Real-Time Specific Energy Monitoring Enhances the Understanding of When To Pull Worn PDC Bits
- Robert J. Waughman (Woodside Energy Ltd.) | John V. Kenner (Hughes Christensen/Baker Hughes) | Ross A. Moore (Hughes Christensen/Baker Hughes)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2003
- Document Type
- Journal Paper
- 59 - 67
- 2003. Society of Petroleum Engineers
- 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.6 Drilling Operations, 1.10 Drilling Equipment, 1.5 Drill Bits, 7.2.3 Decision-making Processes, 4.1.2 Separation and Treating, 1.11 Drilling Fluids and Materials, 1.12.3 Mud logging / Surface Measurements, 4.3.1 Hydrates, 1.6.1 Drilling Operation Management, 1.5.1 Bit Design, 2.4.3 Sand/Solids Control, 1.12.1 Measurement While Drilling, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6.9 Coring, Fishing
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Knowing when to change dulled bits can significantly reduce costs, which can be particularly important in high-cost environments. However, current techniques are based more on speculation and hope rather than science.
The concept developed to dramatically improve this inefficient decision process involved measuring the mechanical energy input at the drill rig floor, calculating the drilling specific energy (SE), checking the current formation type with real-time downhole gamma ray (GR) readings, comparing the SE with the benchmark new-bit SE, and then using these values to assess the bit's "dull" state.
This method has been proven to work in synthetic-based mud systems in which balling does not mask the bit's dull condition. It was imperative that the operator proved that this process worked in water-based drilling fluids that had replaced earlier synthetic muds because of environmental concerns, cost, and improved performance in water-based mud (WBM). Recently, the operator established that this process worked in water-based mud systems treated with antiballing chemicals. The case studies in which this methodology was developed are presented and discussed.
Drilling performance is commonly analyzed by comparing a given run to the average of offsets. However, in offshore projects, offsets are fewer and learning must be accelerated because of the inherent high cost. To reach a desired performance level, aggressive targets must be set and plans to achieve those must be developed and implemented.1 Using real-time drilling efficiency and GR data to monitor bit dull state is one approach refined and used by this operator in particularly troublesome areas.
To estimate the bit's dull state from drilling efficiency data, understanding how incremental bit wear affects performance for different drilling conditions had to be improved. Galle2 and Bourgoyne3 developed early mathematical models for approximating the effects of bit wear on drilling performance (Figs. 1 and 2). Many performance models exist today, but they typically fail to capture the dependencies on formation hardness and balling tendencies vs. the type of drilling tool used-PDC, Tungsten Carbide Insert, or Mill Tooth (Fig. 3). In a previous work, we classified performance expectations across a range of tools and drilling conditions4 (Fig. 4) and now use this information to interpret a dull state. The following field examples illustrate when a bit should have been pulled and the consequences on the performance of subsequent bit runs and estimated cost impact of not doing so.
Drilling off the remote North West Shelf of Australia requires the use of semisubmersible rigs. The discovery of hydrocarbons in 1973 in the Cretaceous sands of the Angel formation led a local operator to drill an offset well, NWS 1 (Fig. 5), into a deeper horizon in January 1996 to investigate the possibility of gasbearing sands in the early Jurassic and Triassic formations. This was the deepest well drilled by the operator in more than 5 years, and offset information for the deeper part of the well was scarce. The operator chose a low-toxicity oil-based mud (LTOBM) for the 121/4- and 81/2-in. hole sections to lessen the chances of differential sticking and bit balling and to improve the chances of complete core recovery while coring overbalanced in the 121/4-in. section. Eliminating shale hydration with the oil mud also allowed the operator to use heavy-set PDC bits while still minimizing the risk of bit balling.
Fig. 6 shows the casing setting points with the pore pressures and mud weight used in the 1996 well. The majority of the PDC bits ringed out, and severe gauge wear was also a problem with two runs, as shown in Table 1 . A post-well analysis revealed the following.
1. All PDC bits were left in the hole too long, adversely affecting the next bit run.
2. Severe gauge wear resulted from excessive reaming with new PDC bits before reaching bottom. This type of overloading in the bit shoulder area contributed to poor overall life and rate of penetration (ROP).
For future high-cost wells, a more precise method had to be devised and used in deciding when to pull bits. Speculation rather than science was the determining factor in whether to change a bit on the NWS-1 well or leave it in the hole. This decisionmaking process was extremely inefficient and did not further the operator's philosophy of continuous improvement.1 The procedure developed by analyzing drilling performance for NWS 1 was then established.
Check the current formation type with a downhole GR reading.
Calculate the drilling SE5 [the amount of mechanical energy input at the rig floor per unit volume of material removed (Appendix A)].
Establish a "new bit" shale benchmark SE for every run when possible.
Compare the real-time SE to the benchmark new-bit SE.
Estimate the wear by comparing the real-time SE with the benchmark value.6
The results of this procedure can be verified by a post-well calculation of mechanical efficiency. The method's foundation was based on the following principles.
No rock is 200,000 psi strong, and, in fact, most rocks drilled in the oil field are much less than 50,000 psi, with shales less than 20,000 psi (unconfined).
SE levels in the field are often observed to be more than 1,000,000 psi.
High-pressure laboratory drilling tests in shale have revealed drilling efficiencies with balled bits as low as 1% and optimized efficiencies approaching 50%.
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