Coiled-Tubing Drilling: Continued Performance Improvement in Alaska
- Thomas M. McCarty (BP Exploration Alaska Inc.) | Mark J. Stanley (BP Exploration Alaska Inc.) | Lamar L. Gantt (Phillips Alaska Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2002
- Document Type
- Journal Paper
- 44 - 48
- 2002. Society of Petroleum Engineers
- 2.2.2 Perforating, 1.14 Casing and Cementing, 1.7.5 Well Control, 1.6.1 Drilling Operation Management, 1.6 Drilling Operations, 5.4.1 Waterflooding, 4.3.4 Scale, 1.11 Drilling Fluids and Materials, 1.6.7 Geosteering / Reservoir Navigation, 4.1.2 Separation and Treating, 1.3.1 Surface Wellheads, 5.1.2 Faults and Fracture Characterisation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 2 Well Completion, 1.6.2 Technical Limit Drilling, 1.10 Drilling Equipment, 2.4.3 Sand/Solids Control
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Coiled-tubing drilling (CTD) has thrived in recent years on the North Slope of Alaska. To date, CTD has sidetracked more than 250 wells in a continuous program of activity since 1995. In that time, Alaska has become a proving ground for CTD tools and techniques. CTD has matured into a highly efficient and economical means of sidetracking wells on the North Slope. Key reasons for the success of the program include continuous use, which allows rapid learning; a culture of technical innovation; effective performance-based service contracts; the right people with the right expertise; and the vision and support of senior management. This paper summarizes the performance improvements realized in North Slope CTD operations, detailing how the tools and techniques have changed.
Applying new technologies and improving existing tools are major levers of CTD progress. Major performance improvement areas include window milling, bottomhole assembly (BHA) reliability, and lost circulation. Reliability improvements in equipment and persistent innovation will continue to fuel CTD's underlying economic performance in Alaska.
Included in this paper is a discussion of the remaining problems associated with through-tubing, slim-hole drilling with CTD technology. Examples of new CTD technologies being used or about to be implemented in Alaska will also be presented.
There is no doubt that CTD has played an important role in mitigating the current decline profile of mature oil fields on the North Slope. CTD has primarily been used to sidetrack wells to small infill locations, targeting originally bypassed oil. Most of these wells would be uneconomic to attempt when drilled with traditional sidetracking techniques that use rotary rigs. In 2000, CTD completed 64 sidetracks on the North Slope at a cost averaging less than one-half that of conventional rotary sidetracks.
CTD was initiated in 1993 on the North Slope of Alaska. The experience gained in through-tubing sidetracking from 1994 to 2000 has no parallel anywhere in the world. (Refs. 1 and 2 provide additional historical perspective on CTD in Alaska.) In this time, the business of CTD has been sidetracking high-angle/horizontal wells through the production liner. The horizontal sections of these sidetracks generally range from 1,000 to 2,000 ft-md. Wells are completed with either cemented and perforated or slotted liners. The hole sizes drilled with CTD range from 2 3/4 to 4 1/8 in. CTD operations are typically performed through production tubing with sizes ranging from 3 1/2 to 7 in. The average cost to drill and complete a CTD sidetrack is approximately U.S. $1.2 million. Fig. 1 compares the volume of CTD work vs. rotary work on a well-count basis in the Prudhoe Bay oil field. The successful program is the result of many factors. North Slope operators have been highly supportive of the technology. Knowledge of equipment used and the continued tool development brought to the table from the contracting community have proven to be invaluable to the program's success. The people, program scope, and broad, long-term vision made the program what it is today.
Alaska is one of the few CTD areas of operations around the world that enjoys the luxury of a continuous program. Facing the routine of drilling and completion problems on a daily basis has fueled CTD technology innovation on the North Slope. Several areas of large technical challenge have been targeted and improved upon by the necessity of developing tools and techniques to enable the successful use of CTD in the various types of wells that are drilled on the North Slope. Key areas of challenge for the CTD program have been through-tubing window milling, improving BHA reliability, lost circulation in heavily depleted reservoirs, and tool-size reduction to enable sidetracks to be drilled through 3 1/2-in. tubing.
On the North Slope, drilling-fluid losses result from wellbore intersections with either conductive faults or high permeability zones. These occurrences have become an all-toocommon part of business for CTD (and the rotary-rig program). Many of the remaining targets require the crossing of mapped and unmapped faults. Each fault crossed increases the risk of lost circulation. The impact of losses on the CTD program is significant. In 1999, nearly 40% of trouble time experienced while drilling was attributed to lost circulation. As the reservoir is depleted, losses become even more common.
Losses have mainly been combated in three ways.
At the planning stage by identifying high-risk faults through detailed seismic analysis and consequent replanning work to reduce the risk.
Developing reliable lost-circulation materials that can be pumped easily with CT.
Modifying operational practices.
When losses are encountered, the strategy to control or eliminate them depends on both fluid-loss severity and the sidetrack objectives. Tactics for dealing with losses range from a "do nothing and drill ahead" approach to cementing back and sidetracking with a revised directional plan, avoiding the fault intersection if possible (the other extreme). Loss rates will range from minimal (<1/4 BPM, less than 20% of the full circulation rate), which often heal in time, to massive (no returns at any pump rate and an inability to keep the hole full). While continued drilling is technically possible with severe losses, attempts are made to slow the losses if they are in excess of approximately 25% of the full circulation rate. In addition to rapidly mounting fluid costs as losses persist, hole cleaning becomes difficult, the risk of a stuck pipe increases, and the liner cement quality could be compromised.
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