API 5CT Tubing Sizes and Weights: Complete Selection Guide

Production tubing is the innermost pipe string in an oil or gas well — the conduit through which reservoir fluids flow to surface. Selecting the right OD, weight, and connection type for the well design determines both the flow capacity of the completion and the mechanical integrity of the string across the full loading envelope from installation to abandonment. API Specification 5CT, 11th Edition defines the dimensional requirements for production tubing from 1.05-inch through 4.5-inch OD, covering three connection types and a wide range of wall thicknesses per size.

ZC Steel Pipe manufactures API 5CT production tubing in grades J55, N80, L80, P110, and L80-13Cr, covering the 1.9-inch through 4.5-inch OD range. Supply includes NU, EU, and premium-connection tubing for operators and EPC contractors in Africa, the Middle East, South America, and Southeast Asia, with EN 10204 3.1 MTCs and PSL-2 inspection available on all grades.

What Is API 5CT Production Tubing?

Production tubing is a tubular string run inside the casing after the well is perforated, designed to convey formation fluids to the surface and to be pulled and replaced during the well's producing life. Unlike casing, which is cemented in place, tubing sits inside the casing string and is set by a production packer positioned near the perforations. The annulus between the casing ID and tubing OD is used for annulus pressure monitoring, chemical injection, or gas lift.

The tubing string must withstand:

• Axial tension from self-weight and thermal expansion
• Internal pressure from reservoir and wellbore fluids
• External collapse pressure from the casing fluid column
• Corrosive environments: CO2, H2S, brine, and combined systems

Unlike casing, tubing is a consumable. Grades and weights are selected to last the well's economic life without requiring an unplanned workover for tubing replacement.

API 5CT Tubing OD Range and Weight Designations

API Specification 5CT defines tubing in ten nominal OD sizes from 1.05 inches to 4.5 inches. Each size is available in several wall thickness options, expressed as nominal weight in pounds per foot (lb/ft). Heavier weight means thicker wall, higher burst and collapse pressure ratings, and higher tensile capacity — at the cost of reduced bore ID and flow area.

The connection type — NU (non-upset), EU (external-upset), or IJ (integral joint) — affects the available OD at the connection and, for NU and EU types, the tensile efficiency of the joint relative to the pipe body.

For the complete burst, collapse, and tensile performance calculations by OD and weight, see the API 5CT specification tables →

To match tubing size and grade to well conditions, use the AI Pipe Grade Selector →

Tubing Size and Weight Table

The following table covers the primary commercial sizes from API Specification 5CT, 11th Edition Table C.19. Dimensions are as defined in the standard.

Source: API Specification 5CT, 11th Edition, Table C.19. Weight values are nominal plain-end unless noted. Full table includes additional weight options per OD not shown here.

The two most commercially significant sizes are 2 3/8-inch and 2 7/8-inch, which together account for the majority of tubing orders in our supply chain. Within each OD, the weight choice is not a minor specification detail — it changes the ID, the flow area, and the pressure ratings by margins that directly affect well deliverability and completion integrity. Read the weight column together with the ID column, not in isolation.

Weight Selection for 2 7/8-Inch Tubing: Burst Comparison

The Barlow burst pressure formula (API 5C3 minimum wall basis) is:

P_burst = 0.875 × (2 × SMYS × t / OD)

Where 0.875 is the API minimum wall tolerance factor (87.5% of nominal wall), SMYS is the specified minimum yield strength in ksi, t is the nominal wall thickness in inches, and OD is the outside diameter in inches.

For 2-7/8 inch L80 Type 1 (SMYS = 552 MPa / 80 ksi), the calculation for the two most common weight options:

2-7/8" 6.40 lb/ft L80 (OD = 73.02 mm / 2.875 in, wall t = 5.51 mm / 0.217 in): P_burst = 0.875 × (2 × 80 × 0.217 / 2.875) = 0.875 × 12.08 = 10,570 psi (72.9 MPa)

2-7/8" 8.60 lb/ft L80 (OD = 73.02 mm / 2.875 in, wall t = 7.82 mm / 0.308 in): P_burst = 0.875 × (2 × 80 × 0.308 / 2.875) = 0.875 × 17.15 = 15,006 psi (103.5 MPa)

The 42% burst improvement from 6.40 to 8.60 lb/ft is substantial — but the 13% reduction in flow area is not trivial in gas wells. A well producing at 5 MMscfd through 2-7/8" tubing sees a measurable increase in flowing tubing pressure if the heavier weight is selected without a corresponding velocity check. Run both the pressure design and the nodal analysis before committing to a weight.

Use the Barlow pressure calculator → to check ratings for your specific OD, wall, and grade.

Connection Types: NU, EU, and Integral Joint

Non-Upset (NU)

The pipe body OD continues through the pin end without enlargement. The coupling OD is larger than the pipe body. NU connections have lower tensile efficiency — approximately 80% of pipe body cross-sectional area — and are suitable for moderate-depth wells and lower tension loads. NU is the most economical connection option for shallow completions where tensile design is not the governing limit.

External-Upset (EU)

The pipe wall is thickened at the pin end by hot-working (upsetting) the tube ends before threading. This allows a fuller thread form and higher tensile efficiency approaching 100% of pipe body. EU is the standard connection for wells deeper than 2,000 m, deviated wells where bending loads add to tension, or any application where the tensile safety factor governs the design. EU is also preferred in wells where repeated workover running of the tubing string increases the cumulative fatigue at the connection.

Integral Joint (IJ)

The pin and box are machined directly into the pipe wall without a separate coupling. The OD at the joint is close to pipe body OD — typically pipe body OD plus a small thread engagement allowance. IJ availability is limited to specific OD and weight combinations (see the table above). IJ connections are used where coupling OD is a constraint, such as slim-hole completions or wells where the coupling must pass through a restriction.

For full connection performance data and running procedures, see the API 5CT tubing connections guide →.

Grade Selection by Well Conditions

The tubing grade is selected to meet the mechanical load requirements of the completion design and the corrosion resistance requirements of the reservoir environment.

The maximum hardness limits for sour service grades are defined by API Specification 5CT, 11th Edition and enforced by NACE MR0175 / ISO 15156 to prevent sulfide stress cracking:

• L80 Type 1: 23 HRC maximum
• C90: 25.4 HRC maximum
• T95: 25.4 HRC maximum

For wells where CO2 partial pressure exceeds approximately 0.02 MPa (3 psi), sweet-service carbon steel grades such as J55 and N80 corrode at rates that typically require either inhibition or upgrade to a chromium-bearing grade. The threshold for selecting L80-13Cr over inhibited carbon steel depends on CO2 partial pressure, chloride concentration, temperature, and the economic comparison between chemical injection cost and the grade upgrade premium.

Named Tubing Selection Failure Modes

Understanding what goes wrong in tubing selection is more useful than understanding what the standard says in isolation. Three failure modes appear repeatedly in OCTG order reviews and completion post-mortems.

Failure Mode 1: Undersized Drift — Logging Tool Stuck in Tubing

Mechanism: When the drift diameter is not specified on the PO, or is specified at the API default without checking it against the planned downhole tool suite, the result is a well where the planned perforating gun, bridge plug, or logging tool cannot be run through the tubing. The tool is either too large to enter the tubing at surface, or enters the tubing but becomes stuck at a connection where the bore is slightly smaller than the pipe body bore due to coupling shoulder protrusion or scale buildup.

Diagnostic: Tool cannot be stabbed into the tubing at surface, or lands off-depth — tool weight indicator shows sudden resistance below a connection collar. Caliper log shows restriction at connection depth. Drift gauge at surface confirms tubing bore below the tool OD.

Fix: Before finalizing tubing size and weight, create a tool compatibility register: list every planned downhole tool (perforating gun, formation tester, logging tool, gas lift valve, coiled tubing OD) and its maximum OD. The tubing drift specification on the PO must exceed the maximum tool OD plus the operator's running clearance (typically ≥ 3mm radial, 6mm diametrical).

Failure Mode 2: Insufficient Burst Rating — L80 Replaced by J55 at Procurement

Mechanism: A completion is designed for 2-7/8 inch L80 tubing with a reservoir pressure of 8,500 psi (58.6 MPa). Procurement substitutes J55 — identical OD, weight, and connection — because J55 is in stock and L80 has a 6-week lead time. J55 6.40 lb/ft burst rating at minimum yield (55 ksi): P = 0.875 × (2 × 55 × 0.217 / 2.875) = 7,264 psi (50.1 MPa). The reservoir pressure of 8,500 psi exceeds the J55 burst rating by 17%. During a kill operation with bullheading, the tubing fails.

Diagnostic: Tubing rupture during high-pressure operation. Maximum surface treating pressure exceeded the design rating. Grade marking on the pipe body shows J55 (one green band) where L80 (one red + one brown band) was specified.

Fix: Never substitute a lower grade in tubing procurement without running the burst and collapse calculations for the substitute grade against the well design pressure. Verify grade by color code at goods receipt. In emergency procurement situations, run a de-rated well design based on the available grade before accepting the substitution.

Failure Mode 3: L80 vs L80 Type Substitution — Wrong Type Delivered

Mechanism: A PO specifying "L80 tubing" without the type designation receives L80-3Cr or L80-9Cr from a mill clearing stock. These grades are mechanically identical to L80 Type 1 but contain 3% or 9% chromium. In a sour-service well where H₂S is present, L80-3Cr and L80-9Cr do not have the same NACE MR0175 / ISO 15156 qualification basis as L80 Type 1 carbon steel — the chromium variants have different hydrogen permeation characteristics that require separate qualification testing. The mill's MTC reads "L80" — technically accurate but misleading.

Diagnostic: MTC lists "L80-3Cr" or "L80-9Cr" on the chemistry section while the grade line reads "L80." Well classified as sour service. Engineering review discovers the type substitution was not disclosed.

Fix: Always specify "L80 Type 1" — not "L80" — on every PO line for sour-service applications. This is explicitly addressed in API Specification 5CT, 11th Edition which distinguishes Type 1, 3Cr, 9Cr, and 13Cr as separate products. The three-character type designation on the PO is the only document control that prevents type substitution.

Drift Diameter and ID Considerations

API Specification 5CT, 11th Edition does not define a standard drift diameter for production tubing. The drift is specified by the purchaser on the PO to ensure that the minimum bore passes all planned downhole tools. Common practice is to specify a drift diameter at nominal ID minus 3.2 mm (⅛ inch), which clears most standard production logging and perforating tools.

For wells that will require coiled tubing intervention, the coiled tubing OD must be sized against the minimum tubing ID, accounting for any expected scale or paraffin buildup that reduces the effective bore over time. Wells planned for pump-and-flow operations must also confirm that the pump tubing string clearances are compatible with the tubing ID.

Specifying a drift diameter on the purchase order is not optional — it is the mechanism by which the buyer controls the minimum bore and verifies mill compliance before acceptance.

When NOT to Finalize Tubing Size Without Running All Four Checks

A tubing selection that satisfies three of these four design checks and fails the fourth creates a well with an unplanned workover built into its future. The most common failure is the drift check — it requires knowledge of the planned downhole tool program, which is often finalized after the tubing PO is placed. Reserve the drift specification on the PO as a hold item until the tool program is confirmed; do not default to the API minimum.

The table above is not a checklist to complete in sequence — all four checks are interdependent. Increasing wall thickness to satisfy burst also changes the collapse rating and reduces the flow area; changing connection type to satisfy tensile changes the coupling OD and may affect casing clearance. Size and weight selection is an iterative loop, not a linear process.

Purchase Order Guidance

Minimum required PO line items for production tubing:

• Grade and type designation: e.g., "L80 Type 1" not simply "L80"; "N80Q" not simply "N80"
• OD in inches, nominal weight in lb/ft, and connection type (NU or EU)
• Drift diameter in mm — hold this item open until the downhole tool program is confirmed
• Length range (R2, 8.5–10.0 m, is the standard for tubing)
• Heat treatment condition: Q+T for N80Q and all L80, C90, T95, P110
• Inspection level: PSL-1 or PSL-2
• MTC level: EN 10204 3.1 or 3.2

Wrong PO: "2-7/8 inch 6.40 lb/ft L80 EUE, API 5CT PSL-1, Range 2, 350 joints"

What the mill ships: L80-9Cr from stock (MTR reads "L80" without type designation). Drift diameter at API default (59.84mm). No PSL-2 inspection.

Correct PO: "2-7/8 inch 6.40 lb/ft L80 Type 1 per API Specification 5CT, 11th Edition, EUE (8-round, 8 TPI), PSL-2, Q+T heat treatment, per-pipe hardness ≤ 23.0 HRC recorded on MTC, drift diameter [specify mm — e.g. 57.50mm for coiled tubing compatibility], Range 2, EN 10204 3.2 MTC, 350 joints."

The difference between the wrong PO and the correct PO is approximately 40 words. Those 40 words determine whether the tubing that arrives is the tubing that was designed. The type designation, hardness limit, and drift specification are the three items most frequently missing from POs we review — and each omission creates a different compliance gap that the mill is not obligated to flag.

What to check on the MTR: Confirm the grade designation includes the type (L80 Type 1, not just L80). Confirm heat treatment is stated and matches the type requirement. Confirm the hardness test results are at or below 23.0 HRC for L80 Type 1. Confirm the drift diameter on the MTC matches the specified value on the PO — not the API default.