inside diameter, Oil & Gas Glossary

Inside diameter, abbreviated ID, is the internal bore measurement of any tubular used in a wellbore, including casing, tubing, drillpipe, liner, and surface flowlines. It is the dimension that controls how much fluid can pass through the pipe, what tools and bottomhole assemblies can run inside it, and how much hydrostatic and friction pressure develops during circulation. ID is always reported together with outside diameter (OD) and a nominal weight per unit length, because for a given OD the wall thickness sets both the weight and the resulting bore. A joint of 7 in OD casing rated at 26 lb/ft (38.7 kg/m) has a published ID of 6.276 in (159.4 mm), while the heavier 32 lb/ft (47.6 kg/m) string of the same OD has an ID of only 6.094 in (154.8 mm); the extra 0.182 in of steel on the wall is what carries the higher burst and collapse rating but costs flow area. In the Western Canadian Sedimentary Basin operators specify these combinations against the American Petroleum Institute standards, principally API Spec 5CT for casing and tubing and API Spec 5DP for drillpipe, which tabulate ID, drift diameter, wall thickness, and tolerances for every grade and weight. The bore is never assumed to be perfectly round or perfectly to gauge, so a slightly smaller drift diameter is published alongside ID: drift is the guaranteed minimum bore a standardized drift mandrel will pass, and it, not the nominal ID, is the number a completions engineer uses to confirm that a packer, a 4.5 in liner, a downhole pump, or a wireline tool string will run to depth without hanging up. Capacity and displacement also flow directly from ID, since the internal volume per metre or per foot is proportional to the square of the bore; for a 4.5 in tubing at 12.75 lb/ft the internal capacity is roughly 0.01422 bbl/ft, a figure drillers and frac crews multiply by depth to size pump displacement, calculate slug volumes, and track returns. Because ID drives flow, tool access, and volume simultaneously, it sits at the centre of casing-design decisions in long Montney and Duvernay horizontals where one extra sixteenth of an inch of bore can decide whether a planned multistage frac sleeve assembly fits.

Key Takeaways

ID Is Set by OD Minus Two Wall Thicknesses: For any tubular, ID equals OD minus twice the wall thickness, so for fixed OD a heavier weight per foot means a thicker wall and a smaller bore. A 5.5 in casing at 17 lb/ft (25.3 kg/m) drifts to about 4.767 in (121.1 mm); the same OD at 23 lb/ft drifts to roughly 4.545 in. Engineers trade flow area against burst and collapse strength every time they pick a weight.
Drift Diameter, Not Nominal ID, Governs Tool Passage: API Spec 5CT publishes a drift diameter slightly smaller than nominal ID to guarantee a standard mandrel will pass. Completions crews drift every joint before running it, because a packer or pump sized to nominal ID can still hang up if a joint is out of round or has a thick wall within tolerance.
Capacity Scales With the Square of the Bore: Internal volume per length is proportional to ID squared, so capacity in bbl/ft or m3/m falls sharply as bore shrinks. Drillers use these factors to compute pump strokes to bottoms-up, displacement volumes for cement jobs, and slug sizing, where an error in assumed ID propagates straight into wrong returns calculations.
Friction Pressure Rises Steeply as ID Falls: Frictional pressure loss during circulation or fracturing scales roughly with the inverse fifth power of bore for turbulent flow, so a small reduction in tubing ID can sharply raise surface treating pressure. In long WCSB laterals this is why operators often run larger production casing to keep frac horsepower and pump-down rates economic.
API Specs 5CT and 5DP Standardize the Numbers: ID, drift, wall, and tolerances are not vendor opinions; they come from API Spec 5CT for casing and tubing and API Spec 5DP for drillpipe. Canadian operators reference these standards in their casing-design programs and AER Directive 010 well-completion expectations so that strings ordered from any mill interchange on dimension and rating.

Reading an ID, OD, and Weight Combination on a Casing Tally

A casing tally for a Montney horizontal might list 177.8 mm (7 in) OD intermediate casing at 34.2 kg/m (23 lb/ft) over the build section, with a published ID of 6.366 in (161.7 mm) and a drift of 6.241 in (158.5 mm). The completions engineer reads three numbers from that single line: the bore that sets pump-down rate, the drift that confirms a 4.5 in frac liner or a coiled-tubing bottomhole assembly will pass, and the weight that fixes the collapse rating against the formation pressure at total depth. If the production casing is later stepped to 25.3 kg/m to handle deeper overpressure, the bore tightens and every downstream tool clearance must be re-checked against the new drift, not the old nominal ID.

ID Selection in Long Horizontal Completions

In Duvernay and Montney laterals exceeding 3,000 m measured depth, the production casing ID is a first-order economic lever. A larger bore lowers frac friction, raises achievable pump-down rate for plug-and-perf or sliding-sleeve work, and lets larger-OD coiled tubing reach the toe for milling. The penalty is cost and the collapse-rating constraint: a thinner wall to gain bore can fail under depletion or frac-driven stresses. Operators such as ARC Resources and Tourmaline weigh 139.7 mm versus 114.3 mm production strings on exactly this trade, since the larger ID can cut treating pressure enough to drop one pump unit off the frac spread.

Fast Facts

The difference between nominal ID and drift diameter is deliberately small but it has stopped many jobs. API drift mandrels for casing 9.625 in and smaller are 42 in long and only 0.125 in under nominal bore; for larger casing the mandrel grows to 12 in long and the drift allowance widens. A single joint that drifts within API tolerance but is at the low end of bore has hung up retrievable packers run to nominal ID, which is why field crews drift-test every joint on the pipe rack before it ever goes in the hole.

Inside diameter is meaningless without its companion outside diameter, since the two together with weight define wall thickness and rating. The bore is the running clearance for casing and tubing strings, and it directly sets the drift diameter that completions crews verify before running packers and pumps. Bore size also governs the annulus geometry between two strings, which in turn controls cement displacement efficiency and circulating pressure.

Real-World WCSB Scenario: A Tight Liner in the Montney

A Grande Prairie operator planned a 114.3 mm (4.5 in) cemented liner inside 177.8 mm (7 in) production casing on a Montney well near Karr, then specified a 73 mm (2.875 in) frac string to run through the liner for a remedial isolation job. The liner had been ordered at 18 lb/ft, giving a drift of about 3.875 in, but the chosen frac tool string measured 3.92 in at its largest sub. Pre-job drift records flagged the conflict before mobilization, avoiding a stuck-tool fishing operation that would have cost roughly CAD 180,000 in rig time and tool recovery.

The crew swapped to a slimmer 3.75 in tool string and the job ran without incident. The lesson booked into the operator's completions standard was simple: size every through-tubing tool against published drift from the API Spec 5CT tables, never against nominal ID, because the gap between the two is exactly where downhole jobs get stuck.