Discovery of external corrosion on tank floors at several aboveground storage tanks (ASTs) along the Trans Alaska Pipeline system (TAPS) led engineers to evaluate methods of repairing corrosion damage and to examine how to improve tank bottoms' cathodic protection.
The corrosion underscored Alaska's difficult operating conditions.
Warm crude oil and turbine fuel, at temperatures of up to 120° F., are stored at various stages of pumping and transport in 31 aboveground steel storage tanks located at 11 pump stations along the pipeline (Fig. 1). Tank sizes range from 20 to 180 ft (Fig. 2).
Smaller tanks contain residue from refining units at temperatures of up to 120° F. Tanks 73 ft in diameter are turbine-fuel storage tanks holding warm product at between 75 and 85° F.
The larger (116-180 ft diameter) tanks are crude-oil relief tanks, storing oil at ambient temperatures. Those temperatures vary from - 60° F. in northern sections of the pipeline during the winter to summer temperatures of 80° F. in central areas.
With the exception of four tanks at Pump Stations 2 and 7 which were constructed in the early 1980s, most of these tanks were built in the mid-1970s during original pipeline construction.
They are placed within a containment area, consisting of a 10-12 ft earth embankment or dike. The entire area is lined with a secondary containment membrane of chlorinated polyethylene which extends to the top of the containment dike.
The tanks are located above the liner on a layer of fill which is 5 ft thick at its maximum. This approach was relatively unique 17 years ago; most of industry's tanks built at that time were not constructed over a secondary containment liner.
The fill beneath the tanks varies at each location from a uniform 0.375 in. minus gravel (gravel crushed to a 0.375 in. or smaller screen size) to 0.750 in. minus with cobbles (as large as 8 in. intermixed).
Discovery of external corrosion
In 1989, a routine API Standard 653 tank-inspection program of ASTs showed that the floors in warm storage tanks were being damaged from external corrosion.
Tanks storing product at ambient temperatures displayed minimal damage from external corrosion. In northern pump stations, where warm product tanks are constructed on permafrost, special provisions were undertaken to keep the tanks from settling.
In permafrost, the soil is frozen to several thousand feet depth and is of an extremely high resistivity. Under these conditions, heat generated by storage of a warm product in the tank creates a "thaw bulb" below it. To address this problem, refrigerant coils were built 3-4 ft below the tank floors.
Although this system works well to stabilize the structure, warm product creates a warm thaw bulb directly under the tank. This promotes the environment in contact with the tank bottom to hold water and have a lower resistivity which creates an accelerated corrosion environment.
No corrosion protection was installed when the pipeline and ASTs were constructed.
The tank inspection prompted Alyeska to install cathodic protection on the external tank bottoms of all ASTs at pump stations along the pipeline containing warm crude oil and warm turbine fuel.
Although various cathodic-protection retrofit systems are available, the presence of secondary containment liners, refrigeration systems, and fluctuating arctic environment necessitated use of a system in which the anodes were located between the secondary containment liners and the tank bottom.
This is because the secondary containment liners are dielectric and impede the flow of cathodic protection from passing through from remote anode groundbeds. Also, the permafrost provides a highly resistant, unsuitable environment for the anode groundbeds.
Method 1: perimeter system
Initially, when tank inspection revealed that most of the external corrosion for Tank No. 130 occurred at the tank floor's perimeter, the decision was made to perform patch repairs to the tank floor and install a tank perimeter conductive-polymer anode loop system.
Tank No. 130 is a 116-ft, crude-oil storage tank at Pump Station 3. It was constructed in 1975 and operates at a service temperature of 75-85° F. A 30-mil thick chlorinated polyethylene secondary-containment liner located approximately 3.5 ft beneath the tank extends to the perimeter of the tank farm. Although this tank has no refrigeration coils beneath it, a 6-in. layer of insulation is present directly beneath the liner.
The conductive-polymer anode loop system consists of a single loop of 0.5-in. diameter conductive polymer wrapped in a porous woven jacket filled with petroleum-grade coke "breeze" (carbon powder) resulting in a 1.5-in. OD anode.
The anode loop was buried above the secondary containment liner at a depth of 2 ft around the tank's perimeter at a standoff distance of 1-2 ft.
Two No. 6 high mole cular-weight polyethylene head er cables were attached to the anode loop with a standard crimp connection with a heat-shrinkable sleeve and run to a 100 v, 15-amp rectifier.
The performance of this system was monitored with four permanent copper sulfate reference cells positioned 6 in. beneath the tank bottom, 15 ft from the outer perimeter of the tank, and at 90° intervals around the tank's circumference.
Tests show that this system performed unsatisfactorily, particularly during cold winter months. Further use was not recommended.
During the winter, the ground surrounding the anode freezes, resulting in an extremely high-resistivity en vironment. It was impossible to increase the rectifier levels (up to 100 v) during the winter months to provide adequate corrosion protection.
Method 2: replacing tank floor
Replacing the tank floor, combined with use of the damaged floor as an impressed-current anode, was the solution for Tank 111, a 180-ft diameter crude-oil storage tank at Pump Station 1 at Prudhoe Bay.
This is one of the few tanks that has no secondary containment liner beneath it. A layer of thermal insulation and protective cover, however, was installed between refrigerant coils and the tank floor.
The old tank bottom was mechanically separated from the tank by removing a 12-in. wide section of plate from the outer diameter of the tank bottom and a 6-in. wide section from around the fill and suction lines. These dimensions were chosen arbitrarily but were considered adequate to ensure that the old tank bottom would remain electrically isolated from the tank.
Separation between the old tank-bottom anode and the new tank bottom was 12 in. Sand was used as fill material.
Uniform current distribution for the tank floor anode was accomplished by symmetrically locating nine independent No. 8 high molecular-weight polyethylene ca bles around its circumference. At each positive connection point, a reinforced steel plate (2 x 2 ft) was welded to the tank-bottom anode.
The cable was connected to the steel reinforcement plate by a thermite weld process. The connection area was then encased in a nonmetallic form and the entire area was filled with a nonconductive electrical sealant to preserve the integrity of the connection.
The cables were run through PVC conduit and terminated in a junction box under an elevated enclosure adjacent the tank. A header cable was then run from the junction box to a 100 v, 60-amp rectifier.
The new tank floor, installed at an elevated level, necessitated retrofits to the inlet and outlet piping. Before installation, 12 permanent reference cells were placed beneath the new tank bottom to monitor the performance of the new cathodic-protection system. These cells, separated from the new tank bottom by 3-4 in., contained a copper/copper sulfate element.
Tests showed that the expected service performance of this cathodic-protection system exceeded 200 years, which easily met a design life of 20 years. Although further tests revealed that this solution provided the most uniform current distribution, engineers felt that the cost and time taken to isolate electrically the old bottom and install a new bottom would impose practical limitations.
They therefore recommended its use only where the old tank floor is so badly damaged that replacement is required.
Solution 3: "undertank" solution
Installing cathodic protection beneath the tank floor without removing it was the solution for Tank 220, another 116-ft diameter crude-oil storage tank, at Pump Station 12. Inspection showed that corrosion damage had occurred at the tank perimeter and that patches would be adequate.
In this system, anodes are placed in a piping network arranged in a "crow's foot" array (Fig. 3). The network is installed between the secondary-containment liner and the tank.
The challenge, however, was to find a method that would successfully install the piping network without perforating the liner or hitting the tank. Engineers could find only one system that could accomplish this, the "Bottom Logic" pneumatic piping advance system from Corrocon Inc., Nederland, Colo.
The method controls and accurately places horizontal piping networks as close as 18-24 in. beneath tank floors of aboveground storage tanks. Precise depth control of the boring head is ensured through the use of dual elevation monitors which allow the operator to "steer" the equipment (Fig. 4).
During drilling, the operator obtains elevation change information in 0.01-ft increments, enabling him to maintain an accurate course and positioning (Fig. 5). Further safety was ensured by studying tank elevation changes from engineering construction documents.
Other pushing and boring technologies without elevation control tended to drive upward toward the tank bottom, potentially causing damage (Fig. 3).
With this system, six 2-in. diameter nonmetallic slotted pipes were installed approximately 3 ft from the tank bottom in a "crows foot" array. Mixed metal-oxide anodes, 0.250 in. x 4 ft long with centralizers, were installed inside the pipe and backfilled with petroleum-grade coke breeze (Fig. 6).
Individual lead wires from each anode are terminated at a remote junction box. Within this box, shunts are installed in series with each anode lead to allow monitoring of individual anode performance.
The system is powered by a 100 v, 60-amp rectifier.
Three reference-cell insertion pipes were placed so that the performance of the cathodic-protection system could be periodically evaluated with copper/copper sulfate reference cells.
Before the completed undertank cathodic-protection system was energized, native potentials were taken at 5-ft intervals along the lengths of the reference-cell insertion pipes.
The undertank systems were then energized and adjusted to provide a desired current output. Tank bottom-to-soil potential data were again obtained from the permanent reference cells and at 5-ft intervals along the reference-cell insertion pipe (Fig. 7).
The results of the corrosion evaluation tests were sufficient to recommend installation of the undertank cathodic-protection system at other pump-station tanks containing warm product. The solution was deemed more cost effective and practical than replacing tank floors and using abandoned floors as anodes.
Although the first few piping networks were installed after the tanks had been emptied and cleaned, most are now being installed while the tanks are still in service. A permanent reference cell and reference-cell insertion piping are also installed to enable periodic evaluation of corrosion-control system effectiveness.
During this work, Corrocon developed a technique for sampling the soil underneath the tanks to help in systems design. The information enabled Alyeska to develop a data base of undertank soil conditions. The information is used to help predict corrosion rates.
The method entailed driving a sample tube at the end of the bore to obtain samples of undisturbed soil. New tooling was designed to provide that capability over a 60-70 ft distance with extremely good vertical depth control.
Growth of method
Cathodic protection of undertank bottoms has become more common in the last 20 years. Many types of systems are now widely used in aboveground tank environments to prolong tank-bottom integrity. API Standard 2610 terms cathodic protection a "Release Prevention System."
In recent years, corrosion engineers have increasingly recommended use of undertank cathodic-protection systems over the more commonly used deep well and shallow-anode ring systems.
Corrosion control experts are finding that perimeter systems often provide insufficient current distribution to an entire tank bottom and may not clearly indicate the condition at the center of the tank.
For these reasons, better protection is provided by placing anodes directly under the structure because it ensures more uniform current distribution.
Existing cathodic-protection systems can also be evaluated with reference cell insertion piping placed by such methods as the Bottom Logic casing-advancement system and the use of API-recommended methods for taking tank-to-soil potential profiles.
Once the evaluation has been completed, the same system can be used to install a permanent reference cell at the end of the PVC pipe for future periodic tank-to-soil potential measurements.
By providing adequate cathodic protection, operators of aboveground storage tank systems can extend API 653 in-tank inspection intervals, thus saving time and money, prolong the life of an important capital asset, and utilize a release-prevention method to reduce liability.
Tom Barletta is a corrosion specialist with ARCO Pipeline Co., Houston, and was recently employed by Alyeska Pipeline Service Co., Anchorage.
Rich Bayle is a corrosion specialist for ARCO Pipeline Co., Houston. He has worked in the corrosion field since 1978 and holds a BA in environmental science from Ferris State University in Michigan.
Kevin Kennelley is a corrosion specialist with ARCO Indonesia, Jakarta. Previously he was a research specialist with ARCO Exploration & Production Technology, Plano, Tex. He has also worked for Exxon Production Research and Schlumberger Well Services. Kennelley holds BS, MS, and PhD degrees in metallurgical engineering and materials science from the University of Oklahoma and is a registered engineer in Texas.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.