Founders of Fluid Components Int’l (FCI)
FCI: The Early Years, as told to Flow Research by co-founder Mac McQueen
Note: Questions (Q.) are by Jesse Yoder of Flow Research. We would like to thank both Bob Deane and Mac McQueen for their help and cooperation in conducting these interviews.
Mac McQueen: The way this got started, I had worked for the Whitaker Company, and as often happens, people bring ideas to companies for possible exploitation. One of the first inventors of thermal flow switches came to us and presented his material to us. I recommended that we not pursue it at the Whitaker Company at that time, because of all the variables involved in the thermal properties of different fluids and gases, and it seemed not too good of a way to go, considering the conditions and atmosphere at Whitaker. So initially I recommended against doing thermal flow switches.
As opposed to our more recent flowmeter, a few years later Bob Deane came to me and told me that there was a need for a flow switch in the oil industry – production department. I thought about if for a week or so, and got some ideas and had Bob come over and discussed those ideas with him. Together we came up with a method of demonstrating how this thing would work, using a candy thermometer, a stainless steel mixing bowl, and a soldiering iron heater. This humble combination of devices was used to demonstrate the operating principle used to determine oil well function and production. As noted above, the above flow switch activity greatly preceded our more recent thermal flowmeter activity.
(Photo by Flow Research)
Q. What year was this?
This was 1964. So initially we started out in this field doing flow switches as opposed to flowmeters. It wasn’t until 1981 that we got around to entering the flowmetering field, and then it was only in gases.
Among the ideas I was tossing around for solving the oil well problem was thermal because although I had first recommended against it, there were some things about this application – it was oil and water, or emulsion of oil and water, and sand, and really a hostile environment where they would occasionally get very high velocities of congealed oil and ice and sand and rust, and anything that would come up out of the ground. The application was in Bakersfield, and occasionally a snowstorm came through and virtually froze the field up, temporarily, at least. But the pump didn’t stop; they kept pumping away, and the whole production string was slowly filled largely with high-pressure gas. Then the sun would come out, and it wouldn’t melt the whole plug; it would just melt the part that was stuck to the pipe. So here comes this plug of ice and sand and gravel and every imaginable thing, including cats and dogs and so forth, howling past the sense point at Mach One. It had a couple thousand psi gas pressure drive. Finally when the plug would purge itself and here would come this blast of gas out of this thing at a high mach number, carrying abrasive particles.
So the application required something that was very rugged, and yet very sensitive, because they wanted to sense two barrels a day of flowrate in a two inch pipe. You can barely see it move if you aren’t watching closely. So it was a challenging requirement we started out with.
Finally we created a fluidic amplifier, wherein an emitter, gate, and base were mounted in a flowing pipeline. This fluidic amplifier operated just like an electronic triode. Except, heated liquid was emitter instead of electrons..
Q. How did it work?
Three ¼ diameter X 1 ½ inch long horizontal steel thermal wells were mounted in the pipe directly across the flow in the two-inch pipe. One thermal well (the emitter) contained a low power (10 watt) heater. Vertically above, parallel to and separated from the heater (about a ¼ inch gap) was a second thermal well containing a temperature sensor. The third thermal well was mounted about ¾ inches away and upstream of the other thermal wells.
During flow, all the heat from the heater was carried away downstream and dissipated into the media. When the ordinary flow stopped, a warm convection current rose vertically from the heater “emitter” across the “gate” (the ¼ inch gap) and heated the “base” temperature sensor to a higher temperature than the upstream temperature sensor. The temperature difference was used to alarm a no-flow condition. Typically, stopped water in the gap would cause a 20oF temperature difference; oil would cause a 40oF difference, and gas would cause a 70 to 100oF difference. Even the slight flowrate of four inches per minute through the gap or gate caused the temperature difference to drop to zero.
No matter what the media, be it: gas, liquid, oil, water emulsions, or solids, gels, and the like; if it stopped, the upper sensor would heat up as compared to the upstream sensor, either by convection heat transfer in ordinary fluid or differential conduction in gels, ice, or solids through the ¼ inch “gate” gap as compared to the ¾ inch gap thermally isolating the upstream sensor from the heater “emitter.” An alarm trip point of 10oF was used as the alarm point; any temperature difference above 10oF would trigger the alarm.
It worked! This thing also became a flowmeter in a way. It was really kind of interesting how it happened. The oil company that was exploiting this particular technology would bring the oils up to 30 wells into many collecting points. At the collecting points, they would have diverter valves that would either divert this flow into a collecting gauge tank, or divert it into a production pipe, in order to pay the people that owned the well property their rightful royalties. Once a month, they would tank-gauge the amount of oil they were getting out of that particular well. It was also part of the management of the field.
Using this method, they could gauge the amount of volume being produced by each well by the gauge tank. They related that to the number of on /off times – how long it was staying on and how long it was staying off during the 24 hour period. They had 3000 wells in this field, and had a huge database. By scanning each well once every six minutes to see if it was on or off, and putting that information into the computer memory, and comparing that data with the periodic on-off periods during well gauging, they were able to tell within one percent how much oil was being produced that day. This was done by recording the on/off history vs. the gauging of that well. They were able to get a relationship between the on/off time of all the wells in the field and the amount of oil that was being produced.
Q. Does this give you the speed of the fluid?
No. All it did was say whether it was on or off as defined by the two barrel a day flowrate trip point. If the switch said it was on ten percent of the time, they knew that well was producing ten barrels a day because they periodically gauged it and the computer knew the relationship. So they related the “on” time of our switches to the amount of oil being produced in that well. Every month they’d get an update on on/off time and how much oil this well was producing. So by looking at the on/off times of all 3000 wells and the gauging data, they were able to statistically determine within one percent how much oil the field was producing. And they had geared up to 100,000 barrels per day. That was in Bakersfield, California.
Then they began to get some discrepancies between what was being produced and what was being shipped. And it wasn’t one percent; it was getting to be two percent or more, which is a significant amount of oil. And by one means or another, they found out that it was being stolen. They used our instruments to determine the rate at which they should be shipping. They had an additional metering instrument on the field to gauge the amount of oil that was actually going on the shipping pipeline. These two were diverging. And they found that the difference was being stolen.
Q. Was that Saddam Hussein who was stealing it?
[Laughter] No. It was some of the guys who were working in the field. I’ve been told that a lot of oil enters the industry through theft.
So that was our first entry into the field. We’re working in the kitchen, my partner’s dining room, and his garage. We are financing this out of our hip pockets. My partner was a manufacturer’s rep, so he was able to do some sales work on it and other things. I was the engineer and we’d work weekends and nights. Finally we got things going. At about that time, the Bakersfield-based oil company wanted to buy 3000 of these things. They knew we were just working in the garage, and weren’t capable of producing that number. So they asked us to license this to someone who would be more capable of producing that number. So we licensed the Whitaker Company on the technology in 1966. That didn’t work very well, so we got eventually got the license back. This also verified my earlier response that the ethics and work environment at Whitaker would not be conducive to a successful license. Oh well, another error!
We got the license back in 1970. Bob Deane, my partner, started up again in his garage. At this time, I was the consulting engineer. I had left the Whitaker Company’s employment back in 1964. I consulted with Whitaker and a lot of other companies while we were trying to get this going. We ultimately retrofitted all the 3000 Bakersfield instruments because Whitaker didn’t do a good job on it. We also sold another 3000 or 4000 for additional wells in the same field, with sales commencing in about 1973.
In this instance, thermal offered so many benefits, in terms of the mechanization that I had reversed my earlier opinion and we developed thermal instruments. It didn’t matter if it was oil or water or gas or steam or solids. Whatever was there, the instrument was able to tell whatever was there if it was moving or stopped. This is all the user wanted to know for oil production. If the product didn’t move for a long time, they sent a crew out to see what was wrong.
Oil wells are temperamental things. They’ll produce, then quit, produce again, and may stop for long periods of time. They’re not all consistent. One well right next to the other one can be totally different from the others. They have to watch them constantly to see what the trends are and in this case only automated “watch” was economical.
We went along making switches until 1981. At the same time, Kurz was developing flow transmitters for gas products. We concluded that we had the basis for doing transmitters if we put more sophisticated electronics on it. So that’s what we did. There may have been some dismay on the part of people in the industry doing transmitters that we had not only exploited the switch market, but now were coming onto their turf.
We went in anyway and we developed our earliest gas flow transmitter. About that time we moved out of Canoga Park in the San Fernando Valley and came down to San Marcos. We had in the meantime gotten involved in the nuclear industry, even though it was collapsing due to the accident at Three Mile Island. So although the industry was collapsing, we got into it with a new technology that had its own growth curve. So despite the downturn of the industry, we were on a growth curve that overcame the downturn.
Then we got into gauging, using the thermal technique of gauging tanks. First we discovered that the flow switch if you turn it upside down was a perfectly good liquid level indicator. So we began to make liquid level switches. It was so sensitive that it could tell the difference between oil and water, or sand and water, so we were able to interface between slurries and clear liquids, different non-miscible liquids, or liquids and gases.
Later, we invented long continuous heaters and RTDs, and were able to gauge the amount of fluid in a tank, as opposed to our initial effort of point interface sensing. After we did the fluidic amplifier, in order to get higher flowrate sensitivity, we changed the heat transfer method from convection to conduction. We did that by bringing the heater into direct fused metallic contact with the heated sensor. So now we were getting heat from the heater into this RTD by conduction, no “GAP” for convective heat transfer. The third separate thermal well was still operating as a reference temperature sensor. Now we could go to higher flowrates because it took a lot of flow across the thermally bonded heater/sensor array to cool the thing enough to be sensitive to flow. This became our first high flowrate sensor.
Q. You put the heater together with the sensor?
Yes, we fused the thermal wells together and eliminated the “GAP” and its free convection heat transfer path that existed in the absence of crossflow through the gap caused by normal media flow in the pipe. We fused them together so we had a conduction heat transfer path between them.
Q. What’s the difference between conduction and convection?
Convection would be like the following example. Suppose you have a burning cigarette in a still room. Smoke rises vertically several inches off the hot ember. That’s a convection flow. If you put your finger in there, you’d burn yourself even though you weren’t in touch with the hot ember, because you’re transferring heat from the hot ember to your finger through a smoky hot convection current. It’s thermally driven convection. If you put your finger on the burning ember, that burn would be caused by conduction.
If you put your heater in direct contact with the heated element, now you have conduction. That’s different from convection. There’s one other method of heat transfer, and that’s “radiant.” That’s how we get our heat from the sun – through radiation. It is not a heat transfer means currently used by use, but you can never tell when it might be used.
Once we fused the two together, we turned the thing upside down and we would still get conduction from the heater to the sensor. When the liquid came up and touched the heated sensor, it would cool it. We could tell when it got into the liquid. We were then able to make this flow switch into a liquid level sensor; the heater now above the heated sensor still heated the sensor by conduction through the “fused” junction of the two thermal walls.
Q. Did you have to put it at one location?
Yes, that would be what we called a point sensor. It would be like a float switch. You put it at one point and when the level is up to that point, it would float and close the contact. We had no moving parts, so there were a lot of people who liked that. Plus we were able to tell what fluids we were in because the heat transfer qualities were so different from fluid to fluid. Interestingly, because of many improvements, we are now able to offer this device as both a flow sensor or liquid level sensor and as a loop-powered sensor.
If you had an oil and water separator, for example, you could look at this instrument and tell if you were in oil or water. So we could do an interface sensor. Or if you were in water and you were transporting sand with that water, if the sand built up to a given level, we could tell if we were in sandy water or clear water. The sand would interfere with the heat transfer. It’s just like when you put your foot in the sand at the beach. Your ankle is still cool and your feet get warm. So we did interface sensing this way.
Later on we discovered that we could even point this downward and get extremely sensitive with a thimble full of water. If we were in a nuclear power plant and we wanted to know if there was leakage someplace, without putting any kind of a sump in or liquid gathering device, we could mount this just off the floor. If the slightest bit of water gathered underneath and carried the heat away, we could tell if it got even slightly wet. We also used those in water treatment plants where they had sludge, for example; where they had an interface between water and sludge in some of these separation systems. We could tell if we were in clear water or sludge.
We did some work in the juice industry where they wanted to know if they had pulp or clear orange juice. We could tell, because of the change in heat transfer.
Q. Would you have to try it out on different fluids?
Yes, we would have to try it out here to advise the people. First we would find out what media they were in and we duplicated it here. Or, we told them how to set it in the field, and they would cause the problem to occur. Then they could see the difference with a voltmeter as the media changed. Then they would set the trip point on the switch according to what the field results were.
The foregoing is basically the early company history prior to our moving to San Marcos in 1981. Thereafter the history resembles the old movie serial “The Perils of Pauline” more than the rational business that it currently is following my retirement.
Dan McQueen
Dan McQueen, son of Mac McQueen, was President and CEO of Fluid Components International LLC (FCI) until his death in 2023. He was a recognized world leader in thermal dispersion process instrumentation used in flow, level and temperature measurement. McQueen served as International Sales Manager, and Director of Sales and Marketing prior to becoming President and CEO in 1995. Mr. McQueen also served as President of Vortab Company, a recognized leader in flow conditioners offering unique patented designs to serve a wide variety of flow conditioning applications.
FCI and Vortab are diversified in many industries including power, aerospace, water, chemical, petrochemical, oil and gas along with nearly all process industries and have regional presence in over 50 countries including FCI B.V. in Holland, FA Holding in Hong Kong and FCI Instrumentation and Technology company in Beijing, China.
Mr. McQueen was a graduate from U.C.L.A with a degree in Economics and completed Executive Management certificate programs at USC and Cal Tech. He was an active member in the (ISA) Instrument Society of Automation and served on (MCAA) Measurement Control and Automation Association Boards. He also served on various San Diego manufacturing company Boards and formal Advisory Councils in banking, insurance and manufacturing companies.