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Hydrodynamics and petroleum migration in the Upper Ordovician Red River Formation of the Williston Basin
Journal of Geochemical Exploration 89 (2006) 179 – 182 www.elsevier.com/locate/jgeoexp
Hydrodynamics and petroleum migration in the Upper Ordovician Red River Formation of the Williston Basin D.K. Khan a,⁎, B.J. Rostron a , Z. Margitai b , D. Carruthers c a
Earth and Atmospheric Sciences, University of Alberta, Edmonton, Alberta, Canada b Alberta Environment, Edmonton, Alberta, Canada c The Permedia Research Group, Ottawa, Canada Received 16 August 2005; accepted 14 November 2005 Available online 20 March 2006
Abstract Simulations of petroleum migration within the Red River petroleum system of the Williston Basin show that petroleum generation and secondary migration preceded the onset of an active hydrodynamic regime that persists to the present day. Furthermore: (1) a better understanding of the eastern limit of the mature source rock area, which is largely facies controlled, is required to reduce exploration risk east of the Nesson Anticline, (2) the Red River play types that have been prosperous in southeastern Saskatchewan should extend considerable distances to the north, as well as throughout central Saskatchewan and western Manitoba, Canada, and (3) accumulations that may have developed in the southwest of the basin have likely been flushed and redistributed subsequent to the onset of hydrodynamics. © 2006 Elsevier B.V. All rights reserved. Keywords: Petroleum migration; Hydrodynamics; Williston Basin; Red River Formation
1. Introduction Long-range petroleum migration within permeable strata of petroliferous sedimentary basins is a widely documented phenomenon (Dow, 1974; Bethke et al., 1991, and others). Buoyancy is the dominant driving force on secondary petroleum migration, with capillary resistance of the rock pores being the dominant resistive force due to the low feeding rates of source rocks (Carruthers, 2003). Hydrodynamics modifies the gradients of capillary resistance to exert significant control on petroleum migration trajectories within carrier beds. The Williston Basin is a large intracontinental sedimentary basin in central North America straddling ⁎ Corresponding author. E-mail address: [email protected] (D.K. Khan). 0375-6742/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.gexplo.2005.11.072
the Canada–USA border. It contains several longdistance migration petroleum systems and an active present-day hydrodynamic regime. The basin underwent a transition from a hydrostatic to a hydrodynamic basin in Latest Cretaceous to Early Tertiary times, at approximately the same time as the generation and expulsion of hydrocarbons within the petroleum systems in the basin (DeMis, 1995; Osadetz et al., 1998). The objective of this study was to improve petroleum exploration efforts in the basin by further constraining the timing relationship between the onset of hydrodynamics and petroleum generation/migration, and by assessing the role of hydrodynamics in the migration trajectories of Red River oil. The Red River (Bighorn) petroleum system is one of several systems in the Williston Basin in which longdistance migration of petroleum is known to have
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occurred (Dow, 1974; Burrus et al., 1996). Organic-rich kukersitic source laminae occur within the same stratigraphic interval as the porous carrier bed, which is classified as the Red River “C” Member in the USA and the Yeoman Member in Saskatchewan, Canada (Longman and Haidl, 1996). The primary seals are anhydrite layers that cap depositional sequences within the Red River Formation, or, where these are absent toward the eastern basin margin, the overlying Stony Mountain shale acts as a seal. Burial history modeling and characterization of the Red River source rock suggests that the Red River first entered the oil window and finished generating petroleum in a narrow time frame beginning with peak generation at 65–70 Ma ago (Burrus et al., 1996; Osadetz et al., 1998). 2. Hydrodynamics The hydrodynamic pressure field within the Red River Formation was mapped across the Williston Basin from drill stem test pressures, accounting for test quality and removing the effects of production-induced pressure drawdown in order to obtain a detailed potentiometric surface map (not shown; Margitai, 2002). The Williston Basin is thought to have been more or less hydrostatic prior to the current hydrodynamic regime, which was initiated in the Late Cretaceous to early Tertiary, in association with the onset of the Laramide Orogeny. Uplift of the basin flanks created a cross-basinal formation water flow system from S–SW to N–NE (DeMis, 1995). The initial hydrodynamic phase would have caused hydraulic head gradients up to three times higher than those observed today, based on erosion estimates in the Black Hills of South Dakota (Lisenbee and DeWitt, 1993). 3. Modeling approach The modeling consisted of three steps: (1) generate Red River oil and simulate migration in a hydrostatic carrier, (2) simulate migration in a hydrodynamic regime, and finally, (3) compare the results of the two simulations with areas of present day production. The difference between the hydrostatic and hydrodynamic cases is with respect to the water pressures. In the hydrodynamic case, pore-water pressures within the carrier bed may differ from hydrostatic at any given location by an amount greater or less than hydrostatic due to the flow of formation water. Migration simulations were done with MPath, which simulates secondary migration using an algorithm based on the invasion percolation concept (Carruthers, 2003).
MPath simulates migration by accounting for the buoyancy driving force resulting from the density difference between the petroleum and water phases, which is oriented in the direction of steepest dip of the carrier bed. The resistive forces that impede the progress of migrating petroleum are calculated as gradients of the threshold capillary pressures (pth). The pth is a specified property of a given rock volume (i.e., a mesh element) which must be exceeded to allow the migration of petroleum through that element. The model domain consisted of a three-dimensional mesh in which the nodes comprising the source/carrier bed were active to petroleum migration. The structural top of the Red River Formation was gridded from basin-wide well control to define the top of the carrier bed. The area of thermallymature source rock was based on a combination of soft lithofacies information and studies characterizing the Red River source rocks (Martiniuk and Barchyn, 1994; Osadetz and Snowdon, 1995; Osadetz et al., 1998). Hydrodynamic simulations used mapped formationwater pressures instead of a calculated hydrostatic pressure field within the carrier. Elevated paleo-pressure gradients were accounted for by increasing the hydraulic heads by up to three times in the uplifted areas and allowing the effect to dissipate toward the discharge areas in the northeast of the basin following an approximately exponential function. Simulations were performed in a stochastic framework, whereby statistical variability in the carrier bed pth field allowed petroleum trajectories to vary slightly in each realization. Other uncertainties were qualitatively assessed, such as the limit of the mature source area. 4. Simulation results Petroleum migration trajectories within a hydrostatic carrier bed radiate outward from the mature source area, driven by buoyancy along flowpaths defined by the steepest structural gradients (Fig. 1A). Notable irregularities in the pattern of petroleum dispersal are (1) the shadow zone (i.e., no petroleum) expanding eastward from the Nesson Anticline, (2) the shadow zone in the entire northwestern part of the study area, and (3) the early filling of the Cedar Creek Anticline, which traps all southwest-migrating petroleum before allowing some spillage. The shadow zone east of the Nesson Anticline is caused by the fact that the eastern limit of the kukersitic source beds coincides roughly with the axis of the Nesson anticline (Fig. 1A). As such, the anticline traps petroleum coming from the source area and funnels the oil out past the gentle updip closure to the north. There is considerable uncertainty in the
D.K. Khan et al. / Journal of Geochemical Exploration 89 (2006) 179–182
181
Fig. 1. (A) Hydrostatic simulation results (a single realization), with petroleum migration trajectories and producing areas (circles). Outline at basin centre indicates mature source. Depth contours increase toward the basin centre from 100 to 4200 m. (B) Hydrodynamic simulation results (a single realization).
eastern limit of the source facies; extending it beyond the eastern flank of the Nesson Anticline eliminated the shadow zone in North Dakota; however, the lack of Red River oil discoveries east of the Nesson Anticline (despite numerous well penetrations) is consistent with the results obtained. Indeed, the migration trajectories in a hydrostatic basin match the areas of known Red River production remarkably well; most importantly, matching with the cluster of northernmost producing areas in southeast Saskatchewan (Fig. 1A). Migration trajectories in a hydrodynamic basin differ considerably from the hydrostatic case (Fig. 1B). Inclusion of hydrodynamics diverts petroleum around the known production areas in southern Saskatchewan (Fig. 1B). Hydrodynamic pore pressure gradients induce large capillary pressure gradients, and as a result, the structural elevation gradient of the carrier bed is no longer the primary control on migration trajectories. Hydrodynamic migration is controlled by the interaction of the buoyancy force field and a new, or modified, heterogeneous resistive force field resulting in the differences in petroleum migration trajectories between the two cases. The strongest dynamic pressure gradients occur near the uplifted basin flanks with the result of completely arresting petroleum migration to the southwest quadrant of the basin, which was observed to varying degrees in the hydrostatic simulations. This
suggests that although migration to this part of the basin may have occurred, subsequent hydrodynamic effects may have flushed any petroleum accumulations in this area. The main phase of Red River oil migration must have taken place in a basin with pore pressures close to hydrostatic based on simulation results and corroboration with areas known to have received petroleum at long-distances from the source area. If the onset of the hydrodynamic regime in the Williston Basin had been coincident with, or preceded the narrow window of time that the Red River source was generative and secondary migration was taking place, the distal accumulations in Saskatchewan, Canada would not exist. 5. Conclusions and implications Simulation results constrained by known hydrocarbon accumulations indicate that the main phase of Red River oil migration must have taken place prior to the onset of the present-day hydrodynamic regime. The implications of this for exploration are: (1) Unless the organic rich kukersitic lithofacies can be shown to exist beyond the eastern flank of the Nesson Anticline, Red River exploration in North Dakota and southern Manitoba are extremely high-risk. (2) The Red River play types that have been prosperous in southeastern
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Saskatchewan should extend considerable distances to the north, as well as throughout central Saskatchewan, and western Manitoba. (3) Although migration seems to have taken place in a hydrostatic basin, hydrodynamics may have flushed and redistributed Red River petroleum accumulations, particularly in the Southwest of the basin, proximal to the present-day Black Hills, Bighorn Mountains, and central Montana uplifts, where the strongest hydraulic head gradients have existed. References Bethke, C.M., Reed, J.D., Oltz, D.F., 1991. Long-range petroleum migration in the Illinois Basin. AAPG Bulletin 75 (5), 925–945. Burrus, J., Osadetz, K., Wolf, S., Doligez, B., Visser, K., Dearborn, D., 1996. A two-dimensional regional basin model of Williston Basin hydrocarbon systems. AAPG Bulletin 80 (2), 248–264. Carruthers, D.J., 2003. Modeling of secondary petroleum migration using invasion percolation techniques. In: Duppenbecker, S., Marzi, R. (Eds.), Multidimensional Basin Modeling. AAPG/Datapages Discovery Series. AAPG/Datapages, Tulsa, OK, pp. 21–37. DeMis, W.D., 1995. Effect of cross-basinal hydrodynamic flow on oil accumulations and oil migration history of the Bakken–Madison petroleum system Wiliston Basin, North America. In: Hunter, L.D. V., Schalla, R.A. (Eds.), Seventh International Williston Basin Symposium. Montana Geological Society, Billings, Montana, pp. 291–301.
Dow, W.G., 1974. Application of oil correlation and source-rock data to exploration in Williston Basin. AAPG Bulletin 58 (7), 1253–1262. Lisenbee, A.L., DeWitt, E., 1993. Laramide evolution of the Black Hills uplift. In: S.A.W., Steidtmann, J.R., Roberts, S.M. (Eds.), Geology of Wyoming. Geological Survey of Wyoming Memoir, pp. 374–412. Longman, M.W., Haidl, F.M., 1996. Cyclic deposition and development of porous Dolomites in the Upper Ordovician Red River Formation, Williston Basin. In: Longman, M.W., Sonnenfeld, M. D. (Eds.), Paleozoic Systems of the Rocky Mountain Region. SEPM. Margitai, Z., 2002. Hydrogeological characterization of the Red River Formation, Williston Basin, Canada–USA, Unpublished M.Sc. Thesis, University of Alberta, Edmonton, Alberta, Canada. Martiniuk, C.D., Barchyn, D., 1994. Petroleum potential of the preMississippian, southwestern Manitoba. Bulletin of Canadian Petroleum Geology 42 (3), 365–391. Osadetz, K.G., Snowdon, L.R., 1995. Significant Paleozoic Petroleum Source Rocks in the Canadian Williston Basin: Their Distribution, Richness and Thermal Maturity (Southeastern Saskatchewan and Southwestern Manitoba). Minister of Energy, Mines and Resources, Canada. 60 pp. Osadetz, K., Kohn, B.P., O'Sullivan, P., Feinstein, S., Hannigan, P.K., Everitt, R.A., Gilboy, F., Bezys, R.K., Stasiuk, L.D., 1998. Williston Basin thermotectonics: variations in heat flow and hydrocarbon generation. In: Christopher, J.E., Gilboy, C.F., Paterson, D.F., Bend, S.L. (Eds.), Eighth International Williston Basin Symposium. Special Publication. Saskatchewan Geological Society, Regina, pp. 147–165.
Hydrodynamics and petroleum migration in the Upper Ordovician Red River Formation of the Williston Basin D.K. Khan a,⁎, B.J. Rostron a , Z. Margitai b , D. Carruthers c a
Earth and Atmospheric Sciences, University of Alberta, Edmonton, Alberta, Canada b Alberta Environment, Edmonton, Alberta, Canada c The Permedia Research Group, Ottawa, Canada Received 16 August 2005; accepted 14 November 2005 Available online 20 March 2006
Abstract Simulations of petroleum migration within the Red River petroleum system of the Williston Basin show that petroleum generation and secondary migration preceded the onset of an active hydrodynamic regime that persists to the present day. Furthermore: (1) a better understanding of the eastern limit of the mature source rock area, which is largely facies controlled, is required to reduce exploration risk east of the Nesson Anticline, (2) the Red River play types that have been prosperous in southeastern Saskatchewan should extend considerable distances to the north, as well as throughout central Saskatchewan and western Manitoba, Canada, and (3) accumulations that may have developed in the southwest of the basin have likely been flushed and redistributed subsequent to the onset of hydrodynamics. © 2006 Elsevier B.V. All rights reserved. Keywords: Petroleum migration; Hydrodynamics; Williston Basin; Red River Formation
1. Introduction Long-range petroleum migration within permeable strata of petroliferous sedimentary basins is a widely documented phenomenon (Dow, 1974; Bethke et al., 1991, and others). Buoyancy is the dominant driving force on secondary petroleum migration, with capillary resistance of the rock pores being the dominant resistive force due to the low feeding rates of source rocks (Carruthers, 2003). Hydrodynamics modifies the gradients of capillary resistance to exert significant control on petroleum migration trajectories within carrier beds. The Williston Basin is a large intracontinental sedimentary basin in central North America straddling ⁎ Corresponding author. E-mail address: [email protected] (D.K. Khan). 0375-6742/$ - see front matter © 2006 Elsevier B.V. All rights reserved. doi:10.1016/j.gexplo.2005.11.072
the Canada–USA border. It contains several longdistance migration petroleum systems and an active present-day hydrodynamic regime. The basin underwent a transition from a hydrostatic to a hydrodynamic basin in Latest Cretaceous to Early Tertiary times, at approximately the same time as the generation and expulsion of hydrocarbons within the petroleum systems in the basin (DeMis, 1995; Osadetz et al., 1998). The objective of this study was to improve petroleum exploration efforts in the basin by further constraining the timing relationship between the onset of hydrodynamics and petroleum generation/migration, and by assessing the role of hydrodynamics in the migration trajectories of Red River oil. The Red River (Bighorn) petroleum system is one of several systems in the Williston Basin in which longdistance migration of petroleum is known to have
180
D.K. Khan et al. / Journal of Geochemical Exploration 89 (2006) 179–182
occurred (Dow, 1974; Burrus et al., 1996). Organic-rich kukersitic source laminae occur within the same stratigraphic interval as the porous carrier bed, which is classified as the Red River “C” Member in the USA and the Yeoman Member in Saskatchewan, Canada (Longman and Haidl, 1996). The primary seals are anhydrite layers that cap depositional sequences within the Red River Formation, or, where these are absent toward the eastern basin margin, the overlying Stony Mountain shale acts as a seal. Burial history modeling and characterization of the Red River source rock suggests that the Red River first entered the oil window and finished generating petroleum in a narrow time frame beginning with peak generation at 65–70 Ma ago (Burrus et al., 1996; Osadetz et al., 1998). 2. Hydrodynamics The hydrodynamic pressure field within the Red River Formation was mapped across the Williston Basin from drill stem test pressures, accounting for test quality and removing the effects of production-induced pressure drawdown in order to obtain a detailed potentiometric surface map (not shown; Margitai, 2002). The Williston Basin is thought to have been more or less hydrostatic prior to the current hydrodynamic regime, which was initiated in the Late Cretaceous to early Tertiary, in association with the onset of the Laramide Orogeny. Uplift of the basin flanks created a cross-basinal formation water flow system from S–SW to N–NE (DeMis, 1995). The initial hydrodynamic phase would have caused hydraulic head gradients up to three times higher than those observed today, based on erosion estimates in the Black Hills of South Dakota (Lisenbee and DeWitt, 1993). 3. Modeling approach The modeling consisted of three steps: (1) generate Red River oil and simulate migration in a hydrostatic carrier, (2) simulate migration in a hydrodynamic regime, and finally, (3) compare the results of the two simulations with areas of present day production. The difference between the hydrostatic and hydrodynamic cases is with respect to the water pressures. In the hydrodynamic case, pore-water pressures within the carrier bed may differ from hydrostatic at any given location by an amount greater or less than hydrostatic due to the flow of formation water. Migration simulations were done with MPath, which simulates secondary migration using an algorithm based on the invasion percolation concept (Carruthers, 2003).
MPath simulates migration by accounting for the buoyancy driving force resulting from the density difference between the petroleum and water phases, which is oriented in the direction of steepest dip of the carrier bed. The resistive forces that impede the progress of migrating petroleum are calculated as gradients of the threshold capillary pressures (pth). The pth is a specified property of a given rock volume (i.e., a mesh element) which must be exceeded to allow the migration of petroleum through that element. The model domain consisted of a three-dimensional mesh in which the nodes comprising the source/carrier bed were active to petroleum migration. The structural top of the Red River Formation was gridded from basin-wide well control to define the top of the carrier bed. The area of thermallymature source rock was based on a combination of soft lithofacies information and studies characterizing the Red River source rocks (Martiniuk and Barchyn, 1994; Osadetz and Snowdon, 1995; Osadetz et al., 1998). Hydrodynamic simulations used mapped formationwater pressures instead of a calculated hydrostatic pressure field within the carrier. Elevated paleo-pressure gradients were accounted for by increasing the hydraulic heads by up to three times in the uplifted areas and allowing the effect to dissipate toward the discharge areas in the northeast of the basin following an approximately exponential function. Simulations were performed in a stochastic framework, whereby statistical variability in the carrier bed pth field allowed petroleum trajectories to vary slightly in each realization. Other uncertainties were qualitatively assessed, such as the limit of the mature source area. 4. Simulation results Petroleum migration trajectories within a hydrostatic carrier bed radiate outward from the mature source area, driven by buoyancy along flowpaths defined by the steepest structural gradients (Fig. 1A). Notable irregularities in the pattern of petroleum dispersal are (1) the shadow zone (i.e., no petroleum) expanding eastward from the Nesson Anticline, (2) the shadow zone in the entire northwestern part of the study area, and (3) the early filling of the Cedar Creek Anticline, which traps all southwest-migrating petroleum before allowing some spillage. The shadow zone east of the Nesson Anticline is caused by the fact that the eastern limit of the kukersitic source beds coincides roughly with the axis of the Nesson anticline (Fig. 1A). As such, the anticline traps petroleum coming from the source area and funnels the oil out past the gentle updip closure to the north. There is considerable uncertainty in the
D.K. Khan et al. / Journal of Geochemical Exploration 89 (2006) 179–182
181
Fig. 1. (A) Hydrostatic simulation results (a single realization), with petroleum migration trajectories and producing areas (circles). Outline at basin centre indicates mature source. Depth contours increase toward the basin centre from 100 to 4200 m. (B) Hydrodynamic simulation results (a single realization).
eastern limit of the source facies; extending it beyond the eastern flank of the Nesson Anticline eliminated the shadow zone in North Dakota; however, the lack of Red River oil discoveries east of the Nesson Anticline (despite numerous well penetrations) is consistent with the results obtained. Indeed, the migration trajectories in a hydrostatic basin match the areas of known Red River production remarkably well; most importantly, matching with the cluster of northernmost producing areas in southeast Saskatchewan (Fig. 1A). Migration trajectories in a hydrodynamic basin differ considerably from the hydrostatic case (Fig. 1B). Inclusion of hydrodynamics diverts petroleum around the known production areas in southern Saskatchewan (Fig. 1B). Hydrodynamic pore pressure gradients induce large capillary pressure gradients, and as a result, the structural elevation gradient of the carrier bed is no longer the primary control on migration trajectories. Hydrodynamic migration is controlled by the interaction of the buoyancy force field and a new, or modified, heterogeneous resistive force field resulting in the differences in petroleum migration trajectories between the two cases. The strongest dynamic pressure gradients occur near the uplifted basin flanks with the result of completely arresting petroleum migration to the southwest quadrant of the basin, which was observed to varying degrees in the hydrostatic simulations. This
suggests that although migration to this part of the basin may have occurred, subsequent hydrodynamic effects may have flushed any petroleum accumulations in this area. The main phase of Red River oil migration must have taken place in a basin with pore pressures close to hydrostatic based on simulation results and corroboration with areas known to have received petroleum at long-distances from the source area. If the onset of the hydrodynamic regime in the Williston Basin had been coincident with, or preceded the narrow window of time that the Red River source was generative and secondary migration was taking place, the distal accumulations in Saskatchewan, Canada would not exist. 5. Conclusions and implications Simulation results constrained by known hydrocarbon accumulations indicate that the main phase of Red River oil migration must have taken place prior to the onset of the present-day hydrodynamic regime. The implications of this for exploration are: (1) Unless the organic rich kukersitic lithofacies can be shown to exist beyond the eastern flank of the Nesson Anticline, Red River exploration in North Dakota and southern Manitoba are extremely high-risk. (2) The Red River play types that have been prosperous in southeastern
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D.K. Khan et al. / Journal of Geochemical Exploration 89 (2006) 179–182
Saskatchewan should extend considerable distances to the north, as well as throughout central Saskatchewan, and western Manitoba. (3) Although migration seems to have taken place in a hydrostatic basin, hydrodynamics may have flushed and redistributed Red River petroleum accumulations, particularly in the Southwest of the basin, proximal to the present-day Black Hills, Bighorn Mountains, and central Montana uplifts, where the strongest hydraulic head gradients have existed. References Bethke, C.M., Reed, J.D., Oltz, D.F., 1991. Long-range petroleum migration in the Illinois Basin. AAPG Bulletin 75 (5), 925–945. Burrus, J., Osadetz, K., Wolf, S., Doligez, B., Visser, K., Dearborn, D., 1996. A two-dimensional regional basin model of Williston Basin hydrocarbon systems. AAPG Bulletin 80 (2), 248–264. Carruthers, D.J., 2003. Modeling of secondary petroleum migration using invasion percolation techniques. In: Duppenbecker, S., Marzi, R. (Eds.), Multidimensional Basin Modeling. AAPG/Datapages Discovery Series. AAPG/Datapages, Tulsa, OK, pp. 21–37. DeMis, W.D., 1995. Effect of cross-basinal hydrodynamic flow on oil accumulations and oil migration history of the Bakken–Madison petroleum system Wiliston Basin, North America. In: Hunter, L.D. V., Schalla, R.A. (Eds.), Seventh International Williston Basin Symposium. Montana Geological Society, Billings, Montana, pp. 291–301.
Dow, W.G., 1974. Application of oil correlation and source-rock data to exploration in Williston Basin. AAPG Bulletin 58 (7), 1253–1262. Lisenbee, A.L., DeWitt, E., 1993. Laramide evolution of the Black Hills uplift. In: S.A.W., Steidtmann, J.R., Roberts, S.M. (Eds.), Geology of Wyoming. Geological Survey of Wyoming Memoir, pp. 374–412. Longman, M.W., Haidl, F.M., 1996. Cyclic deposition and development of porous Dolomites in the Upper Ordovician Red River Formation, Williston Basin. In: Longman, M.W., Sonnenfeld, M. D. (Eds.), Paleozoic Systems of the Rocky Mountain Region. SEPM. Margitai, Z., 2002. Hydrogeological characterization of the Red River Formation, Williston Basin, Canada–USA, Unpublished M.Sc. Thesis, University of Alberta, Edmonton, Alberta, Canada. Martiniuk, C.D., Barchyn, D., 1994. Petroleum potential of the preMississippian, southwestern Manitoba. Bulletin of Canadian Petroleum Geology 42 (3), 365–391. Osadetz, K.G., Snowdon, L.R., 1995. Significant Paleozoic Petroleum Source Rocks in the Canadian Williston Basin: Their Distribution, Richness and Thermal Maturity (Southeastern Saskatchewan and Southwestern Manitoba). Minister of Energy, Mines and Resources, Canada. 60 pp. Osadetz, K., Kohn, B.P., O'Sullivan, P., Feinstein, S., Hannigan, P.K., Everitt, R.A., Gilboy, F., Bezys, R.K., Stasiuk, L.D., 1998. Williston Basin thermotectonics: variations in heat flow and hydrocarbon generation. In: Christopher, J.E., Gilboy, C.F., Paterson, D.F., Bend, S.L. (Eds.), Eighth International Williston Basin Symposium. Special Publication. Saskatchewan Geological Society, Regina, pp. 147–165.