Storage project overcomes industry-standard gap

Robert G. Haley
Union Texas Petrochemicals
Baton Rouge

A workover (51064 bytes)and safety-system upgrade at an underground hydrocarbon storage well in Louisiana was successful despite the lack of a unified set of industry standards for the underground storage of hydrocarbons.

Inferring standards for design and operation from state regulatory rules of Texas and Louisiana and from API recommended practices,1-8 Union Texas Petrochemicals in 1994 completed the workover and upgrade at its ethylene underground storage well in Iberville Parish.

The wells integrity after the job was demonstrated by there being no evidence of nitrogen loss nor brine pressure loss during a final mechanical integrity test.

Periodic workovers

Since the late 1950s, underground storage caverns have been commonly used to store such various products as natural gas, hydrogen, ethylene, ethane, LPG, and crude oil.

Union Texas Petrochemicals owns or operates three underground storage fields in Louisiana. And the companys Louisiana operations include a wholly owned and operated NGL fractionator and a jointly owned and operated olefins plant.

The company also owns and operates storage and distribution terminals for feedstocks, olefins, and natural gas and utilizes jointly and wholly owned ethane and ethylene pipelines.

Periodic well workovers by Union Texas Petrochemicals upgrade existing storage wells to industry standards. All new storage wells are constructed to meet or exceed API specifications and regulatory requirements.

But API RPIII4, Recommended Practices for Underground Storage in Leached Caverns, does not discuss the operating safety system.6

An April 1992 storage accident near Brenham, Tex., prompted the Texas Railroad Commission to issue hydrocarbon-storage regulations.1

In Louisiana, Statewide Rule 29-M requires that all underground storage be constructed to industrial standards.2

Storage well N (27360 bytes)

Union Texas Petrochemicals Storage Well N at Bayou Choctaw was drilled to a depth of 3,590 ft and completed as a storage well in 1976. The cavern was developed to hold 490,000 bbl.

Ethylene (product) storage began in 1977. Ethylene is withdrawn from the storage cavern by displacing the low-density hydrocarbon with the higher-density brine. Louisiana Statewide Rule 29-M and Union Texas Petrochemicals require a maximum operating pressure at the casing seat of 0.9 psi/ft of depth.

The maximum allowable wellhead pressure (MAWP) varies with the direction of the flow and the flow rate. The maximum allowable outbound pressure is determined by the outbound flow rate and the calculated product pressure loss due to friction.

This friction pressure and the product hydrostatic head are then subtracted from the casing-seat pressure limit. This pressure must not exceed the wellhead flange ratings or the 0.9 psi casing-seat pressure limit.

At the maximum outbound flow, Well N will deliver 50,000 b/d with a pressure loss of 228 psi. The product hydrostatic head at 0.124 psi/ft of depth is 0.124 x 1,796 = 223 psi. The maximum allowable casing-seat pressure is 0.9 x 1,796 = 1,616 psi.

Therefore, with flow at 50,000 b/d, the maximum outbound wellhead pressure is 1,616 223 228 = 1,165 psi (Fig. 1).

The inbound pressure limit can be raised because the friction pressure is dissipated before reaching the casing seat. A lighter storage product will increase the MAWP but must still be limited by the maximum allowable casing-seat pressure.

Casing program

The N well was drilled using conventional oil well technology for large-diameter wellbores, and all casing was designed to meet or exceed API Specification 5CT.

The casing program consisted of the following:

80 ft of 30-in. Grade B. The casing was driven to refusal. This casing string isolates the upper layers of loose or poorly compacted soils that would wash out during drilling operations.
800 ft of 20-in. API modified buttress casing. This casing was set 45 ft into the caprock to isolate shallow unconsolidated sands and to seal off potable or freshwater reservoirs.
There is usually a lost-circulation zone in or near the caprock, and many salt domes have voids from sulfur produced by the Frasch method. The casing was cemented to surface with the tag-in inner string method with 1,300 sacks of Trinity Lite-Wate and 350 sacks of Class H neat followed by a drill pipe latch down wiper plug.
1,100 ft of 16-in. API modified buttress casing. This is the first casing cemented into at least 100 ft of salt as required by Louisiana Statewide Rule 29-M. The casing was cemented to surface with the tag-in inner string method with 1,600 sacks of Salt-Saturated Trinity Lite-Wate and 550 sacks of Salt Saturated Class H neat followed by a drill pipe latch down wiper plug.
1,796 ft of 1134-in. API modified buttress casing. This is the final cemented casing or production string, and it is cemented at least 300 ft into the salt. The production string is used to seal the cavern from the wellbore.
This casing depth is determined by the desired operating pressure of the well. Rule 29-M requires that the maximum operating pressure at the casing seat not exceed 0.9 psi/ft of depth.
Product flow is through the product casing string and brine displacement tubing annulus. The casing was cemented to surface with the tag-in inner string method with 2,100 sacks of Salt Saturated Class H neat cement followed by a drill pipe latch down wiper plug.
Before drilling out the float shoe, the casing was pressure tested to 300 psi with 10 ppg drilling mud. After drilling the float equipment and 10 ft of salt formation, the casing shoe was pressure tested to 0.9 psi/ft for 30 min.
3,475 ft of 858-in. API modified buttress tubing. This is the brine displacement tubing. (Tubing is any noncemented casing string.) It is used to remove brine during injection of ethylene into the cavern. Product flow is through the production casing string annulus.
Two 0.5-in. weepholes are burned in the tubing 10 ft from the bottom of the string. These two weepholes will allow a small ethylene kick through the brine tubing and will trip the emergency shut-down (ESD) system. Without the weepholes, a large ethylene kick could come around the end of the tubing (if the cavern were over filled).
To sustain product-delivery rates, brine pumps are used to displace ethylene. Brine velocities are usually kept below 18 fps to prevent erosion of the brine tubing string. The cable of an interface detector (a continuous downhole logging tool) may cause some erosion of the brine tubing near the surface.
Salt crystals may also increase erosion when the well is backwashed at high velocities.

Workover program

Louisiana Statewide Rule 29-M requires a workover every 5 years or as soon as possible thereafter but not to exceed 10 years.

Union Texas Petrochemicals interprets this to mean that if the cavern becomes empty after 5 years, the operator is required to workover the well. The cavern must be emptied, however, and a workover performed before the end of the tenth year.

Well N became empty 7 years after its last workover and a workover was scheduled. After the cavern was emptied, the calculated cavern product balance (inventory) was reset to 0.

The wellhead valves and flow lines were disconnected and inspected. The brine tubing was removed from the well. The threads were visually inspected, and a tubing inspection was completed.

This inspection included an electromagnetic induction and a special end area inspection. The volume of the cavern was measured with a sonar logging device, and a casing inspection log was used to indicate if there was any external or internal wall loss. A multifingered log was also used to decide if the casing was becoming eccentric as a result of subsidence or shearing forces.

An inflatable packer was set at 1,123 ft with 278-in. tubing. The ethylene that seeps from the empty cavern was flared through the tubing at the surface. The existing wellhead was removed and replaced with a new one constructed to meet or exceed API Specification 6A (Fig. 2 [84541 bytes]).

The new wellhead has several built in safety features to prevent the loss of a product from the wellbore. The weakest point of the original well was just below the wellhead. The entire storage volume was contained behind the production casing which protruded above the ground and into the starting head. This area is subject to corrosion and fatigue loadings due to workovers when a substructure was not used.

The intermediate casing was raised and the new starting head attached to it. This increased the integrity of the well and met API 6A. The annulus between the intermediate casing and the production casing is monitored by operations, and a high pressure would suggest a possible production string failure.

Also, added to the wellhead was a brine master valve in line with the well bore. This valve is car-sealed open to prevent accidental closure, which would cut the interface-detector tool cable, dropping it and the cable into the cavern. (Car-sealed refers to the use of a thin metal strip to alert an operator that the valve should be closed only in an emergency.)

Taps or tapped flanges were not allowed on the new wellhead before the master wing valves. All the taps have restricted orifices which will prevent the full volume of a product from escaping should the tap valve or nipple be accidentally severed (Fig. 3 [98222 bytes]).

Safety system

The ESD valves are not considered master valves and are fail closed on loss of signal, air, or power. Part of the pneumatic control tubing is made of polyvinyl chloride (PVC) and, in case of a fire, the pneumatic control tubing would melt, causing air to escape and the ESD valves to close.

The ESD valves are installed on the wellhead according to API 6A. Installing the ESD valves flange to flange on the master valves eliminates possible leak points. Should the ESD valve fail, the master wing valves can be used to shut-in the well.

The ESD system (including an audible alarm) can be activated by operations at the storage well, the control room, and at a location accessible during an emergency. All ESD equipment or control equipment was built to Class I, Group D, Division 2 standards.

Statewide Rule 29-M requires a high pressure shut-in at the MAWP. This prevents over-pressuring of the casing seat or the surface piping. Product low pressure shut-in is not a part of the safety system, but it prevents the flow of brine into the product system when the well is emptied.

The wellhead is protected from accidental injury and trespass. A 4-in. cemented guard rail around the wellhead prevents motorized vehicles from accidentally damaging it. The well-pad area is fenced in to stop trespassing and to prevent an operator from driving up to the well and igniting a possible gas leak.

Gas detectors were installed around the well-pad area to alert operations of a possible gas leak. Gas detectors are also installed on all brine knockout tanks (a flare system not being in use there) and in the process area where hydrocarbons are transferred to and from the storage system.

The brine tubing was reset at 3,475 ft, and 2.5-in. diameter weepholes were burned into the tubing 10 ft from the end. If the cavern is accidentally overfilled, the product interface will reach the top weephole and a small amount of a product will seep to the surface. This will allow the ESD system to shut in the well before the product reaches the full diameter opening at the end of the brine tubing.

A downhole interface detector tool installed in the tubing string monitors the distance from the end of the brine tubing to the brine hydrocarbon interface to help prevent overfilling of the cavern. This is an operational tool only and does not activate the ESD system.

The approximate volumes determined are unsuitable for accounting purposes and should not be compared with the actual measured volumes of hydrocarbons in the cavern.

The primary method used to prevent overfilling the cavern is to measure the injected and withdrawn ethylene. Should the cavern overfill, the product will displace some brine in the brine tubing and kick the remaining brine out of the well.

Careful measurement and bookkeeping are required to prevent overfilling the cavern. Product meters were calibrated and are installed near the wellhead. These meters are also used as a high flow shut-in. A pipeline failure between the wellhead and the process area would exceed the high flow limits and activate the ESD system.

The injected and displaced brine meters (turbine) are also used as a high flow shut-in. A dramatic increase in brine displacement occurs when the brine is being kicked out of the well because the cavern has been overfilled and this high flow will activate the ESD system.

A catastrophic failure of the brine tubing string will also cause the product to kick the brine out of the well and activate the ESD system.

Measuring the brine injection and withdrawal volumes allows operations to monitor brine volumes in the brine storage tanks. By monitoring brine withdrawal rates and comparing them with product injection rates, operations can determine if salt is being deposited in the brine tubing and the well can be backwashed with freshwater to prevent plugging.

By monitoring brine-injection rates, operations can determine if sufficient brine is being injected to displace the required storage product.

If a kick causes an increase in the brine wellhead pressure, the high brine pressure shutdown will act as a backup to the high brine flow shutdown and provide additional redundancy to the safety system.

A densitometer was also added to the brine flow line. When the brine density changes as a result of the presence of ethylene in the brine stream, the densitometer will activate the ESD system. The brine flow lines also have the same pressure rating as the product system. Low-pressure brine displacement pumps are protected from the high product pressure with high-pressure check valves.

Mechanical integrity test

The mechanical integrity test was conducted after the well was reassembled.

Brine was pumped into the cavern via the brine tubing. When the brine tubing pressure reached 350 psi, the brine flow line was blinded off. Nitrogen was pumped through the product valves until the brine nitrogen interface was 300 ft below the surface (determine by wireline).

The wellhead and valves were checked for leaks.

Nitrogen injection continued until the test interface was established at 1,874 ft (74 ft below the casing seat). Surface observations during the test found that the brine and nitrogen pressure stabilized.

During the workover that preceded the mechanical integrity test, an X-Y Caliper Log was run over the interface interval (1,866-78 ft). The diameter of the interface interval was measured at 14 in. (0.5 in.). Volumetric calculations for the 14.5 in. wellbore equate to 0.0170 bbl/in. Standard wireline depth accuracy is 6 in.

Calculations of the nitrogen response to well pressure suggest that no nitrogen was lost from the system. The nitrogen and brine pressure recorders suggested no loss of pressure, and there was no evidence of cavern or well leakage. The well is considered to have mechanical integrity, and the minimum detectable leak rate is 37.2 bbl/week of nitrogen.

A slight decay in brine pressure occurred during the cooler evening hours, but this was recovered during the warmer morning hours.

The test pressure gradient established during the test was 0.87 psi/ft.

References

1. Railroad Commission of Texas, Oil & Gas Division, Rule 95, Underground Storage of Liquid or Liquefied Hydrocarbons in a Salt Formation.

2. Louisiana Statewide Rule 29-M.

3. API Specification RP5C for Care and Use of Casing and Tubing.

4. API Specification 5CT for Casing and Tubing.

5. API Specification 6A for Wellhead and Christmas Tree Equipment.

6. API RPIII4, Recommended Practices for Underground Storage in Leached Caverns.

7. NFPA 70, National Electrical Code, 1993 Edition.

8. API RP5B1, Recommended Practice for Gaging and Inspection of Casing, Tubing and Line Pipe Threads.

This wellhead is one of eight at Union Texas Petrochemicals Choctaw terminal near Baton Rouge where salt-dome storage wells have capacity for more than 22 million bbl of ethylene, propylene, and feedstocks.

The Author

Bob Haley is an engineer for Union Texas Petrochemicals in Baton Rouge. He was previously a petroleum engineer for Thrash Oil & Gas and for Amoco Production. He worked as a mud logger and cementer in the South Texas oil fields before earning a degree in mechanical engineering (1981) from Texas A&M at Kingsville.