Comment from Joe Pikas

And Now the Rest of the Story – SP0169
NACE Central Area Conference, Corpus Christi, TX – 10-17-10

From the NACE Beginning
Let’s start with the history behind this legendary first standard produced by NACE in January, 1969. No let’s start a lot earlier in 1943 when NACE was formed in Houston, TX. Why 1943 in the middle of World War II and why Houston, TX. We could all agree that chemicals produced, pipelines serving the war effort, the Gulf environment above and below ground, operating temperatures, lack of industry standards, and did I mention the number of leaks and failures which brought this group together. “The perfect storm or the perfect venue; take your choice. Even during this massive war effort and the hiring of over 50,000 engineers, technicians and laborers to build atomic facilities to produce plutonium around the country; there were a number of smart guys who decided it was the time to start a corrosion society in this time of distress in our country. It was truly amazing that this occurred.
War is over and no standards?
What happened to NACE from 1943 to 1969? What happened to your “I Like Ike” political buttons as he fell asleep at the wheel and played golf in the early 50’s? NACE held annual conferences almost every year except during the early beginning due to the war effort. Where did all the smart guys go or do for a quarter of a century? Were we still celebrating the big ONE? What about the Korean conflict. We built the Little & Big Inch pipelines from the Gulf Coast to the Northeast only to be followed by many other others, by the way which are still in existence. Why 1969, we were still celebrating largest hippie gathering in Woodstock, NY? What more leaks and failures? Where were the standards? Were NACE and IKE on the same agenda? No wonder the flower power people took over.
Yes it took an act of Congress called the “Pipeline Safety Act” to get the wheels in motion. Was Congress finally doing their job? NACE is finally called to the rescue and to produce a standard by an organization called the Department of Transportation – Office of Pipeline Safety - Wow. How good can it get?
It’s Time to Start Your Engines
With a little nudge from DOT in preparing the Pipeline Safety Act for natural gas lines and certain companies like Transco and Tennessee Gas experiencing SCC failures back in the 60’s, NACE was encouraged to come up with a set of criteria for cathodic protection in a standard. A group of industry leaders including one of my old bosses Sal Bellasai were on the original committee to write this standard. Using their experiences and what worked in the field, they came up with a set of (field) criteria consisting of:
• -850 mV with the protective current applied (IR drop considered)
• 100 mV of polarization
• 300 mV shift
• Net protective current
• E-Log-I
Did these criteria complement each other? Yes. Did they oppose each other? Yes How can that be?
However, today, we have 3 criteria consisting of:
• -850 mV with the protective current applied (IR must be considered)
• -850 mV polarized
• 100 mV of polarization
Yes they also compliment and oppose each other just as the five criteria. But now we deleted 3 and added another -850 criterion (dueling criteria). How can that be? It goes back to the NACE Las Vegas Conference and what goes on in Vegas stays in Vegas. As you know the fight never ended back in the 60’s or the mid 90’s i.e. similar to the Korean Conflict. But somehow we were able to compromise and come up with solution after years of infighting. I cannot put this in words how this came about, but it resulted in some backdoor political compromises in the Frank Sinatra room. Just like Frank’s NY, NY; NACE makes it to Broadway with dueling -850s.
If each of these supposed criterion can oppose each other, then there must be other factors that are influencing the results. Yes, we all heard of shielding, disbondment, AC and DC interference, MIC, temperature, age, type and condition of coating, corrosive soil and electrolytes and other environmental factors. Then one must postulate that none of these criterion has an confidence level since most of the unknowns were not taken into consideration as shown in these limited number of examples.

1. A pipeline in NC exhibited a -1400 mV ON and -1100 mV OFF with several hundred millivolts of polarization yet continued to experience leaks. The coating was a single wrap of cold applied tape with minimal primer, experienced soil stress, experienced poor application and the pipe was pre-70 ERW. Yet the operator concluded and continued to state that the line was fully protected even after each of the leaks occurred.
a. Did the operator meet the criteria for cathodic protection, Yes? Was the line protected, No.?

2. A pipeline in AL exhibited a -1300 mV ON and -1050 mV OFF with several hundred millivolts of polarization, yet a catastrophic failure occurred 2 months after a close interval survey was taken. The coating was a coal tar enamel over the ditch application, experienced soil stress, never had CP for the first 5 to 6 years, was in a low spot with poor drainage and had a history of SCC. This operator continued to show that the line was fully protected even though there was a history of SCC and no CP for five years. Everyone thought that it was SCC; however, the failure was attributed to MIC.
a. Did the operator meet the criteria for cathodic protection, Yes? Was the line protected, No.?

3. A pipeline in North TX exhibited -1200 mV ON and -1000 mV OFF with several hundred millivolts of polarization, yet they were experiencing leaks in less than 10 years of operation. The coating was FBE, with hot applied sleeves, soil stress and poor drainage. The choice of sleeves was poor along with some application issues, but the weak link was wrinkling due to soil stresses.
a. Did the operator meet the criteria for cathodic protection, Yes? Was the line protected, No.?

4. A new pipeline in Gulf region of TX exhibited structure to electrolyte potentials of -1400 mV ON and -1100 mV OFF with several hundred millivolts of polarization, yet the operator was experiencing indications from the in-line-inspection results of pitting. The line and joints were coated with FBE and installation of the pipe was excellent. The coating was inspected in several areas and there was some minor pinholes, minor blisters with high pH and everything appeared to be in accordance to industry standards. Why the pitting? It was near an AC high voltage line. This line was in a rights of way with many other pipelines, but they were not experiencing this issue. The soil resistivity was in the order of 250 ohm cm and it only takes several volts of AC to start AC corrosion on a FBE coated line.
a. Did the operator meet the criteria for cathodic protection, Yes? Was the line protected, No.?

5. Conversely, let’s take a pipeline in South Texas where the structure to electrolyte potentials of -750 mV ON and -600 mV OFF. The coating was an asphalt enamel and was in poor condition and current requirements were extremely high. Everything about this line was as bad as it gets including some rock in the backfill. A direct examination revealed minor corrosion of less than 30 mils. Did I fail to mention the static potential was -250 mV and this line had several hundred millivolts of polarization, it was a dry environment and was 55 years old?
a. Did the operator meet the criteria for cathodic protection, Not in accordance to PHMSA? Was the line protected, Yes
b. It experienced less than 1 mil of pitting per year. Did it look and smell bad, Yes. However, the pipe had integrity, with little or no corrosion.
I can give hundreds more if not thousands of everyday examples of how pipelines operate with similar problems Criteria were designed to be guidelines not harden rigid rules. Why, because there are too many factors and unknowns that should be taken into consideration but are not. Basic tribal knowledge about the pipeline and its environment needs to be known. It is like driving your car in the rain with bald tires. We cannot use a criterion such as the dual -850s without knowing what is underneath the ground like the conditions of the tires. Does the pipe have any tread (coating) left. Has anyone kicked the tires or bent over to look in the ditch to see what is going on. There are companies who refuse to look deep into their systems and come to understand that shielding, MIC, interference; aged coating systems, corrosive soils, etc. are the issues and not the criteria. Then they make the bold statement, we are just going to move to -850 mV polarized criterion to make the material suppliers, contractors and others happy. What they don’t understand is that problem will not be solved. A lot of investment but little improvement in safety.
The SP0169 committee needs to recognize that these field guidelines called criteria are only as good as they fully understand the factors that really impact the integrity of the pipeline. If integrity issues are not part of the criteria, then how could we protect these lines? Any criterion will work as long as the tribal knowledge exists about the pipeline and its environment.
Recommendations:
• Get away from the simple single criterion values or numbers
• Set up system consisting of Confidence Factors (CF) or Risk Assessment (RA) Weighting
o A factor of 1.0 would be a verified laboratory test of a pipe specimen with a specific environment.
o Example of Factors that would influence readings – You the operator would set the weighting factors based on experience, environment, history for the specific pipe segment or plant setting:
 Type, condition and age of coating
 Isolated or grounded to power neutral or plant
 When CP was first applied (within 1 year, 2 years, etc.)
 How many lines in rights of way (1, 5, 25, 100, 150, etc.)
• Bonded, separation distance, stacked, etc.
 Number bonds and current drain to foreign lines
 Current Density to protect pipeline(s) for a specific coating, pipe diameter, length, etc.
 AC/DC interference issues
 Shorted to ground neutral, plant piping, casings etc.
 Type of CP – Impressed, Galvanic, etc.
 Environmental – resistivity, corrosivity, pH, temperature, MIC, etc.
 Plant environments
• Grounding
• Mixed metals such as copper, galvanized and stainless
• Other nearby structures
o Conduit, Rebar, Tubing, Piping Runs, etc.
 History of leaks or failures
 Other – specific to this pipe segment or plant piping
• Get Out of Jail Free Card to offset Confidence or Risk Factors
o Pigging runs with little or no corrosion
o Other technologies such as guided wave with no corrosion
o Direct Examinations at areas of concern that validated structure to electrolyte readings
• Fully understand the integrity of the pipeline system and integrate this tribal knowledge with Corrosion Control Activities and
o History
o Construction and installation
 Inspection records
 Hydro test
o Coatings (Line pipe , Girth welds and fabrication piping)
 Type
 Condition
o CP levels
o Type of Pipe, WT, SMYS, Toughness, etc.
o Operations
 Temperatures
 Pigging Operations(Smart and Cleaning)
 Patrolling Activities
 Excavations
o Get out of the chair and get back in the ditch and really find out what is going on - involvement
o Let’s end the conflict and polarize the pipe not each other.
o No excuses, just old fashioned progress
PS
Did I fail to mention that DOT did not reference the original NACE RP0169 into the Pipeline Safety Regulations 49 CFR 192 Gas Regulations Appendix A back in 1970? ASME, API, ASTM and others were referenced but not NACE. However, DOT did create an Appendix D to Part 192 “Criteria for Cathodic Protection and Determination of Measurements”. The criteria were taken from then RP0169 along with the accepted measurement practices but no mention of NACE.
Does any know why?
If you were not at the NACE Central Area Panel Discussion in Corpus Christi, TX, the answer is that this was NACE’s first document after 26 years in existence with a little government prodding to get NACE to produce RP0169. However, it was not without controversy even at that time (IR drop is nothing new). Now we now understand this situation due to the many variables that are encountered in the right of way or the plant environment to achieve an indirect measurement to meet one of the criteria. In addition, API, ASME, ASTM was already established and had credibility, whereas NACE was finally taking their first baby step to establish standards. We have come a long way by the number of standards produced.
Note:
The above does not represent the view of any of my present or past employers (either operators or corrosion engineering companies), clients, or peers within the industry. These view points are based my 44 years of experience and findings on the many pipelines that I worked, studied and analyzed throughout the USA and the world.
Thank you,


Joe Pikas
Mobile - 832 758-0009
E-mail - jpikas@schiffassociates.com