U.S. patent application number 14/395731 was filed with the patent office on 2015-03-19 for system and methods for treating subsurface formations containing fractures.
The applicant listed for this patent is The Board of Regents of the University of Texas System. Invention is credited to Mukul Mani Sharma.
Application Number | 20150075782 14/395731 |
Document ID | / |
Family ID | 49384109 |
Filed Date | 2015-03-19 |
United States Patent
Application |
20150075782 |
Kind Code |
A1 |
Sharma; Mukul Mani |
March 19, 2015 |
SYSTEM AND METHODS FOR TREATING SUBSURFACE FORMATIONS CONTAINING
FRACTURES
Abstract
Methods of treating hydrocarbon containing formations are
described herein. A method for treating a mudstone formation
includes providing a substantially horizontal or inclined wellbore
to mudstone formation; providing acid to the portion of mudstone
formation such that a size of the fractures is increased; and
allowing hydrocarbons to flow through the fractures.
Inventors: |
Sharma; Mukul Mani; (Austin,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
The Board of Regents of the University of Texas System |
Austin |
TX |
US |
|
|
Family ID: |
49384109 |
Appl. No.: |
14/395731 |
Filed: |
April 19, 2013 |
PCT Filed: |
April 19, 2013 |
PCT NO: |
PCT/US13/37399 |
371 Date: |
October 20, 2014 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61636333 |
Apr 20, 2012 |
|
|
|
Current U.S.
Class: |
166/250.1 ;
166/308.2 |
Current CPC
Class: |
E21B 43/267 20130101;
E21B 43/26 20130101 |
Class at
Publication: |
166/250.1 ;
166/308.2 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method for treating a mudstone formation, comprising:
providing a substantially horizontal or inclined wellbore to the
mudstone formation; forming a plurality of fractures in a portion
of the mudstone formation, wherein the fractures comprise one or
more microfractures having a width of less than 0.5 mm; providing
acid to the portion of mudstone formation such that a width of some
of the microfractures increases to a width greater than the
original width of the fracture; and allowing hydrocarbons to flow
through the widened fractures.
2. The method as claimed in claim 1, assessing a size and location
of fractures in the portion of the mudstone formation.
3. The method as claimed in any one of claim 1 or 2, wherein
mudstone formation contains about 10% carbonate minerals.
4. The method as claimed in any one of claims 1-3, wherein forming
fractures comprises hydraulic fracturing, pneumatic fracturing,
alternate fracturing, or combinations thereof.
5. The method as claimed in any one of claims 1-4, wherein
providing acid etches a surface of the fracture.
6. The method as claimed in any one of claims 1-5, further
comprising producing hydrocarbons from the mudstone formation.
7. The method as claimed in any one of claims 1-6, wherein the
mudstone formation comprises from about 5% carbonate compounds to
about 70% carbonate compounds.
8. The method as claimed in any one of claims 1-7, wherein a
majority of the fractures are microfractures.
9. The method as claimed in any one of claims 1-8, wherein the acid
is provided as an emulsion and/or a foam.
10. The method as claimed in any one of claims 1-9, further
comprising providing stabilizing chemicals to the mudstone
formation.
11. The method as claimed in any one of claims 1-10, wherein the
acid is provided as a solution of acid and quaternary ammonium
salts.
12. The method as claimed in any one of claims 1-11, wherein the
acid is provided as a solution of inorganic salts.
13. The method as claimed in any one of claims 1-12, further
comprising applying pressure to the acid, wherein the application
of pressure forms additional fractures in the mudstone
formation.
14. The method as claimed in any one of claims 1-13, wherein
providing acid enhances conductivity one or more fractures.
15. A method for treating a mudstone formation, comprising:
providing a substantially horizontal or inclined wellbore to the
mudstone formation; providing acid to a portion of the mudstone
formation comprising microfractures; and allowing the acid to flow
through the microfractures; and increasing a size of the
microfractures such that hydrocarbons flow through the fractures,
wherein the acid inhibits softening of the mudstone formation.
16. The method as claimed in claim 15, assessing a size and
location of fractures in the portion of the mudstone formation.
17. The method as claimed in any one of claim 15 or 16, wherein
mudstone formation contains about 50% carbonate compounds.
18. The method as claimed in any one of claims 15-17, wherein
providing acid etches surfaces of the microfractures.
19. The method as claimed in any one of claims 15-18, further
comprising producing hydrocarbons from the mudstone formation.
20. The method as claimed in any one of claims 15-19, wherein the
mudstone formation comprises from about 5% carbonate materials to
about 70% carbonate materials.
21. The method as claimed in any one of claims 15-20, further
comprising forming fractures in the portion of the mudstone
formation prior to providing acid to the mudstone formation.
22. The method as claimed in any one of claims 15-21, wherein the
acid is providing as an emulsion and/or a foam.
23. The method as claimed in any one of claims 15-22, further
comprising providing shale stabilizing chemicals to the mudstone
formation.
24. The method as claimed in any one of claims 15-23, wherein the
acid is provided as a solution of acid and quaternary ammonium
salts.
25. The method as claimed in any one of claims 15-24, further
comprising applying pressure to the acid, wherein the application
of pressure forms additional fractures in the mudstone
formation.
26. A method for treating a mudstone formation, comprises:
providing a substantially horizontal or inclined wellbore to the
mudstone formation that has undergone a fracturing process;
providing acid to a portion of the mudstone formation comprising
microfractures; and allowing the acid to flow through the
microfractures; and increasing a size of the microfractures to
allow placement of proppant inside of the microfractures.
27. A method for treating a shale formation, comprising: providing
a substantially horizontal or inclined wellbore to the shale
formation; forming a plurality of fractures in a portion of the
shale formation, wherein the fractures comprise one or more
microfractures having a width of less than 0.5 mm; providing acid
to the portion of shale formation such that a width of some of the
microfractures increases to a width greater than the original width
of the fracture; allowing hydrocarbons to flow through the widened
fractures; and producing hydrocarbons from the formation.
28. A method for treating a mudstone formation, comprising:
providing a substantially horizontal or inclined wellbore to the
shale formation; providing a first fluid to a portion of the
mudstone formation such that one or more fractures are formed in
the formation; providing a second fluid to the portion of the
mudstone formation, the second fluid comprising acid and having a
viscosity less than the viscosity of the first fluid, wherein
addition of the second fluid increases a width of one or more
formed fractures; and producing hydrocarbons from the
formation.
29. The method as claimed in claim 28, wherein at least one of the
widened fractures has a width of less than 0.5 mm.
30. The method as claimed in any one of claim 28 or 29, wherein the
second fluid comprises proppants.
31. The method as claimed in any one of claims 28-31, further
comprising providing a third fluid to the formation after providing
the second fluid, wherein the third fluid has a higher viscosity
than the second fluid.
32. A method of treating a hydrocarbon formation comprising:
forming a plurality of fractures in a portion of the hydrocarbon
formation; and providing acid to the portion of the hydrocarbon
formation such that a width of some of the fractures increases to a
width greater than the original width of the fracture.
Description
BACKGROUND
[0001] 1. Field of the Invention
[0002] The present invention relates generally to methods and
systems for production of hydrocarbons and/or other products from
various subsurface formations such as hydrocarbon containing
formations containing fractures.
[0003] 2. Description of Related Art
[0004] Hydrocarbons obtained from subterranean formations are often
used as energy resources, as feedstocks, and as consumer products.
Concerns over depletion of available hydrocarbon resources and
concerns over declining overall quality of produced hydrocarbons
have led to development of processes for recovery that is more
efficient, processing and/or use of available hydrocarbon
resources. In situ processes may be used to remove hydrocarbon
materials from subterranean formations that were previously
inaccessible and/or too expensive to extract using available
methods.
[0005] Substantial reserves of hydrocarbons are known to exist in
formations that have relatively low permeability. Examples of such
formations include the Eagle Ford shale, the Barnett shale, the
Travis Peak and Cotton Valley formations and the Bakken shale.
Several methods have been proposed and/or used for producing heavy
hydrocarbons from relatively low permeability formations. Recovery
of hydrocarbons from low permeability subterranean formations is
difficult because of the low mobility of fluids in the pore space
in the subterranean formation (ultra-low permeability rocks). This
makes the production and injection of fluids from such reservoirs
very difficult. Similar problems are encountered in heavy oil
reservoirs (reservoirs containing crude oil with a viscosity larger
than about 100 centipoise). Here too, the mobility of the fluids is
small and it is difficult to inject and produce from the
hydrocarbon bearing rock.
[0006] It is a common practice to acidize subterranean formations
in order to increase the permeability of the formation. For
example, an acidizing fluid is injected into a well in order to
increase the permeability of a surrounding hydrocarbon-bearing
formation, and thus, facilitate the flow of hydrocarbon fluids into
the well from the formation or the injection of fluids such as gas
or water, from the well into the formation. Such acidizing
techniques may be carried out as "matrix acidizing" procedures or
as "acid-fracturing" procedures.
[0007] In acid fracturing, the acidizing fluid is disposed within
the well opposite the formation to be fractured. Thereafter,
sufficient pressure is applied to the acidizing fluid to cause the
formation to break down with the resultant production of one or
more fractures therein. An increase in permeability thus is
affected by the fractures formed as well as by the chemical
reaction of the acid within the formation.
[0008] In matrix acidizing, the acidizing fluid is passed into the
formation from the well at a pressure below the breakdown pressure
of the formation. In this case, increase in permeability is
affected primarily by the chemical reaction of the acid within the
formation with little or no permeability increase being due to
mechanical disruptions within the formation as in fracturing.
[0009] In yet another technique involving acidizing, the formation
is fractured. Thereafter, an acidizing fluid is injected into the
formation at fracturing pressures to extend the created fracture.
The acid functions to dissolve formation materials forming the
walls of the fracture, thus increasing the width and permeability
thereof. Grieser et al. describes in "Surface Reactive Fluid's
Effect on Shale," Presented at the 2007 SPE Production and
Operations Symposium, Mar. 31, 2007 to Apr. 3, 2007 describes
injecting acidizing fluid into the formation at fracturing
pressures.
[0010] In most cases, acidizing procedures are carried out in
calcareous formations such as dolomites, limestones, dolomitic
sandstones, etc. For example, U.S. Pat. No. 5,238,067 to Jennings,
Jr. describes methods to improve fracture acidizing in a carbonate
containing formation. Initially, the formation is hydraulically
fractured to form a fracture in the formation in a preferred
direction. Thereafter, an acid is directed into the fracture to
etch the fracture's face and create channels therein. Afterwards, a
viscous fluid is directed into the fracture which fluid contains a
material sufficient to serve as a diverter and prevent growth in
the existing fracture. Once the diverting material is in place,
hydraulic fracturing is again conducted within the existing
fracture whereupon fracturing forces are directed away from the
diverter to form a branched fracture to contact hydrocarbonaceous
vugs in the formation. The steps of fracturing acidizing, and
diverting are continued until a vuggy area in the formation has
been interconnected with the fracture system.
[0011] Although, there has been a significant amount of effort to
develop methods and systems to produce hydrocarbons and/or other
products from relatively high permeability formations, there is
still a need for improved methods and systems for production of
hydrocarbons from very low permeability formations such as shales
and tight sands.
SUMMARY
[0012] Methods and systems of treating subsurface hydrocarbon
formations containing fractures are described herein. In some
embodiments, a method for treating a mudstone formation includes,
providing a substantially horizontal or inclined wellbore to the
mudstone formation; forming a plurality of fractures in a portion
of the mudstone formation, wherein the fractures include one or
more microfractures having an original width of less than 0.5 mm;
providing acid to the portion of mudstone formation such that a
width of some of the microfractures increases to greater than the
original width of the fracture; and allowing hydrocarbons to flow
through the widened fractures.
[0013] In some embodiments, a method for treating a mudstone
formation, includes providing a substantially horizontal or
inclined wellbore to mudstone formation; providing acid to a
portion of the mudstone formation that includes microfractures;
allowing the acid to flow through the microfractures; and
increasing a size of the microfractures such that hydrocarbons flow
through the fractures, wherein the acid, inhibits softening of the
mudstone formation.
[0014] In some embodiments, a method for treating a mudstone
formation, includes providing a substantially horizontal or
inclined wellbore to mudstone formation; providing acid to a
portion of the mudstone formation that includes microfractures;
allowing the acid to flow through the microfractures; and
increasing a size of the microfractures to allow placement of
proppant inside of the microfractures.
[0015] In some embodiments, a method for treating a shale
formation, includes providing a substantially horizontal or
inclined wellbore to the shale formation; forming a plurality of
fractures in a portion of the shale formation, wherein the
fractures include one or more microfractures having a width of less
than 0.5 mm; providing acid to the portion of shale formation such
that a width of some of the microfractures increases to a width
greater than the original width of the fracture; allowing
hydrocarbons to flow through the widened fractures; and producing
hydrocarbons from the formation.
[0016] In some embodiments, a method for treating a mudstone
formation, includes providing a substantially horizontal or
inclined wellbore to the shale formation; providing a first fluid
to a portion of the mudstone formation such that one or more
fractures are formed in the formation; providing a second fluid to
the portion of the mudstone formation, the second fluid including
acid and having a viscosity less than the viscosity of the first
fluid, wherein addition of the second fluid increases a width of
one or more formed fractures; and producing hydrocarbons from the
formation.
[0017] In further embodiments, features from specific embodiments
may be combined with features from other embodiments. For example,
features from one embodiment may be combined with features from any
of the other embodiments.
[0018] In further embodiments, additional features may be added to
the specific embodiments described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] Advantages of the present invention may become apparent to
those skilled in the art with the benefit of the following detailed
description and upon reference to the accompanying drawings in
which:
[0020] FIG. 1 depicts a schematic side view of treating a mudstone
formation with acid.
[0021] FIG. 2 depicts hydrocarbon formation in FIG. 1 after
treatment with acid.
[0022] FIG. 3 is a scanning electron microscope picture of a
portion a calcareous mudstone or shale formation of an embodiment
of an acid treated mudstone or shale formation.
[0023] FIG. 4A depicts the elemental composition of different
portions of an embodiment of an acid treated mudstone or shale
formation.
[0024] FIG. 4B depicts the carbon composition of the acid treated
mudstone or shale formation depicted in FIG. 4A.
[0025] FIG. 4C depicts the calcium composition of the acid treated
mudstone or shale formation depicted in FIG. 4A.
[0026] FIG. 4D depicts the silicon composition of the acid treated
mudstone or shale formation depicted in FIG. 4A.
[0027] FIG. 5 depicts a schematic of alternate injection of fluids
having different viscosities in a mudstone or shale formation.
[0028] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings and may herein be described in
detail. The drawings may not be to scale. It should be understood,
however, that the drawings and detailed description thereto are not
intended to limit the invention to the particular form disclosed,
but on the contrary, the intention is to cover all modifications,
equivalents, and alternatives falling within the spirit and scope
of the present invention as defined by the appended claims.
DETAILED DESCRIPTION
[0029] The following description generally relates to systems and
methods for treating hydrocarbons in the formations. Such
formations may be treated to yield hydrocarbon products and other
products.
[0030] "API gravity" refers to API gravity at 15.5.degree. C.
(60.degree. F.). API gravity is as determined by ASTM Method D6822
or ASTM Method D1298.
[0031] "Acid" refers to any inorganic or organic fluid that ionizes
to provide high concentrations of protons (low pH) in solution with
water. Examples of acids include hydrochloric acid, acetic acid,
formic acid, hydrofluoric acid, and fluoboric acid.
[0032] A "fluid" may be, but is not limited to, a gas, a liquid, an
emulsion, a slurry, and/or a stream of solid particles that has
flow characteristics similar to liquid flow.
[0033] A "formation" includes one or more hydrocarbon containing
layers, one or more non-hydrocarbon layers, an overburden, and/or
an underburden. "Hydrocarbon layers" refer to layers in the
formation that contain hydrocarbons. The hydrocarbon layers may
contain non-hydrocarbon material and hydrocarbon material. The
"overburden" and/or the "underburden" include one or more different
types of impermeable materials. For example, the overburden and/or
underburden may include rock, shale, mudstone, or wet/tight
carbonate.
[0034] "Formation fluids" refer to fluids present in a formation
and may include gases and liquids produced from a formation.
Formation fluids may include hydrocarbon fluids as well as
non-hydrocarbon fluids. Examples of formation fluids include inert
gases, hydrocarbon gases, carbon oxides, mobilized hydrocarbons,
water (steam), and mixtures thereof. The term "mobilized fluid"
refers to fluids in a hydrocarbon containing formation that are
able to flow as a result of thermal treatment of the formation.
"Produced fluids" refer to fluids removed from the formation.
[0035] "Fracture" refers to a crack or surface of breakage within
rock not related to foliation or cleavage in metamorphic rock along
which there has been minimal movement. A fracture along which there
has been lateral displacement may be termed a fault. When walls of
a fracture have moved only normal to each other, the fracture may
be termed a joint. Fractures may enhance permeability of rocks
greatly by connecting pores together, and for that reason, joints
and faults may be induced mechanically in some reservoirs in order
to increase fluid flow. "Microfracture" refers to a fracture in a
formation that is less than about 0.5 mm in width and/or is too
small to accept a proppant.
[0036] "Hydrocarbons" are generally defined as molecules formed
primarily by carbon and hydrogen atoms. Hydrocarbons may also
include other elements such as, but not limited to, halogens,
metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons
may be, but are not limited to, kerogen, bitumen, pyrobitumen,
oils, natural mineral waxes, and asphaltites. Hydrocarbons may be
located in or adjacent to mineral matrices in the earth. Matrices
may include, but are not limited to, sedimentary rock, sands,
silicilytes, carbonates, diatomites, and other porous media.
"Hydrocarbon fluids" are fluids that include hydrocarbons.
Hydrocarbon fluids may include, entrain, or be entrained in
non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide,
carbon dioxide, hydrogen sulfide, water, and ammonia.
[0037] "Hydraulic fracturing" refers to creating or opening
fractures that extend from the wellbore into formations. A
fracturing fluid, typically viscous, is injected into the formation
with sufficient hydraulic pressure (for example, at a pressure
greater than the lithostatic pressure of the formation) to create
and extend fractures, open preexisting natural fractures, or cause
slippage of faults. In the formations discussed herein, natural
fractures and faults may be opened by the pressure. A proppant may
be used to "prop" or hold open the fractures after the hydraulic
pressure has been released. The fractures may be useful for
allowing fluid flow, for example, through a shale formation, or a
geothermal energy source, such as a hot dry rock layer, among
others.
[0038] "Perforations" include openings, slits, apertures, or holes
in a wall of a conduit, tubular, pipe or other flow pathway that
allow flow into or out of the conduit, tubular, pipe or other flow
pathway.
[0039] "Mudstone" refers to a fine grained sedimentary rock that
consists of compacted silica and clay minerals. "Calcareous
Mudstone" refers to a fine grained sedimentary rock that consists
of compacted silica, carbonate minerals and clay minerals.
[0040] "Relatively permeable" is defined, with respect to
formations or portions thereof, as an average permeability of 10
millidarcy or more (for example, 10 or 100 millidarcy).
[0041] "Relatively low permeability" is defined, with respect to
formations or portions thereof, as an average permeability of less
than about 10 millidarcy. One darcy is equal to about 0.99 square
micrometers. A low permeability layer generally has a permeability
of less than about 0.1 millidarcy.
[0042] "Shale" refers to a fine grained sedimentary rock that
consist of silica, clay, and carbonaceous minerals such as calcite
and dolomite.
[0043] Hydrocarbon fluid production using conventional techniques
from mudstone and calcareous hydrocarbon formations is difficult
due to the very low permeability (for example, less than 0.1
millidarcy) of the hydrocarbon containing formations.
[0044] The term "wellbore" refers to a hole in a formation made by
drilling or insertion of a conduit into the formation. A wellbore
may have a substantially circular cross section, or another
cross-sectional shape. As used herein, the terms "well" and
"opening," when referring to an opening in the formation may be
used interchangeably with the term "wellbore." "Horizontal
wellbore" refers to a portion of a wellbore in a subterranean
hydrocarbon containing formation to be completed that is
substantially horizontal or at an angle from horizontal in the
range of from about 0.degree. to about 15.degree..
[0045] Fracturing in low permeability formations has been developed
in recent years using horizontal wellbores, however, production of
hydrocarbons from these formations has proved difficult. Fracturing
of the low-permeability formations may allow efficient production
of hydrocarbons from the formation. Acid fracturing may allow the
low-permeability formation to be more easily fractured, however,
the acid may dissipate into the formation and not reach the end of
the formation and/or dissolve more of the formation than is
desired.
[0046] Once a fracture forms in the formation, the fracture may
close under stress unless the fracture size is increased or propped
open. The formed fractures, however, are generally not of
sufficient width to allow conventional proppants (for example, sand
or ceramic materials) to enter the fracture because the proppant
particles are too large. Fractures or microfractures that do not
have any proppant in the fracture tend to close when the well
starts production and may not contribute to hydrocarbon production.
Microfractures, however, are wide enough to allow acid to enter the
microfracture.
[0047] Furthermore, in very low permeability hydrocarbon formations
(for example, mudstone) natural barriers may contain a fracture so
that is does not generate a size (height or width).
[0048] Acidizing of low permeability formations after fracturing
has not proved successful. In the acidizing low permeability
formations the rapid reaction rate of the acidizing fluid with
those portions of the formation with which it first comes into
contact and does not penetrate into the formation. Thus, the acid
becomes spent before it penetrates into the formation a significant
distance from the fracture.
[0049] It has been unexpectedly found that permeability of a
mudstone hydrocarbon formation or a calcareous shale formation that
includes at least about 5 wt. %, about 10 wt. %, about 20 wt. %
about 50 wt. %, about 70 wt. %, or more of carbonate minerals is
enhanced using fracturing in combination with acid. In some
embodiments, an amount of carbonate materials in the low
permeability formation ranges from about 1% by weight to about 70%
by weight, from about 5% by weight to about 50% by weight or from
about 10% by weight to about 30% by weight. Examples of such
mudstone and calcareous shale formations are Bakken shale and the
Eagle Ford shale. In carbonaceous mudstones, treatment of a
fractured formation with acid may dissolve the carbonate minerals
after leaving behind the silica, clay minerals and organic material
to potentially prop open the fractures even if the fracture does
not contain any proppant.
[0050] The use of acid in the very low permeability formations
increases the open surface area of microfractures and the main
fracture and increase connectivity between the fractures. Thus,
production of hydrocarbons from the formation may be increased by
at least 20%, at least 30%, or at least 50% as compared to
production using conventional techniques.
[0051] In some embodiments, a portion of a very low permeable
formation that includes at least ten percent carbonate compounds
(for example, calcite or dolomite) is selectively treated with
acid. The acid may be an inorganic acid or an organic acid. For
example, the solution of acid may be an aqueous solution of
hydrochloric acid. Commonly, the aqueous solution of hydrochloric
acid employed for acidizing subterranean calcareous formations
contain between 5 and 28% by weight, between 7 and 20% by weight,
or between 10 and 15% by weight of hydrogen chloride. An aqueous
solution of acetic acid or formic acid may be used. In some
embodiments, the acid solution has a pH of less than about 6, less
than about 5, less than about 3, less than about 1, or less than
about 0.5.
[0052] The acid may be injected in the hydrocarbon containing
formation. Contact of the acid with carbonate mineral in the
formation may consume the carbonate minerals (for example, generate
carbon oxides) and leave behind siliciclastic minerals and organic
material. Asperities may be formed during acid treatment and the
formed asperities may allow the fracture to remain conductive. This
is in contrast to carbonate formations where all or substantially
all of the rock matrix is dissolved. Leaving behind siliciclastic
minerals and organic material and or formation of asperities may
provide topographic relief to the fracture surface or microfracture
surface leading to the creation of open fracture and/or
microfracture pathways through which hydrocarbons may flow.
Treating the hydrocarbon containing formation with acid may
increase conductivity in the formation by creating a connectivity
between fractures and/or associated microfractures. In some
embodiments, treatment of the hydrocarbon containing formation with
acid may increase the conductivity of the main fracture by
non-uniform etching of its surface, which creates rough fracture
surfaces with asperities that do not allow the fracture to close
under stress.
[0053] In some embodiments, the acid is injected with shale
stabilizing chemicals. Shale stabilizing materials include, but are
not limited to, quaternary ammonium salts, inorganic salts such as
sodium chloride and potassium chloride and/or potassium acetate.
Examples of shale stabilization fluids are described in U.S. Patent
Application No. 20010259588 to Ali et al. For example, a solution
of acid, quaternary ammonium salt and/or water may be injected into
a mudstone formation. Injection of acid and/or shale stabilizing
chemicals may stabilize the shale, and thus, make the shale less
susceptible to softening and/or reduce proppant embedment as
compared to conventional methods (for example, water based
fracturing). Softening of the shale may result in a loss in
conductivity of the fracture.
[0054] In some embodiments, an acid solution is injected as an
emulsion or a foam. Injecting the acid as a foam or an emulsion may
reduce the reactivity of the acid.
[0055] In some embodiments, the dissolution and/or selective
dissolution of carbonate compounds may change the mechanical
properties of the rock. For example, the rock may be weakened. A
change in mechanical properties may allow a change in the amount of
pressure (for example, less pressure) needed to propagate the
fracture and/or associated fractures. Thus, allowing different
fracture patterns to be formed in the formation as compared to
conventional fracturing methods.
[0056] In some embodiments, a fracture and/or associated
microfractures are formed in the hydrocarbon formation using
conventional fracturing and well stimulating methods (for example,
hydraulic fracturing, pneumatic fracturing, alternating fracturing
("Texas-Two Step"), zipper fracturing, forced tip screen out, or
the like) in conjunction with acid. For example, a horizontal
wellbore may be provided to a wellbore, a first section of the
formation may be fractured, the well may be plugged at the first
formation and a second fracture may be formed at a second location
along the well. In some embodiments, the fracturing is performed
using solutions that have a pH of greater than about 6, great than
about 7 or greater than about 7.5. After one or more fractures have
been formed, acid may injected into the wellbore and the fractures
acidized and etched as desired. The acid may be placed in any or
all of the fracturing fluid stages, the pad, the main proppant
stages, etc., or before or after the fracture is placed. The acid
may have a pH of less than about 6, less than about 5 or less than
about 1.
[0057] Acidizing the fractures removes the carbonate from the
formation and increases the size of the fracture and
microfractures. Increasing the size of the fracture, may inhibit
the fractures from closing. Seismic and/or microseismic technology
may be used to assess the size and/or shape of fractures formed in
the formation. Acid may injected until a desired fracture size (for
example, width) is obtained. In some embodiments, a fracture has a
width of greater than 1 mm, greater than 10 mm or greater than 1
cm. Due to the increased size of the fractures, proppants may not
be necessary or the amount proppants is reduced. In some
embodiments, a surface of the main fracture may be etched. In some
embodiments, acid increases the width of some the microfractures to
enhance insertion of proppant into the microfracture network.
[0058] In some embodiments, hydraulic fractures are created in a
particular sequence to enhance microfracturing (or microcracking)
of the formation (for example, zipper fracturing and alternate
fracturing). In zipper fracturing, two parallel horizontal wells
are fractured sequentially one fracture at a time while alternating
between wells. Treatment of zipper fractures with acid may open the
microfractures to create conductive fractures and thus, allow
hydrocarbons to flow through the formation. For example, in the
"Texas Two Step" method (alternate fracturing method), fracturing
fluid (for example, fluid having a pH of greater than 5) is pumped
into fractures in a sequence of 1, 3, 5, 7, 9, 2, 4, 6, 8 rather
than the sequence 1, 3, 2, 5, 4 with the numbers representing the
sequence of the fractures along a well starting at the toe. These
types of fracturing in conjunction with the acid may lead to
conductive microfractures. In some embodiments, acid is used in
conjunction with and fracturing sequence to promote formation of
microfractures and secondary fractures.
[0059] In some embodiments, injection of acid into a fractured
formation may stabilize the formation (for example, a mudstone or
shale formation) and inhibit softening of the formation. For
example, the formation may harden due to the acid treatment.
Hardening the formation may reduce proppant embedment as compared
to conventional methods and/or prevent a loss of conductivity of
the fracture.
[0060] FIG. 1 depicts a schematic representation of an embodiment
of a low permeability formation being treated with acid after
forming a fracture in the formation. In some embodiments,
fracturing is not performed and the acid is injected directly into
the low permeability formation. FIG. 2 depicts a schematic
representation of the formation in FIG. 1 (nonacid treated
fractured formation) after treatment with acid. FIG. 3 is a
scanning electron microscope picture of a portion of a calcareous
mudstone or shale formation before and after treatment with acid.
FIGS. 4A-D depict the elemental composition of different portions
of an embodiment of an acid treated mudstone or shale formation.
FIG. 4A depicts the total elemental composition of silicon (data
114, red dots), calcium (data 116, green dots) and carbon (data
118, blue dots), an embodiment of an acid treated mudstone or shale
formation. FIG. 4B depicts the carbon composition of the mudstone
or shale formation of FIG. 4A (i.e., FIG. 4A with the silicon and
calcium removed). FIG. 4C depicts the calcium composition of the
mudstone or shale formation of FIG. 4A (i.e., FIG. 4A with the
silicon and carbon removed). FIG. 4D depicts the silicon
composition of the mudstone or shale formation of FIG. 4A (i.e.,
FIG. 4A with the calcium and carbon removed).
[0061] In some embodiments, a size and location of the fractures in
a low permeability formation may be determined prior to or after
providing acid to the hydrocarbon containing formation. Wellbore
100 may be located in a layer 102 under the overburden 104 of a
hydrocarbon containing layer 106 (for example, a mudstone or
calcareous formation). Wellbore 100 may be horizontal or
substantially horizontal. In some embodiments, wellbore 100 in
provided to a natural fracture or a formed fracture in the
formation. In some embodiments, a size and location of the
fractures 108 and/or microfractures 110 in a low permeability
formation may be determined prior to, during, or after treatment of
the hydrocarbon containing formation 102. In some embodiments,
microfractures 110 are adjacent or proximate to fractures 108.
[0062] Acid may be introduced into formation 110 through injection
wellbore 100. Injection wellbore 110 may include packers and/or
other plugs that allow the acid to follow into selected portions of
the formation. Acid may contact carbonate near or proximate the
wellbores and dissolve a portion of the formation near or proximate
fractures 108 or microfractures 110 to increase the size (for
example, length and/or width) of the fracture as shown in FIGS. 2
and 3. Referring to FIGS. 4B through 4D, the calcium concentration
(data 116 green dots) is much less in than in the acid treated
portion of the mudstone or shale formation. The concentration of
silicon (red dots, data 114, FIG. 4D) and carbon (blue, dots, data
118) remains the same. Such increased permeability may allow
connectivity between fractures and allow hydrocarbons to be
mobilized through the fractures. Thus, a conductivity of the
hydrocarbon layer is increased as compared to conventional acid
fracturing techniques. In certain embodiments, the microfractures
open and interconnect.
[0063] In some embodiments, a fracturing fluid is injected under
high pressure through the wellbore to create fractures 108 and/or
microfractures 110. Creation of fractures 108 and microfractures
110 may be done prior to or after injection of acid into the
formation. Microfractures 110 may extend from fracture 108.
[0064] The process may be repeated to create additional fractures
in the formation. In some embodiments, the newly created fractures
connect with the fractures formed with acid. In some embodiments,
acid is injected in one portion of the low permeability formation.
The acid may increase the size of microfractures and allow the acid
to flow into the microfractures or fractures in a second portion of
the hydrocarbon formation. The acid may etch a surface of fractures
and microfractures. Etching the surface may increase the
conductivity of the fracture. In some embodiments, the width of the
microfractures and/or the fractures 108 in the second portion may
increases after contact with acid. Opening of the microfractures in
the second portion of the hydrocarbon layer may increase
conductivity between the first and second portions of the
hydrocarbon layers.
[0065] Mobilized hydrocarbons (for example, gas and liquids) may be
produced from the treated formation. For example, fluids may flow
from the microfractures into a production wellbore and be produced
from the formation. In some embodiments, fluids are injected into
the formation after formation of the fractures to mobilize
hydrocarbons. Fluids may include steam, water, gas, or compound
known in the art to for drive processes. Fluids may flow into
wellbore 100 and be produced from the formation. In some
embodiments, injection wellbore 108 is a production wellbore. In
certain embodiments, hydrocarbon fluids are produced from different
portion of the formation.
[0066] In some embodiments, a hydrocarbon formation (for example, a
mudstone or shale formation) is treated with fluids having
different viscosities and/or elasticity. Malhotra et al., in
"Proppant Placement Using Alternate-Slug Formation," SPE 16385,
Presented at the SPE Hydraulic Fracturing Technology Conference, TX
Feb. 4-6, 2013, describes treatment of hydrocarbon formations
having different viscosities and/or elasticity.
[0067] In some embodiments, the fluids injected into the formation
include proppants. At least one of the fluids is a mixture of acid
and water. High viscosity and low viscosity fluids may be
alternately pumped into the formation. In some embodiments,
proppants are carried by the low viscosity fluid. A high viscosity
fluid (for example, a linear or cross-linked gel) is pumped into
the formation. After a period of injection, a second fluid having a
lower viscosity than the first fluid (for example, a water based
acid solution) may be injected into the formation. The low
viscosity fluid may disperse (e.g., finger) through the more
viscous fluid, placing the acid deeper into fracture in a
non-uniform manner
[0068] FIG. 5 depicts a schematic of an embodiment of injecting
high and low viscosity fluids in a hydrocarbon formation. First
fluid 120 is injected into microfracture 112 of formation 102
through vertical wellbore 100. In some embodiments, wellbore 100 is
a substantially horizontal or deviated wellbore in formation 102.
In some embodiments, first fluid 120 is injected into fracture 108
and then disperses into microfracture 112. First fluid 120 is a
high viscosity fluid that disperses through formation 102. After
injection of the first fluid 120, low viscosity second fluid 122 is
injected into fracture 108. In some embodiments, second fluid 122
is an acidic solution. Second fluid 122 disperses through the more
viscous first fluid 120 in microfracture 112 in a non-uniform
manner represented by fingers 124. The mixing of the two fluids may
be governed by the mixing zone velocity and finger velocity. A
mixing zone refers to the length over which the local concentration
varies from 0 (concentration of first fluid) to 1 (concentration of
second fluid). For example, length 126 in FIG. 5 represents a
mixing zone. A mixing zone velocity is the rate of change of mixing
zone length. A finger velocity refers to the ratio of finger-tip
velocity to the injection velocity (injection rate dived by the
cross-sectional area).
[0069] After a second injection, a third fluid having a higher
viscosity fluid than the second fluid may be injected into the
formation. The third fluid may have the same viscosity or a
different viscosity than the viscosity of the first fluid. The
higher viscosity fluid may move the acidic fluid deeper into the
fracture and into the microfractures. The injection of the
alternating fluids, therefore, leads to a deeper and, in some
embodiments, a non-uniform distribution of acid into the formation,
(for example, as shown by fingers 124 in FIG. 5). Contact of the
acid with the microfractures may widen the fractures to allow
hydrocarbons to flow from the fractures. Thus, microfractures deep
in the formation may be widened to allow production of hydrocarbon
from the formation. In some embodiments, microfractures are widened
sufficiently to allow proppants to be placed in the widened
fractures. In some embodiments, softening of the formation at
deeper depths in the formation is inhibited.
[0070] In some embodiments, when the acid solution (low viscosity
fluid) contains proppants, a proppant bed may form near the
injection point due to higher settling rate of proppants in the low
viscosity fluid. Injecting a higher viscosity fluid may displace
the proppant bed deeper into the fracture and into the
microfractures. The injection of the alternating fluids, therefore,
leads to a deeper and non-uniform distribution of acid and/or
proppants in the fracture.
[0071] In some embodiments, dissolution of carbonate minerals from
the rock results in a softening of the rock leading to closure of
propped and un-propped fractures by softer organic material (such
as kerogen and bitumen) and clays. In some embodiments, the acid
solution may contain an organic solvent (such as methanol, ethanol
or iso-propyl alcohol) that will solubilize and remove this organic
material. Removal of a portion of the softer organic material may
result in a higher propped or un-propped fracture permeability
after dissolution of the carbonate minerals. In some embodiments,
the organic solvent is injected with the non-acidic fluid.
[0072] Further modifications and alternative embodiments of various
aspects of the invention will be apparent to those skilled in the
art in view of this description. Accordingly, this description is
to be construed as illustrative only and is for the purpose of
teaching those skilled in the art the general manner of carrying
out the invention. It is to be understood that the forms of the
invention shown and described herein are to be taken as the
presently preferred embodiments. Elements and materials may be
substituted for those illustrated and described herein, parts and
processes may be reversed, and certain features of the invention
may be utilized independently, all as would be apparent to one
skilled in the art after having the benefit of this description of
the invention. Changes may be made in the elements described herein
without departing from the spirit and scope of the invention as
described in the following claims.
* * * * *