IADC/SPE 168044

First Field-Testing Of A New Rotary Steerable Drilling Liner Technology On Alaska North Slope Greg Hobbs, Rob Stinson and Chip Alvord, ConocoPhillips; Okechukwu N. Anyanwu, Christian Klotz and Muntasar Mohammad; Baker Hughes

Copyright 2014, IADC/SPE Drilling Conference and Exhibition This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas, USA, 46 March 2014. This paper was selected for presentation by an IADC/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 International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or 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 International Association of Drilling Contractors or 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 IADC/SPE copyright.

Abstract Conventional drilling through lower intermediate intervals in the southern portion of the Alpine field on Alaskas North Slope (ANS) has posed significant challenges, resulting in longer than planned well delivery timing, and additional costs due to accumulated drilling complications. While unstable shale sections can be drilled without significant issues, hole collapse has caused difficulties while tripping out of hole and running casings. The need to overcome these challenges for long term economical access to develop the Alpine sands reservoir section beneath the shale layers led to numerous project initiatives and operational changes. These actions all produced incremental advances to mitigate wellbore stability issues, but never provided a guarantee that a liner would be successfully run to total depth of the open hole section after the trips required to complete this task conventionally. In 2011, a new Steerable Drilling Liner system was proposed as a possible solution for drilling these wellbores while sealing off the troublesome shales. An extensive feasibility study was conducted to ascertain the technical possibility of deploying this technology safely within the Alpine field. Candidate wells were identified and a phased implementation approach was adopted to conduct field trials in order of increasing complexity of well trajectory and open hole and liner section lengths. This paper provides insights into the new technology and the field trial program. We cover the lessons learned and further improvement opportunities applicable to future deployments in this area. Based on the success of the Steerable Drilling Liner technology in this application, further deployments are scheduled to take advantage of developing Alpine reservoir sands in an economical and safe manner. Introduction The Alpine Field, which came online in 2000, lies near the environmentally sensitive shoreline of the Arctic Ocean on the North Slope of Alaska [Fig. 1]. It is the most westerly of the current North Slope producing fields and straddles the border of the National Petroleum Reserve - Alaska (NPR-A). The field was developed without a permanent road connection to the existing North Slope Infrastructure to address environmental and indigenous community concerns. Alpine is connected to the main North Slope spine road network via ice road during the winter months. Much of the resupply effort for the following roadless period is accomplished during the ice road season. Field development has progressed from near-pad targets to higher departure wells in a 6700-ft TVD reservoir section that has introduced drilling challenges. These challenges have been compounded by the thickening of a troublesome overburden shale section in the southern part of the field.

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Fig. 1: The Alpine Field

Background The development of the Alpine reservoir has progressed as an alternating horizontal producer/injector pattern for best recovery efficiency [Fig. 2].

Fig. 2: Well Profiles in Alpine Reservoir

As field pad development advanced southward, it was determined that a shale package had thickened in this direction [Fig. 3]. This thickening, compounded with progressively higher sail angles required to reach points at higher departures, led to issues that affected efficient running and cementing of intermediate liners.

Fig. 3: Miluveach Shale Thickness from North (left) to South (right)

Significant time and costs were incurred completing multiple wells conventionally in the southern area. New techniques involving higher mud weights and managed pressure drilling, to mitigate shale issues and assure successful liner runs, were attempted with limited success. With untapped resources still in this area, the search for a methodology that would eliminate the risks of running liners through the unstable section continued in earnest. Through industry collaboration, we learned of a steerable drilling liner technology that was being developed and deployed in

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offshore Norway by Baker Hughes to drill through and complete beyond troublesome hole sections. This system was researched, and a case made to develop and deploy it in the Alpine field in Alaska. Deploying new technology in a remote, seasonally roadless Arctic development was no small commitment. Potential hydraulics and torque and drag cases were painstakingly studied. Engineers and operations personnel had to be certain that the only rig drilling in the field could handle the equipment. Initial deployment plans utilized non-rotating torque reducers, premium liner connections to assure integrity through multiple rotations in tortuous hole paths, robust solid centralizers proven in casing drilling applications and drilling dynamics sensors placed above and below the liner to provide recorded and real-time data. A four well progressive, directionally complex pilot program was assigned by the resource asset for two reasons. First, it was not cost effective to ship specialized equipment over ice roads for a single well project. Second, it was deemed important that the system be given a fair trial, as it could be a key to future development potential in the area. The technology could enable completion of high-departure wells in an unstable overburden where the environmental sensitivity of the area precluded the placement of more drilling pads. Steerable Drilling Liner Service Overview The Steerable Drilling Liner service combines the advanced rotary closed-loop system (RCLS) with the liner drilling. An advanced rotary steerable system is used in combination with the drilling power of pre-contoured modular motor that provides power for the pilot and reamer bits. The system consists of a retrievable and changeable inner string and a liner string connected via a modified running tool. Because the liner is isolated from the reamer shoe, the liner can rotate at much lower RPMs than the pilot and reamer bits. This design reduces the load on the liner.

System components and Set-Up [Fig. 4]

1. Running Tool: connects the inner string to the liner allowing rotation of the liner while

drilling. 2. Thruster: works as a length compensator between the two connection points between

inner and outer string and ensures the axial drilling load is transmitted to the inner string and not the liner while drilling ahead.

3. Modular Motor with Integrated Landing Sub: The Landing Sub defines the position of the inner string relative to the liner shoe. The Modular Motor adds approximately 150 RPM and delivers drilling torque to the reamer bit and pilot bottomhole assembly (BHA).

4. Reamer Drive Sub: carries extendable pads that are activated (via downlink) to drive the Reamer Bit, providing a reliable connection between the reamer bit and the inner string, and transferring the required weight-on-bit (WOB) and torque-on-bit (TOB). Moreover, it can be de-activated (via downlink) to disengage the Reamer Bit prior to POOH.

5. Reamer Bit: The drilling forces on the reamer bit are placed on the inner string and not on the liner shoe. This reduces wear and tear on the liner and allows a simplified liner shoe design.

6. Standard advanced rotary steerable system (BHA): Incorporates FE and drilling dynamics / optimization sensors to monitor vibrations and weight-on-bit transmission to the pilot bit.

Directionally, the Steerable Drilling Liner platform behaves like a regular rotary steerable system. The short stickout pilot BHA provides the ability to directionally control and steer the system to a required direction for optimal wellbore placement. The Steerable Drilling Liner technology is designed to provide access to reservoirs that are hindered by challenging downhole environments that can drive up non-productive time (NPT) costs, thereby enabling optimum reservoir recovery. Such downhole environments include but are not limited to moving and swelling formations, loss/thief zones, low-pressure zones, depleted/unstable formations, etc. Running liner while drilling eliminates all NPT associated with additional reaming/circulating, cleanout run prior to casing run, and reaming casing to bottom in some cases.

Fig. 4: Steerable Drilling Liner Assembly

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Feasibility Study Extensive study was conducted to ascertain the feasibility of successfully and safely deploying the Steerable Drilling Liner in Alpine to achieve operator objectives. Offset well directional plans covering the range of expected directional profile/challenges were used in the modeling [Figs. 5 and 6]. Major considerations were torque and hydraulics requirements. The rig had to provide the torque required to rotate the Steerable Drilling Liner assembly, including the liner. Efficient hole cleaning was critical while keeping the equivalent circulating density (ECD) and standpipe pressure within specification. Baker Hughes Applications Engineers, working together with the ConocoPhillips technical team, reviewed model outputs and interpretations to determine operational options.

Fig. 5: Along the wellbore profile

Fig. 6: Plan and Section views

Details of directional profiles utilized for Steerable Drilling Liner application feasibility study are provided in Table 1 below.

Table 1: Details of directional profiles

Well Profile A B MD In 12800 10500 MD Out 15370 12400 TVD In 6007.42 6412.90 TVD Out 7000 7111.90 Inc In 60.93 56.91 Inc Out 86 90 Azi In 238.51 173.12 Azi Out 165 153.57 Max Dogleg 3.5 3.51 Total Planned Footage 2570 1900

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Torque and Drag Modeling A wide range of friction factors (0.2 0.4) were considered in modeling the torque and drag. There was a concern that torque values would exceed the rig topdrive capacity and the drillpipe makeup torques. The objective was to cover all possible friction factors that might be encountered while drilling. Additionally, using the upper range of friction factors, we sought to estimate the torque required to break static friction should operations be interrupted, and rotation stopped, for an extended period of time. Results show that the torque required to reach total depth exceeds the topdrive capability for well profile A and is at the limit for well profile B [Figs. 7 and 8].

Fig. 7: Torque modeling results for well profile A

Fig. 8: Torque modeling results for well profile B

The results indicated that it would be challenging to use this technology in Alpine applications without implementing a torque reduction technique. At this point, after a careful review of available options, torque reducers were considered and Non-Rotating Drillpipe Protectors (NRDPP) were selected. Modeling results indicated incorporating NRDPP reduced the torque to reach total depth below operational limits of the rig [Figs. 9 and 10]. It was recommended that we acquire and

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utilize higher-torque rated drillpipes for the project, or at least use these drillpipes in the top section of the hole.

Fig. 9: Torque modeling (with NRDPP) results for well profile A

Fig. 70: Torque modeling (with NRDPP) results for well profile B

Hydraulics Modeling System hydraulics, in terms of pressure loss, hole cleaning, and ECDs, was of particular interest. This was in part due to the limitations of the bottomhole assembly components, and the systems complex annular hydraulic profile, which was made of two main parts (the small clearance between the liner and open hole and the larger clearance between the drillpipe and casing above the liner) (Torsvoll 2010). Initial hydraulics analysis validated concerns for inadequate hole cleaning above the liner due to low annular fluid velocity and the potential for high ECD at the liner. In addition, high standpipe pressure, exceeding rig specification, was required to reach section total depth. Figs. 11 and 12 show hydraulics result for standpipe pressures and ECDs for scenarios with a flow sub closed and open respectively

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Fig. 81: Hydraulics- Standpipe pressure, circulating sub closed

Fig. 12: Hydraulics- Standpipe pressure, circulating sub open

The model with the flow sub placed above the liner resulted in efficient hole cleaning and lower standpipe pressures that were within acceptable limits. Flowrate was limited to 315 USgal/min by the modular motor in the inner string. The flow bypass sub above the liner provides the ability to pump at high flowrates while diverting some of the flow, and without exceeding bottomhole assembly specifications. The hydraulics result for hole cleaning when flow sub is closed [Fig. 13] and with flow sub open [Fig. 14] is presented below. The average annular fluid velocity above the liner is significantly less than the required annular fluid velocity for adequate hole cleaning.

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Fig. 93: Hydraulics- Annular velocity, circulating sub closed

Fig. 104 Hydraulics- Annular velocity, circulating sub open

Running a flow sub above the liner was recommended to boost annular flow and enhance hole cleaning. A fit-for-purpose solution to address this problem in deploying Steerable Drilling Liner technology has been developed in the form of a smart Flow Diverter. The smart Flow Diverter will be placed above the liner to increase annular flow and enhance hole cleaning in the annulus above the liner. This tool can open and close the ports by surface downlink command, as often as is required. This integral component of the steerable drilling liner system was field-tested in December 2011 and commercially deployed for the first time in 2013. It displayed excellent performance.

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Implementation Drilling Operations To date, the first two wells of the pilot program have been drilled with the Steerable Drilling Liner system. Both wells have focused on testing the hardware of the system, verifying modeling results and directional capability in friendly rocks. The first well [Fig. 15] tested the build capability in a shortened shale section of 643-ft MD with a 1044-ft 7-in liner section. The system was able to easily achieve the 17 degrees of build over the section with up to 5 degree per 100-ft doglegs against a plan of 3 degrees per 100-ft. The excessively long liner lap was planned to meet regulatory expectations and compensate for the uncertainty of the top of the reservoir section.

Fig. 11: Plan view of first well

The second well [Fig. 16] tested build and turn capability in a 1657-ft MD shale section with a 2067-ft 7-in liner section. The system achieved a 24-degree build and 31-degree turn with ease again, with 5 degree per 100-ft doglegs where needed against a 3 degree per 100-ft plan.

Fig. 12

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Both wells were drilled with a Glycol Inhibited freshwater-based Low Solids, non-Dispersed system. A lesson from the first well was to eliminate an asphaltene black product that had typically been used in these well sections. The product had a tendency to create large asphaltic chunks of shale debris in the mud system that interfered with some critical placement profiles of the system. After removal of this product, the second well was drilled without drilling fluid issues. Pre-drilling hydraulics modeling proved accurate for the system [Fig. 17]. Adequate hole cleaning was achieved above and below the liner during drilling and was confirmed with post-drilling precautionary sweeps of liner top areas.

Fig. 13

The most significant find of the system during the first two deployments was the slower-than-anticipated rates of penetration. Rates of penetration averaged twelve and fifteen feet per hour, respectively. The anticipated rate of penetration was forty feet per hour. This performance led to a complete re-design of the reamer shoe for the next deployment. It was also determined, from downhole dynamic drilling data recorders, that the non-rotating torque reducers required in the drillstring to assure achievement of total depth with an undersized topdrive, were inhibiting weight transfer. This was mitigated with the installation of a larger topdrive and a high torque string of drillpipe. Future torque reduction tools will be run for casing protection only. The slower-than-anticipated rate of penetration did enable system hardware to be tested in drilling conditions for 130 hours without failure of electronics or liner connections. While torque and drag were large concerns when vetting the project and its viability, pre-project modeling proved accurate after the first two deployments. The 1000-ft 7-in liner added 4000 foot pounds of torque to the system, as modeled, and the 2000-ft liner added 5000 foot pounds of torque to the system. The results verified that cased and open hole friction factors determined for standard bottomhole assemblies were applicable to the liner system when new outer diameters and complete (inner and outer string) system weights were considered. The final modification to the drilling system was applied to the quick connect that mated the 7-in liner to the 4-in inner string. It was determined that the original set screw design was inadequate to hold the cap in place during drilling operations after a failure on the second well. This issue was eliminated by placement of stop blocks in the cap and lower housing where the components meet when made up.

Cementing Operations Although the first two pilot wells were cemented and passed tests required by local regulations to confirm integrity, the jobs were not flawless. The first well utilized an inner string cementing system that had two hydraulic components to actuate with two separate balls. In this first use of the cementing system with the new steerable drilling liner technology, the amount of complexity proved to be too much, resulting in the failure of multiple components in the string, requiring a remedial cement job. The remedial job was pumped at lower than planned, but effective rates given the time between the trips required for cement placement and a

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fear of the hole packing off. The second well deployment attempted to simplify the cementing equipment with the elimination of the inner string and cement placement with a liner wiper plug and drillpipe dart of a standard cement job. The job failed as packoff occurred at the planned cementing rate of 6 bbl/min [Fig. 18].

Fig. 14 (left) Packoff, and (right) remedial inner string Job at 1 bbl/min

Attempts to regain circulation above rates greater than 1 bbl/min failed. Given this low rate, an inner string was run with a cement retainer and 50 bbl of cement successfully placed behind pipe at 1 bbl/min with concern of packoff the entire time, given the amount of time required for trips and cement preparation. The next deployment will use a newly designed cementing string that will eliminate hydraulically set tools, but have the flexibility of an inner string and retainer at the liner shoe with the first equipment run. Cement will be pumped at a maximum rate of 4 bbl/min, which was the successful rate of the first job. The one thing that has stood out about cementing operations is that even with the excessive amounts of time between drilling and cementing operations, there has always been the capability of pumping in the shale section with returns. This was not expected, even in the friendlier pilot area of the field. Conclusions The Steerable Drilling Liner systems deployed at the Alpine field have proven the directional and equipment capability of the system. These favorable results have enabled progression to the troublesome area of the field with optimism that success can be achieved in an area where failed liner runs and sidetracks have impacted operations with a frequency that drove interest in finding a better technology to complete the wells with higher efficiency. While the deployments have not been flawless, all hardware issues, including those with the newest technologies of the system have had root causes determined and the failure points removed. Acknowledgements The authors would like to thank ConocoPhillips Alaska Inc., Anadarko Petroleum Corporation, and Baker Hughes for permission to publish this paper. Special thanks to all who contributed to the success of this publication. Nomenclature

BHA = bottomhole assembly bbl/min = barrels per minute BUR = buildup rate CFD = computational fluid dynamics DH = downhole DLS = dogleg severity ECD = equivalent circulating density

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ESD = equivalent static density FIT = formation integrity test HPHT = high-pressure/high-temperature lb = pounds MD = measured depth PBR = polish bore receptacle POOH = pull out of hole PPG = pound per gallon RDS = reamer drive sub ROP = rate of penetration RPM = rotation per minute RSS = rotary steerable system TD = total depth TOB = torque on bit TVD = true vertical depth T&D = torque and drag WOB = weight on bit

References

A. Torsvoll, J. Abdollahi, M. Eidem, T. Weltzin, A. Hjelle, and S.A. Rasmussen; Statoil ASA; S. Krueger, S. Schwartze, C. Freyer, T. Huynh, and T. Sorheim; Baker Hughes, Inc.: Successful Development and Field Qualification of a 9 in and 7 in Rotary Steerable Drilling Liner System that Enables Simultaneous Directional Drilling and Lining of the Wellbore SPE paper 128685 presented at 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans, Louisiana, USA, 24 February 2010.