Rotating pipe protectors enhance drilling uptime

Michel Dib
Lin Zhu

One common but challenging problem in floating drilling is key-seating wear in the lower section of the drilling riser and casing. This is expensive to repair and may result in the loss of the entire mud column and precipitate a blowout.

To mitigate the risk, the 2007 ISO 13624/API RP 16Q limits the lower flexible joint (LFJ) differential mean angle to 1º for rotating drill pipe, which is half the 2º limit of the previous 1993 API 16Q. But, even for modern rigs, the 1º can be a restrictive angle limit when drilling in harsh environments, particularly in one-year storms, because it imposes a narrow and impractical admissible offset range on the rig. As a result, the uptime has to be reduced to less than one year to achieve a comfortable rig offset range. Furthermore, considering the uncertainty in wellhead verticality, it may result in a feasibility problem.

Rotating drill pipe protectors (RDPP) made of special plastic materials can provide an economical solution to the problems of wear and highly constrained offsets, as they minimize steel-to-steel contact, thereby reducing wear along the riser-BOP-wellhead casing system, and enhancing both uptime and safety. Specifically, the protectors may enable drilling at 2º lower flexible/ball joint mean angle, which doubles the rig offset range for rotating drill pipe. To support this conclusion, the following present results of riser pipe-in-pipe analysis, lab wear testing of drill pipe on grade 80 steel, field experience, and cost impact.

Rig specifications

Because of high day rates on floating drilling rigs, the contract on a rig often specifies drilling uptime for rotating drill pipe, which for a modern rig is usually a one-year storm or one-year current environment. However, this uptime is often difficult to achieve, because stringent code limits on riser angles and emergency disconnect impose admissible rig offset ranges that are too narrow for DP rigs to maintain in the agreed uptime environment.

Progression of tool joint and RDPP inside lower riser and casing.

The 2007 ISO 13624/API RP 16Q industry standard places a limit of 1º on the LFJ differential mean angle for drilling with a conventional subsea BOP stack and top drive system. Riser analyses for feasibility and uptime in one-year conditions showed that this angle limits the admissible rig offsets to a narrow range around the well center in water depths of less than approximately 5,000 ft (1,525 m), a conclusion based on many studies.

The 1º angle limit is recommended to prevent excessive wear in the lower section of the drilling riser, wellhead, and casing, which is expensive to repair, and may result in the loss of the entire mud column and precipitate a well control situation. ISO/API also places a limit on the upper flexible/ball joint mean angle of 1–1.5º, which may severely restrict the rig offset range for drilling in strong currents, when considered with the yellow alert.

One potential solution is to use a mud motor downhole, without assistance from a top drive. Feedback from experienced drillers is mixed about motor reliability, cost, and torque capacity. Motors are good for some applications such as directional drilling, but for most applications rotary drilling is more cost effective.

Another solution

Plastic rotating drill pipe protectors (RDPP) provide another solution to the problems of wear and highly constrained offsets. They prevent steel-to-steel contact, thereby reducing wearing along the riser-BOP-wellhead casing system, and enhancing both uptime and safety.

Traditionally, these protectors are used to protect downhole casings in deviated wells where the tension is low and the change in well slope is gradual. More recently, they have also been used to successfully drill six sidetracks through 9.5-in. drift ID production risers from a production TLP where the tapered stress joints provide a smooth change in curvature in the lower riser.

In addition to their history of success in reducing wear, the rotating protectors offer the following benefits:

  • A simple, commodity, and consumable product widely available from at least five suppliers, and costing less than $60 per piece. This is approximately the rental day rate for the non-rotating protector, which is available from few suppliers.
  • Short fabrication lead time measured in weeks: Eight weeks for 830 pieces.
  • Available for different drill pipe sizes, including the larger 6 5/8-in OD drill pipe, and the design is customizable: solid versus fluted, extra standoffs, and adjustable durometer hardness.
  • The annulus bypass area for most protectors exceeds the tool joint ID area; hence the effect on mud flow rate is minimal.
  • They are pre-installed using a simple procedure.
  • As per the lab testing described below, the plastic materials of three brands can achieve better than 10 times reduction in friction (friction factor=0.02) and torque demand, by comparison to steel on steel (friction factor=0.2), and lesser friction than the non-rotating protector (friction factor=0.03-0.10). Torque reduction is essential for extended reach drilling.
  • They can tolerate more than twice the allowable side load of the non-rotating protector (2,000 lbs), as per the testing described below.
  • One protector brand performed well for drilling geothermal wells, demonstrating resistance to thermal degradation in brine, but the protector degraded in tests at 400°F (205ºC). Therefore, the protectors have potential for drilling high-pressure/high-temperature oil and gas wells. Testing is needed to identify the P-T envelope for the specific drilling fluid.

For MODU drilling with a conventional 21-in. drilling riser, subsea BOP, and top drive, a case study was analyzed to evaluate the benefit of using rotating plastic protectors to limit wear in the lower riser section, where the drill pipe tension is much higher than downhole, and the jump in the (LFJ) angle generates concentrated side loads from the drill pipe bearing against the riser bore. The increase in the LFJ allowable drilling angle to 2º using the RDPP is justified by relating the wear rate from lab test data to the side loads computed from the pipe-in-pipe model.

The lab testing (courtesy of Weatherford) considered seven cases: 108 ksi tool joint steel; tungsten carbide hard band on the tool joint; and five different protectors from three suppliers. The samples were pushed against N80 casing ID by a 3,000 lb/ft force, and the casing was reciprocated slowly during the test to simulate an advancing drill string. The fluid was water based mud with 7% sand. RPM was not documented. The protector plastic material acts as a sacrificial layer at the contact surface, and the wear volume and reduction in thickness of the steel pipe were measured automatically by a computer-based data acquisition system over a period of eight hours for each test. The following are the findings of the tests:

  • The reduction in wall thickness of the N80 was 0.084 in. for bare tool joint, and 0.131 in. for tungsten carbide hard band.
  • The maximum reduction in wall thickness for the five protectors was 0.008 in. over eight hours, corresponding to a rate of 0.001 in./hr.
  • In a separate test of a slick protector, it was observed that if the drill pipe was not advancing, the wearing is more severe at 0.033 in./hr under 3,500 lb side load. This exceptional case does not reflect field conditions, but can be considered by noting the drill pipe tension and LFJ angle.
  • The protector preferred durometer-A hardness is in the range of 50 to 70, to control steel wear.
  • Separate testing of one protector brand at Sandia National Laboratories demonstrated that a load of 4,500-5,500 lbs can be sustained for 8-12 hours without evidence of failure. This range can be used as a safe mean load for one protector, and it is better than twice the load capacity of the non-rotating design (2,000 lb).Strength test results were not available for other brands.

The pipe-in-pipe computer model considered the following wellhead details:

  • Drill pipe: OD 5-in., 25.6 lb/ft, S-135, 30-ft long joint.
  • Tool joint: OD 6 5/8-in., L 22 in.
  • Drill pipe protector: OD 7 1/2-in., L 10 in., with 1-ft clearance from the tool joint, one protector per drill pipe joint. Six drill pipe joints are included in the model.
  • BOP and riser bores: 18 3/4 in. and 19 in. respectively, with the LFJ center of rotation at 50 ft above the mud line.
  • Casing: 9 5/8-in., 53.5 lb/ft, ID= 8.56 in., top of wear bushing at 6 ft above the mud line.

This is a conservative configuration for computing contact loads, as the 9 5/8 in. casing is installed and the drillers are drilling the hole of the 7 in. casing. The drill pipe tension is maximum at 550 kips at the BOP, corresponding to a reservoir depth of approximately 25,000 ft below the mud line. The model is truncated at 75 ft above the LFJ and 40 ft below the mud line for simplicity, and to conservatively estimate the contact loads.

RDPP contacting LFJ and maintaining standoff for tool joint.

The analysis for each LFJ angle of 1º and 2º included six elevations of the tool joint/protector to capture the maximum contact load, with one position of tool joint at the LFJ center of rotation.

Relating the analytical model results for contact load and the lab results for wear indicates that:

  • The three protector brands tested can decrease the wear rate by better than a factor of 10, relative to steel on steel.
  • At 1º LFJ angle, there is no steel-to-steel contact, only protector on steel. The maximum contact load is 3,500 lb at the wear bushing of the 9 5/8 in. casing. The other contact locations are in the riser 21 in. pipe, and in the 9 5/8 in. casing below the wear bushing. For advancing drill string, the time to wear 1/16 in. of steel wall thickness is 72 days of rotating with one protector; seven days for steel on steel without protector; and four and one-third days for tungsten carbide without protectors. Given the high wear rate without the protectors, the ISO/API 1º limit and requirement for inspection are understandable.
  • At 2º LFJ angle, steel-to-steel contact is detected at the LFJ wear ring and at the wear bushing of the 9 5/8 in. casing, but the contact loads are small and wearing 1/16 in. of the steel wall is not critical at these locations. The computed maximum load is 10,100 lbs on the ID of the 21 in. riser joint, indicating criticality in the lower riser joint, and suggesting doubling the protectors to maintain the 5,000 lb acceptable load per protector; or alternatively refining the analytical model to perhaps justify a lower contact load. This finding correlates with field experience where drillers reported severe wear in the lower riser joints, and consequent loss of the mud column. The minimum time to wear 1/16 in. of the riser wall is 16 days, by doubling the protectors. This is an acceptable result considering the short effective duration of one-year storms which in many locations does not exceed two days.
  • The rotating protector is suitable for drilling deep wells, extended reach side tracks, and it looks promising for HP/HT wells after its success in geothermal wells. However, more testing is needed to identify the pressure-temperature envelope. For relief wells, the RDPP can expedite drilling.
  • Suppliers should document the strength testing of their RDPP which is a design factor, and implement quality control procedures because protectors lost down hole may damage PDC bits.

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