Four Trends to Watch in Artificial Lift



Four Trends to Watch in Artificial Lift
'Artificial lift first' mindset will help companies win in unconventionals, says ASME Fellow.

Unconventional oil and gas producers are gaining a variety of new artificial lift technologies to deploy at their onshore well sites, according to a Houston-based artificial lift specialist.  

“Artificial lift is a range of production engineering methods used to lift hydrocarbons and water from a producing reservoir,” explained Stuart Scott, director of technology with Petroleum(etc) and a Fellow of the American Society of Mechanical Engineers (ASME). “Most often, lifting liquids from the well allows the gas to flow using its own energy, but today some methods can also aid in lifting the gas.”

Scott noted that artificial lift approaches fall into two broad categories: energy-added methods and reservoir energy methods. Examples of energy-added methods, which “use external energy to lift fluids to the surface,” include electrical submersible pumps (ESPs), gas-lift, jet-pumps and rod/beam-pumps, said Scott. Relying “on the pressure in the reservoir to lift fluids to the surface,” reservoir energy methods include intermitters, plunger-lift, foam-lift and velocity strings, he added.

Benefits of Minimum Facilities Approach
 

Taking a “minimum facilities approach” for a full production system – not just the well pad – represents a new way of thinking regarding field development. It includes elements such as centralized processing and satellite pads, multiphase metering and wellhead compression. Here are some anticipated benefits of using this approach:

Better reservoir management through more frequent and accurate well testing

• Reduced footprint from O&G operations, trucking, risks of leaks and venting/flaring.

• Supports “long-term producer” strategy by extracting resource for decades beyond initial high-rate flow period.

• Lower capital and operations costs – in some cases by more than 50%.

“Energy-added methods are more expensive in terms of capital and operating expenditures but have a dramatic impact on both ultimate recovery and flow rate,” pointed out Scott. He added that selecting the right artificial lift method helps a producer achieve desired goals in areas such as lease operating expense (LOE), recovery factor and return on investment.

“Often 50 percent of the resource is left to be extracted after the high-rate initial flow period,” Scott said. “Companies that win in unconventionals are the companies that get artificial lift right. I like to use the term ‘artificial lift first.’ This goes to the idea that artificial lift needs to be considered upfront for any development and not as an after-thought.”

What follows is a breakdown of four specific areas of artificial lift innovation to watch.

Liquid Assisted Gas-Lift

Onshore producers need to maintain production from their horizontal gas wells and boost recovery rates from their reservoirs. An up-and-coming artificial lift approach that aims to trim costs across the well life-cycle and solve various issues associated with horizontal well production is Liquid Assisted Gas-Lift (LAGL), a concept demonstrated by Louisiana State University (LSU) petroleum engineering researchers.

“Slugging is a big problem for horizontal wells following the high initial rates,” explained Scott, who is collaborating on LAGL with LSU researchers Paulo J. Waltrich and Renato P. Coutinho. “LAGL has the capability to stabilize production from the often one- to two-mile-long horizontal section of the well which generates the slugging. Lift methods like rod/beam pumps and ESP are limited to the vertical section of the wellbore so the ability of LAGL to operate in the horizontal section solves a very real and urgent problem.”

Also, Stuart said the artificial lift approach competes on cost with conventional gas-lift, reduces in-well equipment eliminates the need for additional compression. The researchers expect to test a commercial unit at LSU in early 2018, and a commercial product could hit the market later next year.

Better Gas-Handling for ESPs

The higher gas fractions and produced sand that typically accompany onshore production translate into rapid erosion of ESP pump stages, driving up costs and curbing pump usage. Researchers at Texas A&M University’s Turbomachinery Laboratory – under the direction of recently retired mechanical engineering professor Gerald Morrison – have conducted experiments monitoring ESP erosion with both gas and sand that are gradually leading to more robust ESP designs, said Scott, noting that designs have traditionally considered only gas-handling.

“These experiments utilized 100 and 140 mesh frac sand and found the expected erosion on the impeller blade leading edge and in the diffuser,” said Scott. “Some designs were found to actually concentrate flow to a single high-velocity point at the diffuser, cutting a hole in the pump. Surprisingly, severe erosion was also observed in the ‘secondary flow paths’ through the bearing and inter-stage seals.”

Driven by the differential pressure across a stage, the secondary backflow paths quickly contributed to severe vibration and pump failure, Scott continued. Findings from the experiments are slowly being integrated into new ESP hydraulic designs that factor in the effects of gas and sand handling, he said.

“New techniques are emerging to increase run life under these conditions,” noted Scott. “These include improved pump hydraulics, high-tech coating and materials and new pump bearing materials.”

Emerging coatings technologies – developed for aerospace applications – show promise for ESP manufacturers and recently hit the market, said Scott. In addition, he said that Texas A&M researchers are currently testing new bearing materials that could be commercialized by next year.

Pad Compression for Onshore Unconventionals

Fracturing and horizontal drilling have commanded much of the attention in terms of technology development in the unconventional realm, often at the expense of well pad surface facilities.

“Production facilities often use technology that is decades old,” said Scott. “There is extensive brute force installation of tanks, separator and piping that take little advantage of the new pad architecture for wells. The thinking was along the lines that the real expense is for the drilling and frac’ing.”

Companies are beginning to shift their focus, said Scott, pointing out that the production facility installed sets a field’s long-term profitability. By taking steps to update pad design development strategies using a “minimum facilities approach,” companies are installing a minimum amount of equipment on each individual pad and then transferring the fluid to a central processing facility, he explained.

“Key to this new approach is the pad compression, which transfers fluids from each pad to the central facility,” Scott continued. “This is accomplished using multiphase pumps. Multiphase pumping for pad compression is receiving renewed interest. Wellhead compression is the first form of artificial lift and a key enabling technology for the multiphase minimum facilities approach for pad-based developments.”

In-Well Gas Compression

A new, compact compressor stands to offer operators improved production from gas wells, including those producing small amounts of liquid. Scott said commercial deployment of the compressor, which has been built and field-tested and will hit the market in 2018, could represent a milestone.

“For the first time we may have true artificial lift for gas,” said Scott. “For artificial lift, the goal is to lower a well’s bottomhole pressure and increase the direct drawdown on the reservoir, thus increasing the gas flow rate and significantly increasing the ultimate recovery.”

Aside from boosting recovery, in-well compression might also solve the problem of liquid loading – something that long vexed onshore gas producers, added Scott.

“Liquid loading reduces production and recovery unless some type of artificial lift action is taken,” Scott concluded.



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