SPE-187593-MS Engineered Bit Design and Drilling Parameters Mark Breakthrough Drilling Performance in Interbedded Damaging Carbonates Waleed Agawani, Baker Hughes; Abdullah M. Al-Ajmi, Kuwait Oil Company; Wasim Fawaz, Baker Hughes; Abdulaziz Al-Rushoud, Kuwait Oil Company; Mehul Pandya, Baker Hughes; Hussain Ali Al-Haj, Kuwait Oil Company; Atef Abdelhamid, Baker Hughes; Mohammed El-Sherif, Kuwait Oil Company Copyright 2017, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Kuwait Oil & Gas Show and Conference held in Kuwait City, Kuwait, 15-18 October 2017. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract West Kuwait's 22-in. section comprises a vertical hole through 3,500 feet of interbedded carbonates varying significantly in compressive strength, and drilled commonly with minimal or no fluid returns. The section is typically drilled with roller-cone tungsten carbide insert (TCI) bits because large polycrystalline diamond compact (PDC) bits are extremely costly and require expensive performance motors to support their generated torque. PDC bits are also at risk of impact damage when drilling through the interbedded formations in this interval. Operators tend to apply higher drilling parameters while in the lower compressive strength intervals to achieve higher rates of penetration (ROP). Consequently, when the TCI bit enters the following harder formations with the same high operating parameters, it often suffers severe cutting structure damage. The result is reduced ROP. Greater weight on bit is then applied, causing further bit damage and possible sealed bearing failure. An engineering project was launched to develop a TCI bit specifically for the interbedded carbonates of this section. The primary challenges of the project were: • • • • Ensure the bit finishes the section in one run Improve dull condition of bit coming out of hole Surpass current field average ROP consistently Maintain efficient cleaning at lower flow rates for drilling in complete fluid-loss scenario Based on data and experience in drilling the application, an engineering process took place where several designs improvements with potential to improve performance were identified and trialled. Field engineers then worked onsite to identify how to drill the interval with optimal parameters for each sub-layer. The final design included: • Specialized TCI cutting structure for carbonate drilling 2 SPE-187593-MS • • • • High impact-resistant insert geometry Simulated hydraulic efficiency to improve hole cleaning Improved high aspect ratio elastomer seals designed to endure longer runs Specialized tungsten carbide to improve cutting structure durability The engineering process yielded a design that successfully drills the complete section in one fast run the fastest of the section - with an improved field average penetration rate to 63%, saving the operator more than 38% in associated cost for drilling the section. The application-engineered cutting structure enabled the use of lower drilling parameters than normal, thereby improving drilling efficiency and enhancing the post-drilling dull condition from the average of 3-3-BT to 1-2-WT. The paper shows a case study in Kuwait demonstrating the engineering and results of designing a TCI bit matched to application. Application Summary Lithology This paper discusses the 22-in. section that spans a vertical interval of ~4,000 ft. of primarily carbonate formations. Table A-1 summarises the lithological breakdown of the column drilled. Formation unconfined compressive strengths (UCS) typically range from 15 to 35 Kpsi. Due to the interbedded nature of some intervals and the varying UCS of different formations, bits drilling the section typically face impact forces that can be detrimental to the cutting structure. Due to these forces the bits are subjected to the section characteristically require a minimum of two bit runs to complete. The initial bit run's ROP drops because cutting structure suffers damage, necessitating a bit trip to continue the section. Table A-1—Lithological Breakdown of Section Fluid System One of the challenges in the section involved drilling with partial or complete losses. To avoid losing expensive oil-based muds, water-based mud is used with a typical mud weight of 8.9 ppg maintained throughout the section. Severe circulation loss reduces flow rates and lowers the mud levels, resulting in lower hydraulic cleaning efficiency of cutting structure. The compounded issues of limited flow rate and water-based mud in presence of shale beds caused partial balling on bit cutting structure. SPE-187593-MS 3 Bottom Hole Assembly As the interval drilled involved a vertical hole, the bottom hole assembly (BHA) was a packed 3 full gauged stabiliser rotary BHA: • • • • 22-in. bit with a full-gauge near-bit stabilizer 12-in. shock sub with a full-gauge string stabilizer 9.5-in. drill collar (29 ft.) with a full-gauge string stabilizer 9.5-in. drill collars Operator Objectives The operator's main objective was to reduce the financial and temporal overhead in drilling the section. In this application two main goals were set to meet this objective: Complete section in one run consistently – The section typically requires two bit runs to complete, costing the operator one trip per well. By eliminating one trip, the time and cost of trip time plus an additional bit's expense are eliminated. Maintain or improve cost per foot (CPF) – A heavier set bit may improve overall durability but may drill more slowly; hence taking as much time as it takes to drill the interval with two bits with minimal overall benefit. The goal here was to sustain drilling performance by remedying issues faced while drilling and improving durability to complete the section in one run, thus the need for minimizing insert breakage without increasing the insert count. Solution Development Process The process of improving performance involved analysing current runs and identifying performance limiters and proposing solutions to remedy them. Data were gathered from various sources and analysed to identify challenges preventing the goals from being achieved: • • • • Dull grading of bits. Post-run bit dulls of current designs were reviewed to identify repeat failure patterns and the types of wear faced across several bit designs. This review and other data enabled the inference of the causes of breakage and decisions on the best approach to address it. Rates of penetration and distance drilled by current designs. Cutting structure and cutter types of longer runs were reviewed and compared with faster runs to optimise a design that would achieve acceptable ROP while drilling extensive footage. Surface parameters used in drilling the section. Uncompressive strength analysis. Correlate formation hardness with other logs to better understand bit behaviours in various formations. Analysis Terminal Formations Fig. B-1 plots several offset runs with older 22-in. TCI designs. From the figure, most runs terminated in the transition zone between the Tayarat and Hartha. The Tayarat is a loss-prone formation, which can mean drilling through inconsistent bottom-hole formations. This would cause drilling instability and result in impact damage. Hartha has a typically high compressive strength (30+ Kpsi) that can further deteriorate cutting structure and cause impact damage. 4 SPE-187593-MS Figure B-1—Previous Design Run Depth Drilled Bearing Life TCI bit bearings are rated to a recommended maximum number of rotations as a safety margin before bearings have higher potential of failure. This is based on engineering knowledge and field experience from running the bits equipped with the bearings in the given application. Where ROP is reduced in longer intervals, bearings are subjected to longer drilling times that can push the total revolutions on a bit beyond its recommended bearing life. In this particular application the interval is relatively long, and bits complete their runs nearing the end of their recommended limits. For various reasons ROP may decrease, thereby pushing the bit beyond the recommended range and result in bearing failure. Drilling with a failed bearing can result in severe damage to the cutting structure similar to that seen in Fig. B-2. In this example the bearing has seized, resulting in dragging the cone across the bottom-hole surface. Figure B-2—Example of Cutting Structure Damage from Bearing Failure Impact Damage The primary types of damage seen on most post-run dull gradings of bits in this section were broken or chipped teeth. This type of damage is typically seen when the cutting structure sustains impact loading during drilling. Causes of impact damage in this application can be attributed to interbedded formations and incorrect drilling parameters applied while drilling. Fig. B-3 is displays typical examples of impact damage seen on post-run cutting structures. SPE-187593-MS 5 Figure B-3—Impact Damage on Cutting Structure – Broken Inserts Broken teeth damage typically begins in one row and then spreads to the closest offset row in neighbouring cones. When a row is compromised, the result affects the remaining cutting structure in two ways. First, the reduced number of inserts in the row causes the remaining inserts to work harder to compensate. Secondly, the large broken inserts may become junk on the hole bottom, which can cause further broken inserts across the cutting structure. In general, ROP drops quickly after a cutting structure is compromised. Uneven Wear Typical post-run analysis of a drill bit that had been drilling efficiently tends to show uniformly distributed wear across the cutting structure, with areas of the bit exposed to greater work showing higher indications of wear. Uneven wear indicates abnormal drilling and the distribution of the wear on the cutting structure can sometimes reveal the possible cause of the damage. A phenomenon seen in some post-run dull inspections is that the inner rows suffered insert breakage while outer cutting structure is still intact, such as that displayed in Fig. B-4. This type of irregular breakage is sometimes seen when improper parameters, such as excessive WOB, are applied resulting in inefficient drilling. Figure B-4—Non-Uniform Wear on Inner Cutting Structure 6 SPE-187593-MS Balled Cutting Structure In some cases bits came out of hole with a partially balled cutting structure. This is another challenge observed in the section as it crosses shale beds and in the event of lost circulation, flow rates are reduced to maintain drilling fluid levels. Even with full circulation rates, the hydraulic horsepower per square inch (HSI) is typically quite low (< 0.5 hp/in2) on large diameter bits such as the subject 22-in bits. Both issues result in an increased chance of cuttings accumulating on the cutting structure and reducing its drilling efficiency. Typical nozzle configuration on larger bits in this kind of application would involve three outer nozzles and one centre nozzle focused on the inner portion of the cutting structure. Due to the size of the bit in question, this kind of configuration may not sufficiently cover the bits cutting structure. Consequently, a customized nozzle configuration may be required to maintain sufficient cone coverage cleaning efficiency. Parameter Review Drilling across varied lithologies requires varying parameters to maintain efficient drilling performance. The effect of parameters used in drilling formations in reference wells were compared with the ROP achieved in each formation and the post-run dulls of the bits. Reference wells were selected for a variety of scenarios where different parameters were applied to better evaluate the effect of parameters and come to a conclusion on how to optimise them. The well referenced in Table B-1 started with conservative parameters that were progressively increased throughout the run. While ROP in most formations was relatively higher overall throughout the run than other reference wells, the parameters trended similar to the results from other offset wells. Because no losses were encountered in the run, the GPM could be maintained higher, which may have aided hole cleaning and sustained ROP. In the transition zone between the Tayarat and Hartha formations the relatively high WOB and RPM were maintained but the ROP dropped considerably, ending the run. The post-run inspection revealed impact damage across the entire cutting structure that would have caused the drop in ROP near the end of the run. Table B-1—Reference Well 1 Parameter Breakdown The second reference well (Table B-2) involved high parameters applied throughout the run. Overall ROP was significantly improved, particularly in softer formations; however the run terminated before reaching Hartha formation and with substantially worse post-run dull condition. ROP dropped considerably in the transition zone between the Tayarat and Hartha until it wasn't economically feasible to continue drilling. SPE-187593-MS 7 Table B-2—Reference Well 2 Parameter Breakdown Reference well 3 (Table B-3) had average parameters applied throughout the section that were managed carefully through the transition zones. Fluid losses were encountered in the transition between the Rus and Radhuma and in the Tayarat, resulting in reduced GPM that improved late in the run. Relatively lower drilling torque was observed at the start of the run, but this increased later in the run as GPM was reduced. Post-run dull analysis showed the bit had reduced damage in comparison with offset runs that may be attributed to the carefully managed parameters through the transition zones. Table B-3—Reference Well 3 Parameter Breakdown Well 4 referenced in Table B-4 represents a scenario where conservative parameters are observed throughout the run. Although post-run dull conditions were improved, the overall ROP was relatively lower compared to offset runs. Table B-4—Reference Well 4 Parameter Breakdown In cases where parameters were optimised through maintaining conservative parameters across transition zones and in harder formations the post-run dulls were better. Maintaining conservative parameters 8 SPE-187593-MS throughout the run as in reference well 2 resulted in the best post-run dull, but the section ROP was relatively low in comparison to the other wells which used more aggressive parameters. A relationship between higher flow rates and lower drilling torque was observed that resulted in improved ROP. This can be attributed to higher flow rates improving hydraulic cleaning and thus reduced bit balling that lowered drilling torque and improved performance. New Bit Design Typically, bits used in carbonate formations exhibit different drilling characteristics, which often lead to compact chipping and breakage. Large-diameter bits with relatively high seal sliding speeds as compared to smaller diameter bits suffered too because they endured more wear on elastomer seals. In addition, because of the relatively high distance between the nozzle exit and bottom hole, large-bit hydraulics are often less effective in achieving sufficient bit and/or hole cleaning. The application-specific TCI bit blends specific features with tougher, impact-resistant carbide grades, innovative compact shapes and advanced cutting structures and hydraulics designed specifically to combat these challenges. After reviewing previous bit performance in this application and inspection of dull bits, the following design features were considered when designing the new TCI bit for the application: Engineered Compacts The previous bit design utilized a typical carbonate drilling grade that still encountered breakage in almost all locations on the bit. To support the durability of the inserts on the new TCI design while keeping the aggressive chisel-shaped inserts, tougher carbides that better resist thermal fatigue and minimize insert breakage had to be utilized (Fig. D-1), increasing achievable footage and ROP. Varying the grain sizes and compositions of the tungsten carbide crystals and the cobalt binder content yields different carbide grade material properties, and when matched with aggressive tooth shapes, may extend bit life in applicationspecific runs. uns. Figure D-1—Toughness vs. Wear Resistance for Drill Bit Tungsten Carbide Grades Robust Seal Geometry The geometry of previous O-ring elastomer seals was not optimised for long drilling hours and highWOB applications. The movement and twisting of the O-ring seal against the internal cone seal recess may accelerate wear and increases the likelihood of bearing seal failure. On this TCI bit, a high aspect ratio (HAR) elastomer seal was added to the already field-tested precision bearing. Thanks to their unique geometry, HAR seals maintain greater sealing integrity than O-ring seals when subjected to identical drilling conditions. Stabilizing ribs or rings were also specified to maintain the optimal seal position within the cone SPE-187593-MS 9 seal recess for long seal life and reliability. (Fig. D-2). The result was significantly longer seal life in a bearing designed for maximum load capacity in both rotary and motor applications. Figure D-2—High Aspect Ratio Seal Computer Modelled Insert Arrangements When designing the cutting structure, engineers used computer modelling to statistically improve resistance to tracking (Fig. D-3). Tracking occurs when compacts consistently fall into previously cut formation, this results in lower ROP and higher vibrations. The spacing of the inserts was optimized to eliminate bit tracking, reduce cutter damage and improve penetration rate. Moreover, the placement of the inserts was optimized to deliver superior borehole quality via consistent 2D bottom-hole coverage that ensures efficient rock removal. Figure D-3—Tracking of Inserts vs. Cutting (No Tracking) Bit Hydraulics The size of the bit and the application dictates that flow reaches all parts of the bit and hole. The new TCI design positions three jets in the centre of the bit aimed at the upper side of all three cones, thereby improving cleaning efficiency and reducing bit balling. Each of the centre jets is equipped with its own nozzle for more effective flow to reduce bit balling than can be achieved with a single-centre jet nozzle. Improved hole cleaning and coverage translates into faster ROPs and less risk of bit balling, especially in a low HSI environment. Moreover, computational fluid dynamics further improved hydraulic efficiency by minimizing body erosion and blind spots (Fig. D4) 10 SPE-187593-MS Figure D-4—Computational Fluid Dynamics module Bit Body Hardfacing To improve overall integrity of the bit, an extremely wear-resistant hardfacing material was applied to the shirttail and leg of the bit to protect these areas from the effects of back-reaming and up-drilling, thereby extending the overall life of the bit. Field Trial Results The new design was field trialled over several wells against sample offset wells of current conventional designs used in field to evaluate its relative performance. Benchmarking each trial was primarily based on average and best performance for total footage drilled and ROP achieved over the complete run. As a secondary evaluation criteria, post-run dull grading was included in the performance comparison to quantify the improved durability of the new design. ROP and Footage Drilled Fig. E-1 references ROP and footage drilled for offset runs representative of typical legacy design field performance and contrasts them with the new field design trials. Several observations can be made from the figure: • • • The new design with optimised parameters completed the interval consistently on all runs, thereby achieving the first goal of consistently completing the section in one run. The section ROP was consistently above the field average and almost always faster than offset runs, even without including the additional trip time for a second or third bit run in the offset wells. New field record of 40.4fph was set for complete section ROP on Trial Well 4. SPE-187593-MS 11 Figure E-1—Offset and Trial Run Performance CPF and ROP Improvements CPF improvements gained in the section came from maintaining an overall ROP higher than field average, eliminating the trip time for a second or third run, and eliminating the incremental cost of a second or third new bit. Table E-1 summarises the improvements gained in ROP and CPF against the field average performance. Overall, the runs improved on the average run performance of older designs and, when combined with eliminated bit trips and extra bit costs, resulted in a 22% to 39%, lower CPF in all these field trial runs. Table E-1—ROP and CPF Improvement on Field Average Post-Run Dulls Overall post-run dulls (Fig. E-2) of the trial runs showed reduced cutting structure breakage, indicating more efficient drilling performance as the cutting structure survived to complete the interval with minimal damage. Bearings were consistently effective, meaning the new seal package was better suited for the longer interval in this section. 12 SPE-187593-MS Figure E-2—Post-Run Dulls of Trial Runs Minimal bit balling was encountered, indicating that the hydraulic design of the new bit improved cleaning efficiency and provided better coverage of cone cleaning. Conclusion Through utilising the latest technological advances in TCI bits and optimising drilling parameters in problematic formations the goals set out at the start of this paper were achieved. Cutting structure durability was improved, enabling the section to be drilled with one bit consistently. Post-run dull analysis showed reduced insert breakage, indicating the combination of the new design and improved carbide grades was better matched to the application than the older designs. This enabled the bits to achieve the first goal of completing the section with a single bit run. Optimised drilling parameters and stronger impact resistant cutting structure yielded an ROP improvement of up to 53% on average. The increased robustness of the new design allowed it to be pushed harder and longer than the old design, resulting in 22% to 39% lower CPF achieved through faster ROP, eliminated bit trips, and additional bit costs. Successful deployment of the new design yielded a saving of almost $80,000 USD and three days in rig time per well. SPE-187593-MS 13 Acknowledgements The authors of this paper thank Kuwait Oil Company and Baker Hughes for permission to publish the data and technical information presented in this paper. Thanks to all those involved in the process of developing and trialling the designs mentioned in this paper; without them it wouldn't have been a success. Nomenclature UCS – BHA – ROP – TCI – FEA – CPF – FEA – HAR – HIS – GPM – WOB – RPM – References Unconfined Compressive Strength Bottom Hole Assembly Rate of Penetration Tungsten Carbide Insert Finite Element Analysis Cost Per Foot Finite Element Analysis High Aspect Ration Horsepower per Square Inch Gallons per Minute Weight on Bit Rotations per Minute Agawani, W., Al-Ajmi, A.M., Taha, M., Gohain, A., Omar, M.G., Al-Haj, H.A. et al 2016, SPE-180673-MS - Application Focused Drill Bit Engineering Delivers Consistent Improvement in Efficient Drilling Performance, Proceedings from IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, 22-24 August, Singapore, Singapore, Available from: OnePetro Digital Library. [20 August 2017]. Al-Baghli, W.J., Al-Khaldy, A.D., Al-Mutawa, F., Saradhi, V., Maliekkal, H., Fayed, M. et al 2011, SPE-147867-MS - Performance Step Change: New 16-in TCI Design Solves Multiple Middle East Carbonate Drilling Challenges, Proceedings from SPE/IADC Middle East Drilling Technology Conference and Exhibition, 24-26 October, Muscat, Oman, Available from: OnePetro Digital Library. [20 August 2017]. Al-Saeedi, M.J., Al-Fayez, F.A., Sounderrajan, M., Al-Mudhaf, M.N., Portwood, G.R., Ghoneim, O. et al 2012, SPE-151615-MS - Solving Multiple Carbonate Challenges: TCI Delivers Performance Step-Change Drilling Deep 28in Hole Section, Proceedings from SPE Middle East Unconventional Gas Conference and Exhibition, 23-25 January, Abu Dhabi, UAE, Available from: OnePetro Digital Library. [20 August 2017].