Sakhalin extended-reach well pushes ERD envelope to a world record

MICHAEL W. WALKER, ExxonMobil Development Company

Schematic representation of the extended-reach wells drilled from the Yastreb rig onshore to the Odoptu reservoirs over 11 km offshore and 1,800 m below the Sea of Okhotsk. The subsurface cutaways depicted are for ease of visualization only. Graphic courtesy of ExxonMobil.

Extended-reach drilling (ERD) offers economical access to reserves that were previously out of reach. This access can be achieved from existing infrastructure, with the added benefit of a reduced environmental footprint. ExxonMobil, as operator of the Sakhalin I project, recently drilled and completed nine extended-reach wells at Odoptu field from shore, culminating with the world record extended-reach OP-11 well. The well reached a total depth of 12,345 m (1,784-m TVD and 11,479-m vertical section) in 60 days with less than 1% NPT.

Challenges that were successfully overcome during drilling included wellbore instability, shocks and vibrations, and high torque. The application of performance management workflow reduced downhole shocks and vibrations, optimized hole quality and resulted in the drilling of each hole section with a single BHA.

Besides stretching the limits of the ERD envelope during drilling, ExxonMobil also achieved extended performance from a completions perspective, as well. Significant achievements for the OP-11 well included the successful placement of a 9⅝-in. floated liner at 10,758 m without rotation and the placement of completion equipment at a world-record depth.

The design for such wells typically employs detailed modeling work. However, a thorough understanding of ERD operational complexities is also required. The design considerations, techniques and lessons learned that are described in this case history can be used to provide valuable insight for the drilling and completion of future extreme ERD wells.

FIELD BACKGROUND

The Sakhalin 1 project is comprised of Chayvo, Odoptu and Arkutun Dagi fields, located offshore the east coast of Sakhalin Island, Russia, Fig. 1. Development operations began in 2003 at Chayvo field with the Yastreb land rig and were complimented in 2005 with development drilling operations from the Orlan platform. In 2009, the Yastreb rig was moved to the Odoptu field, approximately 75 km north of its previous Chayvo location. At Odoptu, nine ERD wells were drilled from 2009 through 2011, targeting Miocene sands. Production and drilling facilities are under construction for the Arkutun Dagi field development, where drilling is expected to begin in 2014.

Fig. 1. Sakhalin Island map, showing adjacent offshore fields.

As of January 2011, 15 of the 20 longest-reach wells in the world had been drilled in the Sakhalin 1 project, with the Odoptu OP-11 surpassing the 2008 Maersk BD-04A well in Qatar (Sonowal, et al, 2009). As ERD drilling techniques and development needs evolve, additional record-reach wells will, undoubtedly, be drilled. Planning is underway to drill wells with measured depths in excess of 13 km as part of the Sakhalin 1 development.

Because of the limited exploration drilling data from Odoptu field, the development was designed to be performed in stages. The first stage of development was designed to obtain drilling and production performance, thereby allowing optimization of future development operations. Hence, the project included drilling a vertical disposal well and seven ERD wells, with two additional ERD wells subsequently added, Table 1. Production from the field is piped back to Chayvo field for further handling.

Following the drilling of a vertical cuttings reinjection well, the first two ERD wells at Odoptu were designed to ascertain the height of the oil column, thereby better refining the remaining drilling objectives. The first well, OP-8, drilled an 8½-in. pilot hole that penetrated the reservoir section horizontally in the oil column and was geosteered updip, to locate the gas/oil contact, measure reservoir pressures (and determine fluid gradients), and exit the top of the reservoir again at a 99° inclination. The pilot hole was then plugged, and a horizontal production hole was drilled and completed. The second well, OP-7, was drilled downdip to determine the pressure and fluid gradient in the aquifer leg of the reservoir. It was subsequently sidetracked horizontally through the oil column and placed into production. Using the pressure and fluid contact data from these two wells, the height of the oil column was determined, and vertical placement of subsequent wells in the reservoir sections was high graded.

ODOPTU WELL DESIGN

At Odoptu (including OP-11), the typical well design includes 30-, 18⅝-, and 13⅝-in. casings; 9⅝-in. liner; 8½-in. hole to TD with 5½-in. completion screens; inflow control devices; swell packers; and 5-in. tubing to surface. The 30-in. conductor is driven to a depth of approximately 90 m. A 24-in. hole is drilled with water-based mud to 800 m, where the inclination is 40° to 45°. An 18⅝-in. casing is run and cemented to surface using the stab-in cementing technique. A 17½-in. hole is then drilled to 3,800 m to 5,250 m, MD, with non-aqueous fluid (NAF), building to an 80°-to-87° angle, and the 13⅝-in. casing is run and cemented. Below the 13⅝-in. casing, a 12¼-in. hole is drilled, building to a final inclination of 90° and reaching section TD just prior to entering the objective hydrocarbon zones. This allows the 8½-in. production hole to be lined up horizontally to the objective sands and minimize well positioning risk. The 9⅝-in. liner is run air-filled (floated), utilizing a mud-filled 6⅝-in. drill pipe landing string, to add additional hookload for pushing the casing or rotation as a contingency. Once in position, the liner is cemented, and a liner top packer is set. The 8½-in. production hole is drilled horizontally through the objective sands. At TD, the drilling mud is displaced to filtered NAF, to allow running of the production screens without plugging. The lower completion is then run into the open hole as a liner using a swivel tool that allows drill pipe (landing string) rotation to overcome axial friction, while not rotating the screens in the lower completion. Once the completion liner is in position and the liner hanger is set, the upper completion is run, consisting of 5½-in. tubing, downhole pressure gauges, gas lift mandrels, and surface-controlled subsurface safety valve.

Drilling rig specifications. The Yastreb rig package includes a top drive rated to continuous drilling torque output of 91,000 ft/lb at 130 rpm; high-torque range three drill pipe (6⅝ and 5⅞ in.); four mud pumps; six shale shakers, and high-volume mud and base oil storage capabilities. The rig does not rack any drill pipe in the derrick. It has an attached pipe barn used to make up stands (including BHAs), and feed pipe or casing to or from the rig floor in range-3 doubles. This eliminates racking limitations and provides a structure that removes many physical barriers that might otherwise hinder efficient construction of world-class ERD wells.

The first few wells at Odoptu produced several lessons learned, resulting in slight well design modifications. Use of high mud weights in the 17½-in. hole section eliminated wellbore instability and enabled smooth, low-friction 13⅝-in. casing runs (Dupriest et al., 2010). In the 12¼-in. hole wellbore instability was commonly noted, which resulted in raising the mud weight up to 12.5 lb/gal (the point at which the 47 lb/ft, 9⅝-in. floated liner becomes neutrally buoyant). To minimize the risks associated with the instability in the 12¼-in. hole section, the 13⅝-in. casing setting depths were extended to deeper depths. Initial well designs set the 13⅝-in. casing at 3,800 m MD, but the OP-11 was the deepest at 5,254 m MD (1,543 m TVD). Typically, setting the 13⅝-in. casing deeper also allowed the 9⅝-in. liner to stay either entirely or mostly within the secure confines of the 13⅝-in. casing, while crossing over to the 6⅝-in. drill pipe landing string. An additional benefit realized with this modification was that it provided a better split between the 17½- and 12¼-in. hole sections, which then allowed for the improved potential for shoe-to-shoe BHA runs. The drill team also noted that buckling loads on the 5⅞-in. drill pipe began to limit the amount of weight-on-bit that could be applied in the 12¼-in. hole section. The 6⅝-in. drill pipe was used to mitigate these buckling concerns, while also providing improved hydraulics and hole cleaning benefits.

Performance management workflow. An integral component driving the well designs and operational practices is ExxonMobil's Fast Drilling Process global performance management workflow. This practice has been well documented (Dupriest, 2006; Bailey et al, 2008), but is noted again, due to the continuing significant impact on drilling performance. The workflow ensures that limitations to drilling performance are continually identified and eliminated, and it also recognizes that the quality of the hole being drilled is of paramount importance. This all-encompassing approach touches on almost every aspect of the drilling operation, from the base well design to the driller's brake handle. Prior to every drilling or completion phase, the drill team performs a pre-section review to discuss the upcoming operation. The purpose of the review is to discuss performance limitations, recent lessons learned, and recommendations and differences from the previous similar operations, and ensure team alignment on the forward work plan. In addition, upon completion of each section, a section debrief is performed to capture and document items that worked well during the operation and should be continued on future wells, as well as document items that did not work well or required further improvement. The debrief also provides specific recommendations for future wells and a plan for future analysis.

Details regarding the various specific optimizations that led to the outstanding drilling performance on the OP-11 well are the topic of a separate publication. A high-level summary of those items would include performance optimization processes, bit design, vibration modeling (pre-job and hindcasting) and optimization, flat-time reduction initiatives, and actions to extend operational capabilities.

OP-11 CASE HISTORY

The OP-11 was the eighth ERD well drilled at Odoptu. Lessons learned from the prior seven wells were incorporated into its design. The drill team recognized that to reach all the objectives, the well plan would result in a world record well, Fig. 2. The wellbore schematic is provided as Fig. 3.

Fig. 2. Extended reach nose plot.  Red points represent ExxonMobil wells drilled at the Sakhalin 1 project.  The blue line represents the Odoptu OP-11 well directional profile. Black points represent all other wells.

Fig. 3. Wellbore schematic for Odoptu OP-11 well.

Batch operations. Batch setting operations were utilized to set the 30-in. conductors, as well as to drill the 24-in. hole section and run the 18⅝-in. casing. This process allows efficiencies to be gained from repetitive operations, and it minimized the mud system swap-outs from water-based to NAF. Using the Yastreb drilling rig, the 30-in. conductor was driven to refusal at 81 m, with one intermediate cleanout run with a 24-in. BHA. The operator has discovered that by drilling a partial 24-in. pilot hole, the conductor is driven more effectively. Below the 30-in. conductor, a 24-in. hole was drilled using a mud motor with a 1.15° bent housing and gyro MWD survey tool, using water-based mud. The hole was kicked off from vertical, beginning at 180 m, and built to 41° by section TD of 800-m MD/ 739-m TVD. Build rates ranged from 1° to 3.5°/ 30 m. The 18⅝-in. casing was then run and cemented to surface, using stab-in cementing equipment. For OP-11, these batch-setting operations took 7.1 days.

17½-in. hole and 13⅝-in. casing. After installing and testing the BOP stack, a 17½-in. drilling BHA, consisting of the drill bit, push-the-bit rotary steerable equipment and MWD, was run on 6⅝-in. drill pipe. The drillstring incorporated the latest BHA and bit design learnings from prior Odoptu wells and resulted in dramatic improvements in vibration reduction, steerability, and overall rate-of-penetration (ROP). Once the BHA was in the hole, the water-based mud was displaced with 12.0 ppg (lb per gal) NAF, the float equipment was drilled out and an integrity test was performed to 14.5 ppg. The hole was then directionally drilled, building to 81° inclination by 1,250 m MD. At 4,700 m, a second build was performed, reaching the planned 87° inclination by 4,900 m MD. The hole continued to section TD at 5,254-m MD/1,543-m TVD. This was 46 m shallower than planned, and was a result of the BHA continuing to build angle. After reaching 5,254-m MD, the hole was backreamed with no indications of instability. The bit was graded 2/3/WT, but one stabilizer in the BHA had significant wear (which had resulted in the build tendency). As wear on the stabilizer continued, it became increasingly difficult for the rotary steerable system to overcome the build tendency. Higher lateral vibrations and stick-slip were observed at the end of the run, as control drilling for directional purposes destabilized the bit.

This 4,454-m section was drilled in a single run, and was a 17½-in. assembly distance record for the directional drilling service provider. Typical operating parameters for this section were a 1,270-gpm flowrate, 40 klb weight-on-bit (WOB) and rotary speed of 160 rpm. The maximum observed drilling torque was 45 kft/lb with average ROP of 100 m/hr (150 m/hr in the beginning of the run). The rig's six shakers were screened to minimize sand content in the mud, which had led to erosional tool failures in previous wells.

The 13⅝-in. casing was run mud-filled to TD without incident, and the casing was then cemented conventionally. This section took 10.9 days to complete (drill and set casing).

12¼-in. hole and 9⅝-in. casing. Design considerations. The 9⅝-in. liner is designed to be set horizontally just prior to entering into the hydrocarbon-bearing objective sands. The 12¼-in. hole section in the offset wells experienced instability, so mud weights were raised to 12.5 ppg early in the program. This action placed the 47 lb/ft 9⅝-in. liner in a neutrally buoyant condition, when it was run air-filled. Any additional mud weight would result in the casing trying to float out of the hole and would increase the force required to push the casing into the hole. Heavier casing could have allowed additional mud weight to fight the instability, but it was not available for this program. Hence the plan was to continue to utilize 12.5-ppg mud and deal with any residual instability by backreaming the hole prior to running the neutrally buoyant floated liner.

When running the liner, hookloads are typically very low, and pushing with the top drive (5-8 klb) is common to speed the run. Once the liner hanger is installed, 6⅝-in. drill pipe is made up, and the running string is mud filled, which allows hookload to build, thereby providing additional push force for the air-filled liner. A sub in the liner hanger service tools provided the necessary separation of the mud-filled drill pipe from the air-filled casing below. Rotation of the liner was a contingency option, but it was not utilized for the successful placement of the liners at Odoptu. Preferably, the entire 9⅝-in. liner would have remained inside the 13⅝-in. casing, until the liner hanger was run. Hence, when the liner entered the open hole, it could be rotated on the drill pipe landing string using the top drive. In actuality, on OP-11, approximately 400 m of 9⅝-in. casing extended into the open hole during the 2-hr period that the liner hanger was being installed.

Actual operations. The 12¼-in. drilling assembly consisted of the bit, a point-the-bit rotary steerable system and MWD. The bit had a 6-in. tapered spiral gauge with depth-of-cut features in the nose area. Above the BHA, heavyweight drill pipe and jars were run, followed by 3,500 m of 6⅝-in. drill pipe, then 5⅞-in. drill pipe with premium high-torque connections at the top of the string. The 6⅝-in. drill pipe was run on the bottom of the string, as this is the location of the highest buckling loads, and it had the additional benefit of increasing the annular velocity, which assists in hole cleaning. As per plan, the section was drilled with 12.5 ppg mud, with a flowrate of 1,150 gpm. The directional assembly drilled as per plan, holding the tangent angle of 87°, then building to horizontal by 10,500 m MD, reaching casing point at 10,758 m MD/1,774 m TVD. At 9,900 m MD, on-bottom drilling torque approached 60 kft/lb, and lubricants were introduced into the system. By section TD, drilling torque was approximately 59–62 kft/lb. Except for some sand/shale interfaces early in the section, vibrations and stick slip in the 12¼-in. hole were extremely low. The 5,504-m section drilled with an average ROP of 46 m/hr.

After reaching section TD, the hole was backreamed into the 13⅝-in. casing with only minimal indications of cavings (wellbore instability). The bit graded 3-2-CT, and several stabilizers had noticeable wear (up to ⅞-in. under gauge). The 9⅝-in., 47 lb/ft floated liner was then run on mud-filled 6⅝-in. drill pipe without rotation. For casing strings with light hookloads, surge effects should not be ignored as they can result in a significant hookload reduction that might otherwise be captured as higher friction or otherwise written off as modeling error or hole problems.

Once the liner was on bottom, the entire casing string was filled with mud, the liner was circulated, the hanger was set and the casing was cemented. The liner top packer was then set by rotating the drill pipe (to overcome axial friction) with 60-kip compression force. The liner top packer was pressure tested to 3,700 psi, and the service tools were then pulled out of the hole. The 12¼-in. hole took 20.6 days to drill and case.

8½-in. hole, lower completion and upper completion. Design considerations. This hole section is designed to be drilled horizontally and contact multiple hydrocarbon objective sands, while making an azimuth turn from 125° to 90° (to facilitate future well placement). Near the end of the section, inclination was lowered to 87°, to reduce overall section length. Equivalent circulating density (ECD) is a significant concern in this section, as the operator uses 5⅞-in. drill pipe inside the 9⅝-in. liner and 8½-in. hole, with 6⅝-in. drill pipe above the liner top. This design provides robust buckling and torque resistance. ECD can add 4 to 6 ppge in this well design, depending on the flowrate. The use of liquid lubricants is commonplace to reduce rotating torque, improve weight transfer and reduce axial friction.

An additional phenomenon was documented in the OP-11 well that can potentially impact well designs and drill pipe buckling loads, as well as ROP performance. In many of its ERD wells, the operator has noted a reduction in hookload when the pumps are turned on, especially while drilling smaller hole (i.e., 8½-in.). Hydraulic forces (pressure and shear) acting along the drillstring combine to reduce the hookload and place additional compressive loads on the drill pipe. For extreme ERD applications such as this, we have noted a hookload loss of 40 to 50 kip, merely by turning on the pumps to the drilling flowrate. Depending on the well design and the drill pipe in use, drillpipe buckling, higher surface torque, and poor weight transfer to the bit (reduced ROP) can result. The operator has documented that as buckling limits are reached, relatively minor flowrate reductions can improve weight transfer and significantly improve ROP performance.

Of paramount importance at these depths is the need to keep the BHA in the hole and functioning properly. A round trip to replace a failed BHA component at extreme depths can take five to six days. The operator's emphasis on vibration reduction (by design and operating practices) is critically important in extending the service life of downhole tools. The directional drilling service provider must be properly aligned and actively engaged, to ensure that the downhole tools are maintained to their highest state of preparedness, support necessary up-front redesign, and actively participate in real-time vibration mitigation efforts.

Completion designs for Odoptu field were carried over from the highly successful Chayvo field drilling campaign. Lower completions, comprised of screens, inflow control devices and swell packers, are run as liners in filtered NAF and positioned into the 8½-in. open hole. Because of the shallow TVD and ERD profile at Odoptu, the lower completion equipment could not be successfully run into position by slacking off, alone. Thus, a swivel tool was utilized to enable the landing string to be rotated above the screens, which removes axial friction and provides the additional force needed to push the non-rotated lower completion into position. The upper completion is then run without rotation. Previous papers have discussed completion methodology (Helmy and Veselka, 2006; Walker, Veselka and Harris, 2009). Other than the use of the swivel tool, the completion philosophy remained essentially unchanged from that previously presented.

Actual operations. The 8½-in. drilling BHA consisted of the bit, point-the-bit rotary steerable tool, density neutron, MWD, formation pressure tool, GR/resistivity, heavyweight drill pipe (HWDP), jars, 7,900 m of 5⅞-in. and 6⅝-in. drill pipe. When tripping in below 8,500 m, the drillstring could no longer be run on elevators (due to negative weight), so the assembly was rotated into the hole. The float track was drilled out, and a leakoff test to 18.0 ppg was performed, using 12.4-ppg NAF. On-bottom torque ranged from 58 to 65k ft/lb while drilling the section. Flowrate was reduced, as ECD approached formation integrity, with the majority of the section being drilled at 500 gpm. This action had the added benefit of reducing the hydraulic lift on the drill pipe and resulted in better weight transfer to the bit. Since off-bottom shocks and vibrations can be more severe than on-bottom, backreaming on connections was limited to 3 m at a reduced RPM to minimize shocks and vibrations. Instantaneous ROP was limited to 65 m/hr in the reservoir section for formation evaluation requirements. A total of 21 formation pressure tests were taken in this hole section. The 1,587-m, 8½-in. hole was drilled in 10.9 days.

After reaching TD at 12,345 m MD/1,784 m TVD, the openhole section was backreamed, the BHA was rotated back to TD (negative weight), and the well was displaced to filtered NAF (required to eliminate plugging of production screens). The NAF was filtered again after pulling back to the 9⅝-in. shoe, and again at the 9⅝-in. liner top. Additional liquid lubricant was added for the ensuing completion run.

The 3,740-m long lower completion, consisting of 5½-in. screens, blank pipe, inflow control devices, and external swell packers, was run, followed by a liner hanger and swivel tool. The assembly was run on a landing string consisting of 5⅞-in. drill pipe, heavyweight drill pipe, and 6⅝-in. drill pipe. As modeled, the assembly could not be successfully placed in the well without rotation of the landing string. Figure 4 is the actual slack-off plot for the lower completion run, and shows that at a depth of 11,700 m, rotation of the landing string was initiated to continue the run. Once the lower completion was at depth, the liner hanger was set, and the running tool was released. The filtered 12.3-ppg mud was then displaced above the liner hanger to filtered 9.5-ppg NAF, to aid in running the upper completion and the subsequent displacement to diesel. The upper completion, consisting of 5½-in. tubing, downhole pressure gauges, gas lift mandrels and safety valve, was run. The well was then circulated to diesel, the production packer was hydrostatically set, and the well turned over to production. The lower and upper completion, and diesel displacement, took 10.1 days and was completed on Jan. 7, 2011. Figure 5 shows the days vs. depth plot for the entire well.

Fig. 4. Hookload hindcast of the Odoptu OP-11 lower completion liner run.

Fig. 5. Day vs. depth plot for the Odoptu OP-11 well.

CONCLUSIONS

ExxonMobil drilled and completed the OP-11 well in 60 days to 12,345 m MD/1,784 m TVD, with a reach of 11,479 m, establishing new ERD reach and measured depth records, and with less than 1% NPT. The well was able to be drilled with a single BHA in each hole section, demonstrating what is capable with careful and relentless redesign, flawless execution, and strong commitments from service providers. Significant items contributing to the well’s success included:

Detailed up-front modeling that yielded a robust, flexible well design

• A purpose-built drilling rig, ideally equipped and suited for ERD operations in the remote, sub-arctic environment
• Well-trained operating staff that was empowered to optimize performance and flawlessly execute the plan 
• A global performance management workflow that extended drilling limitations and highlighted areas for future focus

Lessons learned from this and other ERD operations associated with the Sakhalin I project will aid in the construction of future record wells. 

ACKNOWLEDGMENTS
The authors would like to thank Exxon Neftegas Ltd and its partners for permission to publish this article, and the dedicated operating and contractor personnel that worked on the Odoptu project team. This article was adapted from IADC/SPE paper 151046 paper, “Pushing the extended-reach envelope at Sakhalin: An operator's experience drilling a record reach well,” presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, March 6-8, 2012.