API 5DP Drill Pipe: Grades, Tool Joints, Inspection Classes and How to Order

Quick Answer

API 5DP is the specification for steel drill pipe with upset pipe-body ends and weld-on tool joints; its second edition (2020) is the identical adoption of ISO 11961. Drill pipe is ordered by OD and nominal weight, which fix the wall and bore. The letter names the grade and the number is its minimum yield strength in ksi: E-75 (517 MPa), X-95 (655 MPa), G-105 (724 MPa) and S-135 (931 MPa), each with a maximum yield 30 ksi above the minimum. The current ISO 11961 also lists two enhanced H2S-resistance grades, D and F. Pipe ends are upset internally (IU), externally (EU) or both (IEU). The tool joints have a minimum yield of 120 ksi (827 MPa), are friction-welded to the upsets and carry rotary shouldered connections such as NC50, threaded and gauged to API Spec 7-2. API guidance generally calls for a torsional ratio (tool joint to tube) of at least 0.8. Tube ratings come from API RP 7G: new 5 in 19.50 lb/ft S-135 has a tensile yield of 712,100 lb and a torsional yield of 74,100 ft-lb. Used pipe is classified under API RP 7G-2: Premium keeps at least 80% of the wall, Class 2 at least 70%.

A typical drill pipe enquiry reads: "5 inch drill pipe, S-135, 3,000 metres, best price." It names a size and a grade but not the nominal weight, and 5 in pipe comes in more than one weight. It says nothing about the tool joint, the upset, the range length, hardbanding or the product specification level, or whether used pipe is acceptable and in which inspection class.

Each gap becomes a question or an assumption, and a wrong guess about the tool joint leaves a string that does not match the rig's handling and fishing tools. This guide covers what a complete specification contains and how the ratings are calculated.

The Drill String: Drill Pipe, Heavy-Weight Drill Pipe and Drill Collars

The drill string carries torque and drilling fluid from the rig to the bit and supplies the weight that drives the bit into the rock. Three tubular components share the work:

Drill pipe is designed to work in tension. The collars and HWDP form the bottom-hole assembly (BHA), which is made heavy enough that the neutral point, where compression changes to tension, stays inside it. In a vertical well, drill pipe run in compression buckles, and the bending speeds up fatigue at the tool joints.

What API 5DP and ISO 11961 Cover

API 5DP sets the technical delivery conditions for drill pipe: a seamless pipe body with upset ends and weld-on tool joints. Its second edition (2020) is an identical adoption of ISO 11961.

• Product specification levels: PSL-1 is the base. PSL-2 and PSL-3 (Annex G) add requirements, such as higher Charpy impact energy at PSL-3, and apply only when the order calls them up.
• Grades: E, and the high-strength grades X, G and S. The current ISO 11961 also lists enhanced H2S-resistance grades D and F; check whether the API 5DP edition and addenda named on the order include them.

Three subjects sit elsewhere. Threading and gauging of the connection are in API Spec 7-2 (or ISO 10424-2). Tensile and torsional ratings are in API RP 7G; ISO 11961 states that it does not consider performance properties. Classification of used pipe is in API RP 7G-2.

For how the seamless tube is made, see seamless vs welded steel pipe. Casing and tubing, which line the finished well, are covered in our guide to API 5CT casing and tubing.

Grades: E-75, X-95, G-105 and S-135

The number in a grade is its minimum yield strength in ksi. Each grade also has a maximum yield, 30 ksi above the minimum, and a minimum tensile strength:

For grades E, X, G and S, tool joints have one material requirement: yield 120–165 ksi (827–1,138 MPa) and a minimum tensile strength of 140 ksi (965 MPa). Values are as listed in API 5DP; check the edition named on the order.

Drill pipe in sour wells

Harder, stronger steel is more susceptible to sulfide stress cracking (SSC) in hydrogen sulfide, one reason every grade has a maximum yield. In H2S-bearing wells, drill pipe is protected mainly by drilling fluid chemistry and by limiting steel strength. S-135 is the most susceptible grade; the D and F grades of ISO 11961 and mills' proprietary sour-service pipe address the risk. For H2S materials rules in general, see our guide to NACE MR0175 / ISO 15156.

Sizes, Weights and Upsets

Like casing, drill pipe is specified by OD and nominal weight, which fix the wall thickness and ID. The nominal weight, such as 19.50 lb/ft for 5 in pipe with a 0.362 in wall, is a designation; the tube alone weighs about 17.9 lb/ft (26.7 kg/m). For hook load, use the adjusted weight, which includes upsets and tool joints: one data sheet gives 22.9 lb/ft (34.1 kg/m) for 5 in 19.50 lb/ft S-135 with a 6-5/8 in tool joint.

Ratings are calculated with the API RP 7G formulas in the worked example below.

Upsets: IU, EU and IEU

The tube is thickened at each end before the tool joint is welded on, so that the weld zone is stronger than the tube body. An IU (internal upset) reduces the bore and leaves the OD unchanged; an EU (external upset) increases the OD and leaves the bore unchanged; an IEU does both and is common on 5 in and larger pipe.

Stress concentrates where the internal upset tapers back into the tube, and in pipe that rotates while bent this run-out is a common origin of fatigue cracks. A long, gradual taper lowers the concentration. API 5DP sets upset dimensions and tolerances, and PSL-2 and PSL-3 add a minimum internal-upset taper length.

Tool Joints and Rotary Shouldered Connections

Each joint has a pin (male) tool joint at one end and a box (female) at the other. Tool joints are heat-treated alloy steel forgings, attached to the upsets by rotary friction welding; the weld zone is then austenitised, cooled and tempered.

NC, REG and FH connections

The connection is a rotary shouldered connection: a coarse, tapered thread carries the load, and flat shoulders on pin and box make the seal and hold the make-up preload. API Spec 7-2 covers thread dimensions, gauges and gauging for the numbered (NC), regular (REG) and full-hole (FH) styles, new or recut; recut connections need further inspection under API RP 7G-2.

In an NC designation, the two-digit number is the pitch diameter of the pin thread at the gauge point: about 5.0 in for NC50. Five NC sizes share their thread with older IF (internal flush) sizes and one with 4 in FH, so those pairs interchange. Confirm any pairing in API Spec 7-2 before mixing pipe.

Make-up torque and torsional ratio

Make-up torque, given on the connection data sheet, preloads the shoulders so they stay in contact under bending and tension. Drilling torque is kept below it: above it, the connection tightens further downhole and can damage shoulders and threads.

The torsional ratio is the tool joint's torsional yield divided by the tube's. Below 1.0 the connection limits the torque the string can carry, and API guidance generally calls for 0.8 or more. As the tube wears, its torsional strength falls, so the ratio rises.

A larger tool joint bore improves hydraulics but costs torsional strength; a larger OD adds strength but reduces annular and fishing clearance. Proprietary double-shoulder connections raise torsional capacity for deep and extended-reach wells. The box's tapered or square elevator shoulder must suit the rig's elevators.

Hardbanding and Internal Coating

Hardbanding is a wear-resistant weld overlay on the tool joint OD, usually on the box, that takes the abrasion against the borehole and casing. Hard, carbide-bearing overlays protect the joint but can wear the casing; casing-friendly alloys protect the casing at some cost in joint life.

Internal plastic coating reduces corrosion pitting inside the tube. Pits start many fatigue cracks, so the coating helps fatigue life as well.

Range Lengths

API 5DP measures drill pipe shoulder to shoulder, with the tool joints welded on. The 2009 first edition gives Range 1 as 6.10–7.01 m (20–23 ft), Range 2 as 8.84–9.75 m (29–32 ft) and Range 3 as 12.19–13.72 m (40–45 ft). Range 2 is the most common. Range 3 means fewer connections but needs pipe-handling equipment and a derrick to suit. Older documents quote different limits, so state the range and the edition on the order.

Ratings: Tension and Torsion

API RP 7G calculates tube ratings from the minimum yield strength Ym (psi), the OD D and the ID d (in):

• Tensile yield: P = Ym × A, where A = π/4 × (D² − d²)
• Torsional yield (ft-lb): Q = 0.096167 × J × Ym / D, where J = π/32 × (D⁴ − d⁴)

The constant 0.096167 is 2 × 0.577 ÷ 12: shear yield taken as 0.577 × Ym, the relation between torque and shear stress, and the change from inch-pounds to foot-pounds.

Worked example: 5 in 19.50 lb/ft S-135

Data: D = 5.000 in, t = 0.362 in, d = 4.276 in, Ym = 135,000 psi.

New pipe

• A = π/4 × (5.000² − 4.276²) = 5.2746 in² (34.0 cm²)
• Tensile yield = 135,000 × 5.2746 = 712,070 lb → 712,100 lb (3,167 kN)
• J = π/32 × (5.000⁴ − 4.276⁴) = 28.54 in⁴
• Torsional yield = 0.096167 × 28.54 × 135,000 / 5.000 = 74,100 ft-lb (100.5 kN·m)

Both agree with published data sheets for this pipe.

Premium class, rated with 80% of the wall remaining, worn evenly from the outside, bore unchanged:

• Wall = 0.8 × 0.362 = 0.290 in (7.36 mm); OD = 4.276 + 2 × 0.2896 = 4.855 in
• A = 4.154 in² → tensile yield 560,800 lb (2,494 kN)
• J = 21.73 in⁴ → torsional yield 58,110 ft-lb (78.8 kN·m)

Losing a fifth of the wall costs 21% of the tensile and 22% of the torsional capacity.

Tool joint check. For a torsional ratio of 0.8 on new pipe, the tool joint needs a torsional yield of at least 0.8 × 74,100 = 59,280 ft-lb (80.4 kN·m). Check it on the connection data sheet before accepting a tool joint OD and bore.

Hook load check. Take 3,000 m (9,843 ft) of this pipe at an adjusted weight of 34.1 kg/m (22.9 lb/ft), with a 25 t BHA, in 1.20 SG mud:

• Weight in air: 3,000 × 34.1 = 102.3 t of pipe + 25 t of BHA = 127.3 t
• Buoyancy factor: 1 − 1.20 / 7.85 = 0.847, where 7.85 is the density of steel
• Static hook load off bottom: 127.3 × 0.847 = 107.8 t, or 1,058 kN (237,700 lb)

The top joint carries the full hook load. As Premium pipe, its tensile yield is 2.36 times that load (the load is 42% of yield); as new pipe, 3.0 times. These are yield ratings: operators reduce them by a design factor, keep a margin of overpull for stuck pipe, and check combined tension and torque, because tension reduces the torque a tube can carry.

Ratings by grade and class

The same formulas give these tube ratings for 5 in 19.50 lb/ft pipe:

Inspection class matters as much as grade. Premium S-135 still beats new G-105 in tension (560,800 against 553,800 lb), but Premium G-105 falls below new X-95 (436,100 against 501,100 lb).

Used Drill Pipe: Inspection Classes

Much of the drill pipe in service is used. API RP 7G-2, the recommended practice for inspection and classification of used drill stem elements, classes the tube by its remaining body wall:

Inspection typically covers the tube (visual, full-length OD gauging, ultrasonic wall measurement, full-length electromagnetic inspection) and the connections (visual, thread profile, box swell, box OD, pin ID, shoulder width, tong space). A worn tool joint can limit a string whose tube is still Premium. Where a contract names a stricter proprietary standard, the inspection follows it.

How to Order: Checklist

• OD and nominal weight, for example 5 in 19.50 lb/ft
• Grade (E-75, X-95, G-105, S-135 or an H2S-resistant grade) and PSL
• Upset: IU, EU or IEU
• Tool joint: connection (for example NC50), OD and ID, tong space, elevator shoulder
• Range length
• Hardbanding (type, location, raised or flush) and internal coating
• New or used: for used pipe, the class, the inspection standard and the report
• Quantity in joints or metres
• Service: depth, torque, tension, whether H2S is expected
• Inspection, documents and delivery: third-party inspection, NDE, certificate type (EN 10204 3.1 or 3.2), thread protectors, destination, Incoterm and date

Common Mistakes

1. Ordering by size and grade only. "5 in S-135" leaves out the weight and tool joint, which fix ratings and compatibility.

   Prevention: State OD, nominal weight, upset, connection and tool joint OD and ID.

2. Designing used pipe on new-pipe ratings. Premium pipe has about a fifth less tensile and torsional capacity.

   Prevention: Use the ratings for the class supplied, based on the weakest joints.

3. Ignoring the torsional ratio. A high-strength tube with an undersized tool joint fails at the connection first.

   Prevention: Compare tool joint and tube torsional yield; aim for at least 0.8.

4. Drilling above make-up torque. Connections tighten downhole and shoulders and threads are damaged.

   Prevention: Keep drilling torque below make-up torque, and make up to the data sheet value.

5. Mixing connections or tool joint sizes. Non-matching threads gall; mixed ODs and bores complicate handling, fishing and hydraulics.

   Prevention: One connection and tool joint size per string; check interchangeability in API Spec 7-2.

6. Putting weight on the bit with drill pipe in a vertical well. In compression it buckles and fatigues at the tool joints.

   Prevention: In vertical and near-vertical wells, size the BHA so the neutral point stays in the collars or HWDP; in high-angle wells, check drill pipe compression against its critical buckling load.

7. Choosing the hardest hardbanding by default. In long or deviated wells, casing wear can become the limit.

   Prevention: Match the overlay to the casing programme; use casing-friendly types where casing wear governs.

8. Running high-strength pipe in H2S without controls. S-135 is the grade most susceptible to sulfide stress cracking.

   Prevention: Control drilling fluid chemistry and consider lower-strength or H2S-resistant grades.

Supply from Kasko Makine

API drill pipe

• Use: rotary drilling for oil and natural gas, in shallow and deep wells; supplied in standard sizes and grades
• Standards: designed to meet the dimensional and mechanical property requirements of API standards
• Size: defined by pipe body OD and nominal weight per unit length, which set the wall thickness and inside diameter
• Lengths: pipe bodies and tool joints to API range designations
• Grades (yield min / yield max / tensile min): E75 75,000 / 105,000 / 100,000 psi; X95 95,000 / 125,000 / 105,000 psi; G105 105,000 / 135,000 / 115,000 psi; S135 135,000 / 165,000 / 145,000 psi

API steel casing pipe: for oil and gas wells, foundations and piling; the grades listed include API 5CT H40, J55, K55 and N80 (PSL 1 to PSL 3) and API 5L PSL 1 and PSL 2 grades.

Engineering support: Send the string design or the drill pipe list (size, weight, grade, tool joint connection and dimensions, range, hardbanding and quantity) with the well depth, expected torque and whether H2S is expected. We reply with pricing, lead time and engineering details.

Send the drill pipe size, weight, grade, tool joint, range length and quantity for a quotation — we reply within 24 hours. Reach us at info@kaskomakine.com or WhatsApp +90 (537) 521 1399.

Continue Reading

• API 5CT Casing and Tubing: Grades, Sizes and Connections
• NACE MR0175 / ISO 15156: Sour Service Materials
• API 5L Line Pipe: Grades, PSL1 and PSL2
• Material Test Certificates: EN 10204 3.1 vs 3.2
• Oil and Gas Pipes, Valves and Fittings Supply
• Industrial Equipment Supply in Kazakhstan

Frequently Asked Questions

Q: What is API 5DP drill pipe?
A: API 5DP is the specification for steel drill pipe with upset pipe-body ends and weld-on tool joints. Its second edition, published in 2020, is the identical adoption of ISO 11961. It covers grades E, X, G and S at three product specification levels. Thread gauging, performance ratings and used-pipe inspection are covered by API Spec 7-2, API RP 7G and API RP 7G-2.

Q: What do the drill pipe grades E-75, X-95, G-105 and S-135 mean?
A: The number is the minimum yield strength in thousands of psi: 75,000 psi (517 MPa) for E-75, 95,000 psi for X-95, 105,000 psi for G-105 and 135,000 psi (931 MPa) for S-135. Each grade also has a maximum yield strength 30,000 psi above its minimum and a minimum tensile strength. X-95, G-105 and S-135 are the high-strength grades and must be quenched and tempered.

Q: What is the difference between drill pipe, heavy-weight drill pipe and drill collars?
A: Drill pipe makes up most of the string, transmits torque, carries the drilling fluid and is designed to work in tension. Drill collars are heavy, thick-walled bars at the bottom that supply weight on bit and stiffness. Heavy-weight drill pipe, with a much thicker wall and longer tool joints, sits between them as a transition and adds weight in deviated wells.

Q: What does NC50 mean on a drill pipe tool joint?
A: NC50 is a numbered rotary shouldered connection, threaded and gauged to API Spec 7-2. The two-digit number gives the pitch diameter of the pin thread at the gauge point, about 5.0 inches for NC50. The connection seals at its shoulders, which the make-up torque preloads. Five NC sizes share their thread with older IF sizes and one with 4 inch FH, so those pairs interchange.

Q: What are the range lengths for drill pipe?
A: API 5DP measures drill pipe shoulder to shoulder, with the tool joints welded on. In the 2009 first edition, Range 1 is 6.10 to 7.01 m (20 to 23 ft), Range 2 is 8.84 to 9.75 m (29 to 32 ft) and Range 3 is 12.19 to 13.72 m (40 to 45 ft). Range 2 is the most common. Older documents quote different limits, so state the range on the order.

Q: What is premium class drill pipe?
A: Premium class is used drill pipe with at least 80 percent of its specified wall remaining, classified under API RP 7G-2 and marked with two white bands. Class 2 keeps at least 70 percent and carries a yellow band. Premium ratings assume even wear from the outside, so a 5 inch 19.50 lb/ft S-135 tube drops from 712,100 lb to about 560,800 lb tensile yield.

Q: How are drill pipe tensile and torsional strength calculated?
A: API RP 7G gives tensile yield as minimum yield strength times the cross-sectional area of the tube. Torsional yield in foot-pounds is 0.096167 times the polar moment of inertia times minimum yield, divided by the OD in inches. For new 5 inch 19.50 lb/ft S-135 pipe this gives 712,100 lb and 74,100 ft-lb. These are yield ratings, so operators apply design factors on top.