State-of-the-Art in Coalbed Methane Drilling Fluids
- Leonard V. Baltoiu (Q'Max Solutions Inc.) | Brent K. Warren (Q'Max Solutions Inc.) | Thanos A. Natros (Encana Corp.)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2008
- Document Type
- Journal Paper
- 250 - 257
- 2008. Society of Petroleum Engineers
- 1.2 Wellbore Design, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 2 Well Completion, 2.2.2 Perforating, 1.14.1 Casing Design, 3 Production and Well Operations, 1.6 Drilling Operations, 5.2 Reservoir Fluid Dynamics, 5.4.10 Microbial Methods, 5.1.1 Exploration, Development, Structural Geology, 1.6.6 Directional Drilling, 1.6.1 Drilling Operation Management, 1.11.4 Solids Control, 1.11 Drilling Fluids and Materials, 1.10 Drilling Equipment, 5.8.7 Carbonate Reservoir, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.3 Coal Seam Gas, 1.14 Casing and Cementing, 1.8 Formation Damage, 5.8.5 Oil Sand, Oil Shale, Bitumen
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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.
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.
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