Round Trip

A round trip is the complete operation of pulling the entire drill string out of the wellbore (trip out or pull out of hole, POOH) and running it back to bottom (trip in or run in hole, RIH), which is required whenever the bit must be changed, the bottom hole assembly must be modified, or the wellbore must be prepared for a different operation (casing, logging, or completion). A round trip on a deep well can take 12 to 24 hours of rig time, making trip optimization a major factor in well cost management. The time and cost of round trips are a significant driver of overall drilling efficiency metrics such as non-productive time (NPT) and cost per metre drilled.

Key Takeaways

Trip speed is measured in stands per hour, where a stand is the length of pipe pulled or run in one operation (typically two or three joints of drill pipe, totaling about 18 to 27 metres per stand). A modern top drive rig tripping drill pipe from 3,000 metres depth typically achieves 50 to 80 stands per hour, compared to 25 to 40 stands per hour for an older rotary-table rig. The difference can be 4 to 8 hours per round trip, worth tens of thousands of dollars in daily rig rates.
Tripping in is generally faster than tripping out because less care is required when running pipe in (gravity assists) than when pulling it out (stuck pipe risk means careful monitoring is needed during each stand). Tripping out requires the driller to watch for overpull (which might indicate the bit is balled up or the hole is tight) and to keep the hole full of mud (pumping mud in as pipe is pulled to prevent swabbing and formation fluid influx).
Short trips (tripping from bottom to a higher point in the well and back, without a full round trip to surface) are used to condition the wellbore, verify hole stability, and wash and ream problem intervals. A short trip partway up the wellbore and back is also called a flow check position: the drill string is pulled up so the bit is off bottom and any formation fluid influx can be detected before resuming full-bottom drilling.
Casing runs are round trips where drill pipe is pulled out entirely and casing is run in instead. After the casing is cemented, drill pipe must be run back in with a new bit to drill out the cement shoe and resume drilling. This adds a full round trip plus the casing running time to the well program.
Swabbing is the risk during tripping out: pulling pipe out of hole creates a suction effect below the bit that can reduce the effective mud column pressure enough to allow formation fluid influx. In overpressured formations, swabbing during a fast trip out can cause a kick. Tripping speed in swab-sensitive intervals must be limited, and the hole must be kept full of mud during the trip.

What Is a Round Trip and Why Does It Take So Long?

Imagine threading a 3,000-metre necklace through a 0.2-metre hole one bead at a time. That is roughly analogous to a round trip on a deep well. The drill pipe comes out of the hole in stands of 18 to 27 metres, each stand requiring the driller to set the slips (to hold the pipe while the top joint is unscrewed), spin off the connection (using spinning chain or power tongs), rack the stand back in the derrick, and then pick up the next stand. This cycle repeats for every stand in the string, which for a 3,000-metre well means approximately 100 to 160 stands per trip.

On the way back in, the process reverses: each stand is picked up from the rack, stabbed into the string, made up (torqued to the correct value), the slips are released, and the string is lowered until the next connection is at the rig floor. At the bottom, the bit is carefully tagged to bottom before resuming circulation and rotation, because hitting bottom at full speed with a new bit can damage the cutting elements.

On a deep well (4,000 to 5,000 metres), a round trip can take 20 to 30 hours. At CAD 25,000 to CAD 80,000 per day for a deep Foothills rig, each round trip costs CAD 20,000 to CAD 100,000 in rig time alone, plus the cost of the new bit and bottom hole assembly being run. Minimizing the number of round trips is one of the most important levers for reducing well cost. This drives the selection of long-life PDC bits (which drill further per bit run) and rotary steerable systems (which allow long lateral sections without tripping for BHA changes).

Fast Facts

The fastest commercial drill bit trip in offshore drilling history (as reported by NOV and Nabors Industries in their respective records) involved pulling and running 4,500 metres of 5-inch drill pipe in less than 6 hours using a top drive rig with an iron roughneck (an automated pipe-handling system). This represents a tripping speed of approximately 75 metres per minute. By contrast, early cable tool drilling (the predecessor to rotary drilling, used in the 19th and early 20th centuries) required manually hoisting each length of pipe with a powered cable and wooden bull wheel, and a trip into a 500-metre well took an entire work shift. The invention of the rotary table and drawworks with mechanical advantage, followed by top drives and automated pipe handling, has reduced trip time by an order of magnitude over the history of the industry.

Trip Planning and Wellbore Conditioning

Before a round trip, the wellbore must be conditioned to minimize the risk of getting stuck on the way out or in. Conditioning involves circulating bottoms-up (pumping at least one full wellbore volume of mud through the system to clean cuttings from the hole) and reaming any tight spots (rotating and working the drill string through intervals where the wellbore has narrowed due to swelling or sloughing). A trip without proper conditioning on a problem well risks the drill string getting stuck partway out of hole, which is an expensive situation requiring jarring, sidetrack, or fishing.

Mud weight is a key concern during conditioning. If the mud is too heavy for the trip, the increased hydrostatic pressure as the bit approaches certain depths may cause formation damage or lost circulation. If the mud is too light, swabbing effects during the trip out may cause a kick. The drilling engineer calculates the trip margin: the difference between the estimated swab pressure (the suction created by pulling pipe out at maximum planned speed) and the kick tolerance (how much underbalance the well can tolerate before formation fluid influx reaches the surface). If the trip margin is thin, tripping speed must be reduced and the hole must be filled with mud at shorter intervals during the trip out.

Reducing Round Trip Frequency

The industry has invested enormously in reducing the number of round trips required per well by extending the life and versatility of each bit run. Key innovations include:

PDC (polycrystalline diamond compact) bits, which replaced tricone roller cone bits as the dominant bit type for most formations, can drill 10 to 30 times the footage per bit run in appropriate formations. A Montney horizontal well that required 4 to 6 bit changes in the 1990s with tricone bits can often be drilled with a single PDC bit today.

Rotary steerable systems (RSS) replace the conventional motor-and-bend assembly that required a round trip to change the toolface orientation for directional corrections. An RSS steers continuously while rotating, allowing long lateral sections to be drilled without pulling out to adjust the tool. This can eliminate two to four round trips on a long horizontal well.

Measurement while drilling (MWD) and logging while drilling (LWD) tools provide formation evaluation data in real time without requiring a wireline logging round trip after drilling. Logging round trips on deep wells add 12 to 24 hours per log suite; LWD eliminates this cost at the expense of slightly reduced log quality in some measurement types.

A round trip is also called a pipe trip or simply a trip in daily drilling reports. The individual operations are POOH (pull out of hole) and RIH (run in hole). Related terms include trip out (the operation of pulling the drill string from the wellbore to surface; abbreviated POOH; requires careful control of swabbing pressure and mud level maintenance), trip in (the operation of running the drill string from surface back to bottom; abbreviated RIH; generally faster than trip out and requires careful control of surge pressure), swabbing (the reduction in effective mud column pressure caused by pulling pipe out of hole too quickly; can cause a kick in overpressured formations; limits tripping speed in critical sections), bit run (the distance drilled on a single bit from the time it is run in to the time it is pulled out; maximizing bit run length reduces the number of round trips required per well), and non-productive time (NPT, rig time during which the drill bit is not advancing; round trips are a major component of NPT, alongside stuck pipe, weather downtime, and equipment failure).

How a Drilling Engineer Saved 14 Round Trips on a Horizontal Cardium Well in Alberta

A drilling team was planning a horizontal Cardium well in the Pembina area of west-central Alberta. The planned well depth was 2,850 metres measured depth (MD) with a 1,400-metre horizontal lateral section. Based on offset well experience, the engineering team identified the historical causes of round trips in this area: three bit changes in the vertical section, two bit changes in the build section, four bit changes in the lateral, two wireline logging runs, and three workstring trips for casing running, which totalled 14 round trips per well on average.

The engineering team redesigned the well program around a new PDC bit with a more aggressive cutter layout that had been proven in the Cardium in the neighboring Willesden Green area. This bit had demonstrated 1,800 to 2,200 metres per run in the vertical and build sections, compared to 600 to 900 metres for the previous tricone bits used in this area. An LWD suite was specified instead of wireline logging, eliminating the two wireline round trips. The casing program was redesigned with a flush-joint casing grade that could be run on drill pipe rather than requiring a separate casing running string, eliminating one casing round trip.

The well was drilled with 5 round trips total: one bit change in the vertical, one bit change at the build-to-lateral transition, the casing run, one run for the completion string, and one wireline run for the cement bond log (which LWD could not replace). This was 9 fewer round trips than the field average. At 14 hours per round trip average and a rig rate of CAD 22,000 per day, the 9 saved round trips reduced well cost by approximately CAD 115,000 and reduced the total spud-to-rig-release time by 5.25 days.