Note: Descriptions are shown in the official language in which they were submitted.
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A method of differential etching of the subterranean fracture
The present invention relates to the stimulation of wells penetrating
subterranean formations. More particularly it relates to acid fracturing and
methods of preferentially etching the fracture faces in a heterogeneous
pattern.
This pattern within the hydraulically and chemically generated fracture will
have
a geometry that results in a conductive path from the fracture tip to the
wellbore.
It is through this enhanced etch geometry that one can hope to achieve
enhanced
fluid flow from the formation to the wellbore.
Patent US20050113263 Al describes the use of a system that contains
both an agent that can dissolve at least once component of the formation and
inert solid particles that can inhibit the reaction of the dissolving agent
with the
fracture faces where it contacts them. The inert particles must be shaped so
that,
or be deformable into shapes so that, they cover part of the fracture face,
rather
than having just points or lines of contact.
Patent US20060058197 Al describes a variety of inert solid particles in
combination with a delayed acid system that is primarily composed of a solid
acid-precursor.
Patent application PCT/RU2007/000252 disclosures the ideas relate to
methods of increasing the conductivity around/between pillars or proppant
islands once they are placed. The ideas include: 1. A solvent overflush or an
oxidizer/breaker-laden fluid is introduced to the propped fracture pillar
network
after it has been generated. 2. An overflush of an acidic or otherwise
chemically
reactive fluid that etches the "open" rock surface that exists between/around
the
proppant pillars. 3. Coating the proppant with a resin coating that under
stress
binds the conventional proppant together and forms a mask or barrier on the
fracture surface.
Patents US6114410, US6328105B 1 describes an improved proppant and a
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method of increasing fracture conductivity in subterranean
formations. The proppant contains a mixture of bondable and removable
particles. The bondable particles can be coated with a curable resin. The
bondable particles within a subterranean formation adhere to adjacent bondable
particles to form a permanent, self-supporting matrix; and the removable
particles from the self-supporting matrix provide the ambient fracture
conditions.
This increases fracture conductivity and the overall productivity of the
hydraulic
operation.
Patent US20050274523A1 describes methods for the treatment of
subterranean wells involving injecting a first fracturing fluid into a
formation,
and then injecting at least a second fracturing fluid into the formation in
order to
create extended conductive channels through a formation are described. The
fracturing fluids can be similar in density, viscosity, pH and the other
related
characteristics. Alternatively, the fracturing fluids can differ in their
densities,
viscosities, and pH, allowing for variations in the conductive channels
formed.
Propping agents can also be included in one or both of the injected fluids,
further
enhancing the conductive channels formed. The described methods aid in
minimizing proppant flowback problems typically associated with hydraulic
fracturing techniques.
The ideas in this patent memo describe several methods that may be
employed to decrease the tendency of an acid, or any reactive fluid, from
reacting evenly with the fracture face, primarily within carbonate formations.
However, these inventions can be applied to any formation which can be etched
by means of a reactive fluid. By increasing the heterogeneity of the etch
pattern,
it is desired that conductive channels along the fracture faces are created. A
brief summary of each idea is provided below.
Invention embodiment one. The masking material could placed
heterogeneously in the fracture. This material invades the surface of the rock
through a process of extrusion or simply leaves a film on the surface of the
rock
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when compressed under closure stress conditions (pressure and/or temperature)
when the
fracture has closed. Acid is then pumped at fracturing pressures, refracing
the formation.
Even though the bulk of the material may be displaced, the remaining residue
would protect
the rock, even if this residue on the fracture face or glued film was only
present on one side of
the fracture face.
Invention embodiment two. The masking material is placed relatively
uniformly on the fracture faces. A reactive fluid is pumped into the hydraulic
fracture. The
acid finds anomalies or weak areas of the film and it begins to penetrate this
layer and react
with the native rock underneath. Provided that the amount of acid exposure is
controlled, the
resulting etch pattern can be quite irregular.
Invention embodiment three. A material is pumped that self agglomerates
once in the fracture. This agglomeration process could be triggered either
through diffusion
of a reactive chemical or via physical or chemical changes to the material
itself. A reactive
fluid (e.g. acid) is then immediately pumped into the fracture. The reactive
fluid flows
uniformly through the fracture in the near wellbore area, but where it
contacts the
clusters/agglomerations of material, its flow is impeded. Preferential flow is
around and not
through these structures. Due to the differential flow patterns, the etch
pattern is likewise
altered and non-uniform.
Aspects of some embodiments disclosed herein relate to a method of
differential etching of a subterranean fracture comprising: depositing a
masking material
substantially uniformly on the fracture surface or face; whereby subsequent
treatment by an
acid or a reactive fluid generates a heterogeneous etch pattern on the
fracture surface, the etch
pattern being largely influenced by anomalies or weak areas in the deposited
masking
material; and whereby, upon closure of the fracture, the heterogeneous etch
pattern provides
mismatch of geometry that leaves one or more open conductive channels in the
fracture.
Aspects of some embodiments disclosed herein relate to a method of
differential etching of the subterranean fracture wherein particles which are
initially non-
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tacky/non-adhesive are pumped into the fracture by means of a fracturing fluid
or other means
of conveyance; at a prescribed time, the particles exhibit adhesive
properties; the interaction
of the adhesive particles with each other or the fracture surface leads to the
non-uniform
distribution of material within the fracture; the particles of agglomerated
material
impede/restrict the flow of reactive fluids through them, and require the
fluid to flow around
them.
Detailed Description of the Invention
In acid fracturing treatments, acid is pumped into a hydraulic fracture,
preferentially along the entire length of the structure (i.e. from the tip to
the wellbore). These are
typically pumped in carbonate formations. The goal of these treatments is to
create disparities
within the rock such that when the opposing fracture faces close upon one
another, the geometry
does not match. In the absence of other influences, the differential etching
typically results from
localized heterogeneities in the native formation. It is desired that these
new
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geometries provide a conductive flow path for produced fluid (or injected
fluids as the case may be) along the fracture faces.
A major problem that is encountered during acid fracturing treatments
pertains to the reaction rates of the acid with the formation. Oftentimes the
acid
reacts uniformly with the formation, especially in localized regions of the
fracture. When this occurs, the etch pattern is not sufficient to support
conductive channels along the fracture face after fracture closure. This often
occurs when the delivery rate of the acid to the fracture face is much lower
than
the rate of the reaction of the acid. Several methods have been used in
attempts
to alleviate or minimize these problems. One method has been to keep the live
acid separated from the formation. This can be done by a variety of methods
such as emulsifying or encapsulating the acid and then releasing the acid at a
later time when and where it is desired. A second method has been to delay the
formation or generation of the acid. Several systems have been described that
generate acids once they are downhole, within in the fracture. A third method
involves the use of non-acidic fluids and acidic fluids which "finger" through
one another to generate differential etching patterns.
Recent Schlumberger patent applications (US20050113263,
US20060058197) have described inventions that aim to generate heterogeneity
within the acid fracturing operation through the use of inert "masking
agents".
The additional inventions provided in this patent memo are aimed at adding to
and improving on the ideas expressed in these patent applications. The
embodiment of this invention does not appear to be expressly stated in the
claims of the patent.
The first embodiment pertains to the use of inert materials as masking
agents, with particular emphasis on their ability to either a) extrude into
the rock
formation, or b) cast a film or residue on the rock surface. In previous
applications, the inert particle is described as having a shape, structure, or
properties such that they conform to one or both faces of the fracture and
inhibit
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reaction of acid with the formation where they conform to the fracture
face. These masking agents are placed heterogeneously throughout the fracture,
covering a portion of the fracture faces and preventing the acid from reacting
with this portion of the fracture faces. The un-reacted fracture faces create
a
small pillar that is capable of holding open the etched fracture when it
closes
upon itself. The open area of the fracture is nearly infinitely conductive. An
illustration of this concept is shown in Figure 1. In this configuration, the
masking material which helped create the pillar may remain or can dissolve.
The same will hold true for all further masking agents listed in this patent
memo.
In previous description, it was usually inferred that the masking material
was a solid inert particle that remained on the surface of the fracture face
during
the acidizing process.
There is a side view of a hydraulic fracture on the Fig. 2.
Frame A: An inert masking material has been heterogeneously placed into the
fracture.
Frame B: The fracture closes upon itself and the inert material is compressed.
Frame C: The fracture is hydraulically pressurized by a reactive fluid
(arrow).
Most of the inert masking material is displaced from its initial location and
pushed further down the fracture. The residue of the masking agents is left
behind. In region 1 the residue has invaded the formation. In region II the
residue has only left behind a thin film on the surface of the formation. In
region
III no residue from the masking agent is left behind.
Frame D: The inert residue in regions I and II protects the rock from the
reactive fluid (arrows). In the "masked" regions the surface of the rock
remains
as it was originally. In region III the rock is homogeneously etched by the
reactive fluid.
Frame E: When the fracture closes on itself, the protected regions in I and
II are now high spots and serve as pillars that support the weight of the
fracture
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and hold it open. In region III the fracture closes upon itself as the region
was etched homogeneously.
As illustrated in Figure 2, several scenarios may exist where the bulk of
the masking material can be sloughed off or otherwise removed, however the
small portion of the material 1 that either extruded into the rock face or
left
behind a thin film provides adequate protection. In this process of film
casting
or extrusion, the surface of the masking agent may undergo a phase change
(solid to liquid and possibly back to solid again).
The second embodiment pertains to the use of a fluid which deposits a
relatively uniform film on the fracture surface. This may be likened to a
filter
cake, however, its primary function is not to control fluid loss. Rather, it
provides a barrier which limits the influence of the acid on the native rock
underneath. Due to the challenges in applying a completely uniform film, this
structure is likely to have anomalies or weak areas that will allow the inflow
of
acid. As the acid penetrates the film in distinct locations, the formation
underneath will begin to etch the rock. Provided that the length of acid
exposure
is controlled, this can result in an uneven etching pattern that leads to the
development of pillar-like structures. The details of this idea are
illustrated in
Figure 3.
There is side view of a hydraulic fracture in Figure 3. .
Frame A: The hydraulic fracture is maintained in an open configuration by a
standard fracturing fluid.
Frame B: A second fluid is pumped into the fracture and it leaves behind a
relatively uniform film or residue on the fracture surface.
Frame C: A reactive fluid (black arrows) is pumped into the hydraulic
fracture.
Within anomalies or weak areas of the film, the acid will begin to penetrate
this
layer and react with the native rock underneath
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Frame D: The fracture is over flushed with a wash or standard fracturing fluid
(white arrow). The yellow film may remain on the surface or it may have been
removed.
Frame E: The fracture closes. The etch pattern may be irregular and not match
on either side of the fracture, yet a series of high and low regions are
created.
The resulting structure leaves small channels that remain open even after the
closure stress is applied to the rock faces.
Within this invention it should also be considered that or a uniformly
placed solid could also serve to achieve this goal. In such a scenario, a
solid can
be placed within a fracture and then under the influences of heat, time, and
pressure, it can be converted to a liquid.
The third embodiment pertains to the use of self-assembling (self-
agglomerating particles) for the purpose of changing the flow characteristics
within the fracture. The material is pumped as relatively small particles
(fibers,
ribbons, platelet's, spheres, etc) that can pass through the perforation.
However,
after passing through the perforations, the material undergoes a
transformation
which aids in the agglomeration of the material. This agglomeration can be
tuned by a number of factors (temperature, fluid chemistry, time, pressure,
etc).
One possible use of these self-assembling strips for acid diversion is
illustrated
in Figure 4. Wellbore, perforations and hydraulic fracture formed during the
implementation of the methods of this patent memo.
Frame A: Light grey indicates regions exposed to a standard fracturing fluid.
Black structures areas indicate particulate matter. In this example they are
strips
or coated fibers. The fibers are sent down the wellbore and through the
perforations as individual particles. Once through the perforations, the
material
begins to agglomerate and form clusters. The number and size of agglomerated
material may vary.
Frame B: A reactive fluid is pumped into the hydraulic fracture (Black
arrows).
The fluid flows uniformly through the fracture in the near wellbore area, but
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where it contacts the clusters/agglomerations of material, it's
flow is impeded. Preferential flow is around and not through these structures.
Frame C: The resulting fracture geometry after the treatment is over. The
fracture face is etched in many locations (shaded area); however, in the
vicinity
of where the agglomerated material had been deposited, the amount of etch is
limited (black). These structures then serve as pillars to support the
fracture and
keep it open.
It is desired that these agglomerations may become wedged or otherwise
travel at a rate which is slower than that of the bulk fluid. Preferential
flow of
the fluids will therefore be around and not through these agglomerated masses.
If a reactive fluid is passed through a fracture containing such structures
the
resulting geometry should result in an etch pattern that has high spots (less
reacted rock) in the vicinity of these agglomerations. Once again, these high
areas can serve as pillars which will serve to hold the fracture open after
closure.
Experimental Examples
Experiment for embodiment 1: The surface of an Indiana Limestone block
(17.8 x 7.6 x 1.9 cm) was selectively covered with a thin film of silicone
gasketing material (Dow corning Q3-1566 Heat resistant sealant). The material
was applied liberally to the surface in select regions and then scraped off.
Successive applications were applied and scraped off. Later the surface was
lightly rubbed by hand in order to remove as much of the gasketting material
as
possible.
The block was then exposed to 37% HCI at room temperature and ambient
pressure for approximately 5 minutes. The rock face was heterogeneously
etched with preferential etching in the non-coated areas. The surface of the
rock
was notably smoother in the gasketed areas.
Experiment for embodiment 2: Blocks of of Indiana limestone (8.5 x 4.1 x
2.6 cm).were covered with a thick coating of standard hot melt glue (ethylene
vinyl acetate co-polymer). After being pressed together and heated to 80 deg C
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for several days, the blocks were removed and separated and excess glue
was scraped off the surface. This process was repeated to ensure a uniform
coating. One of the uniformly blocks was then dipped into a concentrated
solution of 37% HC1 for approximately 5 min. Upon removal, it was noticed that
the surface etch pattern is irregular, and in some regions where the glue is
still
present, the etch is minimal.
Experiment for embodiment 3: A film of polylactic acid was cast onto a
Teflon surface 2. The adhesive coated substrate was then coated with either
glucose 3 or calcium carbonate 4. It was noted that when the glucose-coated
strips were dipped in water, the glucose dissolved and the strips were made to
be
sticky again 5. The calcium carbonate coated strips maintained their coating
6,
even after being dipped in water. This is illustrated in Figure 5.
When the loose glucose-coated strips were added to stirred slurry
containing a linear guar-based fracturing fluid and sand, the strips quickly
agglomerated and strongly adhered to one another. However, when calcium
carbonate-coated strips were added to a similar solution, no agglomerations
were
formed. After 10 minutes of mixing 1 mL of acetic acid was added to the
solution to dissolve the calcium carbonate coating. The solution was allowed
to
stir for an additional 5 minutes and no agglomeration was noted. An additional
3 mL of acetic acid was added to the solution. Two minutes after this last
addition the adhesive strips began to adhere to one another, forming an
agglomerated mass.
Additional experiment for embodiment 3: Intermediate strength ceramic
proppant (20/40 mesh) was coated with an acrylic-based spray adhesive. This
coating was then covered with a dusting of calcium carbonate powder. This
proppant was no longer sticky towards each other or other objects, even when
placed in water. Another batch of the ceramic proppant was coated with an
commercially available acrylic-based black spray paint. When completely dry,
the painted proppant had no adhesive tendencies. The two proppant were placed
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into a flow loop containing fresh water. The two proppant were free flowing
and were homogeneously distributed. Acid was slowly introduced into the
flowloop. When the pH had slightly decreased, the external coating of calcium
carbonate of the adhesive-covered proppant began to react and dissolve. This
revealed the layer of adhesive on these proppant particles. When two adhesive
coated proppant particles came into contact, they would sometimes adhere;
however, there was less tendency for an adhesive proppant and a painted
proppant to adhere, and no tendency for two painted proppant to adhere. Within
several minutes all of the adhesive-covered proppant had agglomerated, while
the painted proppant remained free-flowing. The agglomerated particles moved
more slowly within the flow loop and the painted particles would pass over and
around these agglomerated masses.
