Chamber lift

Chamber lift is a form of intermittent-flow gas lift. The chamber installation design determines the success of this type of gas lift operation.

Primary reasons for selecting a chamber lift

There are three primary reasons for selecting a chamber lift to gas lift a well:

1. To lower the depth of gas injection in a low-flowing-bottomhole-pressure well with a long perforated interval or open hole.
2. To fully use an available injection-gas pressure that significantly exceeds the flowing bottomhole pressure in terms of the pressure resulting from the starting slug length.
3. To attain the lowest possible average flowing bottomhole pressure by reducing the fluid-head backpressure against the formation for a given liquid feed-in volume.

Types of chamber lift designs

Although there are numerous variations in the physical design of a chamber, the two fundamental types are the two-packer and the insert bottle type for collecting the well fluids. Both types are shown in Fig. 1. The two-packer chamber utilizes the casing annulus for accumulation of the well fluids. The insert type of chamber is usually fabricated from the largest pipe that can be safely run inside of the casing or open hole. Chamber location and size relative to the working fluid level, the injection- and formation-gas venting, the injection-gas rate through the chamber-operating gas lift valve for lifting the slug, and properly using the chamber-lift principle can be the difference between efficient and inefficient chamber-lift operations.

• 

  Fig. 1-Two basic types of gas lift chambers.

Chamber-lift principle

The chamber-lift principle implies that the injection gas initially contacts the top of the liquid column in the chamber and displaces this liquid into the tubing above the chamber before injection gas enters the lower end of the dip tube. The dip tube is assumed to be filled with liquid at the beginning of an injection-gas cycle; that is, the top of the chamber is located at the working fluid level. The accumulated liquid in the chamber annulus is U-tubed into the tubing above the chamber before injection gas entry into the lower end of the dip tube. Chamber-lift operation prevents water accumulation in the production conduit because the water is U-tubed first from the chamber, followed by the oil, and then by the injection gas.

Design considerations and chamber length

The chamber length should be calculated on the basis of an injection-gas pressure that is 60 to 75% of the initial opening pressure of the chamber-operating gas lift valve to ensure adequate pressure differential across the liquid column at the instant the injection gas enters the lower end of the dip tube. Actual operations have shown higher chamber-lift efficiency when the chamber length is based on an injection-gas pressure that is at least 60 to75% of the opening pressure of the chamber-operating gas lift valve. An adequate pressure differential across the liquid slug is necessary to ensure maximum liquid recovery with a minimum of injection-gas breakthrough during displacement to the surface.

....................(1)

....................(2)

and

....................(3)

where

PioDc	=	injection-gas pressure at depth for calculating chamber length, psig,
PoDov	=	injection-gas initial opening pressure of the chamber-operating gas lift valve at depth, psig,
Lc	=	chamber length, ft,
PtDc	=	tubing pressure at chamber depth based on Pwh when chamber-operating gas lift valve opens, psig,
glc	=	average pressure gradient for liquid production in chamber, psi/ft,
Fat	=	ratio of physical capacities per foot of chamber annulus/tubing above chamber, dimensionless,
Vca	=	capacity per foot of casing or chamber annulus, ft3/ft,
and
Vt	=	capacity per foot of tubing above chamber, ft3/ft.

The actual chamber length is the distance from the top of the chamber to the lower end of the dip tube. The chamber-length equation is based on three assumptions:

• The top of the chamber is located at the working fluid level between injection-gas cycles
• The dip tube is full when the chamber-operating gas lift valve opens
• The physical size of the chamber and dip tube do not change over the entire chamber length

The chamber-length equation must be modified for other geometries and assumptions.

Example problem: two-packer chamber-length calculations

The following data are given for a two-packer chamber at 6,000 ft (top packer):

• Casing size = 7-in. OD, 26 lbm/ft.
• Tubing and dip tube size = 2 7/8-in. OD.
• P_oDov = 800 psig at 6,000 ft.
• g_lc = 0.40 psi/ft.
• P_tDc = 100 psig at 6,000 ft.
• V_ca = 0.1697 ft³/ft.
• V_t = 0.0325 ft³/ft.

Calculate the approximate chamber length using Eqs. 1 through 3.

and

Unloading valve depths

The unloading valve spacing calculations for a chamber installation are the same as the valve depth calculations for an intermittent installation with the exception of the bottom unloading valve. The bottom unloading gas lift valve should be within a few joints of the chamber-operating valve because the depth of gas-injection for the chamber-operating valve is the lower end of the dip tube rather than the actual valve depth, and the fluid-slug length above the valve is based on the chamber annular capacity plus the dip-tube length. The initial opening pressure of a chamber-operating gas lift valve should be at least 50 psi lower than the initial opening pressure of the bottom unloading valve in most installations to ensure lifting from the chamber-operating valve. The tubing pressure at the top of a properly designed chamber that is located at the working fluid level will be near wellhead tubing pressure. The operating-chamber valve must have proper spread characteristics (difference between the operating valve initial opening and closing pressures in the well) to prevent excessive injection-gas usage per cycle. Pilot-operated gas lift valves are widely used as the chamber-operating valve because a large port is available with controlled spread characteristics.

There can be a significant pressure differential across the standing valve immediately after the liquid slug surfaces and blowdown occurs. A mechanical-locking-type standing valve is recommended to prevent the standing valve from being blown out of its seating nipple from this pressure differential.

Importance of chamber-bleed valve

An important consideration is the design and operation of the chamber-bleed valve for venting free gas in the upper section of the chamber after an injection-gas cycle. Most of the free gas is injection gas trapped above the increasing fluid level in the chamber during fill-up. A liquid seal at the lower end of the dip tube occurs soon after a liquid slug surfaces and the injection-gas velocity in the tubing begins to decrease. The liquid seal results from liquid fallback accumulating in the lower end of the dip tube and chamber. Injection-gas from the previous chamber U-tubing cycle is trapped in the chamber annulus above the lower end of the dip tube. The trapped injection gas from the previous injection-gas cycle must be vented from the chamber annulus before the chamber can fill with liquid. If the injection gas is not vented, the trapped injection gas will reduce the liquid production entering the chamber. Without venting the trapped injection gas, a portion of the production entering the chamber increases the length of the liquid column in the tubing. If a significant volume of the reservoir-liquid production fills the tubing above the chamber, the major benefit of an accumulation chamber is nullified in terms of lowering the liquid-column backpressure against the formation. Differential valves have been used as chamber-bleed valves. The differential valve must be properly set with choke sizes that ensure closure immediately after the chamber-operating gas lift valve opens.

Description of chamber-lift injection-gas cycle

A complete injection-gas cycle of operation for chamber lift is described for stabilized operation after unloading. Stabilized production infers that the well has unloaded the kill fluid, all production is from the reservoir, and the production per injection-gas cycle remains approximately the same.

When the chamber-operating valve opens, the standing valve closes. The liquid column in the chamber annulus is U-tubed into the dip tube and tubing above the chamber to form the starting-liquid-slug length. A portion of the starting liquid slug is displaced to the surface by the injection gas. Not all of a starting liquid slug reaches the surface because of injection-gas breakthrough and resulting liquid fallback during displacement.

While the standing valve is closed and the liquid slug is surfacing, the reservoir fluid feed-in continues to enter the wellbore. Formation production enters the casing annulus between the chamber outside diameter (OD) and casing ID of an insert chamber or below the bottom packer of a two-packer chamber installation. Reservoir production cannot enter the chamber while the standing valve is closed. All free gas, including the formation and trapped injection gas, is vented into the tubing through the chamber bleed valve in a properly designed two-packer installation. The formation-gas production in the annular area between the insert chamber OD and casing ID beneath the packer should be vented into the tubing above the chamber to prevent a significant decrease in the maximum daily production from a high-PI, low-flowing-bottomhole-pressure well.

Free-gas problems with insert chambers

Gas separation occurs beneath the packer in the annulus between the insert chamber OD and casing ID. The formation free gas accumulates above the liquid level in this annulus. This trapped formation free gas is compressed by the new production entering the wellbore. The additional formation free-gas production is added to the trapped free gas beneath the packer as the formation free gas separates from the liquid production. This trapped free gas under the packer restricts the total volume of produced-liquid accumulation in the casing-ID/insert-chamber-OD annulus below the packer.

After a liquid slug surfaces, the injection gas in the tubing exhausts into the flowline, and the flowing bottomhole pressure in the chamber decreases. The standing valve opens when the pressure in the chamber is less than the reservoir pressure beneath the standing valve. The liquid in the casing/chamber annulus below the gas/liquid level flows into the chamber first. Liquid is followed by the trapped formation free gas from the casing/chamber annulus until the annulus and chamber pressures are equal at the depth of the standing valve. The casing/chamber annulus between the packer and standing valve depth is totally filled with formation free gas and no liquid at the equalized minimum flowing bottomhole pressure between injection-gas cycles.

The injection-gas cycle frequency depends on the well deliverability. When maximum cycle frequency is required, the next injection-gas cycle begins as soon as the tubing wellhead pressure approaches the production-header (separator) pressure. Time-cycle control of the injection-gas cycle is required to ensure maximum cycle frequency. A very short time after beginning the surface injection-gas cycle, the chamber-operating valve opens and the standing valve closes. Because of the high injection-gas cycle frequency, most of the well production enters the wellbore while the standing valve is closed and the liquid slug is surfacing. As a result, nearly all of the liquid entering the chamber is the liquid accumulation in the casing/chamber annulus before the standing valve opens. Very little production enters the chamber directly from the reservoir because the standing valve is open for a much shorter length of time than it is closed at maximum injection-gas cycle frequency. The solution to this problem is to vent the free gas in the casing/chamber annulus beneath the packer into the tubing above the chamber. The separated formation gas would not be trapped in this annular space. The casing opposite the insert chamber annulus could fill with liquid if the free gas was vented into the tubing above the chamber. When the standing valve opens after a slug surfaces and the pressure in the chamber decreases, mostly liquid rather than free gas enters the chamber when free gas is vented from below the packer.

If a well is producing less than 10 to 20 B/D and is requiring less than 6 or 12 injection-gas cycles per 24 hours, the free gas in the casing annulus is not a serious a problem. Most of the reservoir-fluid production enters the wellbore while the standing valve is open during the long time interval between injection-gas cycles. The free-gas volume above the liquid level in the chamber annulus has sufficient time to flow into the dip tube through a small orifice or bleed valve. One reason that inefficient insert chamber operations in a high-injection-gas-cycle frequency, gassy well is not addressed in the literature is the fact that most low-cost insert-chamber installations use a hookwall packer and hanger nipple, as illustrated in Fig. 1a . This is the type of insert chamber that is run in low-rate, "stripper-type" wells.

There may be little benefit from an insert-chamber installation in a gassy well with a high-frequency injection-gas cycle if the design does not provide a means to vent the trapped free gas below the packer as shown in Fig. 2. Improved chamber-lift operations can be expected by installing a gravity-closed or spring-loaded gas lift valve check below the packer. A tubing-retrievable conventional gas lift mandrel and check valve is run upside down between the packer and top of the insert chamber in Fig. 3. Wireline- instead of tubing-retrievable equipment can be used. Adding a screen to the check-valve inlet is recommended to prevent trash in the well fluids from entering and preventing the check dart from closing. The check valve adds very little cost to this type of chamber installation. Because liquid, rather than trapped formation gas, is in contact with the formation in the casing annulus, better reservoir-liquid feed-in between injection-gas cycles should occur. Only the trapped formation free and injection gas in the chamber must vent through the chamber-bleed valve.

• 

  Fig. 2-Bypass-packer insert-chamber installation without venting free gas below packer.

• 

  Fig. 3-Bypass-packer insert-chamber installation with free-gas vent valve below packer.

Nomenclature

PioDc	=	injection-gas pressure at depth for calculating chamber length, psig,
PoDov	=	injection-gas initial opening pressure of the chamber-operating gas lift valve at depth, psig,
Lc	=	chamber length, ft,
PtDc	=	tubing pressure at chamber depth based on Pwh when chamber-operating gas lift valve opens, psig,
glc	=	average pressure gradient for liquid production in chamber, psi/ft,
Fat	=	ratio of physical capacities per foot of chamber annulus/tubing above chamber, dimensionless,
Vca	=	capacity per foot of casing or chamber annulus, ft3/ft,
Vt	=	capacity per foot of tubing above chamber, ft3/ft.

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See also

Intermittent-flow gas lift

Intermittent-flow gas lift installation design

Intermittent gas lift plunger application

Gas lift

PEH:Gas_Lift