Note: Descriptions are shown in the official language in which they were submitted.
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Targeted Oriented Fracture Placement Using Two Adiacent Wells
in Subterranean Porous Formations
Field of the Invention
The present invention relates to a method of inducing targeted oriented
fractures connecting
two wells drilled in subterranean porous formations whether or not the
connection of the two wells is
oriented perpendicular to the in-situ minimum stress.
Background
In many Earth engineering applications, wells are drilled into subterranean
porous formations. It
is desirable to create a fracture connecting two neighboring wells. In
general, the fracture follows the
plane perpendicular to the least resistance, i.e., perpendicular to the
original in-situ minimum stress,
Smin. Thus, normally, the two wells need to be drilled so that the line
connecting them is aligned
perpendicular to Smin. Otherwise, if the two wells are drilled substantially
deviated from the preferred
direction, a fracture may not be formed to connect the two wells.
In Canada and many parts of the world, petrochemicals are found in heavy,
viscous forms such as
bitumen, which are difficult to extract. The bitumen-saturated oilsands
reservoirs of Canada, Venezuela
and California are just some examples of such subterranean formations. In
these formations, it is not
possible to simply drill wells and pump out the oil. Instead, the reservoirs
are heated or otherwise
stimulated to reduce viscosity and promote extraction.
The two most common and commercially-proven methods of stimulating oilsands
reservoirs are
(a) cyclic steam stimulation (CSS) and (b) steam assisted gravity drainage
(SAGO). In both cases, steam is
injected into the reservoir, to heat up the bitumen. Some variations of these
processes may involve
injecting solvent to aid the viscosity reduction or use electrical heating to
replace the role of steam.
In general, the initial injectivity into the reservoir, i.e., how much volume
of the stimulant can be
injected per unit of time, is relatively small. Fracturing of the reservoir is
desired to provide channels for
the stimulant travel and to access the reservoir. The fracture not only
increases the injectivity, but also
increases the contact area of the stimulant within the reservoir. For example,
in CSS, the injection
pressure goes above the reservoir's fracture pressure with the goal to form
the fracture. It is desirable to
be able to control the orientation, depth and length of fractures in the
reservoir, in order to more
effectively place stimulant in the targeted location, extent and/or time, all
of which can help maximize
petroleum extraction.
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In the SAGD process, before the production can start, communication between
the SAGD well
pair must be established so that the bitumen can flow down to the production
well. Conventionally,
steam is circulated through the said two wells independently until the inter-
well area is heated and the
bitumen viscosity is reduced significantly so that it can flow to the
production well and communication is
established. This process normally takes up to 6 months to complete. Such a
non-productive period
wastes steam and manpower, ties up the capital used to build the
infrastructure. If the SAGD wells can
be hydraulically fractured, forming a high-mobility conduit connecting the two
SAGD wells, the inter-
well communication can occur much earlier and stronger.
The art of hydraulic fracturing as a stimulation method for hydrocarbon
resource recovery has
been practiced for a long time. In general, this method injects liquid at a
high pressure into a well drilled
through the target formation to be stimulated. The high pressure initiates a
fracture from the injection
well and propagates a sufficient distance into the formation. Then, the
fracture is filled with proppants
that are injected from the surface after the fracture is formed. The similar
method is applied in vertical
and horizontal wells and wells of any inclinations. However, the existing art
of hydraulic fracturing is
subject to limitations.
In hydraulic fracturing, there has historically been no proactive control of
the orientation of the
fracture formed. The fracture typically follows the plane perpendicular to the
least resistance, i.e.,
perpendicular to the original in-situ minimum stress, Smin. In many
situations, SAGD wells may not be
drilled in this optimal direction. For example, the azimuth of the SAGD wells
being drilled might be
dictated by the deposit channel of the oilsands resource. The well pair then
tends to follow the channel
direction which may or may not coincide with the Smin direction. If a
horizontal well is drilled in the
direction of the minimum stress Smin or substantially inclined towards it, the
fracture being formed via
the conventional hydraulic fracturing may be discrete in the vertical cross-
section perpendicular or
substantially perpendicular to the horizontal well. Such fractures may not be
ideal for the petroleum
production. For example, discrete fractures perpendicular to the SAGD wells do
not contribute to
uniform communication between the well pair.
There has been some work done in controlling the orientation of fractures
including selective
placement of hydraulically-driven fractures in the plane perpendicular to the
original in-situ maximum
stress, Smax. These practices in the past, however, typically require a
sacrificial well which was fractured
first along the direction perpendicular to Smin, i.e., the original in-situ
stress condition dictates the
fracture formed on this sacrificial well. For example, US Patent 3,613,785 by
Closmann (1971) teaches
creating a horizontal fracture from a first well by vertically fracturing the
formation from a second well
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and then injecting hot fluid to heat the formation. Heating via the vertical
fracture alters the original in-
situ stress so that the vertical stresses become smaller than horizontal
stresses, thus favouring a
horizontal fracture being formed. This method requires a first sacrificial
vertical fracture be formed and
uses costly steam to heat the formation.
US Patent 3,709,295 by Braunlich and Bishop (1971) controlled the direction of
hydraulic
fractures by employing at least three wells and a natural fracture system.
This method is only feasible in
formations already having existing fractures.
US Patent 4,005,750 by Shuck (1975) teaches creating an oriented fracture in
the direction of
the minimum in-situ stress from a first well by first hydraulically fracturing
another well to condition the
formation. Again, additional wells and sacrificial fractures are required
before the targeted fracture can
be formed.
Canadian patent CA 1,323,561 by Kry (1985) teaches creating a horizontal
fracture from a center
well after cyclically steam-stimulating at least one peripheral well. At the
peripheral well a vertical
fracture is created. CSS operations coupled with fracturing at the peripheral
well conditions the stress
field so that a horizontal fracture can be formed. To create the horizontal
fracture, a high-viscosity fluid
is proposed to inject into the center well to limit the fluid from leaking
into the formation.
Canadian patent CA 1,235,652 by Harding et al. (1988) first vertically-
fractures the formation
from peripheral wells to alter or condition the in-situ stress regime in the
center region of the peripheral
wells. The formation is then fractured through a central well to create and
extend a horizontal fracture.
All of the above documents require either the existence of a natural fracture
in the formation
already or the formation of sacrificial fractures before a targeted fracture
can be induced. This pre-
condition adds cost to well drilling and completion.
The idea of forming a target fracture without initiating sacrificial fractures
has been proposed in
two presentation papers by Lessi, J., et al.. ("Underground Coal Gasification
at Great Depth"; Technical
Committee of Groupe d'Etude de la Gazefication Souterraine du Charbon and
"Stress Changes Induced
by Fluid Injection in a Porous Layer Around a Wellbore"; 24th US Symposium on
Rock Mechanics June
1983) . These papers propose drilling two wells and forming a fracture
connecting them even though
their connection line may be not oriented perpendicular to Smin. According to
the authors, this process
relies on pressure diffusion and thus-associated poroelastic stress to create
a fracture between the two
wells. The two papers did not address interaction between the wells.
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It is therefore of great interest to find a new method to over-come the
original in-situ stress condition
for selective placement of a fracture without drilling a sacrificial well or
dictating presence of natural
fractures.
Summary of the Invention
A method is taught of creating one or more targeted fractures in a
subterranean formation. The
method comprises the steps of drilling and completing two wells in the
formation, conditioning said
Iwells to create a stress condition favorable for forming a fracture zone -
connecting said two wells and
initiating and propagating the fracture zone in said formation.
Description of the Drawings
The invention will now be described in further detail with reference to the
following drawings, in which:
Figure la illustrates a subterranean formation drilled with two wells of any
inclinations in any azimuth
with respect to the in-situ stress field;
Figure lb illustrates alternate orientations for pairs of wells that can be
drilled and completed for the
purposes of the present invention;
Figure lc illustrates a well that that has been drilled and completed
according one embodiment of the
present invention;
Figure id illustrates a further well that has been drilled and completed
according another embodiment
of the present invention
Figure le illustrates a further well that has been drilled and completed
according a further embodiment
of the present invention;
Figure 2a illustrates a pair of wells as they are conditioned using a method
of the present invention;
Figure 2b illustrates a pair of wells as they are conditioned using a method
of the present invention;
Figure 3a illustrates a fracture zone in a subterranean formation as a result
of a typical method of
fracturing;
Figure 3b illustrates a fracture zone in a subterranean formation as a result
of the method of the present
invention; and
Figure 4 is a schematic diagram of one embodiment of a method of the present
invention.
Detailed Description of the Preferred Embodiments
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The present invention provides a method of controlling the orientation of
fractures in
subterranean porous formations.
More specifically, the present invention provides a method of forming a
fracture connecting two
wells in subterranean geological formations even though the connection of the
said wells is not oriented
perpendicular to the original in-situ minimum stress. The said fracture(s)
will facilitate the
communication between the said wells. One direct application is to facilitate
early and uniform start-up
of the SAGD process in the in-situ recovery of heavy oil/oilsands reservoirs.
The orientation of the fracture(s) in subterranean formations is typically
dependant on the in
situ stresses at a particular location in the formation. Generally, fractures
form in a direction
perpendicular to the direction of the least stress.
However, the present inventors have found that the original in situ stress
profile can be
modified via interaction of said two wells in the pressure and/or temperature
diffusion, and thereby
change the orientation of induced fractures to the direction connecting the
said two wells. The present
method does not require one or more sacrificial fractures being formed a prior
to preconditioning.
Furthermore, it does not depend whether or not the original in-situ stress
field favors the formation of
the target fracture.
The process is well suited to oilsands reservoirs such as those in Alberta and
Saskatchewan,
Canada. However, the process can be applied to any formations and situations
where the target
fractures are sought. The steps of the present method are generally
illustrated in Figure 4.
Two wells are first drilled and completed. The well drilling and completion
follows the
conventional petroleum engineering practices or difference can be sought, all
of which depends on the
specific applications. Figure la illustrates an example of well drilling
applicable to the present invention
although other methods and configurations of well drilling and completion
would also be suitable for
the present invention and would be obvious to a person of skill in the art.
Some examples of further
well orientations encompassed by the present invention are illustrated in
Figure lb.
An interval or zone 6 along each well is exposed along which injected fluid
and thus pressure can
enter into the target subterranean formation 2. The two wells 4 are preferably
in proximal to one
another and have respective contacts with the formation 2 to be fractured.
For the purposes of the present invention, well-formation contact describes an
interval 6 where
the fluid can be injected into the formation 2 from the well. For open holes,
any section of the wells 4
that is segmented for accepting the injected fluid is the contact.
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The wells 4 may also be cased and cemented into place. The cement 8 is
preferably perforated
to penetrate the steel casing and the cement 8 to provide an interval 6 for
the injected fluid to enter
into the formation 2. The perforated interval 6 can be of any length and the
fracture can be initiated
anywhere along the contact length. This is illustrated in Figure lc.
Alternatively, as illustrated in Figures
id and le, a portion of the well can be cased and cemented 8 while another
portion of well remains
uncased, thus serving as the interval 6 through which injection fluid can
enter the formation 2.
The two wells 4 can be combined in different ways. Preferably, as illustrated
in Figure lb, two
injection intervals 6 are formed from each of said two wells 4. This allows
exposed intervals 6 to be close
to each other so that pressure and/or temperature front can readily interact
with each other.
Optimization of specific inter-well distance and/or orientation of their
connection with respect
to in-situ minimum stress component (Srffin) depend on the in-situ condition,
formation properties,
operating condition, and production objectives among others. Simulations can
be run to determine
these well drilling and completion parameters for particular applications. For
example, SAGD technology
used in the in-situ oilsands development has the two horizontal wells 4 that
are typically 5 m apart and
400 to 1000 m long which is open to the formation 2.
In a second step, the area where said two wells 4 to be connected via a
fracture is conditioned
via controlled injection into one or the two of said two wells 4. The
increased pressure and/or
temperature field alters the original in-situ stress condition via poroelastic
and/or thermoelastic
mechanisms. The new stress condition after the modification favors a fracture
being formed to connect
the exposed injection intervals 6 between said two wells 4. These steps are
illustrated in Figures 2a and
2b. Figure 2a illustrates the rather limited interaction 10 between the two
wells 4 at an early stage of
conditioning and Figure 2b illustrates the more developed interaction 10
between the two wells 4 near
the end of conditioning.
The stress modification step involves pressure diffusion fronts from each of
the said two wells 4
interacting with one another. The faster the pressure and/or temperature
diffusion, the earlier the
stress condition is modified. The larger the pressure and/or temperature
change, the more significantly
the stress condition is modified. The pressure diffusion depends on the
effective fluid mobility in the
formation 2. Anything that can increase the mobility will help. Therefore, one
or more of the following
means can help the stress modification, although other means of stress
modification are also possible
and would be clearly understood by a person of skill in the art as being
encompassed by the scope of the
present invention:
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(1) Dilation to increase the absolute permeability of the formation 2.
(2) Dilation with injected water to increase the relative permeability to
water.
(3) Injection of warm water to reduce the fluid viscosity in the formation 2.
Preferably, warm-up of
the wells 4 via steam circulation prior to warm water injection can help to
maintain the
temperature of the injected warm water.
(4) Injection of chemical solvents or solutions to reduce the fluid viscosity
in the formation 2.
(5) Injection or circulation of steam.
The pressure diffusion increases the pore pressure inside the formation 2,
evoking the poroelastic
stress buildup. Similarly, temperature diffusion increases the temperature
inside the formation 2,
evoking the thermostatic stress buildup. Both poroelastic and thermoelastic
stresses are similar in their
benefits for the dilation promotion purpose. However, in general, the
temperature diffusion is slower
than the pore pressure diffusion. Thus, injection at a higher pressure is more
efficient than injection at a
high temperature. Simultaneous high pressure and high temperature injection is
most preferred for the
purposes of the present invention. For the purposes of the present invention,
the phrase "high-pressure
injection" is used and it should be understood that this phrase includes or
applies to high-temperature
injection as well.
The injection pressure should start below the original in-situ minimum stress
(Sm,õ0). Preferably,
known methods can be used, such as performing a mini-frac test to measure the
original in-situ
minimum stress. As the pore pressure increases in the formation 2, the in-situ
stresses increase due to
the poroelastic mechanism. Thus, after the injection has undertaken for a
certain period of time, it is
possible to increase the injection pressure to somewhat above 5,-õ,n0. Such an
increased injection
pressure will increase the magnitude of the stress modification. The increase
is preferably gradual and
monitored to prevent formation of a macroscopic tensile fracture before the
formation 2 is fully
conditioned. As illustrated in Figure 3a, if a fracture is initiated prior to
full development of an
interaction 10 between two neighboring wells 4, the fractures are not
successful in connecting the two
wells 4.
Between the two wells 4, many alterations can be pursued in the injection
pressure, injection
rates, injected materials and so on. Most preferably, injections are conducted
in both wells 4
simultaneously to aid in accelerating interaction 10 of the pressure diffusion
between the wells 4.
In other circumstances, injection into a single well may be preferred. For
example, if a bottom
layer of water is present in the reservoir, it may beneficial to reduce or
eliminate injection into a lower
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of said wells 4 to avoid communication with the bottom water, although full
elimination of injecting into
the lower well is not necessarily required even in the presence of the bottom
water layer.
In one preferred embodiment, a lower well injected or circulated with steam,
to aid in viscosity
reduction in an upwards direction, due to the tendency of steam to rise. A
upper well can then be
injected with a solvent or chemical solution, to promote viscosity reduction
in a downwards direction,
via gravity-driven fluid movement downwards.
In another embodiment, the injection can start with water such as water
produced from water
treatment plants typically in the vicinity of the wellbore operations. As
dilation of the formation 2
induces more pore space, the injection material can be switched to steam or
solvent that will have a
good injectivity due to the pre-dilation by water. Advantageously in this
arrangement, pore space is
increased using more abundantly available water and more expensive steam or
solvent is used to
promote dilation and diffusion.
Furthermore, the temporal alterations described above can vary between said
two wells 4. In all
cases, the materials, pressures, temperatures and rates of injection and
injection coordination between
the two wells 4 depend on specific geological situations, convenience and
economics. Geomechanical
simulations based on the specific circumstances can decide the optimum
strategy.
Some examples of conditioning means include substantially simultaneous
injection of stimulant
into both wells 4 or substantially alternating injection of stimulant into one
and then another of the well
pair. Stimulant injection during the conditioning phase are preferably
monitored and controlled to
either maintain a constant injection rate and/or pressure or to vary the
injection rate and/or pressure.
Injection pressure can, in one embodiment of the present invention, be
incrementally increased, or
alternatively be raised and lowered to achieve formation 2 conditioning.
Furthermore, the injection rate
or injection pressure during conditioning can vary between the two wells 4.
Stimulant injection rates should be lower than that required to fracture the
formation 2, but
sufficiently high to create a desired rate of pressure increase. Preferably
the injection rate is optimized
to shorten operation time of the whole process.
Stimulant injection rate and time can be determined on-site based on the real-
time monitored
well injection pressure and rate. If the pressure increase is too slow, the
rate can be increased. If the
pressure rises too fast, the rate should be reduced. Site-based real-time
pressure monitoring methods
and devices are well known in the art and are included in the scope of the
present invention.
Preferably, stimulant injection rates are initially slower to probe and assess
characteristics of the
formation 2, before a higher rate is used.
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In some well completions, a well has two or more fluid injection or production
points. For
example, in SAGD operations, a long horizontal well interval is completed with
two or more concentric
tubulars. One leads to the front end, or toe, of the horizontal well and the
others are placed to the
intermittent points behind the toe one of which may be placed at the heel of
the horizontal well. In
these situations, the injection can proceed with injecting into one end such
as toe while producing from
the other end such as heel. The produced rate is smaller than the injected so
that a net injection occurs
into the formation. One advantage of such an injection scheme is to promote
uniform distribution of
pressure or temperature along the well length. Another advantage is an easy
control on the injection
rate or pressure.
The stimulant material to be injected can vary, so long as it serves to raise
formation pressure
and it does not harm the hydraulic conductivity of the formation 2 being
fractured, any material can be
injected. Ease to operate and economics dictates the material. For the
purposes of the present
invention, stimulant includes water of any temperatures, steam, solvent,
solutions of suitable chemicals
or their mixture in any portion.
Stimulant materials being injected into each of the two wells 4 can be
different between them
and/or alter overtime. Furthermore, stimulant type and temperature to be
injected during the stress
modification phase can vary between the two wells 4. For example, cold or warm
water may be injected
into a first well while the second well may be injected with steam.
Alternatively a solvent, either warm
or cold, may be injected in a first well, while the second well may be
injected with steam. A skilled
person in the art would understand that other combinations of stimulant type,
temperature and
pressure are also possible and encompassed by the scope of the present
invention.
Some stimulant materials can increase the pressure diffusion and thus, should
be encouraged.
For example, in heavy oil or oilsands industry, solvent or certain chemical
solutions can reduce the oil
viscosity and thus increase the effective formation mobility. Warm water up to
steam can reduce the
viscosity and thus helps the stress modification.
Stimulants used for injection are not limited and can be anything from water
produced from
nearby water treatment facilities to high-temperature steam or anything
between. The stimulant
viscosity can also range from approximately 1 centipoise (cp), as in the case
of water, to high-viscosity
stimulants. Specific values of the viscosity can be designed by simulations
when the in-situ condition and
formation properties are known.
The stress modification stage serves to modify the in-situ stress field around
the two wells 4 so
that the target fracture can be formed along the connection of the said two
horizontal wells 4. The
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timing of the stress modification phase depends on the in-situ conditions,
formation properties,
stimulant material properties and injection conditions including rate,
pressure and temperature of
injection, and combinations of these conditions and properties. Preferably,
geo-mechanical simulations
can be run prior to conducting the methods of the present invention to
estimate the conditioning timing
and design the injection pressure or other condition. Further preferably,
field pilot tests can be run in a
particular location to fine-tune the timing. Moreover, end of the stress
modification stage can be
determined by pressure interference tests. Conventional interference test
protocols in transient
pressure analysis of petroleum engineering can be used. For example, one of
the well pair is shut-in
while the other well continues the injection. If the shut-in well sees
pressure impact of certain degree
from the injection well, the current dilation stage can end and the subsequent
dilation promotion stage
follows.
Following stress modification, the injection pressure is increased further at
one or the two of
said two wells 4 to break down the formation 2 and to propagate the fracture
zone 12 which will
connect the two wells 4. This step is called fracture communication stage and
is illustrated in Figure 3b.
In both Figures 3a and 3b it should be noted that compressive forces within
the formation are
represented as a positive increase in stress. While this may differ from
typical solid mechanics notation,
representing compression as a positive force is common in geomechanics, and is
the correlation used for
the purposes of the present invention.
For example, when the present method is applied to start up the SAGD process,
injection of the
stimulant serves to stimulate the area around the SAGD well pair so that a
fracture zone 12 is formed
between them.
In another example application, grout may need to be placed to seal a certain
interval in the
subsurface formation 2. In this case, the fracture is first formed along the
certain interval and then grout
is injected into the fracture. In yet another example application,
contaminants may need to be removed
from subsurface. Leaching is normally used. The target fracture can be formed
first to start the leaching
process at the target locations. In a final example, THAI process has been
tried as a potential in-situ
oilsands recovery process. A target fracture can be formed between the
injection well and producer
well.
In geothermal applications, two wells are drilled with one well injecting cold
water and the
other producing the heated water. The present invention can be used to form a
fracture between the
wells.
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The injection pressure is increased by increasing either the injection rate or
injection pressure
above the original in-situ minimum stress, Sm,n, until a fracture zone is
initiated. Initiation of the fracture
zone can be observed by monitoring the injection pressure and/or rate. If
fracturing injection is
maintained at a constant rate, the increased injectivity is reflected by a
decreasing pressure. If fracturing
injection is maintained at a constant pressure, the increased injectivity is
reflected by an increased
demand of more volume per unit time to be injected in order to maintain the
constant pressure. During
initiation of the fracture, injection can be carried out at one or both of the
two wells 4.
Preferably, once the fracture has been initiated, one well is shut-in while
the other well
continues the injection. This enables detection of the inter-well
communication. When pressure at the
shut-in well increases, it means that the two wells 4 are in communication
with each other.
The present method utilizes poroelastic and/or thermoelastic mechanisms to
alter the original
un-disturbed in-situ stress conditions so that the target fracture can be
created. Poroelastic stress comes
from the interaction between pore pressure and solid deformation. The general
theory of poroelasticity
was established by Biot (1941) although the particular case of poroelasticity
relating to interaction
between deformation and pressure diffusion was studied earlier by Terzaghi
(1923) for soils. Poroelastic
effects in rock mechanics related to petroleum engineering were first noted by
Geertsma (1957, 1966).
Thermoelastic stress comes from the interaction between temperature and solid
deformation.
Physically, an increase in the pore pressure (p) or temperature (T) causes
rock to expand. Such
expansion is constrained by the material outside the domain of p/T increase.
The restriction introduces
an additional stress component to the original undisturbed in-situ stress
field in the formation 2. Such
induced stresses are called the poroelastic or thermoelastic stresses
depending on if the causing
mechanism is pore pressure increase or temperature increase.
Mathematically, the stress modification phase and subsequent fracture
initiation and
propagation stage can be simulated by a nonlinear coupled thermo-hydro-
mechanical model.
This detailed description of the present processes and methods is used to
illustrate certain
embodiments of the present invention. It will be apparent to a person skilled
in the art that various
modifications can be made and various alternate embodiments can be utilized
without departing from
the scope of the present application, which is limited only by the appended
claims.
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