The concept of the rod pump can be traced back to the Roman Empire. Roman engineers used something that looks amazingly like today’s version to pump water. But other common oilfield lift strategies would not look familiar to Pliny the Elder, who recorded those Roman ideas for posterity. Electric submersible pumps and various gas lift technologies, along with the strategies under which they operate, are more recent, and they continue to get more and more sophisticated and efficient. Valiant Artificial Lift Solutions, Logie Gas Lift Systems, and Texas Tech are all advancing the cause today.
Valiant: Finding a Balance
With long laterals and skyrocketing development costs, today’s producers have a clearly defined goal, says Valiant’s Director of Engineering and Product Line Kelsey Gonzalez. “Their Holy Grail is that I put one pump in at 4,000 bbl/d and it runs until I only have 50 bbl/d and then it dies. Nobody can come close to that right now. But the goal is to do whatever you can do to reduce the total cost of operation.”
Choosing a lift system for a three-mile lateral well is all about economics, he said. A well’s first production method “is usually determined by what will get the fastest draw-down of that well, or the greatest volume in the shortest period of time,” he said. The steep decline curves of unconventionals (which is ironically exacerbated by the fast drawdown at the first) means a well will require different capacity pumps over its life span.
Today’s wells often begin with a 4,000 bbl/d pump. Gonzalez said that usually lasts eight months at most, drawing a well down to 2,000-1,500 bbl/d. If the flow gets too low for a pump’s capacity, it begins to experience metal fatigue, causing pump failure.
To combat that, Gonzalez said Valiant and other ESP makers are working with more advanced metallurgy. “The longer the pump stays in, the more money the producer makes,” he said. That’s because changeouts are expensive, involving a pulling unit and the cost of another pump.
Often the next pump will be a smaller ESP—some of which can produce efficiently at rates down to 250-300 bbl/d. After that, it’s a beam pump or gas lift to the end. That final change is dreaded by producers because the latter lift systems have radically different surface and downhole footprints, making that the most costly changeover—at a time when production rates are very low.
The $5 million question
Gonzalez says he’s often consulted with producers about slowing production to lengthen pump life, with his ideas mostly falling on deaf ears. He gives an example of what’s happening in the CFO’s mind.
“If I’m producing 3,000 bbl/d of fluid at the high end, there’s probably about1,500 bbl/d of oil in that to begin with. If you put that same well on gas lift, you might get 750 bbl/d (oil cut). At $75 per barrel of oil, the first three months of differential between those two methods is $5 million. Does that tell you why you run an ESP? Because $5 million is close to the cost of the wellbore.”
Stretching the ESP’s Life
One of the issues with lower flow rates and reduced bottomhole pressure is gas slugging. “Centrifugal pumps [which is what an ESP is] like liquid, they don’t like gas,” Gonzalez pointed out. Therefore, constant research goes into both hardware for improved gas separators, into hardware and software for the pumps themselves, and for the variable speed drives (VSDs) that regulate them.
A Radical New Design
What if there was a way to avoid the radical footprint change of the end-of-life lift system? What if an ESP could be designed that would drive a plunger like a rod pump instead of spinning? Such a device could reduce changeover costs from $300,000 to $100,000 per well.
That’s the question Valiant began asking about three years ago. The result, a “linear ESP” called the Vesper, is in the testing phase at this writing, with a commercial release anticipated by the end of 2024. The Vesper uses a more-powerful permanent magnet motor to boost performance.
Says Gonzalez, “We didn’t develop it, we found someone who did, then we put it together with all of the other components. This should be the least traumatic and [least] expensive change-up to get the last barrels out of the wellbore.”
A Quest for Gas Lift Excellence
Noting that a large percentage of the 40,000 horizontal wells drilled in the Permian Basin in the last 10 years are on gas lift, a Texas Tech petroleum engineering professor thinks there should be a better way to evaluate best practices on those wells. So Smith Leggett, Ph.D., decided to round up support from educators and the industry by forming the Texas Tech Gas Lift Consortium. A growing list of producers and artificial lift companies, including Stan Logie (quoted later in this story), are lining up to pitch in.
Its goal, said Leggett, is to “address challenges associated with the widespread implementation of intermittently operating gas lift technology in horizontal, unconventional wells” on shore and offshore.
The group’s three top goals involve finding ways to:
- Reduce OPEX by reducing lift gas requirements
- Reduce CAPEX by deferring artificial lift conversions
- Increase production by minimizing bottomhole pressures
It Hurts When You’ve Got Gas
First, some background on the how, why, and when of gas lift. Leggett said that conventional vertical wells don’t have issues with gas because “the bottomhole is a natural separator—the gas goes up and the liquids fall down into the pump, which is set below the perforations.” But in horizontal wells the long laterals mean there is no clearly defined “bottom” to the hole. “Unless you spend extra effort to drill a sump onto the wells, you can’t set the pump below the perfs,” he said, so the gas can’t separate as easily. Because gas lift makes use of the formation’s gas, with help from extra gas injected into the well, it is preferred in older, lower-pressure wells where the low formation pressure lets the gas escape below the pump, causing gas locking.
Leggett explained the difference between continuous and intermittent gas lift. “In continuous gas lift, you’re injecting the gas stream into the casing and through a valve to lighten the fluid column—you’re continuously injecting and flowing the gas through the fluid column. Gas from the reservoir combines with the injected gas to lighten the fluid column and decrease the bottomhole pressure.
On the other hand, “Under intermittent gas lift, we intermittently close the bottom valve.”
While the valve is closed, the injected gas raises the pressure, and the reservoir “continues to deliver fluids and build up a liquid column in the tubing, containing both oil and water,” he said. At a predetermined point, the valves in the system suddenly open, lifting the liquid slug to the surface, but some of the original slug gets lost along the way. Another alternative is to use GAPL to push the slug to the surface, which eliminates those losses.
So researching, testing, evaluating, and implementing best practices on merging all the gas lift actions and options could boost production by millions of barrels and save tens of millions of dollars—and those are the goals of the consortium.
The numbers on that are impressive. A group called the Artificial Lift Research and Development Council (ALDRC) tested a number of wells in which they switched from CGL to IGL, Leggett said. By switching to IGL they achieved the same production on the wells while reducing lift gas requirements by 50 percent. Multiply that by thousands of wells and over 50 years, and the savings would be staggering, the study said.
Fiber Optics Collect the Details
A non-producing well drilled right on the Tech campus is giving the consortium the environment it needs to control all the variables and get the most accurate lab results. After evaluating what they learn on campus, the proof will come from taking those learnings and applying them in the field.
Leggett’s students will track the production and flow of liquid slugs through the use of fiber optic sensors. Part of the test is to learn how fiber optics can accurately detect and mitigate slugs before they come to the top, he explained.
For the test, they will run a fiber optic cable downhole. The entire fiber is actually a sensor. When the researchers fire a last light into it, and that light backscatters, it will then reflect back into the fiber. From tracking the milliseconds of variance in reflection time, researchers can find and track slugs as they form and travel.
Leggett is hoping to announce some early findings by the end of 2024. At this writing the on-campus testing phase is just beginning.
Logie: When to IGL Instead of GAPL
As noted above, when unconventional wells age and become more gassy, many producers switch to some form of gas or plunger lift. But as also stated above, choosing the right gas lift option is important to maximize long term production and minimize costs.
Many companies choose gas assisted plunger lift (GAPL) for a variety of reasons, says A. Stan Logie of Logie Gas Lift Consulting. Logie points out, however, that there are many times when intermittent gas lift (IGL) can be the answer because it is more cost-effective and, in the long term, it increases production.
Some producers run constant gas lift (CGL) from the start, when fluid production and reservoir pressures are high. Soon, however, “The reservoir pressure eventually depletes, and gas is injected on bottom through the orifice. Later, a control valve is placed on the flowline. This control valve opens and closes periodically and the resulting differential pressure between the casing and lower tubing pressure allows intermittent rise of a downhole plunger. This is GAPL,” Logie said. But he argues that there are two reasons why GAPL is usually not optimal.
First, high pressure gas is injected at depth, downstream of a screen orifice that is commonly installed on the bottom of the reservoir when the well is started on formation-based gas lift. But when high pressure gas is injected downstream, that pressure “pushes back on the depleted reservoir, forcing fluid back into the producing formation,” Logie says. “This action increases reservoir surges, causing faster plunger arrival times, dry runs and ultimately expensive plunger fishing jobs and increased lease operating expenses (LOP),” he notes.
This can also reduce reservoir drawdown and limit the production of oil and gas.
The second issue is that, in many wells with depleted production, gas-to-liquid ratios are too low to support lifting the plunger off the bottom of the well. Here Logie quotes Dr. Kermit Brown of the University of Tulsa: “GAPL installations are best suited for finding unloaded gas wells.” Logie continues, “GAPL installations have been found to work best in higher-pressured reservoirs.” But they do not work well when the pressure is depleted.
How to Convert from GAPL to IGL
The key to making IGL work after using GAPL lies in replacing the screen orifice, Logie explains. “GAPL wells are converted to IGL installations by replacing the “screen orifice” valve downhole with an injection pressure operated gas lift valve, or a pilot operated gas lift valve. When this valve replacement is done in accordance with best gas lift industry practice, IGL installations on average required less than 50 percent of the daily injection gas injection volume used by GAPL installations. In addition, there are consistent increases [over 20 percent] in produced oil and gas resulting from GAPL wells converted to IGL installations.”
Does It Work?
As evidence, Logie sites case studies of successful IGL conversion in Oklahoma’s SCOOP/STACK, wherein production tripled. And in the Permian Basin, converting to IGL from rod pumping boosted production by 20 barrels of fluid per day. He adds, “It is also common to see daily gas injection rates more than halved when wells are converted from GAPL to IGL, significantly reducing field compression capacity.
Some companies balk at the conversion costs, which are around $15,000, but Logie stresses that the investment pays for itself in reduced cost and greater production.