The following is a conversation between a Washington state regulator and Cal Chapman about corrosion protection for underground fiberglass tanks.

Initial Question:

CP testing of Fiberglass Underground Storage Tanks – a Washington State regulator in field, asking for help in data interpretation:

I'm baffled here folks. I was inspecting an UST yesterday and found they were behind on CP testing. I opened the sump and found what appeared to be an Owens Corning fiberglass UST. The last test was good. I tested for continuity and protection. All meet criteria. Has anyone tested a fiberglass tank and got acceptable CP results? What is the cause of this? Most likely there is a metal strike plate inside the tank, which is where I made contact. Thanks.
 
Possible Answers and Other Info from Cal Chapman:
 
Jason, you've already had a lot of good comments offered.  Here are some other, fairly general points to take into account. Before 1978 or so, UST's were just about always steel with simple coating on the outside, unless they were true Owens-Corning fiberglass tanks which were brought out in early 1970's, I believe.  As has been pointed out, fiberglass tanks must have a steel striker plate, or taking stick readings for fuel levels would, sooner or later, punch a hole in the tank. That striker plate, though, is usually encased in fiberglass; you can get a magnet to stick to it, but you're not supposed to get a metal-to-metal contact. And even if striker plate is exposed, the rest of the tank's fiberglass body is completely non-conductive, so with a fiberglass tank, you won't ever get a "structure-to-soil" CP reading from that tank structure to the surrounding soils.

Around 1978, too, the first "Steel Tank Institute P3" (STI-P3 design) tanks came out. They were steel inner shell as the real structure and then had a complete fiberglass external "wrap" for coating, that was supposed to be at least 20 mils thick. Then they had a couple of magnesium anodes attached at factory, which were supposed to be un-bagged and put in native soil contact during tank installation (installers sometimes forgot to take the plastic off, and these anodes never were allowed to give protection to tank!).  Those mag anodes would then give you continuity to electrolyte/soil, for any CP measurements done over life of this kind of tank.  Even if the anodes were completely consumed, you had copper wire touching off to soil. CP readings on STI-P3 tanks are usually easy to get and fairly easy to interpret.  You either get/got really negative voltages, meaning magnesium was doing its job and very little of the tank metal was in electrolytic contact.
 
Reviewing your later points and Derek's questions and points, here are a few more things to consider.  And, yes, I've been around UST systems since late 1988, first doing leak detection and then assessment/cleanup, and then CP.  If you think you're getting an actual tank reading, it's not the tank -- you're proving up that tank structure is fiberglass.  But all manners of grounding structures, metal conduits for electrical runs, possibly steel vent line, the power brought to sub pump (consider both AC ground which could connect back to other metal in area, AND AC neutral wire that can be cross-connected to ground in on or more places), even rebar in or under concrete slab can give you electrical connections you don't expect.  And you're right to be considering copper or brass tight-fill adapter as a separate metal from steel.  Mixed-metal contacts measured in comparison to the CSE won't always give us the answers we figure we should see.  I think you may have a few metal structures electrically contacting one another.  Main question you and the UST owner/operator face: what fuel system components are susceptible to corrosion AND routinely contain fuel? They require CP.
 
Interestingly, the regulators in 1984 through present wrote a dumb approach into the rules (my opinion).  They required electrically isolating steel pipe risers from tank structure, during tank system installation.  For STI-P3 tanks, or the later "ACT 100" design tanks (after about 1990 or so, the fiberglass wrap over steel tank was made at least 100 mils thick, and then no CP was required on the tank long-term), this meant the tank installer did not keep steel tank metal and the metal riser structures electrically continuous -- I would much prefer that these pieces of steel are kept continuous at installation.  What we have seen countless times is that risers need CP, and the tank metal needs CP.  But they are not electrically connected. And there are no inexpensive ways to bond these various risers and tank metal together, to apply CP to an entire metal unit -- whether that's one tank and appurtenances, or several tanks, with risers, submersible pumps, etc. So to protect all components which routinely contain fuel (the way the rule reads), you have to decide whether each riser really needs and gets CP.

What this means is that you might measure "structure to soil" voltage between half-cell and one riser on tank, and get a particular reading.  Then you measure on a different riser, and get a different reading.  You can measure on vent pipe, which may be steel, and get yet another reading.  Now, does this mean all these pieces of steel are screwed into a steel STI-P3 or ACT-100 tank, or into a fiberglass tank? You don't know yet.

To truly determine type of tank is tough.  If you can figure out tank diameter, often done by pulling drop tube and then measuring both total depth to tank bottom, and the depth of riser to tank top.  If you get a diameter that belongs to fiberglass tank, usually much different from typical steel tank construction dimensions, then you know what you have.  Or you can get magnet and bond wire stuck to bottom inside of tank, and apply some current (safely, please) to look for voltage shift on all metal "touch points" accessible on outside of tank/tank system.  If you get shift, you are electrically conductive and tank must be steel, AND it must have conductive path of that steel to soil side.

Much to talk about, certainly.  And my one question is this: you say that in sub pump sump, you could see that the Owens-Corning fiberglass "ribs" were present -- I presume that's what you took to mean the tank was fiberglass, for sure. But the striker plate would not give you a metal-to-metal contact with anything on outside of tank.  As we see from your photos just provided, the metal pipe risers for fill and ATG are both in contact with soil on the outside.  These will give CP readings compared to half-cell, regardless of whether tank composition is metal or fiberglass.  It looks like you are testing risers only.  And there may not be any other metal involved.
 
Regarding the water across bottom of tank being conductive and tying other steel into CP circuit, it would have to be a little on the salty side to be conductive enough.  If the product in tank is gasoline with ethanol, then the water on tank bottom has significant ethanol dissolved in it.  Ethanol much prefers to be in soluble combination with the water and preferentially moves from the gasoline (non-polar liquid) to the water fraction. This should mean the water/ethanol conductivity is much greater than fresh water. So that would make it possible for your copper wire and screw on bottom of your stick to have electrical contact over to the ATG probe.  But probe grounding contact is then somehow connecting back to everything else . . . that I'm not wrapping my head around; the ATG probe should generate a DC signal which is hard-wire-sent back to ATG console. That DC ground is likely same as electrical ground for the ATG system -- which needs robust and separate grounding, in addition to the AC-related grounding.

The Eagle Ford Shale region of South Texas has been booming with a huge amount of oil and gas exploration, construction of infrastructure, and massive job creation. Similar things are happening in other Texas oil shale plays such as the West Texas Sprayberry, Wolfcamp, Cline, and Haynesville. Similar booms have been happening in the Bakken of North Dakota and Montana, Niobrara/DJ Basin in Colorado, the Marcellus and Utica in Ohio, Pennsylvania and West Virginia, and other successful oil and gas plays.

Any business doing oil and gas exploration, drilling and production should protect its assets from corrosion.  These include wells, pad equipment, pipelines, bulk storage and processing facilities, and other expensive infrastructure.  These companies must pay attention to corrosion of the assets they own.  There are at least three major issues with this new infrastructure, just related to external corrosion.

Designers and construction crews need to plan for, and then install a good-quality, well-adhered protective coating on metal that will come in contact with soil or water. The metal should be completely covered by this coating to help prevent external corrosion. 

The construction and installation work must be professionally inspected to ensure that coatings are applied properly, AND are not damaged during transport, fabrication, installation, burial, and so on. Chips and scratches in coating can happen if pipe is not loaded on to trucks correctly and by poor-quality installation.  If damaged, coating should be properly repaired.

In addition to coating, owners of oil and gas assets need to get good cathodic protection systems installed and maintained.  These serve as a second “line of defense” against external corrosion. This protects the metal exposed by the remaining holes in coating that go undetected and unrepaired, often called “holidays.” No coating job is perfect, and all coatings degrade over time. For steel tank bottoms, no coating is typically used at all, so these structures need larger cathodic protection systems designed, installed and kept operating long-term.

Cathodic protection is done by building a low-voltage, DC electric circuit that connects to a set of anodes buried in soil, and to the structure needing protection. This causes the tank bottom, pipeline, or other subsurface structure to become a strong cathode. Anodes get consumed by corrosion over time, while cathodes are protected from corrosion for as long as this electric circuit is working properly.  Cathodic protection systems, when properly designed and installed, do a great job of minimizing external corrosion.

In the Eagle Ford Shale region, as well as others, there are different properties in soil and shallow geology that cause corrosion to speed up. One is very low soil resistivity, a measure of how easy it is for Mother Nature to flow electric current across a piece of metal in the soil. The more current flows, the more steel (if the structure is made of that) corrodes over time.  As a glaring example, the photo below shows a portion of a weld joint that coupled together a pipe joint and a 90-degree elbow.

Corroded weld in a section of pipeline.

This steel elbow had been installed less than three years before the corrosion pitting caused a leak. The crews who welded, then coated and buried this piece of steel did several things wrong.

Number one, the welding job was not properly done.  Number two, the metal was not properly cleaned before the field-applied epoxy coating was mixed and laid on over the weld area. This meant the coating was not properly adhered to the metal, so moisture was able to get under the coating and directly to the metal. This is kind of like applying band aid to wet skin.  It just will not stick properly.  The third problem was with the epoxy coating.  It was not cured properly before the pipe and elbow were placed in the ditch, and then backfilled. The coating was ripped, punctured and wrinkled in many areas. Finally, this pipeline portion was apparently not given cathodic protection for at least part of its service life.  All of these negative factors combined to cause a leaking pipe.

Soils in contact with this steel were extremely low in resistivity, and very salty. The more chemical ions are present in soils and shallow geology, the easier it is for electric current to flow. This land was actually under shallow seas a very long time ago. Anyone who has spent a winter in the north is probably familiar with salted roadways.  Automobiles pick up salt from roads, and if not kept clean, the steel frame and skin are going to rust.  Dings in paint will expose metal, which then rusts from the salt contact.  For this pipe, the combination of water, salt and electric current flow caused several ounces of good steel to turn into rust in one severe pit. Once that little tiny hole opened in the pipe wall, oil under pressure began flowing out of the pipe and into soils. The leak was discovered by pipeline personnel soon afterward.  Not only is an oil leak bad for the environment, it could also cause a fire and severe public safety hazards.

Coatings are the best investment anyone can make to protect against external corrosion. When selected properly, and put on a clean, prepared metal surface using the right procedures, coatings provide great protection to 95 percent, 99 percent, or even more of that external metal surface. It’s just like putting a good paint job on your car or truck. Having said that, every metal structure in contact with soil or water also should ALSO have a properly designed and installed cathodic protection system. NACE International, the leading corrosion protection organization in the world, specifies that coatings and cathodic protection are both required, for a certain piece of metal infrastructure to provide full service life.   Good coatings and cathodic protection represent up-front investments, rather than a costly bunch of repairs down the road.

Any company with assets in the ground should do solid research on coatings, cathodic protection consultants and contractors. Many practitioners of coatings work and cathodic protection try to use “one size fits all” approaches. They don’t take into account conditions local to the job site. They may not consider the nuances of a particular project and its geography, topography, geology, soil science, and construction plans. If a $50 million plant or pipeline is being installed and is supposed to give a 30-year service life or longer, make sure that a little more money and attention are spent at the front end of the project.  Get appropriate coatings selected and applied. Get a quality installation.  Make sure qualified inspectors are overseeing the work.  Have a high-quality and appropriately designed cathodic protection system built and operating.  Make sure there are enough test stations or other measurement points built into the system.

Looking back at the pipeline elbow photo shown earlier, think about how much money this one incident probably cost. Money had to be spent because of an oil leak and there was an environmental cleanup to be carried out. Some of the pipe had to be replaced.  The pipeline operator also needed to stop the flow of oil and that caused lost revenue.  All that had to be done before the repair and cleanup could even take place! Down-time is a huge cost. But it’s not necessarily the worst cost. What if there had been a fire, and injuries, or a major spill rather than a small leak?

The lesson leaned? If proper procedures had been followed when making the weld and coating had been properly applied, this may not have become a problem.  Further, if an appropriate cathodic protection had been in place, a leak would have been prevented.  If good inspectors had been involved to check all this work during construction, this leak may not have occurred. The pipeline operator could have continued normal operations and could have saved a lot of money.

Chapman Engineering – protecting assets and the environment since 1989.

There are miles and miles of underground oil and gas pipelines across the country.  There are very high concentrations of pipelines in the Eagle Ford Shale in south Texas and other oil shale plays.  Over time many miles of pipe without corrosion protection systems in place will corrode.

This is an image of our booth at the Central NACE Conference in St. Louis this week.  The yellow unit is the C-Scan equipment. 

The C-Scan survey, done with proprietary tools supplied by only one vendor worldwide, consists of applying an AC electromagnetic signal, or current, to a pipeline through a conductor attachment.  In the same general area as this conductive attachment, an electrical ground is also established in soil 50 to 300 feet away from the pipeline under study.

The signal generator is then turned on and current “signal” applied to the pipeline.  The C-Scan detector is then walked down the pipeline, and measurements of an electromagnetic field strength coming from the pipeline are made.  C-Scan provides GPS location information on pipe centerline to what is usually sub-meter accuracy.  Of even more value, it gives “depth of cover” information to the nearest inch, and can reliably identify “top of pipe” or “center of pipe” to depths exceeding 30 feet below grade.

As one surveys down the pipeline, multiple antennas in the detector provide the amount of signal loss, compared to the original signal strength at the first test point.  Between a previous test point and the newest test point, average coating conductance and signal attenuation are computed.  Within each pipeline interval “bracketed” by test points, the operator can compare whether the pipeline coating across that interval has shown the same characteristics as other sections, or if more signal is lost, and coating conductance “averaged across” that section is poor.  If this is the case, additional measurements are taken in smaller pipe-length increments.  Using this technique of multiple segments, and then using a “Current-Only Close-Interval Survey” with the same tool, a particular coating defect can be pinpointed to within feet or inches, from “top centerline” position over the pipeline.

C-Scan should be performed on a pipeline that does not have current-interrupted CP survey being done at the same time.  It may also have interference from high-voltage AC power line fields.  Otherwise, this survey is applicable in any case where a reasonably well-coated pipeline is in use.  If a pipeline has very poor coating quality, or is bare, the signal loss is so rapid that meaningful coatings anomaly information is not likely to be obtained.

With the current price of oil so low many oil and gas exploration companies have cut back on drilling.  Since they are not spending money on drilling and building additional pipelines this might be a good time to hire Chapman Engineering to do C- Scan surveys.  The money that had been budgeted for exploration should now go toward protecting their assets.

Contact Chapman Engineering at 800-375-7747.

The Eagle Ford Shale has been very active in terms of oil and gas exploration since 2009-2010.  Pipelines have been installed in record time.  The metal pipe has a corrosion protection coating on its exterior.  Many times this coating gets nicks in it during installation.  These nicks can cause rusting pits into the pipe wall over time.  It’s possible for a pit to go completely through the wall, and then there’s a leak.  Sometimes the integrity of the welds that hold sections of pipe together is not quite right, and it’s possible that the coating over welds is not applied the right way.  These problems can cause severe corrosion over time as well.

Chapman Engineering has equipment that scans pipelines, whether above ground, below ground or under water to look for anomalies in the pipe.  These anomalies can lead to corrosion, but more on that in a future blog post.

 This is a test station installation.

To protect pipelines and other buried metal from corrosion, Chapman Engineering installs corrosion protection systems.  These systems are more often referred to as cathodic protection systems.  A major part of every cathodic protection system is the anode bed.  Chapman Engineering field crews have holes drilled in the ground near the pipelines to be protected.  They drop anodes in the holes and attach wires from each anode to a bonding point on each pipeline.  Then they bury the anodes.  Each anode acts as a sacrificial metal, meaning it will corrode over time.  As it corrodes, it provides a protective electrical current to the pipeline metal, thereby minimizing pipeline corrosion.  Once installed, the anode bed might protect the valuable oil and gas pipeline company’s assets for up to 20 years.

Oil and gas pipelines are not the only assets that need cathodic protection.  Any metal that touches soil or water should have cathodic protection.  That can be underground or above metal storage tanks.  It might be a natural gas distribution system in a small town, or in an apartment complex.  It might be a storage building, or it might be reinforcing steel in concrete.

Corrosion in a pipe.

Corrosion is basically an electrochemical process, meaning there is an exchange of electrons from the metal of the pipe into the environment.  Some soils are more corrosive than others, so each anode bed must carefully designed and installed  based on soil types and other factors.  Cathodic protection systems involve the application of an electric current to offset the flow of electrons otherwise lost in the corrosion process. 

This is a rectifier, which makes AC power into DC power.

A piece of equipment called a rectifier can apply this current to the anodes.  In remote areas in which electricity is not available Chapman Engineering crews have installed solar panels for electrical power.  The anodes give up electrons which flow to the pipe where they provide protection.  So each anode slowly has its metal sacrificed to protect the pipe. 

There is more to the process than this, but this should give readers a basic idea about cathodic protection and how it is used to protect metal assets.