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SPE 166428

Closed Loop Automation of Downhole Weight on Bit Improves SlidingPerformance and Reduces Conservatism in Unconventional Horizontal WellDevelopmentTony Pink, SPE, NOV. William Koederitz, SPE, NOV. Alex Barrie, SPE, NOV. Dave Bert, SPE, Chesapeake,Darrel Overgaard, SPE, Chesapeake

Copyright 2013, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013.

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 beenreviewed 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, itsofficers, 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 toreproduce 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

Today, during the development of unconventionals, the lack of knowledge of the downhole dynamics environmentcreates a culture of conservatism where excessive safety margins need to be applied to prevent damage to therig equipment, drill bits, drill string and sensitive drilling tools. By using downhole data in real time, this risk can bereduced and drilling performance can be significantly improved.

This paper discusses the results of the latest field test program of an automated drilling system where directclosed loop control of machines performs drilling optimization tasks using high speed downhole data. Thedownhole data is measured by a downhole drilling dynamics sub and is then transmitted to the surface via wireddrill pipe. The downhole data is visualized and analyzed by a surface application. The surface application then

sends set points through a control interface to the rig’s pre-existing control system.

The paper focuses on two main areas. The first is the rate of penetration improvements that occurred, whilerotating, sliding, and sliding using an automated rocking application (Maidla and Haci 2004) and secondly, thepositive behavioral change that occurs when the downhole environment is fully understood.

These technologies bring significant benefit to our industry especially in the development of unconventionalassets where sliding becomes slow and more challenging the longer the horizontal. The results demonstrated thatthese technologies significantly improve sliding performance up to 100%, especially when combined with asurface top drive rocking technology. The high speed downhole drilling dynamics data allowed the driller and thecustomer representatives to maximize the performance of the rig without compromising safety or the reliability ofthe equipment.

Introduction

As worldwide oil and gas reserves become increasingly difficult to explore and produce, the challenge foroperators is how to access these reserves and to produce them in the shortest and most cost-effective way, thusmaximizing their returns and expanding their economic reserves. Automation of the well construction process hasthe potential to significantly reduce well construction costs by improving performance, increasing consistency andhelping fill the competency gap which exists across our industry today. In discussions with operators it wasdetermined that their expectation is automation must first deliver consistent performance and then consistentdelivery must become faster and more precise. This consistency enables operators to budget efficiently andoptimize their drilling fleet to develop their asset base.

Well optimization is an important process that all operators must perform in order to increase the efficiency of theiroperations from the early planning stage to the final production of the well. There is always a need to improve

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performance and reduce non-productive time (NPT). Process optimization of the whole well construction processhas a clear benefit for the future economics of both oil and gas projects.

The products and services currently offered within the industry do not link surface, downhole data and informationin an automated, intelligent way for real-time drilling optimization and other related operations in the wellconstruction process. The critical and expensive downhole equipment can be several miles from the rig floor,currently making it impossible to know, with any degree of accuracy, their behavior and the surrounding

conditions. Vibration, poor weight transfer and poor torque transfer typically reduce drilling performance by 40-50% (Pink et al. 2011). Additionally, harmful vibrations affect the life of the drill string, bottom hole assembly(BHA) components and surface equipment, which, in turn, can result in premature and catastrophic failures andcostly downtime. A great deal of effort is dedicated to understanding and attempting to mitigate this vibration, butin most cases the engineers do not have sufficient speed of data to understand what is occurring downhole; thusthere is a clear gap between downhole and surface data in real-time which hinders a holistic optimization solution.

Automation of surface equipment using surface data can produce significant improvements in ROP, but the datademonstrates that there is the potential for a significant jump in performance when the surface machine control isaugmented by high speed downhole data (Pink et al. 2011). In this paper we focus on automated closed loopcontrol using an application that automatically adjusts the surface weight on bit to maintain a desired downholeweight on bit. We look at the benefits of this system both from a stability standpoint and how having this highspeed drilling dynamics data influences the behavior pattern of those on the rig site.

Damaging downhole vibrations, such as stick-slip and bit whirl, are not always detectable at surface. Stick-slip isan extreme form of torsional vibration that occurs when the bit digs into the formation, causing it to stick, which inturn leads to drill string wind-up. Eventually the drill bit breaks free, overcoming the shearing force, and causingthe drill string rotation to go from zero to high instantaneous RPMs. Bit whirl is a form of lateral vibration thatcauses the bit to move off-center and roll around the wellbore. These are just two of the traditionally recognizedevents that can cause damage, not only to the bit, but also the other drill string components.

It should also be noted that, in many cases, other BHA components and the drill string can initiate such damagingevents. Although memory based multi-positional vibration subs have captured such events, the resulting analysisonly brings value to the subsequent wells if the well profile, design and parameters are similar to the benchmarkwell.

A downhole automated control system enables operators to react by changing drilling parameters in real-time,thus reducing the vibration and improving or optimizing the weight and torque parameters being applied to the bit.

Several SPE papers, including Roberts et al. (2005), have documented numerous cases when real timemeasurements downhole (provided by wire-line in a test environment) are different to those at surface.Furthermore, they also illustrated how drilling parameters may be modified to provide greater efficiency in realtime.

Project Description

In 2011 and early 2012 we ran two test projects to help further develop an automated drilling system. The firstproject was on a rig in western Oklahoma in Washita County. The second project was in the Marcellus formationin Pennsylvania. The objective on the first project was to make sure that the high speed drilling mechanics subwas capable of communicating data of sufficient speed and quality to directly control surface machines. We drilledthe 12 ¼ in. section from 4355 ft to 15750 ft, the well was predominantly vertical, and during drilling wetransmitted drilling dynamics data up through wired pipe at an average frequency of 87 Hz. That data was

gathered on the surface and analyzed to asses that the vibration data from the real-time sub matched that ofmemory data from the recorded mode tools. During this test well we proved that the data was of sufficient speedand accuracy for automated control. We also demonstrated that the system was sufficiently robust to work in ahigh vibration environment.

The second project was on the Patterson 260 drilling in the Marcellus in Pennsylvania. This was a single well witha tortuous well path (Fig. 1) including a nudge, a drop back to vertical, a build and hold section, a second verticalsection and then a curve and horizontal section. The objectives of this well were: firstly to test that the data was ofsufficient quality to automate machines while drilling a curve and lateral section; secondly the automateddownhole weight on bit controller was safe, stable and able to control the drawworks; and lastly improve thecustomer’s performance. The results of this well were: the first ever closed-loop control of surface equipmentusing high speed (greater than 50 Hz) data, we proved that the downhole weight on bit data was of sufficientquality to control machines in the vertical, curve and lateral and we proved that we could improve the on-bottom

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ROP using downhole weight on bit (DWOB). The downhole weight on bit data was transmitted up through wireddrill pipe to the surface acquisition system; it was then translated into engineering units and transferred to asoftware application, referred to as a downhole weight on bit controller or (DWOB controller). The interaction ofthe DWOB controller and the rig’s control system and machinery is discussed in more detail later in the paper.

Fig. 1—A three dimensional plot of the well trajectory, including dogleg severity. Blue and purple indicatelow dogleg severity, green medium, and yellow, red and orange high severity.

The third project, which is the main focus of this paper, was a six well project using the Patterson 259. Thesewells were drilled in eastern Ohio from October 2012 to February 2013. The field test project was designed, asmuch as possible, to be able to evaluate the impact of automated downhole weight on bit control on various

assemblies while drilling the curve and laterals of each well bore. It was decided between the automation teamand the customer that we would drill the first three wells using the automation system and conventionalassemblies and then we would drill the last three wells using the automation system and a rotary steerable tool.The first well of each set of three would have no involvement from the automation team in the drilling processother than the tools would be run and the data recorded in real-time. The second well of each set of three wouldinvolve humans using the high speed data to analyze performance and from that analysis the humans wouldprovide verbal recommendations for parameter recommendations to the customer. On the third well of each setthe high speed downhole weight on bit data would be used to directly control the surface machines and thehumans would provide parameter recommendation to minimize vibration and the Mechanical Specific Energy(Dupriest et al. 2005).

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System Description

The system components that make up the “automated well construction system” are visualized in (Fig. 2) andsome of the key components are described below.

Fig. 2—Automated well construct ion system.

Drilling Dynamics Sub

The tool (Fig. 3) is a state-of-the-art Drilling Dynamics Sub. It provides real-time and memory data of the followingparameters: Downhole WOB, Downhole Torque, Lateral/Angular Acceleration, Z (Axial) Acceleration, ExternalPressure, Temperature, and RPM. Whirl and stick-slip are currently under development. The tool is currentlyavailable in 6 ¾ in. tool size.

This data is extremely valuable to the drilling process and thecompany optimization group has already demonstratedconsistent performance improvements of 20-30% with occasional

improvements of 100%+ (Pink et al. 2011). The Drilling Dynamicssub is extremely compact, at 4 ft in length, which enables it to berun in both the BHA and the drill string.

Fig. 3— Downhole Drilling Dynamics Sub designed to runwith wired drill pipe.

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Wired Pipe

The wired pipe consists of a high speed wired drill pipe telemetry system, allowing bi-directional data flow along adrill string. The current state of wired drill pipe allows a 57.6 Kbps bi-directional data rate. It is also possible tomeasure temperature as well as borehole and annular pressures along the sring of pipe. Currently, bottom holeassembly (BHA) interfaces exist for communication with most of the major service providers.

The wired pipe platform is comprised of five main components which are listed below:

- The interface sub connects to the MWD/LWD and Rotary Steerable System (RSS) tools to allow bi-directionalcommunication of logs and commands.

- The wired pipe “Booster Subs” enhance the signal to improve the signal to noise ratio and improvescommunication efficiency between subs. First generation “Measurement Subs” positioned along the drill stringcurrently measure bore and annular pressure as well as electronics board temperature.

- The wired pipe “Broadband Network” is the heart of the system, allowing high reliability data transmissionthrough the drill pipe.

- The Top Drive swivel allows for data to be extracted to the surface system while the drill pipe rotates.

- The wired pipe network, in its current state, is capable of providing data at a sufficient telemetry speed (57 Kbps)to automate all parameters except the vibration data. To achieve a full high speed vibration related optimization, afuture state telemetry speed will be required.

Downhole Weight on Bit Control ler (DWOB controller)

The DWOB controller is a real-time supervisory control system which utilizes software and rig equipment todeliver a DWOB value desired by the driller. The system components are shown below (Fig. 4). The systemoperation and data flow is as follows:

Fig. 4— DWOB control ler system d iagram showing data flow.

High-speed surface measurements, autodriller operational data from surface sensors and the autodriller

are input to the Data Pre-Processor.

High-speed measurements of downhole WOB are made by a sensor in the bottom hole assembly,

transmitted to the surface via a drillstring network and are input to the Data Pre-Processor.

The Data Pre-Processor validates and statistically describes the high-speed surface and downhole data,

and generates a data frame on a fixed time interval.

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The Control Engine analyzes the contents of the data frame, and computes the required Surface WOB

(SWOB) set point to deliver the driller’s desired DWOB.

The autodriller receives the SWOB set point as a request, analyzes it in the context of its current

operational state and safety case, and makes a decision to implement the requested SWOB set point (or

not).

The logic used in the Control Engine uses an adaptive control technique. Since the autodriller controls multipleparameters besides SWOB (for example, it may also control ROP, Surface Drillstring Torque and Mud MotorDifferential Pressure), this logic must also include an awareness of autodriller behavior.

The DWOB controller operation resulted in significant performance improvements. The description of many ofthese improvements is qualitative due to the nature of the improvement; however, where possible quantitativeresults are presented in the results section below.

It should be noted that all of the high-speed surface and downhole data could be presented to the driller andhe/she could attempt to control DWOB by varying the SWOB set point of the autodriller. However, this is generallynot practical, for the following reasons:

The large volume of real-time data would require the driller’s complete attention.

The driller would have to continuously make decisions on SWOB set point values, input these values,

and monitor the resulting consequences. These decision times are of the order of every few seconds, at

most.

The driller has higher-priority demands on his/her time, such as managing the drilling process and the

safety of the crew.

Therefore, while the DWOB controller actions could be duplicated by the driller it is not practical to do so. Themost significant improvements observed in drilling performance came from the ability of the driller to drill the wellcloser to the maximum limits of the performance capabilities of the rig, drillstring, downhole tools and bit. This wasdue to the high level of confidence that the automated system, including the DWOB controller, provided the driller.The driller realized that the DWOB controller could drill more precisely than he/she could and that it could reactfast and accurately as the system approached the limits of desired performance. At the same time, the driller alsorealized that the DWOB controller was simply another tool which was at his/her disposal, so the driller added

additional value by selecting when and how to apply it. Over the duration of the project with feedback from theindividual drillers, the user interface (UI) was updated and developed to make control of the DWOB intuitive andeasy for a busy driller. The final design was as simple as an up/down arrow and a set point box. The driller couldtherefore set the desired DWOB and then tweak it up or down as so desired.

Other qualitative benefits seen were:

The directional drillers observed that while sliding with the DWOB controller they had better control of the

toolface orientation than if they slid with the SWOB or differential pressure. This difference in stability was

considerable and will be further improved when high speed directional data is transmitted up the wired

pipe and incorporated into the control system. On this project the directional data was being transmitted

by slow speed mud pulse and electromagnetic communication.

In rotary mode the DWOB controller was capable of providing very fine WOB control. The system was

capable of maintaining for significant periods of time a DWOB accuracy of plus or minus 1 Klb. The strain

gauges would measure the downhole change in WOB, transmit that data uphole into the DWOB controller

and transmit a command to the drawworks in a matter of milliseconds. The drawworks would then

decelerate or accelerate appropriately. An additional and noteworthy benefit was that by by using the

DWOB controller, the AC controlled drawworks never actually stopped moving while drilling on bottom.

This means that the drill sting stays in the dynamic mode and we don’t have to overcome static friction

after it becomes stationary. This phenomenon could have additional ROP benefits when sliding.

The DWOB controller was tested during the drilling of three directional wells on a six-well pad. These wells

included vertical, curve and long lateral sections; rotary drilling, sliding and “automated pipe rocking system”

operations were conducted on all three test wells. The DWOB controller successfully controlled DWOB while

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drilling under all conditions encountered in the three wells. Fig. 5 is an example of the DWOB controller

controlling the DWOB while rotary drilling. Notice that the DWOB controller is continuously varying the SWOB in

order to deliver the target DWOB value. This control was not affected by changes in top drive rotational speed, as

shown in the interval 14,470 ft to 14,490 ft. Notice the continuing DWOB control and the improvement in ROP

when the DWOB set point is increased starting at 14,505 ft. One could argue that the same ROP increase could

have been achieved by the driller raising the SWOB in the autodriller. However, the driller is unaware of the

varying difference between SWOB and DWOB, and notice also that at 14,504 ft the difference between SWOBand the driller’s SWOB set point increases. While the DWOB controller automatically compensated for both of

these effects, it is unlikely that the driller would have been able to constantly apply the optimum DWOB to get the

maximum ROP that the DWOB controller was able to achieve.

Fig. 5—DWOB contro ller controlling the DWOB while rotary dr illing.

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Fig. 6 below is provided as an example of the DWOB controller controlling DWOB while sliding. Notice that theDWOB value is following the changing DWOB set point, and that the ROP remains constant during this operation(which was desired for this slide).

Fig. 6—DWOB controll er contro lling the DWOB whi le sliding.

Fig. 7 shows the operation of the DWOB controller while running an “automated pipe rocking system”. The drillingstarted as a typical “automated pipe rocking system” operation. The DWOB control was turned on at 12,835 ft.The DWOB controller managed to raise the mean DWOB value to the desired DWOB set point and hold itconstant. This increased ROP by 22%, from 33.7 fph to 41.2 fph.

Fig. 7—The operation of the DWOB controller while running an “ automated pipe rocking system.”

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Once the directional driller realized the benefits and ease-of-use (i.e. no more trial-and-error SWOB set pointchanges) of the DWOB controller during sliding and automated pipe rocking system operations, he/she used the(DWOB controller) exclusively in all following operations, except for the few instances where the driller wantedprecise control of his/her own doing. It was rewarding to see that the drillers and directional drillers realized thevalue of DWOB controller as a tool and developed their own means of applying it where most effective.

Fig. 8—Advanced DWOB controller.

(Figure 8 above) is an example of where we used the the (DWOB Controller) to improve ROP. This interval wasthe end of the lateral and rotary drilling was effectively limited by the top drive being able to deliver only 17,000 ft-lbs of torque. The driller first attempted to maximize ROP by adjusting top drive rotational speed and various

autodriller set points to operate at the edge of the torque limit. The driller also tried drilling on the autodriller torquelimit. Neither of these methods produced good results. The erratic nature of the torque control from thesemethods resulted in either lower-than-maximum torque (hence lost ROP) or torque exceeding the limit (causingtop drive or mud motor to stall, wasting time). The following stand using the DWOB controller is shown on thisfigure. It was noticed at the start that the DWOB controller was holding the surface torque constant with itsconstant DWOB. At 14,505 ft, the driller started adjusting the DWOB set point to get the torque up close to the17,000 ft-lb limit, which resulted in precise torque control. This DWOB adjustment by the driller resulted in a 27%increase in ROP, from 105.9fph to 134.7fph.

The same capability to improve performance was repeated on the next stand. The same DWOB set point nowresulted in a lower torque and ROP. The driller again adjusted the DWOB set point to increase the torque up tothe available limit, and a corresponding increase in ROP occurred again.Results

The automated drilling system’s primary objective was to provide the best real-time drilling optimization possible

without giving up the aspect of safety of the equipment or personnel on the rig. A comparison in drilling stabilitywas performed, with comparison made between the rig autodriller holding the rate of penetration at a steady valueand the automated DWOB controller. The downhole characteristics of the DWOB controlller compared to thesimple autodriller in both the curve and lateral sections of the well were significantly more efficient and consistent.Downhole weight on bit fluctuations, with the autodriller on while drilling with a rotary steerable system fluctuatedanywhere from 28% to 226% of its average value in the curved section of the well. Once the DWOB controllerwas activated, these fluctuations subsided to a manageable 8% to 9% of its average value, yielding a 93%improvement in downhole weight on bit stability. When activated in the lateral section of the well, the DWOBcontroller managed to produce an 86% improvement in downhole weight on bit stability. This increased downholestability may be translated into increased efficiency of the overall drilling process. The long term benefits of thisdrilling stability will be investigated in future test wells. This improved weight on bit stability could have a majorimpact on bit durability.

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A similar test was also conducted using a bent motor assembly instead of a rotary steerable system. Drillinganalysis was conducted on this system in both rotating and sliding modes of operation. While rotating, thedownhole weight on bit in collaboration with the DWOB controller produced a 2% gain in axial stability. The bentmotor assembly with automated rocking and DWOB controller resulted in a stability increase of 25%. A primeexample of the system instability without DWOB CONTROLLER optimization can be seen below in Fig. 9. Theexcessive downhole weight on bit deviation pictured is due to the lack of real time downhole parameter

optimization. One additional benefit was observed that while slide drilling the downhole weight on bit control itallowed for very stable toolface control even while running with relatively high differential pressures.

Fig. 9--DWOB and ROP Instabi lit y, DWOB contro ller off.

Whilst we were observing the DWOB controller running on this project we noticed it enabled the machines toreact very quickly, in the hundreds of millisecond range, when there is a change in formation compentency. Thisallows you to have the ability to decelerate or accelerate the drillstring very quickly. This change in the drillstringspeed allows for very precise depth of cut control as small as 1 mm when drilling at an average speed of 200 ft/hr.If you compare these drilling results with differential pressure control then at 15,000 ft you will have anapproximate delay of 3-3.5 seconds with the corresponding depth of cut control of 10-12 mm. This level of depthof cut control significantly improves cutter durability and bits are capable of being designed with more agrgressiveprovides and deliver faster, longer runs.

ROP Improvement

Rate of Penetration values were also obtained on both bent motor and rotary steerable system runs. When pairedwith the rotary steerable system, the DWOC experienced stable and reliable performance 24 hours per day,

showcasing its robust design and operational value. While drilling with the rotary steerable system in the curvedsection of the well, the DWOC actively increased the ROP drilling stability by an average of 93%, thus leading to amore efficient drilling process. When used in the lateral well section, a similar increase of 86% was seen.

When drilling with a bent motor system and an automated rocking application, the ROP standard deviation wasdecreased from 16.6 to 12.1, for an average stability increase of 27% (Note that this ROP average was limited byfield experimentation parameters. These results, although accurate, are not all inclusive and may be hindered bythis limitation). The ROP increased an average of 23% when the bent motor was used in rotation. A graphicaldepiction of the stability that resulted from the activation of the DWOC on a bent motor with an automated rockingapplication in the lateral well section is portrayed in the following charts:

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Fig. 10.—DWOB and ROP stability w ith the DWOB control ler but no automated rock ing application.

Fig. 11 shows a graphical depiction of the stability that resulted from the activation of the DWOB controller on abent motor while rotating in the lateral well section. ROP experienced an increase in magnitude and decrease indeviation, while DWOB variance was mitigated.

Fig. 11—DWOB and ROP stability while rotating, the DWOB controller on.

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The comparison, Fig. 12 shows the effects of the DWOB controller on a rotary steerable system. The yellowshading indicates the time when the DWOB controller is on. This minimally filtered data set is featured todemonstrate that upon activation, the DWOB controller optimization algorithms determined that a decrease insurface weight on bit and downhole weight on bit, while seemingly ineffectual, was in fact optimal. These changesresulted in a steady increase in ROP, as indicated below by the arrow.

Fig. 12.—The (DWOB contro ller,) DWOB and ROP stability.

VIBRATION MITIGATION

When looking at drilling optimization and safety, vibrational feedback control is crucial for the safety of equipment.The automated drilling system provides real-time vibration control via a controlled torque monitoring system.When the system senses excessive feedback torque spikes (otherwise known as stick-slip) under certain drillstring conditions, it will automatically create a log of the risky drilling criteria and run a series of optimizationalgorithms to mitigate and avoid these areas of risk. In the same series of rotary steerable tests, a decrease intorsional vibration from 20% to 14% was measured when the DWOB controller was enabled. Fig/ 13 shows theresulting data feedback when the DWOB controller transitioned from a state of active optimization (ON, withautodriller limitations) to disabled, allowing the autodriller to control the drilling parameters without intervention.

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Fig. 13—DWOB ctonroller stabilit y comparison without an automatic rock ing sys tem

Both value sets were recorded with a steady rate of penetration value of 60 feet per hour, serving as the testingcontrolled variable. The largest benefit that the DWOB controller provided was in collaboration with a bent motorin rotation, where a 30% decrease in torsional vibration was experienced.

The high speed downhole data allowed the customer to push conservative safety margins by demonstrating thatthe downhole environment was stable. At one stage in the operation we were seeing stick-slip oscillations in therange of 0-220 RPM while the surface RPM was a constant 60 RPM. When the surface RPM was increased to 80RPM the stick-slip disappeared and we had a stable 80 RPM both at the surface and downhole, this stable 80RPM was much less destructive to drill string components and meant that more energy could be transferred to thebit to cut the formation. Another example: at aroung 2000 ft out into the horizontal section and before we haddeployed the automated rocking system we made a slide to correct the trajectory. At one stage in that slide we

had a surface WOB of 128 K while maintaining 20 K at the bit and sliding at 40-60 ft/hr. Without downholemeasurements it would have been unlikely that anyone would have drilled with 128 K of compression in the string.The high speed data and automated control allows rig personnel and the customer to understand the downholeenvironment and push the limits without excessive safety margins.

Future work

We proved the data was of sufficient speed to directly control surface machines without human intervention. Thisopens up a whole new arena of drilling applications and has demonstrated that if we combine high speed WOBcontrol with high speed Direction and Inclination (D&I) data we should be able to build an application that providesautomated directional steering capabilities while sliding with motors.

Further study is required on the impact of stability on drill bit performance and durability but the impact of the

DWOB controller could be significant, particularly in hard rocks.

DWOBCONTROLLERON

DWOBCONTROLLEROFF

DWOB Mean

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Conclusions

1. The automated downhole weight on bit controller (DWOB controller) delivered significant improvements indownhole stability.

In the Curve:

• When the DWOB controller is off, the DWOB fluctuated 28% - 226%• When the DWOB controller is on, the DWOB fluctuated 8% - 9%• The benefit was a 93% improvement in DWOB stability

In the Lateral:

• When the (DWOB controller) is off, the DWOB fluctuated 46% - 100%• When the (DWOB controller) is on, the DWOB fluctuated 7% - 13%• The benefit was an 86% improvement in DWOB stability.2. The automated DWOB controller delivered stable 24 hour control3. The automated DWOB controller improved performance in rotary and sliding modes, and performance was

even further enhanced when the technology was combined with an automated rocking system.4. Automated downhole weight on bit control reduces the use of conservative safety margins because the

downhole environment is truly undertood and the system can be pushed to its correct limits.5. We proved the data was of sufficient speed to directly control surface machines without human intervention.

Drilling with downhole weight on bit provided a much finer depth of cut control and a faster control loop forsurface machine automation.

6. To enable the driller to react appropriately with the application the user interface needs to be intuitive andsimple.

7. The high speed downhole weight on bit control delivered consistent performance on the curve and lateralsections with all three motor wells coming in within six hours of each other when normalized for depth.

References

Dupriest, F.E., and Koederitz, W.L. 2005. Maximizing Drill Rates with Real-Time Surveillance of MechanicalSpecific Energy. SPE/IADC 92194.

Maidla, E. and Haci, M. 2004. Understanding Torque: The Key to Slide-Drilling Directional Wells. SPE/IADC87162.

Pink, T., Harrell, L., Perez, D., Carrico. J., Mackinnon, P. 2011. Integrated Drilling Optimization and DownholeDrilling Dynamics Enables PDC Bits to Drill in the Colorado Region of the San Juan Unconventional Gas Basin.SPE/IADC 139848.

Roberts, T.S., Schen, A.E., Wise,J.L., 2005. Optimization of PDC Drill Bit Performance Utilizing High-Speed,Real-Time Downhole Data Acquired Under a Cooperative Research and Development Agreement. SPE/IADC91782.

Abbreviations

.SWOB, surface weight on bitDWOB, downhole weight on bitDWOB controller, downhole weight on bit controllerMSE, mechanical specific energyKLB, kilo poundSP, set pointNPT, non-productive time

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