irreducible water
TRANSCRIPT
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IRREDUCIBLE WATER
We have already seen how, on a molecular level, the interaction between clay and
water results in lower resistivity values. Now we will step back somewhat, and
readjust our sights for a microscopicexamination of the pores in a pay zone. At this
level, we will see that water, rather than clay, is a prime factor contributing to low
resistivity pays.
n this section, we will describe a number of inter!related factors, each of which are
intimately tied to the amount of non!producible bound!water that a reservoir can hold
"#igure $%Water at the intergranular scale&. 'hough not produced, this bound!water
is none!the!less detected and measured by resistivity tools, which do not distinguish
between freely produced water and immovable water.
Figure 1
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We will start with a brief review of the concepts of porosity and saturation, and will
take a closer look at permeability and capillarity as they relate to bound!water. We
will see that structural position also plays an important role, along with rock!fluid
interactions and fluid!fluid interactions, in determining whether a low!resistivity pay
zone will produce water or hydrocarbons.
Porosity
(orosity is the ratio of pore space in the rock to the bulk volume of the rock. t is
expressed as a fraction or as a percent of the bulk volume. n e)uation form,
where%
* = porosity in fraction
+p pore volume
+b bulk volume
+pand +bcan be expressed in any consistent units.
POROSITYCLASSIFICATION
n terms of production, three types of porosity are recognized%
Total porosityrefers to all pore space in a rock.
Effectiveporosityrefers only to that portion of the total porosity consisting of
interconnected pore spaces- more specifically, effective porosity is that portion
of the total porosity which will allow fluid flow under normal recovery processes
in the reservoir. ffective porosity is a dimensionless )uantity, defined as the
ratio of interconnected pore volume to the bulk volume.
Non-effective porosityis the remaining portion of total porosity which occurs
either as isolated pore spaces or as microporosity.
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'he difference between these porosities may be significant in highly vuggy or
fractured reservoirs, where some vugs or fractures may be isolated.
'he presence of clay also complicates the definition of rock porosity. Although the
layer of closely bound surface water on the clay particle can represent a verysignificant amount of porosity, it is not available as potential reservoir porosity for
hydrocarbons. 'hus, a shale or shaly formation may exhibit a high total porosity,
while actually having a low effective porosity as a potential hydrocarbon reservoir.
/ound water is held by non!effective porosity. When we calculate water saturation
for producibility estimations we are must be sure to use effective porosity.
MICROPOROSITY
Microporosityrefers to pore spaces which are so small in diameter "0 1 or less& that
they trap and hold water immobile through capillary action. 2icroporosity is
commonly associated with authigenic clay minerals whose open structure is able to
trap water. Another example is chalk, which commonly exhibits a large percentage of
microporosity, with very high total porosity but low matrix permeability.
2icroporosity is considered non-effectiveporosity as far as the production potential
of the reservoir is concerned. f it is not recognized as such, microporosity can lead
to optimistic predictions of potential reservoir porosity. 3n the other hand, bound
water associated with extensive microporosity can lower resistivity readings and lead
to pessimistic estimations of water saturation.
Saturatio
4aturation is a measure of the relative volume of each fluid in the pores. 'hus, oil
saturation is defined as the ratio of the volume of the oil in a porous rock to the pore
volume of the same rock. t is expressed in fraction or in percent, and ranges from 5
to nearly $556. Water is always present in all reservoirs, and its saturation is always
greater than zero. n contrast, the oil saturation is zero in gas reservoirs, and the gas
saturation is zero in oil reservoirs when the pressure is above the bubble!point. 3il
or gas saturation is calculated by subtracting the water saturation from unity "in two!
phase reservoirs&.
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IRREDUCIBLEWATERSATURATION
Irreducible water saturation "sometimes called critical water saturation& defines the
maximum water saturation that a formation with a given permeability and porosity
can retain without producing water. 'his water, although present, is held in place by
capillary forces and will not flow. 7ritical water saturations are usually determined
through special core analysis.
'he critical water value should be compared to the reservoir8s in!place water
saturation calculated from downhole electric logs. f the in!place water saturation
does not exceed the critical value, then the well will produce only hydrocarbons.
'hese saturation comparisons are particularly important in low permeability
reservoirs, where critical water saturation can exceed 956 while still producing only
hydrocarbons.
USIN!MA!NETICRESONANCETOOBTAINBOUNDWATERSATURATIONS
After describing total, effective, and non!effective porosity "above&, we can now
define the saturation of non!producible bound water in terms of effective and total
porosity through the following e)uation%
Where
4wbis bound water saturation
'is total porosity
is effective porosity
n essence, this bound water saturation e)uation divides non!effective porosity by
total porosity.
'otal and effective porosity measurements can be obtained through magnetic
resonance logging. #or more information on magnetic resonance logging "N2:& in
low resistivity pay zones, see the section of this module entitled Advances in
Logging.
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3stroff, 4horey, and ;eorgi "$
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'he wettability of a surface is determined by the interaction of interfacial energies
that act on the fluids and the surface. #or two immiscible co!existing fluids in a
porous media, the one with the lower interfacial tension is the wettingphase, while
the other is the non-wettingphase. nterfacial tension is a measure of the surface
energy per unit area of the interface between two immiscible fluids, such as water
and crude oil, or oil and gas. 'he lower the solid!fluid interfacial tension, the lower
the surface energy and the higher the tendency for the fluid to wet that surface.
Per'ea"i#ity
(ermeability is a measure of the ability of porous rock to transmit fluid.
PERMEABILITYCLASSIFICATION
(ermeability is further classified as either absolute or effective depending on
whether one or more fluids occupy the pore spaces of the rock !
Absolute permeability occurs when only one fluid is present in the rock. t is
independent of the fluid used in the measurement. 'his assumes that the fluid does
not interact with the rock.
Effectivepermeability is the measured permeability of a porous medium to one fluid,
when other fluids are present. ffective permeability depends on the relative
proportion of the fluids present "fluid saturation&.
7onsider the case of oil and water together in a pore system. Bnder a given
pressure gradient, the oil and water flow through a pore system together. /ased on
Carcy8s e)uation, we find that%
%or oi# (
%or )ater (
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where%
k permeability
) flow rate
fluid viscosity
p pressure differential
D length
A cross!sectional area
#urthermore, we find that the total flow rate ""t,& is expressed by the e)uation%
@t "@oE @w&,
@t is less than the flow rate that either phase would have if it were at $556
saturation. 'hus it appears as though the two phases interfere with each other8s
progress through the pore system. A useful way to )uantify this phenomenon is to
define the relative permeability, "#r&.
RELATI*EPERMEABILITY
Carcy8s definition of permeability was for a porous medium which was $556
saturated with the flowing phase "the phase was water&. =ydrocarbon reservoirs
normally have two and perhaps three phases present% both water and oil- or water
and gas- or water, oil, and gas sharing the pore space of the rock. We have seen
that having more than one phase present in the pores reduces the ability of the rock
to transmit any one of the fluid phases. #or this reason, we define the effective
permeability as the permeability to one phase when there is more than one phase
present in the pore space. ts value decreases as the phases8 saturation decreases.
'here is an effective permeability value for each phase present.
Bsually the effective permeability is expressed as a fraction of the absolute
permeability which is the permeability at $556 saturation of the flowing fluid. 'his
ratio of effective to absolute permeability is termed the relative permeability and can
be displayed as a set of curves as shown in #igure F, for an oil and water system.
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Figure +
'his graph shows that the relative permeability to oil decreases as the oil saturation
decreases and the water saturation increases above its irreducible "or connate&
value. 7onversely, the relative permeability to water increases, reaching a maximum
when the oil saturation is at its residual saturation. 'his same general principle
applies to any two!or three!phase system.
'he graph shows that relative permeability is also a function of fluid saturation.
When multiple, immiscible fluid phases flow in a rock, the sum of the effectivepermeabilities of the various fluids will commonly be significantly less than the
absolute permeability measured with only a single fluid in the rock. A different way of
stating this is that the sum of the relative permeabilities for all the fluids in the roc#
will commonly be less than one.
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:elative permeability is the ratio of the effective permeability of the rock to one
phase divided by the absolute permeability, and it is )uoted at some particular
saturation value%
kro kr k
krw kw k
Re#ati,e Per'ea"i#ity a$ Irre$u&i"#e Water Saturatio
Another important relative permeability concept is that of the irreducible or residual
saturation.
f two fluid phases,Aand $, are flowing in a rock, the relative permeability of fluid
phase A will decrease as the saturation of fluid A decreases. At some non!zero
saturation of fluidA"commonly G6 to 06&, fluidAwill cease to flow, and only fluid $
will continue to flow in the rock. 'he saturation at that point is termed the irreducible
or residual saturationof fluidAfor theA-$two phase flow system in this rock.
:elative permeability to oil at irreducible water saturationis $556 or $, and as water
saturation increases, #rodecreases until it effectively reaches zero at some high
water saturation corresponding to %or, the residual oil saturation.
:elative permeability to water, on the other hand, commences effectively at zerowhen the rock is at irreducible water saturation 4wi, and thereafter increases as %w
increases. t should also be noted that in an oil!wet system, #rois always less at a
given %wthan in a water!wet system. 7onversely, #rwis always greater in an oil!wet
system than in a water!wet one.
2any workers in this field have proposed generalized empirical e)uations to relate
#ro and #rw to %w, %wi, and %or 3f particular note are those cited in =onarpour,
>oederitz, and =arvey "$
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Structural Position
f a well is completed abovethe transition zone where the reservoir is at irreducible
water saturation "#rw 5&, then water will not be produced.
Ca-i##ary Pressure
n everyday experience, water levels in two or more connected containers have the
same level if exposed to the same atmospheric conditions. /ut when it comes to
spaces of capillary size "like those we encounter in porous media&, we cannot take
this rule so literally. 'o illustrate, consider what happens when a tube of capillary size
is dipped in a larger container filled with water "#igure I& 'he water in the capillary
tube rises above the water level in the container to a height that depends on
capillary size.
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Figure .
Although strictly speaking, the water still finds its level, it does so in such a way as to
maintain an overall minimum surface energy.
n this situation, the adhesion force allows water to rise up in the capillary tube while
gravity acts in the opposite direction. 'he water rises until there is a balance
between these two opposing forces. 'he differential force between adhesion and
gravity is the capillary force. 'his force per unit area is the capillary pressure.
7apillary pressure is defined as the pressure difference between two fluid phases"e.g., oil and water& at the same point in the reservoir. t is a measure of the rock!
fluid adhesion and fluid!fluid interfacial tension forces that act to hold one fluid phase
"e.g., water& at a particular location in the reservoir "e.g., above the oil!water contact&
against the force of gravity. 7apillary pressure is a complex function of the nature of
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the contained fluids, the saturation of the fluid phases, the wettability of the rock, and
the pore size distribution of the rock.
As we might surmise from observations of the capillary tube illustrated in the #igure
above, there is a relationship between capillary pressure, (c , and the interfacialtension between the two fluids "in this example !water and air&.
where
(c capillary pressure
wn wettingnon!wetting phase interfacial tension
r radius of the tube
angle of contact between the solid surface and li)uid
CAPILLARYFLUIDRISE
An alternative way to express capillary pressure is in terms of height above a free
water surface. 7apillary pressure is e)ual to the product of the height above the free
water surface and the density difference between the two fluid phases at reservoir
conditions. n a reservoir, the relationship between water saturation and height
above an oil!water or gas!water contact is, of course, strongly dependent on the rock
pore system, as well as on the wettability and interfacial tension properties of the
rock!fluid system.
We will again use #igure Iof the capillary tube to illustrate fluid height. 'he capillary
tube of radius rwill support a column of water of height h. f the density of the air is
aand the density of the water is w, then the pressure differential at the air!water
contact is simply &w -a&h. 'his pressure differential acting across the cross!sectional
area of the capillary is exactly counterbalanced by the surface tension, T, of the
water film acting around the inner circumference of the capillary tube. f the contact
angle is at the interface between the water and the glass face of the capillary tube,
then at e)uilibrium we have%
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Fr' cos "w!a&h . rF
#orce (ressure . Area
/y simplifying and rearranging this expression we see that height is expressed as%
As the capillary tube radius "r & decreases, the height "h& of the water column
increases- therefore, the height of fluid rise above a free water surface in a capillary
tube is inversely proportional to the radius of the tube. We can draw an analogy
between the capillary tube radius and the radii of pore throats in the rock matrix. n
the above example, we can correlate the air to oil, water with water, and the tube
with pore throats.
'ranslating this laboratory observation in terms of reservoir conditions, we can see
that water can be drawn up into what would otherwise be a $556 oil column by the
capillary effect resulting from small pores in the rock system. 'hus the maximum
height, h, to which water can be raised is controlled by the following factors%
the surface tension, ', between the two phases "oil and water&
the contact angle, , between the wetting fluid "water& and the rock
the radius of the pore throats "r&
the density difference between phases "w!oin this case&
n summary, the capillary rise will be greater in a rock with smaller pore throats than
in one with large pore throats.
Legt/ o% Trasitio 0oe
;iven the above factors, it is easy to characterize the relative length of a transition
zone in a reservoir. :eservoirs with large pore throats and high permeability have
short transition zones, and the transition zone at a gas!oil contact will be shorter
than that at an oil!water contact simply because of the inter!phase density
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differences involved "#igure 0 &.
Figure
4ince a pore system is made up of a variety of pore sizes and shapes, no single
pore throat radius can be assigned to a reservoir. Cepending on the size and
distribution of the pore throats, certain available pore channels will raise water above
the free!water level. 'he water saturation above the top of the transition zone will
thus be a function of porosity and pore!size distribution.
n a water!wet system, the water will wet the surface of each grain or will line the
walls of the capillary tubes. At the time oil migrates into the reservoir, the capillary
pressure effects will be such that the downward progress of oil in the reservoir is
most strongly resisted in the smallest capillaries. A particular elevation will limit the
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amount of oil that can be expected to fill the pores. Darge!diameter pores offer little
resistance "capillary pressure, 'c, is low because pore radius, r is large&. 4mall!
diameter pores offer greater resistance "'cis high because ris small&. #or a given
reservoir, o and wdetermine the pressure differential that an oil!water meniscus
can support.
Ca-i##ary Pressure a$ Irre$u&i"#e Water Saturatio
2aximum oil saturation is controlled by the relative number of small and large
capillaries or pore throats. 'his maximum possible oil saturation, if expressed in
terms of water saturation, translates into a minimum possible water saturation, and
this is referred to as the irreducible water saturation %wi.
4haly, silty, low!permeability rocks with their attendant small pore throats and high
capillary pressures, tend to have very high irreducible water saturations. Just the
opposite is true for clean sands of high permeability, which have low irreducible
water saturations. #igure Gillustrates this important concept by comparing capillary
pressure curves for four rock systems of different porosity and permeability.
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Figure 2
Stru&tura# Positio )it/i t/e Reser,oir
We all know that gravity segregation causes a natural stratification of reservoir fluids,
with gas on top of oil, and oil over water. n the absence of rock pores, the gas, oil,
and water will form distinct layers, with sharp contacts between each phase. n a
reservoir, however, the contacts between each phase are less distinct, as illustrated
in the #igure 9% (eservoir containing oil and water .
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Figure 3
'his diagram divides the reservoir into three levels. 'he upper level is mainly oil- the
lower level is all water, while the middle level shows ever!increasing concentrations
of water as depth increases. (lotted on the right!hand side is a curve of water
saturation, together with a plot of fluid pressure in the pore spaces.
When a formation is abovethe transition zone, i.e., at irreducible water saturation,
the product of and 4wis a constant. +ariations of porosity are normal on a local
scale, caused both by changes in the depositional environment and by subse)uentdiagenesis. f porosity is reduced locally, then either a greater proportion of pore
throats will be small or there will be simply fewer pore throats. ither way, the mean
radius of the pore throat rwill be smaller- thus 'cwill be larger, and more water can
be held in the pore maintaining the constant%
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. 4wi
After a zone has been analyzed on a foot!by!foot basis for porosity and water
saturation, a plot of versus 4wreveals the presence or absence of a transition
zone.
#igure ? shows a log!log plot, where points at irreducible saturation plot along a
straight line "the red line denoting Kero Water (roduction in this graphic&, and the
points in the transition zone plot to the right of the irreducible line.
Figure 4
/y plotting the product of . 4wi, it is possible to predict certain production
characteristics. #or points below irreducible saturation, some portion of water
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production is to be expected, depending on the mobility ratio, "k w1oko1w&, for the
particular fluids present. 3n the other hand, in a low-porosity low-permeability
formation, we again see that surprisingly high water saturations can be tolerated
without fear of water production. 7onversely, in other formations that exhibit good
porosity and permeability, even moderate values of 4w will mean that water
production should be expected.
Again, since both capillary pressure and relative permeability data are a strong
function of pore size distribution and geometry "among other factors&, they will, in
turn, often fall into groups that correlate with specific reservoir facies "2organ and
;ordon $
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Figure 5
'he difference in the measured relative permeabilities illustrates the importance of
pore system configuration in determining fluid flow characteristics.
3ne important observation to be derived from evaluating capillary pressure and
relative permeability for individual geologic facies is the determination of the
producing oil!water "or gas!water& contact elevation throughout various parts of a
reservoir. 'his elevation can vary across a reservoir, and can be substantially
different from the free water surface elevation. 'he free water surface should be at a
constant elevation throughout the reservoir, providing the reservoir is in a state of
gravity!capillary e)uilibrium with no significant flow occurring. 'he producing oil!
water contact is often taken as the highest elevation where $556 water is produced.
T/is $e-t/ )i## ot e&essari#y "e t/e sa'e at a## -oits i t/e reser,oir6 e,e
u$er e7ui#i"riu' &o$itios8 It )i## strog#y $e-e$ o #o&a# &a-i##ary
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-ressure 9)ater saturatio ,ersus /eig/t a"o,e t/e %ree )ater sur%a&e: a$ t/e
re#ati,e -er'ea"i#ity &/ara&teristi&s o% t/e ro&;8
Ca-i##ary Pressure a$ !eo#ogi& Fa&ies
A relationship between geologic facies and capillary pressure curves is illustrated
graphically in #igure
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Puttig It A## Toget/er ( !eo#ogy a$ F#ui$s
We have just reviewed a number of factors which influence the rreducible Water
4aturation within a formation. 'hese factors include interactions between fluidsand
roc#, as well as interactions between different fluids. /y examining porosity, relative
permeability, and capillary pressure relationships, along with rock texture and
structural position, it is possible to determine whether a well having high 4w
calculations will actually produce water, or instead, will produce water!free.
#or example, as we move toward the top of a fining!upward se)uence, the decrease
in sand grain diameter will produce a corresponding decrease in pore throat radius.
'his decrease in pore throat radius is accompanied by an increase in capillary
pressure, thus increasing the amount of water that can be imbibed into the system. f
we add clay or silt to this example, we can expect that microporosity will constitute a
substantial percentage of total porosity. 4uch a setting is bound to produce high
values of irreducible water saturations.
/oth irreducible water and residual hydrocarbon saturations are strongly influenced
by rock texture, which is controlled by depositional environment. #ine!grained
sediments, usually characteristic of low!energy depositional environments, tend to
have high irreducible water with high residual hydrocarbon saturations- coarse!
grained sediments, characteristic of high!energy environments, tend to have low
irreducible water saturation and low residual hydrocarbon saturation. n addition,
fine!grained sediments tend to have lower permeability than coarse!grained
sediments.
'hese factors must all be considered together when analyzing low resistivity pay
zones. (orosity, capillarity, relative permeability, structural position and grain size will
all influence the final evaluation of irreducible water saturation in a low resistivity pay
zone.