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The best CRAs for the job: An interview with Dan Nowak, Senior Materials and Welding Engineer

Building his career in oil and gas, military, and the energy industries, Dan Nowak has gained extensive experience using a number of different corrosion-resistant alloys (CRAs) in various sectors. Stainless Steel World Americas had the pleasure of speaking with Nowak where we learned about his role in the oil and gas sector, and how having access to various CRAs is extremely beneficial when welding components that will be used in harsh and uncommon environments. By Catarina Muia
 
The journey to today

Nowak has an extensive welding portfolio and is now working for one of the leading companies in the oil and gas industry. It all began at Ohio State University (OSU) where he obtained his Bachelor of Science in Welding Engineering. Following that five-year program, which included a year as a Teaching Assistant, Nowak attended the Massachusetts Institute of Technology (MIT) for Mechanical Metallurgy and Penetration Mechanics. He then completed his studies at Rensselaer Polytechnic Institute (RPI) with Graduate Studies in Materials Science.

“Before getting into the oil and gas industry, I had always wanted to be in energy,” he explains. “When I got out of school, nuclear was a big thing; everything was going to go nuclear.” So Nowak got his start at Westinghouse Electric Corporation, which was the biggest company in commercial nuclear at the time, before heading to the U.S. Army Laboratory Command in Watertown, Massachusetts. “I did the Army thing for three years and was in the second- oldest arsenal in the United States’ history.” The Watertown Arsenal was the Materials Technology Laboratory for the Army, which paid for Nowak to attend MIT. At Watertown, Nowak helped the Armor Team by developing armour materials and methods for welding these armours to save enlisted American lives, and he also worked with the Anti-Armor Team with the development of materials.

Following his time at the U.S. Army Lab, Nowak spent a couple of years working at Raytheon Missile Systems as a Staff Welding Engineer. After Desert Storm, Nowak began working as a Principal Engineer for the Department of Energy at the Knolls Atomic Power Laboratory (KAPL) for the Navy Nuclear Program. KAPL had paid for Nowak to attend a number of graduate study courses in Materials Science at RPI.

After completing his final courses at Rensselaer Polytechnic, Nowak decided to refocus his work in the energy industry. He wanted to use his newly-learned Superalloy Metallurgy at GE Energy, where he became a Principal Welding Engineer. There, he oversaw the materials development and welding applications for gas turbine, steam turbine, and wind turbine applications. He also worked on clean coal and Solid Oxide Fuel equipment during his 11 years at GE Energy. GE gave Nowak the opportunity to gain experience with welding exotic materials such as single-crystal nickel-based superalloys. He explains that welding these materials required exotic processes, where “preheating to a minimum 1,500°F is required so you don’t crack the turbine blade.” He adds, “We even had to hook-up air hoses inside the welders’ gloves so they wouldn’t burn their hands.” Nowak was able to provide more than 36 patent disclosures at GE Energy, where more than 20 of them were patented by the U.S., and at some oversea patent offices.

Working at GE Energy is also what opened the door for Nowak to stream into the oil and gas industry. “During my time there, GE bought an Italian company called Nuovo Pignone, which was mainly known for its small turbine and compressor manufacturing capability. However, unlike GE, Nuovo Pignone did a lot of business in the oil and gas industry. They convinced GE Energy to begin buying some upstream oil and gas equipment suppliers. Sometimes Nuovo Pignone, or one of the newly acquired equipment suppliers, would ask for help from the GE Corporate Research Division or from the GE Energy guys. So I made a number of trips to the various GE Oil & Gas facilities over a few years, to help them with welding and material issues. Typically, when I would visit, they would always say to me, ‘You know, you should get in the oil and gas industry.’ And finally I did.”

Wanting to make that transition, Nowak got a job in 2010 at GE Oil & Gas, now called Baker Hughes, a GE Company (BHGE) as the Consulting Welding Engineer. His duties were to oversee the welding, inspection, and materials used to fabricate oil and gas equipment for both upstream and downstream applications. “Most of the materials center on carbon and low alloy steels, but we also had smaller amounts of stainless steel and nickel-based alloys.”


His current role

In 2012, Nowak began at his current job as Senior Materials and Welding Engineer, where he oversees the requirements for welding various types of equipment that are used in extremely harsh environments. Essentially, these weldments need to be made with the strongest, most corrosion-resistant material possible. 

Cladding with nickel-based alloy

“First and foremost, we clad a lot of our steel products in oil and gas because of corrosion concerns. Back around 15 to 20 years ago we used to clad with stainless. We’ve moved away from that and now mainly clad using 625 nickel-based alloy, because it has better corrosion resistance than stainless for dealing with the types of corrosion we find underground. The corrosion environment underground is extremely different from the corrosion you’ll experience up here in the atmosphere,” says Nowak. “There’s one bacteria-based corrosive compound called H2S, which is hydrogen sulfide, and it’s poisonous. When H2S is in the well it is called a sour well, otherwise it’s called a sweet well. At high concentrations, you only have seconds of exposure to it, before it can kill you, so it’s very dangerous. It will also react to wipe out most steel-type materials. So when you go drilling down there and you have a sour situation, you need both optimum strength and corrosion protection. This is where the 300-series stainless steel just isn’t going to cut it.”

There are, however, a few different types of stainless steels the company uses downhole. “We basically use a modified martensitic-type alloy, which is called 13 Chrome L-80. This means the material has a minimum 80 KSI yield-strength and is corrosion-resistant. This alloy is similar to the 420 stainless steel alloy,” he explains. “A lot of what goes downhole is either 13 Chrome L-80 or a Super 13 Chrome alloy that has higher strength than the standard 13 Chrome L-80.”

Exploring 13 chrome stainless steels

The Super 13 chrome includes additions of around 6% nickel, and about 2% to 3% molybdenum (moly), to the standard 13 Chrome L-80. “The nickel is added because it gives you some good toughness, and some improved ductility. The moly is great because it makes the material’s pitting resistance go up,” Nowak explains. “So what happens is that you’ll have different flows of gas and oil and could hit a pocket of CO2. The CO2 is mixed with oil and saltwater at higher temperatures, and it acts like a paint scraper, so the chrome oxide on the surface will just be scraped away. And it’ll just continuously keep removing the oxide which will erode the material.”

Even the less heavy-duty components, such as sand screens, need to be made with 13 chrome. “We have to do a lot of screening, because the oil is basically in sandstone. This sandstone can be under a lot of pressure, which is when we get the incidents where we have oil come flying up. But you might be drilling in an area of sandstone where you think there’s oil, based on a report sample, and it’s 40 feet deep. So we keep drilling and hit another one that’s 60 feet deep. Then we keep drilling until we hit another that’s 110 feet deep. So you can have three, four, five zones where there’s oil, and then one area that’s not behaving and sand is coming up with it, which is why the sand screens are so important. But because sand comes up with your oil, it’s going to put pressure on your topside piping, and eventually the sand will start to erode the elbows and other pinch-points. Sand is your enemy.”

Standardizing valves

A big part of Nowak’s job is to deal with the suppliers who are providing downhole, subsea, and surface equipment. Nowak studies how the components function while being operated, and identifies which part of the system has failed. He then performs a failure analysis and gives the suppliers specific requirements to avoid the same problem from happening again. “However, there is always variation for how things are made across our industry, which means it’s hard to standardize across the industry.”

Nowak adds, “One thing we’re trying to standardize is the design and fabrication of valves. It’s a big thing right now. Our valve guy is always telling me about broken 17-4PH stems and improper coating on ball valves and gate valves. There is a plethora of materials that are used in valves, which can be both a blessing and a curse.”


Improving the industry

Nowak wants the industry to move forward on the proper heat treatment of materials. “When it comes to 17-4PH, a high-strength precipitation hardened martensitic stainless steel, we don’t completely change the structure during the quenching operation. This material has around 4% nickel and copper. The nickel provides toughness and ductility, while the copper precipitates out to increase the material’s strength,” Nowak explains. “However, the issue is not the precipitation heat treatment, but rather getting the alloy properly cleaned up with its initial heat treat. First, you need to heat it up to erase the variation with the grain structure and precipitation in the microstructure that occurred during forging operations, (called austenization) and then quench it in water. The quenching allows the metallurgy to change from 100% austenite to 100% martensite. The problem is that this material typically doesn’t change into 100% martensite, unless you place the part(s) after quenching, into a separate ice bath and leave it cool overnight.

You see, the parts need to get to below 60°F (the martensite finish temperature) in order for all of the austenite to transform. And as most people know, it’s pretty hard to get to 60°F in Houston, Texas. If the heat treater neglects to do the ice bath, then you’ll have retained austenite mixed in with the martensite. Afterwards, we age the parts in the furnace at a lower temperature, and the longer you age it, the more that the small copper precipitates will grow. That is, the small copper peppering in the grain structure starts to come together to form larger copper nodules, which will continue to grow if you keep it in the furnace. The longer you age it, the lower the strength and the larger the areas become between these bigger copper nodules. As a result, the stainless steel is weaker, we call this ‘over-aging’. So the biggest thing is putting the parts in the ice bath, and start out with 100% martensite (eliminating any areas of retained austenite), then you need to age it at the proper time and temperature to provide the optimum base material properties for downhole applications.”

The oil and gas industry has had a few failures in wells and in a number of valves with 17-4PH that showed areas of retained austenite. Another important issue is when the 17-4PH parts need to be welded in an assembly or welded in order to repair them from mis-machining errors. “The temperature during welding really messes up that nice copper particle size next to the weld in the base metal. Some fabricators purposely over-age the parts prior to welding. This reduces the effect from the welding heat. Then they perform the complete austenization/ quench/ice-bath/and age to the welded component or assembly to get the required material properties.”

Nowak explains that a big challenge he faces in the oil and gas industry is that the Material Test Report (MTR) that comes with the 17-4PH purchased part, only states that the parts were quenched. They do not identify if the parts were placed into an ice-bath for additional cooling. “Requiring the heat-treat suppliers to place all 17-4PH components in an ice-bath overnight, would significantly help to reduce the failures that the industry has seen with this material,” says Nowak.

Presently, most oil producers have alternatively substituted alloy 718 or other precipitating nickel-based alloys for the 17-4PH, however this change drastically increases the cost of the component by close to 20X.

 

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