Comparison of Methane Production From Coalbeds Using Vertical or Horizontal Fractured Wells
- F.X. Deimbacher (Mining U. Leoben) | M.J. Economides (Mining U. Leoben) | Z.E. Heinemann (Mining U. Leoben) | J.E. Brown (Dowell Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- August 1992
- Document Type
- Journal Paper
- 930 - 935
- 1992. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 1.6.6 Directional Drilling, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.8.3 Coal Seam Gas, 1.6 Drilling Operations, 2.5.1 Fracture design and containment, 1.4.3 Fines Migration, 2.2.2 Perforating, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.1.1 Exploration, Development, Structural Geology, 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 4.1.9 Tanks and storage systems, 2.3.4 Real-time Optimization, 4.1.3 Dehydration
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Methane production from coalbeds, while originally a safety measure, hasemerged as a major source of gas for a number of locations worldwide. Gasdesorption is the main production mechanism. This is accomplished currently bythe production mechanism. This is accomplished currently by the hydraulicfracturing of vertical wells; draining of water, which is always present in thelimited pore structure; and reducing pressure to begin the desorption process.However, hydraulic fractures tend to propagate parallel to the main naturalfissures and thus normal to the smallest permeability. This is the leastfavorable position. Simulation shows that horizontal wells drilled in theorthogonal direction (i.e., normal to the maximum permeability and the mainnatural fissures) can provide significantly larger gas rates. Several smallhydraulic fractures, performed in the horizontal well with proper zonalisolation, can augment production further. Considering the highly fissured,cleated nature of coalbeds, small stimulations, with much more modestexpectations, are far easier to perform than the single treatments required ina vertical well. Design criteria, well sizing, and stimulation treatment numberand magnitude are calculated and presented.
The coalbed methane industry has emerged as a significant source of naturalgas production. The original perception of coal-associated methane as a hazardin mining operations is becoming obsolete. Today, a coalbed is considered areservoir from which large quantities of methane can be extracted.
In the U.S. alone, the total coalbed resource is estimated to be 4 x 10-13SCf [1 x 10-13 std m3], of which 9 X 10-13 SCf [2.5 x 10-12 std m3] isconsidered recoverable reserves.
Several potential mechanisms have been identified during the production ofcoalbed methane, including free gas from associated production of coalbedmethane, including free gas from associated natural fractures and gasdesorption from the coal surface as the reservoir pressure declines. Primaryporosity in coals is very small, rarely exceeding 0.05, with typical valuesaround 0.02. Reservoir thickness is also very small (this is the thickness of acoal layer) and is frequently less than 10 ft [3.3 m].
Vertical wells, allowing exceedingly small contact between them and a coalseam, are rarely, if ever, acceptable producers. Production rates do not exceeda few thousand cubic feet a day, and Production rates do not exceed a fewthousand cubic feet a day, and they are hindered further by relativepermeability problems caused by the presence of associated water.
Hydraulic fracturing of vertical wells in coalbeds has been attempted in anumber of cases. The perception of coal seams as fracturable reservoirsprompted the study of their rock and reservoir properties as they might affectfracture design.
Several features distinguish coalbeds from other reservoirs. In addition tothe small thickness and porosity already mentioned, the (also small)permeability is usually highly anisotropic, with the maximum permeabilityinvariably along the maximum horizontal stress. This would make the hydraulicfracture parallel to the maximum permeability, which is, of course, highlyundesirable during production when the bilinear flow concept would necessitatea large permeability normal to the fracture face.
Permeability anisotropy in coalbeds is caused by natural fissuresPermeability anisotropy in coalbeds is caused by natural fissures that,although anisotropically distributed, are also at various angles along thehydraulic fracture path. These fissures may open during the treatment,providing large fluid leakoff paths, readily dehydrating the slurry, andresulting in screenouts. To combat this, fracture designs have used very smallproppant slurry concentrations (frequently 2 lbm/gal [240 kg/m3), leading tovery lackluster production rates. Also, fines migrating from the coal fissuresystem may penetrate the hydraulic fracture and reduce its conductivityfurther.
Of the primary fracture treatment variables, the Young's modulus of coalbedsis very small (between 1 x 10-5 and 1 X 10-6 psi 16.9 x 10-8 to 6.9 x 10-9 Pa])compared with normal fracturing candidates with Young's moduli between 3 x 10-6and 10-7 psi [2 x 10-10 and 6.9 x 10-10 Pa]. In the best cases, this featurewould result in short, wide fractures instead of the long penetrations requiredby such low-permeability reservoirs.
Finally, coalbeds to be fractured, presumed to be single reservoirs, presenta large variation in the success of the treatment because of stress variations.They are usually multilayered and are prone to T-shaped fractures. Thesefeatures and others, along with guidelines for adjusting fracture design modelsand recommendations for fracturing treatments, are presented later.
Obviously, maximization of the gas production rate from coalbeds is theissue at hand. From all the above, it should not be too surprising thatproduction from unstimulated or hydraulically fractured vertical wells isusually small, ranging from 50 to 230 Mscf/D [1.4 x 10-3 to 6.5 x 10-3 stdm3/d] in 30 wells in an Alabama field 13 and a cumulative 6 to 7 MMscf/D [1.7 x10-5 to 2 x 10-5 std m3/d] from another 31-well development. A no-proppant foamstimulation in a well was reported to result in an average 4.5-month productionof 49 Mscf/D [1.4 x 10-3 Std m3/d]. production of 49 Mscf/D [1.4 x 10-3 Stdm3/d].
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