Artificial lift

Gas Lift Use Grows in Permian

Unconventional production patterns in the Permian Basin are leading producers to replace electrical submersible pumps (ESPs) with gas lift, which had been little used there.

Gas slugging is caused when water collects in undulating reservoirs. SPE 181212 shows how gas pockets build up, increasing the pressure on the water-filled downdips and slowing the inflow. They ultimately are able to push past the barrier in the form.
Source: SPE 181212

Unconventional production patterns in the Permian Basin have driven operators to reconsider how they maximize early production.

Operators within this booming anomaly—a US onshore play where drilling is going strong—have increasingly shifted from the electrical submersible pumps (ESPs) to gas lift, which had been little used there.

The story behind this change was told in the opening session of the SPE Artificial Lift Conference and Exhibition. It was an economic decision that offers a look into the complexities of production management.

The big problem is that the fractured horizontal wells tapping these unconventional plays produce oil mixed with high levels of natural gas and sand, which can shorten the life of downhole pumps. Large slugs of gas can cause pumps to overheat, and the abrasive sand can chew up the downhole pumps.

“Even before [oil] prices went down, we were looking to cut operating costs. We were spending a lot of money on ESPs,” said Libby Einhorn, senior production engineer for Concho Resources, during the session in which she talked about the company’s shift to gas lift.

Their pumps had average lifespans of a bit more than a year, and cost about USD 100,000 to replace plus the revenue lost due to lost production. Added to the cost were pumps in remote locations where the only available electric power sources were on-site generators.

When Concho and other operators in the Permian starting looking for alternatives, the negatives for ESPs looked like positives for gas lift. The downhole hardware used to inject gas to lighten the crude, which allows natural pressure to lift it, is not affected by sand and the gas in the production stream is a plus.

“One of the biggest problems we have in wells is that gas is disruptive of everything we do, unless it likes gas,” and “gas lift likes gas,” said Bill Lane, an artificial lift consultant for Weatherford who also spoke during the panel session.

There were a lot of arguments for gas lift, but it was still a hard sell.

When the idea first came up, Einhorn there were questions raised about whether the company’s staff, which relied on ESPs and rod pumps, could learn how to install and manage a system that was unfamiliar to them and most other companies working in the area.

“One of the biggest challenge we have is, 30 years ago there was no gas lift in the Permian at all,” Einhorn said.

Lift systems are often chosen based on what is familiar. Experienced hands have “a preference based on the sort of lift [with which] they are most comfortable,” Lane said.

In this case, though, that weight was lightened by the many companies moving in the same direction. Major players in the Permian, including Devon, which works closely with Concho, and Occidental were among those responding to the same issues and increasingly using gas lift.

“At some point where they (Permian operators) experienced problems with slugging, they are using gas lift for slugging mitigation,” said Greg Stephenson, a staff production engineer for ConocoPhillips on the panel.

Over time water builds up in low spots in narrow casing where the up and down undulations reflect the pressure to drill wells faster and cheaper. As gas is produced, the pressure rises high enough to periodically force slugs of gas past the barrier.

“It is not a huge amount [of gas produced], but it comes all at once in burps of gas,” which in one laboratory test grew to be 25 ft long, said Jeremy Van Dam, a senior production solutions leader at the GE Oil & Gas research center in Oklahoma City, in SPE paper 181212 presented at the conference. Some slugs are so large, they can causing overheating in pumps that depend on fluid flow for cooling.  

The fact that GE and Baker Hughes were presenting papers was evidence of ESP makers working on modifications to manage gas and solids problems that have eroded their share of a growing market.

Baker Hughes has been studying gas slugging in a field project with Apache Corp. “The gas from a daily perspective seems manageable at first, but on-site that may not be the case,” said Jordan Kirk, an applications engineer with Baker Hughes. Signs of trouble included rapid swings in casing pressure and in the amps drawn by the ESP motor.

The ESP makers’ counter argument is that their pumps can produce more, and they have incorporated features to limit the intake of sand and limit the effect of slugs with designs that seek to route the gas around the pump.

In the tight confines of a shale well in which 4-1/2 in. casing is common, slugging becomes more of an issue and there is little space to add features to the pump to limit its impact. Also, limited budgets in these mass-produced wells preclude adding features such as creating a short lateral down off the main flow—a rathole—to put the pump below the gas flow.

Until recently, the standard routine in the Permian was to first use ESPs to maximize production in the early years of the well when production was high enough to be efficiently lifted using an ESP. As production dropped below that level, wells are switched to a lower-cost rod pump. Late in the life of wells, rod pumps remain the standard.

That combination fits well with a widely used production strategy—maximize production early on in wells that start strong and soon decline. Lane described it as “produce as much as you can to get the cash today,” and said it is important when planning artificial lift to be conscious of whether the goal is maximizing early output or long-term output, which may not be mutually exclusive.

Concho switched to gas lift even though an ESP’s higher production rate is consistent with the company’s focus on strong early production. “We still want a high initial rate. We may suffer some for not running an ESP, but we feel the cost is justified.”

Gas lift requires installing equipment to compress the gas and inject it under pressure, but it requires less power than an ESP running full-time. Gas lift equipment costs less to keep up and continues to add value even when it could use maintenance and adjustments.

“They are not optimized for efficiency, but they continue to produce and we have yet to have a gas lift failure,” Einhorn said.

Matching gas injections to maximize the benefit in changeable wells demands skills in short supply and an understanding of unconventional flows, which is something the industry is learning from experience in this young field.

But even when the system needs an adjustment, it can still add production, said Stephenson, noting that “it works even when it is broken.”