Tubingless Completion: Small-Diameter Casing Production, Dry Gas Economics, and Operational Trade-Offs

A tubingless completion is a well-completion design in which reservoir fluids are produced directly through a small-diameter production casing string rather than through a separate production tubing run inside a larger casing string. The casing itself functions simultaneously as the structural conduit to surface and as the flow path for produced hydrocarbons, eliminating the conventional tubing-and-packer configuration and the associated annulus space that normally separates the two strings. In a typical tubingless design, a single 60.3 mm (2 3/8 inch) or 73.0 mm (2 7/8 inch) production casing string is cemented from surface through the producing interval, perforated across the pay, and produced directly to a wellhead Christmas tree without any inner string. The design has been widely used since the 1950s for shallow low-pressure dry gas wells in the United States Hugoton Basin, Texas Panhandle, and Oklahoma, and is also used for small-diameter slimhole exploration wells and for high-volume large-diameter dry gas wells in the Middle East and North Africa, where 244 mm (9 5/8 inch) or 339 mm (13 3/8 inch) casing strings carry gas directly to surface at rates of 280 to 2,800 e3m3/d (10 to 100 MMcf/d). In the Western Canadian Sedimentary Basin (WCSB) the tubingless approach historically saw scattered use in shallow Milk River and Medicine Hat sandstone gas pools across southeastern Alberta and southwestern Saskatchewan, where reservoir pressures of 2 to 4 MPa (290 to 580 psi) at depths of 250 to 450 metres (820 to 1,475 feet) made the cost and weight of a conventional 73 mm tubing string unjustifiable for the marginal gas rates of 1.5 to 14 e3m3/d (50 to 500 mcf/d) per well that characterise these pools. The chief economic attraction is capital cost reduction: a tubingless completion eliminates the tubing string itself (typically 25,000 to 80,000 CAD of materials and labour for a 1,000 metre well), the production packer (8,000 to 18,000 CAD), the tubing hanger and seal assembly, and the running time on the workover rig. For a Milk River shallow gas well drilled at total well cost of 220,000 CAD, the tubingless approach saved roughly 12 to 18 percent of total completion expenditure. The trade-offs are equally well-documented and have caused the design to fall out of favour for any well with significant operational complexity. Without a tubing string, there is no isolated annulus for chemical injection, no path for downhole pressure or temperature monitoring, no mechanism for kill-fluid circulation in well-control situations, no opportunity to deploy artificial lift such as gas lift or plunger lift, and no ability to perform tubing-conveyed perforation or coiled-tubing intervention without significant complication. A casing leak in a tubingless completion is a workover-rig event requiring section milling and cement squeeze rather than a simple tubing pull. The design is regulated in Alberta by AER Directive 008 (Casing and Cementing) and Directive 020 (Well Abandonment), with abandonment requirements identical to conventional wells but slightly less expensive because no tubing pull is required.

Why Tubingless Has Largely Disappeared from New WCSB Wells

The shallow Milk River and Medicine Hat gas plays that justified tubingless completions in the 1980s and 1990s have effectively been exhausted as new-drill targets in Alberta and Saskatchewan; the few thousand remaining producers are mostly mature wells in slow decline. Newer WCSB targets such as Montney, Duvernay, Cardium, and Viking demand multistage horizontal completions with high pressure ratings, multiple intervention options, and full artificial lift capability, all of which require a conventional tubing-and-packer configuration. The tubingless approach also struggles in any well that produces measurable liquids, since liquid loading in a single casing flow path leads to slugging, intermittent flow, and ultimately well death without intervention options. New tubingless completions in the WCSB today are extremely rare.

Tubingless Design in Middle East High-Rate Gas Wells

While tubingless completions have faded from North American practice, the design remains common in dry, sweet gas reservoirs in the Middle East and North Africa, where 244 mm (9 5/8 inch) or 339 mm (13 3/8 inch) production casing strings are perforated directly across thick carbonate gas pays and produced at rates up to 2,800 e3m3/d (100 MMcf/d) per well. Operators in Qatar, Saudi Arabia, and Algeria have used this approach extensively in Khuff and Triassic gas reservoirs at depths of 3,000 to 4,500 metres. The economics work because the gas is dry, the reservoirs are at relatively modest pressure, and the rates are high enough that even small drawdown across the perforations supports commercial production without artificial lift.

Related Terms

Tubingless completion sits within a family of well architecture decisions made early in field development. Production tubing describes the conventional inner string that tubingless designs explicitly omit and explains why the trade-offs around chemical injection, intervention, and artificial lift are so significant when tubing is absent. Casing covers the structural string that doubles as the production conduit in a tubingless design, with grade, weight, and pressure-rating selection becoming more critical when the casing must perform both roles. Slimhole drilling and completion practice often goes hand-in-hand with tubingless designs because both approaches target lower-cost wells in low-productivity reservoirs where conventional architecture cannot be justified economically.

Real-World WCSB Tubingless Scenario

A southeastern Alberta operator drills a 380 metre (1,247 feet) Milk River gas well in the Medicine Hat field at a total drilling cost of 95,000 CAD. The reservoir is dry sweet gas at 3.2 MPa (464 psi) bottomhole pressure with expected initial rate of 7 e3m3/d (247 mcf/d). Conventional completion with 73 mm tubing, packer, and full Christmas tree is bid at 78,000 CAD. The operator selects a tubingless completion with 73 mm K-55 casing cemented to surface, a single perforation interval of 4 metres across the Milk River sand, and a basic dry-gas Christmas tree at completion cost of 51,000 CAD. Capital saving is 27,000 CAD or 35 percent of conventional completion cost.

The well produces 6.4 e3m3/d (226 mcf/d) for the first six months, declining to 2.1 e3m3/d (74 mcf/d) by month 36. Net present value at 5 CAD/GJ gas price calculations shows the well payout at 19 months, two months sooner than the conventional design alternative. After year 4 the well begins loading liquids from condensate accumulation and is plugged and abandoned under AER Directive 020 at total decommissioning cost of 38,000 CAD, slightly below the 44,000 CAD that would have been spent on a conventional abandonment.