--> Structural Analysis of a Proposed Pull-Apart Basin: Implications for Gas Hydrate and Associated Free-Gas Emplacement, Milne Point Unit, Arctic Alaska, by R. R. Casavant, A. M. Hennes, R. A. Johnson, and Tim S. Collett; #90035 (2004)

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STRUCTURAL ANALYSIS OF A PROPOSED PULL-APART BASIN: IMPLICATIONS FOR GAS HYDRATE AND ASSOCIATED FREE-GAS EMPLACEMENT, MILNE POINT UNIT, ARCTIC ALASKA

R. R. Casavant1, A. M. Hennes2, R. A. Johnson2, and Tim S. Collett3
1 Department of Mining and Geological Engineering, University of Arizona, Tucson, AZ 85721
2 Department of Geosciences, University of Arizona, Tucson, AZ 85721
3 U.S. Geological Survey, Denver Federal Center, Denver, CO 80225

A robust petroleum system is in place for the generation and emplacement of shallow gas hydrate and associated free-gas resources1 on the central North Slope of Alaska. A better understanding of the distribution, quality, and quantity of these unconventional resources is the objective of a detailed, interdisciplinary reservoir characterization program at the University of Arizona (UA). If found to be commercially viable, the estimated volume of these unconventional resources across the central North Slope will constitute a significant alternative energy target for the nation. Current interpretations place these resources within the eastern portions of the Kuparuk River and the Milne Point Units (KRU, MPU), and the western edge of the Prudhoe Bay Unit (PBU)1. The majority of reservoirs are contained within a thick interval of Late Cretaceous to Late Tertiary stacked sequences of fluvial-deltaic and nearshore marine gravels, sands, and shales.

Near the MPU, the depths of potential reservoirs range from 220 to 1,400 meters below sea level. Where pressure-temperature conditions are favorable for clathrate formation, gas hydrates have formed within the porous, thin-bedded, multistory sand-rich intervals1. Individual gas-hydrate-bearing sands can range in thickness from a few meters to over 30m thick. Across the MPU, the net thickness of free-gas intervals ranges from less than a meter to tens of meters. Thin free-gas-bearing zones occur throughout the study area with best occurrences downdip and below the gas hydrate stability zone (GHSZ). Porosity and resistivity logs indicate more than 10 meters of free-gas bearing sands downdip of gas hydrate-prone intervals for several wells. The likelihood of interbedded free-gas and gas hydrate intervals may be due to localized variations in structural and stratigraphic constraints, varying pressure-temperature conditions, and/or changes in pore-fluid salinity.

Regional structural mapping in the MPU and KRU indicates that gas hydrates and free-gas occur along the highly faulted, northeast-dipping flank of a large anticlinal structure2, 3. This southeast-plunging antiform lies along a regional east-west trending basement antiform, known as the Barrow Arch, which coincides with the northern rifted margin of the Arctic Alaska terrane (AAT) that rifted and docked into its present position during the mid-late Mesozoic4. Fault reactivation and structural inversion along weakened and long-lived basement fault blocks beneath MPU and KRU have been linked to basinal fluid migration and variations in permafrost thickness. Periodic crustal shortening along the southern margin of the terrane continues to reactivate basement deformation across the major structural provinces2.

Interpretations of 3-D seismic data in the MPU reveal that the shallow package of gas-hydrate-bearing rocks in the area is extensively deformed by north- and north-northeast trending syn- and post-depositional faults3. The presence of a diffuse and segmented northwest-trending structural hingeline can be identified on seismic maps as well as by (1) the alignment of termini of north- and north-northeast-trending faults, (2) alignment of inflections, jogs or offset of those fault sets, (3) the offset/termination of some graben structures, and (4) first-order changes in the structural attitude of stratigraphic units downflank, although no NW-trending offset is resolvable in the vertical seismic sections. These hingelines have been linked to deeper fault zones that segment oil reservoirs and define important oil/water contacts in deeper Cretaceous-age reservoirs6. Shallow fault displacements, vertical morphologies, and plan-view distribution suggest that MPU is dominated by down-to-the-east northeast-trending and down-to-the-north northwest-trending systems of normal faulting. A similar conjugate set has been illustrated in numerous studies and recently by Fry (center-to-center) structural analysis of discrete fault blocks at shallow structural levels (this study).

Fault patterns and displacements across the central portion of the MPU suggest the presence of a small, northeast-trending pull-apart basin that may have influenced sediment deposition and the later emplacement of gas hydrates in the area. Analog modeling suggests that the sigmoidal fault geometries in this part of the MPU relate to transtensional deformation in weak sedimentary cover above a left-stepping sinistral strike-slip fault system at depth. En echelon fault patterns support the proposal that the basin formed from the linkage of basement faults across a 30-60° releasing sidestep7. Dimensions of the better-defined portion of the basin, herein referred to as the "Milne Point basin" (MPB), are approximately 5.6 km-wide by 13.7 km-long. The current length/width aspect ratio of the MPB (~2.5:1) suggests that the basin may be close to fully developed7. The northern extent of this transtensional basin is estimated by the convergence of 3-4 fault zones just onshore and west of a pronounced orthogonal bend in the coastline referred to as Milne Point. Southward extrapolation of fault trends into the KRU suggests probable convergence of basin-bounding faults above an offset northeast-trending principal shear.

Intrabasinal structures include an arrangement of cross-basin faults and en echelon fault segments. The MPB is dominated by relatively undeformed half-grabens and an interesting alignment of grabens along the western and eastern margins of the basin. Experimental models and field examples such as the MPU show that pull-apart basins are bounded by complex sidewall faults that exhibit the largest displacements and steep oblique-extensional slip7. The sidewall faults of the MPB are characterized by of a "lazy-Z" geometry that may be related to the formation of structural terraces, and in some locations, small grabens, and fault kinks5. These sidewall fault zones are dominated by right-stepping en echelon and overlapping fault segments. The overlaps may mark the locations of transfer fault zones or relay ramps that probably controlled local sediment input and erosion along the basin margins. These patterns may imply linkage to a deeper through-going sinistral shear zone beneath the basin that may serve as either conduits or barriers to gas migration. Recent seismic interpretations at U. S. Geological Survey support the interpretation of fault linkage at depth.

Vertical seismic profiles and plan-view distributions of faults support the pull-apart model. Dominant half-graben structures are mostly north trending and bordered by en echelon normal fault segments of variable length. Fault displacement along the axis of the basin is dominated by two elongated, 3.5-km long lozenge-shaped inline rhombs. The sidewall faults are broadly antithetic to each other and characterize the pull-apart as a broad graben. Analog models demonstrate that although inline antithetic fault zones (grabens) do occur in pull-apart basins, half-grabens should be the dominant structures. In this sense, the MPB appears to be somewhat unique since segments of its western margin and almost all of its eastern flank are bordered by well-developed en echelon grabens.

These marginal grabens were probably reactivated and downdropped during renewed transtension across the region that resulted from loading in the Eastern Brooks Range and regional tilting of the Barrow Arch. Preliminary USGS interpretation of industry 3D seismic data in the MPU shows some larger-displacement basin-bounding sidewall faults extending from basement to the surface. Overlying these faults, shallow reflectors within the permafrost, gas hydrate, and underlying intervals appear to be more disrupted and displaced relative to intrabasinal areas, attesting to their activity. Wells located within marginal grabens generally exhibit a higher net/gross sand ratio, suggesting that the deep-seated sidewall fault zones were in-part syndepositional and influenced facies distributions and depositional environments. Research into the fault seal probabilites9 and the juxtaposing of reservoir sands along these faults is the topic of on-going research. The axis of the basin coincides with the location and orientation of a north and northeast-trending depositional hingeline as seen on gross and net sand maps of the upper gas-hydrate-bearing sequences in the MPU. The role that this proposed MPB structure might play in sediment deposition, gas hydrate emplacement, and the GHSZ are being studied.

Regional stratigraphic and geophysical studies show that periodic reactivation along basement block boundaries resulted in localized sagging and structural inversion along zones of weakened crust that were constrained to the margins of basement blocks. Morphotectonic analyses of numerous locales across the AAT suggests that basement faulting has long influenced the surface geomorphology, location of modern to ancient fluvial-deltaic to nearshore marine systems, and upward migration of fluids and heatflow2, 8, 9. Seismic structure mapping of shallow sequences in MPU reveals some spatial correlation between subsurface structure and geomorphic features at the surface. These spatial associations suggest the influence of shallow basement control on the morphology of coastal and fluvial elements across the Arctic coastal plains2.

Seismic attribute analysis and geologic mapping confirm that in addition to fault compartmentalization, reservoir continuity is also related to changes in facies type and geometry. Both regional lithostratigraphic and chronostratigraphic correlation frameworks address the stratigraphic and reservoir rock continuity. Lithostratigraphic correlation across the study area confirmed the presence of at least six distinct and laterally continuous gas hydrate-bearing reservoir units1. Application of a more recent sequence stratigraphic framework implies a higher degree of reservoir heterogeneity. The distribution and quality of reservoir sands relates not only to rapid changes in depositional environments and facies, but also to the preservation and scouring of reservoir units along numerous intraformational unconformities that define many sequences. A study of facies, sand body dimensions, and related seismic facies mapping will be employed to develop a more accurate model of reservoir description needed for estimating volumetrics and recovery factors. The sequence stratigraphic analysis and paleodepositional reconstruction is the subject of current research10.

Acknowledgements and Disclaimer:

The University of Arizona contribution is part of a larger collaborative program that includes researchers from the University of Alaska Fairbanks and the U.S. Geological Survey. BP Exploration (Alaska), Inc. provides overall project coordination and provided data for the characterization and modeling efforts. Interpretation and processing software was made available through support from the University Grants Program of Landmark Graphics Corporation and from GeoPlus Corporation. This research was funded by the Department of Energy (Award # DE-FC-01NT41332). The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

References

1. Collett, T. S., K. J. Bird, K. A. Kvenvolden, and L. B. Magoon, 1988, Geologic interrelations relative to gas hydrates within the North Slope of Alaska: United States Geological Survey Open-File Report, v. 88-389, n. 150.

2. Casavant, R. R., 2001, Morphotectonic Investigation of the Arctic Alaska Terrane: Implications to Basement Architecture, Basin Evolution, Neotectonics and Natural Resource Management: Ph.D thesis, University of Arizona, 457 p.

3. Hennes, A., Johnson, R., and R. Casavant, Seismic Characterization of a Shallow Gas-Hydrate-Bearing Reservoir on the North Slope of Alaska, this volume.

4. Hubbard, R. J., S. P. Edrich, and R. P. Rattey, 1987, Geologic evolution and hydrocarbon habitat of the Arctic Alaska microplate, in I. Tailleur, and P. Weimer, eds., Alaskan North Slope Geology, Bakersfield, CA, Society of Economic Paleontologists and Mineralogists, Pacific Section, and Alaska Geological Society, p. 797-830.

5. Grantz, A., S. D. May, and D. A. Dinter, 1988a, Geologic framework, petroleum potential, and environmental geology of the United States Beaufort and northeasternmost Chukchi Seas, in G. Gyrc, ed., Geology and Exploration of the National Petroleum Reserve in Alaska, 1974 to 1982, Washington, D.C., U.S. Geological Survey Professional Paper, p. 231-256.

6. Werner, M. R., 1987, West Sak and Ugnu Sands: Low-gravity oil zones of the Kuparuk River area, Alaskan North Slope, in I. Tailleur, and P. Weimer, eds., Alaskan North Slope Geology, Bakersfield, CA, The Pacific Section, Society of Economic Paleontologists and Mineralogists.

7. Dooley, T., and K. McClay, 1997, Analog modeling of pull-apart basins: American Association of Petroleum Geologists, v. 81, n. 11, p. 1804-1826.

8. Rawlinson, S. E., 1993, Surficial geology and morphology of the Alaskan central Arctic Coastal Plain: Alaska Division of Geological and Geophysical Surveys Report of Investigations, v. 93-1, n. 172.

9. Casavant, R. R., and S. R. Miller, 1999a, "Is the Western Brooks Range on the move?", Abstracts with Program, Geological Society of America, 1999 Annual meeting, Denver, CO, v. 31, n. 7, p. 474.

10. Hunter, R.B., Casavant, R.R., Johnson, R.A., and 11 others, Reservoir-fluid characterization and reservoir modeling of potential gas hydrate resources, Alaska North Slope.

Figure 1. Shallow fault map within the MPU and proposed pull-apart basin (light gray stipple). Regional structural dip is to the east. Fault segments with dip slip greater than 100 ft. are shown as bolder lines. Axial inline rhomb-shaped half-grabens shown in dark gray. Grabens marked with stripe pattern. Unit boundary and coastline shown for reference.