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Casing vs. liner vs. tie-back, explained

All three line the hole with steel — the difference is where the pipe starts. That one choice drives cost, hydraulics, wellhead loads and late-life integrity, and each option is drawn differently on the schematic.

By WellSchema Engineering · July 9, 2026

Every cased hole section ends with the same decision: run the pipe all the way back to surface, or stop it partway up. A full casing string runs from total depth of the section to the wellhead. A liner is the same pipe but hung off inside the previous string, a few hundred feet above the previous shoe. A tie-back converts a liner into a full string later, by running pipe from the liner top back to surface. The physics is identical — the economics and risk profile are not.

A production liner: the 7" string starts at 8,200 ft — inside the 9 5/8" intermediate casing — instead of running to surface. The overlap between 8,200 ft and the 8,600 ft intermediate shoe is the liner lap.

Casing: the default

A full string is the simple, robust answer. It hangs from the wellhead, gives you a continuous new pressure vessel from TD to surface, and needs no downhole hanger or lap to seal. The costs are equally simple: you buy and run the entire length of pipe, the wellhead must carry its weight, and in deep wells the surface casing and rig hook load both feel it.

Liner: pay for pipe only where you need it

A liner is hung from a liner hanger set inside the previous casing, typically with a 200–500 ft overlap called the liner lap. The lap is cemented (and often fitted with a packer) because it is now a pressure-containing joint in the well envelope. Engineers choose liners to:

Save steel — in an 11,800 ft well, starting the 7" string at 8,200 ft saves over 8,000 ft of pipe.
Reduce loads — less hanging weight on the wellhead and less hook load while running.
Improve hydraulics for the next phase — above the liner top you keep the larger casing ID, which matters for drilling fluid hydraulics and for large completions.
Keep options open — the well can be tied back to surface later if conditions demand it.

The liner lap is the classic weak point: a poor cement job across the lap is a leak path that full strings simply do not have. If a liner lap fails a pressure test, expect a squeeze job before moving on.

Tie-back: the liner's insurance policy

A tie-back string stabs into a receptacle at the top of an existing liner and runs from there to the wellhead, restoring a continuous string — usually cemented, sometimes left as an uncemented production conduit. Common triggers:

The drilling phase revealed higher pressures or H2S/CO2 than the intermediate casing was designed to see long-term.
A high-rate or gas-lift completion needs new, gas-tight pipe to surface rather than old intermediate casing of uncertain condition.
The intermediate string is worn from drilling below it (casing wear from rotating drillpipe is real and cumulative).

Choosing between them

	Full casing	Liner	Liner + tie-back
Steel cost	Highest	Lowest	Middle (staged)
Wellhead / hook load	Highest	Lowest	Middle
Integrity risk	Lowest — no lap	Lap is a potential leak path	Lap + tie-back seal, but new pipe to surface
When it wins	Shallow wells, simple designs	Deep wells, big completions above	Liner wells that met worse conditions than planned

How each looks on the schematic

On a correctly drawn schematic the distinction is immediate: a full string's walls run to the top of the drawing; a liner's walls start partway down, inside the previous string, with the hanger at its top and the lap overlapping the previous shoe. A tie-back appears as a separate string from the liner top to surface, nested in the same annulus. If a drawing shows a "liner" running to surface, the drawing is wrong — and wrong drawings cause wrong barrier diagrams.