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  | author  = Mike Shepherd

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A significant proportion of the world's oil reserves are found in carbonate reservoirs. Many of these are located in the Middle East, Libya, Russia, Kazakhstan, and North America. Some very large oil fields have carbonate reservoirs, including the largest conventional oil field in the world, the Ghawar field of Saudi Arabia.

A significant proportion of the world's oil reserves are found in carbonate reservoirs. Many of these are located in the Middle East, Libya, Russia, Kazakhstan, and North America. Some very large oil fields have carbonate reservoirs, including the largest conventional oil field in the world, the Ghawar field of Saudi Arabia.

The reason for the very large size of some carbonate reservoirs is not surprising when one considers the sheer scale of even modern-day carbonate settings. The shallow submerged platform area of the Bahamas extends more than 400 km (248 mi) north–south and covers an area of about 125,000 km2 (48,263 mi2). The size of individual sediment bodies on the Bahama Banks can be impressive too ([[:File:M91FG196.JPG|Figure 1]]). The Joulters Cay ooid shoal is a single carbonate sand body with a mobile border 25 km (15 mi) long and between 0.5 and 2 km (0.3 and 1.2 mi) wide.<ref>Major, R. P., D. G. Bebout, and P. M. Harris, 1996, Facies heterogeneity in a modern ooid sand shoal—An analog for hydrocarbon reservoirs: Bureau of Economic Geology, Geological Circular 96-1, University of Texas at Austin, 30 p.</ref>

The reason for the very large size of some carbonate reservoirs is not surprising when one considers the sheer scale of even modern-day carbonate settings. The shallow submerged platform area of the Bahamas extends more than 400 km (248 mi) north–south and covers an area of about 125,000 km² (48,263 mi²). The size of individual sediment bodies on the Bahama Banks can be impressive too ([[:File:M91FG196.JPG|Figure 1]]). The Joulters Cay ooid shoal is a single carbonate sand body with a mobile border 25 km (15 mi) long and between 0.5 and 2 km (0.3 and 1.2 mi) wide.<ref>Major, R. P., D. G. Bebout, and P. M. Harris, 1996, Facies heterogeneity in a modern ooid sand shoal—An analog for hydrocarbon reservoirs: Bureau of Economic Geology, Geological Circular 96-1, University of Texas at Austin, 30 p.</ref>

[[File:M91FG196.JPG|thumb|300px|{{figure number|1}}Ooid shoal, Bahamas; the bottom edge of the photograph represents a 4.5-km (2.7 mi)-wide transect. The lower inset is an illustration of a cliff exposure of laterally accreting (shingled) oolites from the Lower Cretaceous of Northern Mexico (from Osleger).<ref name=Osleger>Osleger, D. A., R. Barnaby, and C. Kerans, 2004, [http://archives.datapages.com/data/specpubs/memoir80/CHAPTER5/CHAPTER5.HTM A laterally accreting grainstone margin from the Albian of northern Mexico: Outcrop model for Cretaceous carbonate reservoirs], in G. M. Grammer, P. M. Harris, and G. P. Eberli, eds., Integration of outcrop and modern analogs in reservoir modeling: [http://store.aapg.org/detail.aspx?id=658 AAPG Memoir 80], p. 93–107.</ref>]]

[[File:M91FG196.JPG|thumb|300px|{{figure number|1}}Ooid shoal, Bahamas; the bottom edge of the photograph represents a 4.5-km (2.7 mi)-wide transect. The lower inset is an illustration of a cliff exposure of laterally accreting (shingled) oolites from the Lower Cretaceous of Northern Mexico (from Osleger).<ref name=Osleger>Osleger, D. A., R. Barnaby, and C. Kerans, 2004, [http://archives.datapages.com/data/specpubs/memoir80/CHAPTER5/CHAPTER5.HTM A laterally accreting grainstone margin from the Albian of northern Mexico: Outcrop model for Cretaceous carbonate reservoirs], in G. M. Grammer, P. M. Harris, and G. P. Eberli, eds., Integration of outcrop and modern analogs in reservoir modeling: [http://store.aapg.org/detail.aspx?id=658 AAPG Memoir 80], p. 93–107.</ref>]]

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Pore sizes in carbonates vary from micron scale to cave systems. Carbonates with vuggy porosity can store significant volumes of oil, yet sometimes the vugs are largely unconnected, yielding low flow rates. Tiny pores on a micron scale can form a high component of the porosity. The porosity may look impressive on logs, yet much of this may be microporosity and unproduceable.<ref>Pittman, E. D., 1971, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0055/0010/1850/1873.htm Microporosity in carbonate rocks]: AAPG Bulletin, v. 55, no. 10, p. 1873–1878.</ref><ref>Cantrell, D. L., and R. M. Hagerty, 1999, Microporosity in Arab Formation carbonates, Saudi Arabia: GeoArabia, v. 4, no. 2, p. 129–154.</ref> The petrophysical analysis of carbonate reservoirs is difficult and prone to greater uncertainty than with sandstone reservoirs. The uncertainty in the determination of water saturation, effective porosity, net pay, and permeability will impact the estimation of in-place volumes and reserves. Carbonates have a tendency to oil-wet characteristics or show mixed wettability. Typical behavior in oil-wet systems includes early water breakthrough and high water production rates (see Chapter 4, this publication). Carbonates can have thick transition zones in reservoirs with low matrix permeability.<ref>Masalmeh, S. K., I. Abu Shiekah, and X. D. Jing, 2005, Improved characterization and modeling of capillary transition zones in carbonate reservoirs: Presented at the International Petroleum Technology Conference, Society of Petroleum Engineers, November 21–23, Doha, Qatar, SPE Paper 10238, 16 p.</ref> Residual oil saturations can also be high.<ref>Holtz, M., S. C. Ruppel, and C. R. Hocott, 1992, Integrated geologic and engineering determination of oil-reserve growth potential in carbonate reservoirs: Journal of Petroleum Technology, v. 44, no. 11, SPE Paper 22900, p. 1250–1257.</ref> <ref>Kamath, J., R. F. Meyer, and F. M. Nakagawa, 2001, Understanding waterflood residual oil saturation of four carbonate rock types: Presented at the 2001 Society of Petroleum Engineers Annual Technical Conference and Exhibition, September 30–October 3, 2001, New Orleans, Louisiana, SPE Paper 71505, 10 p.</ref>

Pore sizes in carbonates vary from micron scale to cave systems. Carbonates with vuggy porosity can store significant volumes of oil, yet sometimes the vugs are largely unconnected, yielding low flow rates. Tiny pores on a micron scale can form a high component of the porosity. The porosity may look impressive on logs, yet much of this may be microporosity and unproduceable.<ref>Pittman, E. D., 1971, [http://archives.datapages.com/data/bulletns/1971-73/data/pg/0055/0010/1850/1873.htm Microporosity in carbonate rocks]: AAPG Bulletin, v. 55, no. 10, p. 1873–1878.</ref><ref>Cantrell, D. L., and R. M. Hagerty, 1999, Microporosity in Arab Formation carbonates, Saudi Arabia: GeoArabia, v. 4, no. 2, p. 129–154.</ref> The petrophysical analysis of carbonate reservoirs is difficult and prone to greater uncertainty than with sandstone reservoirs. The uncertainty in the determination of water saturation, effective porosity, net pay, and permeability will impact the estimation of in-place volumes and reserves. Carbonates have a tendency to oil-wet characteristics or show mixed wettability. Typical behavior in oil-wet systems includes early water breakthrough and high water production rates. Carbonates can have thick transition zones in reservoirs with low matrix permeability.<ref>Masalmeh, S. K., I. Abu Shiekah, and X. D. Jing, 2005, Improved characterization and modeling of capillary transition zones in carbonate reservoirs: Presented at the International Petroleum Technology Conference, Society of Petroleum Engineers, November 21–23, Doha, Qatar, SPE Paper 10238, 16 p.</ref> Residual oil saturations can also be high.<ref>Holtz, M., S. C. Ruppel, and C. R. Hocott, 1992, Integrated geologic and engineering determination of oil-reserve growth potential in carbonate reservoirs: Journal of Petroleum Technology, v. 44, no. 11, SPE Paper 22900, p. 1250–1257.</ref> <ref>Kamath, J., R. F. Meyer, and F. M. Nakagawa, 2001, Understanding waterflood residual oil saturation of four carbonate rock types: Presented at the 2001 Society of Petroleum Engineers Annual Technical Conference and Exhibition, September 30–October 3, 2001, New Orleans, Louisiana, SPE Paper 71505, 10 p.</ref>

Carbonates are typically brittle rocks and are commonly fractured. The fractures can be a major component of the field performance, enhancing effective permeability and creating connectivity within otherwise heterogeneous reservoirs. Fractures will influence sweep patterns and will cause considerable variability in well-flow rates. Thief zones in fractures and high-permeability intervals can cause early water breakthrough.

Carbonates are typically brittle rocks and are commonly fractured. The fractures can be a major component of the field performance, enhancing effective permeability and creating connectivity within otherwise heterogeneous reservoirs. Fractures will influence sweep patterns and will cause considerable variability in well-flow rates. Thief zones in fractures and high-permeability intervals can cause early water breakthrough.

Carbonate sediments tend to show a ribbon-like geometry and are less commonly developed as widespread sheets. Examples of both geometries are shown by two of the major carbonate reservoir intervals in the Middle East.<ref>Ehrenberg, S. N., P. H. Nadeau, and A. A. M. Aqrawi, 2007, [http://archives.datapages.com/data/bulletns/2007/03mar/BLTN06054/BLTN06054.HTM A comparison of Khuff and Arab reservoir potential throughout the Middle East]: AAPG Bulletin, v. 91, no. 3, p. 275–286</ref> Sediments of the Permian–Triassic Khuff Formation were deposited on a very low relief shelf, sheltered from the open ocean by a barrier reef. These show a layer-cake geometry consisting of interbedded mudstones and fine-grained grainstones.<ref>Alsharhan, A. S., 2006, Sedimentological character and hydrocarbon parameters of the middle Permian to Early Triassic Khuff Formation, United Arab Emirates: GeoArabia, v. 11, p. 121–158.</ref> By contrast, sedimentation in the Jurassic Arab Formation occurred on a shelf differentiated into shallow shoals and intrashelf basins. These exhibit a progradational geometry.<ref>Meyer, F. O., and R. C. Price, 1992, A new Arab-D depositional model, Ghawar field, Saudi Arabia: Presented at the Society of Petroleum Engineers 8th Middle East Oil Show, SPE Paper 25576, 10 p.</ref>

Carbonate sediments tend to show a ribbon-like geometry and are less commonly developed as widespread sheets. Examples of both geometries are shown by two of the major carbonate reservoir intervals in the Middle East.<ref>Ehrenberg, S. N., P. H. Nadeau, and A. A. M. Aqrawi, 2007, [http://archives.datapages.com/data/bulletns/2007/03mar/BLTN06054/BLTN06054.HTM A comparison of Khuff and Arab reservoir potential throughout the Middle East]: AAPG Bulletin, v. 91, no. 3, p. 275–286</ref> Sediments of the Permian–Triassic Khuff Formation were deposited on a very low relief shelf, sheltered from the open ocean by a barrier reef. These show a layer-cake geometry consisting of interbedded mudstones and fine-grained grainstones.<ref>Alsharhan, A. S., 2006, Sedimentological character and hydrocarbon parameters of the middle Permian to Early Triassic Khuff Formation, United Arab Emirates: GeoArabia, v. 11, p. 121–158.</ref> By contrast, sedimentation in the Jurassic Arab Formation occurred on a shelf differentiated into shallow shoals and intrashelf basins. These exhibit a progradational geometry.<ref>Meyer, F. O., and R. C. Price, 1992, A new Arab-D depositional model, Ghawar field, Saudi Arabia: Presented at the Society of Petroleum Engineers 8th Middle East Oil Show, SPE Paper 25576, 10 p.</ref>

Carbonate sediments with ribbon geometries show a complex lateral facies progression in map view. A tendency for lateral accretion in successive cycles creates a subtle shingled geometry, which can make accurate correlation difficult (see Chapter 10, this publication, and [[:File:M91FG67.JPG|Figure 2]]). For example, laterally accreting grainstones show a shingled geometry on a kilometer scale in Albian carbonates in northern Mexico ([[:File:M91FG196.JPG|Figure 1]]).<ref name=Osleger /> It can be a mistake to fit a layer-cake geometry to these systems because this results in reservoir models where lateral connectivity is predicted to be more extensive than is the case.<ref>Tinker, S. W., 1996, [http://archives.datapages.com/data/bulletns/1994-96/data/pg/0080/0004/0450/0460.htm Building the 3-D jigsaw puzzle, applications of sequence stratigraphy to 3-D reservoir characterization, Permian Basin]: AAPG Bulletin, v. 80, no. 4, p. 460–484.</ref> Facies belts may be difficult to define as lithofacies variation in carbonates is frequently transitional rather than sharp.

Carbonate sediments with ribbon geometries show a complex lateral facies progression in map view. A tendency for lateral accretion in successive cycles creates a subtle shingled geometry, which can make accurate correlation difficult ([[:File:M91FG67.JPG|Figure 2]]). For example, laterally accreting grainstones show a shingled geometry on a kilometer scale in Albian carbonates in northern Mexico ([[:File:M91FG196.JPG|Figure 1]]).<ref name=Osleger /> It can be a mistake to fit a layer-cake geometry to these systems because this results in reservoir models where lateral connectivity is predicted to be more extensive than is the case.<ref>Tinker, S. W., 1996, [http://archives.datapages.com/data/bulletns/1994-96/data/pg/0080/0004/0450/0460.htm Building the 3-D jigsaw puzzle, applications of sequence stratigraphy to 3-D reservoir characterization, Permian Basin]: AAPG Bulletin, v. 80, no. 4, p. 460–484.</ref> Facies belts may be difficult to define as lithofacies variation in carbonates is frequently transitional rather than sharp.

Carbonate sedimentation is very rapid and the build-up of carbonate sediment can exceed sea-level rise in a short period of time. For example, Neumann and Land<ref>Neumann, A. C., and L. S. Land, 1975, Lime mud deposition and calcareous algae in the Bight of Abaco, Bahamas: A budget: Journal of Sedimentary Petrology, v. 45, no. 4, p. 763–786.</ref> estimated that the carbonate sediment accumulation rate in the Bight of Abaco in the Bahamas is 120 mm (5 in.) per thousand years. This is about three times the estimated subsidence rate of 38 mm (1.4 in.) per thousand years. The phrase carbonate factory is commonly used to describe the manner in which large volumes of sediment are produced on tropical shelfs.

Carbonate sedimentation is very rapid and the build-up of carbonate sediment can exceed sea-level rise in a short period of time. For example, Neumann and Land<ref>Neumann, A. C., and L. S. Land, 1975, Lime mud deposition and calcareous algae in the Bight of Abaco, Bahamas: A budget: Journal of Sedimentary Petrology, v. 45, no. 4, p. 763–786.</ref> estimated that the carbonate sediment accumulation rate in the Bight of Abaco in the Bahamas is 120 mm (5 in.) per thousand years. This is about three times the estimated subsidence rate of 38 mm (1.4 in.) per thousand years. The phrase carbonate factory is commonly used to describe the manner in which large volumes of sediment are produced on tropical shelfs.

==Subtidal and intertidal complexes==

==Subtidal and intertidal complexes==

[[File:M91FG199.JPG|thumb|300px|{{figure number|5}}The upper photograph shows a Carbonate tidal flat on Andros Island, Bahamas. The tidal channel is about 150 m (492 ft) wide at the bottom of the photograph. The lower diagram shows three tidal flat reservoir cycles in the Permian San Andres dolomite of the northern Delaware basin in New Mexico and Texas (after Shinn).<ref name=Shinn> Shinn, E. A., 1983, [http://archives.datapages.com/data/specpubs/carbona3/data/a043/a043/0001/0150/0171.htm Tidal flat environment], in P. A. Scholle, D. G. Bebout, and C. H. Moore, eds., Carbonate depositional environments: [http://store.aapg.org/detail.aspx?id=656 AAPG Memoir 33], p. 171–210.</ref> Repeated transgression and regression create cycles of tidal flat reservoirs, each sealed by impermeable anhydritic supratidal facies toward the north. Reprinted with permission from the AAPG.]]

[[File:M91FG199.JPG|thumb|300px|{{figure number|5}}The upper photograph shows a Carbonate tidal flat on Andros Island, Bahamas. The tidal channel is about 150 m (492 ft) wide at the bottom of the photograph. The lower diagram shows three tidal flat reservoir cycles in the Permian San Andres dolomite of the northern Delaware basin in New Mexico and Texas (after Shinn).<ref name=Shinn> Shinn, E. A., 1983, [http://archives.datapages.com/data/specpubs/carbona3/data/a043/a043/0001/0150/0171.htm Tidal flat environment], in P. A. Scholle, D. G. Bebout, and C. H. Moore, eds., Carbonate depositional environments: [http://store.aapg.org/detail.aspx?id=656 AAPG Memoir 33], p. 171–210.</ref> Repeated transgression and regression create cycles of tidal flat reservoirs, each sealed by impermeable anhydritic supratidal facies toward the north.]]

The shelf interior in carbonate systems commonly shoals to a tidal flat environment that may be extensive in area ([[:File:M91FG199.JPG|Figure 5]]). The highest porosities and permeabilities are found in the subtidal to intertidal facies with the best reservoir quality in tidal channel sediments. Supratidal sediments show the poorest reservoir quality and are typically barriers to vertical flow.<ref name=Shinn /> In arid environments, supratidal sabkha may be found. The evaporites can act as internal seals.<ref>Wilson, J. L., 1980, A review of carbonate reservoirs, in A. D. Miall, ed., Facts and principles of world petroleum occurrence: Canadian Society of Petroleum Geologists Memoir 6, p. 95–115.</ref>

The shelf interior in carbonate systems commonly shoals to a tidal flat environment that may be extensive in area ([[:File:M91FG199.JPG|Figure 5]]). The highest porosities and permeabilities are found in the subtidal to intertidal facies with the best reservoir quality in tidal channel sediments. Supratidal sediments show the poorest reservoir quality and are typically barriers to vertical flow.<ref name=Shinn /> In arid environments, supratidal sabkha may be found. The evaporites can act as internal seals.<ref>Wilson, J. L., 1980, A review of carbonate reservoirs, in A. D. Miall, ed., Facts and principles of world petroleum occurrence: Canadian Society of Petroleum Geologists Memoir 6, p. 95–115.</ref>

==Chalk==

==Chalk==

[[File:M91FG200.JPG|thumb|300px|{{figure number|6}}Redeposited chalk provides the main reservoir intervals in chalk fields. Resedimentation processes include sliding, slumping, debris flows, turbidity currents, and creep (from Surlyk et al).<ref name=Surlyk>Surlyk, F., T. Dons, C. K. Clausen, and J. Higham, 2003, Upper Cretaceous, in D. Evans, C. Graham, A. Armour, and P. Bathurst, eds., Millennium atlas: Petroleum geology of the central and northern North Sea: Geological Society (London), p. 213–233.</ref> Reprinted with permission from the Geological Society.]]

[[File:M91FG200.JPG|thumb|300px|{{figure number|6}}Redeposited chalk provides the main reservoir intervals in chalk fields. Resedimentation processes include sliding, slumping, debris flows, turbidity currents, and creep (from Surlyk et al).<ref name=Surlyk>Surlyk, F., T. Dons, C. K. Clausen, and J. Higham, 2003, Upper Cretaceous, in D. Evans, C. Graham, A. Armour, and P. Bathurst, eds., Millennium atlas: Petroleum geology of the central and northern North Sea: Geological Society (London), p. 213–233.</ref> Reprinted with permission from, and &copy; by, the Geological Society.]]

Chalk is very fine-grained carbonate sediment, comprising skeletal calcitic debris of algae platelets. Porosity in chalk can be high, sometimes as high as 40–50%. Nevertheless, given the very fine-grained nature of the rock, permeabilities are low; 1–7 md is typical of the productive intervals. Factors influencing porosity preservation in chalk are overpressure, early oil migration, burial depth, chalk lithofacies, mud content, and grain size.<ref>Scholle, P. A., 1977, [http://archives.datapages.com/data/bulletns/1977-79/data/pg/0061/0007/0950/0982.htm Chalk diagenesis and its relation to petroleum exploration: Oil from chalks, a modern miracle?]: AAPG Bulletin, v. 61, no. 7, p. 982–1009.</ref><ref>Nygaard, E., K. Lieberkind, and P. Frykman, 1983, Sedimentology and reservoir parameters of the Chalk Group in the Danish central graben: Geologie en Mijnbouw, v. 62, no. 1, p. 177–190.</ref><ref name=DHeur>D'Heur, M., 1986, The Norwegian chalk fields, in A. M. Spencer, ed., Habitat of hydrocarbons on the Norwegian Continental Shelf: London, Graham amp Trotman, p. 77–89.</ref><ref>Brasher, J. E. and K. R. Vagle, 1996, [http://archives.datapages.com/data/bulletns/1994-96/data/pg/0080/0005/0700/0746.htm Influence of lithofacies and diagenesis on Norwegian North Sea chalk reservoirs]: AAPG Bulletin, v. 80, no. 5, p. 746–768.</ref> A correlation is found between the clay content of the chalk and the degradation of reservoir quality; clay hinders early lithification. As a result, clay-rich chalks are less rigid and will tend to undergo more compaction.<ref name=Kennedy>Kennedy, W. J., 1987, Sedimentology of Late Cretaceous–Paleocene Chalk reservoirs, North Sea central graben, in J. Brooks and K. Glennie, eds., Petroleum geology of northwest Europe 1987: London, Graham amp Trotman, p. 469–481.</ref> It is a common pattern in chalk oil fields to find the highest porosity in the crest of the field, decreasing incrementally toward the oil-water contact.<ref name=DHeur /> This character may result from the race for space between oil migration and cementing fluids (see Chapter 12, this publication). The permeability in the water leg can be so poor that chalk fields are unlikely to have significant aquifers.

Chalk is very fine-grained carbonate sediment, comprising skeletal calcitic debris of algae platelets. Porosity in chalk can be high, sometimes as high as 40–50%. Nevertheless, given the very fine-grained nature of the rock, permeabilities are low; 1–7 md is typical of the productive intervals. Factors influencing porosity preservation in chalk are overpressure, early oil migration, burial depth, chalk lithofacies, mud content, and grain size.<ref>Scholle, P. A., 1977, [http://archives.datapages.com/data/bulletns/1977-79/data/pg/0061/0007/0950/0982.htm Chalk diagenesis and its relation to petroleum exploration: Oil from chalks, a modern miracle?]: AAPG Bulletin, v. 61, no. 7, p. 982–1009.</ref><ref>Nygaard, E., K. Lieberkind, and P. Frykman, 1983, Sedimentology and reservoir parameters of the Chalk Group in the Danish central graben: Geologie en Mijnbouw, v. 62, no. 1, p. 177–190.</ref><ref name=DHeur>D'Heur, M., 1986, The Norwegian chalk fields, in A. M. Spencer, ed., Habitat of hydrocarbons on the Norwegian Continental Shelf: London, Graham amp Trotman, p. 77–89.</ref><ref>Brasher, J. E. and K. R. Vagle, 1996, [http://archives.datapages.com/data/bulletns/1994-96/data/pg/0080/0005/0700/0746.htm Influence of lithofacies and diagenesis on Norwegian North Sea chalk reservoirs]: AAPG Bulletin, v. 80, no. 5, p. 746–768.</ref> A correlation is found between the clay content of the chalk and the degradation of reservoir quality; clay hinders early lithification. As a result, clay-rich chalks are less rigid and will tend to undergo more compaction.<ref name=Kennedy>Kennedy, W. J., 1987, Sedimentology of Late Cretaceous–Paleocene Chalk reservoirs, North Sea central graben, in J. Brooks and K. Glennie, eds., Petroleum geology of northwest Europe 1987: London, Graham amp Trotman, p. 469–481.</ref> It is a common pattern in chalk oil fields to find the highest porosity in the crest of the field, decreasing incrementally toward the oil-water contact.<ref name=DHeur /> This character may result from the race for space between oil migration and cementing fluids. The permeability in the water leg can be so poor that chalk fields are unlikely to have significant aquifers.

Chalk reservoirs can show strong permeability layering. Pelagic chalk is usually non-net reservoir although under favorable circumstances it can be productive.<ref>Megson, J., and T. Tygesen, 2005, The North Sea Chalk: An underexplored and underdeveloped play, in A. G. Dore and B. A. Vining, eds., Petroleum geology: Northwest Europe and global perspectives: Proceedings of the 6th Petroleum Geology Conference, Geological Society (London), v. 1, p. 159–168.</ref> Pelagic or autochthonous chalk results from the slow settling of sediment on the sea floor. Pervasive early cementation and extensive bioturbation significantly reduce the porosity and permeability from an early stage.

Chalk reservoirs can show strong permeability layering. Pelagic chalk is usually non-net reservoir although under favorable circumstances it can be productive.<ref>Megson, J., and T. Tygesen, 2005, The North Sea Chalk: An underexplored and underdeveloped play, in A. G. Dore and B. A. Vining, eds., Petroleum geology: Northwest Europe and global perspectives: Proceedings of the 6th Petroleum Geology Conference, Geological Society (London), v. 1, p. 159–168.</ref> Pelagic or autochthonous chalk results from the slow settling of sediment on the sea floor. Pervasive early cementation and extensive bioturbation significantly reduce the porosity and permeability from an early stage.

Pelagic chalk on the seabed is easily disturbed and remobilized. Clean chalk lacks any significant sediment cohesion as it has no unbalanced interparticle electric charges or platy interlocking grains to hold it together.<ref>Bramwell, N. P., G. Caillet, L. Meciani, N. Judge, M. Green, and P. Adam, 1999, Chalk exploration, the search for a subtle trap, in A. J. Fleet and S. A. R. Boldy, eds., Petroleum geology of northwest Europe: Proceedings of the 5th Conference, Geological Society (London), p. 911–937.</ref> Processes tending to redeposit chalk include debris flows, turbidity currents, slumps, and slides ([[:File:M91FG200.JPG|Figure 6]])].<ref name=Kennedy />

Pelagic chalk on the seabed is easily disturbed and remobilized. Clean chalk lacks any significant sediment cohesion as it has no unbalanced interparticle electric charges or platy interlocking grains to hold it together.<ref>Bramwell, N. P., G. Caillet, L. Meciani, N. Judge, M. Green, and P. Adam, 1999, Chalk exploration, the search for a subtle trap, in A. J. Fleet and S. A. R. Boldy, eds., Petroleum geology of northwest Europe: Proceedings of the 5th Conference, Geological Society (London), p. 911–937.</ref> Processes tending to redeposit chalk include debris flows, turbidity currents, slumps, and slides ([[:File:M91FG200.JPG|Figure 6]]).<ref name=Kennedy />

Redeposited, allochthonous chalk typically shows much better porosities and permeabilities compared to autochthonous chalk in the same interval. The rock properties are thought to have been enhanced by several processes:<ref name=Kennedy /><ref>Taylor, S. R., and J. F. Lapre, 1987, North Sea chalk diagenesis: Its effect on reservoir location and properties, in J. Brooks And K. Glennie, eds., Petroleum geology of northwest Europe: London, Graham amp Trotman, p. 483–495.</ref>

Redeposited, allochthonous chalk typically shows much better porosities and permeabilities compared to autochthonous chalk in the same interval. The rock properties are thought to have been enhanced by several processes:<ref name=Kennedy /><ref>Taylor, S. R., and J. F. Lapre, 1987, North Sea chalk diagenesis: Its effect on reservoir location and properties, in J. Brooks And K. Glennie, eds., Petroleum geology of northwest Europe: London, Graham amp Trotman, p. 483–495.</ref>

# The redeposited chalk tends to form as thicker masses and this results in the bulk of the sediment escaping bioturbation and early cementation at the sediment-sea water interface.

# The redeposited chalk tends to form as thicker masses and this results in the bulk of the sediment escaping bioturbation and early cementation at the sediment-sea water interface.

Given the low permeability of chalks, the presence of fractures can significantly enhance the productivity of chalk fields (see Chapter 14, this publication). Sorenson et al.<ref> Sorensen, S., M. Jones, R. F. P. Hradman, W. K. Leutz, and P. H. Schwarz, 1986, Reservoir characteristics of high and low-productivity chalks from the central North Sea, in A. M. Spencer, ed., Habitat of hydrocarbons on the Norwegian Continental Shelf: London, Graham amp Trotman, p. 91–110.</ref> differentiated between two classes of producing chalk fields in the North Sea: low-porosity chalk (15–30%) and permeabilities in the range of 0.2–1 md, which need an extensive natural fracture system to be productive, and high porosity chalk with 30–50% porosity and permeabilities between 1–10 md.

Given the low permeability of chalks, the presence of fractures can significantly enhance the productivity of chalk fields. Sorenson et al.<ref> Sorensen, S., M. Jones, R. F. P. Hradman, W. K. Leutz, and P. H. Schwarz, 1986, Reservoir characteristics of high and low-productivity chalks from the central North Sea, in A. M. Spencer, ed., Habitat of hydrocarbons on the Norwegian Continental Shelf: London, Graham amp Trotman, p. 91–110.</ref> differentiated between two classes of producing chalk fields in the North Sea: low-porosity chalk (15–30%) and permeabilities in the range of 0.2–1 md, which need an extensive natural fracture system to be productive, and high porosity chalk with 30–50% porosity and permeabilities between 1–10 md.

Horizontal wells are used to develop chalk fields.<ref>Megson, J., and R. Hardman, 2001, Exploration for and development of hydrocarbons in the Chalk of the North Sea: A low permeability system: Petroleum Geoscience, v. 7, no. 1, p. 3–12.</ref> Permeabilities are too low for conventional wells to be effective. Long horizontal wells, commonly 2 km or more in length, maximize the permeability-thickness and productivity of chalk fields. Fracture stimulation is used to enhance productivity (e.g., Cook and Brekke).<ref>Cook, C. C., and K. Brekke, 2004, Productivity preservation through hydraulic propped fractures in the Eldfisk North Sea Chalk field: SPE Reservoir Evaluation and Engineering, v. 7, no. 2, SPE Paper 88031-PA, p. 105–114.</ref> Waterfloods can be highly effective in chalk because the fine capillary structure will draw in water very efficiently, displacing much of the oil.<ref name=Surlyk /> The injection wells should be drilled to avoid any open fractures that are likely to connect up with production wells, as rapid water breakthrough will ensue.

Horizontal wells are used to develop chalk fields.<ref>Megson, J., and R. Hardman, 2001, Exploration for and development of hydrocarbons in the Chalk of the North Sea: A low permeability system: Petroleum Geoscience, v. 7, no. 1, p. 3–12.</ref> Permeabilities are too low for conventional wells to be effective. Long horizontal wells, commonly 2 km or more in length, maximize the permeability-thickness and productivity of chalk fields. Fracture stimulation is used to enhance productivity (e.g., Cook and Brekke).<ref>Cook, C. C., and K. Brekke, 2004, Productivity preservation through hydraulic propped fractures in the Eldfisk North Sea Chalk field: SPE Reservoir Evaluation and Engineering, v. 7, no. 2, SPE Paper 88031-PA, p. 105–114.</ref> Waterfloods can be highly effective in chalk because the fine capillary structure will draw in water very efficiently, displacing much of the oil.<ref name=Surlyk /> The injection wells should be drilled to avoid any open fractures that are likely to connect up with production wells, as rapid water breakthrough will ensue.