REGULATORY, TECHNICAL PRESSURES PROMPT MORE U.S. SALT-CAVERN GAS STORAGE

Thomas F. Barron
PB KBB Inc.
Houston

Natural gas storage in U.S. salt caverns is meeting the need for flexible, high delivery and injection storage following implementation Nov. 1, 1993, of the Federal Energy Regulatory Commission's Order 636.

This ruling has opened the U.S. underground natural gas storage market to more participants and created a demand for a variety of storage previously provided by pipelines as part of their bundled sales services.

Many of these new services such as "no notice" and supply balancing center on use of high delivery natural gas storage from salt caverns. Unlike reservoir storage, nothing restricts flow in a cavern.

Withdrawal rates from salt caverns are usually limited only by the dehydration capability of the gas handling equipment at the surface. Deliveries of 300 500 MMscfd from a single cavern are common.

In addition to high delivery, most salt cavern storage is designed for rapid cycling; in 15 min the operator can change from injection to withdrawal and, in 30 min, back to injection.

Most of the new salt cavern installations are designed for 10 day service permitting the working gas to be withdrawn over a 10 day period.

This withdrawal coupled with the necessary compression to replenish the cavern over a 20 day period, permits the working gas volume to be cycled monthly. Although most caverns experience approximately six turnovers annually, some are cycling monthly.

In fact, gas marketers leasing storage at First Reserve Gas Co.'s Hattiesburg, Miss., gas storage at the Petal salt dome have cycled volumes as much as 20 times a year by using withdrawal or injection capacity not being used daily by other storage customers.'

Because of these features, salt caverns are being used for the following:

To provide peaking service to meet needle peaks for natural gas supply
As emergency supply to replace lost production due to weather related outages such as hurricanes or freezes
For balancing short term load swings and to avoid pipeline imbalance penalties
For spot gas purchasing strategies including off peak or weekend injection followed by weekday/peak withdrawals and monthly or daily spot price hedging.

SALT DEPOSITS

The first U.S. salt cavern was placed into natural gas service by Southeastern Michigan Gas Co. in 1961. A 2,000 ft cavern in a bedded salt deposit to recover brine was converted to storage holding 341 MMscf of gas.

In 1963, Saskatchewan Power Corp. (TransGas) put the first caverns into natural gas service specifically designed for gas storage. This cavern, constructed in bedded salt, was designed to store 262 MMscf.

The first caverns constructed in a salt dome for gas storage were built by Transco in 1970 at Eminence, Miss. The facility consisted of two caverns with a total of 2 bscf of working gas, combined delivery (withdrawal) of 750 MMscfd, and a fill (injection) rate of 25 MMscfd.

Over the years, these facilities have been expanded and new ones added. Editor's note: See Table 1 of the first article in this special report, p. 45.)

Large deposits of salt exist in many areas of the U.S. These deposits range from massive salt domes along the Texas Louisiana Mississippi Gulf Coast to bedded deposits of salt in other parts of the country.

Salt has unique properties that make it ideal for storage:

It has the structural strength of concrete, permitting large caverns to be constructed in the deposit.
It is virtually impermeable to liquid and gaseous hydrocarbons, thus ensuring stored fluids cannot escape through the salt.
It behaves as a plastic allowing it to close and seal fractures that might occur.
It is easily mined by dissolution in water.

Salt domes are easily visualized as large underground mountains of salt. Each dome has a unique size and shape but a sample dome might be reasonably assumed to be cylindrical and symmetrical in shape, about 1 mile in diameter, 30,000 ft in height, and terminate about 1,500 ft below the surface (Fig. 3).

Caverns constructed in salt domes are typically 200 ft in diameter and 800 ft in length; many caverns can be constructed in a single dome.

A salt dome consists essentially of pure halite with dispersed grains of anhydrite sand which frequently makes up 5 10% of the total mass. A dome is typically overlain by a caprock, consisting of a 500 ft porous and fractured zone of anhydrite, gypsum, calcium, and sometimes free sulfur.

Unlike the caprock associated with porous media underground storage, the caprock overlying a salt dome is not called on to contain materials stored in the salt. The salt is the isolating medium.

Bedded salt on the other hand can vary in thickness from a few feet to thousands of feet. In some cases the salt is interspersed with shale or anhydrite or beds of both. As long as these formations are impermeable, storage caverns can be constructed.

Salt caverns have been used for underground liquid hydrocarbon storage since the early 1950s. There are more than 1,000 caverns in U.S. and Canada storing liquid and gaseous hydrocarbons.

CHOOSING LOCATION

Siting a natural gas storage salt cavern depends on four criteria:

Adequate salt
Water for leaching
A means of brine disposal
A reasonable distance to natural-gas pipelines.

Most of what is known about salt deposits has resulted from oil and gas exploration drilling and seismic operations or from earlier construction of liquid storage caverns. At times, however, it is necessary to conduct additional exploratory drilling to qualify a site.

Drilling may be done to define the limits of the deposit or to obtain cores for analysis. Additional seismic may be shot including the use of vertical seismic profiling to detect the edge of salt domes and locate overhangs. Fresh or brackish water for cavern leaching is generally obtained from ground water or from such surface sources as lakes, rivers, canals, and similar water sources.

The total volume of water required to leach a cavern is 7 to 10 times the cavern volume. Therefore, a 3.5 million bbl cavern to store 3 bscf of working gas will require on the average 30 million bbl or 1.3 billion gal of water for construction.

By the same token, provisions for disposing of the same amount of brine must be made.

Brine disposal is generally accomplished through disposal wells completed in saltwater aquifers well below fresh water sands. The disposal zone must be isolated from freshwater zones and be capable of accepting the total volume of brine produced.

The formation must be sufficiently porous and permeable to allow for reasonable injection rates. In the case of bedded salt, the disposal aquifers can be above or below the salt deposit. For salt dome construction, the disposal wells are positioned off the flanks of the dome.

Under the right circumstances, there can be alternatives to deep well brine disposal.

As brine is a feedstock for the chemical industry in production of chlorine and caustic, it can, in some cases, be disposed in this manner. In most cases, however, the cavern is not built near enough to a plant to make this option feasible.

Disposal has also occurred in the Gulf of Mexico at some Strategic Petroleum Reserve sites.

Brine is also produced for evaporation in the production of salt. However, brine disposal by this method depends on a reasonable evaporation rate (not the case in the U.S. Gulf Coast) and entails construction of large evaporation ponds, an additional expense.

Also, salt producers typically consume brine at fairly low rates much lower than is desirable for constructing caverns in a reasonable time. If suitable disposal zones are unavailable, however, solar evaporation may be the only alternative.

Once the extent of salt is known and a source of raw water and brine-disposal method identified, siting hinges on the design of the cavern.

CAVERN DEPTH, SHAPE

Given the dramatic differences in the characteristics of domal and bedded salt, cavern design is approached differently in each case.

In salt domes, there is a great deal of flexibility in positioning a cavern depth down to about 6,000 ft.

At this depth, the salt is so plastic with accompanying pressures and temperatures that salt creep or cavern closure becomes a major consideration. Also, construction and operating costs increase with depth.

On the other hand, a small cavern operating at higher pressures can store the same amount of working gas as a much larger, shallower cavern operating at lower pressures. In addition, the time to construct a smaller cavern can be significantly less than for a larger cavern.

Studies by PB KBB have shown the optimum cavern depth for new construction to be 3,500 5,000 ft, given considerations for salt properties, drilling and leaching costs, operating pressures and temperatures, compression, and operating costs.

In bedded salt deposits, on the other hand, there is usually little flexibility in positioning the cavern at depth because the salt occurs at a given depth or over a given interval in the geologic section penetrated by the wellbore.

Even in bedded salt, however, 6,000 ft still represents a practical limit on cavern depth for the same reasons previously described.

The shape of the original Eminence domal gas storage caverns was long, narrow, and cylindrical, much like the shape of liquid storage caverns at the time. Because of the amount of closure experienced, however, those caverns were releached.

Two of the original four are now more spherical, a shape which has proven more stable over time and is confirmed by modern rock mechanics theory.

Fig. 1 is a sonar survey of a newly constructed salt dome natural gas storage cavern.

A spherical shape is ideal for a bedded salt cavern. Given the limited thickness of some salt beds and the desire to construct as large a cavern as possible to reduce project costs, however, cavern geometry may deviate from the spherical shape within theoretical rock mechanics limitations.

Fig. 2 is a sonar survey of a cavern in bedded salt with a fairly spherical shape. On the other hand, if the salt and roof material overlying the salt exhibits adequate structural strength, it is possible to design for less than a 1:1 height/diameter ratio.

Another technique is to design a "sausage" cavern using two wells connected by horizontal drilling for construction. With this technique, raw water is pumped down one well and brine taken from the other (Fig. 3a).

After a period of time, the procedure is reversed until the final shape if achieved (Fig. 3b). The resulting cavern is larger than two individual, single well caverns.

Use of new computer simulations to model cavern leaching as a function of solution mining parameters (mining rates, water and brine properties, temperatures, etc.) has enabled more accurate prediction and control of cavern shape.

Predicted cavern geometry may then be used as an input for the subsequent modeling of expected creep closure and cavern stability.

CAVERN SIZE

Most facilities constructed today are designed for a minimum of 3 6 bscf of working gas. Although single, large caverns can be constructed in domal salt to accommodate these volumes, several small caverns in bedded salt will be required.

Even in a salt dome, because of the time required to construct a 6 bscf cavern, most if not all operators prefer two caverns in which operations can begin with one cavern in service while the second is leaching.

For example, approximately 24 months is required to perform final engineering, procure the required equipment, and construct and dewater a 3.5 million bbl cavern to store 3.0 MMscf of working gas. Of this time, the leaching of the cavern takes approximately 12 months, dewatering 4 months.

A cavern twice the size would therefore add another 16 months to the construction schedule. The Spindletop, Tex., cavern is a good example of multiple caverns and how timing plays an important part of the construction schedule.

Two caverns, one each for Winnie Pipeline (now Centana Intrastate Pipeline Co.) and Sabine Gas Transmission were simultaneously constructed and converted to storage for the 1992 winter heating season. In the meantime, two additional wells were drilled and leaching began immediately on the second caverns for each company.

In March 1994, Sabine No. 2 was converted to natural gas storage and dewatering begun, a 4 month procedure. The final storage volume is 3.2 bscf of working gas.

In July 1994, dewatering began on Centana No. 2 with a scheduled working gas volume upon completion of 2.8 bscf.

In contrast to the size of these domal caverns, TransGas operates 12 caverns constructed in bedded salt in Saskatchewan.

The caverns have a total working gas volume of 8 bscf or an average working gas volume of 600 MMscf/cavern.2

Many times bedded salt is interbedded with anhydrite or shale layers. As salt is mined from below interbedded layers during solution mining, the more incompetent layers will fall to the bottom in a rubble pile.

As a result, the space occupied by the rubble (including a factor for bulking) is lost to hydrocarbon storage unless the brine can be recovered from the rubble pile. This space can amount to as much as 30-40% of mined volume in some cases.

The two well concept offers one way to use some of the space in the rubble zone as opposed to a single-well leaching scheme.

In addition to positioning the cavern at depth, the cavern must be positioned in the salt relative to other caverns that may exist and to the edge of the salt deposit, and the cavern must have adequate roof thickness for stability and integrity.

SPACING

The amount of salt between the caprock and the casing seat and cavern roof is important for cavern integrity. There must be adequate salt thickness to ensure the casing is properly cemented in the salt interval.

In most cases the casing seat is placed some distance above the roof of the cavern because roof slabbing or creep deformation near the cavern could damage the casing. There must also be adequate thickness of salt to ensure that loads will be transmitted to the cavern walls without developing tensile stresses in the roof.3

Some states require a minimum salt roof thickness. Generally, however, 300 500 ft of salt are recommended to ensure a good cement job and adequate roof support in the salt. Because of the wide variations of imbedded salt sections, each one must be analyzed individually.

Salt near the edge of a dome is more likely to be locally disturbed and contain more impurities than salt in the interior of the dome. The location of the edge of the dome is generally known only to an accuracy of 100 300 ft with good well control.

If adequate well control does not exist, vertical seismic profiling has been used to detect the salt edge and locate overhangs. The distance (P) between adjacent caverns is the width of the salt pillar separating the caverns. The value of P can be used to assess the probability for cavern coalescence.

The ratio of the pillar width to the average of the two caverns' diameters (P/Davg) is inversely related to the relative loading of the salt pillar.3 The larger the cavern for a given pillar width, the greater the loading on the pillar.

Louisiana requires a pillar width of 200 ft for hydrocarbon storage caverns. Studies have shown that P/Davg ratios as low as 0.2 to 0.5 can be tolerated under certain conditions.4

However, these studies did not address the uncertainties associated with determining cavern geometries, variations in salt quality, and other considerations. These parameters along with different operating pressure scenarios must be investigated to resolve questions of potential cavern connectivity.3

PRESSURES

A natural gas storage cavern operates similar to a pressure vessel between maximum and minimum pressures. The overall stability of the cavern is directly related to the operating pressures of the cavern including the time a cavern is exposed to the lower pressures.

Setting the maximum and minimum operating pressures of the early gas caverns was based on experience gained during many years of operating constant pressure liquid storage caverns. An additional consideration included the operating pressure of the pipeline on withdrawal.

Obviously, the minimum cavern pressure must be sufficient to overcome frictional losses in the well and surface equipment to deliver gas into the pipeline at the desired rate unless the gas is to be further compressed for delivery.

Today, the same factors are considered when determining cavern operating pressures. But we now have more than 30 years' operating history on which to base decisions and new, modern, computer based, finite element programs for rock mechanics analyses.

These rock mechanics programs using the mechanical properties of the host salt obtained from sophisticated core analysis are used to model projected cavern operations (fill and withdrawal cycles) for a given cavern design and to aid in determining the optimum operating pressures for a cavern.

Theoretically a cavern should be capable of withstanding an internal pressure equivalent to that imposed by the weight of the overburden without fracturing the salt formation. Historically, the maximum cavern pressure has been based on an assumed vertical stress gradient of 1 psi/ft of depth.

The actual vertical stress gradient for caverns located in domal salt can be calculated from log information and is typically between 0.94 and 1.00 psi/ft of depth, unless there is a very massive caprock involved.3

With application of a safety factor, the maximum allowable pressure at the production casing seat is typically set at 0.80 to 0.85 times the depth for salt dome caverns.

The maximum permissible pressure gradient in Texas is 0.85.

This translates to roughly 0.85 to 0.90 times the vertical stress based on overburden densities at that depth.

In some cases, bedded salt caverns are operated at lower maximum pressures or at greater safety factors recognizing the larger amount of insolubles in the salt. Maximum pressure ranges of 0.65 to 0.75 are typical.

Under differential stress, salt will deform plastically and will "creep." The amount of creep and resultant closure a cavern will experience over time is primarily a function of the magnitude of the stress differential, the temperature of the salt, and the inherent strength of the salt.

Salt storage caverns in LPG service generally experience little closure. The caverns are constructed typically at shallower depths where temperatures are not that high, and the caverns are operated at a relatively constant pressure under a full brine head.

Natural gas storage caverns on the other hand are constructed deeper in the salt (resulting in higher salt temperatures) to allow more gas to be stored per volume of cavern space, that is, at higher pressures. Additionally, a gas storage cavern is operated over a wide range of pressures.

As a result, cavern closure will occur over time. How much depends on the operating pressure history of the cavern. The lower the cavern pressure, the greater the closure; the longer the cavern is sustained at a low pressure, the greater the cumulative closure will be.

Knowing the owner's intended mode of operation, the cavern designer using finite elements/rock mechanics modeling, can investigate different operating pressure scenarios for multiple injection/withdrawal cycles to determine the effect on cavern closure. The creep characteristics of salt can vary widely, however. Without site specific values for the mechanical properties of the salt, projected closure rates can be in error by an order of magnitude.

Given site specific data from core testing or carefully planned field testing, various operating parameters can be modeled for a given design resulting in the establishment of those parameters that will reduce the amount of closure experienced.

Fig. 4 shows the predicted closure for a salt dome cavern based on such a study. Fig. 4a shows the cumulative volume closure of a cavern during and after withdrawal when the cavern is taken from a maximum pressure of 2,000 psi to a minimum final pressure ranging from 1,800 to 600 psi at a withdrawal rate of 150 MMscfd and left at this pressure for 90 days.

For comparison, results for the case of holding the cavern at the maximum pressure at 2,000 psi for 90 days are also included.

Fig. 4b shows the volumetric rate of closure for the same cases. As can be seen, the rate of closure increases dramatically when final pressure is reached.

The rate of closure, however, drops off rapidly within the first 10 days final pressure has been reached of creep induced stress relaxation.

The cavern operator can exercise a great deal of control over the amount of closure and the rate at which it occurs. For example, it would be unusual for an operator to leave a cavern at minimum pressure for 90 days, as shown in Fig. 4.

By striving to keep cavern pressure as high as possible and by refilling the cavern as soon as possible following a drawdown, and through the use of the finite elements/rock mechanics analysis, cavern closures of less than 1% a year are typical with today's modern caverns.

CONSTRUCTION

Except for the "sausage" cavern described earlier, natural gas storage caverns are completed with a single well.

The storage well is designed to ensure gas can be injected into the cavern at desired rates and pressures and that gas can be delivered at the specified rate over the operating pressure range of the cavern.

Additionally, consideration must be given to the rate at which the cavern is to be constructed (leached). This rate is limited by the size of the leaching strings used for construction which in turn are limited by the size of the last cemented casing in the storage well.

For gas storage wells, the required leaching rate generally takes precedence in the well design.

A leaching plant consists of two banks of pumps one for pumping the raw water and another for brine disposal. Additionally, a blanket pump and storage tank are required for the blanket material used to control leaching, as explained presently.

The first step in leaching is the placement of the blanket material in the salt borehole.

The blanket controls upward leaching that, if uncontrolled, would dissolve the cavern's roof and ultimately jeopardize the cavern's integrity and ability to hold pressure.

The blanket material is generally noncorrosive and immiscible with water and lighter than water hydrocarbons (for example, propane, butane, diesel) that will float on top of the brine to prevent the upward dissolution of the salt.

During solution mining or leaching, raw water is injected through the hanging string into the salt formation, dissolving the salt. The resultant brine is then displaced to the surface.

During initial development, a sump is constructed that will act as a repository for the insoluble material in the salt (Fig. 5). Following this, circulation continues using either direct circulation or modified reverse circulation (Fig. 5).

` Computer simulations run before cavern construction are used to position the leaching casings for sump development and cavern construction. The hanging strings are usually repositioned at least once during cavern construction to achieve the desired geometry.

Periodically during the course of construction, leaching is halted and a sonar survey is run in the cavern to monitor construction progress. Upon completion of the cavern, a mechanical integrity test is run to confirm the cavern does not leak.

Following cavern construction, the leaching strings are removed from the cavern. The leaching wellhead is replaced with a storage wellhead complete with emergency shut down (ESD) valves, and a dewatering string is run in the cavern. Natural gas is then injected down the annulus between the last cemented casing and the dewatering string until all the brine in the cavern is displaced to the surface. The dewatering string is removed from the cavern if maximum flow capacity, is desired, and the cavern is ready for service.

CONVERSIONS

Although these descriptions apply to new cavern construction, many caverns in natural gas service were brine caverns or LPG storage caverns converted to natural gas service.

Converting such a cavern to natural gas service offers the obvious advantage of immediate availability compared to the time required to construct a new cavern and should be less costly than new construction. The same principles as previously discussed apply for determining the feasibility of converting a cavern to natural gas storage. A sonar survey is run to determine cavern size and dimensions for analysis.

A casing inspection log is run to determine if the present production casing is suitable for natural gas storage or if a new casing must be run and cemented in place. (Some states require two cemented casing strings in the salt for hydrocarbon storage so that installation of a new casing may be required when a brine well is converted.) Lastly, a mechanical integrity test of the well and cavern at the anticipated storage pressure is performed to confirm integrity. Since LPG salt dome storage caverns are generally small relative to natural gas storage caverns, the cavern may be enlarged before conversion, space permitting.

In 1992, an ethylene storage well at the Napoleonville dome in Louisiana was enlarged by Ponchartrain Gas from 1.7 to 3.3 million bbl and converted to storage. Enlarging the well expanded the working capacity from 1.0 bscf to 2.6 bscf. The major components of the surface gas handling facilities consist of the following:

Compressors to inject at the desired rate over the operating pressure range of the cavern
A pressure reduction station to reduce wellhead flowing pressure during gas withdrawal to that of the surface handling facilities and receiving pipeline
Dehydration equipment to remove water from the gas absorbed during storage (Fig. 6).

Additional equipment consists of the necessary piping, instrumentation, metering, and controls.

OPERATIONS

First Reserve Gas Co.'s Hattiesburg storage was placed in service in 1990.1

The facility is located on the Petal salt dome at Hattiesburg, Miss., and consists of three caverns converted from LPG storage.

Working gas totals 3.5 bscf and base gas is 2.2 bscf. Maximum deliveries from storage are 350 MMscfd and injection capacity is 175 MMscfd.

Storage serves five gas distributors, three combination gas and electric utilities, two interstate pipelines, two major gas producers, one gas marketing company and seven brokered capacity/interruptible service customers.

Fig. 7a shows both daily injections and withdrawals and the accompanying daily storage inventory level in the caverns from Dec. 1, 1991, through Mar. 31, 1993. The company's experience demonstrates the use of the facility for both supply security to protect against supply interruptions such as those occurring during Hurricane Andrew and for balancing service particularly during the shoulder and summer months when market demands are subject to high levels of change. Storage inventory volumes shown in Fig. 7b indicate that storage customers are maintaining high inventories during winter months for supply interruption insurance but reducing levels during the off peak season to make room for balancing requirements.

Hattiesburg's customer mix is dominated by Northeast U.S. local distribution companies (LDCs) which have 60% of the total contracted capacity. Their daily injection and withdrawal activities are shown separately on Fig. 8a. Again, the pattern of using the facility for production area supply security in the heating season and balancing services in the nonheating season is apparent.

Southern U.S. customers on the other hand use Hattiesburg more in the winter months than in the summer (Fig. 8b).

Pipelines serving the Northeast are full during winter when the degree day or heating load dominates.

For southern markets, however, the daily temperature swings and gas heating loads are more cyclical, requiring more storage injection and withdrawal activity to meet the changing gas loads during the heating season.

Fig. 9 shows the combined daily injection and withdrawal activity from Nov. 1, 1993, through Feb. 28, 1994, of marketing and interruptible customers at Hattiesburg. Their usage shows an almost continuous daily movement of gas, with both injections and withdrawals occurring on the same day.

The facility serves a broad market via the Transco main line, the Tennessee 500 system, and Koch Gateway system, possibly explaining the high cycling activity.1 It also suggests the marketers are using Hattiesburg to manage gas-supply delivery nominations and intra-day nomination changes,

Because most of the marketing companies storing gas at Hattiesburg are serving southern LDC markets, the information shown in Fig. 9 also demonstrates that injection capability is equally as important as withdrawal capacity for nominal daily nomination changes. It also indicates that, as the 1993 1994 heating season progressed, larger market swings occurred as a cold spell was followed by warm weather which, in turn, was followed by another cold snap.

REFERENCES

Wright, Michael G., "Gas Storage Strategies: Open Access and Market Rates," presented at Gas Daily and Gas Storage Report's Sixth Annual Conference, Houston, Apr. 12 13, 1994.
Crossley, N. Graeme, "Gas Storage in Saskatchewan Bedded Salt," presented at the Solution Mining Research Institute Meeting, Houston, Oct. 18 21, 1992,
Chabannes, C. R., "Salt Cavern Creep Why it Happens, How to Predict It and How to Minimize It," presented at Gas Storage: A Technical Seminar, Houston, May 12 13, 1992.
Ratigan, J.L., and DeVries, K.L., "Potential Geo-mechanical Problems Resulting from Closely Spaced Storage Wells in Salt Domes," presented at SP: Gas Technology Symposium, Dallas, June 7 9, 1988.