SPE Members Abstract This paper presents the results of a study undertaken to investigate the reasons why data from injection/falloff tests of coalbed methane wells were not interpretable using conventional well test analysis techniques and the results of a field study to investigate completion effectiveness during injection tests. The pressure transient test data obtained using the old injection/fallout test design were found to be interpretable only by history matching analysis. A modified test design is presented. A field example is presented which illustrates how application of the modified test design resulted in easily interpretable data using conventional well test analysis techniques. Spinner surveys run during injection tests showed that breakdown/fallout treatments are required prior to simultaneous testing of multiple coals in cased-hole completions to ensure adequate communication between the well and all target coal seams. Introduction Recent work has shown that permeability is the reservoir parameter that primarily controls methane recovery from coals. In water saturated coal seams, permeability controls the initial rate at which water can be removed from vertical degasification wells, Therefore, permeability controls the rate at which the reservoir can be dewatered and the producing time required to achieve maximum gas production from the coal reservoir. Consequently, it is extremely Important for engineers to have accurate measurements of reservoir permeability to design field installations (well completions) and optimally manage reservoir performance. Several recent papers show evidence of the importance of reservoir permeability in determining optimal well spacing and stimulation design. Well tests are used to determine the reservoir permeability in coals. Most coal seams are saturated with water at virgin reservoir conditions. The best opportunity to test coal seams is prior to well production when the reservoir is 100% water production when the reservoir is 100% water saturated. Interpretation of tests run on coal wells after pressure drawdown, when two-phase flow conditions are established in the reservoir, is difficult at best. Historically, slug tests and water injection/falloff tests have been used to determine permeability in water saturated coals. These tests are generally preferred over classical drawdown/buildup tests because they test the reservoir under single-phase flow conditions. This paper is based primarily on the experiences of one operator, Taurus Exploration, Inc. (Taurus). Taurus operates hundreds of coalbed methane wells in the Black Warrior Basin, covering a wide range of geologic conditions (permeabilities). Both slug tests and injection/falloff tests have been used by Taurus to determine the permeability of coal seams in the Black Warrior permeability of coal seams in the Black Warrior Basin. P. 425
Fracture stimulation is commonly used for coal degasification at the Black Warrior basin in Alabama. To understand coal bed fracturing better, Well AM-1 in the Oak Grove field was completed open hole in the section bracketing the Black Creek coals. Special diagnostics used on this project included various injection tests, static-line pressure measurements, and a downhole television camera. The television camera observed fractures during injection tests and after the propped fracture treatment. The authors believe these are the first successful downhole television pictures of propped fractures in coal beds. Results were compared with predictions of hydraulic fracture simulators. This is a valuable way of "calibrating" hydraulic fracture models for improved design/optimization.
This paper was selected for presentation by an SPE Prognun Committee following review of information contained in an abstract submitted by tho autbor(s). Contents of tho paper, as presented, have not been reviewed by tho Society of Petroleum. Engineers and are subjected to oorrcction by tho autbor(s). The material, as presented does not neoessarily reflect any position of tho Society of Petroleum. Engineers, its offioers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of tho Society of Petroleum. Engineers. Permission to ropy is restricted to an abstract of not more than 300 words. lliustrations my not be oopied. The abstract sboold oontain OOI18piC\lOU8 acknowledgement of where and by whom tho paper was presented. WriteLibrarian, SPE, P.O. Box 833836, Richardson, TX75083-3836, U.S.A., fax 01-214-952-9435. AbstractThis paper presents the first field scale measurements of insitu stress effects on permeability of coal seams. The importance of these effects on a highly compressible reservoir such as coal is demonstrated by relating permeability and production to stress.Well testing complications and the implications of stress toward exploitation of existing reserves and exploration for new reserves are also discussed. Additionally, comparisons of this paper's findings to prior theoretical work, core testing, and limited field data are presented.
Forty-three gel fracture treatments are analyzed in this report -in both Mary Lee/Blue Creek seams and in Black Creek seams. Although 12/20 sand concentrations were added to 10 ppg, there were virtually no screenouts, presumably because pad volumes were so high (almost 50%). The Black Creek fractures are vertical, with substantial height growth, and are characterized by high treating pressures but relatively low fracture propagation pressures. There is conspicuous erosion by 12/20 sand of the fracture "entry region": perforations, perforation/fracture junction, or near-wellbore fracture constriction. It is postulated that erosion is conspicuous because (a) not all perforated zones are taking fluid, (b) the overall perforation/fracture junction may be more complex when subfractures from Black Creek seams join up 'to form the main fracture, or (c) the fluid, sand, and products of erosion are not confined to the coal seams.There are relatively few proppant-induced pressure increases, again possibly due to the fact that the 12/20 sand and products of erosion are not confined to the coal seams. The constant behavior of shut-in pressure with time in the majority of cases is consistent with an absence of any poroelastic effect (although about 25% of cases are consistent with a poroelastic effect). Approximately half of the Mary Lee/Blue Creek fractures are just like the Black Creek fractures and are interpreted similarly. The other half are different and exhibit high fracture propagation pressures. They are probably T-shaped fractures. A T-fracture is confined to a coal seam (there might be a T-fracture in more than one seam). Shut-in pressures measured throughout such fracture treatments are greater than 1 psi/ft, but generally decrease with time. In general the high pressure T·fractures are shallower than the low pressure vertical fractures. They do not show any correlation with a prominent fault block, which contradicts a previous finding.There are more proppant.-induced pressure increases. In the high pressure Mary Lee/Blue Creek cases, the pressure drops at final shut.-in range from References and illustrations at end of paper. 277small (~100 psi) to large (~750 psi). The former appear to be consistent with an elevated fracture tip resistance (or apparent fracture toughness). The latter are consistent with a near-wellbore flow constriction (discrete offsets/obstructions, or multistrands, or tortuous fluid flow path due to T-fracture geometry). The pressure decline after shut-in is not any faster in the high pressure Mary Lee/Blue Creek cases than in the low pressure cases. The most likely explanation is a reduction in coal permeability due t.o (a) high' ambient in-situ stress, (b) damage by the high fracturing pressures. Gas production appears better, by more than 50%, in low pressure Mary Lee/Blue Creek cases t.han in high pressure cases. This is consistent with the notion that a vertical fracture is a more effective stimulation than a T·fracture.
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