Heavy-iron pumpjacks are using technologically advanced sensors and software to add value for operators.

Like most other oilfield applications, the basic, reliable pumpjack with its familiar bobbing horsehead is getting an education, and that education is providing higher rates of production, lower operating expenses and less downtime.
Manufacturers have added sophistication through the years. Although the basic downhole pump driven from the surface has remained about the same for decades, the way it works has improved steadily.
Power control has improved. "Power in the oilpatch really stinks," said Andy Cordova, vice president of sales and marketing with Lufkin Automation. Surge protectors helped avoid downtime from power variations and improved reliability.
The programs on controllers moved from analog to microprocessors to microprocessors with flash programming units, he said.
Control systems started with timers that shut the rod pumps down and restarted them on a timed schedule. Next, the industry added information about loads on the motor to improve reliability. Then controllers added to the sophistication.
The next step was surface cards that compared the load on the polish rod with the position of the horsehead. Additional information showed compression and stretch of the rod string. That was better, but rod elasticity could be caused by friction in the wellbore as well as load from the pump.
New downhole cards show the actual load at the top of the downhole pump, he said. It shows the amount of fluid in the pump. The equation for the downhole card came from Dr. Sam Gibbs, a researcher for Shell Oil Co. who broke ranks to form Nabla Corp., which Lufkin bought in 1997. The company even named its Sam rod pump controller after him.
At the next level of sophistication came the variable-speed drive. The traditional method of producing with a rod pump required cycling the pump on and off to produce a well. Some wells, however, create back pressure that shuts off flow. And with Canadian heavy oils, the rod pump doesn't always fall to the bottom of the fluid easily when the unit is off. In other areas, sand gets in the pump when it stops and grinds away at parts when it starts again.
With a variable-speed motor on some wells, the drive changes speed in response to the pumping design program. The program can start at a low speed and increase gradually to find the window that allows the pump to fill to the programmed fluid level and avoid stress, Cordova said.
This system isn't for every well. It probably isn't an economic answer for the 410,000 US wells that make less than 10 b/d of oil.
Some operators use controllers on wells that produce as little as 5 b/d of oil. In Canada, operators tend to go to higher levels of production before adding controllers than operators in other parts of the world. Lufkin Automation provides a basic controller for the huge number of stripper wells in the world.
The variable-speed motor can help in situations such as those found in the Levelland, Texas, area, where it may take days to pump off the water enough to produce oil. Any well that produces copious amounts of water or has sanding problems is a candidate for these variable-speed systems.
The industry is starting to set up economic models for rod pumping systems, Cordova said. Those programs look at the needs of the petroleum engineer in producing the well and the accountant who wants maximum economic production, he added.
Supervisory control and data acquisition (SCADA) systems have been around for a long time, but they can combine with the new production optimization systems to give an operator anywhere in the world the ability to spot problems instantly and make some corrections.
The combination makes the operator proactive in dealing with production rather than reactive in responding to problems.
Typically, Cordova said, these systems provide a 4% increase in production, an 18% reduction in electricity costs and a 25% reduction in maintenance costs. That doesn't just mean the electronics will take a 100-b/d well to 104 b/d. "Even a good operator may overpump. This reduces down time," he said. It offers a faster return to production time.
"With SCADA, you know in minutes to hours about a problem. Previously, it could have taken days," depending on the next scheduled visit by the pumper, he added.
With computer programs and the downhole card, Lufkin can add inferred production. The controller looks at the downhole card and calculates the amount of fluid moving through the pump. Before the downhole card, a well test offered only the accurate reading. That's still the most accurate method, but the downhole card normally comes up with an answer within 10% of the well test numbers.
An operator can set a controller for a typical 80% pump fillage, but with the old surface cards, it was never sure what it was getting. When the controller "sees" the pump is 80% full, it shuts down for a predetermined amount of downtime. Ideally, that happens when the actual plunger downstroke in which the traveling valve is open is 80% of actual downhole plunger movement. But with some units, the surface stroke may appear pumped off when pump fillage is still full or adequate. If that happens, the producer loses production.
Gas interference also may fool the surface card into seeing a full pump, but a downhole pump card sees the amount of incomplete fillage caused by that gas. If the operator knows that amount of incomplete fillage, it can reset to controller for more efficient production. A SCADA system can relay that information immediately. That's one of the reasons 80% of the rod pumps the company sells go to a SCADA system.
In a state-of-the-art system, the operator gets more than immediate notification of conditions in the hole and the ability to adjust to those conditions. It gets run times and load trends. If it knows the well conditions, it can see indications that scale and paraffin are loading up in the wellbore.
The producer can see problems coming in time to treat them. That often saves money in downtime when the typical timed treatments are too few and far between and force the operator to shut the well in for treatment. It also saves money for the operator who treats the well more often than necessary.
New systems do away with the uncertainties of scheduled maintenance. In addition, the Lufkin system gives the operator dynamometer readings, which can indicate pump leakage.
Like most companies, Lufkin didn't have its own SCADA software, so it adopted a SCADA system. Reaching for higher technology, it formed a technology partnership with the Theta Enterprises XSPOC system developed by John G. Svinos. He had developed the downhole card approach that yielded well information with every stroke of the pumpjack. With the information sent from the top of the pump, the software, with the help of the Sam controller and analysis system, takes on the chore of analyzing the information and reporting downhole conditions.
That's particularly important these days. "We've lost a lot of rod pumping experts in the field. We try to make it easy for the novice to read," Cordova said. In short, Theta is an artificial intelligence program that uses information from Svinos' experience and knowledge and helps oilpatch newcomers benefit from that expertise.
"It's going to take optimization and automation to the next level for our oil and gas customers," added Svinos.
The Theta system also features an open software package. That means a company doesn't have to junk its existing analytical software to take advantage of the high-technology approach. It works well with a company's legacy systems.
In addition, modern communications are beginning to bypass the periodic pumper visits as well as the need for a field headquarters that gathers information from all the wells, compiles it and relays it to a central computer.
Satellite communications allow a person or a company with four wells in Colorado, six wells in West Texas and five wells in Oman to monitor and control them all. "Essentially, it puts people at any well anywhere in the world," Cordova said.
He said the new software, controllers, SCADA and communications make the tried-and-true rod pump a high-technology production unit. For example, pump demands may not remain the same throughout the life of a well. With flash memory, programmers at the Lufkin Automation offices can take information from the well and requirements of the operator and create the code for a new program for the controller. They can send the code electronically to Bakersfield, Calif., or Egypt or anywhere else in the world, and technicians at the wellhead can plug in the new program in minutes.
Those programs are backed by experience from operators around the world. The information they provide from their wells goes into a database that may contribute to algorithms that show the effect of paraffin buildup on the polish rod.
The work never stops as operators and service companies try to find new ways to make the beam pump more efficient.
Lufkin is working with a partner in West Texas on a system that throws the clutch on a gas-engine system to rotate production and rest periods. It also is working on a governor that allows the system to overpump for a period of time to pump off water from the wellbore and then go back to underpumping.
Progressive cavity pumps
The pumpjack isn't the only system getting a dose of higher technology. The company is working on a controller for progressive cavity pumps. "The customer cares little about the workings of the controller. It just wants the controller to do what it's supposed to do. It wants one controller to handle everything," Cordova said. Ideally, the service company collects all of the expert information and the method of compiling and analyzing that information, and it gets the information from the well to the controller, where it can make a difference in production full time.
The typical SCADA system, he added, is a snapshot. The controller, downhole card and software provide a higher level of knowledge and convert that snapshot into a movie; the communications advances turn it into a live, real-time show.
The company is working to put the whole system online, which would give the guy in his living room access to individual well information without repeaters. He would be able to see the well conditions on his home computer using the Internet and control the operations of each well.
That's not a universal solution. Major oil companies are reluctant to leave that kind of entry in the corporate firewall. Major companies also tend to have very large fields with field-level operating offices.
Smaller independents, however, will find a lot to like with this kind of system. They also have security concerns, but the system's benefits may outweigh the risks.

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