SPE/IADC 163485

Offshore West Africa Deepwater ERD: Drilling Optimization Case History Hernando Jerez, SPE, Rafael Dias, SPE, and Jim Tilley, SPE, Halliburton

Copyright 2013, 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, 57 March 2013. 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 Extended reach step-out wells provide challenging opportunities for the drilling team. A deepwater extended reach well for a major operator in West Africa required a tangent section in a soft formation maintaining an 85 drift angle for ~3,400 m (11,150 ft) in a single interval. The production section required steering the well into the best section of the pay-zone. To accomplish the drilling objectives, an exhaustive, detailed plan with multiple scenarios was required before the well was drilled.

The detailed drilling plan included the use of a tailored bottom-hole assembly (BHA) with a point-the-bit rotary steerable system and an extended gauge bit. The BHA had to overcome the natural tendency of the formation to drop inclination while creating a high quality wellbore to provide sufficient hole cleaning capacity in the deeper sections. The use of a state-of-the-art modeling tool enabled the team to balance the dynamic BHA forces while drilling to avoid common drilling problems. The five sections required for the deepwater extended reach well were drilled with only six BHAs. The challenging 12 -in. tangent interval was drilled in one run with the modeled BHA, reaching a total length of ~3,400 m (11,150 ft). This paper highlights the accuracy of the BHA modeling performance in the planning stage as this process was key to delivery of the actual results. The approach used to overcome the challenges enabled the drilling team to drill the longest 12 -in section in an extended reach well in the area. This approach follows the service companies model-measure-optimize process, which is being used to improve drilling efficiency. Introduction West Africa has seen a significant shift in drilling activity, mainly in deep water offshore. As part of the deepwater golden triangle, many of the major international operators are carrying out important exploration and development activities. Typical field development plans (FDP) in offshore projects call for step-out directional and extended reach wells, to reach and develop large areas from a single drilling platform.

To be successful in an extended reach well, a solid drilling plan is required. The plan should be comprehensive but feasible for achieving the desired results. In this case study, the ER trajectory called for the delivery of build rates in the 17 -in. hole interval not previously reached in the shallow soft formations, building up to an 85 sail angle. For the 12 -in. tangent interval, the BHA must hold the angle and step-out the well along a faulted shale, and later turn the well more than 60 in azimuth to properly intersect the reservoir.

A proprietary state of the art BHA planning tool was used to model and design the appropriate BHA for each interval. Different iterations were performed to account for potential hole enlargement, build rate response, vibration mitigation, and hole cleaning. The proposed solution was to use a point-the-bit Rotary Steerable System (RSS) with attributes to overcome hole enlargement and deliver the planned trajectory and hole quality.

The RSS was used to drill all of the directional intervals. All intervals were drilled casing-to-casing in one run with one BHA per section. Each section was drilled flawlessly, delivering an average of 3.5/30m (between 3.2/30 m and 3.8/30 m) in the build section, and minimizing tool deflection in the 12 -in. section during the longest tangent ever drilled in the area. Finally, the production interval was drilled and opened up from 8 -in. to 9 -in. to accommodate the completion. The well reached the payzone with less than 1 meter of separation from the well trajectory.

2 SPE/IADC 163485

Extended Reach Drilling (ERD) Envelope In the early 1980s, a well with a horizontal displacement of 1,500 m (5,000 ft) from the surface location was considered an extended reach well, while in recent years over 12,000 m (~40,000 ft) of displacement has been achieved. Previously, the industry defined an extended reach well as those with departure or displacement higher than 2 times the TVD. Designer wells with negative sections or 3D complex trajectories are not well quantified using displacement/TVD criteria. Today, the industry is using the ratio MD/TVD to define ERD wells.

Fig. 1 shows the current industry envelope for extended reach drilling. Gravity has a big impact on the drilling process, the shallower the well the more complex the ERD operation. Several factors come into play, including available weight to drill with, tripping into and out of the hole, fracture gradients, and equivalent circulating densities and torque and drag.

The MD/TVD ratio is a measurement used to define the complexity of the ERD operation. ERD wells represent critical operating environments and downhole components must be managed from the perspective of component specification, confidence, and reliability. One of the tools that has allowed expansion of ERD applications is the rotary steerable system. Many of the challenges involved can be overcome with the right planning tools to simulate different BHAs and optimize the BHA based on modeling analysis.

The red circle indicates this ERD well case history, which has a 2.5 MD/TVD ratio.

Fig. 1Industry extended reach well drilling envelope. Case Study Main Drilling Challenges The case study well is an oil producer, planned to reach ~6800 m (22,300 ft) TD. The main objective is to drain the reserves located in an un-swept area of the reservoir that cannot be reached with conventional well profiles.

The plan called to build angle in the surface hole to 85 inclination and keep the sail angle close to the top of the reservoir, then turn around 60 in azimuth and drop to an inclination of 70. The drilling program required the intermediate casing to be landed at the top of the reservoir in the correct azimuth to maximize payzone exposure.

The critical well challenges included the ability to obtain sufficient and smooth build rates in a soft formation, and manage hookload, and torque and drag loads critical to the successful step out of the well.

To reach the payzone, the plan called for an 85 tangent along a faulted shale, then a turn of 60 in azimuth for proper reservoir intersection. This step out in the 12 -in. section required a perfectly tuned and balanced BHA; being able to drill for the first time in the area a 3,400 m (11,150 ft) tangent interval.

The third critical challenge was the narrow mud weight window, which based on the calibrated hydraulic model, was required to control ROP to keep the ECD in the safe operational window.

2.0

3.0

4.0

5.0

6.0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000

TVD,

ft

MD,ftERDIndustryEnvelopeMDvs.TVD

SperryERDMD/TVD2.0MD/TVD3.0MD/TVD4.0MD/TVD5.0MD/TVD6.0ERCaseStudyERDIndustryEnvelope

SPE/IADC 163485 3

Modeling and Planning The approach used to overcome challenges is the model measure optimize process, which focuses on integrated planning and execution activities to reach objectives and improve drilling efficiency.

The planning stage is critical for the success of any project. The comprehensive directional drilling plan was the foundation that described the road to reach the geological target efficiently. Using specific BHA simulators, the operational conditions were defined to determine the optimum parameters required to generate optimum ROP and BHA performance.

Hole enlargement in soft formations is a factor that can significantly affect BHA performance. Modeling was performed using different enlargement scenarios. In the build section, hole enlargement can be reduced by reducing the sideloads generated at contact points along the steering BHA. Sideloads generated at the bit by the steering system can be reduced and managed by adding contact points to the lower non-rotating housing. If hole enlargement occurs, the contact points on the lower housing will reduce the sideforce at the bit and limit the amount of hole enlargement that occurs. This modeling technique can be used to control hole enlargement when the formation compressive strength is lower than the side force generated by the drive system.

The BHAs were modeled using an analytical steady-state planning tool that simulates complex downhole dynamic conditions (Chen 2007). Well Trajectory The well trajectory corresponds to an offshore well with more than 1,000 m (3,280 ft) of water depth, a total MD around 6800 m (22,300 ft) and TVD of 2,700 m (8,860 ft). The well has a MD/TVD ratio of 2.5. Fig. 2 shows the well trajectory.

Fig. 2Extended reach well trajectory. Tool Geometry BHA modeling for the 17 -in. section indicated a need to tune the RSS tool geometry. An additional stabilization point was added to the conventional RSS configuration. This contact point at 1.44 m (4.724 ft) from the bit reduces the side load generated at the fulcrum point with the bit sleeve at 0.68 m (2.231 ft). The objective was to minimize the side force generated by the drive system, which in turn, avoids hole enlargement due to the low compressive strength of the formation at this shallow depth. Fig. 3 shows the BHA modeling for the 17 -in. build section interval.

4 SPE/IADC 163485

Fig. 317 -in. interval BHA modeling.

Similar criteria was used to the design the 12 -in. BHA, however the goal was not only generate minimum sideforces but also to maintain angle and direction in the tangent section with minimum deflection of the steering system. Again a stabilization point was used on the lower non-rotating housing to reduce hole enlargement. The geometry and deflection was optimized for the tangent section to produce neutral behavior and maintain the inclination with minimal steering. Balancing the loading on the BHA helps to reduce vibration and stress in the downhole tools which improves performance and longevity. Fig. 4 shows the BHA modeling for the 12 -in. tangent section.

Fig. 4Balanced 12 -in. BHA. BHAs Proposed The directional plan included tailored BHAs with a point-the-bit rotary steerable system and an extended gauge bit. The geometry of the RSS was adjusted to accomplish the objectives.

A sensitivity analysis using a model calibrated with offset wells was performed with different tool geometries and BHA components. Each BHA was modeled varying stabilization points, stabilization diameters, component positions, percentage of deflection, etc. The analysis had two main purposes:

To be able to generate continuous dog legs to follow the trajectory smoothly while keeping tool deflection capability in reserve.

To maintain the sail angle in the 12 -in. section with minimal tool deflection.

SPE/IADC 163485 5

After calibrating the tool response based on offset data; the model for the 17 -in. interval showed a 3.81/100 ft (~3.81/30 m) response. The calibration took into account the hole enlargement that often hampers build rate capability, and the hole size was estimated to be 17 7/8-in or a 3/8-in. overgauge hole. Fig. 5a shows the BHA response in a 3/8-in. overgauge hole.

Correspondingly, multiple simulations were performed to define the stabilizers size and position to drill the extended 12 -in. tangent section. The hole was estimated at 12 3/8-in. or 1/8-in. overgauge. In order to hold the 85 inclination, the model indicated the RSS would require a deflection of 30%. The BHA was precisely balanced to manage the natural drop tendency of the formation while keeping building capability in reserve. Fig. 5b shows the RSS deflection modeled to overcome the formation drop tendency.

Fig. 5a17 -in. calibrated BHA response. Fig. 5b12 -in. RSS deflection required. Execution During execution, the model, measure, and optimize approach calls for performance measurement and also for optimization based on the real-time data captured from sub-surface and surface sensors. The optimization process is part of a proprietary drilling performance workflow allowing the drilling team to use planning analysis and road maps to track the drilling process and adjust variables when required.

Using state of the art modeling tools, which include a newly developed generic algorithm allowed the team to deliver accurate drilling models. In addition, the point the bit RSS used was matched with a long gauge bit, it is an integrated drilling system that incorporate the bit into the BHA design. The bit included the correct features and steerability design for the intended application. The use of the matched drilling system also allowed the team to accommodate different attributes and tool geometry modifications to achieve the model requirements. BHA Performance The BHA proposed for all sections (17 -in., 12 -in., and 8 -in. x 9 -in. hole sizes) included a modified RSS configuration to overcome the challenges specific to each interval.

The build section was drilled flawlessly delivering an average of 3.5/100 m (~3.5/30 ft) from 3.2 to 3.8 matching the expected 3.81/30 m (~3.81/100 ft).

The 12 -in. BHA was able to maintain the sail angle with tool deflection on the order of 35%. No problems were experienced as the planned trajectory was followed with only a few deflection adjustments required to correct azimuth.

The production interval was drilled in the same way using RSS with adjusted geometry to overcome the trajectory challenges experienced in a soft formation.

The tools not only performed as expected from a BHA response point of view, but the optimization of the design allowed drilling of all sections casing-to-casing with no downtime while drilling.

During the time the paper was written a further refinement in the contact points and side force of the tool design has allowed delivery of a trajectory with higher dog legs (above 4/100 m) in the 17 -in. soft formation section, while retaining

6 SPE/IADC 163485

deflection in reserve. This capability has allowed the use of RSS in the shallow surface intervals offshore, typically drilled with motors.

The incorporation of RSS in big holes delivers smooth build sections in extended reach wells, bringing important benefits from a trajectory point of view:

Reduce the sail angle required in extended-reach drilling Reduce torque and drag, and facilitate faster, smoother tripping Allow access to farther reserves from the same platform

Fig. 6 compares two extended reach well trajectories; the red one using an RSS with high dog leg capabilities in large surface holes, allowing for a reduced sail angle, which in turn brings important benefits from the execution point of view as pointed above.

Fig. 6Benefits of high dogleg RSS in ERD. Survey Management Survey management is important for quantifying uncertainties around the surveyed well. In extended reach wells, survey management is fundamental because of cumulative errors at the point of hitting a geological targetlarge uncertainties severely constrain the available targets. Through better understanding of the error sources, uncertainties were reduced to ensure reaching the geological target.

Survey management techniques including misalignment between the survey tool and borehole axis, correction for magnetic interference, and for transient variations in the earths magnetic field were used.

SAG correction was used to account for the error in inclination measurements caused by the misalignment of the directional sensor in relation to the borehole. MWD azimuth data was calculated using In Field Referencing IFR, where the values for the magnetic declination angle, dip, and field strength were adjusted for local crustal anomalies. In addition, a more rigorous quality control of the raw data was performed through multi-station analysis; using proprietary software. The benefits were a significant reduction in positional uncertainty.

The IFR correction was applied automatically (in real-time) at the rig site, by using the values listed in the Well Survey Data Sheet. QC and multi-station analysis was conducted by a survey management team in real time. At TD the wellbore was positioned within 1 meter of the proposed location.

To overcome a collision risk, surveys were taken every 10m during the first 200m; the well was monitored from town while drilling below a separation factor of 2.0 and the survey management team was validating all surveys in real time.

ModifiedRSSforsoftformationConventionalRSS

Higher sail angle

Reduced sail angle

SPE/IADC 163485 7

Hole-Cleaning Management One of the main challenges in deepwater, which can generate high Non Productive Time (NPT) in the drilling process, is the narrow mud weight window. It is caused by the lack of formation compaction. Multiple unplanned events can be related to the narrow mud weight window and the ability to manage hole cleaning efficiently. This case was no exception. The challenge was addressed in the planning stage and the drilling road map included the lower and upper limit of the mud weight window. A sensitivity analysis was also performed to determine the maximum ROP allowed to keep the ECD within limits. An upper ROP limit of 50 m/hour was defined early in the planning stage. During execution, a further limit was required based on real-time data and live road maps.

Mud losses were experienced below the 13 3/8-in. casing shoe due to an excess of cuttings from cleaning out the rat hole. The mud weight was adjusted and drilling resumed. The well was drilled to TD with no additional loss events. The ROP was controlled to 30 m/hr while drilling practices were implemented to maximize hole cleaning.

A torque and drag road map was also used to monitor downhole drilling conditions and identify deviations from the normal trend. Fig. 7 shows actual pick up, rotating, and slack-off loads during drilling of the 12 -in. hole. Real-time monitoring allowed the team to make decisions regarding ROP, drilling parameters, and drilling practices to ensure proper hole cleaning.

Fig. 7Real-time T&D road map. Vibration Analysis Vibration is one of the main dysfunctions of the drilling process, accounting for a large amount of tool failures. This condition can be more severe on high angle and extended reach wells.

In the planning stage, it was necessary to model the dynamic conditions of the BHA and determine frequencies that could exacerbate detrimental downhole vibrations.

Fig. 8 shows critical RPM vs. WOB for the 12 -in. interval. Due to the complex well trajectory only a few places allowed a safe RPM. The yellow area was the target area where RPM would not cause resonance of the BHA.

8 SPE/IADC 163485

Fig. 8Dynamic BHA modeling with safe drilling parameters window.

No vibration issues were experienced in the 17 -in. build section. Standard drilling practices were applied and close

monitoring of real-time vibration kept the RPM within the green zone the entire run. Drilling the 12 -in. extended interval, stick-slip vibration occurred. The cause of the stick-slip vibration was the

interaction of the drill pipe tool joints lying on the long 85 tangent. A TEM (torsional efficiency monitor) sensor was used to continuously monitor stick-slip and interactive software helped to identify the mechanism of vibration and recommend mitigation (what changes to make to the drilling parameters to keep the RPMs at least in the yellow zone). The best place was between 180 and 200 RPM and this continued until TD of the section. Fig. 9 shows the downhhole RPM measured at the rotary steerable system while drilling 12 -in. step-out interval. The figure shows in blue the average RPM along the interval; also shows acceleration and deceleration data points in red (Minimum and maximum RPM values). The higher frictional torque along the length of the wellbore reduces the amount of energy reaching the bit, generating drillstring torsional vibration. Drilling parameters were tuned to overcome stick-slip events and smooth the drilling process.

SPE/IADC 163485 9

Fig. 9Downhole RPM while drilling.

Data from downhole sensors was monitored in real time. Vibration sensors that can identify lateral, axial and torsional

vibration diagnose the correct vibration generation mechanism; also some suggestion solutions are displayed to mitigate the vibrations. Fig. 10 shows a typical real-time vibration monitoring screen.

Fig. 10RT vibration monitoring.

9.5

11.5

13.5

15.5

17.5

19.5

21.5

50 100 150 200 250 300 350 400 450 500

MeasuredD

epth,K

ftDownHoleRPM

RSSDownholeRPM 121/4"HoleSize

GPRPMAVERAGEGPRPMMINIMUMGPRPMMAXIMUM

10 SPE/IADC 163485

Despite the stick-slip dysfunction and unstable formations causing momentary pack-offs, the BHA modeling and the implementation of the model measure optimize process were the key for the BHA to last until TD of the 12 -in. section; which took 115 drilling hours.

The 8 -in. section as well as the 12 -in. section experienced stick-slip vibration. Drilling parameters were adjusted to 200 RPM which lowered the stick-slip vibration from severe to moderate. Although the BHA was balanced and matched with an extended gauge bit, the vibration phenomena still occurred during the last two intervals. However, the team was able to manage the vibration levels and avoid catastrophic tool failures. Conclusions

The challenges faced on the case study ER well were surmounted by exceeding expectations and achieving the drilling objectives.

The critical path to execute flawless drilling was to use an analytical steady-state planning tool that simulates complex downhole dynamic conditions for each proposed BHA.

The modelmeasureoptimize process was paramount not only to planning, executing, and measuring performance but also for optimizing drilling based on real-time data captured both from the sub-surface and the surface.

BHAs used for all sections (17 -in., 12 -in. and 8 -in. x 9 -in.) employed a modified RSS configuration to overcome the challenges specifics for each interval.

The team was able to manage the vibration levels and avoid catastrophic tool failures. References Bailey, J.R. et al. 2008. Drilling Vibration Modeling and Field Validation. Paper SPE/IADC 112650 presented at the 2008 IADC/SPE

Drilling Conference, Orlando, Florida, USA. 4-6 March. Chen, David C-K. 2007. Integrated BHA Modeling Delivers Optimal BHA Design. Paper SPE/IADC 106935 presented at the SPE/IADC

Middle East Drilling Technology Conference and Exhibition. Cairo, Egypt, 22-24 October. Dow, Michael et al. 2011. Introduction of a Modified Rotary Steerable System in Papua New Guinea Improves Drilling Performance in

Poor Quality Wellbores with Tectonic Breakouts. Paper SPE 147809 presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, 20-22 September.

Stuart, D. et al. 2003. New Drilling Technology Reduces Torque and Drag by Drilling a Smooth and Straight Wellbore. Paper SPE/IADC

79919 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 19-21 February.