U.S. patent application number 14/103203 was filed with the patent office on 2015-06-11 for method of treating a subterranean formation.
This patent application is currently assigned to Schlumberger Technology Corporation. The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Andrey Bogdan, Chad Kraemer, Bruno Lecerf, Dmitriy Usoltsev.
Application Number | 20150159477 14/103203 |
Document ID | / |
Family ID | 53270639 |
Filed Date | 2015-06-11 |
United States Patent
Application |
20150159477 |
Kind Code |
A1 |
Lecerf; Bruno ; et
al. |
June 11, 2015 |
METHOD OF TREATING A SUBTERRANEAN FORMATION
Abstract
A method of treating a subterranean formation, involving
performing a fracturing operation and performing a shut in. At a
time before or after the shut in is commenced, changes in
properties at or near a fracture are estimated based upon monitored
data. A plugging agent is injected taking into consideration the
estimated changes in properties.
Inventors: |
Lecerf; Bruno; (Houston,
TX) ; Kraemer; Chad; (Katy, TX) ; Usoltsev;
Dmitriy; (San Antonio, TX) ; Bogdan; Andrey;
(Sugar Land, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Assignee: |
Schlumberger Technology
Corporation
Sugar Land
TX
|
Family ID: |
53270639 |
Appl. No.: |
14/103203 |
Filed: |
December 11, 2013 |
Current U.S.
Class: |
166/250.1 |
Current CPC
Class: |
E21B 43/267
20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 47/00 20060101 E21B047/00; E21B 33/13 20060101
E21B033/13 |
Claims
1. A method of treating a subterranean formation penetrated by a
wellbore comprising: performing a fracturing operation by
introducing a treatment fluid into the wellbore at a fluid pressure
equal to or greater than a fracture initiation pressure of the
subterranean formation to induce a fracture in the subterranean
formation; estimating changes in fracture geometry by monitoring
data from one or more sensors while the fracture is open;
performing a shut-in by stopping injection of the treatment fluid;
and introducing a plugging agent, after performing the shut-in,
plugging the induced fracture; wherein the plugging agent is
introduced after a period of time, the period of time being
determined based upon the monitored data.
2. The method according to claim 1, wherein the plugging agent is
introduced into the wellbore after the shut-in is performed.
3. The method according to claim 1, wherein the plugging agent is
introduced into the wellbore before the shut-in is performed.
4. The method according to claim 1, wherein the plugging agent
includes a diverter pill.
5. The method according to claim 1, wherein the period of time is
from 5 minutes to 12 hours.
6. The method according to claim 1, wherein the period of time is
from 15 minutes to 2 hours.
7. The method according to claim 1, wherein the estimating the
changes in the fracture geometry occurs in real-time by monitoring
real-time data.
8. The method according to claim 1, wherein a width of the fracture
is decreased to a value smaller than the size of the plugging
agent.
9. The method according to claim 1, further comprising generating
tubewaves on surface, wherein the monitored data comprises data
acquired while monitoring tubewave reflections from the
fracture.
10. The method according to claim 9, wherein the low-frequency
pressure waves comprise one or more pulses.
11. The method according to claim 9, wherein the plugging agent is
introduced at a time when the change in values of the tubewave
reflections reach a threshold amount.
12. The method according to claim 9, further comprising resuming
the introduction of the treatment fluid into the wellbore at a
fluid pressure equal to or greater than the fracture initiation
pressure of the subterranean formation.
13. The method according to claim 9, wherein the monitoring data
comprises monitoring a fluid pressure change in the wellbore after
the shut-in is initiated.
14. The method according to claim 13, wherein the fluid pressure
change is determined by plotting a G function plot.
15. The method according to claim 13, further comprising
determining fluid leakoff based upon the monitored fluid pressure
change in the wellbore.
16. A method of monitoring a portion of a subterranean formation,
comprising: performing a fracturing operation by introducing a
treatment fluid into the wellbore at a fluid pressure equal to or
greater than a fracture initiation pressure of the subterranean
formation to induce a fracture in the subterranean formation;
generating tubewaves on surface, wherein the tubewaves comprise one
or more pulses; detecting a change in reflection of the pulses to
thereby determine a characteristic of the fracture of the
subterranean formation in real-time; and introducing a plugging
agent.
17. The method according to claim 16, wherein the characteristic of
the fracture of the subterranean formation includes whether a width
of an opening of the fracture has decreased by a predetermined
amount.
18. The method according to claim 16, wherein the introducing
further comprises introducing a plugging agent when the
characteristic of the fracture of the subterranean formation has
reached a threshold amount.
19. The method according to claim 18, wherein the plugging agent is
a diverter pill.
20. A method of monitoring a portion of a subterranean formation,
comprising: performing a fracturing operation by introducing a
treatment fluid into the wellbore at a fluid pressure equal to or
greater than a fracture initiation pressure of the subterranean
formation to induce a fracture in the subterranean formation;
monitoring a fluid pressure change in the wellbore of the
subterranean formation; and treating the fracture in the
subterranean formation at a time that is calculated based on when
the fluid pressure change in the wellbore reaches a threshold
value.
21. The method according to claim 20, wherein the threshold value
of the pressure change is a value calculated by plotting a G
function plot and determining where a measured pressure deviates
from linearity.
22. The method according to claim 20, wherein treating the fracture
includes introducing a plugging agent into an induced fracture.
23. The method according to claim 22, wherein the plugging agent is
pumped at a pressure lower than the fracture initiation pressure.
Description
BACKGROUND
[0001] Hydrocarbons, such as oil, condensate and gas, are often
produced from wells that are drilled into the formations containing
them. Oftentimes, the flow of hydrocarbons into the well may be
low, at least because of inherently low permeability of the
reservoirs or damage to the formation caused by the drilling and
completion of the well. To allow for desirable hydrocarbon flow,
various treatments, such as hydraulic fracturing or acid fracturing
may be performed.
[0002] Hydraulic fracturing and acid fracturing of horizontal wells
and multi-layered formations often involve using diverting
techniques in order to enable fracturing redirection between
different zones. Diverting methods may include using mechanical
isolation devices such as packers and well bore plugs, setting
bridge plugs, pumping ball sealers, and pumping slurred benzoic
acid flakes and removable and/or degradable particulates.
[0003] Diversion treatments using particulates may be based on
bridging of particles of the diverting material behind casing and
forming a plug by accumulating the rest of the particles at the
formed bridge. In these treatments, some concerns such as reducing
bridging ability of diverting slurry during pumping because of
dilution with wellbore fluid, using large quantities of diverting
materials, and poor stability of some diverting agents during
pumping and later treatments may be encountered. Additionally, when
an induced fracture is open, there includes a risk that solid
particles used for diverting will not actually bridge over the
fracture, and the particles may be lost within the fracture.
[0004] Performing a diversion treatment with solid particulates may
be achieved when the downhole features are narrow, so as to avoid a
concern of losing particulates within large, wide open fractures.
However, controlling or determining the width of a downhole feature
in a near-wellbore region may be difficult. It is difficult to
control a width of an induced fracture when fracturing a well, at
least because of the large amount of uncertainty in properties of
portions of the formation. Further, a plugging agent often carries
particular limitations regarding its size and loading, which may
lead to plugging agents that may not be capable of plugging a
particular fracture width.
SUMMARY
[0005] 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, not is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0006] The statements made merely provide information relating to
the present disclosure, and may describe some embodiments
illustrating the subject matter of this application.
[0007] In a first aspect, a method for treating a subterranean
formation penetrated by a wellbore is disclosed. The method
includes performing a fracturing operation by introducing a
treatment fluid into the wellbore at a fluid pressure equal to or
greater than a fracture initiation pressure of the subterranean
formation to induce a fracture in the subterranean formation. The
method further includes estimating changes in fracture geometry by
monitoring data from one or more sensors while the fracture is
open, performing a shut-in by stopping injection of the treatment
fluid and introducing a plugging agent. The plugging agent may be
introduced after performing the shut-in, so as to plug an induced
fracture. The period of time after which the plugging agent is
introduced may be determined based upon the monitored data.
[0008] In a second aspect, a method for monitoring a portion of a
subterranean formation is disclosed. The method includes performing
a fracturing operation by introducing a treatment fluid into the
wellbore at a fluid pressure equal to or greater than a fracture
initiation pressure of the subterranean formation to induce a
fracture in the subterranean formation. The method further includes
generating tubewaves on surface from one or more pulses, and
detecting a change in reflection of the pulse(s) to thereby
determine a characteristic of the fracture of the subterranean
formation in real-time, and introducing a plugging agent.
[0009] In a third aspect, a method of monitoring a portion of a
subterranean formation is disclosed. The method includes performing
a fracturing operation by introducing a treatment fluid into the
wellbore at a fluid pressure equal to or greater than a fracture
initiation pressure of the subterranean formation to induce a
fracture in the subterranean formation. The method further includes
monitoring a fluid pressure change in the wellbore of the
subterranean formation, and treating the fracture in the
subterranean formation at a time that is calculated based on when
the fluid pressure change in the wellbore reaches a threshold
value.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 shows a graphical depiction of a G-plot according to
one or more embodiments herein.
[0011] FIG. 2 shows a graphical depiction of a pressure plot
according to one or more embodiments herein.
[0012] FIG. 3 shows a graphical depiction of pulsation reflection
according to one or more embodiments herein.
[0013] FIG. 4 shows a graphical depiction of a treatment plot
according to one or more embodiments herein.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0014] In the following description, numerous details are set forth
to provide an understanding of the present disclosure. However, it
may be understood by those skilled in the art that the methods of
the present disclosure may be practiced without these details and
that numerous variations or modifications from the described
embodiments may be possible.
[0015] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation-specific
decisions may be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the composition
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a range listed or described as being useful, suitable, or the like,
is intended to include support for any conceivable sub-range within
the range at least because every point within the range, including
the end points, is to be considered as having been stated. For
example, "a range of from 1 to 10" is to be read as indicating each
possible number along the continuum between about 1 and about 10.
Furthermore, one or more of the data points in the present examples
may be combined together, or may be combined with one of the data
points in the specification to create a range, and thus include
each possible value or number within this range. Thus, (1) even if
numerous specific data points within the range are explicitly
identified, (2) even if reference is made to a few specific data
points within the range, or (3) even when no data points within the
range are explicitly identified, it is to be understood (i) that
the inventors appreciate and understand that any conceivable data
point within the range is to be considered to have been specified,
and (ii) that the inventors possessed knowledge of the entire
range, each conceivable sub-range within the range, and each
conceivable point within the range. Furthermore, the subject matter
of this application illustratively disclosed herein suitably may be
practiced in the absence of any element(s) that are not
specifically disclosed herein.
[0016] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description.
[0017] The methods of the present disclosure may be used to treat
at least a portion of a subterranean formation. The term "treat,"
"treatment," or "treating," does not imply any particular action by
the fluid. For example, a treatment fluid placed or introduced into
a subterranean formation may be a hydraulic fracturing fluid, an
acidizing fluid (acid fracturing, acid diverting fluid), a
stimulation fluid, a sand control fluid, a completion fluid, a
wellbore consolidation fluid, a remediation treatment fluid, a
cementing fluid, a driller fluid, a frac-packing fluid, or gravel
packing fluid.
[0018] While the embodiments described herewith refer to well
treatment it is equally applicable to any well operations where
zonal isolation is desired, such as drilling operations, workover
operations, and the like. In some embodiments, the methods of the
present disclosure may include preventing overdisplacement of a
proppant that enters a fracture by forming a removable plug from
the plugging agent in the fracture. Such methods are described in
"Methods For Minimizing Overdisplacement of Proppant in Fracture
Treatments," to Bruno Lecerf et al. (concurrently filed herewith),
the disclosure of which is incorporated by reference herein in its
entirety.
[0019] As used herein, the term "wellbore" refers to a drilled hole
or a borehole, including an openhole or uncased portion of a well.
A wellbore may be any type of well, including, a producing well, a
non-producing well, an injection well, a fluid disposal well, an
experimental well, an exploratory deep well, and the like.
Wellbores may be vertical, horizontal, deviated some angle between
vertical and horizontal, and combinations thereof, for example a
vertical well with a non-vertical component.
[0020] As used herein, the term "treatment fluid," refers to any
known pumpable and/or flowable fluid used in a subterranean
operation in conjunction with a desired function and/or for a
desired purpose. As used herein, a "pill" is a type of relatively
small volume of specially prepared treatment fluid placed or
circulated in the wellbore.
[0021] As used herein, the term "plugging agent" or "removable
plugging agent" may refer to a solid or fluid that may plug or
fill, either partially or fully, a portion of a subterranean
formation. The portion to be filled may be a fracture that is
opened by a hydraulic or acid fracturing treatment.
[0022] The removable plugging agents may be any materials, such as
solid materials (including, for example, degradable solids and/or
dissolvable solids), that may be removed within a desired period of
time. In some embodiments, the removal may be assisted or
accelerated by a wash containing an appropriate reactant (for
example, capable of reacting with one or more molecules of the
plugging agent to cleave a bond in one or more molecules in the
plugging agent), and/or solvent (for example, capable of causing a
plugging agent molecule to transition from the solid phase to being
dispersed and/or dissolved in a liquid phase), such as a component
that changes the pH and/or salinity. In some embodiments, the
removal may be assisted or accelerated by a wash containing an
appropriate component that changes the pH and/or salinity. The
removal may also be assisted by an increase in temperature, for
example when the treatment is performed before steam flooding,
and/or a change in pressure.
[0023] In some embodiments, the removable plugging agent materials
may be degradable material and/or a dissolvable material. A
degradable material refers to a material that will at least
partially degrade (for example, by cleavage of a chemical bond)
within a desired period of time such that no additional
intervention is used to remove the plug. For example, at least 30%
of the removable material may degrade, such as at least 50%, or at
least 75%. In some embodiments, 100% of the removable material may
degrade. The degradation of the removable material may be triggered
by a temperature change, and/or by chemical reaction between the
removable material and another reactant. Degradation may include
dissolution of the removable material.
[0024] Removable materials for use as the plugging agent may be in
any suitable shape: for example, powder, particulates, beads,
chips, or fibers. When the removable material is in the shape of
fibers, the fibers may have a length of from about 2 to about 25
mm, such as from about 3 mm to about 20 mm. In some embodiments,
the fibers may have a linear mass density of about 0.111 dtex to
about 22.2 dtex (about 0.1 to about 20 denier), such as about 0.167
to about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers
may degrade under downhole conditions, which may include
temperatures as high as about 180.degree. C. (about 350.degree. F.)
or more and pressures as high as about 137.9 MPa (about 20,000 psi)
or more, in a duration that is suitable for the selected operation,
from a minimum duration of about 0.5, about 1, about 2 or about 3
hours up to a maximum of about 24, about 12, about 10, about 8 or
about 6 hours, or a range from any minimum duration to any maximum
duration.
[0025] The removable materials may be sensitive to the environment,
so dilution and precipitation properties should be taken into
account when selecting the appropriate removable material. The
removable material used as a sealer may survive in the formation or
wellbore for a sufficiently long duration (for example, about 3 to
about 6 hours). The duration should be long enough for wireline
services to perforate the next pay sand, subsequent fracturing
treatment(s) to be completed, and the fracture to close on the
proppant before it completely settles, providing an improved
fracture conductivity.
[0026] Further suitable removable materials and methods of use
thereof include those described in U.S. Patent Application
Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the
disclosures of which are incorporated by reference herein in their
entireties. Such materials include inorganic fibers, for example of
limestone or glass, but are more commonly polymers or co-polymers
of esters, amides, or other similar materials. They may be
partially hydrolyzed at non-backbone locations. Any such materials
that are removable (due in-part because the materials may, for
example, degrade and/or dissolve) at the appropriate time under the
encountered conditions may also be employed in the methods of the
present disclosure. For example, polyols containing three or more
hydroxyl groups may be used. Suitable polyols include polymeric
polyols that solubilizable upon heating, desalination or a
combination thereof, and contain hydroxyl-substituted carbon atoms
in a polymer chain spaced from adjacent hydroxyl-substituted carbon
atoms by at least one carbon atom in the polymer chain. The polyols
may be free of adjacent hydroxyl substituents. In some embodiments,
the polyols have a weight average molecular weight from about 5000
to about 500,000 Daltons or more, such as from about 10,000 to
about 200,000 Daltons.
[0027] Further examples of removable materials include
polyhdroxyalkanoates, polyamides, polycaprolactones,
polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl
alcohols, polyethylene oxide (polyethylene glycol), polyvinyl
acetate, partially hydrolyzed polyvinyl acetate, and copolymers of
these materials. Polymers or co-polymers of esters, for example,
include substituted and unsubstituted lactide, glycolide,
polylactic acid, and polyglycolic acid. For example, suitable
removable materials for use as plugging agents include polylactide
acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate;
polyethylene; polyhydroxyalkanoates, such as
poly[R-3-hydroxybutyrate],
poly[R-3-hydroxybutyrate-co-3-hydroxyvalerate],
poly[R-3-hydroxybutyrate-co-4-hydroxyvalerate], and the like;
starch-based polymers; polylactic acid and copolyesters;
polyglycolic acid and copolymers; aliphatic-aromatic polyesters,
such as poly(.epsilon.-caprolactone), polyethylene terephthalate,
polybutylene terephthalate, and the like; polyvinylpyrrolidone;
polysaccharides; polyvinylimidazole; polymethacrylic acid;
polyvinylamine; polyvinylpyridine; and proteins, such as gelatin,
wheat and maize gluten, cottonseed flour, whey proteins,
myofibrillar proteins, casins, and the like. Polymers or
co-polymers of amides, for example, may include
polyacrylamides.
[0028] Removable materials, such as, for example, degradable and/or
dissolvable materials, may be used in the plugging agent at high
concentrations (such as from about 20 lbs/1000 gal to about 1000
lbs/1000 gal, or from about 40 lbs/1000 gal to about 750 lbs/1000
gal) in order to form temporary plugs or bridges. The removable
material may also be used at concentrations at least 4.8 g/L (40
lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2
g/L (60 lbs/1,000 gal). The maximum concentrations of these
materials that can be used may depend on the surface addition and
blending equipment available.
[0029] Suitable removable plugging agents also include dissolvable
materials and meltable materials (both of which may also be capable
of degradation). A meltable material is a material that will
transition from a solid phase to a liquid phase upon exposure to an
adequate stimulus, which is generally temperature. A dissolvable
material (as opposed to a degradable material, which, for example,
may be a material that can (under some conditions) be broken in
smaller parts by a chemical process that results in the cleavage of
chemical bonds, such as hydrolysis) is a material that will
transition from a solid phase to a liquid phase upon exposure to an
appropriate solvent or solvent system (that is, it is soluble in
one or more solvent). The solvent may be the carrier fluid used for
fracturing the well, or the produced fluid (hydrocarbons) or
another fluid used during the treatment of the well. In some
embodiments, dissolution and degradation processes may both be
involved in the removal of the plugging agent.
[0030] Such removable materials, for example dissolvable, meltable
and/or degradable materials, may be in any shape: for example,
powder, particulates, beads, chips, or fibers. When the such
material is in the shape of fibers, the fibers may have a length of
about 2 to about 25 mm, such as from about 3 mm to about 20 mm. The
fibers may have any suitable denier value, such as a denier of
about 0.1 to about 20, or about 0.15 to about 6.
[0031] Examples of suitable removable fiber materials include
polylactic acid (PLA) and polyglycolide (PGA) fibers, glass fibers,
polyethylene terephthalate (PET) fibers, and the like.
[0032] In some embodiments, the plugging agent content may include
pre-processed fiber flocks, which represent solids entrapped inside
a fiber network.
[0033] In some embodiments, the plugging agent may be a
non-removable material, which is a material that does not at least
partially degrade within a desired period of time. Non-degradable
materials suitable for use as a plugging agent include cement,
proppant and material of proppant-like composition (for example,
ceramics, sands, bauxites). The non-degradable materials form a
non-degradable (and/or non-dissolvable) plug, which may
subsequently be at least partially or completely removed using
other means, such as coil tubing or an abrasive, such as sand.
[0034] The term "subterranean formation" refers to any physical
formation that lies at least partially under the surface of the
earth.
[0035] The term "fracturing" refers to the process and methods of
breaking down a geological formation and creating a fracture, such
as the rock formation around a wellbore, by pumping a treatment
fluid at very high pressures (pressure above the determined closure
pressure of the formation), in order to increase production rates
from or injection rates into a hydrocarbon reservoir. The
fracturing methods of the present disclosure may include estimating
changes in fracture geometry by monitoring data from one or more
sensors while the fracture is open, performing a shut-in by
stopping injection of the treatment fluid and introducing a
plugging agent, but otherwise use conventional sensors and
techniques known in the art.
[0036] When hydraulic fracturing is applied in hydrocarbon
reservoirs to increase the production rate of hydrocarbons from the
reservoir, the primary objective of the well treatment is to
increase the production surface area of the formation. Between this
increased surface area and the production well, a flow path of
higher conductivity than the formation has to be situated. To
increase the surface area, high pressure is used, which fractures
the rock.
[0037] The term "shut-in" refers to a time where a treatment is
halted or stopped, either temporarily or permanently, and
sufficient pressure is maintained in the wellbore to prevent the
well from flowing back.
[0038] The term "real-time" refers to the actual time during which
a process or event occurs. Real time monitoring of data refers to
live monitoring of data, for example data relating to the size or
orientation of a fracture, that may allow for an action, for
example a plugging application, to be taken based upon the
monitoring. According to some embodiments, the real-time monitoring
occurs from 0 to about 10 minutes from when an event occurs, or
from between 0 and about 7 minutes from when an event occurs, or
from between 0 and about 5 minutes from when an event occurs.
[0039] Suitable techniques, sensors, and methodology for monitoring
data in subterranean formations are discussed in, for example, U.S.
Pat. Nos. 7,302,849, and 4,802,144, the disclosures of which are
incorporated by reference herein in their entireties. The methods
of the present disclosure may be employed in any desired downhole
application (such as, for example, hydraulic fracturing and/or
stimulation) at any time in the life cycle of a reservoir, field or
oilfield.
[0040] In embodiments, the methods of the present disclosure, which
comprise estimating changes in fracture geometry by monitoring data
from one or more sensors while the fracture is open, performing a
shut-in by stopping injection of the treatment fluid and
introducing a plugging agent, include performing a fracturing
operation by introducing a treatment fluid into the wellbore at a
fluid pressure equal to or greater than a fracture initiation
pressure of the subterranean formation to induce a fracture in the
subterranean formation.
[0041] The term "field" includes land-based (surface and
sub-surface) and sub-seabed applications. The term "oilfield," as
used herein, includes hydrocarbon oil and gas reservoirs, and
formations or portions of formations where hydrocarbon oil and gas
are expected but may additionally contain other materials such as
water, brine, or some other composition.
[0042] The term "bridging" refers to intentionally or accidentally
plugging off pore spaces or fluid paths in a rock formation, or to
make a restriction in a wellbore or annulus. A bridge may be
partial or total, and may be caused by solids (drilled solids,
cuttings, cavings or junk) becoming lodged together in a narrow
spot or geometry change in the wellbore. Bridging can be caused by
manufactured shapes such as proppant and diverters in the shapes of
fibers, flakes and particles.
[0043] The term "tubewave" refers to pressure waves generated on
surface and propagating along wellbore walls at the velocity
approximately equal to the sound velocity in the fluid. Obstacles
in the wellbore, pipe sections with different diameters,
perforations and open fractures are characterized by different
hydraulic impedances and serve as tubewave reflectors. Hydraulic
impedance is ratio of oscillatory pressure to oscillatory flow can
be also thought as acoustic rigidity of the media. The downhole
reflector's properties can be interpreted in terms of their
impedances. One way to determine depths and impedances of
reflectors is to generate one or several perturbations and measure
travel times and amplitudes of reflected/propagated waves.
Pertubation creates transient pressure and flow conditions in the
well. The perturbation may be produced by rapidly removing a slug
of fluid from the pressurized well by opening and closing a valve,
or rapidly injecting a slug of fluid resulting in free oscillation
of the well, or by the continuous action of reciprocating pumps, or
by other methods that cause transient fluid flow. The tubewave
travels down the wellbore along the interface between the fluid in
the wellbore and the wall of the wellbore.
[0044] In some embodiments, an operation may be performed to treat
a subterranean formation. The operation may be a hydraulic
fracturing operation, which may include fracturing a portion of the
subterranean formation by providing hydraulic pressure. Other
operations, such as acidizing a formation to generate a fracture
may also be used.
[0045] In a hydraulic fracturing operation, a treatment fluid,
which includes a predetermined amount of proppant, may be injected
into a wellbore at a fluid pressure equal to or greater than a
fracture initiation pressure of the subterranean formation. The
fluid pressure is the rate (volume/time) at which a fluid is
pumped. The term "fracture initiation pressure" refers to the fluid
pressure sufficient to induce a fracture in a subterranean
formation.
[0046] Fracturing a subterranean formation may include introducing
hundreds of thousands of gallons of fracturing fluid into the
wellbore. In some embodiments a frac pump may be used for hydraulic
fracturing. A frac pump is a high-pressure, high-volume pump, such
as a positive-displacement reciprocating pump. In embodiments, a
treatment fluid may be introduced by using a frac pump, such that
the fracturing fluid may be pumped down into the wellbore at high
rates and pressures, for example, at a flow rate in excess of about
20 barrels per minute (about 4,200 U.S. gallons per minute) at a
pressure in excess of about 2,500 pounds per square inch ("psi").
In some embodiments, the pump rate and pressure of the fracturing
fluid may be even higher, for example, at flow rates in excess of
about 100 barrels per minute and pressures in excess of about
10,000 psi may be used.
[0047] In a hydraulic fracturing operation according to some
embodiments, a proppant may be injected into a well, and the
proppant may include a crosslinked gel fluid. The operation may
then include fracturing according to a sequence of slurries being
pumped. The slurries may be pumped at any desired rate, such as a
rate of from about 20 bbl (barrels)/min to about 140 bbl
(barrels)/min, or a rate of from about 40 to about 100 bbl
(barrels)/min.
[0048] A treatment fluid including a first slurry to be introduced
may be introduced at any desired volume and concentration, such as
a pad fluid in which the total volume of the pad is from about 50
bbl to about 1000 bbl, or about 100 bbl to about 800 bbl, and where
the fluid is designed to control leakoff into the formation. The
treatment fluid may be injected at any desired pressure, such as a
pressure that is of a high enough magnitude to induce a fracture in
the subterranean formation, for example, any pressure equal to or
greater than the fracture initiation pressure, or a pressure
sufficient to induce a fracture of width typically exceeding the
proppant diameter by a factor of about 4 to about 5. Provided that
proppant size is from about 25 microns to 1.7 mm, an open fracture
may be at least about 0.15 mm to 1 cm.
[0049] The treatment fluid suitable for use in the methods of the
present disclosure may also any well treatment fluid, such as a
hydraulic fracturing fluid, an acidizing fluid (acid fracturing,
acid diverting fluid), a stimulation fluid, a sand control fluid, a
completion fluid, a wellbore consolidation fluid, a remediation
treatment fluid, a cementing fluid, a driller fluid, a frac-packing
fluid, or gravel packing fluid. The solvent (or carrier solvent)
for the treatment fluid may be a pure solvent or a mixture.
Suitable solvents or use with the methods of the present
disclosure, such as for forming the treatment fluids disclosed
herein, may be aqueous or organic based. Aqueous solvents may
include at least one of fresh water, sea water, brine, mixtures of
water and water-soluble organic compounds and mixtures thereof.
Organic solvents may include any organic solvent that is able to
dissolve or suspend the various other components of the treatment
fluid.
[0050] In some embodiments, the treatment fluid may have any
suitable viscosity, such as a viscosity of from about 1 cP to about
1,000 cP (or from about 10 cP to about 100 cP) at the treating
temperature, which may range from a surface temperature to a
bottom-hole static (reservoir) temperature, such as from about
-40.degree. C. to about 150.degree. C., or from about 10.degree. C.
to about 120.degree. C., or from about 25.degree. C. to about
100.degree. C.
[0051] While the treatment fluids of the present disclosure are
described herein as comprising the above-mentioned components, it
should be understood that the treatment fluids of the present
disclosure may optionally comprise other chemically different
materials. In embodiments, the treatment fluid may further comprise
stabilizing agents, surfactants, diverting agents, or other
additives. Additionally, a treatment fluid may comprise a mixture
of various crosslinking agents, and/or other additives, such as
fibers or fillers, provided that the other components chosen for
the mixture are compatible with the intended use of the treatment
fluid. Furthermore, the treatment fluid may comprise buffers, pH
control agents, and various other additives added to promote the
stability or the functionality of the treatment fluid. The
components of the treatment fluid may be selected such that they
may or may not react with the subterranean formation that is to be
treated.
[0052] In this regard, the treatment fluid may include components
independently selected from any solids, liquids, gases, and
combinations thereof, such as slurries, gas-saturated or
non-gas-saturated liquids, mixtures of two or more miscible or
immiscible liquids, and the like. For example, the treatment fluid
may comprise organic chemicals, inorganic chemicals, and any
combinations thereof. Organic chemicals may be monomeric,
oligomeric, polymeric, crosslinked, and combinations, while
polymers may be thermoplastic, thermosetting, moisture setting,
elastomeric, and the like. Inorganic chemicals may be inorganic
acids and inorganic bases, metals, metallic ions, alkaline and
alkaline earth chemicals, minerals, salts and the like.
[0053] Various fibrous materials may be included in the treatment
fluid. Suitable fibrous materials may be woven or nonwoven, and may
be comprised of organic fibers, inorganic fibers, mixtures thereof
and combinations thereof.
[0054] In embodiments, the treatment fluid may be driven into a
wellbore by a pumping system that pumps one or more treatment
fluids into the wellbore. The pumping systems may include mixing or
combining devices, wherein various components, such as fluids,
solids, and/or gases maybe mixed or combined prior to being pumped
into the wellbore. The mixing or combining device may be controlled
in a number of ways, including, for example, using data obtained
either downhole from the wellbore, surface data, or some
combination thereof.
[0055] Next, a suitable amount of a second slurry comprising about
0.5 to 8 pounds of proppant per unit gallon of fluid, carried by a
crosslinked fluid may be introduced into the subterranean
formation. The crosslinked fluid may be any conventional
crosslinking fluid known to those skilled in the art. Typical
fluids include guar or guar derivatives such as hydroxypropyl guar
(HPG) or carboxymethylhydroxypropylguar (CMHPG), cellulose or
cellulose derivative or xanthan gum or viscoelastic
surfactant-based fluids. Crosslinkers can be borate, titanium,
zirconium or aluminum based.
[0056] In some embodiments, the treatment operation may be halted
either temporarily or permanently. In embodiments where the
treatment operation is halted temporarily, the injection of a
stimulating slurry is halted for a predetermined duration, such as
about 1 to about 180 minutes, or about 5 to about 150 minutes,
about 10 to about 100 minutes, about 15 to about 90 minutes, about
20 to about 60 minutes, or about 30 to about 45 minutes. Such a
stoppage of the treatment operation, also referred to as a shut-in,
may allow for monitoring of a fracture and/or an area around the
fracture to be examined and monitored.
[0057] Once the shut-in has commenced, monitoring of data may
occur. The monitoring of data may occur immediately upon the
commencement of the shut-in, or at some time after the commencement
of the shut-in. The monitoring of data may involve any data
relating to a fracture in the subterranean formation. The data to
be monitored may include data of an average width of a fracture, or
a pressure decline in a wellbore, or reflection of pressure waves.
Further, the data can be monitored at real-time, or can be stored
for future analysis or study. By monitoring data, one skilled in
the art would understand that the data can be compiled, analyzed,
compared to previously compiled or stored data, and/or any
combination of these features.
[0058] In some embodiments, the fracture to be examined and
monitored may be a fracture in a near wellbore area. The fracture
in the near wellbore area may be a fracture that changes shape in a
manner that makes it more prone to being plugged. Thus, in some
embodiments, changes in geometry of the fracture may be estimated.
As fluid leaks off during the duration of the shut-in, changes in
fracture characteristics, including the geometry of the fracture,
may be estimated. The changes in the fracture geometry may relate
to the width, diameter, depth, near-wellbore tortuosity and/or
structure of the fracture can be understood. In some embodiments,
the width of the fracture may be decreasing when fluid leaks off
during the duration of the shut-in, and such a fracture width can
be estimated based upon monitoring fluid leakoff.
[0059] Fluid leakoff can be determined based upon estimation of a
pressure decline in the wellbore after the wellbore is shut. The
rate at which the pressure declines can be used to infer a fracture
closure time. The fracture closure time may allow for a width of a
fracture opening to be determined. In some embodiments, the
subterranean formation, including the pressure decline rate, is
monitored until the estimated width of the fracture opening has
decreased to a predetermined amount. In some embodiments, the
effective width of a fracture opening has been reached when the
width has decreased to a value prone to be bridged or plugged by
the diverter to be used. For a given diverter, the width that can
be effectively bridged can be determined in the laboratory. Another
method is to decrease the width to a value smaller than the size of
the diverter. For example, if a diverter particulate of diameter 2
mm is used, then an appropriate fracture width to be plugged may be
any value less than 2 mm Such fracture widths may allow for
plugging agents with appropriate size, composition and other
characteristics to be used to plug the fracture and allow for
bridging over the fracture area.
[0060] In some embodiments, the rate of pressure decline in the
wellbore can be estimated by G-function analysis using a G-function
plot. The G function plot is a plot disclosed in, for example
Reservoir Stimulation, 3.sup.rd Edition, Economides M. J. and K. G.
Nolte, Sections 9.5.2 and 9F, Wiley Publishing, or Modified
Fracture Pressure Decline Analysis Including Pressure-Dependent
Leakoff, Castillo J. L. and D. Schlumberger, SPE16417, or
Determination of Pressure Dependent Leakoff and Its Effect on
Fracture Geometry, Barree, R. D., Marathon Oil Company and
Mukherjee H. Dowell Schlumberger, SPE 36424, the teachings of which
are hereby incorporated by reference. The G function is a function
that can be defined as:
G(.DELTA.t.sub.D)=(4/.pi.)[g(.DELTA.t.sub.D)-g.sub.0],
[0061] where:
[0062] g(.DELTA.t.sub.D) is the fluid loss volume function;
[0063] g.sub.0 is the initial value of the fluid-loss volume
function; and
[0064] .DELTA.t.sub.D=.DELTA.t/tp and is the ratio of shut-in
(.DELTA.t) to the pumping time (t.sub.p)
[0065] In some embodiments, the G function plot can be represented
by plotting pressure and expressions of pressure derivatives
against G. As can be seen in FIG. 1, surface pressure and
superposition derivative G. .DELTA.P/.DELTA.G can be plotted with
respect to the G function.
[0066] In some embodiments, the time at which the superposition
derivative G..DELTA.P/.DELTA.G reaches a constant value can be
considered as closure time of a feature of the fracture. The G
function plot may be used for characterizing the fracture and/or
the subterranean formation entirely. In some embodiments, the G
function plot can be used to determine the time at which the
near-wellbore region is more prone to being bridged off by a
plugging agent. The plot can be obtained in real time using a
pressure decline analysis program.
[0067] In some embodiments, a plugging agent may be injected at or
after some period of time based upon a result of the performed
pressure decline analysis. The time may be from about 5 minutes to
about 12 hours, or from about 10 minutes to about 1 hour. The time
may be determined based upon commencement of the shut-in operation,
or at another time where monitoring of data is commenced. In some
embodiments, when the superposition derivative G..DELTA.P/.DELTA.G
reaches a plateau, the plugging agent may be pumped. The plugging
agent may be pumped at a pressure lower than the pressure to reopen
the fracture.
[0068] In some embodiments, the plugging agent is introduced after
the shut-in is performed. The plugging agent may be introduced into
the wellbore, or into any other area of the subterranean formation.
In embodiments where the plugging agent is introduced into the
wellbore, the plugging agent may be introduced into the wellbore
before the shut-in is commenced, or after the shut-in is
commenced.
[0069] The plugging agent may be a manufactured shape, at a loading
sufficiently high to be intercepted in the proximity of the
wellbore. The loading may be more than about 50 lb/1000 gal. The
manufactured shape of the plugging agent may be round particles
having dimensions that are optimized for plugging. Alternatively,
the particles may be of different shapes, such as cubes,
tetrahedrons, octahedrons, plate-like shapes (flakes), oval, and
the like. The plugging agent may be of any dimension that is
suitable for plugging. For example, as described in U.S. Patent
Application Publication No. 2012/0285692, the disclosure of which
is incorporated by reference herein in its entirety, the plugging
agent may include particles having an average particle size of from
about 3 mm to about 2 cm. Additionally, the plugging agent may
additionally include a second amount of particles having an average
particle size from about 1.6 to about 20 times smaller than the
first average particle size. Alternatively, the plugging agent may
include flakes having an average particle size up to 10 times
smaller than the first average particle size.
[0070] In some embodiments, the plugging agent is a diverter pill.
The diverter pill may be a diversion blend with fibers and
degradable particles with a particular particle size distribution.
The diverter pill may include about 2 to 50 bbl of a carrier fluid.
The diverter pill may include a diversion blend that is used as a
plug and may have a mass of 10 to 400 lbs. The diversion blend may
include about 50 pounds to 200 lbs of fiber per 1000 gallons of
blend. It may include about 20 to about 200 pounds of particles per
1000 gallons of blend. The diverter may include beads with an
average size such as described in TABLE 1 of U.S. Patent
Application Publication No. 2012/0285692 A1, which is hereby
incorporated by reference in its entirety.
[0071] In some embodiments, a width of a near wellbore fracture can
be inferred from monitoring the hydraulic impedance of the
fracture, which is the ratio of oscillatory pressure to oscillatory
flow. Hydraulic impedance can be monitored by generating pressure
pulses and measuring travel times and amplitudes of
reflected/propagated waves. The technique can be used to determine
when the impedance of the fracture is lower than the initial
impedance. When the impedance of the fracture is a threshold amount
lower than the initial impedance, the fracture may be of a
desirable geometry for plugging, and a plugging agent may be
subsequently injected. The threshold amount should be the threshold
corresponding to ratio (actual fracture width)/(fracture width
which can be bridged by diverter) and can be estimated from the
width of the fracture, typically 5-8 times of more the size of the
proppant which is used in the fracturing treatment, and the width
value which is bridged by the diverter and which can be determined
from laboratory testing, or can be assumed of being the size of the
largest particle used in the diverter blend.
[0072] Pressure waves generated on surface and/or propagating along
the wellbore walls at a velocity approximately equal to the sound
velocity of the fluid may be referred to as tubewaves. The
tubewaves may be reflected by obstacles in the wellbore, pipe
sections with different diameters, perforations and open fractures.
These components of the subterranean formation may have different
hydraulic impedances and thus serve as tubewave reflectors. The
impedance of such media is a ratio of the oscillatory pressure to
the oscillatory flow, or otherwise can be considered the acoustic
rigidity of the medium. Additionally, the downhole reflector's
properties can be interpreted in terms of their impedances.
[0073] At a time before or after a shut-in is commenced, tubewaves
can be generated on a surface using a tubewave source. The
tubewaves may be utilized by generating pressure signals from the
surface and sending the pressure signals downhole from a tubewave
generator. The tubewave source may include a storage chamber, a
fast valve to allow exchange of fluid with the tube, and a system
to pre-charge the chamber. The generator produces positive pulses
with a chamber pressurized at a pressure above the pressure of the
tube, such as up to 15000 psi.
[0074] To determine depths and impedances of particular reflectors,
the travel times of and amplitudes of the reflected and/or
propagated waves of the pressure pulses can be measured. Further,
the signals for the pressure pulse can be recorded, as well as the
signal reflected from the wellbore. Based on a change in reflection
of pulsation, it may be inferred that a particular fracture will be
more receptive at that time to a plugging agent. Accordingly, a
plugging agent can be injected at some time at or after a change in
reflection above a threshold value has occurred. The threshold
amount should be the threshold corresponding to ratio (actual
fracture width)/(fracture width which can be bridged by diverter)
and can be estimated from the width of the fracture, typically 5-8
times of more the size of the proppant which is used in the
fracturing treatment, and the width value which is bridged by the
diverter and which can be determined from laboratory testing, or
can be assumed of being the size of the largest particle used in
the diverter blend. The change in the fracture property may also be
detected by monitoring the time at which the reflected signal
changes in shape and reveals a fracture which is closed. The change
in reflection may be at about 5 to about 12 hours, or from about 10
to about 1 hour after the shut-in has commenced.
[0075] In some embodiments, the plugging agent may be injected at
or after some period of time based upon a result of the performed
reflection analysis. The time may be any suitable period of time,
including from about 5 minutes to about 12 hours, or from about 10
minutes to about 1 hour. The time may be determined based upon
commencement of the shut-in operation, or at another time where
monitoring of data is commenced. In some embodiments, when the
change in reflection of the tubewave has occurred, the plugging
agent may be pumped into the fracture so as to plug the
fracture.
[0076] The foregoing is further illustrated by reference to the
following examples, which are presented for purposes of
illustration and are not intended to limit the scope of the present
disclosure.
Example 1
[0077] In a first example, a well is completed in sixteen 300 foot
sections, each separated by bridge plugs. Each 300 foot section is
fractured with a proppant, which is carried by a cross-linked gel
fluid. Each 300 foot section is then fractured using a sequence of
slurries, each pumped at 60 bbl/min.
[0078] First, 286 bbl of pad is injected to fracture the rock.
Next, 2015 bbl of slurry comprising 180,000 lbs of proppant carried
by a crosslinked fluid is injected. FIG. 2 shows a typical pressure
curve from the pad to the diverter, where the diverter pill
generates a pressure of 727 psi. On this well, the maximum pressure
increase caused by the diverter when no shut-in was used no
diverter pill generates a pressure exceeding was 2242 psi.
[0079] Next, in one of the sixteen 300 foot sections, the treatment
was shut-in for about 90 minutes. 65 bbl of diverter pill
comprising 50 to 75 pounds of a carrier fluid viscosified by non
crosslinked guar was then injected. The pressure response obtained
when the diverter hit the perforations was 3700 psi, which was 2816
psi above the average pressure generated by the 15 other pills, and
1458 psi higher than the highest pressure recorded in the other
stages.
Example 2
[0080] In a second example, a well is completed and pressure
signals are generated from the surface and sent downhole from a
tubewave source. The tubewave generator includes a storage chamber,
a fast valve to allow exchange of fluid with the tube, and a system
to pre-charge the chamber. The generator produces positive pulses
with a chamber pressurized at a pressure above the pressure of the
tube.
[0081] A shut-in was then performed and tubewaves were generated on
the surface using the tubewave source. A positive pressure pulse
was generated at 100 second intervals. The pressure was recorded on
the surface at a frequency of 500 Hz. The signals for the pressure
pulse sent are shown on the top portion of FIG. 3, and the signals
reflected from the wellbore are shown on the bottom portion of FIG.
3.
[0082] As shown in FIG. 3, for the first 9 pulses sent in the
wellbore, the negative reflection at approximately 2.73 seconds
shows the open fracture. However, the 10.sup.th reflected pulsation
shows a change in reflection. The negative reflection from the
fracture is no longer visible at 2.73 seconds, but a positive
reflection develops at approximately 2.68 seconds. The change in
reflection at the 10.sup.th pulsation is explained by change of
internal fracture geometry which leads to change of interference
picture between waves reflected from fracture mouth and internal
fracture reflectors like possible jogs or fracture tip. This may be
explained by closing the fracture at the near wellbore region.
Plausibly, the fracture still may have relatively wide open
fracture in far field and the fracture continues closing after the
drastic change event. The knowledge about closure of near wellbore
region may provide for a beneficial time to inject a plugging
agent.
[0083] FIG. 4 displays a time at which the change in reflection
occurs. In the pressure plot shown on FIG. 4, the vertical lines
represent respectively (i) the time where the well is shut in and
(ii) the time at which the 10th pulsation is sent and reflected by
a fracture closed in the near wellbore area. At that time where the
10.sup.th pulsation is sent, the plugging agent may be injected to
obtain excellent plugging.
[0084] Although the preceding description has been described herein
with reference to particular means, materials and embodiments, it
is not intended to be limited to the particulars disclosed herein;
rather, it extends to all functionally equivalent structures,
methods and uses, such as are within the scope of the appended
claims. Furthermore, although only a few example embodiments have
been described in detail above, those skilled in the art will
readily appreciate that many modifications are possible in the
example embodiments without materially departing from the
disclosure of METHOD OF TREATING A SUBTERRANEAN FORMATION.
Accordingly, all such modifications are intended to be included
within the scope of this disclosure as defined in the following
claims. In the claims, means-plus-function clauses are intended to
cover the structures described herein as performing the recited
function and not only structural equivalents, but also equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail employs a cylindrical surface to secure
wooden parts together, whereas a screw employs a helical surface,
in the environment of fastening wooden parts, a nail and a screw
may be equivalent structures. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn.112(f) for any limitations
of any of the claims herein, except for those in which the claim
expressly uses the words `means for` together with an associated
function.
* * * * *