Artificial Lift Techbook 2019

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36 | April 2019 | ARTIFICIAL LIFT: TECHNOLOGY 6,000 rpm. "Having that large a range of speed means you can adjust the speed lower and still operate effi- ciently at reduced flow rates and with pump stages designed to handle it as well," he said. For this particular pump system, one of the enabling technologies is the stages, which are man- ufactured using a metal injection molding process. What that allowed was different stage geometries and improved surface finish that would not otherwise be available through a regular investment casting pro- cess. "Using this technique we are able to implement both novel and interesting hydraulic designs but also use more wear-resistant materials," he noted. Simmons pointed to the typical PMM series—406, 456 and 562. "We have a 406 series PMM. It is a smaller OD motor. We're getting 228 hp in under 25 foot of motor. The 406 is helping because you get greater annular clearance around the motor. You've got better flow for motor cooling. We're finding it helps with things like gas breakout as the produced fluid is moving up to the intake. If you are breaking gas out prior to the intake, you are not going to take it inside the pump as much either." Switching annular/tubing flow Annular flow gas lift has been around for many years. It has been used primarily for the initial unloading of a well at very high rates of fluid production. Hav- ing a larger flow area initially allows an operator to capture more production. The problem is that annu- lar lift gets to the point where it is no longer efficient, explained Liberty Lift's Archa. Once a well reaches a normalized production rate, annular lift becomes inefficient. "You start seeing a lot of slugging occurring, and production can be erratic during those slugs. More than anything, it causes downtime—slugging equals downtime and downtime equals less production," he said. "Over the years a lot of operators have moved away from annular lift just because they know in six months, one year or two years, annular lift is not going to be right for their well. So they abandoned it completely. They didn't want to have to go in and do a $100,000 workover to pull the annular lift system and put a conventional tubing lift system back in the hole," he added. Liberty Lift Solutions now has a patent-pending solution to that problem. Its HyRate system allows operators to switch back and forth between annular flow gas lift and tubing flow gas lift without having to work the well over, according to Archa. "This allows the client to benefit from the higher initial rates associated with annular lift with the option to switch to a conventional tubing flow system in the future without working the well over. You can use them at different points in the well's life. Both sys- tems are designed and installed in tandem," he noted. Liberty Lift does nodal analysis on these instal- lations. If you're producing on annular lift, the company looks at lifting efficiency, bottomhole pressure and nodal analysis to determine the most efficient flow path for each particular stage in the well's life cycle. "This ensures we won't lose production when we switch from annular gas lift to tubing gas lift. It makes that transition almost seamless," he said. The HyRate system does not utilize costly side- pocket mandrels. The company uses conventional injection-pressure-operated (IPO) gas-lift valves and checks. The HyRate mandrel allows the company to inject gas down the tubing and into the casing without compromising the ID of whatever tubing the well is completed with and still allows the operator to utilize conventional IPO valves, Archa said. "Wireline retrievable equipment, such as side- pocket mandrels, are generally expensive. By using commodity gas-lift valves, mandrels and checks, we're able to keep the overall cost of the system a lot lower," he said. Switching back and forth is straightforward. Annu- lar lift is used during the initial production. Once the operator is ready to inject down the casing and produce up the tubing, it is simple to shut a valve on the surface, then close another valve to achieve those results, Archa said. "If a well makes a lot of sand and the operator wants to do an intervention on the well, as far as slickline goes, they don't have to run an isolation sleeve because that is just one less point of failure," he explained. "You've got flexibility because you have preset gas-lift valves on the tubing and annular lift sides. If you needed to tap into an annular lift again, it is a simple flip of a switch. With everything set up on the surface to either continue annular flow or to switch back to tubing lift, we've done the switch in 15 minutes." Switching back to annular lift generally is needed when flow rates increase. For example, some cus- tomers have implemented HyRate after being hit by offset fracks or stimulations. "They may have a well that is making 200 barrels per day," Archa said. "The old style thinking is that if they've got a well with normalized production at 200 to 300 barrels per day, they are going to install a 200 to 300 barrels per day gas-lift design. "When that particular well gets smoked by an offset frack, all of a sudden it is seeing 3,000 barrels

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