U.S. patent application number 14/350517 was filed with the patent office on 2014-09-18 for hydraulic fracturing with proppant pulsing through clustered abrasive perforations.
The applicant listed for this patent is Prad Research and Development Limited, Schlumberger Holdings Limited, Schlumberger Technology B.V., SCHLUMBERGER TECHNOLOGY CORPORATION, Services Petroliers Schlumberger. Invention is credited to Konstantin Burdin, Fedor Nikolaevich Litvinets, Konstantin Mikhailovich Lyapunov, Alejandro Pena, Alexey Yudin.
Application Number | 20140262263 14/350517 |
Document ID | / |
Family ID | 48082735 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262263 |
Kind Code |
A1 |
Yudin; Alexey ; et
al. |
September 18, 2014 |
HYDRAULIC FRACTURING WITH PROPPANT PULSING THROUGH CLUSTERED
ABRASIVE PERFORATIONS
Abstract
Well completion techniques are disclosed that combine the
creation of perforation clusters created using abrasive-jet
perforation techniques with hydraulic fracturing techniques that
include proppant pulsing through the clustered abrasive jet
perforations. Both the abrasive-jet perforation and hydraulic
fracturing with proppant pulsing may be carried out through coiled
tubing.
Inventors: |
Yudin; Alexey; (Tyumen,
RU) ; Lyapunov; Konstantin Mikhailovich;
(Novosibirsk, RU) ; Litvinets; Fedor Nikolaevich;
(Biysk, RU) ; Burdin; Konstantin; (Tyumen, RU)
; Pena; Alejandro; (Katy, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research and Development Limited |
Sugar Land
Paris
Tortola
The Hague
Tortola |
TX |
US
FR
VG
NL
VG |
|
|
Family ID: |
48082735 |
Appl. No.: |
14/350517 |
Filed: |
October 11, 2012 |
PCT Filed: |
October 11, 2012 |
PCT NO: |
PCT/US12/59645 |
371 Date: |
April 8, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61627429 |
Oct 12, 2011 |
|
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|
Current U.S.
Class: |
166/280.1 |
Current CPC
Class: |
E21B 29/00 20130101;
E21B 43/267 20130101; E21B 43/26 20130101; E21B 43/114
20130101 |
Class at
Publication: |
166/280.1 |
International
Class: |
E21B 43/267 20060101
E21B043/267; E21B 29/00 20060101 E21B029/00 |
Claims
1. A method for perforating and fracturing of a subterranean
formation with a wellbore lined with casing extending through at
least part of the formation, the method comprising: forming a first
cluster of at least one perforation through the casing and into the
formation with hydro-abrasive jets; injecting a proppant-free
fracturing fluid into the wellbore through the first cluster;
combining the proppant-free fracturing fluid with a proppant to
form a first proppant-laden slurry and alternatingly and repeatedly
injecting the first proppant-laden slurry followed by injecting the
proppant-free fracturing fluid into the wellbore and through the
first cluster.
2. The method of claim 1 further including: combining one of the
proppant-free fracturing fluid with additional proppant to provide
one or more additional proppant-laden slurries of varying
concentrations of proppant and for each additional proppant-laden
slurry, alternatingly and repeatedly injecting each additional
proppant-laden slurry followed by injecting the proppant-free
fracturing fluid into the wellbore and through the at least one
cluster.
3. The method of claim 1 wherein the one or more additional
proppant-laden slurries have a different concentration of proppant
than the first proppant-laden slurry.
4. The method of claim 1 further including: forming a second
cluster of at least one perforation through the casing and into the
formation with hydro-abrasive jets, wherein the second cluster is
spaced apart from the first cluster by a nonperforated interval;
injecting the proppant-free fracturing fluid into the wellbore
through the first and second clusters simultaneously; alternatingly
and repeatedly injecting the first proppant-laden slurry followed
by injecting the proppant-free fracturing fluid into the wellbore
and through first and second clusters simultaneously.
5. The method of claim 1, wherein the non-perforated interval has a
length ranging from about 10 cm to about 5 m.
6. The method of claim 1 wherein the first and second clusters each
include from about 1 to about 10 perforations.
7. The method of claim 1 further including: forming from 1 to about
100 additional clusters; injecting the proppant-free fracturing
fluid into the wellbore through all of the clusters simultaneously;
alternatingly and repeatedly injecting the first proppant-laden
slurry followed by injecting the proppant-free fracturing fluid
into the wellbore and through all of the clusters
simultaneously.
8. The method of claim 1, wherein the injecting of each of the
first proppant-laden slurry followed by the injecting of the
proppant-free fracturing fluid is carried out over a series of
substantially uniform pulses.
9. The method of claim 1, wherein the fracturing fluid also
includes fibers.
10. The method of claim 3, wherein the fracturing fluid also
comprises fibers.
11. The method of claim 6, wherein the fracturing fluid also
comprises fibers.
12. The method of claim 1 wherein the forming of the first cluster
and the is performed through coiled tubing and the alternatingly
and repeatedly injecting of the first proppant-laden slurry
followed by injecting the proppant-free fracturing fluid into the
wellbore and through first cluster is performed through an annulus
between the coiled tubing and the casing.
13. A method for perforating and fracturing of a subterranean
formation with a wellbore lined with casing extending through at
least part of the formation, the method comprising: (a) forming a
first cluster through the casing and into the formation with
hydro-abrasive jets; (b) injecting a proppant-free fracturing fluid
into the wellbore through the first cluster of perforations; (c)
combining the proppant-free fracturing fluid with a proppant to
form a first proppant-laden slurry; (d) injecting the first
proppant-laden slurry through the first cluster; (e) repeating
parts (b) and (d) in an alternating fashion.
14. The method of claim 13 further including: (a)(1) forming a
second cluster through the casing and into the formation with
hydro-abrasive jets, with a nonperforated interval being disposed
between the first and second clusters; (b)(1) injecting the
proppant-free fracturing fluid into the wellbore and through the
first and second clusters simultaneously; and (d)(1) injecting the
first proppant-laden slurry through the first and second clusters
simultaneously (e)(1) repeating parts (b)(1) and (d)(1) in an
alternating fashion.
15. The method of claim 14 wherein the non-perforated interval has
a length ranging from about 10 cm to about 5 m.
16. The method of claim 13 further including: forming from 1 to
about 100 additional clusters; injecting the proppant-free
fracturing fluid into the wellbore through all of the clusters
simultaneously; alternatingly and repeatedly injecting the first
proppant-laden slurry followed by injecting the proppant-free
fracturing fluid into the wellbore and through all of the clusters
simultaneously.
17. The method of claim 13 wherein the forming of the first cluster
is performed through coiled tubing and the injecting of the first
proppant-laden slurry and proppant-free fracturing fluid are
carried out through an annulus between the casing and the coiled
tubing.
18. The method of claim 13 wherein the forming of the first and
second clusters is performed through coiled tubing and the
injecting of the first proppant-laden slurry and proppant-free
fracturing fluid are carried out through an annulus between the
casing and the coiled tubing.
19. A method for perforating and fracturing of a subterranean
formation with a wellbore lined with casing extending through at
least part of the formation, the method comprising: forming from 2
to about 100 clusters of perforations with abrasive-jets with
nonperforated intervals disposed between each cluster; injecting a
proppant-free fracturing fluid into the wellbore through the
clusters; combining the proppant-free fracturing fluid with a
proppant to form a first proppant-laden slurry and alternatingly
and repeatedly injecting the first proppant-laden slurry followed
by injecting the proppant-free fracturing fluid into the wellbore
and through the clusters; combining one of the proppant-free
fracturing fluid or the first proppant-laden slurry with additional
proppant to provide additional proppant-laden slurries of varying
concentrations of proppant and for each additional proppant-laden
slurry, alternatingly and repeatedly injecting each additional
proppant-laden slurry followed by injecting the proppant-free
fracturing fluid into the wellbore and through the first and second
clusters.
20. The method of claim 19, wherein the non-perforated interval has
a length ranging from about 10 cm to about 5 m, and wherein
clusters each include from about 1 to about 10 perforations.
Description
BACKGROUND
[0001] Hydrocarbons (oil, natural gas, etc.) are obtained from a
subterranean geological formation by drilling a well that
penetrates the hydrocarbon-bearing formation. This provides a
partial flow path for the hydrocarbon to reach the surface. In
order for the hydrocarbon to be "produced," that is, travel from
the formation to the wellbore and ultimately to the surface, there
must be a sufficiently unimpeded flow path.
[0002] Hydraulic fracturing is a primary tool for improving well
productivity by placing or extending highly conductive fractures
from the wellbore into the reservoir. During the first stage,
hydraulic fracturing fluid is injected through wellbore into a
subterranean formation at high rates and pressures. The fracturing
fluid injection rate exceeds the filtration rate into the formation
producing increasing hydraulic pressure at the sand face. When the
pressure exceeds a critical value, the formation strata or rock
cracks and fractures. The formation fracture is more permeable than
the formation porosity.
[0003] During the next stage, proppant is deposited in the fracture
to prevent it from closing after injection stops. The resulting
propped fracture enables improved flow of the recoverable fluid,
i.e., oil, gas or water. Many other proppants may be used such as
sand, gravel, glass beads, walnut shells, ceramic particles,
sintered bauxites and other materials including bearings of
spherical, cylindrical or irregular shapes.
[0004] Hydraulic fracturing fluids are aqueous solutions containing
a thickener, such as a soluble polysaccharide, to provide
sufficient viscosity to transport the proppant. Typical thickeners
are polymers, such as guar (phytogeneous polysaccharide), and guar
derivatives (hydropropyl guar, carboxymethylhydropropyl guar).
Other polymers can be used also as thickeners. Water with guar
represents a linear gel with a viscosity that increases with
polymer concentration. Cross-linking agents are used which provide
engagement between polymer chains to form sufficiently strong
couplings that increase the gel viscosity and create
visco-elasticity. Common crosslinking agents for guar include
boron-, titanium-, zirconium-, and aluminum-laden chemical
compounds.
[0005] Fibers can be used to enhance the ability of the fracturing
fluids to transport proppant and to mitigate proppant settling
within the hydraulic fracture. For operations in which proppant is
pumped in slugs or pulses, fibers can also be used to mitigate the
dispersion of the proppant slugs as they travel throughout the well
completion and into the fracture.
[0006] Proppant flow back control agents can also be used during
the latter stages of the hydraulic fracturing treatment to limit
the flow back of proppant placed into the formation. For instance,
the proppant may be coated with a curable resin activated under
down hole conditions. Different materials, such as bundles of
fibers, or fibrous or deformable materials, also have been used to
retain proppants in the fracture. Presumably, fibers form a
three-dimensional network in the proppant pack that limits its flow
back.
[0007] The success of a hydraulic fracturing treatment depends upon
hydraulic fracture conductivity and fracture length. Fracture
conductivity is the product of proppant permeability and fracture
width; units are typically expressed as millidarcy-feet. Fracture
conductivity is affected by a number of known parameters. Proppant
particle size distribution is one key parameter that influences
fracture permeability. The concentration of proppant between the
fracture faces is another (expressed in pounds of proppant per
square foot of fracture surface) and influences the fracture width.
One may consider high-strength proppants, fluids with excellent
proppant transport characteristics (ability to minimize
gravity-driven settling within the fracture itself), high-proppant
concentrations, or big proppants as means to improve fracture
conductivity. Weak materials, poor proppant transport, and narrow
fractures all lead to poor well productivity. Relatively
inexpensive materials of little strength, such as sand, are used
for hydraulic fracturing of formations with small internal
stresses. Materials of greater cost, such as ceramics, bauxites and
others, are used in formations with small to moderate closure
stresses. Materials of greater cost, such as ceramics, bauxites and
others, are used in formations with higher closure stresses.
[0008] The proppant pack must create a conduit having a higher
hydraulic conductivity than the surrounding formation rock. The
proppant pack within the fracture is often modeled as a permeable
porous structure, and the flow of formation fluids through this
layer is generally described using the well-known Darcy's law (1)
or Forscheimer's equation (2):
.differential.P/.differential.x=-(.mu.u/k); (1)
.differential.P.differential.x=-[(.mu.u/k)+.beta..rho.u.sup.2],
(2)
[0009] where
[0010] P is a fluid pressure in the fracture;
[0011] x is a distance along the fracture from the wellbore;
[0012] .mu. is a viscosity of the formation fluid;
[0013] u is a flow (filtration) speed of the formation fluid;
[0014] k is a permeability of the proppant pack;
[0015] .beta. is a coefficient referred to as beta-factor that
describes non-linear corrections to the Darcy's filtration law;
and
[0016] .rho. is a density of the formation fluid.
[0017] The result of multiplying fracture permeability by fracture
width is referred to as "hydraulic conductivity". The most
important aspect of fracture design is optimization of the
hydraulic conductivity for a particular formation's conditions.
[0018] A fracture optimization process will strike a balance among
the proppant strength, hydraulic fracture conductivity, proppant
distribution, cost of materials, and the cost of executing a
hydraulic fracturing treatment in a specific reservoir. The case of
large proppant particle sizes illustrates compromises made during
an optimization process. A significant hydraulic fracture
conductivity increase is possible using large diameter proppants.
However, at a given internal formation stress, large diameter
proppants crush to a greater extent when subjected to high fracture
closure stresses, leading to a decrease in the effective hydraulic
conductivity of the proppant pack. Further, the larger the proppant
particles, the more they are subjected to bridging and trapping in
the fracture near the injection point.
[0019] U.S. Pat. No. 6,776,235, "Hydraulic Fracturing Method",
which is hereby incorporated by reference discloses a method and
means for optimizing fracture conductivity. The well productivity
is increased by sequentially injecting into the wellbore alternate
stages of fracturing fluids having a contrast in their ability to
transport propping agents to improve proppant placement, or having
a contrast in the amount of transported propping agents. The
propped fractures obtained following this process have a pattern
characterized by a series of bundles of proppant spread along the
fracture. In another words, the bundles form "pillars" that keep
the fracture opens along its length but provide a lot of channels
for the formation fluids to circulate.
[0020] Hydro-abrasive methods for surface treatment and cutting are
often used for cutting perforation holes or slots in casing and
formation instead of using explosive cumulative charges or milling
cutters.
[0021] Devices for cutting slots in a formation with a
hydro-abrasive jet may include a perforator hung on tubing inside
of a well with a hydro-abrasive jet generator located on ground
surface. The perforator may include two opposite side oriented
nozzles directed to wall of the well. A hydro-abrasive slurry may
be prepared in a hydro-abrasive jet generator and pumped through
tubing and down hole to perforator. Other abrasive perforating
devices are known in the art.
SUMMARY OF THE DISCLOSURE
[0022] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is this
summary intended to be used as an aid in limiting the scope of the
claimed subject matter.
[0023] For purposes of this disclosure, the terms perforation and
station are interchangeable and the term perforation will be used.
On the other hand, a cluster may include one or more perforations.
If the cluster includes a plurality of perforations, the
perforations are grouped relatively close together and typically,
are formed simultaneously using an abrasive jet perforations tool
with a plurality of nozzles. A plurality of clusters would refer to
individual clusters (i.e., one or more perforations) separated by
an unperforated interval.
[0024] In one aspect, a method for perforating and fracturing of a
subterranean formation with a wellbore lined with casing extending
through at least part of the formation. The disclosed method may
include forming at least one cluster of perforation(s) through the
casing and into the formation with hydro-abrasive jets. The
disclosed method may further include injecting a proppant-free
fracturing fluid into the wellbore through the cluster. The
disclosed method may also include combining the proppant-free
fracturing fluid with a proppant to form a first proppant-laden
slurry and alternatingly and repeatedly injecting the first
proppant-laden slurry followed by injecting the proppant-free
fracturing fluid into the wellbore and through the cluster of
perforations. The method may also include repeating the combining
of the proppant-free fracturing fluid with the proppant to provide
additional (i.e., second, third, fourth, etc.) proppant-laden
slurries of varying proppant concentrations, alternatingly and
repeatedly injecting each additional proppant-laden slurry followed
by injecting the proppant-free fracturing fluid into the wellbore
and through the cluster of perforations. The method may also
include forming additional cluster(s) through the casing and into
the formation with hydro-abrasive jets, wherein the additional
cluster(s) are spaced apart from the other cluster(s) by a
non-perforated interval. The disclosed method may also include
treating all clusters simultaneously with the proppant-free
fracturing fluid followed by the proppant-laden slurries as
discussed above.
BRIEF DESCRIPTION OF THE DRAWINGS
[0025] FIG. 1 illustrates a plurality of discreet perforation
clusters separated by non-perforated intervals that may be formed
by abrasive-jet perforating.
[0026] FIG. 2 illustrates an annular fracturing and abrasive-jet
perforating tool.
[0027] FIG. 3 graphically illustrates a fracturing pumping schedule
in accordance with this disclosure.
[0028] FIG. 4 is a photograph of a cavern or perforation made by an
abrasive-jet technique.
[0029] FIG. 5 is a flow diagram illustrating a perforation and
pumping schedule in accordance with this disclosure.
DETAILED DESCRIPTION
[0030] This disclosure is directed to the combination of improved
abrasive-jet perforation techniques which enables the creation of
discreet clusters of perforations separated by nonperforated
intervals followed by improved hydraulic fracturing techniques
which include proppant pulsing. Anywhere from one to 100 or more
clusters may be treated together and each cluster may include from
one to 20 or more perforations. Each cluster may be up to 5 m or
more in length and the nonperforated intervals may range from about
10 cm to about 5 m or more in length. The abrasive-jet perforating
may optionally be performed through coiled tubing and the
subsequent fracturing techniques may optionally be performed
through an annulus created by the coiled tubing and the casing. Of
course, other techniques may be employed as will be apparent to
those skilled in the art.
[0031] Abrasive-jet perforation may have advantages over cumulative
perforation in the respect that abrasive-jet perforating can allow
for a selective approach to perforating cluster location and a
nonperforated interval between perforation clusters. Abrasive-jet
perforation may also allow for significantly reduced amount of
perforations inside the casing, but may still provide risk-free
proppant admittance due to the large surface area of the caverns
created inside the cement and the formation by abrasive-jet
perforation techniques. Further, such caverns may connect the
wellbore with the fracture.
[0032] In an embodiment, an abrasive perforating scheme may include
clusters of perforations of up to 5 meters long and also may
include non-perforated intervals between the clusters that can from
about 10 cm to 5 m or more in length. The number of clusters for
the fracturing treatment can vary from 1 to 100, or any suitable
number, depending upon such factors as formation thickness,
wellbore deviation and fracture design parameters. The number
perforations in each cluster may vary from 1 to 20 or more, or any
suitable number, depending upon such factors as formation
characteristics and fracturing treatment design specifics. In one
instance, each cluster may include from 1 to 6 perforations or
caverns created in azimuthally different directions by fluid jet
flow through nozzles of the perforator. An illustration of such a
perforation scheme is shown in FIG. 1 and an illustration of an
abrasive-jet perforating device is shown in FIG. 2
[0033] FIG. 1 shows a sectional view of a wellbore 10 that is been
lined with casing 11 with the annular space disposed between the
casing and the formation 12 being filled with cement 13. FIG. 1
illustrates a plurality of perforation clusters 14 that, in the
embodiment illustrated in FIG. 1, each include from one to four
perforations 15 that form caverns that extend through the cement 13
and into the formation 12. The clusters 14 may be separated from
one another by nonperforated intervals 16. While each cluster 14
may be treated separately using the improved hydraulic fracturing
techniques disclosed below, each cluster 14 may also be treated
simultaneously using the disclosed hydraulic fracturing
techniques.
[0034] An abrasive-jet perforating tool 19 for forming the clusters
14 shown in FIG. 1 is illustrated in FIG. 2. The tool 19 includes a
collar locator/centralizer 20, a connector 22, and a sand jetting
sub 23. The collar locator/centralizer 20 is connected beneath
connector 22, which may be used to attach the tool 19 to coiled
tubing (not shown) or another tool string (not shown). The collar
locator 20 is used to determine when the tool 19 is within a
particular zone of interest in the well based on collars 24 located
in the well casing 11 (FIG. 1). Although the embodiment of FIG. 2
includes a collar locator/centralizer 20, this device may be one of
a various number of down hole devices used to determine the
location of a down hole assembly within a wellbore 10. The
disconnect tool 22 may releasably connect the tool 19 to the bottom
end of a coiled tubing, tool string, drill pipe, wire line, etc. A
reverse check valve with a bull nose 25 is disposed at a distal end
of the tool 19.
[0035] Once the tool 19 has been located within the new zone of
interest and the sand jetting sub 23 is positioned at the proper
location, an abrasive laden fluid may be pumped at a high pressure
through the jetting ports 27 on the exterior of the sand jetting
sub 23. For example, 20/40 Ottowa sand may be pumped through the
sand jetting sub 23 to create perforations 15 through the casing 11
at the desired locations as shown in FIG. 1. Using 20/40 Ottowa
sand pumped through the sand jetting sub 23 may perforate the
casing 11 and cement 13 at the zone of interest in as little as
twenty minutes. The tool 19 may also be used to perforate tubing as
would be appreciated by one of ordinary skill in the art having the
benefit of this disclosure. The configuration of the jetting ports
27 of the sand jetting sub 23 may be varied to change the number
and locations of perforations created by the sand jetting sub 23.
The configuration of the individual jetting ports 27 may also be
changed to modify the cutting power of the sand jetting sub 23.
[0036] After the casing 11 (or tubing) has been perforated as shown
in FIG. 1, the tool 19 may be withdrawn from the wellbore 10 or, if
the tool 19 is disposed at an end of a coiled tubing (not shown),
the tool may be moved away from the perforations 15 to provide a
sufficient annular flow path to allow stimulation of the
perforations 15.
[0037] Fracturing fluid is pumped down the casing 11 at a high
pressure in an attempt to generate fractures through the
perforations 15 in the zones of interest.
[0038] In a hydraulic fracturing method for a subterranean
formation, a first stage referred to as the "pad stage" involves
injecting a fracturing fluid into a wellbore at a sufficiently high
flow rate that it creates a hydraulic fracture in the formation.
The pad stage is pumped until the fracture is of sufficient
dimensions to accommodate the subsequent slurries pumped in the
proppant stages. The volume of the pad can be designed by those
knowledgeable in the art of fracture design.
[0039] Water-based fracturing fluids are common with natural or
synthetic water-soluble polymers added to increase fluid viscosity
and are used throughout the pad and subsequent propped stages.
These polymers include, but are not limited to, guar gums;
high-molecular-weight polysaccharides composed of mannose and
galactose sugars; or guar derivatives, such as hydropropyl guar,
carboxymethyl guar, and carboxymethylhydropropyl guar.
Cross-linking agents based on boron, titanium, zirconium or
aluminum complexes are typically used to increase the polymer's
effective molecular weight making it better suited for use in
high-temperature wells.
[0040] To a small extent, cellulose derivatives, such as
hydroxyethylcellulose or hydroxypropylcellulose and
carboxymethylhydroxyethylcellulose, are used with or without
cross-linkers. Two biopolymers--xanthan and scleroglucan--prove
excellent proppant-suspension ability, but are more expensive than
guar derivatives and so are used less frequently. Polyacrylamide
and polyacrylate polymers and copolymers are used typically for
high-temperature applications or as friction reducers at low
concentrations for all temperatures ranges.
[0041] Polymer-free, water-base fracturing fluids can be obtained
using viscoelastic surfactants. Usually, these fluids are prepared
by mixing in appropriate amounts of suitable surfactants, such as
anionic, cationic, nonionic and Zwiterionic. The viscosity of
viscoelastic surfactant fluids are attributed to the
three-dimensional structure formed by the fluid's components. When
the surfactant concentration in a viscoelastic fluid significantly
exceeds a critical concentration, and in most cases in the presence
of an electrolyte, surfactant molecules aggregate into species,
such as worm-like or rod-like micelles, which can interact to form
a network exhibiting viscous and elastic behavior.
[0042] After the "pad stage", several stages, referred to as
"propping stages", are injected into formation. A propping stage
involves the periodical introduction into the fracturing fluid in
the form of solid particles or granules to form a suspension. The
propped stage is divided into two periodically repeated sub-stages,
the "carrier sub-stage" involves injection of the fracturing fluid
without proppant; and the "propping sub-stage" involves addition of
proppant into the fracturing fluid. As a result of the periodic
slugging of slurry containing granular propping materials, the
proppant doesn't completely fill the fracture. Rather, spaced
proppant clusters form as posts with channels between them through
with formation fluids pass. The volumes of propping and carrier
sub-stages as pumped may be different. That is the volume of the
carrier sub-stages may be larger or smaller than the volume of the
propping sub-stages. Furthermore the volumes of these sub-stages
may change over time. That is, a propping sub-stages pumped early
in the treatment may be of a smaller volume than a propping
sub-stage pumped latter in the treatment. The relative volume of
the sub-stages is selected by the engineer based on how much of the
surface area of the fracture he desires to be supported by the
clusters of proppant, and how much of the fracture area is open
channels through which formation fluids are free to flow. As non
limiting example, the volume of carrier sub-stage or propping
sub-stage can be zero.
[0043] A sample pumping schedule for a propped stage is shown in
Table 1 below. Table 1:
TABLE-US-00001 TABLE 1 Pump Fluid Prop Prop Slurry Pump Dirty Clean
Rate volume Conc. mass volume time pulse pulse Stage m.sup.3/min
m.sup.3 kgPA kg m.sup.3 min sec sec Cycles PAD 3.18 79.5 0 0 79.5
25 0 1500 0 1 PPA 3.18 3.9 120 228 3.9 1.2 12.4 12.4 2 2 PPA 3.18
7.4 240 854 7.6 2.4 12 12.0 6 3 PPA 3.18 6.1 359 1033 6.4 2.0 12
12.0 5 4 PPA 3.18 10.7 479 2401 11.4 3.6 12 12.0 9 5 PPA 3.18 11.8
589 3233 12.7 4.0 12 12.0 10 6 PPA 3.18 11.6 719 3766 12.7 4.0 12
12.0 10 7 PPA 3.18 18.3 839 6829 20.4 6.4 12 12.0 16 TAIL-IN 3.18
0.8 839 711 1.1 0.3 20 0 0 FLUSH 3.18 6.2 0 0 6.2 1.9 0 116.5 0
Another pumping schedule is illustrated graphically in FIG. 3. In
Table 1 and FIG. 3, "dirty pulse` refers to "propping sub-stage"
and "clean pulse" refers to "carrier sub-stage". Referring to FIG.
3, the first stage, known as the pad stage is shown at 31. A
plurality of proppant stages are shown at 32-37 wherein, each
proppant stage 32, 33, 34, 35, 36 represents the injection of a
proppant-laden fracturing fluid having increasing concentrations of
proppant. Within each stage, 32, 33, 34, 35, 36, pulses of "clean"
fracturing fluid is followed by pulses of "dirty" or proppant-laden
fracturing fluid (or slurry). The .DELTA.t for each pulse may vary
widely from the example of 12 seconds given in Table 1. For
example, the clean and dirty pulse times may range from about 5
seconds to a minute or longer, also pulse times in the range of
from about 5 seconds to about 30 seconds may be preferred. The
final tail-in stage is shown at 37 and has zero volume of clean
pulse.
[0044] Some concepts in support of such an abrasive perforation
scheme to promote channel creation inside fracture after treatment
with proppant pulsing technique include the following: (1) The
near-wellbore area is the most critical zone for proppant
admittance (high tangential stresses). The disclosed technique may
allow for reliable proppant admittance and reduction of risk for
proppant bridging. This can be achieved even with a lower number of
holes inside the casing than the number of holes that would be
needed with a cumulative perforation technique. The reduced number
of holes inside casing would be achieved by the geometry of the
abrasive cavern--which has larger contact area with the fracture
relative to the contact area generated from a channel developed
with the cumulative perforation technique. An abrasive cavern is
created without excessive temperatures or pressures and without
damaging the surface around it. (2) Due to better proppant
admittance, it is possible to decrease total number of perforation
holes without increasing risk of proppant bridging (one perforation
hole per cluster in some cases) to increase diverting pressure
resulting in enhancement of injection profile (all clusters admit
slurry). Better division of a proppant pulse into smaller
structures is achieved by clusters at the wellbore, before slurry
enters the fracture. (3) Decreasing number of perforations within a
given perforation interval can be beneficial in completions where
several fractures are to be initiated during fracturing fluid
injection. An example is initiation of several transverse fractures
in a horizontal wellbore where one fracture is to be initiated
through each perforation cluster. The more perforations are created
within a cluster, the less predictable the number of initiated
fractures is. If the number of perforations within a cluster is not
enough for adequate proppant admittance (e.g. cumulative
perforations), then no fracture may be created at a given cluster.
If the number of perforations is too large, then more than one
fracture can be created within one cluster. Accurate estimation of
number of fractures created is necessary for proper design of
fracturing job. For example number of created fractures can affect
choice of duration for "propping sub-stage" and "carrier
sub-stage". Hence, using of abrasive perforations with small number
of holes within a cluster can result in more reliable design of the
fracturing treatment. (4) Clusters can be tailored in their
separation one from another to ensure optimal channel creation.
Clusters sizes, distances between clusters, hole density,
variations of hole density inside specific cluster, hole sizes,
variations of hole sizes inside of specific cluster can be readily
customized to fit changes of geomechanical properties of formation
if abrasive perforation is used. One of characteristics of a
perforation gun is shot density. Inverse value to shot density is
shot spacing or distance between shots. If conventional perforation
guns are used than cluster height and distance between clusters
should be multiple to shot spacing. Abrasive perforation does not
have such limitations. Hole size and perforation channel geometry
in cumulative perforation depends on thickness of casing, charge
type and rock properties. For cumulative perforation, parameters
such as hole size and channel geometry are limited by gun and
charge specifications. In case of abrasive perforation, slurry rate
and duration of cutting can be chosen during treatment to customize
hole size and cavern geometry
[0045] Reinforcing and/or consolidating material may be introduced
into the fracture fluid during the propped stage to increase the
strength of the proppant clusters formed and prevent their collapse
during fracture closure. Typically the reinforcement material is
added to the propping sub-stage, but this may not necessarily be
always the case. The concentrations of both propping and the
reinforcing materials can vary in time throughout the propping
stage, and from sub-stage to sub-stage. That is, the concentration
of reinforcing material may be different at two subsequent
sub-stages. It may also be suitable in some applications of the
present method to introduce the reinforcing material in a
continuous fashion throughout the propped stage, both during the
carrier and propping sub-stages. In other words, introduction of
the reinforcing material isn't limited only to the propping
sub-stage. Particularly, different implementations may be
preferable when the reinforcing material's concentration doesn't
vary during the entire propped stage; monotonically increases
during the propped stage; or monotonically decreases during the
propped stage.
[0046] Curable or partially curable, resin-coated proppant may be
used as reinforcing and consolidating material to form proppant
clusters. The selection process of the appropriate resin-coated
proppant for a particular bottom hole static temperature (BHST),
and the particular fracturing fluid are well known to experienced
workers. In addition, organic and/or inorganic fibers can reinforce
the proppant cluster. These materials can be used in combination
with resin-coated proppants or separately. These fibers could be
modified to have an adhesive coating alone; or an adhesive coating
coated by a layer of non-adhesive substance dissolvable in the
fracturing fluid as it passes through the fracture. Fibers made of
adhesive material may be used as reinforcing material, coated by a
non-adhesive substance that dissolves in the fracturing fluid as it
passes through the fracture at the subterranean temperatures.
Metallic particles are another preference for reinforcing material
and may be produced using aluminum, steel containing special
additives that reduce corrosion, and other metals and alloys. The
metallic particles may be shaped to resemble a sphere and measure
0.1-4 mm. Preferably, metallic particles are used of an elongated
shape with a length longer than 0.5 mm and a diameter of 10 to 200
microns. Additionally, plates of organic or inorganic substances,
ceramics, metals or metal-based alloys may be used as reinforcing
material. These plates may be disk or rectangle-shaped and of a
length and width such that for all materials the ratio between
biggest and smallest dimensions is greater than 5 to 1.
[0047] Both the carrier and propping sub-stages may include
introduction of an agent into the fracturing fluid to increase the
proppant transport capability. In other words, reducing the
settling rate of proppant in the fracture fluid. The agent may be a
material with elongated particles whose length much exceeds their
diameter. This material affects the rheological properties and
suppresses convection in the fluid, which results in a decrease of
the proppant settling rate in the fracture fluid. Materials that
may be used include fibers that are organic, inorganic, glass,
ceramic, nylon, carbon and metallic. The proppant transport agents
may be capable of decomposing in the water-based fracturing fluid
or in the down hole fluid, such as fibers made on the basis of
polylactic acid, polyglycolic acid, polyvinyl alcohol, and others.
The fibers may be coated by or made of a material that becomes
adhesive at subterranean formation temperatures. They may be made
of adhesive material coated by a non-adhesive substance that
dissolves in the fracturing fluid as its passes through the
fracture. The fibers used can be longer than 0.5 mm with a diameter
of 10-200 microns, in accordance with the main condition that the
ratio between biggest and smallest dimensions is greater than 5 to
1. The weight concentration of the fibrous material in the
fracturing fluid is from 0.1 to 10%. The proppant should be chosen
with consideration to increasing the proppant clusters strength. In
an embodiment, the fibers may be made of polylactic acid,
polyglycolic acid or copolymers comprising lactic acid and/or
glycolic acid. In another embodiment, the fibers are added at a
concentration of 0.5 to 20 kg per m3 of fracturing fluid.
[0048] A proppant cluster should maintain a reasonable residual
thickness at the full fracture closure stress. This method provides
an increase in fluid inflow through open channels formed between
the proppant clusters. In this situation, a permeability value of
the proppant, as such, isn't decisive for increasing the well's
productivity using this method. Thus, a proppant cluster may be
created successfully using sand whose particles are too weak for
use in standard hydraulic fracturing in the present formation. Sand
costs substantially less than ceramic proppant. Additionally,
destruction of sand particles during application of the fracture
closure load might improve strength behavior of the same cluster
consisting of proppant granules. This can occur because the
cracking/destruction of proppant particles decreases the cluster
porosity thereby increasing the proppant compactness degree. Sand
pumped into the fracture to create proppant clusters doesn't need
good granulometric properties, that is, the narrow diameter
distribution of particles. For example, it is possible to use 50
tons of sand, wherein 10 to 15 tons have a diameter of particles
from 0.002 to 0.1 mm, 15 to 30 tons have a diameter of particles
from 0.2 to 0.6 mm, and 10 to 15 tons have a diameter of particles
from 0.005 to 0.05 mm. It should be noted that about 100 tons of a
proppant more expensive than sand would be necessary to obtain a
similar value of hydraulic conductivity in the created fracture
implementing the prior (conventional) method of hydraulic
fracturing.
[0049] It may be preferable to use sand with an adhesive coating
alone, or an adhesive coating coated by a layer of non-adhesive
substance dissolvable in the fracturing fluid as it passes through
the fracture. A non-adhesive substance guarantees that particles of
the adhesive proppant won't form agglomerates prior to entering the
fracture, and allows for control of a time moment (a place) in the
fracture when (where) a proppant particle gains its adhesive
properties. The adhesive coating is cured at the formation
temperature, and sand particles conglutinate between each other.
Bonding particles within the clusters reduces the proppant cluster
erosion rate as formation fluids flow past the cluster, and
minimizes proppant cluster destruction by erosion.
[0050] In some cases, the propping stage may be followed by a
proppant stage, referred to as the "tail-in stage" in FIG. 3, which
involves a continuous introduction of an amount of proppant. If
employed, the tail-in stage of the fracturing treatment resembles a
conventional fracturing treatment, where a continuous bed of
proppant is placed in the fracture relatively near to the wellbore.
The tail-in stage may involve introduction of both an agent that
increases the fluid's proppant transport capability and or an agent
that acts as a reinforcing material. The tail-in stage is
distinguished from the second stage by the continuous placement of
a well-sorted proppant, that is, a proppant with an essentially
uniform size of particles. The proppant strength is sufficient to
prevent its cracking (crumbling) when subjected to stresses that
occur at fracture closure. The role of the proppant at this stage
is to prevent fracture closure and, therefore, to provide good
fracture conductivity in proximity to the wellbore.
[0051] The disclosed hydraulic fracturing methods introduce one or
more agents into the treatment fluid to promote the formation of
proppant clusters in the fracture during pumping, while
continuously pumping propping agents. When the agent reacts it
causes the local formation of a proppant cluster. Typically the
agent is selected or designed such that its action or function is
delayed until it is placed within the fracture. Delaying chemical
and or physical reaction is a process commonly used in hydraulic
fracturing as well as many other industrial processes. One process
that can be used is the simple temperature activation of the agent
as the fracturing fluid heats up as it enters the higher
temperature formation deep in the earth. For example, ammonium
persulfate homolysis is relatively slow at surface temperatures of
20.degree. C., but relatively rapid at formation temperatures of
100.degree. C. A second process is a slow dissolution of a reactive
agent, or of a binder. For example, the dissolution ratio of
polyvinyl alcohol in water is dependent on its molecular weight.
Encapsulation of a reactive species is a common process employed in
hydraulic fracturing. The reactive material or agent is protected
for a time from the fracturing fluid by a relatively non-reactive
capsule. The encapsulated material subsequently releases the
reactive agent, either slowly or quickly by many different methods.
The encapsulation can be designed to release its contents by
dissolution, mechanical erosion, crushing swelling and rupturing,
or simply by slow diffusion.
[0052] The first stage of the fracturing treatment, the "pad stage"
(FIG. 3) is pumped as usual. Unlike the previous embodiment where
proppants were pumped discontinuously, the proppant (propping
agents) are pumped continuously. The concentration of the proppant
may increase, stay constant, or decrease during the propped stage.
Normally proppant concentrations start low, and are ramped up to
higher concentrations near the end of the treatment. The key to
this embodiment is that an agent causes the nucleation or formation
of proppant clusters is discontinuously or periodically introduced
into the fracturing fluid during the propped stage. The agent is
designed to work in only a small region or zone within the
fracture. Propping materials within this zone are influenced in
such a way that they form cluster, bridge out and become immobile.
In addition proppants that are pumped subsequent to the cluster
formation may accumulate on the cluster and make it grow in
size.
[0053] One way to generate clusters of proppant is to locally
reduce the ability of the fluid to transport solid phase particles.
In this case, the agent could be a high concentration of oxidative
"breakers", such as ammonium persulfate, that--when reacting with
the fracturing fluid at different places in the fracture--lead to
drastic and significant decreases in the fracturing fluid's local
viscosity. When fluid viscosity drops below a critical value, the
fracturing fluid is unable to transfer the proppant particles and
the particles stop, settle, and form proppant clusters. The
addition of fibers greatly enhances proppant cluster formation.
Encapsulated breakers with a long release time can be used at the
beginning of the propped stage, and encapsulated breakers with
short release times can be used at the end of the propped
stage.
[0054] Reinforcing materials such as fibers can greatly increase
the tendency of proppants to locally jam between the fracture walls
and form a cluster. Therefore, in this embodiment fibers and or
other reinforcing materials as discussed above may be added to the
fracturing fluid during the propped stage either continuously into
or discontinuously (at the same time as the breaker).
[0055] Requirements for proppant properties used in the first
embodiment apply in the second one as well. It's possible to use a
proppant without a narrow diameter distribution of particles, that
is, a poorly-sorted proppant with a relatively small strength value
per particle. For instance, there may be sand particles with
coatings similar to that described in the first embodiment of the
method. The above-mentioned third stage may also take place.
[0056] Chemical species that competitively bind the crosslinking
agents could be another type of agent used to locally reduce fluid
viscosity. The local release of chelants, (that react with
zirconate crosslinkers), sorbitol or polyvinylalcohol (that react
with borate crosslinkers) or other species that deactivate the
cross linker can cause the polymer gel to de-crosslink and
significantly reduce the fracturing fluid viscosity. Since many
crosslinking reactions are pH dependent, the localized release of
an acid or base can also reduce fluid viscosity. For example, one
may manipulate the fracturing fluid pH through the introduction of
an encapsulated acid and/or particles of substances, for instance
polylactic acid or polyglycolic acid in which release or generation
of the acid occurs at a controlled rate. Changing the fracturing
fluid pH reduces the cross linker affinity to form stable bonds
with the polymer and the fluid viscosity decreases for certain
specific polymer cross linker combinations.
[0057] For said purposes, an encapsulated absorbent or competitive
chelating agent of the polymer chain cross-linker may be used also,
which allows for controlled release. Cross-linked gel chemicals,
such as sodium gluconate or sorbitol, may be used for a borate. For
metal crosslinkers, such as titanates or zirconates, chemicals
including but not limited to EDTA, NTA, phosphates, polyvinyl
acetates may be used. Selection of the specific chemical to attack
the cross linker in question are well known to skilled workers.
Such absorbents may be, for instance, phosphates or polyvinyl
acetates.
[0058] The agent that provides proppant cluster formation by
decreasing the fracturing fluid's local viscosity may also
represent chemical substances that react with the fracturing fluid
to provide a significant amount of local heat extraction, resulting
in heating the fracturing fluid and thereby decreasing its local
viscosity. Examples of such substances include explosives or
encapsulated reactive metals such as sodium, that release the
substance in various places in the fracture to provide proppant
cluster formation throughout the length of the fracture.
[0059] Proppant clusters and channels between the clusters may be
formed by reducing proppant mobility in the fracture. This method
includes the pad and propping stages described above, but differs
in that the agents that produce cluster formations decrease
mobility of proppant particles.
[0060] Specifically, the additives may be fiber bundles that slowly
expand and shed individual fibers due to mechanical agitation. The
increased excluded volume of the bundle and the localized increase
in fiber concentration can initiate jams and create of proppant
clusters.
[0061] The additives may be also cut wires made of an alloy
possessing "shape memory" properties. For example
Copper-Aluminum-Nickel (CuAlNi) shape memory alloys function over
the temperature range of many oil and gas-bearing formations. These
materials may be bent to shape small balls (springs) and retain
their shape at surface temperature. When heated to reservoir
temperature, the material with "shape memory" undergoes phase
transition accompanied by recovery of its original memorized
straight-line shape. Phase transition temperature variation is
possible by varying the alloy composition. It may be preferable to
introduce a material whose phase transition temperature varies from
portion to portion. At the beginning of the propped stage, for
instance, it may be reasonable to introduce materials with the
highest phase transition temperature, for example, slightly less
than the formation temperature; and at the end of the second stage
in may be reasonable to introduce a material having the lowest
phase transition temperature, for example, slightly more than the
surface fluid temperature. Balls of the material with "shape
memory" are usually similar in size to proppant particles.
[0062] When the metal balls are subjected to an elevated
temperature in the fracture, they recover their original shape,
that is, they straighten. As noted above, local increase of their
contents effectively promotes formation of proppant clusters in the
fracture. The ability to vary the shape recovery temperature
gradually by varying the alloy composition allows formation of
wires and thereby immovable clusters of proppant distributed
uniformly throughout the length of the fracture.
[0063] The use of super-absorbing material to form local jams in
the flowing fracturing fluid may also be employed. Super-absorbents
such as cross-linked polyacrylamide polyacrylate copolymers can
adsorb an amount of water 100 to 300 times their weight in water. A
wide variety of super-absorbents are available. Selection of a
particular one may be determined by such factors as formation
temperature, salt content of the water used to prepare the
fracturing fluid, and others.
[0064] A super-absorbent may be used that is protected by a shell
or emulsion that is dissolved or dispersed at its passes through
the fracture or upon elevation of the fracturing fluid temperature,
or a combination of these conditions. By varying shell thickness,
it is possible to control the time span between introduction of a
portion of the super-absorbent into the fracturing fluid and its
release from the shell. When the shell dissolves or is dispersed,
an absorbing particle begins its growth by absorbing water from its
surroundings. Increasing the mass and size of particles decelerates
their movement through the fracture and ultimately results in local
jams, capture of proppant particles, and formation of proppant
clusters.
[0065] Additives may also be used to decrease proppant mobility in
the fracture may be granules, fibers, or plates whose surface
becomes "adhesive" at formation temperatures. Additional coating of
particles with adhesive surfaces with a layer of a non-adhesive
substance dissolvable in the fracturing fluid may be preferable; by
varying the substance thickness, the time span can be varied whose
lapse gives rise to formation of proppant clusters due to their
surface adhesive properties. Another technique for controlling time
span employs coatings that gain adhesive properties at different
temperatures. It may be preferable to introduce particles with a
maximum thickness of protective coating (thus with a maximum
temperature of demonstrating "adhesive" properties) at the
beginning of the second stage. And be preferable to introduce
respectively particles with a minimum thickness of a protective
coating (thus with a minimum temperature of demonstrating
"adhesive" properties) at the end of the second stage. When such
particles enter the fracture, they collide (bump) and conglutinate
forming agglomerates of proppant particles. When the agglomerates
size become comparable with the characteristic width of the
fracture, they wedge between the fracture faces causing local
proppant jams and formation of proppant clusters.
[0066] Using reinforcing materials with the fracturing fluid may
also be employed, thus increasing the strength of the formed
proppant clusters; and introducing agents that increase the fluid's
proppant transport ability by decreasing the proppant settling rate
through the fracturing fluid. All these requirements for proppant
selection, particularly for use of a proppant that is relatively
moderately strong, a (possibly) wide distribution of particle
sizes, the proppant coated preliminarily with a binder layer
curable under formation conditions, remain applicable.
[0067] The formation of proppant clusters and channels between them
by sequentially pumping two fluids with contrasting viscosities
into the wellbore may be employed. This method involves a pad stage
as discussed above, and the propping stage involves continuous
introduction of proppant into a given fluid. Similar to the
previous embodiments, the propping stage may involve introducing
reinforcing materials into the fracturing fluid, these materials
increasing the strength of the formed proppant clusters; and
introducing an agent that increases the fluid's proppant transport
ability by decreasing the proppants settling rate. All requirements
for proppant selection, particularly the use of a proppant with a
relatively moderate strength, a wide size distribution of
particles, and preliminarily coated with a binder layer curable
under formation conditions, are still applicable.
[0068] Then the injection of proppant-containing fracturing fluid
together with other materials is terminated, and a fluid of very
low viscosity is injected into the created fracture. Owing to the
difference between their viscosities, injection of the
lower-viscosity fluid after injection of the more viscous fluid
results in penetrating the lower-viscosity fluid into the more
viscous fluid in the form of "intrusions". This forms channels in
the proppant that fills the fracture dividing the proppant into
discrete clusters.
[0069] As discussed above, a fourth "tail-in" stage may involve a
continuous introduction of a proppant with essentially uniform
particle size, a reinforcing material, and/or a material with
elongated particles that increase the proppant transport ability of
the fracturing fluid into the fluid.
[0070] All methods for hydraulic fracturing described above and
with different mechanisms to form proppant clusters provide very
high hydraulic fracture conductivity. This occurs through the
formation of strong proppant clusters well spaced throughout the
fracture's length and height. The clusters are stable enough to
prevent the fracture from closing; and the inter-cluster channels
have a sufficiently large cross-section for formation fluids to
flow.
INDUSTRIAL APPLICABILITY
[0071] FIG. 5 is a flow diagram illustrating another disclosed
combination of abrasive jet perforating and improved hydraulic
fracturing techniques. Part 41 signifies the placement of the
disclosed perforating tool 19 into the wellbore 10. The tool 19 is
located within the zone of interest in part 42. An initial
perforation cluster 14 is created within abrasive jet at part 43.
In part 44, the tool 19 is relocated to a new zone of interest. In
part 45, a new cluster 14 is perforated. In part 46, fracturing
fluid without proppant is pumped down the casing 11. This is
referred to above as the pad stage, which is also illustrated FIG.
3. Then, in part 47, proppant-laden slurry is pumped down the
casing 11 and parts 46 and 47 are repeated sequentially for a given
proppant concentration in part 48 as illustrated in FIG. 3. Then,
another proppant-laden slurry is pumped down the casing 11 in part
49 followed by pumping clean fracturing fluid in part 50. Parts
49-50 may then be repeated in part 51 and the pattern set forth in
FIG. 3 may be followed.
[0072] Although only a few example embodiments have been described
in detail above, though skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from the spirit and scope of this
disclosure. Features shown in individual embodiments referred to
above may be used together in combinations other than those which
have been shown and described specifically. Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims.
* * * * *