Optimization Work Flow Converts Power to Performance for GOM Drilling

Time spent on bottom drilling is only approximately 10% of the time consumed by drilling operations, but this still provides a significant opportunity for savings if it can be reduced.


Time spent on bottom drilling is only approximately 10% of the time consumed by drilling operations, but this still provides a significant opportunity for savings if it can be reduced. The goal of the work described in this paper was to decrease this percentage while drilling an exploratory well in the Gulf of Mexico. Significant results were achieved with the use of advanced hybrid polycrystalline-diamond-compact/tungsten-carbide-insert (PDC/TCI) bits.


The focus well is in the Walker Ridge area approximately 150 nautical miles south of Port Fourchon, Louisiana. The rig floor to the zone of interest includes 6,500 ft of water, 1,200 ft of sediments, 12,250 ft of salt, and then deeper sediments. In the basic well design, a 38-in. conductor would be jetted to 200 ft below the mudline. The 26-in. section would be drilled through sediments and 2,000 ft of salt without risers using seawater and a 9.3‑lbm/gal water-based pump-and-dump (PAD) drilling fluid, after which the 22-in. casing would be set. The 16½-in. section would be drilled through the bulk of the remaining salt with a riser in place using synthetic-based drilling fluid. The well would remain vertical until the kickoff point. After setting a 14‑in. casing, the remaining hole sections would exit the salt and penetrate the deeper zones using synthetic-based drilling fluid.

Design Phase: Offset Well Study

The first step in the optimization process was to evaluate the drilling challenges that could be encountered in each hole section and identify potential performance limiters. The key lessons from the analysis of offset wells include the following:

  • The shale/sand sequence above the salt would be soft and could be drilled as quickly as desired, though subject to wellbore stability and hole-cleaning limitations.
  • The salt section would be very drillable, but mechanical specific energy (MSE) levels would be approximately 40 ksi.  
  • PDC bits would be very aggressive, so torque would be highly sensitive to weight on bit (WOB).  
  • Peak rate of penetration (ROP) in both salt and sediments would be directly proportional to the power provided to the bit.
  • Torque variation could be as low as 10 to 20% for stiff drillstrings featuring 6⅝-in. drillpipe using relatively high rotary speeds (e.g., 170 rev/min or greater).  
  • Bottomhole assembly (BHA) designs with a minimal tendency to hang up are desirable.

Design Phase: Candidate Well Optimization

The offset study suggested that the subsurface challenges for the 26-in. and 16½-in. hole sections for the focus well would be manageable and that the greatest performance limiter would likely be the availability of mechanical power from the topdrive on the drillship.  

26-in. Bit Selection. Virtually any bit could drill the sediments, but the salt portion of the hole section would present a greater challenge because of higher energy requirements in the large hole.  

The model indicated that ROP could be maximized by selecting bits with the highest possible efficiency. Relatively high bit aggressiveness also may be desirable, but bits with both high aggressiveness and low torque variation would be preferred. These considerations led to selection of an advanced hybrid PDC/TCI bit design.

The interaction between the shearing action of the PDC cutters and the crushing action of the TCI cutting structure provides a managed level of aggressiveness compared with PDC bits.  

Fig. 1—The 16½-in. hybrid bitwas designed with two conesand four blades for increasedaggressiveness.

26-in. BHA Design. The desire for minimal torque and drag and precise directional control through sediments and salt led to the selection of rotary-steerable-system (RSS) technology with continuous proportional steering.

While the RSS was expected to deliver a smooth, near-vertical hole, minor deviation in soft sediments would result in some off-bottom torque caused by friction. Because the entire drillstring would be rotated from the surface, the product of friction torque and string rotational speed represented an amount of power that would be unavailable to the bit for making hole. The greater this value, the more ROP would suffer. The best way to maximize the proportion of power consumed by the bit was first to increase WOB until the maximum acceptable torque was reached and then to increase string speed until the topdrive power was exhausted. This philosophy held true for all hole sections and was a governing principle for parameter selection while drilling.

16½-in. Bit Selection and BHA Design. The same decision criteria that led to selection of the advanced PDC/TCI hybrid for the 26-in. section ultimately led to selection of a similar design for the 16½‑in. hole section. Modifications included an enhanced bearing package to ensure reliability over the much longer interval and a more-aggressive cutting structure with two cones and four blades to increase efficiency (Fig. 1). 

The ROP model was again exercised to identify the ranges of WOB and rotational speed that would allow ROP to be maximized for the available horsepower. Results shown in Fig. 2 neglect the presence of friction torque, and, for this case, the target of 250 ft/hr was deemed achievable. Once friction torque exceeded 5,000 lbf-ft, the model suggested that ROP would fall below the target value.  

Fig. 2—Predicted torque vs. WOB (red) and ROP vs. WOB (blue dotted, dashed, and solid lines) for the 16½-in. hybrid bit in salt.

Execution Phase

26-in. Hole Section. This section commenced after the 38-in. pipe was jetted into place. The sediments encountered for approximately the first 1,200 ft were drilled with seawater using flow rate and equivalent circulating density to provide sufficient hole cleaning and bottomhole pressure to maintain wellbore stability. When the top of the salt was approached at approximately 7,900 ft, the drilling fluid was changed to a water-based PAD fluid. This was maintained to the end of the section near 10,000 ft.  

Flow rate and rotary speed were held back for approximately the first 150 ft to minimize washout of the weak sediments and allow the stabilized portion of the BHA to enter the open hole. After some periods of erratic torque, ROP was controlled at 200 ft/hr using 10,000‑lbf WOB, 150 rev/min, and 10,000 lbf-ft of torque. The torque was consistent with predictions, but ROP was significantly higher.

The transition to salt occurred at approximately 8,050 ft, slightly deeper than expected. Once the stabilized portion of the BHA was safely in the salt, the parameters were increased to pursue the maximum achievable ROP on the basis of available topdrive power. Rig personnel increased WOB to 70,000 lbf and held string speed at 150 rev/min to use the available 1,100 hp while drilling the salt. Despite being slightly less aggressive in salt than expected, the combined effects of high bit efficiency and low in-situ strengthening of salt led to lower power consumption than expected, and thus higher ROP.  

The 26-in. hybrid was pulled with only slight wear after drilling a total of 3,241 ft in 28.9 hours for a gross ROP of 112.1 ft/hr. The ROP was 15% faster than the rig’s previous best despite drilling a section that was 90% longer. Both ROP and run length were records.

16½-in. Hole Section. Before drilling the 22-in. casing, the surface WOB was pushed to the 70,000- to 75,000‑lbf limit of the BHA and rotary speed was held near constant at 160 rev/min until the kickoff point, where it was decreased to 150 rev/min. The instantaneous ROP gradually decreased from approximately 225 to 175 ft/hr over the interval as friction consumed progressively more of the available torque and power. Friction torque ranged from approximately 5,000 lbf‑ft at the start of the section to 10,000 lbf-ft at section total depth. Downhole WOB was approximately 10,000 lbf less than surface WOB despite the planned vertical trajectory to 18,000 ft. Data suggested that weight transfer may have been affected by the upper portion of the BHA. The total mechanical power was held nearly constant near the 1,150-hp rating of the topdrive. Rotating the entire drillstring consumed approximately 25% of the available power through much of the hole section. Possibilities for reducing this power consumption include using roller reamers to reduce string torque or using a downhole motor to provide bit speed while minimizing string rotation speed.  

Both axial energy and MSE remained essentially constant through the run, as expected while drilling salt. As with the previous section, the 16½-in. hybrid was pulled with little wear. The bit aggressiveness was somewhat less than expected for the two-cone, four-blade cutting structure. While the lower aggressiveness did require higher WOB to generate a given bit torque than a PDC bit would have, it also delivered the desired smooth downhole rotation and surface torque.  


  • The theoretical relationship between bit power and ROP was verified in both offset wells and the focus well.
  • A mechanical power profile that presents system torque and rotational speed data vs. topdrive capabilities can be used to visualize performance limiters and identify potential opportunities for performance improvement.  
  • A drilling model based on the inverted MSE equation can be used to predict ROP and torque for a given WOB and rotational speed for 26-in. and 16½-in. hybrid PDC/TCI bits while drilling sediments and salt.  
  • The combination of an advanced 26-in. hybrid PDC/TCI bit, continuous-proportional-steering RSS, and engineered parameters delivered the longest, fastest 26-in. run for the operator, with an ROP 15% faster than the previous best for the drillship despite a hole section 90% longer and containing 2,000 ft of salt.  
  • The 16½-in. hybrid bit, RSS, and engineered parameters yielded an ROP 38% faster than the rig’s previous best despite drilling a hole section more than twice as long. Performance was similar to that achieved by rigs with far more powerful topdrives.  
  • The time savings for the two hole sections reduced drilling costs, compared with the plan, by $1 million.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29065, “Converting Power to Performance: Gulf of Mexico Examples of an Optimization Work Flow for Bit Selection, Drilling-System Design, and Operation,” by Mark W. Dykstra, SPE, Miguel A. Armenta, SPE, Fitzerald A. Mathew Ain, SPE, Omolara Adesokan, and Tess L. Schornick, Shell, and Ashabikash Roy Chowdhury, SPE, and Mark D. Allain, Baker Hughes, a GE company, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–3 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission.