Field Verification of Drilling Models and Computerized Selection of Drill Bit, WOB, and Drillstring Rotation

Abstract

Summary A computer program was developed for the simultaneous selection of a roller-cutter bit, bit bearing, weight on bit (WOB), and drillstring rotation that minimizes drilling cost per foot for a single bit run. Two drilling models were tested with data from five wells located offshore Alagoas, Brazil. Results show that the rate of penetration (ROP) of the fifth well can be predicted with coefficients calculated from the four previous wells, resulting in cost savings. previous wells, resulting in cost savings. Introduction Several authors have studied optimization of single bit runs to develop techniques to predict the best combination of rotary speed and WOB to minimize cost per foot drilled. Minimizing cost per foot drilled is of particular interest to offshore operations because rig time is very costly and savings can be significant. Such cost savings can occur only if the drilling model correctly predicts bit performance throughout the bit's entire life. Thus, before any performance throughout the bit's entire life. Thus, before any optimization is performed, bit-performance predictions must be checked and the reasons for prediction failures must be studied. Some drilling models work by predicting the effects of various drilling parameters on ROP and back-calculate their "constants" whenever history data are available. Therefore, good data recording is essential for meaningful predictions. The objective of this study was to check the predictions of two drilling models with field data and to develop a practical method that can be applied in the field for selecting a roller-cutter bit, bit bearing, WOB, and drillstring rotation to minimize drilling costs (within certain constraints). Drilling Models Two drilling models were considered in this study. Bourgoyne and Young's Model. Bourgoyne and Young considered the effect on ROP of the formation strength, compaction, differential pressure, WOB, rotary speed, tooth wear, and bit hydraulics and pressure, WOB, rotary speed, tooth wear, and bit hydraulics and used a multiple-regression technique to calculate the constants of the model. Their model is given by R = exp,......................(1) D where a1 = effect of formation strength and a2×2 and a3×3 = effects of compaction, with x2 = 10,000 −D....................................(2) 0.69 and ×3 = D (gp-9.0)................................(3) a4×4 = effect of pressure differential, with x4 = D(gp -pc),...................................(4) and a5×5 = effect of WOB and bit diameter, with x5 = 1n{[(W/d)-(W/d)t]/[4.0-(W/d)t]}..............(5) where W/d=WOB per inch of bit diameter, 1,000 lbf/in., and (W/d)t=threshold WOB at which the bit begins to drill, 1,000 lbf/in. Note that Eq. 5 has not been verified by published experimental data. a6×6 = effect of rotary speed, with x6 = 1n(v/100);,..................................(6) a7×7 = effect of tooth wear, with x7 = −h,..........................................(7) and a8×8 = effect of bit hydraulics, with x8 = 1n(Fj/1,000).................................(8) Tooth wear rate can be calculated by H3 v H1 (W/d)max− 1+(H2/2) Rh =, ..(9) H 100 (W/d)max-(W/d) 1+H2h where (W/d)max = weight diameter ratio for instantaneous tooth failure, 1,000 lbf/in. Bearing wear rate can be calculated by 1 v b1 W b2 Rb = ....................(10) B 100 4d Authors' Model. This model was developed by using dimensional analysis and by considering the effects on ROP of rock compressive strength, formation strength, compaction, differential pressure, WOB, rotary speed, tooth wear (the same as Bourgoyne pressure, WOB, rotary speed, tooth wear (the same as Bourgoyne and Young's model), and bit hydraulics.