Annular Production: Definition, CBM Wells, and Dual Completion

Annular production is the production of hydrocarbons or formation fluids through the annular space between the production tubing string and the innermost casing string, rather than through the bore of the production tubing itself. In a conventionally completed well, formation fluids flow up through the inside of the production tubing while the casing-tubing annulus is isolated by a packer and maintained at a controlled pressure for well integrity monitoring. Annular production reverses this configuration, deliberately routing all or part of the production stream through the annular space, which may be several times larger in cross-sectional area than the tubing bore. The practice arises in four distinct operational contexts: coalbed methane (CBM) and coalbed gas wells, where gas is commonly produced up the annulus while dewatering pumps operate inside the tubing; rod-pumped stripper oil wells with low production rates, where produced liquid may be lifted through the annulus in some legacy completions; dual completion wells with independent perforated intervals, where one zone produces up the tubing and another produces up the annulus simultaneously; and gas-lift operations, where injection gas travels down the casing-tubing annulus to lift formation fluids up the tubing. The physical principles, regulatory requirements, and well integrity implications differ significantly between these contexts, but the common thread is the deliberate use of the annular space as a flow conduit rather than merely as a monitored barrier.

Key Takeaways

• Annular production routes hydrocarbons through the casing-tubing annulus rather than through the tubing bore; it is most common in coalbed methane (CBM) wells, some rod-pumped stripper wells, dual-zone completions, and gas-lift installations where injection gas travels down the annulus.
• In CBM dual-string completions, the industry standard is to produce gas up the annulus (larger flow area, lower pressure drop per unit length) while simultaneously pumping water down through the tubing via a downhole pump or up through the tubing via a rod pump, removing the formation water that holds gas in solution within the coal matrix.
• Annular velocity, defined as the volumetric flow rate divided by the annular cross-sectional area, is the key hydraulic design parameter: if the annular velocity is too low, produced liquids accumulate and load up the annulus, shutting in gas production; if it is too high, erosion of tubing and casing surfaces accelerates and annular pressure builds excessively.
• Regulatory agencies including the UK Health and Safety Executive (HSE), the US Bureau of Safety and Environmental Enforcement (BSEE), and Alberta Energy Regulator (AER) impose specific well integrity requirements on wells producing through the annulus, including maximum sustained casing pressure (SCP) thresholds, mandated pressure tests, and enhanced monitoring frequencies compared to tubing-only producing wells.
• Gas-lift operations, the most widespread artificial lift method globally with installations on hundreds of thousands of producing wells from the Permian Basin to offshore Abu Dhabi, use the casing-tubing annulus as the injection gas conduit in the conventional configuration, making the flow of gas down the annulus and production up the tubing the exact reverse of CBM-style annular production.

Fundamental Definition and Geometry

The annular space in a producing well is the concentric gap between the outer diameter of the production tubing and the inner diameter of the innermost production casing string. In a typical North American land well with 7-inch (177.8 mm) production casing (ID approximately 6.276 inches, 159.4 mm) and 2-7/8-inch (73 mm) production tubing (OD 2.875 inches, 73 mm), the annular cross-sectional area is:

A-annulus = pi/4 * (ID-casing^2 - OD-tubing^2) = pi/4 * (6.276^2 - 2.875^2) = pi/4 * (39.39 - 8.27) = 24.44 sq. in. (157.7 cm^2)

The tubing bore area for 2-7/8-inch tubing with standard ID of 2.441 inches (62.0 mm) is:

A-tubing = pi/4 * (2.441^2) = 4.68 sq. in. (30.2 cm^2)

In this example the annular area is 5.2 times the tubing bore area. For gas at a given wellhead pressure and temperature, the larger the flow area, the lower the pressure drop per unit length of flow path, so for low-rate or low-pressure gas wells the annulus provides a substantially lower-friction flow path than the tubing. This is the primary hydraulic justification for annular production in CBM wells: coal seam gas (methane) is typically produced at low rates and low flowing wellhead pressures, often under 100 psi (690 kPa), and the pressure drop through a tubing string of modest diameter would represent an unacceptably large fraction of the available drawdown. Producing the gas up the larger annulus reduces the flowing pressure drop and improves the net drawdown against the coal seam, increasing gas desorption and production rate. See also: natural gas, production tubing, packer, wellbore.

The physical boundary of the annulus is defined at the bottom by the completion assembly (a production packer or open perforations if no packer is set) and at the top by the wellhead annular isolation valve and tubing head. In a packerless CBM completion, gas and water both enter the annulus from open perforations; the downhole pump (electric submersible pump, ESP, or rod pump) sitting inside the tubing draws down the water level, and gas migrates up the annulus above the perforations while water is pumped up the tubing to surface. In a packer-set dual completion, the packer divides the annulus into an upper zone (producing up the annulus from perforations above the packer) and a lower zone (producing up the tubing from perforations below the packer). See also: casing, annular pressure.

How It Works: CBM and Coal Seam Gas Completions

Coalbed methane (CBM) production exploits methane adsorbed onto the internal surface of coal cleats and micropores. Unlike conventional gas reservoirs where free gas is held in pore space by capillary pressure, coal seam gas is held in adsorbed form and is released only when the reservoir pressure is reduced below the desorption pressure for the local temperature, as described by Langmuir isotherms. Because most coal seams are water-saturated, dewatering the seam to reduce the hydrostatic head is the primary production mechanism; once reservoir pressure drops below desorption pressure, methane begins to desorb from the coal matrix and flows through the cleat network to the wellbore. The dewatering and gas production functions are therefore simultaneous and require two independent flow paths in the same wellbore, which is exactly what the dual-string (annular production) completion provides.

In a typical CBM dual-string completion in the Powder River Basin (Wyoming), the Black Warrior Basin (Alabama), the Bowen Basin (Queensland, Australia), or the Horseshoe Canyon Formation (Alberta, Canada), the well is cased with production casing (commonly 5-1/2-inch, 139.7 mm, or 7-inch, 177.8 mm) and perforated at the coal seam interval. A 2-3/8-inch (60.3 mm) or 2-7/8-inch (73 mm) tubing string is run on a retrievable or permanent production packer or, in many shallow CBM wells, without a packer (open annulus completion). A rod pump or ESP is installed inside the tubing with the pump intake positioned at or below the coal seam perforation interval. When the pump operates, it draws down the water level in the annulus and tubing, reducing the bottomhole pressure against the coal seam. Water is produced up the tubing to the surface pumping unit. Gas, which is less dense than water and rises naturally through the annulus, flows up the casing-tubing annulus to the surface gas gathering system, which is connected to the casing (annulus) valve at the wellhead. The two fluids are separated and metered at the wellhead: water goes to disposal or beneficial use (irrigation, livestock watering in some jurisdictions), and gas is compressed and delivered to the sales pipeline.

Key design parameters for CBM annular production include: the annular liquid unloading velocity, the minimum annular gas velocity required to prevent liquid fallback and accumulation, and the annular pressure rating relative to the formation fracture pressure. Liquid loading in the annulus is the primary cause of declining gas rates in rod-pumped CBM wells: as gas rate falls with reservoir pressure depletion, the annular velocity eventually drops below the critical unloading velocity, liquid accumulates in the annulus, the hydrostatic head increases, bottomhole pressure rises, and further gas desorption from the coal is suppressed. Operators manage liquid loading by reducing pump speed (to allow liquid to accumulate), then running the pump at high speed in intermittent cycles, by plunger lift in the annulus, or by installing velocity strings (smaller-diameter tubing) inside the annulus to increase annular velocity at low flow rates. See also: natural gas, production tubing, annular pressure.