Drilling for Coalbed Methane in the San Juan Basin With Coiled Tubing
- Karen Bybee (Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 2007
- Document Type
- Journal Paper
- 73 - 76
- 2007. Society of Petroleum Engineers
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- 88 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105874, "Drilling for Coalbed Methane in the San Juan Basin With Coiled Tubing: Results, Learnings, and a World First," by Sam Noynaert, SPE, and Dale Pumphrey, BP plc; and Tony Pink, SPE, Schlumberger; and Tug Eiden, Fred Hartensteiner, SPE, and Chip Nelson, SPE, BP plc, prepared for the 2007 SPE/IADC Drilling Conference, Amsterdam, 20-22 February.
In 2006, a coiled-tubing-drilling (CTD) pilot program was initiated in the San Juan basin consisting of seven wells, drilled in order of increasing complexity. The intention was to evaluate the capabilities of CTD and its potential for use in the San Juan basin. The rig used was a new, custom-built, coiled-tubing (CT)/rotary hybrid rig with a single-sized derrick, rotary table, and topdrive. This allowed the rig to drill with jointed pipe, handle and make up bottomhole assemblies (BHAs), and run liners and casing.
The San Juan basin is approximately 9,000 sq miles in northwestern New Mexico and southwestern Colorado. Remaining recoverable gas reserves are estimated to be 12.9 Tcf, with 8.5 Tcf of this coalbed-methane (CBM) reserves. Since the first well was drilled in 1901, thousands of wells have been drilled in the San Juan basin. Most of these wells targeted gas reserves in the Picture Cliffs, Mesa Verde, and Dakota formations. Starting in 1988, wells targeting CBM in the Fruitland Coal began to be drilled. The basin currently contains approximately 30,000 producing wells, the majority of which are producing gas from the Fruitland Coal.
The drilling program was set up to evaluate the potential of CTD in the San Juan basin. Five major areas of performance were highlighted as key indicators of potential: rate of penetration (ROP), directional capability, rig mobility, re-entry/horizontal-sidetrack performance, and safety performance. Because of the high daily cost or spread rate of a hybrid CTD rig vs. the conventional rotary rigs in the basin, high average ROPs would be the key to enable CTD to compete economically with conventional rigs. Relatively higher average ROPs with CT had been documented in other areas. Along with higher ROPs, overall well-completion time has historically dropped with the use of CT because of CT trip speed and dog-leg-severity capability.
The wellbore directional plans included build-and-hold and S-shaped plans and horizontal sidetracks. All of the wells to be drilled except for the sidetracks, both vertical and directional, needed to be drilled with larger hole sizes (8 3/4 and 6 1/4 in.) to accommodate the typical wellbore completions; this necessitated the use of larger, 3 1/2- and 2 7/8-in.-outside-diameter (OD) CT. Although directional work with large-size CT has been completed successfully, smaller-size CT typically is used for directional CTD work. The directional component of the program was complicated further by testing a rotary-steerable system (RSS) for directional control in the wells to be drilled. This was done successfully and was a world first in the industry.
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