DRILLING '98

New drilling technologies optimize North Slope wells

Operator/contractor drilling team for ARCO/BP’s North Slope fields designed new techniques and improved conventional methods to cut well costs and open previously inaccessible reservoirs

Jeff Allison, Drilling Engineering Manager, Sperry-Sun (Alaska District); and David Nims, Drilling Operations Manager, BP Gulf of Mexico, Houston*

* (Formerly Drilling Superintendent with BP/ARCO’s Arctic Shared Services Drilling Group, North Slope.)

escribed here are several examples of how the Shared Services Drilling team of two major North Slope operators and service company contractors joined forces to meet challenging downhole drilling conditions in North Slope fields. New techniques of Through-Tubing Rotary Drilling with 3-3/4-in. bits in 4-1/2-in. tubing, and a new high-torque motor are illustrated with several well examples.

This work was expanded to drilling of 4-1/2-in. holes through 5-1/2-in. tubing to establish record length horizontal sections. And further efforts to optimize conventional drilling with steep turns and dips to open elusive payzones are covered, using Well P-26 as an example illustration.

Economic Drilling Target

Within the last couple of years, there has been renewed optimism regarding the long-term outlook for oil production from the North Slope of Alaska. This area, Fig. 1, represents about 25% of total U.S. domestic oil production. North Slope production, which began a decline in 1988, has been predicted by industry participants to bottom out sometime next year (1999) and then stabilize or even rise. Sources at ARCO and BP, two of the North Slope’s largest property owners, with both companies’ drilling services now directed under a merged department called Shared Services Drilling (SSD), were quoted in early 1997 as saying "Internal cost-cutting and development of new cost-reducing technology have made it profitable to pump oil that previously did not pay its way."

One of the service companies that, since August 1996, has been participating in a performance-based risk/reward contract for a percentage of the Shared Services Drilling MWD and directional drilling work is Sperry-Sun, a Division of Dresser Industries, Inc. According to sources within SSD, this service company has a solid foundation of technology and innovation, enabling these four elements, that make drilling in the North Slope economic, to be feasible:

1. reduced drilling costs,
2. accessibility of previously inaccessible payzones,
3. accessibility of multiple payzones within one well, through what are known as "designer wells," and
4. avoidance of troublesome zones, thus saving liner settings.

A hurdle rate of U.S. $2.50 per barrel drilling costs must be maintained. Thus, for a typically expected one million barrels of reserves, drilling costs must not exceed U.S. $2.5 million per well, or multiple targets must be successfully accessed.

The North Slope is much like other areas of the world regarding reservoir differences and field status, varying from unexploited to severely depleted, thus requiring a variety of different techniques to cost-effectively drill and produce. The following delineates some techniques used, with case histories to illustrate them. These techniques have helped fuel the continued optimism regarding the North Slope’s future.

Through-Tubing Rotary Drilling (TTRD)

Use of this technique eliminates costly completion work, reducing drilling costs as much as 30 to 50% vs. traditional drilling costs, through the use of smaller-capacity rigs, reduced tubulars, reduced volumes, as well as less waste generation and its consequent disposal costs. Typical well costs using this technique are in the range of $1 million to $1.5 million.

TTRD, a technique that offers an alternative to coiled tubing drilling, achieves this significant cost reduction through the drilling of a sidetrack well through an existing well’s completion tubing. The technique was given a BP Technical Achievement award, for successful achievement of a planned process that had never been used.

Small-diameter, 3-3/4-in. holes. The first North Slope TTRD well was C-23A, in which a total 1,709 ft of 3-3/4-in. hole was drilled with 3-1/8-in. tools and 2-7/8-in. and 2-3/8-in. high-torque drill pipe through 4-1/2-in. tubing. The well was part of a pilot program conducted in the Prudhoe Bay Unit (PBU), comprising four producing wells in this hole size.

Technology was further pushed with Well 17-19A, which was a short-radius 3-3/4-in. TTRD horizontal well. It was planned and drilled at a 53°/100-ft build curve from 28° inclination, with a 30° azimuth turn, which enabled SSD to access a reservoir that was within a very narrow TVD window. The well drilled nearly 3,000 ft of horizontal section, using geosteering via gamma ray throughout the horizontal section to keep the wellbore in the most prolific sand.

Drilling this well highlighted the huge difference in success rates, vs. those achieved using small tools in previous jobs, with the relative ease in tackling daunting dogleg severities and drillability beyond short-radius curves. The technique allowed more well planning flexibility and consequently increased the number of reservoirs considered accessible.

High-torque power motor. Based on successes of the TTRD pilot projects in Prudhoe Bay Unit, the Endicott Asset Team proposed drilling the costly and difficult Endicott field utilizing the same technique. From lessons learned in the PBU, Sperry designed a 3-1/8-in. SPERRY DRILL Performance Power Section Motor to create greater downhole torque, which allowed SSD to more aggressively pursue ROP targets and effectively handle the tortuous drilling nature of Endicott fields. With its 69-hr trial run without a failure, and without previously seen high levels of vibration (which increase failure rates on sensitive electronic components), the motor proved itself on Well 3-17C/M-31, the first Endicott 3-3/4-in. TTRD well.

Drilling 4-1/2-in. hole. Subsequent TTRD programs were injector wells in 4-1/2-in. hole through 5-1/2-in. tubing using 3-5/8-in. drilling tools with 2-7/8-in. high-torque drill pipe. The short-radius nature of these smaller tools enabled emphasis to be placed on accessing reservoir areas previously out of reach to conventional directional drilling tools and techniques.

Bit selection consisted almost exclusively of PDC bits in an effort to increase time on bottom drilling, as tripping in this hole size is purposely slow due to the inherent swab and surge pressures associated with small hole sizes. The PDC bits required high torque output motors while simultaneously keeping vibration to a minimum to maintain electronic integrity in the MWD tools, an environment in which the new power section motors perform well.

Well R-25Ai, which was the first 4-1/2-in. North Slope TTRD well, was successfully drilled (and under budget), with a TTRD motor run of 66.5 hr. The SOLAR 175 MWD tool, designed specifically with the robustness required for smaller hole size, high-vibration environments, was used, along with a 3-5/8-in.-OD motor. The 2,850 ft of hole was drilled in two BHA runs, the first being a North Slope record of 1,770 ft in 38 drilling hours.

The wellpath of this injector well was a 2-cycle sinusoidal curve which varied vertically by more than 100 ft. To drill this profile, the lateral inclinations varied from 76° to 99°. TD of the well was 13,115 ft MD and 8,784 ft TVD. Average doglegs varied between 15° and 18°/100 ft. This well proved the viability of sinusoidal injector wells for better sweep efficiency drillable via TTRD technology, thus saving the operator significant drilling costs.

Measured depth record. The technological envelope continued to be pushed with Well R-05A, a 4-1/2-in. hole, sinusoidal (2-cycle) injector well, setting a North Slope record in MD of TTRD section drilled of 3,983 ft. Total depth for the well was 12,950 ft, with a TVD of 8,810 ft. The profile began at 11°, then built to as high as 104° of inclination, with a total azimuthal change of 188°. Total sinusoidal TVD change from landing point to TD was 176 ft. Doglegs were between 25° and 33°/100 ft. This TTRD plan placed a sinusoidal injection well below the pad, accessing previously unreachable reserves.

A further example well, R-32Ai, broke another record in drilling 5,189 ft of hole beyond the whipstock, 4,930 ft of horizontal section, and by being the first North Slope TTRD well allowing the intersection of two target blocks. The short-radius well (35°/100 ft doglegs) was again a sinusoidal injector, with a 40° azimuth turn 2,600 ft into the horizontal section. The final measured depth of this well was 16,894 ft.

Conventional Drilling Optimization

In addition to the innovations detailed above, time and cost reductions were also achieved while setting new technical benchmarks, not with new techniques but through such common sense approaches as highly focused well planning, use of highly competent operator/technical personnel, fit-for-purpose equipment and tools, and an inherent confidence in a mutual ability to produce results.

The results far exceeded historic benchmarks. For example, Well 11-38 has the distinction of being the lowest cost-per-foot (at $138/ft) Prudhoe Bay horizontal well to date. Another example is Well P-26, with 5,809 ft of 6-in. lateral section — the North Slope lateral section record, Fig. 2. Four targets were penetrated horizontally, requiring a 138° azimuthal change in the lateral section of the wellbore. Geosteering was required in this lateral section, successfully accomplished with good BHA selection and "Dynamic well planning"; which means that, as the wellpath was being geosteered, it was constantly analyzed and optimized for predicted BHA responses.

Sharp wellpath turn. Another well, Y-09A, is a showpiece in Shared Services’ continuing "Designer well" program because it allowed an extended directional lateral section to successfully intersect multiple horizontal targets, thus greatly enhancing well production. About 3,600 ft into the lateral section, the wellpath was turned more than 70° using 30°/100 ft dogleg severities.

Such a high dogleg severity had never before been accomplished on the North Slope so far out in a horizontal section. This achievement allowed Shared Services to intersect an additional desirable target polygon. Following the 30°/100 ft turn, more than 1,300 ft of reservoir was accessed and geosteered to TD. The 6-in. production horizontal section of this well totaled 5,122 ft.

Steep inclination drop. The ability to access reserves via sidetracking directly beneath drill pads, close to parent wellbore fault blocks, or perpendicular to the existing wellpath is also important to ensure maximum flexibility in exploiting reserves cost-effectively. Well 18-08A accomplished the most aggressive wellpath drop in North Slope history, reducing angle to 4° from 38° of inclination using short-radius 25° to 30°/100 ft drop rates. After the low angle was achieved, the wellpath was built to 98° of inclination while turning a total of 204° azimuthally, thereafter leveling out to 90°; this was also done using short-radius build/turn rates of 25° to 30°/100 ft.

Abrasive, unstable zones. The ability to cost-effectively conquer the technical challenge of an abrasive conglomerate or an unstable zone is also necessary in the continued successful exploitation of the North Slope environment. For example, Zone 3 in the Prudhoe Bay Unit has traditionally been a very abrasive conglomerate zone that reduced a BHA’s DLS potential, rendering predictability poor.

Prior to the Sperry contract award, Zone 3 was designed and drilled as a tangent section, severely reducing well planning options for effective reservoir management. The contractor and SSD reached consensus on attempting a short-radius build through this problem zone based on the success the contractor has had in both predicting and drilling Zone 3. The SPERRY DRILL 2.0 stage Ultra Slow Speed motor was used to successfully drill a 25°/100 ft build rate through Zone 3 on Well H-16A. The slower rpm of this and other specially designed motors has extended bit runs in this zone and allowed drilling in similarly abrasive formations with reduced bit wear/damage, resulting in lower costs.

This achievement adds value to the concept of aggressively drilling Zone 2 targets (directly below Zone 3) without the threat of Zone 1 penetration in the event of water encroachment, thus adding to recoverable reserves. In addition, being able to perform directional work in a zone previously limited to straight-hole drilling, the doglegs required for performing entire build/turn curves have been reduced, thus allowing for greater use of steerable (rotatable) assemblies. With the Zone 3 drilling initiative firmly in place, a minimum of two assembly trips are saved by directional drilling through this previously tangent section zone.

An example unstable zone is the Kingak Shale, also located in Prudhoe. The original plan of the 13-02B wellbore was to drill through the Kingak and attempt to land and drill horizontally with the shale exposed. This proved unachievable on several attempts, thus requiring an alternate way forward.

A plan, which involved drilling through the shale with pipe set immediately through the base at a 45° inclination in 8-1/2-in. hole, was mutually developed. Then a 6-in. hole size utilizing a 40°/100 ft build rate was drilled immediately out of the 7-in. casing shoe to land in the target Sag River formation, immediately below the Kingak. This technical achievement adds several Sag River formation possibilities to available reserves.

Conclusion

As is evident, the consistent technical innovation — as well as aggressive well planning and optimal decision-making while drilling — required to deal with the rigors of the North Slope downhole environment helped enable Shared Services Drilling to access reserves otherwise deemed inaccessible, cut drilling costs and deal with troublesome formations. The contractor has played a key role in these achievements, as well as maintaining a record of reliable adherence to environmental regulations protecting the North Slope, thus aiding the continued successful exploitation of this major U.S. resource.

Acknowledgment

The authors wish to acknowledge the contributions of the following personnel in the Sperry-Sun Alaska District: Ken Broussard, Gordon Hecht, Mike Ross, Mike Teel, Jim Brown, Sonny Hoburka and Scott Crosby.

The authors

Jeff Allison, drilling engineering manager, Sperry-Sun, a Division of Dresser Industries, Inc., Alaska District, earned a BS degree in petroleum engineering from Colorado School of Mines. Before being appointed to his present position, he served as integrated solutions area manager, Asia-Pacific Region, drilling engineer, and company representative for Conoco in the Gulf of Mexico, Alaska and Dubai. Mr. Allison is a member of SPE.

David Nims, drilling operations manager, BP Gulf of Mexico, Houston, graduated from Glasgow College of Science & Technology. Before moving to his present position, he was drilling superintendent with BP/ARCO’s Shared Services Drilling group on the North Slope. Formerly, he was with Britoil/BP’s UKCS E&A drilling group. Before that, he was with Shell in drilling operations in the Netherlands and Brunei, then moving to Shell International (SIPM).

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company