Contribution of non-coal facies to the total gas-in-place in Mannville coal measures, Central Alberta

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• 作者：A.M.M. Bustin ; ^{abustin@eos.ubc.ca" class="auth_mail" title="E-mail the corresponding author} ; R.M. Bustin
• 关键词：Coalbed methane ; Reservoir facies ; Shale ; Mudstone ; Isotherms ; Gas content ; Desorption ; Resource
• 刊名：International Journal of Coal Geology
• 出版年：2016
• 出版时间：15 January 2016
• 年：2016
• 卷：154-155
• 期：Complete
• 页码：69-81
• 全文大小：3486 K

文摘

The contribution of non-coal, organic rich, fine grained lithofacies to total gas-in-place and producible gas in the Upper Mannville Group coal measures, has been investigated in the producing and prospective coalbed methane fairway in Alberta. Petrophysical well logs, core, fluid, and gas analyses of organic rich rocks have been evaluated in order to quantify the total gas-in-place resource that may be accessed by a horizontal well(s) completed in the thickest coal seam. Within a ± 20 m stratigraphic interval of the completed seam, significant additional gas storage exists in coal seams too thin to warrant separate completions and in organic rich, fine grained facies. Such gas, although not currently attributed to producible reserves, can reasonably be expected to be produced.

Three non-coal, organic reservoir facies are recognised based on core desorption and laboratory analysis and are identified on log, through mainly a combination of the bulk density and gamma ray logs. The reservoir facies are carbonaceous mudstone (1.5–2.0 g/cm³), organic rich mudstone (2.0–2.2 g/cm³), and organic mudstone (2.2 g/cm³–2.4 g/cm³). The gas storage in the mudstone reservoir facies, similar to the coal, is mainly in the adsorbed state with minor amounts in solution within the water/brine, and in the free state within the pores and fractures. The average gas content from canister desorption of carbonaceous mudstone is 147 scf/t,¹ organic rich mudstone is 83 scf/t, and organic mudstone is 54 scf/t. Gas in solution ranges from about 5 scf/t for the carbonaceous mudstones to a low of 0.5 scf/t for the organic mudstone reservoir facies. The measured as received porosity of the mudstones ranges from 2.5 to 14%.

The organic matter in all lithologies is dominated by particulate carbonaceous material derived from vascular plants (Type III kerogen/vitrinite). The gas capacity of non-coal facies, as determined by adsorption isotherms, and gas content as determined by desorption analysis of core, increase with thermal maturity (rank), and percentage organic matter. Values for the carbonaceous mudstone approach those of coal.

Regionally, the gas capacity and content of the coals and non-coal reservoir facies increases from northeast to southwest in parallel with the increase in current depth of burial and level of organic maturation (coal rank), although local variations exist. The gas composition of the coal and non-coal reservoir facies in the producing fairway is similar: the highest carbon dioxide contents occur in areas of highest and lowest maturity, whereas the percentage of heavier gases (C₂–C₅) increases with maturity/depth of burial. Anomalously high C₂–C₅ hydrocarbons (up to 10%) occur in the shallowest coal measures, which, in the absence of an alternate explanation, is attributed to migration. Isotopic composition of the methane has a thermogenic signature in the deepest strata, through mixed thermogenic–biogenic, to biogenic signatures at shallower depths.

In order to quantify the stratigraphic and areal variation in gas content of the non-coal lithofacies in wells where no core exits, a protocol was developed that allows extrapolation of data from cored wells to non-cored wells of similar maturity and depth of burial using petrophysical logs. In the producing and prospective fairway within ± 20 m of the main coal seam, the net thickness of the carbonaceous mudstone facies varies from 0.3 to 9.3 m and averages 2.7 m. In this interval the organic rich mudstone ranges up to 7 m thick and averages 2.6 m and, the organic mudstone, ranges up to 7 m thick and averages 2.7 m thick.

The total gas resource in the current area of production and in prospective areas was determined by applying the measured and calculated gas density (gas per unit volume) of the reservoir facies at estimated high median and low values to the net thickness of each facies in some 203 wells across the study area. The average well in the study area, using the estimate medium gas content, has a resource of 10.2 BCF/mi² (billions of cubic feet per square mile). Of the 10.2 BCF/mi², the contribution to the total gas-in-place of the thickest coal seam is 21%, the total cumulative coal is 57%, the carbonaceous mudstone facies is 21%, organic rich mudstone is 13%, and the organic mudstone is 9%.

Most producing coalbed methane formations are similar to the Mannville coal measures in that they include non-coal organic rich lithologies that can be anticipated to have generated and retained hydrocarbons similar to coal. How much the non-coal lithologies will contribute to the producible ‘coalbed’ will vary with geology of the coal measures and the drilling and completion methods utilised. Not considering the contribution of non-coal facies to the gas resource and producible gas, will under value the resource and result in non-optimal field development.