Alberta Multiwell Micro-Pilot Testing for CBM Properties, Enhanced Methane Recovery and CO2 Storage Potential

Abstract

Abstract The Alberta Research Council (ARC) is performing a project entitled "Sustainable Development of Coalbed Methane; A Life-Cycle Approach to Production of Fossil Energy" that is funded by an international consortium of companies. The main objectives of the project are to reduce greenhouse gas emissions by subsurface injection of CO2 into deep coalbeds and to enhance coalbed methane recovery and production rates. We have performed extensive field tests that includes efforts on two wells located near the towns of Fenn and Big Valley in Alberta that penetrated Medicine River (Mannville) coal seams. This paper presents test procedures, quantitative data measured during this effort, and the interpretation thereof. The evaluation was completed over three years ago and was based upon procedures described previously.1 These data have allowed complete characterization of the coal seam properties with new insights gained into the behavior of coal seams, the volume of natural gas that can be produced, and the volumes of CO2 that can be sequestered in this area. The fieldwork began by reentering the Gulf Canada (now ConocoPhillips) well FBV 4A-23–36-20 (FBV 4A) well. We conducted a series of single well micro-pilot tests. We began by production and shut-in testing to obtain estimates of the reservoir pressure and permeability before CO2 injection. A CO2 injection test was followed by a shut-in test to insure that CO2 injection was possible. We then injected over 91,500 m3 of CO2 vapor in 12 separate injection cycles. Although CO2 reduced the absolute permeability, injectivity actually increased. The CO2 was allowed to soak into the coal and we returned the well to production. Post-injection testing allowed us to determine the CO2 sweep efficiency as well as the ECBM and CO2 storage potential. Fourteen months later, we injected 83,500 m3 of flue gas using underbalanced drilling equipment that was followed by a post injection-production test. A second well (FBV 5) was drilled 487 m north of the first well. FBV 5 was cored and logged for reservoir property data. The well was then cased and completed in one Medicine River coal seam. A combination of production tests and water-injection falloff tests were conducted to determine original reservoir pressure, permeability, and gas composition. N2 injectivity tests were performed before injecting 75,483 m3 of a 53%–47% mix of N2 and CO2. The gas mixture was allowed to soak into the coal and the well was returned to production. All of the post-injection production tests of both wells included detailed measurement of pressure and temperature conditions as well as gas composition variations vs. time. These data allowed us to determine the changes in permeability caused by the injected gas, to estimate possible hydrocarbon sweep efficiency, and possible CO2 storage volumes. FBV 4A Micro-Pilot Testing Gulf Canada donated the FBV 4A well to the project. After review of available data, we concluded that the well penetrated Medicine River coal seams typical of those penetrated by many wells in the Alberta Plains region. The absolute permeability also appeared to be typical. FBV 4A History The FBV 4A well was originally an oil production well but after the original completion was abandoned, the well was recompleted into two Medicine River (Mannville) coal intervals. The upper coal interval was perforated from 1,259 to 1,263 m and the lower coal interval from 1,277 to 1,283 m. A bridge plug set above the lower coal interval isolated the upper interval, which is the subject of this paper. The upper Mannville coal interval was hydraulically fracture stimulated with a 10 metric ton liquid CO2 treatment in August 1992. A 40-m3 liquid CO2 pre-pad was pumped to initiate the fracture treatment. 160 m3 of liquid CO2 was mixed with sand proppant in concentrations increasing from 50 to 200 kg/m3 and injected into the coal at a rate of 8 m3/min at 20 MPa. The fracture gradient was 14.1 kPa/m. The well was produced for 48 hours with a final recorded gas rate of 2,600 m3/D. Gas samples taken just before production ceased still contained significant CO2 concentrations indicating incomplete CO2 recovery. A second stimulation treatment was performed in January 1993. 14 m3 of CO2 was injected followed by 1,600 m3 of N2. Both fluids were pumped at 1 m3/min at a surface pressure of 13 MPa(g).