Once a trickle, now a flood. Increased broadband availability and additional features have dramatically expanded automation’s coverage.
By Paul Wiseman, special contributor
As recently as four years ago, the number of U.S. wells being monitored offsite was about 20-30 percent, according to Stuart Royal of Wellkeeper. “I would say that number is perhaps even double that” today, he said. “So the rate of adoption has increased, I would say, exponentially, in the last four years.”
The oil patch’s historical hesitancy to adopt technology is slowly being overcome, at least in the field of automation, by simple economies and by improvements in the technology itself that make adoption almost a no-brainer.
It could be said that onsite automation began in the late 1970s and early 1980s with the advent of pump off controllers and other devices that shut the well off when “pump off,” or a less-than-full pump barrel, was detected. Then in the late 1980s and early 1990s the ability to get reading remotely came into being.
At that time, telemetry was an issue in automation as opposed to remote monitoring. For monitoring alone, the bandwidth of radios or, later in the 1990s, of affordable satellite feeds was enough. But to obtain the two-way communication needed for remote monitoring, which includes a type of “remote control” of the well, broader bandwidth, economical only through cell phones, was needed. And in the “despoblado” areas of some remote West Texas regions, cell towers were few and far between.
But now cell phone companies are awaking to the availability of new revenue streams from telemetry companies like Wellkeeper and Spirit Global Energy Solutions, which pay monthly fees to transmit data both directions over cell towers even in areas far from a jackrabbit. This has removed one of the biggest remaining obstacles to remote automation.
“It’s rare now that we don’t have cellular connectivity,” said Matt Raglin, of Spirit Global Energy. “For example, I was south of Bakersfield, about 35 miles south of I-10, out in the middle of nowhere, and there’s one well, and my cellphone coverage was really good.” The connection allowed them to talk to that well every day.
Even so, cell technology is not without its challenges. Royal stated that cell phone companies regularly update their technology, necessitating constant adjustments for Wellkeeper in order to stay in touch.
While the majors were the earliest adopters of this technology, both Royal and Spirit’s Raglin say automation is now common among large, mid-size, and even some small independents and operators with as little as one well—because all are beginning to see the cost benefits.
Remote monitoring allows companies to “pump by exception,” as Royal put it. “You can imagine that, in the morning, the pumper or the field operations person wakes up and instead of hopping in his truck and going to the 50 wells that are on his route, he logs onto Wellkeeper. He takes a look at Wellkeeper and says, ‘Okay, this site looks good, this site looks good, I’ve got a problem here and I’ve got a problem here.’ So where do you go to first? You go to the problem wells.”
He noted that each well still needs to be personally inspected at some regular interval because monitoring cannot tell the operator everything, but it can help by putting known problems at the top of the priority list.
More telemetry companies like Wellkeeper are offering software that can solve some problems without anyone going to the well. This feature is still underutilized because, as Royal pointed out, some producers are reluctant to limit their problem-solving to a remote adjustment, feeling it is best if a person goes to the site to make sure that the adjustment had the desired result. Plus, starting a beam pump remotely can have safety issues if someone is standing nearby, even if that person is doing something that is unauthorized.
Another factor is that every office has computers, smart phones, and internet access now, which means that the in-office hardware needed for well monitoring is already in place. Overall costs of automation on the field side have also come down to the point, said Raglin, that “the cost of not having [automation] has gone up.”
The cost of remediating a spill at an un-monitored tank battery is much higher under current regulations than it used to be. Contaminated dirt must be hauled off and cleaned, “clean” dirt must be hauled in, and it’s rare that there’s a run-over of a tank battery. That is, rare “because the thing is automated and starts shutting wells down, or opens or closes valves,” Raglin observed.
Both Raglin and Royal were quick to note that well monitoring is not designed to do away with employees, but rather to make them more efficient. Still, in an environment wherein finding and keeping a full staff is a daily challenge, any efficiencies that can be found are welcome.
One of the newest efficiencies involves the addition of artificial intelligence, or AI. The newest generation of pump off controllers “learn” to make adjustments designed to optimize the well’s performance while still protecting the well from fluid pound damage. “We’re trying to build some competence into the controller,” said Raglin.
Faster processors have allowed technicians to capture two million pieces of data per second, giving the system a huge amount of information on which to base decisions.
“What we built into our Genesis controller was the ability to learn things, to see trends to [allow it] to make adjustments as necessary,” Raglin explained.
For example, the Genesis system uses variable-speed drives to ramp up and down the pumping process as a well cycles between pump off and recovery. Ideally, the pump’s cycle will match exactly to reservoir inflow. That way the producer can maximize the recovery of every drop of oil from the well without damaging the pump by running it when the formation has pumped off.
“The kicker is this: reservoir inflow is dynamic,” said Raglin. “So my equipment has to be able to make a decision to speed up or slow down in response to such questions as: How much incomplete fillage in my pump do I see before I make that decision? Am I truly seeing pump off or am I seeing a little hit of gas?”
Spirit has “trained” its controllers to recognize the difference between incomplete fillage due to a pumped-off condition, and that caused by gas interference. This is referred to as “smart fillage.” Stopping the well completely is an option, which then requires the program to decide when to restart.
The total amount of data available begins with things like tank levels, pump pressure, and, as alluded to previously, POC runtime. But both Raglin and Royal noted that audio and video streaming, while still a new concept, is becoming more and more popular, especially on remote sites where good bandwidth is available.
This increases security in a number of ways, said Royal. “In a typical situation where you have truckers coming up to haul water to an SWD, the driver would come up to put in a PIN…, a truck number and a ticket number and the computer… recognizing those things as valid numbers, and opening a valve to allow them to unload,” Royal said. This can also work for trucks coming to pick up produced oil from tanks and for other loads that require accounting.
While all this data is great, few companies other than a few majors have the capability to set up and maintain the hardware and software with in-house personnel. Most contract the systems out to companies like Spirit and Wellkeeper. This technology changes so fast and requires such upkeep itself that mid-size and smaller companies find it more economical to concentrate on finding and producing oil and to farm out the automation.
With each passing year automation companies broaden their capabilities and producers find fewer and fewer reasons to resist, changing the question from, “Why automate?” to “Why not automate?”
A freelance writer in Midland, Texas, Paul Wiseman has written extensively on the oil business and on business in general. He can be reached at email@example.com.