Xstream Lift

More Oil Production

With High Pressure Gas Lift (HPGL)

More Oil Production

With High Pressure Gas Lift (HPGL)

The Problem

The Problem

Our patented ULM technology is available in two versions: Portable trailer-mounted units and Skid mounted units.

Unconventional wells exhibit characteristics that make them challenging to produce, resulting in increased operating costs and high failure rates associated with conventional artificial lift methods.

Severe Wellbore Deviation

Resulting from drilling extended long reach laterals from multi-well pads.

Sand and Solids Production

Resulting from sand and plug parts used in the multi-stage hydraulic fracturing process.

High Initial Well Productivity

With extremely high initial production rates.

Steep Production Declines

With “hyperbolic” style decline curves characteristic of unconventional wells.

Increasing GOR

As the bottom hole pressure falls below bubble point the ratio of gas to oil production increases over time.

Frac Interference

From infill field development as parent wells get hit by offset child well completions resulting in increased bottom hole pressure and high water production that requires de-watering.

Poor Electrical Infrastructure

And long lead times for robust grid construction In remote areas where oil and gas development is typically concentrated.

ESP and Conventional
Gas Lift Characteristics

ESP and
Gas Lift

Historically, the go-to artificial lift methods used for these wells have been Electric Submersible Pumps (ESP), and conventional gas lift. Each of these methods has its strengths and weaknesses, but ultimately results in tradeoffs when addressing the challenging producing environments of unconventional wells.


ESPs are expensive and complicated electromechanical machines, but they excel at producing high volumes of fluids, especially at high water cuts. This is ideal for maximizing new well initial production rates, achieving an accelerated financial rate of returns, and aggressively dewatering frac-hit wells to re-establish hydrocarbon production.

However, because of their electromechanical complexity, reliability can suffer severely due to things like wellbore deviation, sand and solids production, steep production declines, increasing GOR, and poor electrical infrastructure. This results in high failure rates and increased well intervention and workover expenses.

While conventional gas lift systems excel where ESPs fall short, are relatively low-cost, and experience low failure rates, their inability to achieve high initial production rates and dewater frac hit wells limit cashflows, well economics, and can even negatively impact EURs. 

High-Pressure Gas Lift (HPGL) addresses the shortfalls of conventional gas lift to achieve high production rates that compete with, and often exceed, ESP flow rates while maintaining the low cost and high reliability of gas lift.

Conventional Gas Lift vs. HPGL

Conventional Gas Lift vs. HPGL

In conventional gas lift systems, compressed gas is injected down the casing and is produced into the tubing using downhole gas lift valves. This reduces the density of the fluid column and reduces backpressure on the reservoir, allowing fluid to flow to the surface under the natural pressure of the reservoir and the lifting effect of expanding gas as it rises up the wellbore.

There are two primary factors that limit conventional gas lift systems from achieving the high production rates seen with ESPs:

Limited Injection depth

Historically, wellhead gas compression has been limited to 1,200 psi discharge pressure. This restricts how deep gas can be injected into the wellbore and the proportion of the fluid column density that can be reduced. This is especially detrimental in new wells with a high bottom hole pressure and high productivity index, where the conventional gas lift can only inject ~2,500 ft deep on a ~10,000 ft deep well, only able to reduce the density of ¼ of the fluid column.

High-pressure Gas Lift (HPGL) solves this problem by increasing the maximum discharge pressure of the compressor up to 4,500 psi. This allows gas to be injected into the bottom of the wellbore, which in turn lightens the density of the entire fluid column. This maximizes the drawdown of the reservoir by minimizing the backpressure of the hydrostatic pressure acting against it. An HPGL machine with a max discharge pressure of 4,500 psi can inject gas to the bottom of a well 12,000 ft deep with a bottom hole pressure of over 5,000 psi, requiring no gas lift valves.

The majority of wells drilled in the Permian basin are drilled using 5-1/2″ 20# or 23# casing. This limits production tubing options to 2-7/8 or smaller and restricts production flow rates because of the small cross-sectional flow rate.

HPGL solves this by injecting down the tubing and producing up the casing annulus early in the well’s life. Instead of flowing up 2-7/8″ tubing, flowing up the casing annulus with 2-7/8″ tubing inside 5-1/2″ 20# casing almost triples the cross-sectional flow area, a flow area greater than that of flowing up 4-1/2″ tubing. This eliminates any hydraulic friction limitations in the wellbore and allows for the maximum flow rate the reservoir can produce.

Annular Flow Area vs
Conventional Tubing

Annular Flow
Area vs


Conventional Tubing Flow Area:

Annular Flow Area: