Tripping pipe moves the drill string repeatedly between the wellbore, rig floor, and setback area, exposing every drill pipe joint to lifting, gripping, connection breakout, racking, stabbing, and make-up. During tripping out, the string is pulled from the hole and stands are progressively disconnected and racked; when running back in, those stands return to the well center, are made up again, and are lowered into the well. OSHA describes the same operating sequence through slips, elevators, breakout, pipe racking, and repeated make-up as the string returns downhole.
For the drill pipe itself, a trip involves much more than vertical movement. The pipe body is repeatedly supported and released, the tool joint is gripped during breakout and make-up, and the pin, box and shoulder pass through another connection cycle before returning downhole. Drill pipe handling therefore depends not only on the rig procedure, but also on pipe size, joint weight, tool-joint geometry and connection condition throughout the trip.
What Does Tripping Pipe Mean in Drilling?
A trip removes part or all of the drill string from the hole and, when required, returns it downhole. A complete pull-out followed by running the string back in is commonly called a round trip.
The string may be pulled for a bit change, BHA work, inspection, logging, or another operation that requires access to the drill string or bottom-hole assembly.
During tripping out, each stand reaches the rig floor in sequence. The suspended string is supported, the connection is broken, and the stand is moved into the racking area. When tripping in, the process reverses: the stand returns to well center, the connection is stabbed and made up, and the string is lowered farther into the hole.
This repeated cycle matters because different parts of the drill pipe are loaded and contacted in different ways. The pipe body may be held by slips, the tool joint may be gripped during breakout, and the pin, box, and shoulder pass through another connection cycle before the string returns downhole.
What Happens to Drill Pipe During Tripping Out and Tripping In?
The rig design may vary, but the drill pipe passes through a similar sequence of lifting, supporting, breakout, racking and make-up during most pipe tripping operations.
| Tripping Stage | Main Action | Drill Pipe Area Involved |
|---|---|---|
| Raise the string | Elevators lift the drill string or stand | Tool joint / elevator contact area |
| Set the string | Slips support the suspended string | Pipe body / slip contact area |
| Break the connection | Tongs or powered equipment apply breakout torque | Tool joint OD, pin and box |
| Move and rack the stand | The disconnected stand is transferred to the setback or fingerboard | Pipe body, tool joints and pipe ends |
| Return the stand | The stand is moved back to the well center | Pipe body and connection ends |
| Stab and make up | The pin is aligned with the box and the connection is tightened | Threads, shoulder faces and tool joint |
| Run in hole | The connected drill string is lowered into the well | Complete drill string |
OSHA’s tripping guidance identifies elevators, slips and tongs as key equipment used to lift, support and connect the drill string during a trip. Because each tool transfers load through a different part of the drill pipe, the resulting contact marks and damage patterns also appear in different locations.
During pipe tripping operations, tong marks are more likely to appear on the tool joint, slip marks develop on the pipe-body contact area, while the pin, box and shoulder surfaces are repeatedly exposed during breakout and make-up. These indications should therefore be evaluated according to where they occur and how the load was applied, rather than being treated as the same type of handling damage.
Why Drill Pipe Size and Weight Matter During Tripping
Nominal drill pipe size does not fully describe what the rig is actually handling. Wall thickness, pipe weight and internal diameter can change while the nominal outside diameter remains the same, and the tool joint introduces another set of dimensions.
Published TMK drill pipe data provide a useful example for 5 in. drill pipe. Their dimensional table lists both 19.50 lb/ft and 25.60 lb/ft configurations at the same 5.000 in. nominal OD.
| 5 in. Drill Pipe Data | 19.50 lb/ft Configuration | 25.60 lb/ft Configuration |
|---|---|---|
| Nominal OD | 5.000 in. / 127.0 mm | 5.000 in. / 127.0 mm |
| Nominal weight | 19.50 lb/ft / 29.05 kg/m | 25.60 lb/ft / 38.13 kg/m |
| Wall thickness | 0.362 in. / 9.19 mm | 0.500 in. / 12.70 mm |
| Pipe-body ID | 4.276 in. / 108.62 mm | 4.000 in. / 101.60 mm |
| Upset | IEU | IEU |
The published dimensions show why two joints described simply as “5-inch drill pipe” should not automatically be treated as identical. The 25.60 lb/ft configuration has a wall approximately 38% thicker than the 19.50 lb/ft configuration—0.500 in. compared with 0.362 in.—while its pipe-body ID is correspondingly smaller. The upset configuration is another part of the finished joint that should be confirmed together with body size and tool-joint dimensions. IEU, EU and IU drill pipe upset types change the pipe-end geometry before the tool joint is welded.
The difference is relevant to tripping for more than one reason. Increased nominal pipe weight changes the steel weight being moved, while different body and tool-joint geometry can affect the interfaces used by slips, elevators, and tongs.
The same TMK product range lists E75, X95, G105, and S135 drill pipe grades and 4½–5½ in. drill pipe with wall thicknesses extending up to 0.500 in.
Grade, however, should not be confused with handling geometry. E75, X95, G105, and S135 describe different strength classes; those grade names do not tell the rig crew the tool-joint OD, tong area, elevator profile, or the exact finished dimensions of the connection.
That is why pipe selection should consider the complete API 5DP drill pipe sizes, grades and connections rather than using nominal OD or grade alone.
Where Handling Equipment Contacts the Drill Pipe
During drill pipe handling, different tools act on different parts of the pipe. That sounds obvious, but it matters when a joint comes back from a trip with new marks or surface damage.
Elevators carry the stand as it moves through the rig floor, while slips hold the suspended string when a connection is being worked. Tongs act farther out on the tool joint, where they provide the grip needed for breakout and make-up. Once the connection is broken, the stand is moved into the setback area, introducing another round of contact with racking and transfer equipment.
The result is that handling marks tend to have a location as well as a cause. Slip marks normally appear on the pipe-body gripping area, while tong marks are associated with the tool joint. Damage around the pin, box or shoulder is more closely related to connection handling, stabbing and repeated make-up or breakout.
This is also why nominal drill pipe size is not enough when checking handling compatibility. The rig actually handles the finished joint, including the pipe body, upset and tool joint. Tool-joint OD, available tong area and the profile used by the elevator can all matter even when two pipes share the same nominal body OD.
Mechanical Loads and Wellbore Effects During Tripping
A drill string behaves differently on the way out of the hole than it does simply hanging still.
While tripping out, the hoisting system has to lift the suspended string and overcome resistance where the pipe contacts the wellbore. In a relatively straight hole this may be modest. In a directional or long horizontal section, drag can become much more noticeable, so the hook load seen while pulling upward may differ considerably from the apparent string weight.
Curved sections of the well add another effect. Drill pipe passing through a dogleg bends as it moves, while still carrying the weight of the string below. The pipe is therefore seeing more than simple tension, particularly in wells with significant inclination or repeated changes in trajectory.
Pipe movement also affects the fluid around it. Pulling the string can reduce bottom-hole pressure through swab effects, while running it back down can increase pressure through surge. How large those changes become depends on the actual well—not just the drill pipe. Hole size, BHA geometry, clearance around the string, drilling-fluid properties and pipe movement all play a part.
For that reason, a drill pipe specification cannot provide one tripping speed that is suitable for every job. The pipe supplier can confirm dimensions, grade, connection and mechanical properties, but the operating limits for pipe tripping operations have to be determined from the actual well and rig conditions.
For the drill pipe itself, the useful question is simpler: whether the body and connection have enough capacity for the expected service and whether the finished joint matches the equipment that will lift, grip and make up the pipe.
Where Drill Pipe Damage Occurs During Tripping
Drill pipe damage during tripping usually appears at the same places where the pipe is repeatedly gripped, supported, broken out, made up, or moved around the rig floor. The type of damage often gives a clue to how it was produced.
Pin and box threads go through another connection cycle every time a stand is broken out and later made up again. Poor stabbing alignment can bring the threads into contact before the pin is properly centered, while dirt, drilling-fluid solids, metal particles or impact damage can interfere with smooth make-up. Galling, damaged thread crests or visible deformation deserve more attention than ordinary residual thread compound.
Shoulder faces are easier to overlook because most attention naturally goes to the threads. A dent, raised metal or trapped debris on the shoulder can prevent the connection from seating correctly even when the thread profile still appears acceptable.
The tool joint OD sees a different type of contact. Tongs and breakout equipment grip this area directly, so handling marks commonly appear here. Light impressions are not the same as deep die marks, localized crushing or damage close to the connection.
The pipe body and slip area experience concentrated support while the string is suspended. Repeated setting and releasing can leave characteristic marks in this zone. Deeper slip cuts, gouges, impact dents or local deformation deserve closer attention because the pipe will return downhole and carry drilling load again.
A visible mark alone does not determine whether a joint remains suitable for service. Its location, depth, shape and the inspection criteria being applied matter more than appearance alone.
Why the Finished Drill Pipe Joint Matters During a Trip
A drill pipe purchase description often starts with body OD, nominal weight and grade, but those values do not describe every interface used during a trip. The rig actually works with the complete joint: pipe body, upset, tool joint and connection.
A 5-inch body may therefore require different handling considerations when tool-joint OD, tong space or connection geometry changes. Grade works the same way. E75, X95, G105 and S135 describe pipe-body strength levels, but they do not identify the elevator profile or tong area of the finished joint.
This is why drill pipe selection should consider the complete API 5DP drill pipe sizes, grades and connections, rather than body OD or grade alone.
What Drill Pipe Conditions Matter Before Running Back In?
Running the string back downhole starts with the connection that is about to be made, not with a generic checklist applied equally to every surface mark.
Connection identity should be clear so that the correct pin and box are being paired. The threaded surfaces should be checked for obvious contamination, impact damage, or conditions that could prevent normal engagement.
Shoulder faces also need attention. Dirt or newly created mechanical damage at the shoulder can affect how a rotary-shouldered connection seats during make-up.
The tool-joint OD can show what happened during breakout and handling. Fresh heavy tong impressions, impact damage, or unusual deformation should not simply be ignored because the threads themselves look clean.
The slip-contact region of the pipe body provides another useful comparison point. New cuts or gouges that appeared during tripping out should be distinguished from pre-existing surface wear.
IADC’s tripping guidance similarly emphasizes the condition of tong jaws, tong dies, elevators, and slips before and during a trip, reflecting the direct relationship between equipment condition and the surfaces being handled.
These checks are not a substitute for formal drill stem inspection. A rig-floor observation can identify a condition that needs attention, but it should not create an arbitrary acceptance limit. Continued service depends on the applicable inspection program, drilling requirements, and qualified evaluation.
FAQ
Q: What does tripping pipe mean in drilling?
A: Tripping pipe means moving drill pipe or the drill string out of the well, back into the well, or completing both movements as a round trip. The operation repeatedly involves hoisting, slips, elevators, breakout, racking, stabbing, and connection make-up.
Q: What is the difference between tripping in and tripping out?
A: Tripping out pulls the drill string from the hole and progressively removes or racks stands. Tripping in returns those stands to the well center, makes up the connections, and lowers the string back downhole.
Q: Why does drill pipe handling depend on the finished-joint dimensions?
A: Nominal pipe OD does not define wall thickness, pipe-body ID, nominal weight, tool-joint geometry, or connection dimensions. Published 5 in. drill pipe, for example, includes 19.50 lb/ft and 25.60 lb/ft configurations with different wall thicknesses and internal diameters.
Q: Where does drill pipe damage during tripping usually need the most attention?
A: Pin and box threads, shoulder faces, tool-joint tong areas, and pipe-body slip-contact areas deserve particular attention because they repeatedly interact with connection and handling equipment during a trip. The significance of any indication depends on its location, severity, and applicable inspection criteria.
