PRELIMINARY SPATIAL ANALYSIS OF FAULTING AND GAS HYDRATE OCCURRENCE MILNE POINT UNIT, ARCTIC ALASKA

Greg. L. Gandler¹, Robert R. Casavant¹, Charles E. Glass¹, Andrew M. Hennes², Casey Hagbo², and Roy A. Johnson^2
1 Department of Mining and Geological Engineering, The University of Arizona, Tucson, AZ 85721
² Department of Geosciences, The University of Arizona, Tucson, AZ 85721

Shallow unconventional gas hydrate and associated free-gas resources have been identified in and around the Milne Point Unit (MPU) on the central North Slope, Alaska 1, 2. This potential unconventional energy resource is the subject of a multidisciplinary reservoir and fluid characterization program at the University of Arizona (UA). This presentation introduces a preliminary investigation of linkages between inferred hydrocarbon occurrence and the location, density, morphology, displacement, and orientation of syn- and post-depositional faults that compartmentalize the field.

The depth of interest in this field extends from the surface down to 1400m (4500ft), and includes the highly variable Tertiary Sagavanirktok formation. The Sagavanirktok consists of stacked fluvial-deltaic and shallow-marine sequences that in some respects reflect modern deposition in the area. The formation is extensively deformed by syn- and post-depositional faulting with some of the faults extending from basement to surface³. Interpretations of gas hydrate and free-gas resources within MPU are currently based on well log and mud log responses that appear to correlate with gas hydrates that were cored in the NW Eileen State 2 well southwest of the Unit. Geophysical attributes of gas hydrate occurrence are also under investigation. Thin beds of gas hydrates and free-gas occur in the upper 1300m of the stratigraphic section within sand- and gravel-rich units. The extent and quality of these clastic reservoirs confirms that they are vertically and laterally heterogeneous and that free-gas may not commonly communicate with contiguous updip gas hydrate. Gas hydrate zones may also exist within the lower half of a thick permafrost interval that extends to depths of 600m beneath the surface of the modern coastal plain, but are difficult to distinguish from ice-bearing sand intervals.

The MPU encompasses both onshore and offshore production from deeper Tertiary and Cretaceous units. Regional structure maps show that the field lies along the northern and steepest flank of a NW-striking anticline that plunges to the southeast. This structure, known as the Barrow Arch, is part of a regional east-trending antiform. The Barrow Arch has been subjected to episodic extension and fault reactivation as demonstrated by numerous stratigraphic studies. Displacements are dominated by basement-related normal and subsidiary strike-slip faults. This study investigates the location and quality of gas hydrate and free gas-bearing reservoirs in relation to fault proximity, density, morphology, and orientation. Relationships to fault timing/reactivation are not addressed. Although the analysis is not constrained to individual sequences, these may be addressed in future studies.

Dip slip movement along faults in the MPU varies widely and ranges from a few meters to more than 400 meters. The potential for impeding vertical and lateral movements of fluids across fault boundaries may be related to total fault displacement, sense of slip, and morphology. An important implication of the alternating sand and shale intervals within the Sagavanirktok is that displacement along faults may have created low-permeability zones that exhibit varying degrees of fault sealing; the most likely sealing mechanism is clay/shale smearing. ^4,5,6 Fault sealing mechanisms are currently being investigated by the UA team (this volume). Conversely, depending on kinematics, some fault segments may function as periodic conduits for upward migration of gas, which might then accumulate beneath thick shale units that are juxtaposed across a fault. Fault seal mechanisms in the MPU may be addressed more fully in the future.

Interpretation of gas hydrate spatial occurrence and proximity to faults reveals a correlation between gas hydrate thickness and fault proximity. Our analyses suggest that the position of gas hydrate and free-gas, as interpreted by previous studies in the MPU is reasonable. The hypothesis assumes that the closest fault to a gas hydrate or gas-bearing well would most likely play a role in either trapping or permitting up-section migration of gas. Reservoir units too far away or down-structure of the fault would be too low or outside the lateral extent of the gas accumulation. Reservoir modeling and neural network analysis may help to better qualify these assumptions.

Nearest faults and their apparent throw were identified from seismic fault maps and time-depth converted 3-D seismic attribute maps. In a few areas, faults were inferred where abrupt and linear changes in seismic waveform classification occurred. Perpendicular distances between faults and nearest gas hydrate- or free gas-bearing wells were measured on a workstation. Cross plots of the fault proximity to total thickness of gas hydrate per well are encouraging enough to warrant further study. Conversely, however, a spatial relationship between fault proximity and free-gas occurrence was poor, probably due to an inadequate sample population of free-gas thickness. Future analysis along this theme will incorporate fluid estimations, derived from quick-look analysis and a new log-based algorithm that estimates probable fluid types.

We also investigated the intensity of faulting. Calculation of fault intensity was similar to that employed in drainage density studies. Around each well, an appropriate and consistent circular area of about 12.5 km² was drawn. Within the perimeter of each area, the length of all faults and fault segments was summed. The idea was to compare the thickness of the gas hydrate and free-gas intervals with fault intensities. Our preliminary work shows no correlation between fault intensity and inferred resource occurrence. More work is planned on this topic.

Additional activities in our spatial/morphological analysis are still in progress. One analysis is looking for linkages between the general orientation of the closest fault/fault segment and gas hydrate-bearing and gas-bearing zones. Another study is investigating whether the presence or absence of free-gas and/or gas hydrates may be related to fault morphology (e.g. number of fault strands, vertical complexity, segments in plan-view, etc.). For example, many fault segments along the longer and more displaced NNE-trending faults exhibit en echelon pattern. At a regional scale, we are currently investigating the kinematics that fault pattern implies (i.e. transtensional shearing vs. extensional relay ramps). This work has implications to our understanding of fault seal mechanisms and sealing properties.

Another study in progress is comparing fault orientations and proximity to gas hydrate or free-gas occurrence. Three sets of fault orientations exist across the MPU. These include a north-northeast, a north-south, and less prevalent and structurally-complex northwest-trending set. For purposes of our preliminary orientation analysis all segmented fault zones were converted to rectilinear features to determine orientation and proximity to the nearest well. Only a few northwest-trending fault zones can be identified in shallow intervals across the MPU. These northwest fault zones are best described as diffuse structural hingelines rather than as discrete faults. They are identified on seismic maps by the (1) alignment of termini of north- and north-northeast-trending fault sets. (2) co-alignment of inflections, jogs or fault offset, and (3) offset/termination of graben structures. In vertical seismic profiles, northwest fault zones are characterized by (1) numerous small faults that exhibit little dip slip, (2) the presence a low amplitude zone, and (3) first-order changes in the structural attitude of stratigraphic units downflank of the anticline.

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., 1998, Gas hydrates of northern Alaska--a potential energy resource or just a nuisance?: Alaska Geology, v. 28, n. 1, p. 1-5.

2. 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.

3. 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.

4. Aydin, A., and E. Yehuda, 2002, Anatomy of a normal fault with shale smear: Implication for fault seal: American Association of Petroleum Geologist Bulletin, v. 86, n. 8, p. 1367-1381.

5. Sverdrup, E., J. Helgesen, and J. Vold, 2003, Sealing properties of faults and their influence on water alternating-gas injection efficiency in the Snorre field, northern North Sea: American Association of Petroleum Geologists Bulletin, v. 87, n. 9, p. 1437-1458 and reference therein.

6. Yielding, G., D. T. Freeman, and D. T. Needham, 1997, Quantitative fault seal prediction: American Association of Petroleum Geologists Bulletin, v. 81, n. 897-917.