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PSThe Future Oil Discovery Potential of the Mackenzie/Beaufort Province*
Zhuoheng Chen1, Kirk Osadetz1, James Dixon1, Giles Morrell1, and J.R. Dietrich1
Search and Discovery Article #10133 (2007)
Posted September 3, 2007
*Adapted from poster presentation at AAPG Annual Convention, Long Beach, California, April 1-4, 2007. National Resources Canada ESS contribution number: 20070247.
1Geological Survey of Canada, Calgary, AB ([email protected])
The Mackenzie/Beaufort province hosts large quantities of proven and potential petroleum resources that are of strategic importance for future North American energy supply. Petroleum exploration in the province has resulted in 53 distinct accumulations in 48 significant conventional crude oil and gas discoveries (National Energy Board, 1998). The discovered quantities of conventional petroleum resources are estimated to be 1.744 x 109 bbls (277.3 x 106m3) recoverable crude oil and 11.74 tcf (332.4 x 109m3) recoverable natural gas (Dixon et al., 1994). Recent studies of unconventional petroleum resources indicate that an immense natural gas potential exists in the form of methane hydrate in this province (e.g., Osadetz and Chen, 2005).
The Mackenzie/Beaufort province (Figure 1) exhibits a complex basin evolution (Figure 2A), from an open marine setting throughout most of the Paleozoic, followed by a rift-drift system in Jurassic to Early Cretaceous. The Late Cretaceous-Cenozoic successions represent a post-rift passive-margin basin comprising more than 14 km of deltaic sediments (Dixon et al., 1992), complicated by the Cordilleran Thrust Belt in the west. Tectonically, the province can be divided into four structural domains: a stable craton in the south and southeast, a rifted margin in the southeast, the Cordilleran Fold Belt in the southwest, and the Canada Basin in the north. Figure 2 is a composite diagram, showing regional stratigraphy, major tectonic events, essential petroleum system elements, petroleum plays/play groups and their stratigraphic position and spatial association, and discovered reserve and estimated potential oil resources. Although oil discoveries are from almost all stratigraphic levels, from Paleozoic to Cenozoic, more than 95% of discovered oil accumulations are in Tertiary successions.
This study is based on the previous petroleum resource assessment conducted by the Geological Survey of Canada (GSC) (Dixon et al., 1994), with emphasis on the petroliferous rifted basin margin and the southern part of the Canada Basin, extending from south of the Mackenzie Delta, north to about 2500 meter water depth because this is the most accessible region for exploration and development. Areal extent of the assessment and boundaries of the play groups are shown in Figure1. Several petroleum plays overlap, particularly in the south, because of the nature of the rifted passive margin and the stacked stratigraphy of the delta systems. Recent studies in organic geochemistry, basin hydrodynamics, petroleum systems analysis, and geoscience data integration in cooperation with industry, provide an improved geoscience framework for understanding the petroleum resource potential in this province.
Three major potential source rock sets may exist in this province: a) the Jurassic-Lower Cretaceous syn-rift shales, b) Upper Cretaceous passive margin marine shales, and c) Tertiary passive margin marine shales. The syn-rift Jurassic-Lower Cretaceous successions may have three potential source beds. Shale in the Husky Formation is found in the southeast basin margin and nearshore areas, and it is also possibly present in some of the deeply buried grabens in the shelf area. If the rotational model of Arctic plate tectonics is valid, the syn-rift Jurassic-Lower Cretaceous (J-lK) successions should also be present in the west Beaufort Sea. Oil and source rock correlation indicates that this shale could be a major contributor of natural gas in the Parsons Lake gas field and Unak gas discovery (Langhus, 1980). The Lower Cretaceous Arctic Red Formation, found in the Kugmallit Trough in a slope to basinal environment (Dixon et al., 1994), is presumably present in most of the province and represents sedimentation during the last phase of continental drifting. Recent organic geochemical analyses indicate biomarker signatures from the Arctic Red shale in a number of discoveries (Li, personal communication, 2006). Localized source rock, such as the Lower Cretaceous McGuire shale, is inferred to be responsible for oils found in the Kamik discovery well and adjacent areas (Dixon, personal communication). It may also be present in the offshore area. Source rock maturity studies (see Figure 5) indicate that the J-lK source rocks could be one of the sources for the Rifted Margin, Taglu Delta and Kugmallit Delta play groups, but are over-cooked in most of the offshore area, because of deep burial.
The Upper Cretaceous succession of the Boundary Creek and Smoking Hills formations represents the earliest sedimentary records accumulated in outer shelf and slope environments of this passive margin basin and contain organic-rich and radioactive shales, which are widely distributed in the Arctic region. These shales are recognized to be one of the major contributors to the oils found in the discoveries in the Tuk, Atkinson and Mayogiak wells, in the central and northern Tuktuyaktuk Peninsula (Dixon et al., 1994; Dixon et al., 1985). Biostratigraphic data and new 3D seismic interpretation indicate that the uK mobile substrata cores some of the shale diapirs (Bergquist et al., 2003) in the west Beaufort Sea, and part of the uK source rock could still be in the hydrocarbon generation window in part of the offshore area.
The Lower Tertiary succession contains several organic-rich shale intervals in the major sequences, such as Richards, Taglu and Aklak, and are inferred to be responsible for some of the oil and gas accumulations found in this province (Snowdon, 1984; Snowdon et al., 2004; Brooks, 1986). Where it is mature, the Tertiary succession is considered to be one of the major source rocks for the accumulation in the deep/ultra deep-water setting. Analyses of the measured vitrinite reflectance from cuttings and cores indicate that the maturity level of the Lower Tertiary succession has reached the oil window just below 3000 meters (Ro>0.6%) in the Richards Island and western Beaufort Sea. The vitrinite reflectance reached 0.6% at top of the Aklak Sequence in Richards Island and offshore areas. The oil correlations indicate a good correspondence between the oils from the Adlartok P-09 well and Tertiary source rocks (Li, personal communication). It is anticipated that the Lower Tertiary shales and coal seams are the major sources for the oil and gas accumulation in the west Beaufort Sea play and an important contributor in other part of the shelf areas.
Organic geochemical analyses indicate a large range of variation in TOC% measured from cuttings and side wall cores in exploration boreholes at almost all stratigraphic levels. Although most samples have a TOC% <3%, a number of stratigraphic intervals show a fairly high TOC, up to 9%. Figure 3 displays histograms of TOC% from nine stratigraphic levels, showing the variations. Results from Rock-Eval analysis suggests a diversity of kerogen types in the basin. Figure 4 is a cross-plot set of hydrogen index vs. oxygen index of borehole cuttings from nine stratigraphic intervals, suggesting predominant type II and type III kerogen in this province.
Vitrinite reflectance was measured from cuttings and cores in ninety two wells (green dots, Figure 5). Maturity level increases basin-wards at the top of the Aklak Sequence; whereas it increases northwest-wards for the Mesozoic and older strata. Figures 5a - e show maturity trends at tops of five different stratigraphic levels, indicated by the vitrinite reflectance (Ro) contours. Figure 5f is a Ro contour map at a depth of 3000 meters, showing the spatial variation of the basin thermal heterogeneity.
Petroleum system modeling suggests multiple phases of petroleum generation and migration from potential source rocks at different burial depths. Significant petroleum generation/migration may have started as early as Late Cretaceous and continued to rather recently, depending upon the thermal history of the source rocks. Figure 6 shows results from 1D modeling at four synthetic well locations, illustrating hydrocarbon generation/expulsion histories in different parts of the basin.
In the west Beaufort Sea, the Tertiary sources appear to be the effective source rocks because of the high thermal maturity level, whereas the Cretaceous and older source rocks have all passed through oil window and the oils were expelled before the major phase of trap formation in the late Eocene. In contrast, in the southeast part and deep-water portion of the basin, the Cretaceous source rock seems to be the major contributor because of either a shallow burial depth of the Tertiary source rocks in the rifted margin or a low level of maturity in the Tertiary depocenters.
Faults/fracture zones associated with mobile substrata, listric and thrust fault systems provide adequate vertical migration routes. However, fluid migration and entrapment are dynamic processes throughout the entire basin development history. The episodic nature of overpressure and pressure release may have led to loss/partial loss or redistribution of early accumulated hydrocarbons.
Several episodes of tectonic activity in the Tertiary are recognized in this province (Lane and Dietrich, 1998). The most important ones include tectonic inversion during the Late Eocene, which led to diapirism and trap formation over a wide area. While in the eastern part, the same tectonic episode reactivated the pre-existing faults and generated roll-over structures. Tectonic activity at the end of the Miocene may have triggered large scale submarine sliding and formed turbidities and basin-floor sheet sands over a wide area. Tectonic activity at the end of the Miocene may have accelerated the secondary migration process and caused re-migration of some previously trapped hydrocarbon accumulations.
In the Tertiary basin-fill history, five major delta systems developed (Figure 2A). Figure 7 shows four of the major delta systems, illustrating the extent of each of the systems, and how the delta systems evolved in time and space in response to tectonism, and depositional provenances. The shape and areal extent of each individual delta system is defined from the 20% and 30% sand content derived from borehole logs. The major delta systems cover almost the entire present continental shelf and Richards Island. The deltaic sandstones of delta plain and delta front provide quality reservoirs for hydrocarbon accumulations in the Taglu Delta, Kugmallit Delta, and West Beaufort Sea play groups.
Additional types of reservoir rock include channel-fill sandstones and submarine-fan sands in recent as well as paleo-slope and deep-water basins. Interpretation of the newly acquired 3D seismic data indicates the existence of large scale channel-fill sandstones in the Richards Sequence (Bergquist et al., 2003) in the west Beaufort Sea (Figure 8). The Oligocene and Miocene sequences are shale-dominant in general, and they may also contain channel-fill sandstones or other type of sand bodies. For example, clinoforms (Figure 41 of Dixon et al., 1985; Figure 11b and 13 a and b of Hubbard, et al., 1985) and channel forms (seismic profile 8E of Dixon et al., 1990) on seismic lines in the Mackenzie Bay Sequence indicate delta front, delta plain and channel sands. Sandstones associated with submarine fan systems in the Iperk, Mackenzie Bay and Kugmallit sequences are the major reservoir type in the Basinal facies play.
In the deep-water play, inferences were made based on analogy to known world deep-water settings (Weimer and Slatt, 2004), as well as the pale-slope and deep-water basin of this province, and limited regional seismic interpretation. Three possible reservoir types may exist in this play: channel fill sands/sandstones, basin floor turbidite sand sheets, and overbank levee sand beds. Interpretation of available reflection seismic lines indicates various channel fills and possible basinfloor sheet sands in Tertiary stratigraphic successions. These reservoir rocks are more subtle in older strata on seismic profiles, but possibly also present.
For the Rifted Margin play group, discoveries in the Mesozoic and Lower Paleozoic indicate both porous clastics and carbonates are present and can be reservoir rocks. However, they are restricted to the rifted margin play group in the southeast and shallow shelf in the east.
Several types of traps have been recognized in this region. Structural closures associated with shale-cored anticlines formed during the Eocene tectonic inversion (Bergquist et al. 2003; Dixon, et al., 1994) are typical in the fold belt in the western part of the province (Figure 9). This type of structural trap is also common in the slope between water depths of 500 m to 2500 m. Beyond the outer continental slope, the magnitude of the structures becomes smaller and then disappears. This type of structures is large (see closure size distribution in Figure 10 from mapped structure traps), and faults are commonly part of this structural trap. These Tertiary diapiric structures become progressively younger northward, from the uK Smoking Hills/Boundary Creek cored structures (Bergquist et al. 2003) in the west Beaufort Sea to pre-Eocene diaper-cored structures in the slope (Dixon et al., 1990) to the north. Other trap types associated with shale diapirism include the stratigraphic pinch-out against diapirs, fault-sealed structural noses, and drape structures over the diapirs. In contrast, the trap styles of a typical passive margin comprise roll-over structures in the east and the delta, and fault blocks in the southeast along the basin margin. These later types of structure are more apparent in the older stratigraphic succession. Roll-over anticlines associated with listric faults are most common in the delta area.
Stratigraphic traps are recognized in this province. Unconformity traps are interpreted from seismic data, and pinch-out is an important component for several discoveries made in the basinal facies play (Dixon et al., 1994). Other traps, such as a combination of structural and stratigraphic traps and unconformity associated traps (e.g., erosional truncations), are anticipated in this basin.
The shale-dominant Richards, Mackenzie Bay and Akpak sequences are regional top seals in this area. The shales in this region may contain substantial amount of silts, which may affect the seal capacity.
The seal integrity may be at risk for some of the diaper-cored anticlines because diapirism, overpressure, and associated crestal faulting/fracturing may have weakened the top seal. Note the shallow overpressure zone in the basinal facies play, north to the Tarsiut-Amauligak Fault Zone (TAFZ).
Eighteen plays were defined based on the trap configurations and reservoir age/types, among which fourteen are identified or inferred to have oil potential. Figure 2C shows the stratigraphic and predominant trap type of the plays/play groups. This assessment employs the GSC's probabilistic approach and uses plays as the assessment unit. For the established plays with sufficient discoveries, statistics from known pools/fields provide good data for estimating the distribution of volumetric parameters, such as pool area, reservoir porosity, net pay, and hydrocarbon saturation. For the immature and conceptual plays, the estimation of the volumetric parameters is based on geological similarities with known plays. For the deep water area, where no wells were drilled, analogs were used to derive the volumetric parameters.
These fourteen plays were assessed separately for oil, and the resources were then aggregated into play groups to represent the stratigraphic and geographic distribution of the oil potential. The six play groups include the Rifted Margin group, the Taglu Delta group, the Kugmallit Delta group, the basinal facies group, the deep water group, and western Beaufort Sea group. Estimated oil potential appears to increase basinward, reflecting the geological control of source-rock quality and source-rock maturity. Other geological factors such as overpressure and top-seal leakage may also affect the geographical distribution of oil resources.
Figure 12a to f are cumulative distributions of the aggregated play group resources for the six play groups, showing the estimated potential and associated ranges of uncertainties. The estimated resource potential in the six play groups, as well as the province are summarized in Table 1. The rifted margin play group has an estimated mean of 1.6 billion barrels (268 x106m3) and the Taglu Delta group has 1.2 billion barrels (184 x106m3) recoverable oil resources. The plays in these groups are more gas prone and have the lowest oil potential among the plays assessed. The Kugmallit Delta has a mean estimate of 2.6 billion barrels (415 x106m3) of recoverable oil. The basinal facies play has potential of 2.4 billion barrels (386 x106m3), and deep water play group has the largest oil resource with a mean estimate of 6.7 billion barrels (1072 x106m3) recoverable oil. The western Beaufort play group has a mean of 2.2 billion barrels (351 x106 m3) recoverable oil. The aggregated total mean for the six play groups is 16.8 billion barrels (2.7 x109m3) recoverable oil (Figure 13).
Given the large undiscovered oil resource potential, the future discovery growth in this province is expected to come from:
Only a part of the entire Mackenzie/Beaufort province prospective sedimentary succession is the subject to this petroleum resource potential appraisal. Our focus is limited to the region south of continuous pack ice and restricted to the shallow part of the total sedimentary succession (largely in the Tertiary succession). This reflects the current, early exploration history stage of this province. It is expected that there will be both increased data and understanding that will lead to new large discoveries in the more remote areas and deeper parts of the sedimentary succession as the scope of exploration expands both geographically and technologically. The discovery and reserve growth patterns of the Mississippi Delta petroleum province, where very large accumulations continue to be found as exploration expands into the geographically remote, deep water and technologically challenging parts of the Gulf of Mexico, may provide a useful analogy for the future exploration outlook and overall potential of the Mackenzie/Beaufort province.
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