operation of a natural gas storage cavern differs fromliquid hydrocarbon storage; brine is not used for productdisplacement. In salt caverns used for liquefied petroleum gas(LPG) storage, the product is physically displaced by injectingbrine into the bottom of the cavity while the product is being

withdrawn from the top. The dry-type (brine-free) gas storagecavern operates between a maximum and minimum gasstorage pressure, with the gas volume between these twopressures being usable storage gas.

Natural gas is stored at a maximum pressure of 4,000 psia.

During withdrawal, the cavern pressure drops to a minimumof 1,225 psia. Fig. 13.10 is a cross section of the EminenceDome during the leaching process. Fig. 13.11 illustrated theoperation of the Eminence gas storage facility.


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The use of salt caverns for underground storage

of liquefied petroleum gases such as propane,

butane, etc., has been in practice

for over ten years. Considerations related to

location, creation, operation, size, capacity

and deliverability of salt cavern storage


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Creation of Salt Cavern ReservoirsThe process of washing out a cavern in rock salt is inexpensive

(from 19 cents to $1.80 per bbl) and quite simple. A shaft isdrilled into a subterranean salt stratum and the salt isdissolved and brought to the surface by pumping in freshwater and pumping out brine, leaving an opening of thedesired size within the stratum. In theory, every 6.03 bbl of

fresh water will dissolve one bbl of salt.Salt cavities should be formed in an area free from shaleledges if possible. If present, these ledges may break off andkink or snap any brine or product tubes that might be locatedin the cavity. In some operations, the amount of insolublesmay be excessive and tubing may have to be raised from thebottom of the cavity to prevent plugging.


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There are three methods of developing the salt cavity (Fig. 6.2)

a) bottom injection;

b) reverse circulation, and

c) progression technique.

When creating caverns in salt layers, fracturing may be employedto facilitate the cavern construction. Two or more wells maybe sunk then be washed out to provide a large storage area.Fracturing probably cannot be used in salt domes because thegeneral homogeneity of physical properties of salt may notlend itself to controlled horizontal fracturing. Figure 6.2 showsgraphically three distinct methods of developing salt cavitiesof controlled shape.


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Creation of Salt Cavities-DissolutionCreation of a salt cavity requires not only a main well forinjecting water into the cavity, but also a source of fresh waterand a brine disposal system, often rock layers of highpermeability containing brackish water. The time of dissolutionis predictable; it depends upon the water injection rate.

Cavern development on a site located by cores drilling or otherdata involves drilling the well through which fluid enter andleave the cavity (Figure 9.6). Using normal surface casing forpotable water protection, the main casing size is determined bythe size of the cavern. When drilling into salt, mud with

saturated brine gives protection from further dissolution of saltwhile the hole is drilled to the bottom of the proposed cavern.Fracturing of salt is to be avoided for storage projects.


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The direct leaching flow system involves pumping fresh waterdown the inner tube of the well to the bottom of the drilledhole. The brine, after dissolution, comes up the annulusbetween the fresh water tube and the casing. For reversedleaching the fresh water is introduced in mid chamber from an

annulus, with brine exiting through the inner tube (Figure 9.7).

Experiences show that using various positions of the watersupply and exit can control the brine concentration and theshape of the cavern. Sonar caliper tools (Figure 9.8) are used to

obtain the wall distances at various levels.


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ECONOMICS OF STORAGE


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ECONOMICS OF STORAGESeveral items enter into the total investment necessary to put an

underground storage field into operation. These items include

cost of acquisition, development, cushion gas, dehydration,

compression, and transmission.

Acquisition cost will involve purchase of all physical equipment in

the field including remaining gas or oil wells, gathering lines,

process equipment, compressor station, etc. It will be

necessary to purchase the remaining recoverable gas or oil in

the formation and the right to use the formation for storage.

Physical equipment can often be purchased for itsdepreciated value. Remaining minerals can usually be

acquired at the same rate as the rate paid during production.


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Development cost includes cost of drilling storage wells,

observation wells, and structure-control wells and cost of

wellhead structures and gathering system.

Complete drilling costs

including drilling, well casing,

cement, logging, coring, and testingcould vary from $5 to

$100 per foot, depending upon the depth and amount of

logging, coring, and testing that is done. A shallow storage

well less than 2,000 ft in depth could be drilled andcompleted for no more than $10 per foot. Wellhead

structures might cost up to $5,000 per well.


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Gathering-system costs will depend upon the capacity of the

wells and well-spacing patterns, but should not cost more

than 10,000 per well. Another significant cost in some fields

might be the money necessary to redrill and activate or

permanently plug and abandon all old gas or oil wells

abandoned during the producing history of the field. This item

could amount to a larger figure per well than the cost of

drilling new wells.In the average underground storage field, the total reservoir

capacity is divided approximately into 50 per cent cushion gas

and 50 per cent working gas. The cost of cushion gas could

fluctuate from 25 to 50 cents per Mcf, depending upon thelocality. In any instance it should be equal to the pipeline com-

pany's off-peak or interruptible sales price.


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Compression, transmission, dehydration, and other gas-

treating costs are entirely dependent upon individual

situations. Compressor stations can be built for $250 to $300

per installed horsepower. Transmission-line costs vary widely.

A rule of thumb that would prove satisfactory for approximatecosts would be 50 to 60 cents per inch of diameter per foot of

length of transmission line. Gas-treating costs would depend

upon what treatment is necessary. Separators and gas

cleaners would be included in the compressor-station costs.


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Illustrative Problem

A gas bubble 1,000 ft in radius has been developed on ananticline in a blanket fresh-water sand 50 ft thick. Thepermeability of the sand is 300 millidarcys and the porosity 20per cent.

The temperature of the reservoir is 68F and the pressure is1,000 psia.

How much gas can be injected over a period of 1 year bymaintaining the gas bubble at 100 psi above the originalaquifer pressure and pushing water out into the surrounding

area? The stored gas has a gravity of 0.6.


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Solution

The compressibility of water and formation are taken as 3.2 X10-6 psi-1 and 3.6 X 10-6psi-1 respectively, for a total of 6.8 X10-6 vol/(vol)(psi).

q = 6.283 X 0.20 X 6.8 X 10-6 X 1,0002 X 50 X 100Qt = 42,700 Qt

From Table 10-4, at tD = 509, Qt= 165.1. Therefore,

q = 42,700 X 165.1 = 7,050,000 cu ft of water

At 1,100 psia, the 7,050,000 cu ft of space would hold7,050,000 X 93 (from Fig. 11-30) or 655,000,000 cu ft of gas,which would be injected at constant pressure as a result ofwater moving out from the bubble.


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Gas Storage in Aquifers and Salt Caverns