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AU: F. AGOSTA, M. PRASAD, A. AYDIN
TI: Physical properties of carbonate fault rocks, fucino basin (Central Italy): implications for fault seal in platform carbonates
SO: Geofluids
VL: 7
NO: 1
PG: 19-32
YR: 2007
ON: 1468-8123
PN: 1468-8115
AD: Rock Fracture Project, Department of Geological and Environmental Sciences and; Geophysics Department, Stanford University, Stanford, CA, USA
DOI: 10.1111/j.1468-8123.2006.00158.x
US: http://dx.doi.org/10.1111/j.1468-8123.2006.00158.x
AB: We documented the porosity, permeability, pore geometry, pore type, textural anisotropy, and capillary pressure of carbonate rock samples collected along basin-bounding normal faults in central Italy. The study samples consist of one Mesozoic platform carbonate host rock with low porosity and permeability, four fractured host rocks of the damage zones, and four fault rocks of the fault cores. The four fractured samples have high secondary porosity, due to elongated, connected, soft pores that provide fluid pathways in the damage zone. We modeled this zone as an elastic cracked medium, and used the Budiansky2013O'Connell correlation to compute its permeability from the measured elastic moduli. This correlation can be applied only to fractured rocks with large secondary porosity and high-aspect ratio pores. The four fault rock samples are made up of survivor clasts embedded in fine carbonate matrices and cements with sub-spherical, stiff pores. The low porosity and permeability of these rocks, and their high values of capillary pressure, are consistent with the fault core sealing as much as 77 and 140 m of gas and oil columns, respectively. We modeled the fault core as a granular medium, and used the Kozeny2013Carmen correlation, assigning the value of 5 to the Kozeny constant, to compute its permeability from the measured porosities and pore radii. The permeability structure of the normal faults is composed of two main units with unique hydraulic characteristics: a granular fault core that acts as a seal to cross-fault fluid flow, and an elastic cracked damage zone that surrounds the core and forms a conduit for fluid flow. Transient pathways for along-fault fluid flow may form in the fault core during seismic faulting due to the formation of opening-mode fractures within the cemented fault rocks.


AU: STANLEY J. LUKASIEWICZ, JAMES S. REED
TI: Specific Permeability of Porous Compacts as Described by a Capillary Model
SO: Journal of the American Ceramic Society
VL: 71
NO: 11
PG: 1008-1014
YR: 1988
ON: 1551-2916
PN: 0002-7820
AD: New York State College of Ceramics, Alfred University, Alfred, New York 14802
DOI: 10.1111/j.1151-2916.1988.tb07572.x
US: http://dx.doi.org/10.1111/j.1151-2916.1988.tb07572.x
AB: The specific liquid permeabilities of a wide variety of phosphatebonded, porous alumina compacts prepared from alumina powders of differing size distribution, and ranging in porosity from 32 to 50 vol%, were not described well by the Carmen-Kozeny model but were described by a capillary model based on mean entry pore radius. The specific permeability varied directly with the square of the mean entry pore radius determined by mercury intrusion. The compacts containing the lowest phosphate bond phase obeyed Poiseuille's law.


AU: J. A. Deckelman, S. Lou, P. S. D'onfro, R.W. Lahann
TI: QUANTITATIVE ASSESSMENT OF REGIONAL SILICICLASTIC TOP-SEAL POTENTIAL: A NEW APPLICATION OF PROVEN TECHNOLOGY IN THE PELOTAS BASIN, OFFSHORE BRAZIL
SO: Journal of Petroleum Geology
VL: 29
NO: 1
PG: 83-96
YR: 2006
ON: 1747-5457
PN: 0141-6421
AD: ConocoPhillips Company, Houston, Texas, USA.
DOI: 10.1111/j.1747-5457.2006.00083.x
US: http://dx.doi.org/10.1111/j.1747-5457.2006.00083.x
AB: Using the offshore Pelotas Basin, Brazil, as an example, we present a methodology by which petrophysically-derivedVclay and capillary displacement pressure data, in conjunction with interval isochore maps, can be used quantitatively to evaluate regional, siliciclastic present-day and palaeo-top-seal effectiveness and relative risk. This method has broad application to frontier and maturing exploration areas where data limitations preclude more sophisticated seismically-derived velocity-based evaluations. As much of the Pelotas Basin is deemed to be gas prone, top-seal effectiveness for normal density (0.1 to 0.2 g/cc) dry gas was assessed quantitatively by establishing relationships between density-log -derived hydrocarbon column height and overburden thickness using a most likely Vclay content. With constant Vclay, column height increases with increasing overburden due to a compaction-driven decrease in mudrock porosity, accompanied by a decrease in permeability and pore-throat diameter. Using these relationships, interval isochore maps (overburden thickness maps) can be transformed into hydrocarbon column-height maps to define spatial variation in top-seal effectiveness, expressed in metres of contained gas column. Laboratory and previously-published model data show that clay content and porosity (ultimately pore throat diameter) are the dominant controls on siliciclastic mudrock permeability, hence top-seal potential. Mudrock porosity is driven dominantly by burial-induced compaction; clay content is dependent on both depositional and diagenetic processes. Overburden can be determined with a reasonable degree of certainty from seismic and well data, whereas regional variations in clay content can, at best, only be estimated from depositional models. Therefore, for a given overburden, it is uncertainty in clay content that comprises the greatest risk in regional siliciclastic top-seal analysis. For this reason, we relate siliciclastic top-seal risk to clay content, when overburden/ mudrock-porosity relationships, fluid densities and requisite column heights are known.


AU: B. Beiranvand, A. Ahmadi, M. Sharafodin
TI: MAPPING AND CLASSIFYING FLOW UNITS IN THE UPPER PART OF THE MID-CRETACEOUS SARVAK FORMATION (WESTERN DEZFUL EMBAYMENT, SW IRAN) BASED ON A DETEMINATION OF RESERVOIR ROCK TYPES
SO: Journal of Petroleum Geology
VL: 30
NO: 4
PG: 357-373
YR: 2007
ON: 1747-5457
PN: 0141-6421
AD: Petroleum Geology Dept., Exploration & Production Division, Research Institute of Petroleum Industry, Western side of Azadi Complex Stadium, PO Box 14857-3311 Tehran, Iran.; Reservoir Study Center, Exploration & Production Division, Research Institute of Petroleum Industry, Western side of Azadi Complex Stadium, PO Box 14857-3311 Tehran, Iran.; Reservoir Simulation Department, RIPI, No. 7, Hoveyzeh St. Shariati Ave., PO Box 1863 Tehran, Iran.
DOI: 10.1111/j.1747-5457.2007.00357.x
US: http://dx.doi.org/10.1111/j.1747-5457.2007.00357.x
AB: The mid-Cretaceous Sarvak Formation, the second-most important reservoir unit in Iran, is composed mainly of grain-supported carbonates. For the purposes of this study, flow units in the upper part of the formation were identified, mapped and classified as part of an integrated reservoir characterization study at a giant oilfield in SW Iran. Pore types and geometries, pore-scale diagenetic history and core-scale depositional attributes were logged using conventional petrographic and lithological methods. The resulting data were combined with core descriptions, mercury-injection capillary pressure data, and wireline log and geophysical data to identify five reservoir rock types: (i) highly oil-stained, grain-supported carbonates, including patch reef and barrier complex deposits with high porosities and permeabilities; (ii) leeward and seaward shoal deposits including grain-supported packstones and skeletal wackestones with high porosities and permeabilities; (iii) dominantly mud-supported lagoonal and open-marine facies with fair porosity and permeability; (iv) grain-supported but highly cemented facies which had poor reservoir characteristics; and (v) calcareous shales and shaly limestones with no reservoir quality. Based on the reservoir rock types, eight flow units were recognised. Subsequently, four reservoir zones were defined based on these flow units at a field scale. This study has contributed to our understanding of flow units in this complex carbonate reservoir, and has improved our ability to characterize and model the architecture of the reservoir from pore to core to field scale.