Optimization Techniques For Weight-On-Bit And Rotary Speed. Part I: Point And Interval Optimization

1976 ◽  
Vol 15 (04) ◽  
Author(s):  
R.G. Bentsen ◽  
D.C. Wilson
Keyword(s):  
Optimization Techniques ◽  
Interval Optimization ◽  
Weight On Bit ◽  
Rotary Speed

Analysis of Efficiency of Drilling of Large-Diameter Wells With a Profiled Wing Bit / Badania Efektywności Wiercenia Studni Wielkośrednicowych Świdrem Skrawającym z Profilowanymi Skrzydłami

2012 ◽  
Vol 57 (2) ◽  
pp. 363-373
Author(s):  
Jan Macuda
Keyword(s):  
Average Rate ◽  
Large Diameter ◽  
Open Pit ◽  
Mechanical Parameters ◽  
Drilling Rate ◽  
Geological Conditions ◽  
Rock Drillability ◽  
Drilling Technology ◽  
Weight On Bit ◽  
Rotary Speed

Abstract In Poland all lignite mines are dewatered with the use of large-diameter wells. Drilling of such wells is inefficient owing to the presence of loose Quaternary and Tertiary material and considerable dewatering of rock mass within the open pit area. Difficult geological conditions significantly elongate the time in which large-diameter dewatering wells are drilled, and various drilling complications and break-downs related to the caving may occur. Obtaining higher drilling rates in large-diameter wells can be achieved only when new cutter bits designs are worked out and rock drillability tests performed for optimum mechanical parameters of drilling technology. Those tests were performed for a bit ø 1.16 m in separated macroscopically homogeneous layers of similar drillability. Depending on the designed thickness of the drilled layer, there were determined measurement sections from 0.2 to 1.0 m long, and each of the sections was drilled at constant rotary speed and weight on bit values. Prior to drillability tests, accounting for the technical characteristic of the rig and strength of the string and the cutter bit, there were established limitations for mechanical parameters of drilling technology: P ∈ (Pmin; Pmax) n ∈ (nmin; nmax) where: Pmin; Pmax - lowest and highest values of weight on bit, nmin; nmax - lowest and highest values of rotary speed of bit, For finding the dependence of the rate of penetration on weight on bit and rotary speed of bit various regression models have been analyzed. The most satisfactory results were obtained for the exponential model illustrating the influence of weight on bit and rotary speed of bit on drilling rate. The regression coefficients and statistical parameters prove the good fit of the model to measurement data, presented in tables 4-6. The average drilling rate for a cutter bit with profiled wings has been described with the form: Vśr= Z ·Pa· nb where: Vśr- average drilling rate, Z - drillability coefficient, P - weight on bit, n - rotary speed of bit, a - coefficient of influence of weight on bit on drilling rate, b - coefficient of influence of rotary speed of bit on drilling rate. Industrial tests were performed for assessing the efficiency of drilling of large-diameter wells with a cutter bit having profiled wings ø 1.16 m according to elaborated model of average rate of drilling. The obtained values of average rate of drilling during industrial tests ranged from 8.33×10-4 to 1.94×10-3 m/s and were higher than the ones obtained so far, i.e. from 181.21 to 262.11%.

Drilling in the Digital Age: Machine Learning Assisted Bit Selection and Optimization

2021 ◽  
Author(s):  
Peter Batruny ◽  
Hafiz Zubir ◽  
Pete Slagel ◽  
Hanif Yahya ◽  
Zahid Zakaria ◽  
...  
Keyword(s):  
Machine Learning ◽  
Monte Carlo Analysis ◽  
Specific Model ◽  
Planning Decisions ◽  
Drilling Performance ◽  
Weight On Bit ◽  
Data Points ◽  
Ideal Tool ◽  
Rotary Speed ◽  
Artificial Neural Network Ann

Abstract Conventionally, a bit is selected from offset well bit run summaries. This method of selection is not always accurate since each bit is run under different conditions which might not be reflected in an offset study analysis. The large quantities of data generated from real time measurements in offset wells makes machine learning the ideal tool for analysis and comparison. Artificial Neural Network (ANN) is a relatively simple machine learning tool that combines inputs and calculation layers to compute a specified output layer. The ANN is fed over thousands of data points from 17-1/2 in hole sections across multiple wells. A specific model is then trained for every bit with weight on bit (WOB), rotary speed (RPM), bit hydraulics, and lithological properties as inputs and rate of penetration (ROP) as output. The model is finalized when a satisfactory statistical set of KPI's are achieved. Using a combination of Monte-Carlo analysis and sensitivity analysis, different bits are compared by varying parameters for the same bit and varying the bit under the same parameters. A bit and its optimized parameters are proposed, resulting in an average instantaneous ROP improvement of 32%. Performance benchmarked with individual drilling parameters shows improved ROP response to WOB, RPM, and bit hydraulics in the optimized run. This project solidifies machine learning as a powerful tool for bit selection and parameter optimization to improve drilling performance. Machine learning will become a significant part of well planning, design, and operations in the future. This study demonstrates how ANN's can be used to learn from previous operations and influence planning decisions to improve bit performance.

Coal identification using neural networks with real-time coalbed methane drilling data

2019 ◽  
Vol 59 (1) ◽  
pp. 319 ◽  
Author(s):  
Ruizhi Zhong ◽  
Raymond Johnson Jr ◽  
Zhongwei Chen ◽  
Nathaniel Chand
Keyword(s):  
Real Time ◽  
Coalbed Methane ◽  
Gamma Ray ◽  
Ann Model ◽  
Drilling Data ◽  
Weight On Bit ◽  
Net To Gross ◽  
Rotary Speed ◽  
Artificial Neural Network Ann ◽  
Log Interpretation

Currently, coal is identified using coring data or log interpretation. Coring is the most dependable methodology, but it is costly and its characterisation is expensive and time consuming. Logging methods are convenient, reliable, and reproducible, but can be subject to statistical and shouldering effects and often have operational difficulties in deviated or horizontal wells. Drilling data, which are routinely available, can potentially be used to identify coal sections in a machine learning environment when conventional wireline logs are not available. To achieve this, a four-layer artificial neural network (ANN) was used to identify coals in a well at Walloon Sub-Group, Surat Basin. The ANN model used drilling data and some logging-while-drilling (LWD) data. The inputs for the lithological model from high-frequency drilling data include weight on bit, rotary speed, torque, and rate of penetration. Inputs from LWD data include gamma ray and hole diameter. The criterion for coal identification is based on bulk density cutoff. The simulation results show that the ANN can deliver an overall accuracy of 96%. Due to the low net-to-gross ratio of coals within the Walloon sequence, a lower but reasonable F1 score of 0.78 is achievable for the coal sections. The proposed model can potentially be implemented in real-time to identify coal intervals without additional logs and aid validation of minimal log data.

scholarly journals Investigation on the effect of changing rotary speed and weight bit on PCD cutter wear

2019 ◽  
Vol 10 (3) ◽  
pp. 1063-1068
Author(s):  
A. M. Abdul-Rani ◽  
Khairiyah Ibrahim ◽  
A. H. Ab Adzis ◽  
B. T. Maulianda ◽  
M. N. Mat Asri
Keyword(s):  
Interaction Model ◽  
Wear Model ◽  
Element Analysis ◽  
Rock Interaction ◽  
Optimum Range ◽  
Model And Simulation ◽  
Cutter Wear ◽  
Weight On Bit ◽  
Hard Formation ◽  
Rotary Speed

Abstract The research is to determine the optimum range of rotary speed and weight-on-bit value for interbedded formation to reduce PCD cutter wear rate. To simulate an interbedded formation, a combination of limestone as the soft formation and granite as the hard formation is selected. The research is conducted based on analysis of cutter-rock interaction model, wear model and simulation of PCD cutter using finite element analysis in ABAQUS software. The results show that the optimum range of weight on bit and rotary speed for limestone is between 1000 N, 21.4 RPM, and 4000 N, 85.6 RPM, while for granite it is between 1000 N, 21.4 RPM and 3000 N, 64.2 RPM.

scholarly journals Drilling Vibration Modes and Penetration Rate Modeling using Artificial Neural Network and Multiple Linear Regression Analysis in Khoman Formation at the Egyptian Western Desert

2021 ◽  
Author(s):  
Sherif A. Ezz ◽  
Mohamed S. Farahat ◽  
Said Kamel ◽  
Ahmed Z. Nouh
Keyword(s):  
Neural Network ◽  
Regression Analysis ◽  
Penetration Rate ◽  
Drill String ◽  
Western Desert ◽  
Circulation Rate ◽  
Vibration Level ◽  
Stick Slip ◽  
Weight On Bit ◽  
Rotary Speed

Abstract Drill string vibrations are one of the most serious problems encountered while drilling as the bit and drill string interaction with formations under certain drilling conditions usually induces complex shocks and vibrations into the drill string components resulting in premature failure of the equipment and reduced drilling penetration rate. In severe cases where shocks and vibrations accumulated into drill string till exceeded its maximum yield or torsional strength, fatigue will occur and thereby increase the field development costs associated with replacing damaged components, fishing jobs, lost-in-hole situations, and sidetracks. Thus, real-time monitoring for downhole generated vibrations and accordingly adjusting drilling parameters including weight on bit, rotary speed, and circulation rate play a vital role in reducing the severity of these undesirable conditions. Vibration optimization must be done incorporation with the penetration rate, as a minimum economical penetration rate is required by the operator. In this study, three penetration rate and vibration level models were developed for axial, lateral, and stick-slip drilling modes using both MATLAB™ Software neural network and multiple regression analysis. It is found that the three models' results for vibration level and penetration rate; as compared with those recorded drilling data; showed an excellent match within an acceptable error of average correlation coefficient (R) over 0.95. The prediction of penetration rate and vibration level is thoroughly investigated in different axial, lateral, and stick-slip vibration drilling modes to be able to best select the optimum safe drilling zone. It is found that the axial vibration could be dampened by gradually increasing the weight on bit and increasing rotary speed while both the lateral and torsional vibrations are enhanced by increasing the rotary speed and decreasing the weight on bit.

A Monte Carlo Approach to Optimal Drilling

1972 ◽  
Vol 12 (05) ◽  
pp. 423-438 ◽  
Author(s):  
Ronald L. Reed
Keyword(s):  
Monte Carlo ◽  
Numerical Procedure ◽  
Tooth Wear ◽  
Optimization Techniques ◽  
Feasible Region ◽  
Constant Weight ◽  
Best Constant ◽  
Variable Weight ◽  
Method Of Solution ◽  
Rotary Speed

Abstract The variable weight-speed optimal drilling problem bas been soloed rigorously using a Monte problem bas been soloed rigorously using a Monte Carlo scheme to vary the drilling schedule toward the least cost per foot. Constraints are readily accommodated and the global nature of the optimum can he checked by starting with different initial paths. paths. Examples are given of optimal drilling schedules that lie partially interior to the feasible region as well as on upper weight or speed constraints. Comparison with the variational method of Galle and Woods showed good agreement using drilling equations presented here. However, in all cases studied, it was found that variable weight-speed optimization offered very little advantage over the simpler constant weight-speed approach. In view of ibis, a last computer program was developed for the constant weight-speed case using the powerful conjugate-gradient technique. This method should be very effective in connection with field applications. Introduction Although numerous papers discuss drilling optimization or provide optimization techniques based on field experience, it appears that the first analytical approach to the problem was published by Moore. He used drilling equations that were so simple it was possible to calculate directly the optimum weight corresponding to a given rotary speed. In 1959, Graham and Muench used what is sometimes called the "graphical" approach, together with more realistic drilling equations, to calculate optimum combinations of weight and speed to bearing failure. In their paper, cost per foot is computed vs weight for various depths at fixed speed. This is repeated for various speeds until the optimum is found for each depth. The most significant contribution to the field appeared in 1960. This paper by Galle and Woods culminated years of drilling mechanics research, reducing it all to a concise set of drilling equations. Necessary conditions for the optimal variable weight-speed path are found using the classical calculus of variations with integrated drilling equations acting as constraints. The final result is obtained using a numerical procedure. One conclusion was that, in most cases, the variable weight-speed method would effect a saving of at least 10 percent over the best constant weight-speed schedule. Although we do not want to detract from the importance of this work in any way, it is subject to question on two counts. First, the method of solution requires weight and speed to vary continuously as a function of time. Second, it is recommended that bearing-wear-limited schedules be computed using tooth-wear-limited theory. In 1962, Billington and Blenkarn used the equations and techniques developed by Galle and Woods to optimize the variable weight schedule when speed is fixed by rig limitations. They concluded there was little cost advantage in using a variable weight-speed schedule in preference to a constant speed program. In 1963 the second contribution of Galle and Woods to optimal drilling appeared. In this paper ordinary constrained calculus is used to solve the two-dimensional best constant weight-speed problem. They also provide the best speed for a given weight and the best weight for a given speed. Charts are furnished so that hand calculations can be rapidly made. In the introduction, Galle and Woods note that, in certain cases, the procedures in which both weight and rotary speed are varied or where weight alone is varied result in only slightly lower cost than if the bit were properly operated at constant weight and rotary speed. We have therefore seen a transition from the belief that in most cases variable weight-speed is at least 10 percent better than constant weight-speed to the opinion that there is very little difference between the two methods. At this point, one is not certain what to conclude. In this paper a new, rigorous method of optimization is developed. It provides an independent check on the approximations involved in the variational approach of Galle and Woods and compares optimal variable weight-speed schedules to the corresponding optimal constant weight-speed programs. programs. SPEJ P. 423

Effects of Size on Three-Cone Bit Performance In Laboratory Drilled Shale

1985 ◽  
Vol 25 (04) ◽  
pp. 473-481 ◽  
Author(s):  
Alan D. Black ◽  
Gordon A. Tibbitts ◽  
John L. Sandstrom ◽  
Bennie G. DiBona
Keyword(s):  
Confining Pressure ◽  
Rock Properties ◽  
Drill Bit ◽  
Pressure Drops ◽  
Rule Of Thumb ◽  
Mancos Shale ◽  
Water Based ◽  
Weight On Bit ◽  
Rotary Speed ◽  
Rock Bit

Abstract The effects of size on the performance of three-cone bits were measured during laboratory drilling tests in shale at simulated downhole conditions. Four Reed HP-SM three-cone bits with diameters of 6, 7 7/8, 9, and 11 in. [165, 200, 241, and 279 mm] were used to drill Mancos shale with water-based mud. The tests were conducted at constant borehole pressure, two conditions of hydraulic horsepower per square inch of bit area, three conditions of rotary speed, and four conditions of weight-on-bit (WOB) per inch of bit diameter. The resulting rates of penetration (ROP's) and torques were measured. penetration (ROP's) and torques were measured. Statistical techniques were used to analyze the data. Introduction Drill bit manufacturers generally recommend WOB operating ranges for their bits in terms of pounds-force per inch of bit diameter. The practice of normalizing the per inch of bit diameter. The practice of normalizing the effect of bit size by expressing it in these terms has been widely used and often accepted as a "rule of thumb" in the drilling industry. Many have suspected that this rule of thumb may be an oversimplification because bit design tends to vary widely with size even in the same models, and hydraulic cleaning of the bit and bottom of the hole becomes much more difficult as size increases. A better understanding of the effects of size on bit performance and the validity of the WOB per inch of bit performance and the validity of the WOB per inch of bit diameter rule of thumb was sought by performing drilling tests with various-size bits under controlled laboratory conditions. Drilling tests were performed with four Reed HP-SM three-cone bits with diameters of 6, 7 7/8, 9, and 11 in. [165, 200, 241, and 279 mm]. As many variables as possible were held constant during the drilling tests, including rock type; confining pressure and overburden stress on the rock; mud type, properties, and temperature; and borehole pressure. Nozzle sizes and flow rates were selected so that each bit was tested at approximately the same conditions of hydraulic horsepower per square inch of bit area. Three rotary-speed conditions per square inch of bit area. Three rotary-speed conditions and four WOB per inch of diameter conditions were run. The resulting ROP's and torques were measured at each condition. A detailed statistical analysis was performed on me dam to determine the relationship between the independent variables of bit size, WOB, rotary speed, and hydraulic horsepower per square inch of bit area and the dependent variables of ROP, torque, and mechanical horsepower expended at the bit. Drill Bit, Rock, Mud, and Nozzle Selection Four new Reed HP-SM bits with diameters of 6, 7 7/8, 9, and 11 in. [165, 200, 241, and 279 mm] were provided by Reed Rock Bit Co. for the tests. The provided by Reed Rock Bit Co. for the tests. The HP-SM bit is specified in the IADC code under four classifications (537, 547, 617, and 627). The manufacturer recommends the HP-SM bit for both soft formations containing streaks of harder materials and medium-strength formations. The HP-SM bits have conical inserts except for the chisel-shaped inserts on the gauge row. The manufacturer's recommended operating ranges for WOB per inch of bit diameter and rotary speed are 3,000 to 6,000 lbf [525 to 1051 N/mm] per inch of bit diameter and 45 to 140 rev/min, respectively. Fig. 1 is a photograph of the HP-SM bits. The number of inserts, average insert diameter, and average insert length were measured and are listed in Table 1. The rock formation samples drilled were Mancos shale. Mancos shale is a Cretaceous, gray to black, shale/siltstone formation containing 10% clay composed of illite and chlorite. Samples 15 in. [394 mm] in diameter by 36 in. [914 mm] long were used for the 6–, 7 7/8–, and 9-in.- [165–, 200–, and 241-mm]-diameter bit tests. A sample 17 in. [445 mm] in diameter by 36 in. [914 mm] long was used for the 11-in.–[279-mm]-diameter bit test. All samples were originally cored from a massive surface outcropping located in central Utah and preserved for the drilling tests. Mancos shale has an unconfined compressive strength of 9,000 psi [62 053 kPa] and a permeability less than 1 d. Detailed rock properties permeability less than 1 d. Detailed rock properties and a comparison of laboratory and field shale drilling have been given previously. A "standard" water-based mud with properties listed in Table 2 was selected for the tests. To compare the performance of different-size bits, it was felt that hydraulic horsepower per square inch of bit area (HSI) should be held constant during the tests. It was also felt that similar pressure drops across the bit should be run if possible. Calculations were made to determine the nozzle diameters that would create approximately the same pressure drop at constant HSI conditions. SPEJ p. 473

scholarly journals Fractional-order controllers for stick-slip vibration mitigation in oil well drill-strings

2021 ◽  
pp. 146134842098404
Author(s):  
Massinissa Derbal ◽  
Mohamed Gharib ◽  
Shady S Refaat ◽  
Alan Palazzolo ◽  
Sadok Sassi
Keyword(s):  
Fractional Order ◽  
Degrees Of Freedom ◽  
Lumped Parameter Model ◽  
Oil Well ◽  
Proportional Integral Derivative ◽  
Stick Slip ◽  
Proportional Integral ◽  
Drilling Performance ◽  
Weight On Bit ◽  
Rotary Speed

Drillstring–borehole interaction can produce severely damaging vibrations. An example is stick–slip vibration, which negatively affects drilling performance, tool integrity and completion time, and costs. Attempts to mitigate stick–slip vibration typically use passive means and/or change the operation parameters, such as weight on bit and rotational speed. Automating the latter approach, by means of feedback control, holds the promise of quicker and more effective mitigation. The present work presents three separate fractional-order controllers for mitigating drillstring slip–stick vibrations. For the sake of illustration, the drillstring is represented by a torsional vibration lumped parameter model with four degrees of freedom, including parameter uncertainty. The robustness of these fractional-order controllers is compared with traditional proportional-integral-derivative controllers under variation of the weight on bit and the drill bit’s desired rotary speed. The results confirm the proposed controllers effectiveness and feasibility, with rapid time response and less overshoot than conventional proportional-integral-derivative controllers.

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