U.S. patent application number 12/253426 was filed with the patent office on 2010-04-22 for method of hydrocarbon recovery.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Kevin W. England, Jerald J. Hinkel.
Application Number | 20100096129 12/253426 |
Document ID | / |
Family ID | 42107298 |
Filed Date | 2010-04-22 |
United States Patent
Application |
20100096129 |
Kind Code |
A1 |
Hinkel; Jerald J. ; et
al. |
April 22, 2010 |
METHOD OF HYDROCARBON RECOVERY
Abstract
A method is given for treating a wellbore to increase the
production of hydrocarbons from a subterranean formation penetrated
by a wellbore, involving a period of injecting into the formation
an aqueous injection fluid having a different chemical potential
than the aqueous fluid in the formation. If there is water
blocking, an osmotic gradient is deliberately created to cause flow
of water into the injected fluid; hydrocarbon is then produced by
imbibition. If the pore pressure in the water-containing pores in
the formation is too low, an osmotic gradient is deliberately
created so that water flows from the injected fluid into the
water-containing pores, increasing the pore pressure and
facilitating hydrocarbon production by imbibition. The method may
be repeated cyclically. A semipermeable membrane may be created to
enhance the osmosis. Wetting agents may be used to influence
imbibition.
Inventors: |
Hinkel; Jerald J.; (Houston,
TX) ; England; Kevin W.; (Houston, TX) |
Correspondence
Address: |
Schlumberger Technology Corporation
P. O. Box 425045
Cambridge
MA
02142
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Cambridge
MA
|
Family ID: |
42107298 |
Appl. No.: |
12/253426 |
Filed: |
October 17, 2008 |
Current U.S.
Class: |
166/270.1 |
Current CPC
Class: |
E21B 43/16 20130101 |
Class at
Publication: |
166/270.1 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. A method of producing hydrocarbon from a subterranean formation
penetrated by a wellbore comprising a period of injecting into the
formation an aqueous injection fluid, other than a fracturing fluid
or a pad, having a higher chemical potential than the aqueous
formation fluid, wherein water in the injection fluid flows into
the formation fluid by osmosis, whereby there is an increase in
pressure in the formation, and whereby a portion of the hydrocarbon
flows to the wellbore, and further wherein, if the formation is
hydraulically fractured, the volume of aqueous injection fluid
having a higher chemical potential than the aqueous fluid in the
formation is greater than the volume of the hydraulic fracture plus
the volume of any natural fractures contacted plus the volume
leaked off during the hydraulic fracturing treatment.
2. The method of claim 1 wherein the injection fluid contacts at
least one quarter of the practical wellbore drainage volume.
3. The method of claim 1 wherein injection is performed in
different places in the formation.
4. The method of claim 1 wherein the period of injection is
followed by a period of production without injection.
5. The method of claim 4 wherein the period of production without
injection is followed by a second period of injection.
6. The method of claim 1 further comprising injecting a
semipermeable-membrane forming material in an amount sufficient to
form a semipermeable membrane.
7. The method of claim 1 wherein the injection fluid comprises
formate.
8. The method of claim 1 wherein the injection fluid further
comprises an agent that increases the contact angle of the
formation with water.
9. The method of claim 1 wherein the injection fluid further
comprises an agent that decreases the contact angle of the
formation with water.
10. The method of claim 1 wherein the osmotic pressure generates
fractures in the formation.
11. The method of claim 1 wherein the formation is hydraulically
fractured.
12. (canceled)
13. A method of producing hydrocarbon from a subterranean formation
penetrated by a wellbore comprising injecting into the formation an
aqueous injection fluid, other than a fracturing fluid or a pad,
having a lower chemical potential than the aqueous formation fluid,
wherein a portion of the water in the formation fluid flows into
the injection fluid by osmosis, whereby a portion of the
hydrocarbon flows to the wellbore, and further wherein, if the
formation is hydraulically fractured, the volume of aqueous
injection fluid having a lower chemical potential than the aqueous
fluid in the formation is greater than the volume of the hydraulic
fracture plus the volume of any natural fractures contacted plus
the volume leaked off during the hydraulic fracturing
treatment.
14. The method of claim 13 wherein the injection fluid contacts at
least one quarter of the practical wellbore drainage volume.
15. The method of claim 13 wherein injection is performed in
different places in the formation.
16. The method of claim 13 wherein the period of injection is
followed by a period of production without injection.
17. The method of claim 16 wherein the period of production without
injection is followed by a second period of injection.
18. The method of claim 13 further comprising injecting a
semipermeable-membrane forming material in an amount sufficient to
form a semipermeable membrane.
19. The method of claim 13 wherein the injection fluid comprises
formate.
20. The method of claim 13 wherein the injection fluid further
comprises an agent that increases the contact angle of the
formation with water.
21. The method of claim 13 wherein the injection fluid further
comprises an agent that decreases the contact angle of the
formation with water.
22. The method of claim 13 wherein the osmotic pressure generates
fractures in the formation.
23. The method of claim 13 wherein the formation is hydraulically
fractured.
24. (canceled)
25. A method of producing hydrocarbon from a subterranean formation
penetrated by a wellbore comprising injecting into the formation an
aqueous injection fluid having the same chemical potential as the
aqueous fluid in the formation, whereby no osmotic pressure
gradient is created, and whereby a portion of the hydrocarbon flows
to the wellbore.
26. The method of claim 25 wherein the injection fluid contacts at
least one quarter of the practical wellbore drainage volume.
27. The method of claim 25 wherein injection is performed in
different places in the formation.
28. The method of claim 25 wherein the period of injection is
followed by a period of production without injection.
29. The method of claim 28 wherein the period of production without
injection is followed by a second period of injection.
30. The method of claim 25 further comprising injecting a
semipermeable-membrane forming material in an amount sufficient to
form a semipermeable membrane.
31. The method of claim 25 wherein the injection fluid comprises
formate.
32. The method of claim 25 wherein the injection fluid further
comprises an agent that increases the contact angle of the
formation with water.
33. The method of claim 25 wherein the injection fluid further
comprises an agent that decreases the contact angle of the
formation with water.
34. The method of claim 25 wherein osmotic pressure is used in a
separate step to generate fractures in the formation.
35. The method of claim 25, wherein the formation is hydraulically
fractured.
36. The method of claim 35, wherein the volume of injected fluid is
at least the volume of the hydraulic fracture.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application is related to commonly-assigned and
simultaneously-filed U.S. patent application Ser. No. 12/253,406,
entitled "Enhancing Hydrocarbon Recovery", incorporated herein by
reference in its entirety.
BACKGROUND OF THE INVENTION
[0002] The invention relates to the recovery of hydrocarbons from
subterranean formations. More particularly, it relates to methods
of using osmotic pressure effects to increase the rate and/or
amount of hydrocarbon that flows to producing wells.
[0003] Hydrocarbons (gas, supercritical fluid, condensate, and oil)
are typically found in the pores of subterranean rock formations.
Although occasionally hydrocarbons flow naturally to a producing
well at a commercially acceptable rate and extent due to inherent
hydraulic forces, normally some means must be employed to increase
the rate and/or extent of this flow. Methods include pumping, which
will not be discussed further, stimulation, and enhanced recovery.
Stimulation methods increase or improve the flow path from the
reservoir to the producing well. They include acidizing (and
treating with other chemically reactive treating fluids designed to
remove various types of damage and pumped at bottomhole pressures
less than that required to hydraulically fracture the formation),
and hydraulic fracturing (including acid fracturing). Enhanced
recovery may involve drilling both injection and production wells.
Another method of enhanced recovery may involve systematically
converting existing production wells into injection wells.
Additionally, it is common to utilize the same wellbore as both
injector and producer in cycles to obtain the desired effect in the
reservoir. We can call these cases A, B, and C. In cases A and B,
fluid is forced into the injection wells and causes formation
fluids to flow to the production wells. The injected fluid may act
solely hydraulically or, more commonly, it has an additional
function. As examples, the fluid may be hot and cause a reduction
in oil viscosity; the fluid may be a solvent for the hydrocarbon;
and the fluid may contain chemicals, for example surfactants, that
change the formation rock wettability and/or change the interfacial
tensions between the hydrocarbon and water phases and the rock. In
case C, fluid is injected into the wellbore in order to
create/modify fluid-rock properties in the reservoir such that when
the wellbore is cycled back to production mode it will recover
hydrocarbons at a higher rate with better ultimate recovery. Other
stimulation methods include the use of explosives (i.e.
nitroglycerine) and propellants, hydrodynamic and acoustic pulsing,
special perforating techniques, and jetting (such as
hydrojetting).
[0004] There are three main driving forces of interest in this
discussion that govern fluid flow in reservoir rocks: hydraulic
pressure, capillary pressure, and osmotic pressure. Because of
these different driving forces, a fluid, for example water, does
not necessarily flow from a region of high pressure to a region of
low pressure, rather it flows from a region of high potential to a
region of low potential.
[0005] There is a need for methods of manipulating osmotic flow to
improve hydrocarbon recovery.
SUMMARY OF THE INVENTION
[0006] One embodiment of the Invention is a method of producing
hydrocarbon from a subterranean formation penetrated by a wellbore.
The method includes a period of injecting into the formation an
aqueous injection fluid having a higher chemical potential than the
aqueous fluid in the formation. Water in the injection fluid flows
into the formation fluid by osmosis, there is an increase in
pressure in the formation, and a portion of the hydrocarbon flows
to the wellbore. This flow may be by co-current and/or
counter-current imbibition (hereinafter referred to collectively
simply as "imbibition"). The injection fluid may contact, for
example, at least one quarter of the practical wellbore drainage
volume. The period of injection may be followed by a period of
production without injection. The period of production without
injection may be followed by a second period of injection. The
method may additionally include injecting a semipermeable-membrane
forming material in an amount sufficient to form a semipermeable
membrane. The injection fluid may, for example, include a formate.
The injection fluid may also include an agent that increases the
contact angle of the formation with water. The injection fluid may
alternatively include an agent that decreases the contact angle of
the formation with water. In the method, the osmotic pressure may
generate fractures in the formation.
[0007] Another embodiment of the Invention is a method of producing
hydrocarbon from a subterranean formation penetrated by a wellbore
involving injecting into the formation an aqueous injection fluid
having a lower chemical potential than the aqueous fluid in the
formation. A portion of the water in the formation fluid flows into
the injection fluid by osmosis, phase trapping is reduced, and a
portion of the hydrocarbon flows to the wellbore. This flow may be
due to imbibition. The injection fluid may contact, for example, at
least one quarter of the practical wellbore drainage volume. The
period of injection may be followed by a period of production
without injection. The period of production without injection may
be followed by a second period of injection. The method may
additionally include injecting a semipermeable-membrane forming
material in an amount sufficient to form a semipermeable membrane.
The injection fluid may, for example, include a formate. The
injection fluid may also include an agent that increases the
contact angle of the formation with water. The injection fluid may
alternatively include an agent that decreases the contact angle of
the formation with water. In the method, the osmotic pressure may
generate fractures in the formation.
[0008] Yet another embodiment of the Invention is a method of
producing hydrocarbon from a subterranean formation penetrated by a
wellbore that involves injecting into the formation an aqueous
injection fluid having the same chemical potential as the aqueous
fluid in the formation. No osmotic pressure gradient is created,
but a portion of the hydrocarbon flows to the wellbore. This flow
may be due to imbibition. The injection fluid may contact, for
example, at least one quarter of the practical wellbore drainage
volume. The period of injection may be followed by a period of
production without injection. The period of production without
injection may be followed by a second period of injection. The
method may additionally include injecting a semipermeable-membrane
forming material in an amount sufficient to form a semipermeable
membrane. The injection fluid may, for example, include a formate.
The injection fluid may also include an agent that increases the
contact angle of the formation with water. The injection fluid may
alternatively include an agent that decreases the contact angle of
the formation with water. Osmotic pressure may be used in a
separate step to generate fractures in the formation.
DETAILED DESCRIPTION OF THE INVENTION
[0009] Although some portions of the following discussion may
emphasize hydraulic fracturing, and other portions may emphasize
enhanced recovery, it is to be understood that, with suitable
modification, the methods of the Invention may be used with any
type of fluid recovery technique. The Invention will be described
for hydrocarbon recovery, but it is to be understood that the
Invention may be used for wells for the recovery of other fluids,
such as water or carbon dioxide, or, for example, for injection or
storage wells. It should also be understood that throughout this
specification, when a concentration or amount range is described as
being useful, or suitable, or the like, it is intended that any and
every concentration or amount within the range, including the end
points, is to be considered as having been stated. Furthermore,
each numerical value should be read once as modified by the term
"about" (unless already expressly so modified) and then read again
as not to be so modified unless otherwise stated in context. For
example, "a range of from 1 to 10" is to be read as indicating each
and every possible number along the continuum between about 1 and
about 10. In other words, when a certain range is expressed, even
if only a few specific data points are explicitly identified or
referred to within the range, or even when no data points are
referred to within the range, it is to be understood that the
inventors appreciate and understand that any and all data points
within the range are to be considered to have been specified, and
that the inventors have possession of the entire range and all
points within the range.
[0010] It is widely believed that water imbibition into a reservoir
from a well that will be used for production is deleterious in
several ways. (See, for example, Bennion, D. B., et al., "Low
Permeability Gas Reservoirs: Problems, Opportunities and Solutions
for Drilling, Completion, Stimulation and Production," SPE 35577,
Gas Technology Conference, Calgary, Alberta, Canada, Apr. 28-May 1,
1996, and Bennion, D. B., et al., "Formation Damage Processes
Reducing Productivity of Low Permeability Gas Reservoirs," SPE
60325, 2000 SPE Rocky Mountain Regional/Low Permeability Reservoirs
Symposium and Exhibition, Denver, Colo., Mar. 12-15, 2000.) Imbibed
water increases the water saturation and is thought to become
trapped and to block hydrocarbon flow. If imbibed water is fresher
than formation water, it may affect fresh water sensitive expanding
clays present in the reservoir. Furthermore, imbibition of water
into formations such as shales during drilling may be responsible
for spalling and wall (borehole) collapse. For these reasons,
operators often would like to complete wells with non-aqueous
fluids but do not do so in the vast majority of the cases because
of such reasons as significantly higher costs and environmental
risks. Water invasion of reservoirs, except in water-flooding with
distinct injectors and producers, is considered a damage mechanism
and is to be avoided.
[0011] Bennion, et al. (2000) illustrate both the present
understanding of one example of how capillary pressures lead to
phase trapping of water and to blocking of hydrocarbon production,
and give proposed solutions that are opposite the principles and
method of the present Invention. Bennion, et al. (2000) teach that
very low permeability gas reservoirs are typically in a state of
capillary undersaturation, where the initial water (and sometimes
oil) saturation is less than would be expected from conventional
capillary mechanics for the pore system under consideration.
Retention of fluids (phase trapping) is considered to be one of the
major mechanisms of reduced productivity, even in successfully
hydraulically fracture-stimulated completions in these types of
formations. In a low permeability gas reservoir, due to the very
small size of the pore throats and pore bodies, the tortuous nature
of the pore system and the high degree of micro-porosity, the
observed radii of curvature of the gas-liquid interfaces are very
small, particularly at low water saturations, which gives rise to
the higher capillary pressure values and higher irreducible water
saturation values which are commonly associated with poor quality
porous media. In general, as permeability and porosity decrease and
the relative fraction of micro-porosity increases, both the
capillary pressure and the irreducible water saturation tend to
increase substantially.
[0012] Bennion, et al. (2000) further teach that often associated
with this increase in trapped initial liquid saturation is a
significant reduction in the net effective permeability to gas,
caused by the occlusion of a large portion of the pore space by the
irreducible and immobile trapped initial liquid saturation present.
On a relative permeability basis, in general, the greater the value
of the initial trapped fluid saturation, the less original reserves
of gas in place are available for production, and also the lower
the initial potential productivity of the matrix. In reservoir
situations where exceptionally low matrix permeability is present,
one finds that, if the reservoir is in a normally saturated
condition (that is, if the reservoir is in free contact and
capillary equilibrium with mobile water and is at a normal level of
capillary saturation for the specific geometry of the porous media
under consideration), Bennion, et al. (2000) teach that very high
trapped initial liquid saturations tend to be present, and that it
can be observed that in reservoir rocks of permeability to gas on
an absolute basis of less than 0.1 mD, effective initial water
saturations are often in the 60% plus region. (It should be
appreciated that such high saturations may be erroneous, due to
contamination during handling.) This often results in significant
reductions of the original reserves of gas in place in the porous
media, and may also result in a very low or zero effective
permeability to gas, as the gas saturation may be at or near the
critical mobile value, and hence it will exhibit limited or no
mobility when a differential pressure gradient is applied to the
formation during production operations.
[0013] Therefore, Bennion, et al. (2000) teach that in most cases
where very low permeability gas reservoirs are potentially
productive, the reservoir exists in a situation where the reservoir
sediments have been isolated from effective continual contact with
a free water source which is capable of establishing an equilibrium
and uniform capillary transition zone. They believe that a
combination of long-term regional migration of gas through the
isolated sediments (resulting in an extractive desiccating effect
as temperature and pore pressure are increased over geologic time),
or an osmotically-motivated suction of connate water into highly
hydrophilic clays or overlying/interbedded sentiments, may be
responsible for the establishment of what is commonly referred to
as a "sub-irreducible" initial water saturation condition.
[0014] A reservoir having a sub-irreducible initial water
saturation is defined by Bennion, et al. (2000) as a reservoir
which exhibits an average initial water saturation less than the
irreducible water saturation expected to be obtained for that
porous medium at the given column height present in the reservoir
above a free water contact (based on a conventional water-gas
capillary pressure drainage test). In situations where
exceptionally low matrix permeability is present in a gas-producing
reservoir, unless a sub-irreducibly saturated original condition is
present, the reservoir will exhibit insufficient initial
reserves/permeability to be a viable gas-producing candidate.
Therefore, Bennion, et al. (2000) believe that, with few
exceptions, the vast majority of ultra-low permeability gas
reservoirs that would be classified as exhibiting economic
gas-producing pay, would fall into this classification of
subnormally saturated systems. This phenomenon, they teach, gives
rise to one of the most severe potential damage mechanisms in low
permeability gas reservoirs: fluid retention or phase trapping.
[0015] Bennion, et al. (2000) then teach that "considerable
invasion, due to capillary suction effects, can occur when water
based fluids are in contact with the formation, even in the absence
of a significant overbalance pressure. A phenomena [sic] known as
countercurrent capillary imbibition has been well documented in the
literature in previous papers and studies by the authors . . . and
illustrates how a significant increase in water saturation in the
near wellbore or fracture face region can occur in such a
situation, even if underbalanced operations are being used when
water based fluids (including foams), are circulated in contact
with the formation face." They then propose that this problem can
be mitigated by not using water based fluids in drilling,
completion, and stimulation. If water based fluids must be used,
then they recommend minimizing the exposure time so as to minimize
the depth of water invasion. They then advise that "Capillary
pressure, which is the dominant variable controlling fluid
retention, is a direct linear function of interfacial tension
between the water and gas phase. If this interfacial tension can be
reduced between the invading water-based filtrate and the in-situ
reservoir gas, the magnitude of the capillary pressure and the
degree of observed fluid retention may also be lessened." and they
teach that "natural capillary imbibition will want to `wick` or
imbibe water from the high water saturation zone (encompassing the
original invaded area) deeper into the formation, resulting in a
`smearing` of the water saturation profile . . . . As long as a
recharge source of unbound water is removed from the wellbore or
fracture, this will obviously result in a gradual reduction in the
value of the trapped water saturation in the near wellbore or
fracture face region, which may result in a slow long term
improvement in the permeability to gas in the region which
previously exhibited near zero gas permeability." In other words,
Bennion, et al. (2000) advise that availability, let alone
injection, of water should be minimized, especially if the
interfacial tension has been lowered. This is the exact opposite of
the method of the present Invention.
[0016] Formulating drilling and completion fluids with high ionic
strength in order to use osmotic forces to dehydrate shales to
promote wellbore stability during drilling and completion
operations is well known. Recently, Mese et al., in US Patent
Application Publication No. 2008/0156484, taught injecting a high
ionic strength fluid into a wellbore drilled, for example, through
a shale or clayey sandstone containing a target fluid, and allowing
osmotic forces to extract pore fluid from the formation and lower
the pore pressure in the formation, where the target fluid is
released. They further taught injecting a high ionic strength
fluid, allowing osmotic forces to extract fluid from the formation,
applying a hydraulic pressure to fracture the formation, and
producing from the formation. They explained that using osmotic
pressure to dehydrate shales in combination with hydraulic
fracturing of a formation lowers the hydraulic fracturing threshold
pressure and/or creates microfractures. They further taught
rehydrating shales (using a second fluid having lower ionic
strength than the fluid used in the fracturing but higher ionic
strength than the formation fluid) to strengthen or "harden" them,
for example to allow microfractures to stay open, and to release
the fluid from the formation. In none of this was there a
suggestion of using osmotic (or hydraulic) pressure to move large
volumes of fluid deep into a formation.
[0017] Hinkel and England (U.S. Pat. No. 6,069,118) teach adjusting
the ionic strength of fracturing fluids to use osmotic pressure
gradients to cause flow of leaked-off fracture fluids from the
formation through fracture faces into the fracture, for the purpose
of removing stagnant fracture fluid from the reservoir, or flow of
fracture fluids from the fracture into the formation, for the
purpose of cleaning up fractures. (The latter is accomplished, for
example, by injecting a high salt brine before the fracturing
treatment or using a high salinity fracture fluid early in the
fracturing treatment and then in the later stages of the fracture
fluid using a lower salinity fracturing fluid.) The amount of fluid
moved from the formation to the fracture is no more than the amount
of fluid leaked off into the formation during the fracturing step;
the amount of fluid moved from the fracture to the formation is no
more than the fluid volume of the fracture. In fact, the amount of
fluid moved is determined by the equilibrium between the two
fluids. Again, there was no suggestion of using osmotic (or
hydraulic) pressure to move large volumes of fluid deep into a
formation.
[0018] We have found that osmotic pressure effects combined with
imbibition may be used to increase hydrocarbon production from
hydrocarbon reservoirs. This may be accomplished when any type of
wettability is present (oil-wet, water-wet, intermediate-wet, and
mixed wettability) We define a water-wet solid as having a contact
angle, measured through the water, of from 0 to about 70 degrees
when a drop of water is placed on the surface. A surface is
intermediate-wet when that angle is from about 70 to about 110
degrees; a surface is oil-wet when the angle is from about 110 to
180 degrees. A mixed wettability surface is defined as a surface
having regions of differing wettability. With suitable adjustments,
the method of the Invention may be applied to a formation of any
type of wettability. "Water" is defined as including fresh water
and water containing any dissolved materials, for example salt or
surfactant. In this application, the terms "Hydrocarbons" and "Oil"
are intended to be defined broadly as any type of hydrocarbon
material that is able to flow to the surface under achievable
subsurface conditions, including for example petroleum, gas,
kerogen, paraffins, asphaltenes, supercritical fluid, and
condensate. Osmotic pressure is the fluid pressure produced by a
solution that is separated from a solvent by a semipermeable
membrane, due to a differential in the concentrations of solute. A
semipermeable membrane, also termed a selectively-permeable
membrane (selectively permeable to the solvent (water) in
preference to the solute), a partially-permeable membrane or a
differentially-permeable membrane, is a membrane that will allow
certain molecules or ions to pass through it by diffusion. Thus,
water will spontaneously flow from a region of lower ionic strength
(salinity; solute concentration) to a region of higher ionic
strength. Lower ionic strength is also called higher potential (or
higher chemical potential) or higher activity, because the solvent
(water) flows from higher potential to lower potential. Osmosis is
an equilibrium process. The rate of passage depends on the
pressure, concentration, and temperature of the molecules or
solutes on either side, as well as on the permeability of the
membrane to each solute. Depending on the membrane and the solute,
permeability may depend on solute size, solubility, properties, or
chemistry. We will generally discuss aqueous systems. The pressure
that must be applied to the solution on the low activity side to
make the activity of water equal to the activity of water on the
high activity side is the osmotic pressure; if the pressure on the
low activity side is less than this pressure, then water will flow
from the high activity side, through the membrane, into the low
activity fluid by osmosis.
[0019] The "membrane" is the interface separating the higher and
lower activity fluids. Low-permeability shales, for instance, can
act as membranes (or at least imperfect membranes). Consider a
wellbore or fracture in a shale formation; water in the wellbore or
fracture diffuses through the shale interface and into the more
solute-rich shale pore fluid. The extent (equilibrium) of fluid
transfer is dependent upon the solute differential between the two
regions separated by the membrane. Fluid transfer in response to
the chemical potential gradient occurs until it is eventually
countered by the osmotic pressure--i.e., the pressure exerted
against the membrane by the fluid being diluted by solvent
transfer. Thus fluid transfer occurs until equilibrium is reached.
Moreover, the osmotic pressure is a function of the membrane's
efficiency. Thus, an imperfect membrane will sustain a lower
osmotic pressure since solvent and solute can readily migrate back
and forth across the membrane until equilibrium is reached.
Obviously, what is desired is to maximize fluid transfer, for
example from the fracture or wellbore across the membrane and into
the formation. As evidenced by this discussion, the skilled artisan
can now see that the greater the efficiency of the membrane (i.e.,
the more selectively permeable it is to solvent) the greater the
osmotic pressure it can sustain, and therefore the greater the
solvent transfer at equilibrium. Thus, it is highly desirable to
increase the efficiency of the membrane that exists in the
subterranean formation and that separates the wellbore or fracture
from the formation. Occasionally the formation comprises a
naturally good membrane, for instance, a low-permeability shale is
an effective membrane, which may not require any artificially
established membrane in order to execute the method of the present
Invention; optionally an artificial membrane may be superimposed on
the natural membrane to enhance its effectiveness. Typically, a
sandstone is not a suitable intrinsic membrane. In those instances
where the formation does not provide a sufficient membrane, one
must be artificially created to maximize fluid removal according to
the present Invention.
[0020] Methods of creating subterranean semipermeable membranes are
discussed in U.S. Pat. No. 6,069,118, hereby incorporated by
reference in its entirety. The list of possible materials that can
form a semipermeable membrane suitable for the present Invention is
long. The person skilled in the art of semipermeable membrane
chemistry, working in concert with one skilled in the art of
reservoir engineering can select suitable candidates for the
semipermeable membrane material by following the general guidance
provided in the present Specification, by following the teachings
in the art, and by following certain specific guidelines. The
following references are helpful in this regard and are hereby
incorporated by reference: H. P. Gregor and C. D. Gregor,
"Synthetic-Membrane Technology," 239, Scientific American, 112
(1978); R. Durbin, "Osmotic Flow and Water Across Permeable
Cellulose Membranes," 44 J. General Physiol., 315 (1960). U.S. Pat.
No. 7,398,829, hereby incorporated by reference in its entirety,
discloses the use of water inert polymers, for example emulsion
polymers and latex polymers, to form a film on fracture surfaces;
such films may be useful as semipermeable membranes. Preferred
semipermeable membranes of the present Invention should possess the
following attributes. First, the semipermeable membrane must be
water-wettable. Second, the semipermeable membrane material, once
in place, should comprise pore spaces of sufficient size to yield
acceptable osmotic pressures. Naturally, the semipermeable membrane
should be easy and cost-effective to establish. Numerous more
specific considerations, known to the one skilled in the arts to
which this Invention is directed, will direct the engineer or well
operator to the optimal semipermeable membrane candidate. For
instance, in the brine stages of a treatment, conventional polymers
may not be suitable due to their tendency to destabilize at high
temperatures in the presence of brine.
[0021] Again, the formation itself may, in some instances, provide
an intrinsic membrane--without the need to establish one
artificially. In other instances, a suitable membrane may exist,
having been established during another step in the fracturing
process--e.g., lining the fracture faces with filter cake to
prevent leak-off of the fracture-inducing fluid.
[0022] If one desires to establish a selectively permeable membrane
suitable to practice the present Invention, then it can be done,
for instance, by injecting into a wellbore or into a fracture, a
membrane-forming material (for example, a conventional fluid-loss
additive). This membrane-forming material forms a membrane layer at
the appropriate interface, thus ideally sealing in the solute-rich
solution-containing formation. The ideal membrane is one that is
freely permeable to water, but impermeable to all solutes. Again,
creating this membrane may comprise a separate step--i.e., it may
not be an intrinsic part of the drilling, completion, or
stimulation process--or a coating placed on the formation from a
prior injecting step may be further utilized as the membrane of the
present Invention. For instance, a "filter cake," comprised of, for
instance, a dewatered guar gum, is often deliberately established
on the formation face of a wellbore or fracture. The purpose of
this filter cake is to prevent leak-off, or loss of drilling or
fracturing fluid into the formation. A filter cake may also be
created (generally unintentionally) when a guar gum solution
carrying proppant is delivered into a fracture and the gum sticks
to the formation and dewaters, forming a filter cake. The filter
cake diverts the fluid's flow path so that instead of leaking off
from the hydraulic fracture laterally into the formation, it
continues to move down the hydraulic fracture and thus extending
deeper into the formation. The process would be exactly the same
for any additional fractures created by branching off from the main
hydraulic or additionally in the case where multiple hydraulic
fractures are propagated simultaneously. The point is that this
filter cake can then be used as the selectively permeable membrane
of the present Invention. Thus, it may be desirable to manipulate
the composition of the material used to create the filter cake so
that it forms a membrane suitable for the present Invention.
[0023] Numerous materials may be used to establish the membrane of
the present Invention. Several membrane compositions suitable upon
modification for use in accordance with the present Invention
include those disclosed in U.S. Pat. Nos. 5,041,225, and 4,851,394.
In particular, the '394 patent discloses membranes comprised of
polyhydroxy compounds. Both of these patents are hereby
incorporated by reference in their entirety. Galactomannans
crosslinked with boric acid, and cellulose acetate (commonly used
in dialysis) can also form membranes suitable for use in the
present Invention. Many suitable semipermeable membrane materials
are associated with the medical industry. For reverse osmosis and
other applications, the use of Thin Film Composite Membranes (TFC
or TFM) is common. Essentially, a TFC material is a molecular sieve
constructed in the form of a film from two or more layered
materials. Membranes used in reverse osmosis are typically made out
of polyamide, chosen primarily for its permeability to water and
relative impermeability to various dissolved impurities including
salt ions and other small, unfilterable molecules. One example of a
reverse osmosis membrane is made from cellulose acetate as an
integrally skinned asymmetric semipermeable membrane. This membrane
was made by Loeb and Sourirajan at UCLA in 1959 and is described in
U.S. Pat. Nos. 3,133,132 and 3,133,137, both of which are hereby
incorporated by reference in their entirety. Another example of
reverse osmosis (RO) membrane materials is based on a composite
material described in U.S. Pat. No. 3,551,331, hereby incorporated
by reference in its entirety. FilmTec's FT30.TM. membrane is known
as a polyamide thin film composite membrane. As is suggested by the
name, such TFC membranes are composed of multiple layers, for
example a polyamide layered with a polysulfone as an interlayer and
a polyester as a porous support layer. It is the aromatic or mixed
aromatic, aliphatic polyamide that may be used to form the
semipermeable membrane of the present Invention. Other materials,
usually zeolites, are also used in the manufacture of TFC
membranes.
[0024] In one preferred embodiment of the present Invention, the
membrane is comprised of polyhydroxy compounds; in one particularly
preferred embodiment, it is comprised of polyethylene glycol (PEG).
Other hydroxylated polymers, for example polypropylene glycol
(PPG), and PEG-PPG block copolymers, may be used. Other types of
materials are also particularly suitable: e.g., colloids, polymers,
aluminosilicates and mixtures of aluminosilicates and fatty acid,
starch, and silica flower. Methyl glucoside (methyl-glucopyranose)
which can be formed by reacting methanol with the anomeric hydroxyl
on glucose, and other similar classes of materials may also be
used. A copper hexacyanoferrate membrane may be formed either by
sequential injection of solutions, or by the injection of one
solution followed by the diffusion of the solute from a second
solution. Copper sulfate and potassium ferrocyanide are known to
react on contact to form a copper hexacyanoferrate membrane. In
addition, silicates may form membranes suitable for the present
Invention. More particularly, clays, such as bentonite, are
preferred embodiments of the present Invention.
[0025] The following non-limiting list of additives, if applied
correctly, may increase the efficiency of a semipermeable membrane
formed on the face of a formation, for example a shale formation:
electrolytes, phenols, tetra methylammonium laurate, tetra
methylammonium oleate, silicic acid, potassium methyl siliconate,
sodium methyl siliconate, biopolymers, hydroxyethyl cellulose,
sodium carboxylmethyl-hydroxethyl cellulose, synthetics such as
polyethylene amines, copolymers of 2-acrylamide-2-methyl propane
sulfonic acid and N-vinyl-N-methyl acetamide, HALAD-344 (a random
copolymer of 2-acrylamide-2-propane sulfonic acid and N,N-dimethyl
acrylamide), HALAD-413 (a caustized lignite grafted with
2-acryamide-2-methylsulfonic acid, N,N-dimethylacrylamide, and
acrylamide), latexes such as polyvinylalochol and styrene
butadiene, and silicate compounds such as sodium silicate and
potassium silicate.
[0026] Whenever two or more fluids co-exist in a system of pores
(capillaries), the combination of surface tension and curvature due
to the capillaries causes the two phases to experience different
pressures. As the relative saturations of the phases change, it has
been found that these pressure differences also change. The
difference between the pressures of any two phases is referred to
as the capillary pressure. We define the capillary pressure, for
example in the pores of a formation, as the difference in pressure
across the interface between two immiscible fluids:
p.sub.c=p.sub.non-wetting phase-p.sub.wetting phase.
[0027] In oil-water systems or oil-gas systems, either the water or
the hydrocarbon may be the wetting phase; for gas-oil systems, oil
is the wetting phase. The Young-Laplace equation states that the
pressure difference is proportional to the surface tension, y, and
to the cosine of the wetting angle, .theta., of the liquid on the
surface, and inversely proportional to the effective radius, r, of
the interface (for example a formation pore throat):
p c = 2 .gamma. cos .theta. r ##EQU00001##
[0028] This equation for capillary pressure is actually valid only
under capillary equilibrium, in the absence of flowing phases. The
capillary pressure as defined here is the maximum driving force for
fluid flow. During flow, both the contact angle--advancing--and the
effective radius may change. The radius of curvature of the
interface is greatest when the length of the `suspended` column
reaches its maximum. Clearly, in a subterranean formation, the
capillary pressures may be altered by changing the interfacial
tension between the fluid phases and the wettability of the
surface. Typically in the practice of the Invention, these
parameters are used to maximize the imbibition of the injected
water; this is done, for example, by increasing the water-wetting
properties of the formation and/or by lowering the
hydrocarbon/water interfacial tension. It may be found in some
cases that lowering the interfacial tension may maximize the
ultimate hydrocarbon recovery but lower the imbibition rate.
Enhancing water imbibition by adding water-wetting agents and/or by
adding water/oil interfacial tension lowering agents has been
proposed (see U.S. Pat. No. 5,411,086) for use in driving water
from injection wells to production wells for enhanced oil recovery
in diatomaceous reservoirs. That patent taught that "Some oil or
hydrocarbonaceous fluids will be displaced by counter current
imbibition into fractures communicating with the injection well or
wells. For this reason it is preferred that the injector well or
wells occasionally be placed on production to produce additional
oil or hydrocarbonaceous fluids from the diatomaceous formation or
reservoirs."
[0029] Capillary pressure affects imbibition and drainage. It is
the hysteresis effect during the cycles of drainage and imbibition
that impacts the capillary pressure. Primarily this phenomenon is a
result of the changing wettability in the system. The higher the
saturation of the wetting fluid, the lower the capillary pressure.
In real porous media the changes mean that some fluid advancing via
imbibition cannot then be displaced by drainage, which results in
phase trapping. In other words, the capillary pressure can vary
during drainage and imbibition; this variation accounts for the
observed hysteresis. The hysteresis results from differences
between the advancing (imbibition) and receding (drainage) contact
angles. The relative values of the contact angles are:
Advancing>Receding>Static.
[0030] The saturation changes capillary pressure, with increasing
wetting fluid saturation always leading to lower capillary
pressure. An easy way to envision this is to consider the common
capillary rise experiment. At the beginning of the experiment the
capillary is empty (zero wetting fluid saturation) and the
capillary pressure is at its highest. At equilibrium, i.e. maximum
rise, the capillary pressure has fallen to zero and the capillary
has reached its maximum wetting fluid saturation. The concept is
best illustrated by the following expression for capillary
pressure:
P.sub.c=.rho.g(h-z)
in which z represents the height of the column at any instant
during filling, and h represents the maximum height (equilibrium).
(This assumes that the contact angle is 0 degrees and that the
capillary is vertical.) Fractional saturation can be stated as z/h.
Phase trapping can best be explained by referring to the Jamin
effect. (See, for example, R. Cosse, "Basics of Reservoir
Engineering", Gulf Publishing Company, Houston, Tex. (1993), p.
180.) Displacement of the non-wetting phase can be stopped when a
blob reaches a small pore. Surfactants will reduce phase trapping.
In the present Invention, the fluid movement is controlled by
selecting the proper surfactants to take advantage of these
processes, or to mitigate the negative effects, in order to
maximize hydrocarbon production and/or ultimate recovery.
[0031] Non-limiting examples of agents that lower hydrocarbon/water
interfacial tension are those surfactants used in enhanced oil
recovery by surfactant flooding; they are well known and include
sulfonates, ammonium salts of linear alcohols, ethoxy sulfates,
calcium phenol ethoxylated alkyl sulfonates, and mixtures of these
materials. Particularly suitable agents are carboxylates,
ethoxylates, ethoxylated alcohols, alkyl ethoxylated alcohols,
nonyl phenol ethoxylated alcohols, sulfonates, alpha olefin
sulfonates, alkyl benzyl sulfonates, sulfonic acids, sulfates,
ethoxylated sulfates, phosphates and phosphate esters of vegetable
oils containing polyunsaturated fatty acid ester groups in the
triglyceride molecules, such as soybean, cottonseed, corn,
safflower, and sunflower oils. The effects of these materials may
be enhanced by the use of co-surfactants and suitable electrolyte
concentrations. Caustic, such as sodium or potassium hydroxide, may
be used to form natural surfactants by reaction with organic acids
if oil is present.
[0032] Non-limiting examples of agents that increase water-wetting
of formations include mono-, di-, and tri-basic forms of sodium or
potassium phosphate, sodium silicate, oxyalkylated alkyl phenols
and sulfates, fluorocarbons, alkyl di-methyl amine oxides, and
other amine oxides. It should be noted that surfactants may be
generated in situ, for example by the action of acids on petroleum
components.
[0033] Non-limiting examples of agents that increase
hydrocarbon-wetting of formations include lecithin; organic
surfactant compounds having the formula R1-(EOx-PrOy-BuOz)H wherein
R1 is an alcohol, phenol or phenol derivative or a fatty acid
having 1 to 16 carbon atoms, EO is an ethylene oxide group and x is
1 to 20, PrO is a propylene oxide group and y is 0 to 15, and BuO
is a butylene oxide group and z is 1 to 15; an organic polyethylene
carbonate having the formula R2-(--CH2-CH2-O--C(O)--O--)qH wherein
R2 is an alcohol having 7 to 16 carbon atoms and q is 7 to 16;
butoxylated glycols having 1 to 15 butylene oxide groups;
ethoxylated-butoxylated glycols having 1 to 5 ethylene oxide groups
and 5 to 10 butylene oxide groups; and alkyl-aminocarboxylic acids
or carboxylates. In general, a strong cationic surfactant is
appropriate to oil-wet sandstone and a strong anionic surfactant is
appropriate to oil-wet carbonate.
[0034] The use of osmotic forces to transport large volumes of
fluid from a wellbore to the producing formation may be done with
or without hydraulic fracturing (fracture-stimulated, stimulated,
etc.), depending primarily upon the overall permeability of the
formation. If satisfactory volumes and rates of injection and
production cannot otherwise be achieved, the well is
fracture-stimulated. Fracturing may be accomplished by hydraulic
fracturing with any kind of fluid (water-based, acid-based,
oil-based, gaseous, energized, foamed, crosslinked polymer,
non-crosslinked polymer, viscoelastic surfactant, other
non-polymeric viscosifier, friction reducer, straight water, etc.).
Fracturing may also be accomplished by the use of osmotic forces
themselves (in which the osmotic pressure is higher than the
formation fracturing pressure; this is particularly desirable when
it occurs along the face of a very long hydraulic fracture already
extended or dynamically extending into the reservoir. Especially in
low permeability, high salinity, shaley formations (in which
capillary pressures can be high because of low pore radii of
curvature, formation chemical potentials are low, and the formation
is an effective semipermeable membrane) osmotic pressures can be
created that are greater than the pressure required to fracture the
reservoir. This generally results in many microfractures being
created where the higher chemical potential fluid contacts the
formation. This is achieved by injecting into the wellbore, and/or
into a hydraulic fracture, a fluid having a higher chemical
potential (lower ionic strength) than the fluid that it will
contact across a semipermeable membrane. The microfractures
increase the surface available for imbibition. Osmotic forces may
also be used in conjunction with well treatments involving
explosives, propellants, perforating, hydrojetting, thermal
fracturing, and other techniques. Osmotic forces may also be
utilized whenever fracturing or any other methods are used to
create a connection between existing disconnected or partially
disconnected natural fractures in the formation and a wellbore.
[0035] Once it has been determined that adequate flow rates to and
from the wellbore and the reservoir are possible, large volumes of
fluid are injected so that they penetrate deep into the formation.
By deep into the formation we mean that the fluid contacts a
significant portion of the producing wellbore drainage volume, also
known as the "practical" wellbore drainage volume of the well, for
example at least one quarter of the practical wellbore drainage
volume, or in another example at least one half of the practical
wellbore drainage volume. By "practical" wellbore drainage volume,
we mean the wellbore drainage volume the operator intends to drain
over the lifetime of the well via the well, any hydraulic fractures
and any natural fractures in fluid communication with the well.
This drainage area is estimated with current geophysical,
petrophysical, etc. information and well production performance
data available at the time based on standard reservoir engineering
practice. It should be understood that with additional information
over time, the expected drainage area of a wellbore may be changed
accordingly. The drainage area of a well is not to be confused or
associated with the current well spacing as this spacing is
regulated by various regional (for example county, parish, state,
or federal authorities) and is also subject to change over time as
better information on the reservoir and well production behavior
becomes available. The minimal volume injected into a hydraulically
fractured system is preferably the volume of the hydraulic fracture
plus the volume of any natural fractures contacted plus the volume
leaked off during the hydraulic fracturing treatment.) This contact
does not necessarily occur in the first injection cycle, or even
the first few injection cycles of a treatment, but preferably
occurs by the end of the treatment. The most desirable result is to
impact all of the practical wellbore drainage volume of every
hydraulic fracture that extends from a wellbore into the reservoir.
In sufficiently permeable reservoirs, no hydraulic fractures are
likely needed but on occasion may be utilized as individual
situations warrant. In very low permeability reservoirs, it may be
necessary to fracture-stimulate, treat the practical wellbore
drainage volume by the method of the Invention, refracture on a
different azimuth, treat, refracture, etc. Often, only a single
hydraulic fracture is created during an individual treatment. The
length of the hydraulic fractures created is dependent on all of
the geomechanical factors of the reservoir itself along with the
limitations imposed by the wellbore configuration and construction,
the surface pumping equipment and other logistical aspects. In the
optimal case, the operator determines what the potential practical
wellbore drainage area could be for a given well. The operator then
creates fractures and injects fluid so that all of the practical
wellbore drainage area is reached by the injected fluid. This is in
contrast to other methods in which fluids that have higher
potential than formation fluids may be injected for other reasons;
such fluids do not contact a substantial portion of the practical
wellbore drainage area of the well. Optionally, diverting materials
are used in the fracturing process in order to create hydraulic
fracture branches off of the main fracture in order to expose more
reservoir surface area. The goals may also be achieved on existing
wells by going back in and performing a refracturing treatment or
treatments. The ultimate aim is to increase the hydrocarbon
production rate and/or ultimate recovery from each wellbore and to
optimize overall reservoir development.
[0036] The fluid to be injected is designed (after suitable
analysis of the formation rock and fluid properties, if possible,
or by analogy to similar wells or reservoirs) to alter the pore
pressures in the formation by osmosis in order to aid in
hydrocarbon production by imbibition. Production of hydrocarbon in
low permeability formations by imbibition is described, for
instance, in commonly-assigned and simultaneously-filed U.S. patent
application Ser. No. 12/253,406, entitled "Enhancing Hydrocarbon
Recovery" incorporated by reference above. However, imbibition
alone may not be capable of producing economical rates and/or
volumes of hydrocarbon in some reservoirs. The proper fluid
selection, for osmosis to aid imbibition in the present Invention,
depends upon the formation wettability and the wetting and
non-wetting phase saturations and activities. In one embodiment, if
the rock is water-wet, osmosis may be used to aid recovery by
increasing the pore pressure in the pores containing water such
that this pressure may be transmitted to adjacent pores containing
the non-wetting fluid (the hydrocarbons). On the other hand, if the
reservoir is hydrocarbon-wet (by non-limiting example kerogenic and
heavy oil reservoirs) then osmotic forces may be used to cause an
increase in non-wetting fluid saturation, resulting in an increase
in the pressure in the water-containing pores. Finally, if the rock
is above its irreducible oil saturation, then even injection of a
fluid having the same chemical potential as the formation fluid
will cause an increase in capillary pressure and so will allow
hydrocarbon to flow to the well by imbibition. Furthermore, if the
fluid also contains a wetting agent, such as a surfactant, the
wetting agent will be moved into capillaries containing non-wetting
fluid both by hydraulic and saturation gradients, and aid any of
the above processes by reducing phase trapping.
[0037] The method of the Invention takes advantage of the forces
which dominate fluid movement within the reservoir. Under some
conditions there may be limitations as to how much advantage is
possible, but knowing the details of the reservoir and the initial
conditions, the treatment fluid may be formulated, designed and
pumped as necessary. In a mixed-wettability reservoir, the same
approach as has already been described may be taken. Since the
method of the Invention uses aqueous fluids, both osmosis and
imbibition forces may be taken advantage of when the reservoir is
primarily water-wet. In oil-wet reservoirs, osmosis will likely be
the greatest contributor to success. For mixed-wet reservoirs, the
operator may use both osmosis and imbibition. In other words,
osmotic processes may be used to manipulate events in the reservoir
to aid hydrocarbon recovery. Reservoir characterization determines
how the method of the Invention is best carried out. In the case of
a oil-wet reservoir, imbibition using an aqueous fluid may be less
effective, but the pore pressure in the hydrocarbon-filled pores
may be increased by osmotic action in adjacent water-wet pores, and
this facilitates hydrocarbon recovery. In other words, proper
manipulation of the osmotic pressure may be an aid to imbibition in
either water-wet or oil-wet reservoirs, or it may be used alone in
cases where imbibition might not be effective or feasible.
[0038] Particularly suitable agents for controlling the ionic
strength (raising or lowering the chemical potential or the
activity) of water include formates, such as cesium formate,
potassium formate, sodium formate, ethyl formate, methyl formate,
methyl chloro formate, triethyl ortho formate, trimethyl ortho
formate, and the like. Other particularly suitable agents for use
in the inventive method include salts that are commonly used to add
salinity and/or density to drilling, completion, and stimulation
fluids, for example, but not limited to ammonium chloride, calcium
bromide, calcium chloride, potassium chloride, potassium bromide,
sodium bromide, sodium chloride, zinc bromide, zinc chloride,
calcium nitrate, and blends of these salts. Other suitable
materials include magnesium chloride and sugars. Any soluble
substance may be used that alters the ionic potential of the
solution. Incompatibility with formation rock or formation fluid
should not be a problem, because invasion of the agents into the
formation is not intended. The fluid injected may contain any of
the typical oilfield fluid additives, as appropriate, for example
biocides, and friction reducing agents such as polyacrylamides.
Compatibility with formation rocks, formation fluids, and any other
fluids to be used should be checked in the laboratory as usual.
[0039] The method of the Invention is particularly applicable in
reservoirs in which fluids are likely to be trapped in the pores.
If either the wetting phase or the non-wetting phase, either water
or hydrocarbon, is trapped, this may inhibit the desired flow of
hydrocarbon to the well during production. For example,
particularly in a water-wet reservoir, trapped water may block the
flow of hydrocarbon. Obviously, under any conditions, trapped
hydrocarbon is undesirable.
[0040] The steps normally followed in the use of osmotic pressure
to assist imbibition in hydrocarbon production include the
following. Not every step may be needed in every treatment, and
additional steps may be included in some treatments as necessary as
would be understood by one skilled in the art. This description
does not include hydraulic fracturing, which may be done before,
during (at any point), or after the following: [0041] 1.
Characterize the Reservoir [0042] 2. Select the Injection Fluid
Major Component(s) [0043] 3. Formulate the Injection Fluid [0044]
4. Test Formation Fluid and Rock Compatibility (and other tests as
necessary) [0045] 5. Design the Job [0046] 6. Determine the Need to
Create or Improve an Existing Semipermeable Membrane in the
Reservoir and Optionally Create or Improve the membrane [0047] 7.
Inject Fluid [0048] 8. Optional Shut-In [0049] 9. Produce Fluid
[0050] 10. Repeat Steps 7 through 9 [0051] 11. Optionally Repeat
Any of Steps 1-6 and then 7-9 (or then 9 and then 7-9)
[0052] The individual steps may include the following procedures:
[0053] 1. Characterize the Reservoir: This is typically done from
information already available, or obtained for the purpose, from
adjacent wells in the reservoir, for example from analysis and
interpretation of data from well logs and histories, formation
cores, and fluid samples. If no such data are available, inferences
from reservoirs believed to be similar may be used, but this may
not be as satisfactory. It is recommended that data from the wells
to be treated, or from adjacent wells, be obtained and used if
possible. [0054] 2. Select the Injection Fluid Major Component(s):
The major components of the fluid, as defined here, are those that
would most effectively affect the osmotic and capillary pressures.
These include potentially major contributors to ionic strength
(such as buffers; pH adjusters; and clay stabilizers), and
surfactants (such as emulsifiers; demulsifiers; foaming agents; and
anti-foaming agents; and agents specifically chosen for their
ability to affect formation wettability and/or interfacial
tension). Other materials that may be incorporated in the fluid but
are less likely to have a major affect on osmotic and capillary
pressures include biocides; oxygen scavengers; antioxidants; iron
control agents; and corrosion inhibitors. The major components may
be selected through the use of laboratory tests, such as
wettability, sorption, and imbibition, on cores, preferably using
cores and formation fluids from wells to be treated. Suitability of
a fluid for providing the benefits of osmosis for increasing
hydrocarbon recovery may be tested and confirmed in the laboratory
with an imbibition test using a core having one end open and all
other surfaces sealed. Any other fluid components should be tested
to ensure that they are compatible with the major fluid components.
If laboratory tests are not feasible, or if the reservoir is well
characterized and candidate injection fluids are well known,
correlations may be used. Compatibilities must always be taken into
account; for example, some components, such as some surfactants,
may sorb onto formation surfaces. [0055] 3. Formulate the Injection
Fluid: In conjunction with selection of major components, the base
fluid is identified. This may be fresh water, formation water,
creek water, municipal water, or another water, and may be dictated
by availability or cost. (It is unlikely that the base fluid is sea
water or a brine, because the injection water normally must have
lower activity than the formation water.) Typically, the amounts of
major components to be added are then determined, followed by the
amounts of other components. In formulating the fluid, care must
taken to avoid harmful interactions of the injection fluid with the
formation or formation fluids. For example, if core analyses or
information on the formation in adjacent or similar wells or
reservoirs indicates that the formation to be treated may contain
fresh-water-sensitive clays or zeolites or clays that could be
destabilized, then the injection fluid should be formulated
accordingly. Similarly, if formation fluid analysis, or information
on the fluids from adjacent or similar wells or reservoirs,
indicates the possibility of precipitation of scales, asphaltenes,
paraffins, or other materials, then the injection fluid should be
formulated to minimize these possibilities. Those skilled in the
art will know how to minimize such fluid-formation and fluid-fluid
interactions. [0056] 4. Test Formation Fluid and Rock Compatibility
(and other tests as necessary) and make any adjustments in the
injection fluid formulation if required. [0057] 5. Design the Job:
This involves primarily the determination of the optimal rate and
volume of fluid to be injected in each cycle before the well is put
on production. The rate and volume are generally economic
considerations, provided that the volume does not exceed that
sufficient to fill the expected drainage area of the well. Models
may be used to calculate, predict and optimize the job design and
results. The rate and volume may be affected by the pumping
horsepower available, fluid formulation equipment limitations,
chemical availabilities, hydrocarbon gathering, storage, and
shipment capabilities, and other factors. Fluid injection rate and
volume are not believed to be major factors in hydrocarbon
recovery. Hydrocarbon production may be stopped, and another
injection stage begun, when hydrocarbon recovery rates becomes
unacceptably low; on the other hand, it is believed that the switch
from production to injection may be made before it is economically
necessary without deleteriously affecting the ultimate recovery. At
this time, also, ensure that the zone to be treated is properly
isolated, using packers, diverting agents, etc., as is well known
to those of skill in the art. [0058] 6. Determine the Need to
Create or Improve an Existing Semipermeable Membrane in the
Reservoir and Optionally Create or Improve the membrane: If the
characterization, testing, and/or correlations done above indicate
that it is necessary or economically warranted, a semipermeable
membrane may be created or enhanced by the injection of a fluid
containing suitable chemicals, as described elsewhere in this
specification. Of course, care must be taken to avoid a deleterious
reduction in permeability. [0059] 7. Inject Fluid: The initial job
design may be altered, either during the first injection cycle, or
more especially in subsequent cycles. Note that if fluid is being
pumped to improve or create a semipermeable membrane, this may be
done in a number of ways. 1) An initial (separate from the main
imbibition/osmosis treating fluid) treatment may be pumped to
improve or create the semipermeable membrane. There may be a
shut-in period required in order for the membrane to reach its best
condition. 2) The semipermeable membrane forming fluid may be
pumped and immediately followed by the imbibition/osmosis fluid
(optionally separated by a spacer fluid). 3) It is possible,
although less preferred, that the semipermeable membrane fluid and
the imbibition/osmosis fluid be pumped together as a single stage.
Also, the fluids may be pumped as single stage sequences,
alternating sequences, etc. in order to contact as much of the
reservoir as possible. [0060] 8. Optional Shut-In: Whether or not a
shut-in period is needed, or beneficial if not needed, depends on
the reservoir characterization and an estimation of the rate at
which the processes reach an equilibrium or optimum. Shutting in
the well, or wells, to allow the processes to progress, will almost
always be beneficial, since all the processes of the method take
time. The method may be carried out in stages, for example inject,
shut-in, sweep, inject, shut-in, sweep, etc. [0061] 9. Produce
Fluid: Production in each cycle is generally continued as long as
economically warranted. Optimal producing conditions may be
estimated by numerical modeling (reservoir simulation). Cycle times
are generally long enough to allow installation of a pump for
artificial lift. A lot of the artificial lift equipment may
optionally remain in place during the injection cycles. [0062] 10.
Optionally Repeat Steps 7 through 9: Normally a number of
injection/production cycles will be repeated as long as the
economics warrants. [0063] 11. Optionally Repeat Any of Steps 1-6
and then 7-9 (or then 9 and then 7-9): Typically, the job is
closely monitored, especially pressure during the injection
cycles(s) and pressure and fluid composition during the production
cycle(s). The use of evaluation technology would be very beneficial
in these cases. For example, microseismic monitoring may be used to
determine hydraulic fracture behavior in real-time. It may also be
warranted to use permanent downhole monitoring (this may be in
specific wells used only for monitoring or in the production wells
themselves) to gauge the overall reservoir behavior. Other
techniques may also be used, such as tagging fluids with chemical
tracers to monitor during flowback to estimate efficiency (first
in, first out) and overall zonal coverage. If performance is
unsatisfactory or unexpected, or if additional information becomes
available (for example core, fluid, and/or performance data from
one or more adjacent wells) any or all of the first 5 steps may be
repeated.
[0064] The method of the Invention may be applied in formations of
any permeability, but if production is economically unsatisfactory,
or expected to be, then a well or wells may optionally be
hydraulically fractured or otherwise stimulated before, during or
after the above procedure. An operator may utilize an existing
hydraulic fracture proppant-pack as the conduit to deliver the
treatment of the Invention to the reservoir. Most commonly, an
operator uses the method of the Invention during, or as a part of,
a hydraulic fracture stimulation process. The method may also be
applied to wells that have already been fracture-stimulated, in
which case the treatment is a re-frac. A decision to hydraulically
fracture may be made during any step. If a well is then
hydraulically fractured, as many of the original steps as possible
should then be repeated. The fracture treatment and subsequent
injection/production cycles of the Invention must be carefully
designed to ensure that effects of the fracture fluid (and pad)
components have been accounted for. For example, the viscosifier
(polymer or viscoelastic surfactant or other non-polymeric
viscosifier such as a vesicle former) may significantly alter
capillary pressures and osmotic effects; fluid loss control agents
could affect the semipermeable membrane; and clay stabilizers could
affect osmotic forces. On the other hand, flowback after hydraulic
fracturing may not be appropriate, and water that flows into the
formation during the fracturing may be beneficial.
[0065] The methods of the Invention may be used in cased or
open-hole wells.
[0066] The methods of the Invention have been described thus far
primarily for a single well. Typically, however, the methods of the
Invention may be performed using more than one well in a field
and/or to more than one formation location accessible using a
particular wellbore. In this way, the inventive method may be
performed in different places in the formation. These different
places can include two or more locations in different
dual-laterals, multiple-laterals, multiple wellbore branches (such
as sidetracks, multiple-laterals located in different vertical
layers of the same geologic reservoir, multiple-laterals located in
different vertical layers covering one or more different geologic
reservoirs, etc.) from the main wellbore, injecting fluids into two
or more separate wellbores (wells) for the purpose of improving
injection coverage, etc. Many formations consist of multiple
layers. Performing the inventive method in different places in the
formation may include performing the inventive method in the same
and/or in different layers of the formation and, as noted
immediately above, these places may accessed from the same wellbore
or from different wellbores. Any well pattern may be used. Having
some wells on injection and some on production at any one time
normally optimizes use of people and equipment. Normally, although
hydrocarbons flow toward the production well during the injection
stage, they might or might not reach the well. If they reach the
production well, injection may be stopped and production begun. The
operator may monitor produced fluid for trace components of the
treatment fluid or other materials (tagging agents) that may have
been added to the treatment fluid for identification purposes. It
is also possible to infer injector influence on producers by
monitoring the reservoir pressure changes. It is common to model
the reservoir numerically and match the pressure behavior by
adjusting the influence of the injectors on the producers.
[0067] Another option is suitable and falls within the scope of the
Invention. Hydrocarbon released from the formation pores may be
produced from another well under certain circumstances. For
example, if an injection/production well is a first horizontal well
in a formation, at least some of the released hydrocarbon may flow
due to buoyancy to a second producing horizontal well in the same
formation, i.e. dual-lateral wells with one of the horizontal
wellbores above the other. Optionally, the second well may also be
an injection/production well with the cycles of the two wells
coordinated by monitoring tracers or hydrocarbons, as the fluid
sweeps the reservoir. In another embodiment, the first
injection/production well penetrates a non-horizontal formation
layer at a lower point and the second production (or
injection/production) well penetrates the formation at a higher
point. In this case one of the wells is higher on the geological
structure. In these cases gravity effects play a larger role in the
overall process. As mentioned before, this is taken into account
with the numerical models to determine which injection and
production conditions are optimal for increasing the rate and/or
ultimate cumulative hydrocarbon production from the reservoir. All
of this may be modeled by one of skill in the art using fluid
compositions (viscosities and densities), flow rates, water and
gas/oil saturations, etc., optionally using any oilfield diagnostic
evaluation techniques (such as chemical tracers, radioactive
tracers, microseismic monitoring, permanent downhole monitoring
systems, etc.).
[0068] While the Invention is described through the above exemplary
embodiments, it will be understood by those of ordinary skill in
the art that modification to and variation of the illustrated
embodiments may be made without departing from the inventive
concepts herein disclosed. Moreover, while the preferred
embodiments are described in connection with various illustrative
structures, one skilled in the art will recognize that the system
may be embodied using a variety of specific structures.
Accordingly, the Invention should not be viewed as limited except
by the scope and spirit of the appended claims.
* * * * *