What is HPGL?
"High Pressure Gas Lift", abbreviated to "HPGL", also called "Single Point High Pressure Gas Lift" or "SPGL", is an artificial lift method, a type of modified Gas Lift that uses high pressure gas to produce oil and gas wells without the need for gas lift valves, and takes advantage of downhole hydraulic forces to maximize well production.
Unconventional wells exhibit characteristics that make them challenging to produce, resulting in increased operating costs and high failure rates:
Severe wellbore deviation from drilling multi-well pads and achieving well spacing with long reach laterals
Sand and solids production from sand and plug parts from the frac and drillout
High initial well productivity with extremely high IP rates
Steep production declines with “hyperbolic” trends characteristic of unconventional wells
Increasing Gas to Oil ratio as the well ages
Frac Interference from infill development, resulting in high bottom hole pressure and high water cut requiring de-watering
Poor electrical infrastructure in remote areas where oil and gas development is concentrated
Historically, the go-to artificial lift methods used to lift unconventional wells have been Electric Submersible Pumps (ESP) and conventional gas lift. Each of these methods have their strengths and weaknesses, but ultimately result in tradeoffs when addressing the challenging producing environments of unconventional wells:
Severe Wellbore Deviation
Sand & Solids Production
High Initial Production Rates
Steep Production Declines
Poor Electrical Infrastructure
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 accelerated financial rate of returns, and aggressively dewatering frac hit wells to re-establish hydrocarbon production. But 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, it’s inability to achieve high initial production rates and dewater frac hit wells limit cashflows, well economics, and can even negatively impact EUR’s.
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
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 fluid column and reduces backpressure on the reservoir, allowing fluid to flow to 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 system from achieving the high production rates seen with ESPs:
Limited injection depth
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 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 max discharge pressure of the compressor up to 4,500 psi. This allows gas to be injected to the bottom of the wellbore, which in turn lightens 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 injection 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.
Conventional Tubing Flow Area
Cross Sectional Flow Area
2-3/8” 4.6# Tubing
2-7/8” 6.5# Tubing
3-1/2” 9.3# Tubing
4-1/2” 12.75# Tubing
Annular Flow Area
Cross Sectional Flow Area
2-3/8” tubing inside 5-1/2” 20# Casing
2-7/8” tubing inside 5-1/2” 20# Casing
2-3/8” tubing inside 5-1/2” 23# Casing
2-7/8” tubing inside 5-1/2” 23# Casing