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This article describes the physics of how oil, gas, and water interact with each other and the rock. The basic concepts of wettability, capillary pressure, and relative permeability are important. This is knowledge required to understand how reservoirs behave. Physical processes also control the distribution of oil and water in a reservoir, and an understanding of these will help the production geologist to estimate the in-place hydrocarbon volumes.

This article describes the physics of how oil, gas, and water interact with each other and the rock. The basic concepts of wettability, [[capillary pressure]], and relative permeability are important. This is knowledge required to understand how reservoirs behave. Physical processes also control the distribution of oil and water in a reservoir, and an understanding of these will help the production geologist to estimate the in-place hydrocarbon volumes.

==Wettability==

==Wettability==

Where a reservoir rock is water wet, the water forms a thin film over most of the grain surfaces and will also fill the smaller pores. The oil or gas will occupy the remaining, more central volume of the pore system. Conversely, in a reservoir that is oil wet, it is the oil that covers the grain surface and occupies the smaller pores; the water is located centrally within the pore structure.<ref name=Anderson86>Anderson, W. G., 1986, Wettability literature survey: 1. Rock/oil/brine interactions and the effects of core handling on wettability: Journal of Petroleum Technology, SPE 13932, v. 38, no. 10, p. 1125–1144.</ref>

Where a reservoir rock is water wet, the water forms a thin film over most of the grain surfaces and will also fill the smaller pores. The oil or gas will occupy the remaining, more central volume of the pore system. Conversely, in a reservoir that is oil wet, it is the oil that covers the grain surface and occupies the smaller pores; the water is located centrally within the pore structure.<ref name=Anderson86>Anderson, W. G., 1986, Wettability literature survey: 1. Rock/oil/brine interactions and the effects of core handling on wettability: Journal of Petroleum Technology, SPE 13932, v. 38, no. 10, p. 1125–1144.</ref>

Most reservoirs were water wet before oil migration started; the major mineral phases in reservoirs such as quartz, carbonate and dolomite are all water wetting prior to coming in contact with oil.<ref>Abdallah, W., et al., 2007, Fundamentals of wettability: Oilfield Review, Summer 2007, v. 19, no. 2, p. 44–61.</ref> Following oil migration, sandstone reservoirs can end up as predominantly water wet, predominantly oil wet, or more frequently in a mixed-wettability state, that is, somewhere in between oil wet and water wet. Carbonate reservoirs are commonly described as showing mixed wettability tending to oil wet.<ref>Treiber, L. E., D. L. Archer, and W. W. Owens, 1972, A laboratory evaluation of the wettability of fifty oil-producing reservoirs: Presented at the Society of Petroleum Engineers 46th Annual Fall Meeting, October 3–6, New Orleans, SPE Journal, SPE Paper 3526, v. 12, no. 6, p. 531–540.</ref><ref>Chilingar, G. V., and T. F. Yen, 1983, Some notes on wettability and relative permeabilities of carbonate reservoir rocks: II: Energy Sources, v. 7(1), no. 7, p. 67–75.</ref> The degree of wettability can vary even within a single reservoir. The rocks in the reservoir will show a variety of mineral types, each mineral with its own wetting characteristics. Other variables affecting wettability include the wetting nature of the numerous compounds comprising crude oil and the degree to which polar compounds from the oil are absorbed onto the rock surface.<ref name=Anderson86 />

Most reservoirs were water wet before oil migration started; the major mineral phases in reservoirs such as quartz, carbonate and [[dolomite]] are all water wetting prior to coming in contact with oil.<ref>Abdallah, W., et al., 2007, Fundamentals of wettability: Oilfield Review, Summer 2007, v. 19, no. 2, p. 44–61.</ref> Following oil migration, sandstone reservoirs can end up as predominantly water wet, predominantly oil wet, or more frequently in a mixed-wettability state, that is, somewhere in between oil wet and water wet. Carbonate reservoirs are commonly described as showing mixed wettability tending to oil wet.<ref>Treiber, L. E., D. L. Archer, and W. W. Owens, 1972, A laboratory evaluation of the wettability of fifty oil-producing reservoirs: Presented at the Society of Petroleum Engineers 46th Annual Fall Meeting, October 3–6, New Orleans, SPE Journal, SPE Paper 3526, v. 12, no. 6, p. 531–540.</ref><ref>Chilingar, G. V., and T. F. Yen, 1983, Some notes on wettability and relative permeabilities of carbonate reservoir rocks: II: Energy Sources, v. 7(1), no. 7, p. 67–75.</ref> The degree of wettability can vary even within a single reservoir. The rocks in the reservoir will show a variety of mineral types, each mineral with its own wetting characteristics. Other variables affecting wettability include the wetting nature of the numerous compounds comprising [[crude oil]] and the degree to which polar compounds from the oil are absorbed onto the rock surface.<ref name=Anderson86 />

Waterfloods produce more efficient sweeps in water-wet reservoirs than in oil-wet systems. Water forced to move through a water-wet pore system will displace the oil from the center of the pores relatively efficiently ([[:File:M91FG25.JPG|Figure 2]]). Water will also be drawn into the smaller pores, displacing oil into the main flow pathways. In an oil-wet sandstone, the oil forms a film around the sand grains and water will move through the center of the pores, particularly the larger connected pores. The pathway for the water here is less tortuous than in water-wet sandstones, and the water will move through the rock more quickly, bypassing a large volume of oil. Rapid water breakthrough to the production wells typically occurs, and oil rates will drop significantly once this happens. Nevertheless, the film of oil around the grains can survive as a continuous path to a production well after water has broken through. Because of this, a continuous flow of oil can still be maintained in oil-wet reservoirs by injecting large volumes of water.<ref>Anderson, W. G., 1987, Wettability literature survey: 6. The effects of wettability on waterflooding: Journal of Petroleum Technology, SPE 16471, v. 39, no. 12, p. 1605–1622.</ref>

Waterfloods produce more efficient sweeps in water-wet reservoirs than in oil-wet systems. Water forced to move through a water-wet pore system will displace the oil from the center of the pores relatively efficiently ([[:File:M91FG25.JPG|Figure 2]]). Water will also be drawn into the smaller pores, displacing oil into the main flow pathways. In an oil-wet sandstone, the oil forms a film around the sand grains and water will move through the center of the pores, particularly the larger connected pores. The pathway for the water here is less tortuous than in water-wet sandstones, and the water will move through the rock more quickly, bypassing a large volume of oil. Rapid water breakthrough to the production wells typically occurs, and oil rates will drop significantly once this happens. Nevertheless, the film of oil around the grains can survive as a continuous path to a production well after water has broken through. Because of this, a continuous flow of oil can still be maintained in oil-wet reservoirs by injecting large volumes of water.<ref>Anderson, W. G., 1987, Wettability literature survey: 6. The effects of wettability on waterflooding: Journal of Petroleum Technology, SPE 16471, v. 39, no. 12, p. 1605–1622.</ref>

When hydrocarbons migrate into a trap, the buoyancy force exerted by the lighter oil (or gas) will push the water that was previously in the pore space sideways and downward. However, not all of the water is displaced; some of it will be held by capillary forces within the pores. Narrower capillaries, pores with smaller pore throats, hold onto water the strongest.

When hydrocarbons migrate into a trap, the buoyancy force exerted by the lighter oil (or gas) will push the water that was previously in the pore space sideways and downward. However, not all of the water is displaced; some of it will be held by capillary forces within the pores. Narrower capillaries, pores with smaller pore throats, hold onto water the strongest.

The two forces acting on the fluids in the pore space are controlled by physical laws. The equation for the buoyancy pressure is given by

The two forces acting on the fluids in the pore space are controlled by physical laws. The equation for the [[buoyancy pressure]] is given by

:<math>P_b = (\rho_w - \rho_{nw})gh</math><br>

:<math>P_b = (\rho_w - \rho_{nw})gh</math><br>

where P_b is the buoyancy pressure; ρ_w and ρ_nw are the specific gravities of the wetting and nonwetting phases respectively; g is the acceleration of gravity; and h is the height above the free-water level.

where P_b is the buoyancy pressure; ρ_w and ρ_nw are the specific gravities of the wetting and nonwetting phases respectively; g is the acceleration of [[gravity]]; and h is the height above the free-water level.

The equation for capillary forces is given by

The equation for capillary forces is given by

:<math>P_c = \frac{2 \sigma \cos \theta}{r}</math><br>

:<math>P_c = \frac{2 \sigma \cos \theta}{r}</math><br>

where Pc is the capillary pressure, sigma is the interfacial tension, thetas is the contact angle between the wetting fluid and the solid surface, and r is the capillary (pore throat) radius.<ref name=Vavra />

where Pc is the [[capillary pressure]], sigma is the interfacial tension, thetas is the contact angle between the wetting fluid and the solid surface, and r is the capillary (pore throat) radius.<ref name=Vavra />

The volume of water remaining at a given height in a reservoir is a function of the balance of capillary forces pulling the water up from the hydrocarbon-water interface and the force of gravity acting together with the density contrast between the reservoir fluids, acting to pull the water down.<ref>Arps, J. J., 1964, [http://archives.datapages.com/data/bulletns/1961-64/data/pg/0048/0002/0150/0157.htm Engineering concepts useful in oil finding]: AAPG Bulletin, v. 48, no. 2, p. 157–165.</ref> Thus, a given part of the pore space within the hydrocarbon leg can contain both hydrocarbons and water. The fraction (percentage) of water to total fluid volume is termed the water saturation.

The volume of water remaining at a given height in a reservoir is a function of the balance of capillary forces pulling the water up from the hydrocarbon-water interface and the force of gravity acting together with the density contrast between the reservoir fluids, acting to pull the water down.<ref>Arps, J. J., 1964, [http://archives.datapages.com/data/bulletns/1961-64/data/pg/0048/0002/0150/0157.htm Engineering concepts useful in oil finding]: AAPG Bulletin, v. 48, no. 2, p. 157–165.</ref> Thus, a given part of the pore space within the hydrocarbon leg can contain both hydrocarbons and water. The fraction (percentage) of water to total fluid volume is termed the water saturation.

As the buoyancy pressure increases with height above the free-water level, the oil phase will displace more water from increasingly smaller pore volumes. The effect of this is that hydrocarbon saturations increase with height above the hydrocarbon-water contact. The relationship between capillary and buoyancy forces thus controls the static distribution of fluids in oil and gas pools. Knowledge of these relationships is fundamental to the accurate calculation of hydrocarbon volumes within a reservoir.

As the buoyancy pressure increases with height above the free-water level, the oil phase will displace more water from increasingly smaller pore volumes. The effect of this is that hydrocarbon saturations increase with height above the hydrocarbon-water contact. The relationship between capillary and buoyancy forces thus controls the static distribution of fluids in oil and gas pools. Knowledge of these relationships is fundamental to the accurate calculation of hydrocarbon volumes within a reservoir.

Capillary pressure is typically measured in the laboratory by injecting mercury under pressure into a core plug. The mercury is a nonwetting phase, which replicates the behavior of hydrocarbons in reservoir rocks. The procedure simulates the entry of hydrocarbons into a water-wet rock and the way in which buoyancy pressure increases with height in the hydrocarbon column.

[[Capillary pressure]] is typically measured in the laboratory by injecting mercury under pressure into a core plug. The mercury is a nonwetting phase, which replicates the behavior of hydrocarbons in reservoir rocks. The procedure simulates the entry of hydrocarbons into a water-wet rock and the way in which buoyancy pressure increases with height in the [[hydrocarbon column]].

Mercury will not enter the rock immediately. The pressure required to do this will depend on the radius of the pore throats, the contact angle, and the mercury-air interfacial tension. The pressure at which the mercury effectively enters the pore network is termed the displacement or entry pressure.<ref name=Vavra /> Lower entry pressures are found in the better quality reservoir rocks, that is, those with larger pore throat diameters. A cap rock with tiny capillaries, shale for instance, has a very high displacement pressure. The displacement pressure for a cap rock can be so high that the tightly bound water in the pore space of the shale will prevent the oil from entering and the oil remains trapped in the underlying reservoir rock.<ref name=Schowalter1979 /><ref>Berg, R. R., 1975, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0059/0006/0900/0939.htm Capillary pressures in stratigraphic traps]: AAPG Bulletin, v. 59, no. 6, p. 939–956.</ref>

Mercury will not enter the rock immediately. The pressure required to do this will depend on the radius of the pore throats, the contact angle, and the mercury-air interfacial tension. The pressure at which the mercury effectively enters the pore network is termed the displacement or entry pressure.<ref name=Vavra /> Lower entry pressures are found in the better quality reservoir rocks, that is, those with larger pore throat diameters. A cap rock with tiny capillaries, shale for instance, has a very high [[displacement pressure]]. The displacement pressure for a cap rock can be so high that the tightly bound water in the pore space of the shale will prevent the oil from entering and the oil remains trapped in the underlying reservoir rock.<ref name=Schowalter1979 /><ref>Berg, R. R., 1975, [http://archives.datapages.com/data/bulletns/1974-76/data/pg/0059/0006/0900/0939.htm Capillary pressures in stratigraphic traps]: AAPG Bulletin, v. 59, no. 6, p. 939–956.</ref>

With increasing injection pressure, more and more mercury is forced into the rock. The shape of the curves on a capillary pressure plot reflects the grain sorting and the connection of pores and pore throats. The longer the plateau shown by the capillary curve, the better the reservoir quality. Poorly sorted, fine-grained sediment with narrow pore throats will retain water to higher pressures than coarser grained, better sorted sediments. A homogenous reservoir rock can be represented by a single capillary pressure curve. By contrast, a heterogenous reservoir will have a family of rock types, each with its own capillary pressure curve ([[:File:Mem91BuoyanceForcesFig27.jpg|Figure 4]]).

With increasing injection pressure, more and more mercury is forced into the rock. The shape of the curves on a capillary pressure plot reflects the grain sorting and the connection of pores and pore throats. The longer the plateau shown by the capillary curve, the better the reservoir quality. Poorly sorted, fine-grained sediment with narrow pore throats will retain water to higher pressures than coarser grained, better sorted sediments. A homogenous reservoir rock can be represented by a single capillary pressure curve. By contrast, a heterogenous reservoir will have a family of rock types, each with its own capillary pressure curve ([[:File:Mem91BuoyanceForcesFig27.jpg|Figure 4]]).

Sometimes a new well will find an oil-water contact significantly shallower than the common oil-water contact established in the wells drilled so far in the field, yet there is evidence for pressure communication between the new and old wells ([[:File:M91FG30.JPG|Figure 7]]). The shallower oil-water contact may be a perched oil-water contact. These are common features yet are hardly ever mentioned in the literature. Perched oil-water contacts result from the trapping of small to moderate volumes of water when the oil initially migrated into the reservoir. Normally, the water will be displaced down and sideways as the oil enters. However, if a barrier prevents the water from being moved out of the way, the water will remain where it is.

Sometimes a new well will find an oil-water contact significantly shallower than the common oil-water contact established in the wells drilled so far in the field, yet there is evidence for pressure communication between the new and old wells ([[:File:M91FG30.JPG|Figure 7]]). The shallower oil-water contact may be a perched oil-water contact. These are common features yet are hardly ever mentioned in the literature. Perched oil-water contacts result from the trapping of small to moderate volumes of water when the oil initially migrated into the reservoir. Normally, the water will be displaced down and sideways as the oil enters. However, if a barrier prevents the water from being moved out of the way, the water will remain where it is.

Sometimes a localized perched oil-water contact can be found more than 50 m (164 ft) higher than the established oil-water contact. For example, in the Fulmar field, UK North Sea, a perched oil-water contact in the north of the field was found at 3228 m (10,590 ft) true vertical depth subsea (TVDSS), 73 m (240 ft) higher than the main oil-water contact at 3301 m (10830 ft) TVDSS. Pressure and production data indicate communication within the oil column between the two areas (Stockbridge and Gray, 1991).

Sometimes a localized perched oil-water contact can be found more than 50 m (164 ft) higher than the established oil-water contact. For example, in the Fulmar field, UK North Sea, a perched oil-water contact in the north of the field was found at 3228 m (10,590 ft) true vertical depth subsea (TVDSS), 73 m (240 ft) higher than the main oil-water contact at 3301 m (10830 ft) TVDSS. Pressure and production data indicate communication within the oil column between the two areas.<ref>Stockbridge, C. P., and D. I. Gray, 1991, The Fulmar field, Blocks 30/16 and 30/11b, UK North Sea, in I. L. Abbots, ed., United Kingdom oil and gas fields, 25 years commemorative volume: Geological Society (London) Memoir 14, p. 309–316.</ref>

The most common type of perched oil-water contact is a downwarped thin reservoir with the downward flow of water blocked by a sand pinch-out or a sealing fault. Local synclinal areas flanked by sealing faults can also retain water (Weber, 1995).

The most common type of perched oil-water contact is a downwarped thin reservoir with the downward flow of water blocked by a sand pinch-out or a sealing fault. Local synclinal areas flanked by sealing faults can also retain water.<ref>Weber, K. J., 1995, Perched hydrocarbon-water contacts—A common but poorly understood phenomenon: Abstracts of the 57th EAGE Conference, Glasgow, F035.</ref>

==References==

==References==

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