Drilling Report

Advanced drilling technology benefits mature field

The straight-hole drilling technology, combined with a new bit design, reduced casing wear while improving torque, drag, cementing operations and ROP, thus saving the operator over $150,000.

Gary Poulain and Dave Winchester, Chesapeake Energy Corp.; Sandeep Janwadkar, Baker Hughes OASIS; Matthew Isbell, Hughes Christensen and Wolfgang John , Baker Hughes INTEQ

Highly complex and faulted geology in southern Oklahoma, coupled with the high dip angles, creates a challenging drilling environment. The inclination-building tendencies of these formations compel operators to use a steerable motor with a bend angle to construct boreholes that are intended to be nearly vertical. To address these issues, Chesapeake Energy recently applied VertiTrak (VT), a sophisticated straight-hole drilling device, together with a new-style, reduced-exposure Genesis PDC bit, to enable the operator to save considerable rig time and increase ROP while delivering quality wellbores, resulting in minimal casing wear, reduced torque and drag, and improving casing-cement jobs.

BACKGROUND

Drilling the 12-1/4-in. hole section on the Emmons 2-1 saved the operator five days of rig time, which translated into about $154,000 saved. Building on this success, Chesapeake applied the new BHA combination to drill the Barbara 1-18, which enabled the operator to drill the entire 8-3/4-in. hole section on the Barbara 1-18 with one bit, thus saving 3.6 days of rig time. The record 7,940-ft section was drilled by a single Hughes Christensen Genesis PDC bit at an average ROP of 33 ft/hr, resulting in a net savings of $73,000 relative to the cost of the offset well.

The following two wells were drilled in Caddo County, Oklahoma. They demonstrate the favorable results achieved due to offset well analysis, planning, implementation and the use of high-end drilling technology to solve specific challenges in this mature area.

Case study 1. The following information is provided as background reference for drilling the 12-1/4-in. hole sections in several offset wells. The 17-1/2-in. surface hole was drilled to a depth of about 1,000 – 1,400 ft, followed by the 12-1/4-in. section that typically bottomed around 9,800 – 12,300 ft. In most cases, inclination reached 8° over the 12-1/4-in. section, Fig. 1. Directional drilling assemblies reduced wellbore inclination but resulted in dogleg severity (DLS) reaching 4°/100 ft. Additionally, up to four bits were required to drill the 12-1/4-in. interval from 3,500 – 8,300 ft further inflating the cost/ft. Best offset ROP was 40 ft/hr.

Fig. 1. Inclination and DLS plots of Emmons 2-1 and Offset Well 1.

The 17-1/2-in. surface hole section on the Emmons 2-1 was drilled to 3,565 ft, then a 9-1/2-in.-OD VT with a 12-1/4-in. HCM406 PDC bit was picked up. The BHA drilled 4,794 ft of 121/4-in. hole section down to 8,359 ft with the following results. The VT/PDC bit combination significantly reduced inclination and dogleg severity to just 0.41° and 0.2°/100 ft, respectively, while increasing the average penetration rate to 46.5 ft/hr. The new system also reduced torque/ drag and delivered a smooth wellbore, totally eliminating costly correction runs while reducing the number of bits required to complete the hole section. This increase in performance saved the operator five days of rig time for a net savings of $154,000 relative to a three-well offset average, Fig. 2.

Fig. 2. Plot of drilling time versus measured depth of Emmons 2-1 and offset wells.

Case study 2. The following story outlines the challenges encountered while drilling the 7-7/8-in. hole section in the offset well. Wellbore construction began with the 12-1/4-in. section bottoming at 1,215 ft. However, while drilling the 7-7/8-in. portion of the well, inclination climbed to 12.2°. The operator attempted to control the increasing deviation with a directional drilling assembly, but dogleg severity increased to 2.8°/100 ft, Fig. 3. Further exacerbating the inclination issues, the bent housing assembly decreased ROP to just 12 ft/hr. It also took six bits to reach the 7-7/8-in. hole section at 9,194-ft TD.

Fig. 3. Inclination and DLS plots of Barbara 1-18 and Offset Well 1.

On the Barbara 1-18, the operator drilled the 12-1/4-in. hole section to 1,210 ft, and then picked up a 6-3/4 -in.-OD VT with a 8-3/4-in. HCM406Z PDC bit. The maximum inclination in the 8-3/4-in. hole section was 0.83° with a DLS of 0.8°/100 ft. Additionally, the PDC/VT BHA drilled the entire 8-3/4-in. hole section (1,210 – 9,150 ft) in a single run, with only one PDC bit, Fig. 4. The 8-3/4-in. HCM406Z drilled a total of 7,940 ft, setting a new single-run footage record for the area. The VT was run for 249.25 hours, which was a new world record for the 6-3/4-in. VT.

Fig. 4. Plot of drilling time vs. measured depth of Barbara 1-18 and Offset Well 1.

MOTOR ASSEMBLY CHALLENGES

Although using a conventional directional drilling assembly decreases wellbore inclination, this approach still had several incremental drawbacks, including:

1. Higher dogleg severity (DLS) and wellbore tortuosity
2. Multiple bit runs, implying higher cost/foot
3. Reduced penetrations rates for correction runs to maintain a vertical wellbore
4. Increased torque and drag
5. Increased wear on drill pipe, rig, casing and production equipment
6. Higher risk of stuck pipe, twist off and drillstring failure
7. Increased chances of complications in deeper sections of the well.

The ability to effectively drill vertically for all or parts of the well has been a key objective. All subsequent operations performed in the well would be greatly simplified and the related costs both of drilling and subsequent workover operations would be significantly reduced. To improve upon the problems listed above, a team from Chesapeake Energy Corp. and Baker Hughes ( Oasis , Inteq and Hughes Christensen) developed a strategy.

A drilling optimization service conducted a detailed analysis of drilling performance, mud logs and wireline data from offset wells. This helped identify potential problems and led the operator to set objectives for drilling the well with the highest possible ROP while maintaining a near-vertical wellbore. To achieve these objectives, the operator elected to use the VT system and an HCM406Z PDC bit.

The system. The VT system consists of a single automated downhole tool and a surface control package that has the ability to drill a near-vertical well.^{1 – 8} It is also applicable in a wide range of economic scenarios. The benefits of this technology are now being realized in many areas where drilling a vertical well was previously considered difficult.

The three steering ribs of the system are located on the bearing housing of the downhole tool, Fig. 5. As soon as the inclination of the borehole exceeds zero degrees, the hydraulic cylinders on the high side of the VT tool are pressurized and press against the borehole wall and push the tool back to vertical. Due to the continuous steering process, local doglegs are minimized, producing a high-quality in-gauge wellbore. The steering process happens automatically, without interaction from surface, and without compromising optimum drilling parameters. WOB and bit speed can be adjusted and maintained to obtain optimum performance, while the independent hydraulic system and electronics keeps the well vertical. The sensors that measure hole inclination, downhole temperature, etc., are located in the sensor sub at the top end of the tool, Fig. 5.

Fig. 5. Components of the vertical drilling system/ BHA.

Highly faulted formations are often also highly stressed. The borehole walls can tend to break out if subjected to shocks from a rotating drill string. From caliper logs, engineers determined that borehole quality is often negatively affected by drillstring rotation. To minimize the destructive mechanical energy in the hole, the system was designed to run in the sliding mode, without string rotation.

Note that cuttings transport in low-angle wells is not assisted by string rotation. An X-treme downhole motor power section was integrated into the tool. This power section uses a new style pre-contoured steel stator tube, which is coated with a thin layer of elastomer, Fig. 5. It generates the equivalent output at a shorter length than a conventional “full rubber” cylindrical stator tub, making the system a compact, stand-alone drilling system.

There is also a “ribs-off” mode. Because some operations benefit from drilling cement out of a casing shoe or back reaming, the ribs of the VT tool can be retracted into the housing by applying a specific flowrate variation pattern from surface. The tool can then be switched back to the steering mode by another flowrate variation pattern. At the surface, the tool requires a standard setup, comprising a pressure transducer and a pulse decoding system, as is used for conventional MWD and directional drilling jobs.

These systems are available for hole sizes from 8-1/2-in. to 9 7/8 -in. (6-3/4-in. tool size) and 12-1/4-in. to 28-in. (9-1/2-in. tool size). Due to their modular design, the tools can easily be adjusted in the workshop to different hole sizes. The modular design also permits the use of different power sections on the tool. The offering includes high-speed power sections for impregnated bits in very hard and abrasive formations, high-torque power sections for PDC and standard roller cone bit applications, and low-speed power sections for use with roller cone bits in large hole sizes.

HCM406Z PDC. The drillbit was engineered to operate as a part of the overall system. The higher torque capability of the mud motor meant higher ROP potential if the bit could drill smoothly and without torque oscillation that would affect steering functions of the VT. The tool's steering function places significant side load on the bit for the entire run, and so the side cutting aggressiveness had to be matched with the control system of the tool to optimize system response. Torsional oscillation of the tool can affect the steering function.

A depth of cut control technology was used to engineer the bit's torque response to minimize oscillation and provide a smooth torque response to applied WOB. Basically, the exposure of the cutters above the blade are carefully adjusted so that, when ROP increases above a predetermined level, a bearing surface engages the hole bottom. At higher ROP, the bearing area increases exponentially while torque increases linearly.

Overall, the effect is that aggressiveness decreases suddenly after the depth of cut limit is reached. This approach also has the advantage of fully using an efficient, aggressive cutting structure while staying within the operating torque window of the tool. Gauge length was adjusted to provide both stabilization for the bit and support the side load applied by the tool, while maintaining adequate side cutting aggressiveness for deviation control.

Cutter technology also played a role in the performance improvement. Engineers determined that residual stresses in PDC cutters are a source of cutter failures. A new style, the Zenith, cutter was used in the HCM406Z that contains an interface between the diamond table and the carbide substrate. It has been engineered to break up the high residual stress concentrations from the portion of the cutter that see the highest service-induced stress. The cutter interface has improved the management of these stresses, which helps it to resist spalling and impact failures. They utilize the latest in the layered-diamond table technology and are manufactured using a patented process that allows for a top diamond layer to provide superior wear resistance at the cutting edge, and interim layers which provide for outstanding toughness and durability. The result is a sharp, efficient cutting edge on the cutter and a spall/ impact-resistant table.

CONCLUSION

The seven application-specific challenges posed by the complex geology of southern Oklahoma and listed in this article were effectively dealt with by careful engineering analysis, advanced drilling equipment and implementation of good drilling practices. The VT system and reduced-exposure PDC bit made a significant contribution in achieving those challenges. In addition, production was able to be brought on earlier than would otherwise have been the case. 

ACKNOWLEDGEMENTS

The authors thank the management at Chesapeake Energy Corp., Hughes Christensen and Baker Hughes INTEQ for their approval to publish the data. The authors also express their gratitude to Craig Fleming, Baker Hughes, for his valuable contribution in editing and compiling this article.

LITERATURE CITED

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³ Chur, C. and J. Oppelt, “Vertical drilling technology: A milestone in directional drilling,” paper presented at the SPE/ IADC Drilling Conference held in Amsterdam, The Netherlands, February 23 – 25, 1993.

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⁸ Al-Suwaidi, A. S., A. A. Soliman, Z. Klink, M. Isbell, M. Dykstra and C. Jones, “New PDC design process solves challenging directional application in Abu Dhabi onshore fields,” paper SPE 79796 presented at the SPE/ IADC Drilling Conference, Amsterdam, The Netherlands, February 19 – 21, 2003.