Summary
The production of methane from wet coalbeds is often associated with the
production of significant amounts of water. While producing water is necessary
to desorb the methane from the coal, the damage from the drilling fluids used
is difficult to assess, because the gas production follows weeks to months
after the well is drilled. Commonly asked questions include the following:
- What are the important parameters for drilling an organic reservoir rock
that is both the source and the trap for the methane?
- Has the drilling fluid affected the gas production?
- Are the cleats plugged?
- Does the "filtercake" have an impact on the flow of water and
gas?
- Are stimulation techniques compatible with the drilling fluids used?
This paper describes the development of a unique drilling fluid to drill
coalbed methane wells with a special emphasis on horizontal applications. The
fluid design incorporates products to match the delicate surface chemistry on
the coal, a matting system to provide both borehole stability and minimize
fluid losses to the cleats, and a breaker method of removing the matting system
once drilling is completed.
This paper also discusses how coal geology impacts drilling planning,
drilling practices, the choice of drilling fluid, and completion/stimulation
techniques for Upper Cretaceous Mannville-type coals drilled within the Western
Canadian Sedimentary Basin. A focus on horizontal coalbed methane (CBM) wells
is presented.
Field results from three horizontal wells are discussed, two of which were
drilled with the new drilling fluid system. The wells demonstrated exceptional
stability in coal for lengths to 1000 m, controlled drilling rates and ease of
running slotted liners. Methods for, and results of, placing the breaker in the
horizontal wells are covered in depth.
Introduction
Methane production from coal has become one of the more interesting
practices in recent years to produce hydrocarbons (MacLeod et al. 2000; Peters
2000; Hower et al. 2003; Stevens and Hadiyanto 2004; Mavor et al. 2004; and
Bastian et al. 2005). In the United States in 2005, it is estimated that 11.7%
of all gas produced is from CBM sources (Mohaghegh et al. 2005).
While in conventional drilling in sandstones and carbonates, it is often
simple to tell if a drilling fluid is fully or partially responsible for
formation impairment, it is often much more difficult see in CBM wells. When a
CBM well depends on the production of water to reduce formation pressure and
thus lead to gas desorption, the influence of drilling fluid becomes masked or
even forgotten.
As the frontiers of CBM wells are pushed into the horizontal drilling realm,
the importance of the drilling fluid is magnified. The fluid needs to both
stabilize the wellbore during the drilling phase, but at the same time minimize
any production shortfalls caused by damage. A simple N2 fracture, which may be
used on a 5 to 10 meter (m) vertical coal seam, is not a simple matter to
transfer to a 500 to 1000 m horizontally drilled coal section.
This paper discusses how coal geology impacts drilling planning, drilling
practices, the choice of drilling fluid, and completion/stimulation techniques
for Upper Cretaceous Mannville-type coals drilled within the Western Canadian
Sedimentary Basin. A focus on horizontal CBM wells is presented.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
14 August 2006
- Meeting paper published:
16 October 2006
- Revised manuscript received:
12 February 2008
- Manuscript approved:
25 February 2008
- Version of record:
15 September 2008
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