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Secondary migration and leakage of methane from a major tight-gas system

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ABSTRACT

Tight-gas and shale-gas systems can undergo significant depressurization during basin uplift and erosion of overburden due primarily to the natural leakage of hydrocarbon fluids. To date, geologic factors governing hydrocarbon leakage from such systems are poorly documented and understood. Here we show, in a study of produced natural gas from 1,907 petroleum wells drilled into a Triassic tight-gas system in western Canada, that hydrocarbon fluid loss is focused along distinct curvilinear pathways controlled by stratigraphic trends with superior matrix permeability and likely also structural trends with enhanced fracture permeability. Natural gas along these pathways is preferentially enriched in methane because of selective secondary migration and phase separation processes. The leakage and secondary migration of thermogenic methane to surficial strata is part of an ongoing carbon cycle in which organic carbon in the deep sedimentary basin transforms into methane, and ultimately reaches the near-surface groundwater and atmosphere.

No MeSH data available.


Cross-plot of normalized methane (C1) content versus iC4/nC4ratio for natural gas samples from 1,907 petroleum wells drilled into the Montney formation.Data points are colour-coded by ‘excess methane' defined as the amount of methane greater than the inferred indigenous thermal maturity trend (black dots) at comparable iC4/nC4 ratio. The excess methane signature (values greater than 0.025 and shown by coloured dots) is interpreted to indicate methane that is introduced to indigenous hydrocarbon fluids by secondary migration. A reversal in the trend of iC4/nC4 ratios at very high methane contents (>95%), as reported for the Barnett Shale21 (Fig. 2), is not evident in the Montney data set.
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f5: Cross-plot of normalized methane (C1) content versus iC4/nC4ratio for natural gas samples from 1,907 petroleum wells drilled into the Montney formation.Data points are colour-coded by ‘excess methane' defined as the amount of methane greater than the inferred indigenous thermal maturity trend (black dots) at comparable iC4/nC4 ratio. The excess methane signature (values greater than 0.025 and shown by coloured dots) is interpreted to indicate methane that is introduced to indigenous hydrocarbon fluids by secondary migration. A reversal in the trend of iC4/nC4 ratios at very high methane contents (>95%), as reported for the Barnett Shale21 (Fig. 2), is not evident in the Montney data set.

Mentions: Our study shows that the trends of both iC4/nC4 ratios and equivalent vitrinite reflectance values increase with depth, and that these two thermal maturity indicators have a strong positive correlation (Fig. 3a,b). Mapped distributions of the key natural gas attributes are shown in Fig. 4a–c. A map of iC4/nC4 ratios (Fig. 4a) shows progressively increasing values to the southwest in accord with the increase in both depth and thermal maturity towards the Cordilleran foredeep. A map of normalized methane (C1) content shows a first-order trend that increases to the southwest, again consistent with thermal maturity (Fig. 4b). The C1 map, however, also has second-order trends, oriented orthogonal or oblique to the first-order trend, defined by curvilinear fairways with methane contents higher than expected from the regional first-order C1 trend. A cross-plot of normalized methane content versus iC4/nC4 ratio shows two gradational groups (Fig. 5). The first group (black dots) follows the normal indigenous thermal maturity trend of the Barnett Shale21 (cf.Fig. 2), and shows a strong positive correlation of iC4/nC4 ratio with methane content. The second group (coloured dots) is offset to higher methane values than the indigenous hydrocarbons of both the first Montney group and the Barnett Shale trend. The amount of methane greater than expected from the indigenous thermal maturity trend at comparable iC4/nC4 ratio is expressed as ‘excess methane'; this amount can be as high as 15%. Wells with this excess methane signature are not randomly distributed geographically, but instead are concentrated along the second-order trends on the C1 map (Fig. 4b). The second-order C1 trends are most clearly evident on a regional map of excess methane (red arrows, Fig. 4c) that was generated using the values from Fig. 5. These excess methane trends are high porosity and permeability targets for vertical wells drilled before the adoption of horizontal drilling in the last decade. From the available well control, the excess methane trends are typically 2–6 km wide and can be mapped from the overpressured Montney section for 10 s km up-dip into the normally pressured Montney section (Fig. 4c). Pixler18 plots of C3 versus C4 and C1 versus C4, colour-coded by excess methane (Fig. 6a,b), indicate no significant segregation of propane and butane but strong selective segregation of methane with respect to other light n-alkanes.


Secondary migration and leakage of methane from a major tight-gas system
Cross-plot of normalized methane (C1) content versus iC4/nC4ratio for natural gas samples from 1,907 petroleum wells drilled into the Montney formation.Data points are colour-coded by ‘excess methane' defined as the amount of methane greater than the inferred indigenous thermal maturity trend (black dots) at comparable iC4/nC4 ratio. The excess methane signature (values greater than 0.025 and shown by coloured dots) is interpreted to indicate methane that is introduced to indigenous hydrocarbon fluids by secondary migration. A reversal in the trend of iC4/nC4 ratios at very high methane contents (>95%), as reported for the Barnett Shale21 (Fig. 2), is not evident in the Montney data set.
© Copyright Policy - open-access
Related In: Results  -  Collection

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getmorefigures.php?uid=PMC5121425&req=5

f5: Cross-plot of normalized methane (C1) content versus iC4/nC4ratio for natural gas samples from 1,907 petroleum wells drilled into the Montney formation.Data points are colour-coded by ‘excess methane' defined as the amount of methane greater than the inferred indigenous thermal maturity trend (black dots) at comparable iC4/nC4 ratio. The excess methane signature (values greater than 0.025 and shown by coloured dots) is interpreted to indicate methane that is introduced to indigenous hydrocarbon fluids by secondary migration. A reversal in the trend of iC4/nC4 ratios at very high methane contents (>95%), as reported for the Barnett Shale21 (Fig. 2), is not evident in the Montney data set.
Mentions: Our study shows that the trends of both iC4/nC4 ratios and equivalent vitrinite reflectance values increase with depth, and that these two thermal maturity indicators have a strong positive correlation (Fig. 3a,b). Mapped distributions of the key natural gas attributes are shown in Fig. 4a–c. A map of iC4/nC4 ratios (Fig. 4a) shows progressively increasing values to the southwest in accord with the increase in both depth and thermal maturity towards the Cordilleran foredeep. A map of normalized methane (C1) content shows a first-order trend that increases to the southwest, again consistent with thermal maturity (Fig. 4b). The C1 map, however, also has second-order trends, oriented orthogonal or oblique to the first-order trend, defined by curvilinear fairways with methane contents higher than expected from the regional first-order C1 trend. A cross-plot of normalized methane content versus iC4/nC4 ratio shows two gradational groups (Fig. 5). The first group (black dots) follows the normal indigenous thermal maturity trend of the Barnett Shale21 (cf.Fig. 2), and shows a strong positive correlation of iC4/nC4 ratio with methane content. The second group (coloured dots) is offset to higher methane values than the indigenous hydrocarbons of both the first Montney group and the Barnett Shale trend. The amount of methane greater than expected from the indigenous thermal maturity trend at comparable iC4/nC4 ratio is expressed as ‘excess methane'; this amount can be as high as 15%. Wells with this excess methane signature are not randomly distributed geographically, but instead are concentrated along the second-order trends on the C1 map (Fig. 4b). The second-order C1 trends are most clearly evident on a regional map of excess methane (red arrows, Fig. 4c) that was generated using the values from Fig. 5. These excess methane trends are high porosity and permeability targets for vertical wells drilled before the adoption of horizontal drilling in the last decade. From the available well control, the excess methane trends are typically 2–6 km wide and can be mapped from the overpressured Montney section for 10 s km up-dip into the normally pressured Montney section (Fig. 4c). Pixler18 plots of C3 versus C4 and C1 versus C4, colour-coded by excess methane (Fig. 6a,b), indicate no significant segregation of propane and butane but strong selective segregation of methane with respect to other light n-alkanes.

View Article: PubMed Central - PubMed

ABSTRACT

Tight-gas and shale-gas systems can undergo significant depressurization during basin uplift and erosion of overburden due primarily to the natural leakage of hydrocarbon fluids. To date, geologic factors governing hydrocarbon leakage from such systems are poorly documented and understood. Here we show, in a study of produced natural gas from 1,907 petroleum wells drilled into a Triassic tight-gas system in western Canada, that hydrocarbon fluid loss is focused along distinct curvilinear pathways controlled by stratigraphic trends with superior matrix permeability and likely also structural trends with enhanced fracture permeability. Natural gas along these pathways is preferentially enriched in methane because of selective secondary migration and phase separation processes. The leakage and secondary migration of thermogenic methane to surficial strata is part of an ongoing carbon cycle in which organic carbon in the deep sedimentary basin transforms into methane, and ultimately reaches the near-surface groundwater and atmosphere.

No MeSH data available.