During my visit to Alicat® Scientific’s Tucson headquarters for a product training event, I had the opportunity to sit down and discuss​
how digital, intrinsically safe devices are transforming the work I do in process automation. ​Over the years, the shift from LNG import to LNG export in the United States has driven major infrastructure changes. That transition increased the industry’s need for safer, more automated measurement and control systems. Working in hazardous oil and gas environments means safety is always a priority. We rely on strict protection methods, and intrinsic safety has become the preferred approach because it allows instrumentation to operate directly in Class I, Div 1 areas without bulky enclosures or complex purge systems. Today, digital, multivariate instruments that provide real-time, actionable data are shaping the future of the industry. These tools improve reliability, streamline operations, and move us closer to predictive, data-driven control in process analysis.
​
​
​
​
​
Q: Bobby, you’ve been in process automation for a while now. Can you start by sharing a bit about your background and how you’ve seen the oil and gas industry evolve?
​
I’ve been in the industry since about 2007. I started with a rep firm handling analyzer and instrumentation products, worked for a few manufacturers after that, and eventually founded Kaizen Controls & Automation.
Early on, we were building LNG import facilities—heating gas from overseas and pushing it into U.S. pipelines. Then fracking changed everything. Suddenly, we were producing so much natural gas domestically that we had to redesign import terminals to become export terminals. That shift rippled across the whole industry. The new infrastructure required updated measurement and control systems, and that’s really where safety, accuracy, and automation started to overlap in a big way.
​
Q: Most of those environments are hazardous. How does the industry account for safety?
​
Right, most analyzer shelters in oil and gas are in Class I, Div 1 zones, so you assume flammable gas is present.
There are three main ways to protect the equipment: purge and pressurization systems that push clean air through the enclosure, explosion-proof housings that contain any internal ignition, and intrinsic safety. The first two work, but they’re heavy, expensive, and not easy to maintain. Intrinsic safety has become the go-to method. You limit the circuit energy so even if there’s a fault, there’s not enough power to cause ignition. Instruments like Alicat’s IS‑Max™ and IS‑Pro™ series are good examples—they’re designed for use directly in hazardous zones without needing purge panels or explosion-proof boxes. That saves space, reduces the number of leak paths, and simplifies compliance.
​
Q: What makes integrated flow and pressure control more reliable than traditional setups with separate components?
​
A big part of it is taking out the old mechanical devices—rotameters, regulators, variable-area meters. Over time, they stick or foul, especially if you’ve got waxy hydrocarbons or particulates in the line. From the outside, the float might look like it’s sitting at the right flow, but in reality there’s nothing moving. And that’s where the human factor comes in. A maintenance tech might be responsible for 20 or 30 square miles of analyzer stations. They drive by, glance at that rotameter through the glass, and think, “Looks good.” Meanwhile, the analyzer’s getting no sample and drifting out of spec. ​With an integrated digital flow controller, or a digital pressure meter, you can see the actual flow and pressure values on screen or in the DCS. Because these devices have measurement and control are in the same body, the feedback is instantaneous and accurate. Multivariate devices that report parameters like flow, pressure, temperature, and totalizer give a lot of visibility in a sampling loop running every few milliseconds.
​
Q: How does that digital control compare to pneumatic or manual systems still in the field?
​
Pneumatic systems are reliable but limited, they’re slow to react and don’t give you feedback. With digital control, you’re getting precise, repeatable response and diagnostic data in real time. Modern intrinsically safe instruments can sample hundreds or even a thousand times per second, so they catch transient changes before they reach the analyzer. You can monitor or adjust setpoints remotely through MODBUS RTU or a simple analog 4 – 20 mA signal and that’s what operators expect now—fast, stable control with lots of visibility.
​
Q: Maintenance seems to be a recurring challenge in these manual systems. What would it look like to replace them with digital solutions?
​
Maintenance drops off considerably. Mechanical regulators drift, rotameters foul, and valves gum up over time. Many plants rebuild or replace them on a set schedule—every year, sometimes sooner. Plus it’s dependent on the process, right? If you’ve got something that kicks up a lot of dust and dirt, that grime transfers onto the devices. I’ve had situations where customers are fine with that, but others require some level of guarantee that their devices won’t be compromised because of the surroundings. With regards to these [intrinsically safe] devices, you’ve got fewer moving parts and no glass tubes or floats to clean. They hold calibration longer and are usually rated to IP 66 or higher, so dust and moisture aren’t a problem. The added diagnostics help too, because you can often spot a developing issue remotely on your system before needing to actually go out to the device and troubleshoot.
​
Q: Installation time and complexity are another major cost driver. What does that look like in practice?
​
In a typical analyzer shelter, you might have separate transmitters for flow, pressure, and temperature. Each needs its own mounting, conduit, and wiring. That adds up, especially when you’re trying to minimize the time a team spends in a classified area. Integrated intrinsically safe [electronic] controllers simplify that. You’re mounting one instrument instead of three, pulling one set of wires instead of several. For large sites, that can mean the difference between a multi-day installation and one that’s done in hours. And since the control signal can be digital or analog, they fit into existing DCS architectures without re-engineering the system.
Q: EPA compliance puts a lot of pressure on analyzer reliability. How does flow and pressure stability factor into that?
It’s everything. Most EPA rules like Quad O (EPA 40 Code of Federal Regulations, Part 60, Subpart OOOO) or Refinery MACT require at least 98% uptime for analyzers. If your sample system isn’t stable, you can’t meet that, and you could get the book thrown at you. For flow and pressure stability, fluctuating pressure or inconsistent flow will throw off readings and calibration. In systems that do flaring, backpressure spikes can push gas back into the analyzer and corrupt your data. If you have fast, closed-loop digital control, you can maintain steady flow and pressure so the analyzer always sees the same conditions and that consistency is what keeps you compliant and avoids penalties.
Q: Intrinsically safe digital control seems to be reshaping how sampling systems are designed. What's different now compared to ten years ago?
​
Absolutely—the technology has evolved, but just as importantly, so has the industry’s mindset. We’re moving toward automation and remote operations, which means fewer people in the field and a much stronger focus on systems that can, more or less, take care of themselves. Ten years ago, if you needed instrumentation in a hazardous area, you were almost guaranteed to rely on bulky explosion-proof enclosures or purge systems. Those worked, but they added complexity and a lot of hands-on maintenance.
Now we’ve got digital options, like intrinsically safe devices and IS‑series instruments, that can sit directly in the hazardous zone without all that extra infrastructure, you can still interact with them during operation if needed, but maintenance becomes far easier—no specialized enclosures to open, no purging routines, and far fewer site visits just to check basic readings.
Q: Looking ahead, what’s next for process analysis and control?
​
The next step is intelligence, using all this new data for predictive operation instead of of reactive. If you know when something is going to go wrong before it does, you can save uptime and cost.
At the end of the day, the goals haven’t really changed, the industry still wants to keep people safe, keep analyzers accurate, and keep uptime high. What’s changed is that we finally have the tools that make all three of those things easier, while being remote.
I believe the future is data, and the only question now is how far we can push what we do with it.
Q: Thank you for your time, Bobby.
​
Of course, thanks for having me!
​
Disclaimer: The descriptions and viewpoints expressed above are for general informational purposes only and represent my professional opinions. Hazardous area classifications, safety requirements, and installation standards vary by facility. For site-specific evaluations, compliance questions, or engineering guidance, please contact your safety engineer or an authorized hazardous-location specialist.
​
​
​
