Total drills extended-reach record in Tierra del Fuego

Located at the southern tip of South America in Tierra del Fuego, the Cullen Norte No. 1 set a world record 10,585 m of horizontal displacement, reaching a TD of 11,184 m in March 1999. Forasol's Rig No. 1625/3, on location facing the South Atlantic Ocean, uses a variety of innovative extended-reach drilling technologies, including a horizontal pickup-laydown machine and cuttings-weighing equipment (Fig. 1).

By combining innovative technologies, learning experience,¹ and a slim-hole well configuration, these companies saved $3 million, or 20% of the originally planned costs for this 11,184 m (36,693 ft) long well.

This first of a two-part series describes the innovative technologies and well-design configuration used on the Cullen Norte No. 1 well. These innovations include the first use of an onshore horizontal laydown-pickup machine and the refitting of small-diameter drill pipe and tubulars with high-torque, wedge-thread pipe connections.

The conclusion describes other downhole and surface technologies, including polycrystalline diamond-compact (PDC) bit selection, subsurface data gathering, cuttings-weighing equipment, and pertinent operational details that helped achieve this world record.

Extended-reach history

Because of the success of these wells in terms of cost and production, a seven-well onshore campaign was initiated from mid-1997 to late-1998 to develop oil and gas accumulations in the Ara and Kaus fields.² Three of these wells reached at least 8,000 m (MD) while the next to last well, the Cullen Sur No. 1 (CS-1), reached a TD of 8,687 m MD (8,107 m HD) in 83 days.

The confidence gained through the engineering and technology achievements of these wells led Total and its partners to drill the Cullen Norte No. 1. After 3 months of fast-track engineering and procurement, this well was drilled and completed in 142 days, including a geological sidetrack.

Smart-and-slim program

However, to extend the well depth in terms of horizontal displacement and total depth, it would have been necessary to upgrade the top drive while adding rig power, pump capacity, and 3,000 m of 65/8-in. drill pipe. The costs for this option were high and nearly prohibitive for the project.

The second and more viable option consisted of drilling the well using a slim-hole well architecture consisting of 171/2, 121/4, 81/2, and 61/8-in. hole sections.

Well profile study

It also meant, however, that a very long 121/4-in. slant section would have to be drilled. For example, the CS-1, located 14.4 km southeast of the Cullen Norte No. 1, included a 6,773 m MD slant section with inclinations up to 83°. This lengthy section significantly increased the risk associated with long-term, open-hole conditions.

To reach the pay zone in the Cullen Norte No. 1, using the same program, it would have required a 9,500-m MD, 84° slant section. In this case, the partial floatation technique-a process where the 95/8-in. casing is run in partially empty with the bottom section unfilled-would have reached its limit in regards to pushing the casing to TD.

At the same time, the power and pump-pressure requirements needed to achieve optimum hole cleaning for the 121/4-in. section would have required an upgrade of the rig's equipment.

A viable alternative

1. Drill a 5,000-m, 121/4-in. slant hole section with an inclination of 81°. Run a 95/8-in. casing string across this interval.
2. Drill a 4,000-m 81/2-in. slant section with an inclination of 88°. Rotate a 7-in. liner to TD.

Torque-and-drag simulations show that this is the case for well trajectories with an HD/TVD (true vertical depth) ratio under 3.5. Above this ratio, the ERD (extended-reach drilling) domain begins, after which it becomes necessary to use specialized techniques to continue drilling operations.

The only known way to run a casing or drill-pipe string in such an environment, where conditions of friction, torque, and drag impede drilling progress, is through rotation, a mode which allows string weight to be transmitted to the bottom of the assembly instead of losing it through axial friction.

Unfortunately, some strings cannot be rotated because of the configuration, including completion strings that have packers, eccentric side-pocket mandrels, and control lines. Past a certain point, rotation is impossible for certain heavy casing sizes and large ODs where the torque required to rotate the tubulars can exceed the top drive limit or the makeup torque of the connection.

Therefore, in the new well design, it was decided to set the 95/8-in. shoe so that its departure would respect the condition of HD/TVD = 3.5 (Fig. 4, Line A) [124,989 bytes]. The TVD for this application was given by other constraints, including the optimization of production parameters that require the placement of the gas-lift mandrels as close as possible above the reservoir-in terms of TVD, not MD.

This is especially important in regards to the geophysical uncertainty and bottom-hole assembly (BHA) behavior that may result in penetrating the reservoir before the given departure reached its objective. Therefore, the second 181/2-in. slant section had to maintain a sufficient TVD margin above the reservoir with enough relative incidence to accurately approach the reservoir.

An inclination of 88° was found to be a good compromise in this situation, with the intersection of Lines A and B in Fig. 4 reflecting the optimum setting depth for the 95/8-in. casing string. This trajectory also allowed for a respect of local geological constraints, especially when dealing with the Inoceramus Superior shales that tend to generate serious stuck-pipe events.

These zones could be crossed at a lower angle than usual (81° instead of 84°), providing conditions of improved well-hole stability. Furthermore, this allowed casing to be set across the 121/4-in. open hole section much quicker, the result of a shortened hole section.

The second slant section drilled the more resistant Margas Verdes formation, usually in gauge as compared to the upper formations. The progressive build-up section was drilled with a small dog-leg severity (DLS) of 3°/30 m maximum, allowing the natural tendency of the formations to keep it smooth.

Wedge threads

Unfortunately, the clearance requirements for slim-hole drilling, combined with the extreme structural requirements of extended-reach drilling, limited these choices. The Hydril Series 500 wedge thread connections presented the optimum design for both 4 and 23/8-in. drill pipes sizes in addition to the 7 and 5-in. liners. The high-torque resistance of these connections is developed through the simultaneous engagement of the opposing flanks of the dovetail wedge thread.

These connections allow the torque strength to become independent of the tool joint's OD, thus allowing for a relatively small OD (Fig. 5) [30,311 bytes]. Consequently, torque, annular pressure losses, and the equivalent circulating density were proportionally reduced.

For casing strings, the streamlined OD in the running and circulating direction avoided the bulldozer effect that can occur on the residual cuttings bed (cutting that pile up on the bottom portion of the slanted hole), eliminating the coupling-face hang-up effect normally encountered under slim-hole conditions. In addition, because the torque strength is not limited by the thickness of the last engaged pin thread, a large ID is maintained through the tool joint, resulting in improved hydraulic efficiencies.

While running liners are under rotation, the thread flanks provide a positive torque stop. This prevents the excessive makeup from over-torque that can be generated while rotating during a cement job.

At the planning stage, torque-and-drag simulations show that the torque on top of the 4,000-m long 7-in. liner could reach 25,000 ft-lb. The confidence in the design of the H521 connection allowed for an increase in the admissible torque.

A 1.5 safety margin on the yield torque was established, allowing for a maximum torque value set at 31,000 ft-lb. However, the thin No. 23 N80 pipe thread for the liner did not allow the possibility of making-up connections to the full planned torque setting. This is because the tongs could distort the pipe, causing a restriction or gross failure of the pipe body. On the other hand, downhole makeup resulting in increased torque on the tool joints is acceptable.

For the drill pipe, a tapered, two-step thread profile, introduced in 1993, allowed a wide range of makeup torque, up to 31,500 ft-lb in this case. On one occasion, during the 61/8-in. phase, unplanned downhole conditions forced the operator to exert the maximum available torque on the entire drillstring. After this event, while pulling out of hole, the 4-in., No. 14, S135 WT38 pipe thread connections had to be broken out with up to 50,000 ft-lb of torque, considerably above and beyond the recommended torque yield.

After pulling the pipe, however, string inspection revealed no damage to the connections and it was re-run. For this level of torque, the slim dimension of the 43/4-in. OD, 29/16-in. ID tool joints were key components used to reduce pressure losses while drilling extended-reach hole sections.

Pipe storage

For example, across the 121/4-in. hole section, the CS-1 was drilled to 7,792 m MD, using 5,000 m of 65/8-in. drill pipe. The larger tool joints consequently reduced the overall amount of pipe that can be racked back in the derrick.

Initially, the Forasol 1625/3 featured a racking board that could only hold 5,300 m of 51/2 and 65/8 in. mixed drill pipe. Beyond that depth, however, it became necessary to makeup and lay down pipe sections as single joints. This generated lost time and additional costs.

Furthermore, the lengthy procedures associated with this work resulted in a high-risk well situation by keeping the hole open for a longer period of time. Safety implications resulting from repeated makeup and break-out operations were also of high concern.

At this point, the manufacturer of the mast was asked to reconsider its engineering analysis, taking into account the constant strong winds of Tierra del Fuego. The fingerboard was finally modified for a maximum capacity of 7,900 m, certified for 150 km/hr wind gusts at full load.

Yet again, despite these efforts, the need to drill even longer wells, in this case the Cullen Norte No. 1, surpassed even this expanded racking capacity.

Lay-down machine

In summary, the hole sections leading up to 171/2 in. required 65/8-in drill pipe. For the 121/4-in. hole section, both 51/2 and 65/8-in. drillstring were needed. Across the 81/2-in. hole section, both 51/2 and 5-in. drill pipe were required. Finally, the 61/8-in. hole section required the introduction of mixed 4 and 51/2-in. drill pipe.

For an extended-reach well, changing out 121/4 to 81/2-in. drill pipe can take up to 3 days. To overcome space limitations associated with the mast, Total wished to build a pickup-laydown machine for the safe and rapid handling of horizontal stands between the pipe racks and drill floor (Fig. 6). After a preliminary in-house design, the realization was left to Forasol engineering group. Although this equipment exists on floating rigs, onshore applications for such a technology were unheard of by this opeator.

Furthermore, land-rig systems required a dedicated design that must consider technical and logistical issues such as rig moving and rigging-up operations in remote areas like Tierra del Fuego. And last but not least, the overall cost had to be kept proportional to the day rate of the rig itself.

The machine was installed on the Cullen Norte No. 1 location, the first well to prove the validity and efficiency of both the concept and the design. The machine provided an alternative method for dealing with the mast's inadequate storage capacity, surpassing the fingerboard capacity with almost no limitation while circumventing problems associated with strong wind conditions.

The specific site conditions related to clustered well locations allowed stands to be laid down and stored in an accessible position for the next slot. The machine was also designed to handle casing, generating the same safety attributes as before, while introducing the benefits of handling doubles in place of singles.

Manipulating the drillstring stand by stand instead of in single sections resulted in an 80% time saving. In addition, further time and cost savings were achieved through the addition of equipment that could makeup and break out the stands horizontally at the yard instead of occupying drill floor and rig time.

Some specific geographical or road conditions would also allow moving drill pipe made up as stands between locations, further reducing cycle time and the effort involved with the drilling process.

Acknowledgment

The authors wish to thank Total SA and its Cuenca Marina partners-Pan American Energy and Deminex-for permission to publish this article. They also wish to thank all the participants in the project, especially the company men, rig site engineers, mud engineer, drillers, and directional drillers who helped to make this well a success.

References

1. Millheim, K., et al., "An Example of the Drilling Analysis Process for Extended Reach Wells," SPE paper 49111, prepared for the SPE Conference (cancelled), New Orleans, Sept. 27-30, 1998.
2. Soden, D., Delahaye, T., and Haegel, M., "Con pozos direccionales Total Austral perfora yacimiento marino desde tierra," Revista Latinoamericana, May/June 1998, p. 26.

The Authors

Roland Vighetto is the ERD project manager for Total in Rio Grande, Tierra del Fuego. Since 1977, he has worked as an on-site company man and on several R&D projects in Paris where he was involved with computing, rig-automation, slim-hole drilling, directional, and horizontal drilling projects. Vighetto has been working in the operation's side of the business for 6 years now and holds a BS from the Ecole Superieure du Petrole et des Moteurs in Paris.

Matthieu Naegel joined Total in 1993 and was the senior drilling engineer during the Tierra del Fuego onshore ERD project. He has held various positions in drilling operations and R&D. Naegel graduated from Ecole Nationale Superieure des Arts et Metiers in Paris and Ecole Nationale Superieure des Petrole et Moteur in Paris.

Emmanuel Pradi? was assigned to the ERD project of Tierra del Fuego 2 years ago, as a drilling engineer. After spending 1 year on the rig site, he is now in charge of the ERD operations. Pradi? graduated from the Ecole Nationale Superieure d'Ing?nieurs d'Hydraulique et de M?canique de Grenoble, France.

Copyright 1999 Oil & Gas Journal. All Rights Reserved.