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SPE-158245-PPElectromagnetic Measurements While Drilling: A Telemetry Solution for Casing While DrillingM Zarir Musa, Dian Semesta Bt Abdul Aziz, Heru Hermawan and Trigunadi Budi Setiawan, Petronas, Ilen Kardani, Mohd Azlan Shah Askar Ali, and Rosli Sidek, HalliburtonCopyright 2012, Society of Petroleum EngineersThis paper was prepared for presentation at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Perth, Australia, 22–24 October 2012.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.AbstractCasing-while-drilling (CWD) operations have become a well-known technology used to minimize drilling time and reduce the AFE budget. A major oil and gas company has drilled several wells in Malaysia by using this technology, which has proven to be a cost-efficient strategy, particularly in the batch drilling process.Past CWD operational experiences have demonstrated stark differences when compared to conventional drilling in terms of wellbore surveying and formation evaluation. Weak and noisy signals from mud-pulse telemetry specific to the CWD environment were primary issues that required a significant amount of rig time when acquiring measurement-while-drilling (MWD) and logging-while-drilling (LWD) data.In fact, several significant challenges were encountered. First, the mud-pulse signal, which traverses from downhole (MWD) to the surface, somehow dampened out. Although various types of mud-pulse telemetry systems have been used, significant problems remain. In addition, the signal transmission worsened when seawater was used as the drilling fluid, resulting in non-productive time owing to the provisioning of change-out tools with different configurations for mitigation and trial-and-error purposes. Finally, overall drilling efficiency was reduced as a result of poor signal detection and capturing.Electromagnetic (EM)-MWD used in combination with gyro-while-drilling (GWD) was identified for implementation when drilling four wells using Tesco CWD technology in the Erb West field. The mud-pulse and electromagnetic telemetry systems were executed as a pair to compare captured signal strengths in the same environment (i.e., directional CWD with seawater drilling fluid).After drilling ceased, the generated results proved that EM-MWD is a viable technology that can be used to overcome signal attenuation issues in a CWD operation. Most importantly, such application reduced rig time by 3.9 days, which contributed to 26% of the cost saving for the surface section drilling by having trouble-free MWD signal detection and faster drilling operation. It also minimized health, safety, and environment (HSE) risks by reducing the time spent on rig activities, as well as established a working model of EM-MWD-CWD.IntroductionThe Erb West field is situated offshore of Borneo, about 80 km to the northwest of Kota Kinabalu, the state capital of Sabah, East Malaysia (Fig. 1). The field is operated by a major oil and gas company in Carigali Sdn. Bhd. as a subsidiary of Petroliam Nasional Berhad. The Erb West general structure consists of a domal NE-SW trending anticline divided in four fault blocks by three major east-west trending faults.The main prospective sequences, the N sands containing the main part of the oil reserves, are deposited in a shallow marine environment in the Middle Miocene. The intercalation of the sand and shales is clearly visible on the log shown in Fig. 2. The shales separating the sands are generally continuous field-wide. As of 2012, a total of 48 wells have been drilled, inclusive of the latest revisit program rolled out at EWDP-B.Project ChallengesIn developing brown fields, the most common challenge is the selection of a cost-effective and low-risk technology. Therefore, the main objective given was to significantly improve total field production while minimizing the drilling budget use without jeopardizing HSE and wellbore quality.2 SPE-158245-PPSome aspects that influence and lower drilling costs are listed below:1.Optimize drilling ROP: high-drilling ROP should be supported by a good hole-cleaning practice, minimizingstationary pipe, ensuring fast connection times, and avoiding cuttings settling.2.Minimize survey time: minimize the survey period via tool deployment that eliminates idling during survey executionfrom mud-pulse MWD.The following lists the typical problems that occured in the previous drilling campaigns:1. Stuck Pipe. There have been some cases where the drillpipe and casing became stuck at shallow depths owing toformation stability. Despite depletion of zones, there were no major differential wall-sticking problems duringprevious campaigns.2. Accidental Sidetrack. Owing to soft formation at shallow depths, sidetracking was a real risk when opening pilotholes. There were some notable sidetracking incidents while opening the 8-1/2–in. pilot hole to 17 1/2 in.3. Damaged Drilling Bit. Several bit trips were required because of premature wearout before reaching the targeteddepth. Shale inter-bedded with limestone stringer formation was the main factor that substantially reduced bitendurance.4. Washout. This problem was noticeable during the early Erb West drilling campaign in the deeper section of mostwells.5. Hole Stability. Shallow, soft formations have resulted in hole packoffs and stuck drillpipe and casing.Based on these factors, the CWD technology was identified as a key enabler solution for the latest drilling campaign.Ultimately, its application proved to reduce rig time, avoid NPT related to wellbore stability, eliminate the need for drillingmud in the top hole by using seawater instead, reduce the total AFE budget, and guarantee that the casing would be set at thedrilled depth.However, previous experiences of CWD applications within the company had demonstrated some issues pertaining to toolreliability and operational difficulties. Mud pulse generated from the MWD tool suffered from excessive noise, as well as lowsignal strength. Occasionally, the time to take a survey was long as 20 minutes because the limitation on mud pulse as a signalstrength will become weak in CWD because casing ID is larger than the drill pipe ID in normal drilling operations. This hadexposed the drilling operation to the potential risk of a stuck-pipe event and several other issues associated with the pipe beingstationary.Consequently, the number of surveys had to be reduced as a result of the inability to rectify and demodulate the signal atsurface system. The lack of survey measurements taken had introduced less directional control and increased the uncertainty ofwellbore positioning. Directional drillers could not steer the well to the planned well trajectory if the toolface data required tonavigate the well was not available. This signal detection problem was compounded if seawater was used as a drilling fluid.A significant amount of NPT was incurred to rectify the problems related to MWD signal decay during CWD operationeither by changing out the BHA or reconfiguring the setting while the BHA remained in hole. On a separate case from anotherproject, similar MWD signal problems led the company to abandon CWD operations and switch to conventional drilling. Thisevent hampered the team’s initiative to cut down the flat time of the drilling curve.The number of operational adversities led to a collaborative decision from the operator and services companies to deploycasing-while-drilling technology with the use of EM-MWD. This combination of technologies was propounded to meet thecriteria to improve drilling ROP while minimizing idle time while taking the survey. Another advantage of EM-MWD was forthe directional driller to use the toolface reading while the pump is off or during the connection time; thus, less time is wastedin adjusting the toolface prior to initiating steering.Engineering Design and PlanningWith EM-MWD, an electromagnetic signal was transmitted by the propagation of electromagnetic waves through theformation with the drillstring and casing acting as a wave guide. The MWD tool created the electromagnetic wave by creatinga current through a differential of potential at the level of the emitting sub. The current was transmitted into the formationthrough the annulus, and the EM wave then propagated through the formation. The signal was captured on the surface betweentwo antennas; one was connected to the BOP, and the second antenna was connected via the earthed stake in the ground foronshore or an anchor on the seabed for offshore (Fig. 3).Pre-modeling was done for both conventional drilling with a drillpipe and CWD to check on the estimated signal strengthand depth range; the model showed that signal strength for CWD was higher than for conventional drilling. The model alsoshowed that tool was capable of emitting sufficient electromagnetic energy to overcome the attenuation resulting from theformations in the field.There are three main components of EM-MWD, including the Upper Sleeve, Insulated Annular Gap, and Lower Mandrel.The insulated “gap” is created by a ceramic, annular coating that electrically isolates the upper sleeve from the lower mandrelSPE-158245-PP 3 after they were mechanically shrunk together to form the antenna collar. This tool has dual functions as both transmitter andreceiver (Fig. 4).The surface system connected to a remote antenna, or a cluster of antennas, consists of a computer, signal processor, andamplifier (Fig. 5). The downhole components vary by the MWD services required by the core of the EM-MWD system in theEM probe itself. The EM-MWD probe received and relayed commands from the surface. It also gathered and sent data to thesurface based on operator-set parameters. The drillpipe acted as a dipole antenna for the EM signal to be carried to and fromthe downhole tool. A repeater may be used in areas of high-signal attenuation or at extended depths.EM-MWD does not have any moving parts compared to the mud-pulse telemetry, which contained pulser and/or turbineparts to give almost no limitation for the LCM to be pumped through EM-MWD (Fig. 6). This robust design had placed EM-MWD at a higher level of reliability compared to the mud-pulse telemetry. As for transmission speed, EM-MWD can providerates 3 to 4 times greater than mud-pulse telemetry during CWD operations. This transmission rate can be adjusted whiledrilling by downlinking the process to optimize the signal strength and surface demodulation.Signal propagation is dependent on the nature (resistivity) of the formation traversed by electromagnetic waves on thefrequency of the waves carrying the information. A limitation in the application of the electromagnetic telemetry systemresulting from the depth and lithology has traditionally been overcome through the implementation of a signal repeater(booster).A detailed engineering study was performed from the Job Safety Analysis, Risk Assessment, and breakdown to a step-by-step set of operations. Tool, procedures, and personnel planning were discussed and documented for future reference, as it wasthe first EM-MWD offshore operations in Malaysia. Setting up the equipment offshore, such as installing the antennas,mounting receivers, making up the BHA, and downlinking process, were explained in detail to all parties. Numerous meetingswere conducted in the office, workshop base, and at the rig site to help ensure that the job was done safely and efficiently.Gyro while drilling (GWD) was used in this project to anticipate the anti-collision issues with other producing wells fromthe same platform. As this was a first-time application for PCSB, mud-pulse MWD was also executed as a pair with EM-MWD for quality assurance and to compare both tools in the same environment. This additional precaution providedsecondary measures against any unplanned trip in the event of failure, as the drilling progress was highly critical for CWD.There would be no interference between EM-MWD against mud-pulse MWD, as both were working in different methods eventhough run in tandem.BHA modeling for CWD was significantly different compared to conventional BHA owing to the nature of CWD that gavea higher friction factor that contributed to the torque and drag value. The hoisting system and Top Drive System (TDS) of therig were evaluated to ensure that the rig could handle the load and torque while drilling. The design limit was the maximumtorque on surface that the casing connection could still handle, as well as the available power from the TDS to transfer thetorque through Casing Drive System (CDS).Operations Results/ExecutionA basket test of all the BHA components was carried out at the base onshore prior to mobilizing the tools to the rig, whichensured the compatibility for both hardware and software for each of the tools (Fig. 7). Communications from each BHAcomponent, EM-MWD mud-pulse MWD-GWD-Resistivity-GR-PWD, were tested and successfully met the standardrequirement.Rigging up the surface equipment was done offline. The most suitable and safest location to deploy the EM winches andsubsea antenna were at the poop deck, starboard side, which would not obstruct the rig operation (Fig. 8). Making up the EM-MWD with the rest of the CWD BHA components took another 3–4 hours, including the surface test. Two antennas and onereceiver were installed and tested, and all processes performed flawlessly.EM-MWD gave 90% continuous detection throughout the run compared to the mud-pulse telemetry, which gave only 40%detection. Looking back at the pre-job modeling, the strength of the signal from the actual operation showed more attenuationas a result of the casing extinction effect. The detection comparison for each well is shown in Fig. 9.With the survey program calling for a borehole survey for every casing joint drilled, a significant time savings wasrecorded owing to the ability of the EM-MWD to transmit data back to surface independent from the rig operations, flow rates,and fluid properties. A survey was taken and transmitted while adding a new joint of casing. The toolface was continuouslytransmitted to surface, thus allowing the directional driller to resume drilling ahead right after connection without waiting for asurvey, as was previously done with mud-pulse MWD. In addition, the directional driller can use the flow rate as they like tooptimize dogleg output of the BHA without any risks of losing MWD survey or LWD data. Because of its attribute of non-mud-based telemetry, it is acceptable by the team plan to use seawater in the surface hole-casing drilling operation.Another advantage of EM-MWD technology with transmission through the casing is the ability to monitor annuluspressure while the pump is off, thus allowing the detection of fluid level in case of any changes in the hydrostatic pressure.The driller can, therefore, act quickly should there be any indication of mud loss or influx while tripping in or out.Three wells were successfully drilled with EM-MWD – CWD technology in the Erb West project, saving a significantamount of rig time and AFE budget. The forth well was drilled conventionally after the team decided to drop the CWD option.A breakdown of the comparison between the conventional operation and EM-MWD – CWD drilling is shown in Table 1. Arange of drilling parameters applied during the operation is shown in Table 2.4 SPE-158245-PPTime Saving for the Entire CWD – EM-MWD in the Erb West Project for Three WellsSurvey time:17 hrs (EM-MWD taking survey during connection)Tool face orientation:4.9 hrs (EM-MWD transmitting toolface during connection)Avoid potential trips:20–24 hrs per well (Mud pulse would likely change out the configuration as getting deeper, which is not the case for EM-MWD)Faster Drilling ROP: 40–45 hrs per well with average of ROP 70 ft/hr compared to the potential slower ROP 30 ft/hrwith mud pulse only.TABLE 1: COMPARISON ON SURVEY TIME BETWEEN EM AND MUD-PULSE TELEMETRY.TABLE 2: DRILLING PARAMETER COMPARISON BETWEEN CWD VS. CONVENTIONAL TO DRILL 17-1/2-IN. SECTION.Drilling Parameter Conventional EW-216 CWD EW-214 CWD EW-215 CWDEW-217 Measured Depth @ TD, ft 3,630 1,849 2,058 1836Footage, ft 3,144 1,362 1,554 1317WOB, kips 20 10 15–20 5GPM 700–1,000 600–1,000 600–1,000 600–1,000RPM (*Casing during orienting)160 20* 30* 40*TFA, in.2 1.084 1.29 1.09 1.74HSI 1.9 1.4 1.9 0.8ROP, Avg ft/hr 70 68 70 200Torque, klbs-ft @ TD 9 17 20 20Drilling Duration 8 days 3.33 days 5.79 days 1.76 daysProject Highlights.1. Zero LTI and zero environmental incidents throughout the CWD operation.2. No downtime caused by EM-MWD telemetry tools.3. Deepest offshore EM run globally at EW-216 recorded depth of 2,578 ft MD.4. No interruption of detection during lost circulation.5. Four wells were drilled by using EM-MWD, three with CWD, and one well with conventional drilling. Comparisonshows EM-MWD having a 90% continuous detection throughout the run, while positive pulse MWD had only 40%.6. Quicker learning curve from the rig crew and MWD crew on the setup, considering the first-time application inoffshore Malaysia in the newly-built rig.Well Total Survey EM SurveyDurationMWD Survey Duration EM Toolface Duration MWD Toolface Duration 18 1 3 minutes per survey EW 21449 0.8 6.5 0.8 2.5 EW 21533 0.4 3.6 0.4 1.3 EW 21713 0.1 0.8 0.1 0.3 EW 216 37 0.10.5 0.1 0.2 2.4 19.4 2.4 7.3 Survey difference(hours) 17 Tool face difference (hours)4.9 Total Saving Time (hours)21.9SPE-158245-PP 5 EM Challenges and In-field MitigationBecause of the fact that this was the first field trial of EM-MWD in an offshore environment, the team had to face someoperational challenges, which were also part of the learning curve in understanding the performance and behavior of thesystem in offshore applications. Listed below are the challenges observed during the entire operation.Casing Extinctions Effect. EM-MWD was susceptible to the casing-extinction effect, whereby signal strength droppedsignificantly when the tools transmitted the data inside casing. In the Erb West operation, the team experienced total loss ofreal-time EM signal. This was more severe compared to the EM offshore experience. As a mitigation step and counter measurein the field, the team had spent some time capturing the survey slowly and verified the toolface with the rig silent environmentprior to drilling ahead until the EM tool was outside the casing.Poor Signal Detection. When drilling with CWD at EW-214, the team had encountered poor EM-MWD signal detection. Itwas also noticed that the level of background drilling noise was very high, specific to that well only, and not seen during EW-217, EW-215, and EW-216. The problem was solved by relocating the antenna at BOP to the adjacent conductor, where agood signal was regained.Rig Noise. Throughout the operation, rig noise was identified as the Achilles’ heel to the EM telemetry performance. It posedadverse effects mostly as a result of the electrical noise over the duration of the project. Post mortem of the operation showedthat the source of the noise came from welding activities as well as from Top Drive noise during the connection. As withmitigation, welding activities on the platform were suspended while drilling activities were ongoing. In addition, the surveytiming sequence was also reconfigured to avoid noise spike during connection.Future Recommendations1.The casing-extinction effect is expected, but severity is more compared to EM onshore operations.To mitigate thecasing-extinction effect, it is suggested to do the following:a.BHA Planning: Place the antenna sub closer to the bit.b.Well planning considerations: Allow for rotating the BHA out of the casing.c.Run the mud-pulse tool on top to obtain TF inside the casing.d.Modify the survey list to improve survey time in the casing.It is recommended that the EM engineering and design team would offer more powerful downhole amplifiers to boostthe signal strength to surface.2. A parted subsea antenna cable was experienced while retrieving back to the rig, so it is recommended to identify andforecast the sea current to know the safe window for retrieving the seabed antenna.3.As the project also used GWD in tandem with MWD, there is a potential survey time improvement that can beimplemented in the future. Some of the future proposals would be to eliminate the duplication of MWD and GWDsurveys on the same list. Furthermore, the survey time can be minimized by modifying the GWD sequence so that thesurvey can be taken immediately to eliminate the 3 minutes waiting period, as practiced in the project.ConclusionThe EM-MWD and LWD system effectively transmitted downhole measurements data while drilling a directional well withcasing. The company identified many advantages for implementing EM-MWD technology for both drilling and sub-surfacerequirements. This success eliminated the problems of providing downhole measurements with casing-while-drillingoperations, which occured in the past. The success also proved that EM telemetry is a better alternative to mud-pulse telemetryfor offshore CWD operations, and, above all, it translates to a 26% of cost savings for the surface section drilling by havingtrouble-free MWD signal detection and faster drilling operations.Continuous data transmission throughout the operations has improved drilling efficiency tremendously, as well as wellborequality. Fast data transmission helped the DDs to steer the well in a smoother trajectory and in a minimum stationary time forconnection, minimizing the risks of getting stuck. Survey and formation evaluation data were available anytime on demandwithout waiting for the pump to recycle or after connection.Now, operators and CWD companies have the EM-MWD option to meet their objectives and drill in the safest and mostefficient manner. This technology was proven to be robust and independent of the downhole noise, which might come fromdrilling tools, downhole vibration, or surface systems. This value has been proven in theErb West project for the company’soperations in Malaysia.6 SPE-158245-PP ReferencesCuauro, A. Ali, M.I., Jadid, M.B., Kasap, E., and Friedel, T. 2006. An Approach for Production Enhancement Opportunities ina Brownfield Redevelopment Plan. Paper SPE 101491 presented at the SPE Russian Oil and Gas Technical Conferenceand Exhibition, Moscow, Russia, 3–6 October.Dawson, G., Buchan, A., Kardani, I., Harris, A., Wercholuk, L., Khazali, K.A., Shariff, A.H., Sisson, K., and Hermawan, H.2010. Directional Casing While Drilling (DCwD) Heralds a Step Change in Drilling Efficiency from a ProducingPlatform. Paper OTC 20880 presented at the 2010 Offshore Technology Conference in Houston, Texas, USA, 3–6 May.Halliburton Energy Services. 2010. “Mercury, EM MWD Field Operations Manual”, Printed in USA.Hocker, C., Track, A., Cao, D., Williams, R., Dupal, L., and Shapiroo, B. 1993. The Acquisition and Processing of VerticalSeismic Profile in Horizontal Wells, Erb West Field, Sabah, Malaysia. Paper SPE 25360 presented at the SPE AsiaPacific Oil and Gas Conference, Singapore, 8–10 February.Janwadkar, S., Klotz, C.,Welch, B., and Finegan, S. 2010. Electronic MWD Technology improves Drilling Performance inFayetteville Shale of North America. Paper SPE 128905 presented at the IADC/SPE Drilling Conference and Exhibition,New Orleans, Lousiana, USA, 2–4 February.Lopez, E., Bonilla, P., Castilla, A., and Rincon, J. 2010. Casing Drilling Application with Rotary Steerable and Triple Comboin New Deviated Wells in Infantas Field. Paper SPE 134586 presented at the SPE Annual Technical Conference andExhibition in Florence, Italy, 19–22 September.Van der Harst, A.C. 1991. Erb West: An Oil Rim Development With Horizontal Wells. Paper SPE 22994 presented at the SPEAsia-Pacific Conference in Perth, Western Australia, 4–7 November.Weisbeck, D., Blackwell, G., Park, D., and Cheatham, C. 2002. Case History of First Use of Extended-Range EM MWD inOffshore, Underbalanced Drilling. Paper IADC/SPE 74461 presented at the IADC/SPE Drilling Conference, Dallas,Texas, 26–28 February.SPE-158245-PP 7 AppendixFig. 1—Situation Map of the Erb West Field – Malaysia.Fig.2—Typical Cross-section of the Erb West Formation.8SPE-158245-PPFig. 3—Location of 2 EM antenna both in at surface BOP and seabed (Left Picture). Antena hooked at seabed with anchor and atsurface BOP (Right Picture).Fig. 4—Three Main Components of EM Transciever Tool Installed in Drilling BHA.Fig. 5—Surface System which Accommodates the EM Antennas.SPE-158245-PP 9Fig. 6—Typical BHA Component using EM Telemetry (Upper Picture). Typical BHA using mud-pulse telemetry, positive pulse type(Lower Picture).Fig. 7—Component of CWD BHA made up together with EM MWD.Fig. 8—Location of Subsea Antenna Winch at Tender Rig Poop Deck.10 SPE-158245-PPFig. 9—Comparison of EM Signal where Red is Expected Signal and Blue is Actual Signal.。