SPINDLETOP SALT-CAVERN POINTS WAY FOR FUTURE NATURAL-GAS STORAGE
Southwestern Gas Pipeline Inc.
The Woodlands, Tex.
Clinton Oldham
Centana Intrastate Pipeline Co.
Beaumont
Spindletop underground natural-gas storage complex began operating in 1993, providing 1.7 bcf of working gas capacity in its first cavern.
The cavern and related facilities exemplify the importance and advantages of natural gas storage in leached salt caverns. Development of a second cavern, along with continued leaching of the initial cavern, target 5 bcf of available working gas capacity in both caverns by the end of this year.
During Spindletop's first year of operation, 1 bcf of the initial 1.7 bcf of working gas storage capacity was fully leased to outside parties.
The storage project began in 1990 when Winnie Pipeline Co., then subsidiary of Mitchell Energy & Development Corp., The Woodlands, Tex., announced plans to build underground natural gas storage in the salt-dome formations of the famous Spindletop field in East Texas near Beaumont.
Spindletop was selected primarily because, unlike a typical reservoir storage, operation of salt dome storage provides extremely fast injection and withdrawal capability. Spindletop can inject as much as 150 MMcfd of gas and withdraw up to 1 bcfd.
In May 1994, Mitchell agreed to sell the storage complex and adjacent pipeline assets to Centana Intrastate Pipeline Co., subsidiary of Panhandle Eastern Corp., Houston, one of the largest interstate pipeline companies in the U.S.
Centana took over storage operations on June 1.
OWNERSHIP
The storage facility encompasses 167 acres of land: Sabine Gas Transmission Co. owns 88 acres, Centana owns 62 acres (as of June 1), and 17 acres are jointly held. Additionally, the two companies jointly own an 88 acre brine disposal site approximately 3 miles from the main storage complex.
The facilities that currently make up the Spindletop complex include two salt dome gas storage wells and a 24,000 hp compression and dehydration facility owned by Sabine Gas; two salt dome gas storage wells and a 15,900 hp compression and dehydration facility owned by Centana; a 7,000 hp leaching plant; and three jointly owned brine disposal wells.
Mitchell began looking at gas storage opportunities in 1987 to reinforce its market position in southeast Texas. The addition of gas storage promised Winnie a reliable, cost effective gas supply to its industrial customers in the region.
By utilizing the rapid injection and withdrawal characteristic of salt dome storage, the company wanted to be able to respond quickly to changes in market conditions. Additionally, it wanted to minimize the pitfalls of mid month price volatility by protecting itself from price spikes while taking advantage of low cost distress gas. Winnie and its parent considered several proposals from 1987 to 1989 from sole ownership of all facilities that make up a storage complex to joint ownership of the entire project with an electric utility company.
A proposal that included initial plans, project economics, and conceptual designs was submitted to and approved by Mitchell Energy's board of directors in December 1989. The designs included jointly owned leaching and brine disposal facilities, individually owned salt dome gas-storage wells, and compression and dehydration.
The approved proposal called for construction of three salt dome storage wells, each with 3.5 bcf of working gas capacity and an associated 100 MMcfd compression and dehydration facility owned solely by Mitchell Energy, a 3,000 gpm leaching and brine disposal facility, and three brine disposal wells that would be jointly owned.
In late 1990, the design concept was amended to include two 6 bcf (working gas capacity) salt dome storage wells with 150 MMcfd compression, dehydration, and two headers to connect the storage to several intrastate and interstate pipelines.
To develop an overall plan for the complex, Winnie enlisted PB KBB Inc., Houston, subsidiary of a German company with multinational operations and an industry leader in the engineering and construction of subsurface containment systems. (Editor's note: See accompanying article p. 55.)
PB KBB conducted subsurface studies and selected the areas with the most promising characteristics for the development of salt caverns, disposal wells, and surface facilities. The firm also assisted in developing data required for the various permits and handled the permitting process.
Acquisition of the property that makes up the Spindletop complex was a joint effort among Sabine Gas, Gulf States Utilities (Beaumont), and Winnie Pipeline.
Purchase was complicated by the historical significance of the area and part of the area's classification as wetlands by the U.S. Army Corps of Engineers. Additionally, several small tracts of land were owned by several small interest owners who were difficult or impossible to locate.
Ultimately, between 300 and 400 transactions were required to obtain clear title to the property.
Before closing on the property, the company had to complete environmental impact studies to ensure that the ecological and historical significance of the area would be preserved. An exemption from the Corps of Engineers also was required for improvements in the wetlands areas.
DESIGN GOALS
A primary goal of PB KBB and Winnie engineers was to design the gas injection and withdrawal facilities generally to meet the needs of Winnie Pipeline and its customers and potential customers and specifically to be flexible enough to manage seasonal as well as daily and hourly changes in supply and demand.
Additionally, the geographical location of the storage in a market area with direct access to several major inter and intrastate pipelines enhances the value of storage services, particularly in the post FERC Order 636 environment (FERC = U.S. Federal Energy Regulatory Commission).
Spindletop near Beaumont, Tex., was ideal (Fig. 1).
The design team determined that the piping and process equipment would be capable of functioning under a wide range of pressures and flow rates in both injection and withdrawal modes.
To accomplish that goal, Winnie obtained the normal and low minimum and the normal and high maximum pressures of all the major pipelines located near Spindletop. Engineers chose to use a normal range of pressures for the design suction of the compressor units.
They used high maximums with an allowance for piping pressure losses to determine the design pressure of most of the station piping and the two main headers. The numbers for low minimums were used mainly as a benchmark for the design capabilities of all of the equipment.
To calculate the discharge pressure of the compressor units in the two stage mode, engineers used the anticipated range of cavern pressures corresponding to the minimum and maximum storage levels. And in the design of the discharge pressure of the compressor units in the booster mode, they used the normal maximum pressures of the major pipelines in the area (Fig. 2).
The maximum storage pressure was used to determine the design pressures for injection and withdrawal equipment. This pressure was also used for design of the pressure reduction facilities required for gas deliveries to meet the operating pressures of pipelines leaving the site.
Winnie's storage marketing group also provided a range (minimum and maximum) of anticipated flow rates for injection and withdrawal for each potential customer.
Design engineers employed these criteria, along with the pressure ranges already mentioned, to determine the number and sizes of the compressor units used in injection (two stage) and to establish design criteria and ranges for measurement, pressure, and flow control, pipe sizing, dehydration, etc. The capabilities previously listed allow the operator to meet the changing needs of multiple customers cost-effectively.
Another major goal was to maintain the operational integrity and safety of all the process equipment. Those goals were achieved by separating the process equipment into two groups: operating and monitoring.
The equipment used for changing flows, pressures, temperatures, moisture content, and so forth falls into the operating group and is categorized as "active." This equipment can be operated manually but normally is operated from the control room by the operator as part of his or her daily routine.
The monitoring group consists of passive equipment or "watch dogs." Most of the equipment in this group is not operated from the control room but is self controlled and checked only periodically by the operator. All equipment in the monitoring group is designed to fail in the "safe" position.
The two types of passive watch dogs are called operator and equipment failure. The former includes overpressure protection devices, low-flow limiters, temperature alarms, moisture alarms, and others.
Among the equipment failure devices are shutdown systems in the compressor programmable logic controller (PLC), flame, heat, and gas sensors, overpressure protection, the emergency shutdown (ESD) system, and others.
LEACHING PLANT; WELLS
PB KBB designed and built the leaching plant. The initial design called for an injection/withdrawal rate of 1,500 gpm. This rate was sufficient to develop one cavern at a time.
After it was decided that both Sabine Gas and Winnie would be developing storage caverns, the injection/withdrawal capability was increased to 3,000 gpm. The design of the leaching plant and associated facilities involved personnel from PB KBB and representatives from Gulf States Utilities for the electrical substation.
The leaching plant includes fourteen 500 hp, electric driven pumps, raw water handling facilities, brine-handling facilities, and three brine disposal wells, which are located approximately 3 miles from the leaching plant on an 88 acre site jointly owned by Sabine and Winnie (now Sabine and Centana).
The 11 high pressure pumps are arranged so that five pumps are dedicated solely to fresh water service and five to brine service with the one remaining pump capable of either fresh water or brine service. This arrangement provides some flexibility in the event of a pump problem.
Construction on the leaching plant and related fresh water and brine pipelines began on June 15, 1991, and was completed Oct. 25, 1991. The facilities were placed in service the next day when leaching began on the first cavern.
Drilling of the first injection well, the Winnie Well No. 1, got under way July 7, 1991. On Oct. 26, 199 1, leaching of the first salt dome cavern began, and on Oct. 15, 1992, the well was placed into gas service.
The cavern's physical (liquid) volume as of March 1994 was 1.8 million bbl. It extends vertically from 4,002 ft to 5,009 ft below ground level and is designed to be expanded to a volume of approximately 6.9 million bbl.
On May 14,1992, Winnie Well No. 2 was spudded; it was completed and leaching started on Sept. 23, 1992. Its current volume is approximately 3.7 million bbl, with the top of the cavern at 4,012 ft below ground level and the bottom at 5,215 ft.
PIPING; COMPRESSORS
Two 1,200 psig (MAOP) 20 in. pipelines provide access into and out of Spindletop storage. These pipelines normally operate 300 550 psig for injection and 700 1,200 psig in withdrawal.
Each line can operate independently of one another, and both are connected to several major pipeline companies located near the storage facility. A third, 12 in. pipeline operates at 200 psig to provide processed fuel to the engines, heaters, and utilities from a nearby cryogenics plant. This line also is used as the first stage of blowdown for the facility's piping during scheduled maintenance.
Six lean burn Superior 16SGTB engines driving Superior W76 compressors provide gas compression for cavern injection and pipeline boosting (Fig. 3). These units are designed independently to compress gas from either or both 20 in. pipelines into the storage caverns (two staging) or boosting (single staging) from either 20 in. line to the other. The cavern injection pressures range from 1,200 psig to 3,200 psig, depending upon storage levels. The discharge pressures under the boosting mode range from 700 psig to 1,200 psig.
Each compressor unit is designed to operate at full or nearly fun load conditions throughout the entire operating spectrum.
Under average conditions, each unit can compress 50 MMcfd in the booster mode and 25 Mmcfd in the high-pressure injection mode.
From the control room, the operator can shut down the units or switch each from injection to booster mode or vice versa and from either 20 in. pipeline. These procedures are discussed in more detail presently.
DEHYDRATION; HEATERS
Three glycol units provide dehydration service on the gas withdrawn from the cavern. Dehydration is necessary for the first two or three storage cycles.
After the third cycle, the water left in the cavern from the leaching operation is essentially dried out and dehydration may no longer be needed.
Each glycol unit has a design capacity of 50 MMscfd (for a total of 150 MMscfd). Because the gas from the caverns is never fully saturated with water, the effective dehydration capacity is two to three times greater than the available dehydration capacity.
Dehydration of the gas is controlled by a PLC that is connected to an online moisture analyzer. The system monitors a blended stream of gas downstream of the dehydration units and bypasses gas around the dehydration units if the water content is less than 7 lb/MMcf.
The gas pressure must be reduced from a cavern pressure of 1,200 3,200 at the surface before the gas can enter the pipeline system, which is operating at a pressure of 500 1,200 psig. Such large reductions in pressure can cause moisture in the gas to hydrate or freeze.
Two 14 MMBTU/hr heaters are used to prevent hydration or freezing as gas is withdrawn. Generally, this condition only exists when the cavern is at or near its maximum storage capacity (maximum pressure being 3,200 psig).
The fuel flow to the heaters is controlled by a gas temperature sensor that monitors the gas temperatures after each stage of pressure reduction.
CONTROL
Design of the station control system enables a single person to operate the entire storage facility all station activity and engine and equipment, performance from a console in the control room. The station control software is based on the Wonderware Intouch software package running on two Dell 486/50 PCs.
The operator can choose from five different operating modes and change the station from injection to withdrawal in only a few minutes. Strategic Controls Inc., Dallas, provided design and installation services for the station control system.
In injection or booster mode, the operator decides how many compressor units are required to perform the desired function.
Once this decision is made, he or she proceeds with either a standard valve set up or a customized one.
After the equipment is on line, he performs fine tuning by adjusting the rpm of each unit and, if required, the suction pressures to the individual units.
In withdrawal, the operator automatically creates the passage of gas from the cavern(s) to a specific (or both) 20 in. line. Once the passage is created, the station's pressure controllers and rate controllers handle the pressures and the volumes of gas being withdrawn from the cavern. The operator can change the settings of all pressure and rate controllers from the control room to ensure appropriate rates and the safety of the system. The overpressure controllers and monitors protect each individual pressure system (their settings cannot be changed from the control room). These instruments are calibrated and checked periodically.
A complete supervisory control and data acquisition (scada) system, driven by a Bristol 3330, is an integral part of the control system. Pressure, differential pressure, temperature, moisture content, status, and control transmitters are used to monitor and control the gas flows in and out of the storage facility.
They are also used to provide information to remote locations for the dispatching of gas and other business decisions. The station control system physically consists of seven Siemens 545 PLCs mounted in freestanding enclosures. Each of six of the PLCs is dedicated to one of six compressor units. The seventh is dedicated to station controls.
The main PLC sits inside the station control building. It is connected to remote input/output (I/O) modules located in the station yard near the glycol regeneration equipment, inlet gas scrubbers, pressure reduction area, and inside the engine room.
The station PLC is programmed to provide overall control of the storage facility, including station valve positioning, flow control through dehydration contactor towers, heater bath temperatures, remote starting on glycol regeneration skids, and monitoring of gas pressures and temperatures.
Each of the six compressor units has its own control panel consisting of one 545 PLC. The PLC monitors a variety of points on the compressor units, including engine oil pressure, engine oil temperature, compressor oil temperature, and discharge gas temperature.
The unit control panel sets up the automatic valve sequencing for unit starting, loading, and shutdown in any of the five different operating modes. If a unit begins to operate outside any of the design operating parameters, it will automatically shut down. Engine and compressor operating information is fed back to the station PLC.
SAFETY; MEASUREMENT
An ESD system, complete with gas and flame detection and sensors, can automatically or manually isolate and evacuate ("blow down") all gas lines within the entire facility. Two separate ESD systems are used: one for the compressor building and another for the remaining station piping.
A smokeless flare and vent are located east of the station. The flare system is used for all maintenance gas pipeline isolation and evacuation procedures and is also partially used in ESD blow down conditions. A back up generator provides full power to operate the entire complex in case of power failure. Backup batteries supply uninterrupted power to the computer and control system in powerdips or short term power failures.
In a complete power failure, however, all controllers and valve actuators fail in a predetermined, safe position.
Station gas measurement is by three Bristol 3330 remote terminal units (RTUs), each capable of handling up to six meter tubes. In addition, each 3330 is set up to communicate with an on line gas chromatograph analyzer, as well as with a data concentrator located inside the station's control panel.
Individual measuring stations are located at the terminus of each of the 20-in. pipelines entering the storage complex. Multiple cascading orifice meter runs measure the gas entering or leaving the facility. Each station is designated to measure a wide range of flow rates accurately (approximately a 30:1 turn down ratio). In withdrawal mode, they are designed to measure flow rates up to 450 MMscfd.
Each header has been designed for easy expansion (double capacity) by merely adding valves and meter tubes. The gas in and out of each cavern is measured by an insertion turbine meter. The fuel gas for each compressor unit and the utility gas are all measured independently.
CONSTRUCTION, COMMISSIONING
Construction of the facility was divided into two phases:
- Phase I included site cleaning, grading, roadways, drainage ditches including culverts, subgrade preparation, six compressor and cooler foundations, miscellaneous equipment foundations, and site clean up and move out.
A contractor was selected; construction began on May 6, 1992, and was completed by the target date, June 30, 1993.
- Phase II construction included all additional civil, mechanical, structural, and electrical work.
Oct. 1, 1992, was the scheduled de watering date for Cavern No. 1. All piping and necessary equipment and accessories for three compressor units were required for the de watering operation.
Because the 20 in. injection piping was not completed by the scheduled date, a 6 in. temporary discharge line was installed and de watering began on Oct. 15,1992.
The high pressure suction header, fuel, and starting gas lines for compressor units No. 2, No. 3, and No. 4, and the 6-in. temporary line were tested, purged, and placed in service at this time.
Because the compressor units were equipped with individual control panels capable of operating in manual, automatic, or remote service modes, the units were able to run in the manual mode, even with the station control room incomplete. The de watering of Cavern No. 1 was completed on Dec. 15, 1992. All other piping and equipment components for the withdrawal function of the facility were completed by Dec. 19, 1992.
Gas successfully withdrawn from the first cavern on Dec. 21, 1992. Most of the construction was completed by April 1993.
Fine tuning and modifications continued for several months on the control system. The stand by generator was tested and placed in service on May 18, 1993. Construction of the remaining compressor units and the final installation of the injection and withdrawal facilities was completed on June 13, 1993.
FIRST YEAR'S OPERATION
The compressors were placed in service on Oct. 23, 1992, so that contractors could begin de watering the Winnie No. 1 cavern. De watering was a by compressing gas into the cavern, displacing the brine remaining in the cavern. The de watering operation subjected the three compressors available for service to operational requirements of 2,500 psig discharge pressure and maximum discharge flow rates.
With construction of the facility incomplete at this time, the injection operation, and later the withdrawal operation, were more complicated and difficult than an operation in a completed facility, and temporary electrical and mechanical installations often operated poorly.
Extended wet weather contributed to problems such as the shorting of engine spark plugs. And when any of the three operating compressor units experienced mechanical problems, the staff had to cannibalize the three other units in order to continue uninterrupted injection operations at the scheduled rates.
Throughout the first year of operation, the facility's capabilities and flexibility were fully tested by the numerous requests for injection, boosting and withdrawal services at varying rates and varying pressures. Despite many operational problems, Spindletop performed exactly as designed, and, at times, better.
CUSTOMER BASE
Late in 1992, the company decided to stop leaching the first cavern to make 1.7 bcf of working gas capacity immediately available to customers for the winter heating season. Winnie
The pipeline began storing some of its own affiliate gas, and Chevron leased 250 MMcf of space as back up for its Port Arthur refinery.
Early in 1993, Mobil Natural Gas became Spindletop's second customer, leasing 250 MMcf of storage space with an option to lease an additional 250 MMcf in the second cavern as back up for its Beaumont refinery. Then, in July 1993, Mitchell signed a 10 year lease with Natural Gas Clearinghouse, the nation's largest independent natural gas marketer, for 1 bcf of storage capacity.
Clearinghouse reserved space for half that amount in the first cavern and will claim the remainder when a second cavern begins operating.
In November 1993, the company completed the final stretch of a 20 in. pipeline linking Spindletop storage with Texaco Sabine Pipeline and providing high pressure deliveries into the Texaco Sabine system.
Centana Intrastate is operating Spindletop storage and adjacent Centana pipeline which consists of 430 miles of 2 20 in. gathering and transmission pipelines primarily in Galveston, Chambers, Jefferson, and Orange counties.
The company will continue to develop additional storage to bring total working storage capacity to about 5 bcf by the end of 1994.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
