IADC/SPE 119570

Step-Change Improvements with Wired-Pipe Telemetry Scott Allen, SPE, and Chris McCartney, SPE, Occidental Petroleum; Maximo Hernandez, SPE, and Michael Reeves, SPE, NOV IntelliServ; Azaad Baksh and Danial MacFarlane, Baker Hughes

Copyright 2009, SPE/IADC Drilling Conference and Exhibition This paper was prepared for presentation at the SPE/IADC Drilling Conference and Exhibition held in Amsterdam, The Netherlands, 1719 March 2009. This paper was selected for presentation by an SPE/IADC 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 or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors, 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 or the International Association of Drilling Contractors 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/IADC copyright.

Abstract This paper describes the rationale, justification and benefits associated with the deployment of wired-pipe telemetry drillstrings at Occidental of Elk Hills, Inc. (OEHI) in Kern County, California. Recent technological advances in Measurement While Drilling (MWD) systems, Logging While Drilling (LWD) systems, and wired-pipe telemetry systems have overcome historical data bandwidth issues enabling real-time acquisition of critical data streams. These data sets include: continuous annular pressure for equivalent circulating density (ECD) management; vibration diagnostics for drilling optimization; instantaneous downlink commands to Rotary Steerable Systems (RSS) that aide in eliminating secondary non-productive time (NPT) and enhancing directional control; and memory quality formation evaluation measurements to improve reservoir navigation and wellbore placement. With this new wealth of data, onsite drilling personnel, geoscientists, and office engineering staff are able to make real-time decisions that serve to enhance wellbore quality and reduce overall costs. Utilizing wired-pipe to its full potential has helped to deliver an average drilling time savings of 10%. Introduction The benefits of drilling dynamics and formation evaluation from MWD and LWD tools are well known. However, these systems are impacted by bandwidth limitations which restrict the amount of data that can be transmitted to surface in real time. Recent advances in technology have addressed this issue. At the OEHI asset, Oxy and the service providers worked together to evaluate the application and benefits of deploying wired-pipe transmitted data in a land based environment. The technology was tested in combination with multiple downhole LWD and RSS tools. The system was tested in both a 5-in. tubular/mud-based and a 4-in. tubular/foam-based environment. Benefits in the Use of Wired-Pipe Telemetry One of the major challenges in a fast rate of penetration (ROP) drilling environment is transmitting all the required data to surface in a timely manner. When mud-pulse telemetry or electromagnetic data transmission is used, a large amount of this data is stored in memory and downloaded after the tool is tripped out of the hole. The drawback to this system is the lag time in receiving and processing the downhole measurements on the surface. As downhole acquisition technology continues to advance, these measurements are requiring additional bandwidth. This reduces the data density of mud-pulse telemetry points transmitted to surface while drilling, thus, making real-time interpretations and decisions challenging. In order to make an interpretation from a full data set, the operators must wait for the bottomhole assembly (BHA) to be tripped out of the hole and the memory data to be downloaded.

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In contrast, wired-pipe telemetry systems provide a bandwidth more than 1,000 times greater than conventional mud-pulse or electromagnetic telemetry systems. Data rates typically achieved with mud-pulse telemetry systems range from 3 to 40 bits per second (bps). In addition, these systems are affected by noise introduced by mud pumps, signal loss due to depth, fluid properties, and/or fluid flow rate since flow is required for transmission. Electromagnetic telemetry data rates range from 3 to 20 bps and these tools are limited in the vertical drilling distance since the signal attenuates heavily in certain formations. Because wired-pipe has a bandwidth of ~57,600 bps, the MWD/LWD personnel on location are able to configure downhole tools to transmit all acquired data through the network at the fastest possible update rates. Transfer of information to the surface can be reliably achieved at a fixed high-speed real-time transmission without being affected by depth, formation resistivity, fluid properties or flow rates. Hence, the drilling progress is optimized regardless of logging and steering requirements. Full Telemetry Redundancy Within the wired-pipe telemetry configuration, the mud-pulse telemetry system serves as a backup should the wired-pipe system malfunction or fail. This redundancy ensures minimum data requirements are continually met and avoids NPT for equipment troubleshooting or repair. The wired-pipe network was fully operational for 87% of the time while it was being used at OEHI. The majority of the downtime experienced was due to learning curve related elements regarding pipe handling and installation resulting in damage to some of the components during the startup of the project. When the proper handling methods were used, the reliability of the system noticeably increased as shown in Fig. 1.

0

50

100

150

200

250

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17

Hou

rs (T

otal

wel

l hou

rs)

Well number

Time distribution per well

Telemetry not required

Actual Telemetry Hrs

Telemetry Down Hrs

NPT

5" String 4" String

Fig. 1Telemetry use and reliability. Minimum NPT even when wired-pipe telemetry is unavailable. High-Speed Bi-Directional Communication The wired-pipe telemetry network enables concurrent high-speed transmission of data between the downhole tools and surface equipment. Thus, the control of the BHA while running RSS or other advanced services that require surface control are enhanced (i.e; formation pressure testing and seismic while drilling). Since there are no restrictions to when commands are sent to the downhole tools, the fully bi-directional nature of wired-pipe telemetry reduces NPT while improving control of all tools. This is in contrast to the downlink transmission process using mud-pulse telemetry systems that require several minutes to send commands to downhole tools.

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The initial two (2) wells drilled with wired-pipe telemetry at OEHI realized a drilling time savings of 4 and 6.5 hours respectively (Fig. 2). These wells were drilled in 43.4 hours and 41.5 hours. A 10% time savings and reduced drilling costs significantly improved the project economics.

Well No. of

DownlinksDownlink Time and

Confirmation (hr:mm)

Time Saved

(hr:mm)

25 bps Mud-Pulse

Telemetry A 58 04:00 0 B 71 04:15 0 C 54 03:45 0

Wired-Pipe

Telemetry

1 50 N/A 04:02 2 72 N/A 06:24 3 62 N/A 04:00

Fig. 2Comparison of downlinking efficiency during the project (all the above wells were drilled in the same field). Wired-Pipe Telemetry Components & Handling The drillstring used for wired-pipe telemetry is similar to a conventional drillstring in functionality, handling, and specifications. The drillpipe is modified to accommodate an inductive coil in the secondary shoulders of the pin and box which allow for data transmission from one joint of drillpipe to the next. The coils at the end of each joint of pipe are connected via a high-strength, high-speed data transmission conductor cable embedded inside the tool joint that exits to the joint internal diameter at the connection upset. The conductor cable is under tension inside the pipe. Electrical continuity from the drillpipe to the BHA is achieved by using an interface sub; therefore, the system network allows bi-directional transmission to and from the downhole tools. Data boosters are embedded in pipe tool joints at ~1500 ft intervals (10-15 per well) to increase signal-to-noise ratio and ensure no data is lost. Also, the boosters are fitted with temperature and pressure sensors allowing for the ability to acquire measurements along the drillstring. On the surface, a data swivel mounted to the topdrive enables the extraction of data flow inside the drillpipe to the surface computers while the pipe is rotating. This system allows for full bi-directional communication at ~57,000 bps while drilling (Fig. 3). Tubular handling and care was of utmost importance since damage to connections could potentially harm the networking components. Proper training of rig personnel on double-shouldered connections was critical to the success of the project. Because tubular dimensions and specifications were the same as regular non-wired, double-shouldered connections, no additional safety hazards were identified with the use of the equipment involved.

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Telemetry PipeConveys the Telemetry Signal

DataLinkBoosts the Signal, Wellbore Measurements

Top Drive SwivelExtracts the Signal on the Rig

Interface SubConnects to MWD Tools

Fig. 3Wired-pipe telemetry network schematic (left) and topdrive swivel image (right). Memory Quality Data While Drilling Memory quality data is received on surface from the real-time wired-pipe transmissions. Due to the high data rate, it is possible to deliver most downhole measurements with full digital resolution to the surface in real time, which results in improved clarity of the downhole conditions and wellbore. The use of drilling dynamics measurements have greatly improved since shock and vibration data is available in real time. Shock and vibration can change rapidly and cause severe drillstring damage very quickly. The instantaneous peaks in the measurements would not be detected in real time with standard mud-pulse telemetry systems since the updates for those systems are much slower; therefore, this data would not be available to correct the condition. With high-frequency real-time drilling dynamics data, drilling parameters can be optimized and life expectancy of the bit and downhole tools increased. Identification of undesired vibration was clearly observed by the downhole vibration sensor data transmitted to surface. Below is a short example of four (4) instances showing the clarity of the data transmitted through the wired-pipe telemetry. In Fig. 4 and Fig. 5, the vibration during a connection is shown as it was acquired by the LWD tool and transmitted through wired-pipe. Fig. 4 shows a connection without any damaging vibration; whereas, Fig. 5 has large instantaneous vibration spikes and rotations per minute changes which could damage downhole tools. Fig. 6 represents the data acquisition from a mud-pulse telemetry vibration measurement system as a means of comparing the quality of data for downhole events. This additional data from the wired-pipe system allows for a much clearer image of the drilling dynamics, thus, optimizing drilling performance.

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Fig. 4Connection with no damaging vibration.

Fig. 5Connection with damaging vibration levels. Project engineers are able to adjust drilling parameters and practices to mitigate vibration.

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Fig. 6Comparison of wired-pipe to mud-pulse telemetry measurements. Another advantage of wired-pipe is pressure and ECD management in standard and underbalanced drilling environments. This data can be acquired while the pumps are off, which can ensure health, safety, environmental and NPT incidents are avoided and risk mitigation is improved. Fig. 7 through Fig. 10 shows the advantages of pressure management with wired-pipe. Improved ECD management is achieved by acting on real-time downhole parameters which are indiscernible from surface. Fig. 9 and Fig. 10 show the effects of mud temperature on the viscosity and density of the drilling fluid and the resulting change to ECD. When an operating ECD window is critical (i.e., lost circulation, formation damage, etc.), data from downhole tools can help to ensure the drilling parameters are maintained within the window guidelines.

Fig. 7Erratic ECD measurements are shown clearly when using wired-pipe telemetry.

These data tracks display the same data acquired with both wired-pipe (left) and mud-pulse (right)

These data tracks display the same data acquired with both mud-pulse (right) and wired-pipe (left)

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Fig. 8Flow-off pressure and ECD via wired-pipe. In the example below (Fig. 9), 2 hours of circulation time were required to bring the mud system to the drilling operating temperature.

Fig. 9Cold oil-based mud at start of run causes a higher ECD.

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Fig. 10Warm oil-based mud after a few hours causes lower ECD. The greatest benefit of using wired-pipe is the ability to transmit large data sets in real time while drilling. In general, data sent to surface through a mud-pulse telemetry system is limited by the system bandwidth; therefore, interpretation of the data is more difficult. This limitation is more evident when reservoir navigating operations are being used and proper placement of the wellbore is critical to a successful well. In this case, wired-pipe telemetry enabled the transmission of two (2) additional resistivity curves, an 8-sector gamma image, and all the drilling dynamics and pressure management information simultaneously at 5-second intervals. Case one (1) is a reservoir navigation application where 4,324 ft of reservoir interval was successfully drilled in a 24-hour period. This enabled the drilling and reservoir teams to stay within the productive zone. Fig. 11 is a comparison between the logging deliverables obtained with mud-pulse and wired-pipe systems. These examples of logs were used to steer the wellbore to an optimum location in the reservoir. Using wired-pipe allowed the interval to be drilled at a ROP greater than 300ft/hr. If a mud-pulse system was used, a slower ROP would have been required to achieve an adequate data density to optimize wellbore placement within the reservoir.

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Fig. 11Reservoir navigation data comparison between mud-pulse and wired-pipe telemetry. In addition to having these high-speed, real-time measurements on location, the data was transmitted via satellite link to all project team members. This data was viewed and processed by office personnel in real time allowing critical decisions to be made in a timely manner. Due to the significant volume of data, highly qualified and experienced personnel are needed to properly interpret the data. With data overload an issue, precautions need to be in place prior to the start of drilling operations. Downhole Tool Diagnostics With rig efficiency a high priority, the importance of effective root cause analysis of downhole tools remains critical. However, mud-pulse telemetry systems often cannot deliver the required data to accurately diagnose downhole problems or suspected tool failures. Many times, problems could be resolved prior to tripping out of the hole for a perceived tool failure if all the diagnostic data was available. This advanced troubleshooting and diagnostic system prevents NPT (i.e., trip for diagnostics/perceived tool failures). In one (1) case, personnel on location were able to successfully diagnose hole problems that caused directional control issues. If the information received from the downhole tools were not transmitted via the wired-pipe, a trip would have been required to resolve the issue. Instead, the additional diagnostics data received indicated the rotary steerable assembly was functioning correctly. By viewing raw sensor values, the personnel on location were able to determine that wellbore deterioration was the root cause of the steering difficulties; therefore, drilling parameters were adjusted and the BHA drilled to total depth without any further problems. There were several other instances where tool diagnostics were used to determine tool functionality or downhole problems; thus, unnecessary NPT was eliminated. Once again, qualified and experienced personnel are necessary to interpret and achieve these results. If any of these incidents had occurred with a typical mud-pulse telemetry system, a diagnostic downlink would be shorter and less detailed. Also, this could require up to two successful downlinks and a lengthy transmission of diagnostic data. There is an extremely high probability the BHA would have been pulled out of the hole to determine the problem in these situations.

Mud-pulse Data Wired-pipe Data

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Replacement for Wireline Applications Because the drilling ROP is much lower than the electric logging wireline trip speed, the data acquisition from the LWD tools is acquired at a higher density. Also, the data is less impacted by borehole deterioration and drilling fluid invasion as observed on wireline logs since wireline data is acquired long after the borehole is drilled. Foam Drilling Design and Applications A significant industry milestone was achieved during this project. This was the first time that a reservoir navigation operation utilized wired-pipe with foam as the drilling fluid (Fig. 12). Five (5) of the seventeen (17) wells analyzed were drilled with foam using 4-in. wired drillpipe and a 6-in. bit. The use of foam was critical for proper ECD and pore pressure management. Fig. 13 shows the BHA configuration as it was run. The use of wired-pipe mitigated and eliminated the typical issues encountered with mud-pulse telemetry in a foam drilling application. Namely, the lack of continuous data flow due to the absence of uniform density and flow rate of the drilling fluid. Typically, this results in erratic voltage input from the system power turbines which leads to the possibility of the downhole tools switching on/off as the well is drilled. The most important element in the execution of ECD management was the capability to monitor well pressures when foam flow was off. It is very important to manage the pressure surges generated when pumps are restarted after connections to avoid damage to the formation. Acquisition of measurements (i.e., annular pressures with the pump) is a challenging task for LWD service providers since downhole power is required. This problem was resolved by using a battery sub installed in the BHA. As the pumps were turned off for a connection, the battery sub provided power to transmit the required data. Once the connection was made, all measurements were transmitted as normal. This allowed the drilling engineers to monitor and control the pressure surges generated when the mud pumps were started. In addition, this system enabled the acquisition of directional surveys when the pumps were turned off during the connections.

Fig. 12Plot of the first log image acquired via wired-pipe telemetry while using foam drilling fluid.

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ITEM NO.

DESCRIPTION

12

Wired HWDP

11

1 Wired NMCSDP

10

Interface sub

9

Mod Stab

8

LWD

7

Mod Stab

6

Mod X/O Box-Box

5

Smart Battery

4

X/over Pin-Pin

3

6 1/2" Stabilizer

2

4 3/4" Mud Motor

1

6 3/4" PDC Bit Fig. 134 -in. BHA designed for foam drilling.

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Analysis of Mud Displacement with Foam Fig. 14 illustrates the need to monitor ECD and downhole pressure changes as drilling mud is being displaced with foam. This is particularly significant to avoid potential formation damage.

Fig. 14Change in pressure and ECD as water-based mud is displaced by foam.

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Tubular and Topdrive Hardware Development Fig. 15 and Fig. 16 show damage to the wired drillstring resulting from improper stabbing procedures. When severe pipe damage occurs at the pin or box end, there is a possibility that the inductive coil can malfunction. Having specialized wired-pipe personnel on site during drilling operations ensures damage will be minimized. When the 5-in. drillstring was moved to another drilling rig, a modification to the topdrive was required to accommodate the topdrive data swivel. This modification allowed for more space between the quill and the top of the grabber box in the top drive. A lead time of approximately 90 days was required to manufacture the parts necessary for the modification. This delay time was identified as the main challenge for changing the drillstring to other drilling rigs. The issue is being mitigated by proactive inventory buildup and proper pre-project planning.

Fig. 15Example of dropped stand damage. Fig. 16Example of severe stabbing damage. With the technological advance in downhole data transmission comes the need to improve other components of the drilling systems to achieve the full potential of wired-pipe technology. Enhancing the power of surface and downhole data processing hardware is needed to handle the increased data flow and increased memory is necessary to accommodate additional measurements. Plans are already in place to run other services using wired-pipe technology (i.e., electrical and density images, 3D caliper measurements) to support land-based drilling operations. These services combined with wired-pipe telemetry will be capable of delivering higher quality real-time data that cannot be achieved with mud-pulse telemetry. To accommodate the increase in data being transmitted, the next version of wired-pipe telemetry will achieve data transfer speeds of 1 million bits per second. Also, work is being conducted to develop a 350F high-temperature version of the system. Conclusions Improvements achieved in this project were: ECD management enhancements; vibration diagnostics for drilling optimization; instantaneous downlink commands to RSS; elimination of data linking related NPT; directional control improvements; and memory quality formation evaluation measurements which allowed for more effective reservoir navigation and wellbore placement. The learning curve associated with the implementation of the wired-pipe and downhole tool combination in real time does not represent a threat to the operations and the risk associated with its adoption is low. The total NPT was approximately 10 hours from the seventeen wells. Although avoidable through technology and process improvements, these initial imperfections do not represent a threat to the widespread implementation and the capability for exceptional reservoir placement. The technology combinations presented herein are still in an early implementation stage. Even so, drilling a well 10% faster demonstrates the advantages and potential of these technologies and techniques.

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Acknowledgements The authors would like to acknowledge the contributions of Carl Rhodes, Hal Owens, Brian Anderson, and Greg Howard, Occidental of Elk Hills and Arash Aghassi, Dave Taylor and Ross Lake, Baker Hughes INTEQ. References

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2. Jellison, M.J., Hall, D.R.: Intelligent Drill Pipe Creates the Drilling Network, paper SPE 80454 presented at the 2003 SPE Asia Pacific Oil and Gas Conference, Jakarta, Indonesia, September 9-11, 2003.

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