USA Toll Free: 1-866-800-8016 Local: +1-713-331-0534 Fax: +1-281-360-6959
FOR UNDERSATURATED RESERVOIRS
Monty E. Hoffman
Safford Exploration, Inc.
6565 West Hoover Place
Littleton, Co 80123
Contact Monty for more information: email@example.com
This paper has required integrating concepts from many different
fields. It would not have been possible without the help of
people too numerous to mention. To all of those people I would
like to give special thanks and to acknowledge that I couldn’t
have written it without your help.
Recent work has documented the existence of reservoirs that
are undersaturated in water and are in capillary pressure
non-equilibrium. These reservoirs will spontaneously imbibe
water if they are drilled or completed with water based fluids.
This imbibition causes the reservoir to water block and is
very difficult to remove because it requires returning the
reservoir to a non-equilibrium state. Once the reservoir is
water blocked, it may produce nothing at all, or it may produce
water greatly in excess of any water that was lost to the
reservoir, even if it would have produced all hydrocarbons
if properly drilled.
Undersaturated reservoirs form by post hydrocarbon migration
uplift and erosion. This removal of overburden causes the
water to cool and shrink and the pores to dilate. This increases
the pore volume and decreases the water volume and the reservoir
is in capillary pressure non-equilibrium.
Wettability changes in a reservoir can control what parts
of an undersaturated reservoir can be water blocked, since
water can only be imbibed if it is the wetting phase. Production
changes caused by wettability changes can mimic the distribution
of production that would be expected from water, transition,
and hydrocarbon zones in a reservoir, but the geophysical
logs will not show the expected fluid changes.
Any undersaturated reservoir that has been drilled and completed
with a water based fluid has not been properly evaluated.
Lack of hydrocarbon recovery or recovery of large volumes
of water does not preclude commercial production of hydrocarbons
if the reservoir is properly drilled.
Introduction Reservoirs that are in non-equilibrium with respect
to capillary pressure in the subsurface and that can produce
water more readily than oil or gas when exposed to water based
drilling and completion fluids have been identified (Bennion,
et al, 2000). These reservoirs are undersaturated with water
for their present capillary pressure. This has significant
implications in terms of drilling methods and drilling fluids.
Improperly drilled wells in these types of reservoirs will
produce no fluids or are capable of producing entirely different
fluids than the reservoir would produce if properly drilled.
Stated simply, an oil or gas reservoir can be made to produce
predominately water and produce an amount of water that is
much greater than any water lost during the drilling process.
Recent drilling in undersaturated reservoirs has resulted
in the discovery of an economically viable reservoir with
greater than 5 TCF in place by Encana in British Columbia
(Encana Corp, 2002). This reservoir had many wells drilled
through it before it was recognized as undersaturated and
subsequently drilled properly. There are many similar type
reservoirs that have been penetrated and gone unrecognized
because they cannot be evaluated and produced by standard
oil field practices.
Description and Cause Figure 1 is from Bennion, et al’s, (2000) article
and shows the capillary pressures for undersaturated reservoirs.
Initial water saturation (point “A”) is less than
the capillary pressure equilibrium curve (point “B”).
If any water is introduced into the borehole in an undersaturated
reservoir, capillary forces spontaneously imbibe water into
the reservoir, increasing the water saturation and relative
permeability to water and simultaneously decreasing the relative
permeability to hydrocarbons (Bennion, ET, al, 2000). The
imbibed water is difficult to remove because capillary forces
act to hold the water in place to maintain capillary equilibrium.
While Bennion, et al (2000) have recognized this class of
reservoirs, their explanation of their development, moving
large volumes of gas through them to dehydrate them, is difficult
to fit to a geologic and hydrologic model. A better explanation
can be derived from Ferran’s (1973) explanation of low
pressured Morrow sands.
We recognized early on in our pursuit of these reservoirs
that many, but not all, of the undersaturated reservoirs are
also underpressured and that there may be a genetic link between
the underpressured state and the undersaturation. Ferran proposes
that the underpressuring occurs because uplift and erosion
cause three changes that reduce the water volume in the reservoir.
First is pore dilation in the reservoir as the overburden
pressure is removed. Second is the shrinkage of the water
as it cools (Barker, 1972; Kennedy and Holser, 1966). Third,
is the resaturation of the surrounding shales as they expand
when the overburden pressure is removed. Examination of a
pressure profile in the Oklahoma panhandle (figure 2) shows
that the gradient is not formation or lithology dependent,
so having surrounding shales does not appear to be a critical
requirement and its contribution is minimal. These processes
all reduce water volume relative to volume of pore space and
cause underpressuring and undersaturation, but cooling has
by far the greatest influence.
Figure 3 illustrates the development of undersaturation.
After hydrocarbon migration and emplacement, point 1 shows
the initial capillary pressure and saturation condition at
a point in the reservoir. After uplift and erosion, Sw has
shifted to point 2 and the reservoir is out of capillary pressure
equilibrium. If any water is made available to the reservoir,
it will imbibe it in an attempt to return to point 3, the
capillary pressure equilibrium point on the imbibition curve.
Post hydrocarbon migration uplift and erosional removal of
overburden will result in a reservoir that has less water
volume in the pore space than when it was charged with hydrocarbon
and it will be in a non equilibrium situation. The volume
that was occupied by water is taken up by gas expansion and
gas that comes out of solution in the oil and expands. Almost
all of the sixty undersaturated reservoirs that we have studied
have low GORs and gas caps on low gravity oil reservoirs.
Pore Systems and Relative Permeability
Figures 4 through 6 are modified from Standing (1975) and
show the progression of fluid distribution in pore sizes upward
through a hydrocarbon accumulation. Starting at the free water
surface, where capillary pressure is zero, all pores are filled
with water (Figure 4).
Moving up into the transition zone, with increasing hydrocarbon
column height and corresponding increase in capillary pressure
due to buoyancy, the hydrocarbons displace the water from
the pores, with the water being moved out of the largest pores
first. This occurs because capillary forces are lowest in
the larger pore systems and the water will move from these
pores with a lower buoyancy force (figure 5). At high hydrocarbon
column heights, the hydrocarbons have displaced all nearly
of the water that can be moved and the reservoir is at irreducible
water saturation (Figure 6).
Because the hydrocarbons are sorted into different pore
systems by capillary entry pressures (Standing, 1975), the
relative permeability to different fluids can be altered by
blocking off different pore systems. If the hydrocarbon system
is blocked off by water block, this will cut down the cross
sectional area of the reservoir and increase the force on
the water system that remains open. Darcy’s Law can
be rewritten in the form:
Where q is the volume flux (volume per unit time) in centimeters
per second for horizontal flow, K is the permeability constant
in darcys, A is the cross sectional area in square centimeters,
µ is the fluid viscosity in centipoises, and dp/dx is
the hydraulic gradient (the difference in pressure, p, in
the direction of flow, x) in atmospheres per centimeter.
As the cross sectional area (A) decreases, the force across
the water pore system (dp/dx) increases. This increase in
force is enough to overcome the capillary forces that had
previously prevented the water from flowing in part of the
water pore system. Water that was previously immobile is now
mobile. By damaging the reservoir by water block, the critical
water saturation of the reservoir has been reduced and a large
amount of water that would not have moved can now be produced
in the well bore. The relative permeability to hydrocarbons
has been greatly decreased and the relative permeability to
water has been increased in the reservoir. The reservoir will
flow water in amounts that are greatly in excess of any water
lost during drilling, even though the reservoir would have
made no water if it had not been damaged.
Critical Water Saturation
versus Irreducible Water Saturation Figure 7 (Arps, 1964) shows a generalized relationship
between water saturation, relative permeability, and capillary
pressure. The diagram shows the difference between critical
water saturation (CWS), defined as the water saturation below
which the formation will only flow oil or gas, and irreducible
water saturation (IWS), defined as the water saturation below
which little additional water can be displaced from the formation
by a higher capillary injection pressure. It shows that the
water saturation at which we start to produce water free oil
is not determined by irreducible water saturation, but by
the critical water saturation. When Krw is zero (CWS), only
oil or gas will be produced regardless of how much mobile
water is in the formation.
Figures 8 and 9 show calculated relative permeability and
hydrocarbon column height curves for a 2.8 millidarcy core
plug from the Mississippian Limestone in North Ness City Field,
Ness County, Kansas. CWS is 47% water saturation and IWS is
5% water saturation or less. Figure 9 shows that CWS is reached
at 75 feet above the free water surface but IWS still isn’t
reached at 4000 feet above the free water surface. Undamaged,
this reservoir will produce 100% oil 75 feet above the free
water surface. Damaged it could produce significant water
4000 feet above the free water surface and produce water greatly
in excess of any water lost during drilling.
Testing and Production Problems Bennion, et al, (2000) recognized that in a reservoir
that is at irreducible water saturation, the primary problem
with introducing water into these reservoirs from drilling
fluids is that it changes the relative permeability to oil
or gas and severely limits hydrocarbon production.
For reservoirs that are below critical water saturation but
not at irreducible water saturation, the problem is even more
difficult. Water blocking the hydrocarbon porosity system
causes the critical water saturation of the reservoir to be
reduced by increasing the force on the water system and overcoming
the capillary forces that have held the water immobile in
part of the water pore system. Part of the water that was
immobile before the reservoir damage is now mobile. When the
reservoir is flow tested, it will produce little or no hydrocarbons
and large amounts of formation water. In standard oil field
practice, the zone will be considered wet and abandoned, even
though the geophysical logs show hydrocarbon saturation.
Effects of Wettability Wettability adds a further complication to the problem.
Wettability of a reservoir is a variable that is affected
by capillary pressure, oil and water chemistry, fluid-fluid
interactions and rock-fluid interactions. Work on wettability
over the last ten years has focused on wettability changes
caused by reservoir condition variations. (Jerauld and Rathmell,
1997; Jain, et al, 2002) This work has resulted in a recognition
that wettability can change in a reservoir with the height
of the hydrocarbon column and the subsequent change in capillary
pressure and initial water saturation. It can also change
from reservoir to reservoir in an area because of oil or water
Because a reservoir will only imbibe the wetting phase, the
ability to damage a reservoir by water block changes as the
wettability changes. A reservoir that is capable of producing
only water low in the hydrocarbon column where it is still
water wet will be capable of producing some hydrocarbon as
the reservoir changes to mixed wet and will produce all hydrocarbons
when it becomes mostly oil or gas wet.
This distribution of production mimics what would be expected
from water, transition, and hydrocarbon zones in a reservoir.
The difference is that the log character does not show the
fluid changes that would be expected as the logs pass from
zone to zone. Improper drilling and completion techniques
can result in water tests in the hydrocarbon column. This
can result in a large part of the hydrocarbon column being
considered as being below the free water surface. Properly
drilled, the hydrocarbon production can be extended down dip.
Asphaltene compound deposition on grain surfaces also changes
rocks from water wet to mixed wet. In an area where there
are oils with different asphaltene contents, the oils with
greater asphaltene content will become mixed wet and prevent
water block. Oils that are high in paraffin content and low
in asphaltene content tend to be water wet at lower water
Conclusions 1. Bennion, et al, (2000) have documented the existence
of reservoirs that are undersaturated with regard to water
in relation to capillary pressure equilibrium. Because of
this, the reservoirs water block by spontaneous imbibition
and are very difficult to return to a productive condition
because it requires going from equilibrium to a non-equilibrium
situation to remedy the damage.
2. Undersaturated reservoirs form when pore dilation and
water cooling cause the volume of water relative to the pore
space in the reservoir to shrink. This is caused by post hydrocarbon
migration uplift and erosion.
3. Reservoir fluids are sorted into different pore systems
by capillary entry pressures. The relative permeability to
the different fluids can be changed by water blocking the
hydrocarbon pore system.
4. If a reservoir is at irreducible water saturation, the
water block will greatly reduce the relative permeability
to hydrocarbons. If a reservoir is below critical water saturation
but above irreducible water saturation it can produce all
water even if it would produce all hydrocarbons if undamaged
5. The amount of water produced can be greatly in excess
of the amount of water lost to the reservoir during drilling
and completion operations. This is caused by the water block
lowering critical water saturation and causing previously
immobile water to become mobile.
6. As reservoirs change from water wet to mixed wet to mostly
oil or gas wet, the damage that can be done by water block
changes. This mimics the distribution that would be expected
going from the free water surface through a transition zone
to irreducible water saturation. The geophysical logs can
be used to tell whether the fluid recovery changes are due
to fluid content changes or water blocking.
7. Any undersaturated reservoir that has been drilled and
completed with water based fluids has not been properly evaluated.
Lack of fluid recovery or recovery of large volumes of water
does not preclude production of hydrocarbons if the reservoir
is drilled properly.
Arps, J.J., 1964, Engineering Concepts
Useful in Oil Finding: Am. Assoc. Petroleum Geologists
Bull, Vol. 48, No. 2, pp. 157-165.
Barker, C., 1972, Aquathermal Pressuring-Role
of Temperature in Development of Abnormal-Pressure Zones:
Am. Assoc. Petroleum Geologists Bull, Vol. 56, pp.2068-2071.
Bennion, D.B., Thomas F.B., and Ma,
T., 2000, Formation Damage Processes Reducing Productivity
of Low Permeability Gas Reservoirs: Society of Petroleum
Engineers Paper # 60325.
Encana Corp., 2002, News and Views,
June 4, 2002 http://www.encana.com/news_and_views/4_0_20020604_1.shtml
Ferran, L.H., 1973, Evaluation of
Abnormally High and Low Pressured Morrow Sands in Northwestern
Oklahoma Using Well Logs and Water Sample Data: Univ.
of Tulsa Master’s Thesis.
Jain, V. ,Chattopadhyay, S., and Sharma,
M.M., 2002, Effect of Capillary Pressure, Salinity, and
Aging on Wettability Alteration in Sandstones and Limestones:
Society of Petroleum Engineers Paper #75189.
Jerauld, G.R. and Rathmell, J.J.,
1997, Wettability and Relative Permeability of Prudhoe
Bay: a Case Study in Mixed-Wet Reservoirs, SPE Reservoir
Engineering, February 1997, pp. 58-65. (SPE Paper # 28576)
Kennedy, G.C., and Holser, W.T., 1966,
Pressure-volume-temperature and phase relations of water
and carbon dioxide, Sec. 16 in Handbook of physical constants
(rev. ed.: Geol. Soc. America Mem. 97, pp.371-383.
Oklahoma State University School of
Geology, 2002, Anadarko Basin Pressure Data http://www.okstate.edu/geology/gri/exa-pd.gif
Standing, M.B., 1975, Notes on Relative
Permeability Relationships: Stanford University, CA.
Figure 1 – Typical capillary pressure curves
for undersaturated water wet porous media illustrating imbibition
potential upon exposure to water based fluids. (Bennion,
Thomas, and Ma, 2000)
Figure 2- Texas County, Oklahoma pressure-depth profile
(Oklahoma State University School of Geology, 2002)
Figure 3- Development of undersaturated reservoirs
by uplift and erosion
Figure 4- Pore size distribution of fluids below the
free water surface (after Standing, 1975)
Figure 5- Pore size distribution of fluids in the
transition zone (after Standing, 1975)
Figure 6- Pore size distribution of fluids at irreducible
water saturation (after Standing, 1975)
Figure 7- Relationship of critical water saturation
and irreducible water saturation to water saturation, relative
permeability, and capillary pressure (Arps, 1964)