SPE PP. Copyright 2010, Society of Petroleum Engineers

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1 SPE PP Continual Bit Design Evolution Improves Performance in the Skinner Ridge Field - Piceance Basin Travis Garza, SPE, James Wimberg, SPE, Kevin Kopp, SPE, Chevron U.S.A Inc.; David Cheatheam, Gary Hettinger, Chaunsey Pantuso, Halliburton Drill Bits & Services Copyright 21, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Eastern Regional Meeting held in Morgantown, West Virginia, USA, October 21. 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 3 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The Piceance Basin is one of several unconventional gas resources that have been the subject of intense industry activity throughout onshore North America. Due to challenged Rocky Mountain natural gas prices and a recent high cost environment, drilling and completing wells quickly and inexpensively is crucial to managing the economic conditions in Chevron s Skinner Ridge Field development in western Colorado. A focused effort on continual improvement has been employed by the Chevron Piceance Drilling Team to maximize drilling efficiency. In terms of drilling performance, an obvious method to reduce drilling time and cost is to physically drill faster by achieving increased drill bit rate of penetration (ROP) without compromising bit reliability. The following paper summarizes performance improvements achieved through numerous bits trials, dull bit grading analyses and design iterations through a process of application design engineering at the supplier/customer interface. The result has been a step change in drill bit performance exhibited by the continual increase in average 7-7/8 inch bit ROP: from 45 ft/hr during the initial delineation program to 184 ft/hr on the most recent development well pad. Based on this demonstrated performance, the bit designs and cutter technologies have been transferred to other operations, showing that the application of this design approach provides practical means of maximizing efficiency. Introduction The Piceance Basin occupies approximately 7,11 square miles in western Colorado with Chevron s Skinner Ridge Field located on the western edge of the Basin (Figure 1). The topography of the Piceance Basin is characterized by a series of high plateaus and deep valleys 1, which creates two types of generalized drilling: valley and mesa drilling operations. The area is a hotbed of natural gas activity; rig count exceeded 1 rigs in late 28. High drilling activity drove up the overall cost of operations. Rocks of the Skinner Ridge Field consist of the Tertiary-age Green River and Wasatch Formations as well as the Upper Cretaceous Williams Fork and Iles Formations of the Mesaverde Group (Figure 2). A typical well consists of a 12-1/4 inch surface hole with 8-5/8 inch casing set at 1, ft measured depth (MD) within the upper portion of the Wasatch Formation. A 7-7/8 inch production hole is drilled to 6,-7,5 ft MD with 4-1/2 inch production casing set at total depth (TD). Lithologies in the upper half of the production hole section consist primarily of mudrock interbedded with lenses of fluvial sandstone. The lower half of the production hole section is comprised of the Williams Fork Formation and the Rollins Member of the Iles Formation. The Williams Fork consists of interbedded, non-marine sandstone, mudrock, and coal, while the Rollins Member consists of marine sandstone underlain by a tongue of the Mancos Shale. 2 All wells are directionally drilled with an S-shaped wellbore profile. Kick-off point ranges from 1-25 ft MD. For most wells, the build section is drilled in the surface hole with the tangent, drop and vertical portions of the well in the production hole interval. Vertical sections range from near-vertical to more than 2, ft displacement (Figure 3). Fortythree percent of the Skinner Ridge wells drilled fall within 1,-1,5 ft of vertical section with an average maximum wellbore inclination of 28 degrees. The primary target reservoirs are located within the Williams Fork and are stacked, highly discontinuous, fluvial sandstones occurring throughout an approximately 2,4-foot gross interval. 3 Referred to as tight sands due to their low permeability, Williams Fork sandstones contain gas trapped in lenses sealed by impermeable shale layers.

2 2 SPE PP Background Drilling has occurred at Chevron s Skinner Ridge Field intermittently since the 198s in both the valley and mesa areas. Delineation of the field was conducted in 24 and 25, which consisted of 13 wells spaced throughout the field to evaluate reservoir potential. Development of the field began in the summer of 27 with the arrival of two Helmerich and Payne (H&P) Flex 4S drilling rigs. Drilling focused on valley acreage. Flex 4S drilling rigs have substructure skidding capabilities that allow for up to 22 well slots to be drilled from a single pad without the need to relocate the auxiliary rig equipment such as mud tanks, mud pumps, etc. Another key component of Flex 4S drilling rigs is the advanced automatic drilling system. The automatic driller allows for control of weight on bit (WOB), instantaneous ROP, differential pressure and drilling torque. This precise control of drilling parameters diminishes WOB fluctuations, reduces bit chatter, extends bit life, minimizes drilling inefficiencies and optimizes the drilling process. 4 Multi-well pad drilling has enabled Chevron to take advantage of the benefits of batch drilling in which a series of hole sections (surface or production) can be drilled in sequential order. The main advantage of batch drilling originates with the operational improvements from performing repetitive tasks for the same hole interval. From a drill bit performance standpoint, batch drilling allows for multiple surface or production bits to be run in a short period of time, and lessons learned can be applied immediately. Project Goals Chevron s goals were to improve bit ROP, durability and steerability. Improving bit ROP was necessary to decrease drilling time and cost. An ideal bit design would need to be aggressive enough to maximize ROP thru the softer drilling of the long Wasatch Formation where unconfined compressive strength (UCS) averages approximately 6, psi, yet still be durable enough to drill the harder Williams Fork Formation, where UCS can exceed 19, psi with an average of approximately 1, psi. Drilling the entire production interval with one bit also was considered a priority in order to reduce non-productive time (NPT) for bit trips. Because of the S-shaped directional well profiles, achieving the stated goals would require a bit design that enabled good directional control through minimizing tool-face fluctuations and slide drilling. The Bit Program During the 13-well delineation program, several different 7-7/8 inch bit designs were run. Design characteristics typically included a 16mm cutter size on 4- or 5-bladed polycrystalline diamond compact (PDC) bits. With all 13 wells drilled as vertical wells requiring no directional control, effective ROP with these bits ranged from 29 to 65 ft/hr, with an average effective ROP of 45 ft/hr. Five of the wells required multiple bits to drill the production hole section. With the start of the development program, bit steerability became a design feature of fundamental importance due to the requirements of directionally drilling wellbores from a single multi-well pad. To date, nine such multi-well pads have been drilled, totaling 195 wells. Although other bit designs were periodically introduced, Halliburton Drill Bits and Services (HDBS) 5-bladed, 16mm cutter bit FMHX555ZM (555) and the 5-bladed, 19mm cutter bit FMHX565ZM (565) became the standard designs for Chevron s drilling operations. HDBS PDC bit types initially utilized by other Piceance Basin operators prior to Chevron s start-up, provided a baseline to the 555 and the 565 bits. These base bit designs were later modified extensively during the Skinner Ridge drilling program. Bit Design Process Bit optimization for Chevron s Skinner Ridge development consisted of a process that integrates planning, implementation and evaluation, and continually uses fewer and fewer design iterations to meet performance objectives. The development process of Design at the Customer Interface (DatCI ) was comprised of customer-directed application design engineering, detailed bit performance analyses and use of proprietary Direction by Design (DxD) bit design software to simulate new bit designs with different sets of recommendations for a faster and greater level of drilling optimization. Direction by Design Central to the DatCI service platform, DxD software was used for advanced bit design engineering to optimize directional performance for the specific drilling system used at Skinner Ridge. The program employs a new, more complete kinematics model that eliminates time-consuming trial and error bit design. 5 For a given bit under given drilling conditions, DxD determines the effects of bit geometry parameters on steerability and walk rate, and calculates bit torque variance during directional drilling to account for different bit behaviors

3 SPE PP 3 during kick-off, build and hold drilling modes. 6 Vital to the strategy of overall design optimization, this advanced capability means bit design and matched drilling system performance are optimized together. Using this process enabled a dedicated HDBS bit design engineer to work in close connection with Chevron personnel for fast design production, since innumerable new designs can be made and tested in the DxD software. In addition to expediting the design process, another advantage of having a dedicated bit designer locally in Grand Junction, Colorado, is the insight provided by area knowledge and experience. By bringing that insight together with direct customer input, each design was analyzed and refined in a process that ensured continuity as well as continuous improvement. Testing Ground The consistent nature of the Skinner Ridge operations created an ideal testing ground where use of the DatCI process could advance the performance objectives of substantially improving ROP and successfully drilling the 7-7/8 inch section in a single bit run. It was clear from the beginning that data consistency benefited the process tremendously. Maintaining geological constancy, standardizing operational parameters and equipment, and minimizing personnel attrition for a multi-rig operation can be difficult to manage. By maintaining operational regularity, efficiencies were duplicated in a short amount of time, accelerating the learning curve and development of best practices, creating a more efficient operation. The limited areal extent of the development program, a radius of less than 2.5 miles for all wells, allowed for geological uniformity. There is formation continuity in the Piceance Basin and, save for the occasional structural anomaly, the formations drilled were uniform for the data set. A standard drilling assembly design was employed throughout the development program that was made up of a slick bottom hole assembly (BHA) with a directional motor and measurement-while-drilling tool. In addition, Chevron standardized drilling parameter best practices both across rigs and amongst each drilling crew. A review of rotating/orienting on-bottom ROPs for each formation was analyzed, and each crew was provided a drilling road map specifying drilling parameters (WOB, top drive RPM, flow rate, ROP limits, etc.) to optimize drilling efficiency. This helped minimize variety in drilling performance between crews. Minimizing rig personnel turnover can have the largest impact to consistency. Drilling in the Rocky Mountain region and the Piceance Basin historically has been hindered by the fact that many drilling rig personnel live outside the state, which tends to result in higher crew turnover. In addition, due to the extremely high rig count, qualified workers were hard to locate and keep. Chevron was successful in creating a positive, safe work environment that resulted in very little crew attrition. Because of the consistency of the key drillsite personnel, drilling performance became repeatable. By standardizing the areas above, performance analysis between different bit designs was easier and more reliable. With this in mind, Chevron became a testing ground for new HDBS bit designs and technology. The testing ground approach provided a consistent data set of significant volume, by which fact-based decisions in design could be made with the confidence needed to meet performance goals. Bit Design Evolution An in-depth study was conducted to determine the influence of PDC bit profiles, blades counts, cutter sizes and types, versus lithology, mechanical properties and well deviation. Different sets of drilling parameters also were studied to evaluate their influence on ROP and bit wear. DxD software was used to quantify how changing bit features and dimensions would affect steerability, bit walk and bit face control for any given well trajectory and BHA. Summary of Design Iterations Three 7-7/8 inch bit designs went through a total 2 iterations over a two-year period, with the latest FMHX563ZM (563) bit design serving as the new benchmark. Each design revision was made in an effort to improve ROP through more aggressive design features; improve durability through use of specific materials and practices designed to keep cutters sharper longer; and improve steerability through optimized design parameters according to DxD. FMHX555ZM. The 7-7/8 inch 555, or Triple Nickel, is a 5-bladed design with 16mm cutters. Over the course of 14 design revisions, testing included multiple cutter types, material makeup and other features. In addition, three cutter edge preparations were tested, as well as Modified Diamond Reinforcement, designated the M feature. In terms of hydraulics optimization, variations included testing different nozzle placements for optimal cleaning and use of various matrix powder formulations in bit manufacture to combat bit body erosion which resulted from drilling with bit hydraulic horsepower in excess of 5. hhp/square inch (HSI). Figure 4 summarizes the performance improvements realized over the course of design iterations, as average onbottom ROP steadily improved from 12 ft/hr initially to 234 ft/hr by the final revision and average effective ROP improved from 85 ft/hr to 181 ft/hr.

4 4 SPE PP FMHX565ZM. While the Triple Nickel bit provided a base bit, efforts also focused on increasing on-bottom ROP with a more aggressive bit type. For that purpose, the 5-bladed 565 with bigger, 19mm cutters provided a base design. Like the Triple Nickel design, tests on the 565 included varying cutter type, matrix powder, edge preparation and use of the M feature over the course of five iterations. Used strictly in low inclination wells, the 565 design set on-bottom penetration rate records at the time, consistently topping 2 ft/hr average on-bottom ROP with each new revision. Performance is summarized in Figure 5. FMHX563ZM. The 563, created especially for the Skinner Ridge Project, was designed to further increase penetration rates over the 555 as well as improve steerability over the 565. A totally new and very aggressive bit design, the 5-bladed 563 with 19mm cutters combines what were considered ideal features from the 555 and 565 bits. Everything about this bit is different from the previous 565 design, including back rake, side rake, cutter count and cutter placement. The new 563 design had been run only three times and was on track to become the benchmark bit design when the drilling program ended sooner than expected. On-bottom ROP averaged 262 ft/hr as shown in Figure 4. This latest design has proven to be the most steerable of all HDBS designs utilized for the Chevron project, as shown in Figure 6, which illustrates the bit side forces required to steer the various bit components as calculated by DxD. Results Bit performance has shown continuous improvement throughout the development drilling program. Bit ROP has increased immensely, reducing drill time and setting several Piceance Basin effective ROP records. Durability has been reliable with fewer wells that require multiple bit runs to reach TD and with less cutter wear. ROP Improvement Figures 7 & 8 illustrate the pad-to-pad effective ROP for both drilling rigs including the delineation program data. Vast effective ROP improvements were made when comparing the last development pads with the delineation program. Rig #1 improved by 226%, and Rig #2 improved by 39%. Each rig also showed continuous pad-to-pad effective ROP improvement ranging from 4% to 44%. To compare Chevron s drilling performance with other Piceance Basin operators, valley 7-7/8 inch bit runs during the first half of 29 were taken into consideration. Table 1 illustrates the difference in effective ROP bit performance between Chevron and other operators. Chevron averaged 191% faster effective ROP and required fewer bits per well (1. bit runs/well versus 2.2 bit runs/well). During the course of the Skinner Ridge drilling program, numerous Piceance Basin effective ROP bit records were set, including the highest effective ROP drilled with a 7-7/8 inch for an entire production hole interval: In the SKR AV-17, 5,445 feet were drilled in 25 hours using the 555 bit at a record effective ROP of 218 ft/hr. The well had a maximum inclination of 36 degrees and 1,19 ft of vertical section. Rotary steerable directional drilling system technology was evaluated to improve drilling ROP. Eliminating sliding drilling would indeed improve overall ROP but only slightly. Figures 4 and 5 illustrate the impact of sliding drilling on the overall average on-bottom ROP. The average difference between on-bottom rotating ROP and overall on-bottom ROP is approximately 5% for the 555 and the 565 bits. The reason for the small delta is the fact that regardless of the directional profile of a well, on average, sliding drilling accounts for only 9% of the total footage. Therefore, the minimal time savings that would be realized by eliminating sliding drilling would not support the high cost of a rotary steerable system. Durability Durability is a component in achieving the performance objectives set forth at the beginning of the project. It was critical that the bits be durable enough to reach TD in one bit run to decrease NPT. Success rate of single bit runs to reach TD (excluding wells with multiple bit runs due to downhole tool failures, hole problems, etc.) improved from the delineation program through the development program. The delineation program had a 61.5% success rate. During the development phase a success rate greater than 93% was achieved. Dull Bit Grading. Dull bit grading is critical to closing the loop on the bit analysis process and is a direct measurement of bit durability. By understanding the failure mechanism, improvements can be made to the next design. An analysis of 12 runs for the 555 bit was completed to identify dull trends. The results are as follows: 64% had major dulls related to Worn Teeth/Cutters (WT) and Chipped Teeth/Cutters (CT). o WT 37% o CT 27% Of the 38 bit runs with WT as the major dull characteristic, 46% showed a dull location on the shoulder area of the bit.

5 SPE PP 5 Of the 28 bit runs with CT as the major dull characteristic, 89% had CT in 3 primary locations: o Shoulder 33% o Gauge 31% o Nose 25 % For all bit runs, over 9% showed an average cutter wear of two and below for both the inner and outer cutting structures. In addition, 8% of all bit runs graded a one or zero on the inner and outer cutting structures. Cutter wear was identified as the main dull characteristic for all bits runs averaging 1.2 degrees of inner row cuter wear and 1.8 degrees of cutter wear on the outer row. Better Hole Conditions The production section rotating hours have been reduced on average by 87 hours from the delineation program to the most recent development well pad. Reduced circulating time resulting from the reduction of rotating hours has several benefits: Improved wellbore hole conditions for tripping pipe and running casing (i.e. less washout zones and tight spots); Improved production casing cement jobs due to a more in-gauge wellbore; and Less inhibitive mud properties needed due to reducing openhole shale exposure time. Conclusions Exceptional improvement in the 7-7/8 inch bit ROP has been a big factor in the success of Chevron s Skinner Ridge Field project. Bit changes were made through a drilling optimization process that provided a continual cycle of in-depth planning, field implementation and post well evaluation, which directly resulted in the ROP improvement. Other factors that helped to improve ROP performance include: batch drilling, optimizing drilling parameters and improving connection, surveying and reaming efficiencies. As a result, drilling time for the production hole section has been reduced by more than half. This time improvement along with improved drill time in the surface hole section and other improvements made by Chevron helped to significantly reduce the average pad drilling days per well (Figure 9). As demonstrated by successful results documented in the paper, application of this bit selection and design approach provides a practical solution to today s challenges of maximizing efficiency in a tight market. To date, HDBS have taken the lessons learned from the cutter testing to other operators in the Piceance Basin as well as to other Basins, namely the Uintah Basin in Utah and the Williston Basin in North Dakota, where similar positive results are being realized. Nomenclature Effective ROP: total footage drilled divided by the total hours drilled as defined by the IADC Daily Drilling Report. On-Bottom ROP: total footage drilled divided by the total hours the bit was actually on bottom and rotating. This excludes such operations as survey time, connection time, etc. Bit Side Force: the force required to move the bit laterally. Side force is calculated at different components on the bit to measure its contribution to overall steerability. Degrees of Cutter Wear: measure of lost, worn and/or broken cutting structure on a linear scale of -8. Average Pad Drilling Days per Well: total time from picking up the bit to drill the first surface hole until releasing the rig after finishing the last production hole divided by the total number of wells on a pad. References 1. Topper, R., Spray, K., et.al., Groundwater Atlas of Colorado, Special Publication 53, Colorado Geological Survey, Division of Minerals and Geology, Department of Natural Resources, Denver, Colorado, Cole, R., and S.P. Cumella, 23, Stratigraphic architecture and reservoir characteristics of the Mesaverde Group, Southern Piceance Basin, Colorado, in K. M. Peterson, T.M. Olson, and D.S. Anderson, eds., Piceance Basin 23 Guidebook, Rocky Mountain Association of Geologists, p

6 6 SPE PP 3. Cumella, S.P. and D.B. Ostby, 23, Geology of the basin-centered gas accumulation, Piceance Basin, Colorado, in K. M. Peterson, T.M. Olson, and D.S. Anderson, eds., Piceance Basin 23 Guidebook, Rocky Mountain Association of Geologists, p Boyadejieff, G.,Murray, D., et.al., Design Considerations and Field Performance of an Automated Driller, paper SPE/IADC presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, Feb., Valdez, D. and Thomas, M., Front-End Engineering Eliminates Costly Trial-and-Error Directional Bit Design, World Oil, November, Pruitt, J. et al.: Software program offers predictive capability to optimize drilling, World Oil pp 77-85, April 22. Acknowledgments The authors wish to thank and acknowledge the contributions of the following individuals, Carl Rademacher, HDBS; Stan Gatlin, HDBS; Scott Nelson, HDBS; Chris Ewing, Halliburton-Sperry; Martin Leafstedt, Halliburton-Sperry; Tom Haas, Chevron; Marty Knauss, Chevron; Mike Winiesdorffer, Chevron.

7 SPE PP 7 Chevron and Offset Operators Bit Performance - First Half 29 Operator AVG Effective Bit Wells AVG Bit AVG Run ROP (ft/hr) Runs Drilled Runs/Well Length (ft) % ROP Chevron Rig # Chevron Rig # A % B % C % Table 1. Bit performance analysis for Chevron and offset operators. Figure 1. Piceance Basin Map

8 8 SPE PP Figure 2. Skinner Ridge Stratigraphic Column Figure 3. Spider plot displaying well vertical section. FMHX555ZM & FMHX563ZM Performance 3 25 AVG On Bottom ROP AVG Effective ROP AVG On Bottom Rotating ROP AVG On Bottom Sliding ROP 2 ROP (ft/hr) Figure 4. ROP performance for the 555 and 563 bits.

9 SPE PP AVG On Bottom ROP AVG Effective ROP AVG On Bottom Rotating ROP AVG On Bottom Sliding ROP FMHX565ZM Performance ROP (ft/hr) Figure 5. ROP performance for the 565 bit Direction By Design (DxD) Side Force (lbs) Side Force to Steer the Entire Bit Side Force to Steer Bit Gage Pad Side Force to Steers Cone Cutters Side Force to Steer Shoulder Cutters Side Force to Steer All Cutters Side Force to Steer Gage Cutters Figure 6. Forces required steering different bit designs as modeled by DxD.

10 1 SPE PP 2 Rig #1 AVG Effective ROP per Pad Effective ROP (ft/hr) % 44% 19% 4% 25 Delineation Pad # Figure 7. Rig #1 7-7/8 inch bit AVG effective ROP improvement. Effective ROP (ft/hr) Rig #2 AVG Effective ROP per Pad 11% 14% 31% 35% 82% Delineation Pad # Figure 8. Rig #2 7-7/8 inch bit AVG effective ROP improvement.

11 SPE PP % Rig 1 AVG Days per Well % Rig 2 AVG Days per Well % 1 44% Days/Well % 4% Days/Well % 11% 8% Figure 9. AVG Days per Well improvement.