Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
METHOD FOR REMEDIATING A SCREEN-OUT DURING WELL COMPLETION
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefits of U.S. Provisional
Patent Application No.
62/059,517, filed 3 October 2014, titled "Method For Remediating A Screen-Out
During Well
Completion," and U.S. Provisional Patent Application No. 62/116,084, filed 13
February 2015,
titled "Method For Remediating A Screen-Out During Well Completion". This
application is
related to co-pending U.S. Patent Appl. No. 13/989,728, filed 24 May 2013,
titled "Autonomous
Downhole Conveyance System," which published as U.S. Patent Publ. No.
2013/0248174. This
application is also related to co-pending U.S. Patent Appl. No. 13/697,769,
filed 13 November
2012, titled "Assembly and Method for Multi-Zone Fracture Stimulation of a
Reservoir Using
Autonomous Tubular Units," which published as U.S. Patent Publ. No.
2013/0062055.
BACKGROUND OF THE INVENTION
[0002] This section is intended to introduce various aspects of the art,
which may be associated
with exemplary embodiments of the present disclosure. This discussion is
believed to assist in
providing a framework to facilitate a better understanding of particular
aspects of the present
disclosure. Accordingly, it should be understood that this section should be
read in this light, and
not necessarily as admissions of prior art.
FIELD OF THE INVENTION
[0003] This invention relates generally to the field of wellbore
operations. More specifically,
the invention relates to completion processes wherein multiple zones of a
subsurface formation are
fractured in stages.
GENERAL DISCUSSION OF TECHNOLOGY
[0004] In the drilling of oil and gas wells, a wellbore is formed using a
drill bit that is urged
downwardly at a lower end of a drill string. After drilling to a predetermined
bottomhole location,
the drill string and bit are removed and the wellbore is lined with a string
of casing. An annular
area is thus formed between the string of casing and the surrounding
formations.
[0005] A cementing operation is typically conducted in order to fill or
"squeeze" the annular
area with columns of cement. The combination of cement and casing strengthens
the wellbore and
facilitates the zonal isolation of the formations behind the casing.
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[0006] It is common to place several strings of casing having progressively
smaller outer
diameters into the wellbore. A first string may be referred to as surface
casing. The surface
casing serves to isolate and protect the shallower, freshwater-bearing
aquifers from
contamination by any other wellbore fluids. Accordingly, this casing string is
almost always
cemented entirely back to the surface.
[0007] A process of drilling and then cementing progressively smaller strings
of casing is
repeated several times below the surface casing until the well has reached
total depth. In
some instances, the final string of casing is a liner, that is, a string of
casing that is not tied
back to the surface. The final string of casing, referred to as a production
casing, is also
typically cemented into place. In some completions, the production casing (or
liner) has
swell packers or external casing packers spaced across selected productive
intervals. This
creates compartments between the packers for isolation of zones and specific
stimulation
treatments. In this instance, the annulus may simply be packed with sand.
[0008] As part of the completion process, the production casing is
perforated at a desired
level. This means that lateral holes are shot through the casing and the
cement column
surrounding the casing. The perforations allow reservoir fluids to flow into
the wellbore. In
the case of swell packers or individual compartments, the perforating gun
penetrates the
casing, allowing reservoir fluids to flow from the rock formation into the
wellbore along a
corresponding zone.
[0009] After perforating, the formation is typically fractured at the
corresponding zone.
Hydraulic fracturing consists of injecting water with friction reducers or
viscous fluids
(usually shear thinning, non-Newtonian gels or emulsions) into a formation at
such high
pressures and rates that the reservoir rock parts and forms a network of
fractures. The
fracturing fluid is typically mixed with a proppant material such as sand,
crushed granite,
ceramic beads, or other granular materials. The proppant serves to hold the
fracture(s) open
after the hydraulic pressures are released. In the case of so-called "tight"
or unconventional
formations, the combination of fractures and injected proppant substantially
increases the
flow capacity of the treated reservoir.
[0010] In order to further stimulate the formation and to clean the near-
wellbore regions
downhole, an operator may choose to "acidize" the formations. This is done by
injecting an
acid solution down the wellbore and through the perforations. The use of an
acidizing
solution is particularly beneficial when the formation comprises carbonate
rock. In operation,
the completion company injects a concentrated formic acid or other acidic
composition into
the wellbore and directs the fluid into selected zones of interest. The acid
helps to dissolve
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carbonate material, thereby opening up porous channels through which
hydrocarbon fluids
may flow into the wellbore. In addition, the acid helps to dissolve drilling
mud that may have
invaded the formation.
[0011] Application of hydraulic fracturing and acid stimulation as
described above is a
routine part of petroleum industry operations as applied to individual
hydrocarbon-producing
formations (or "pay zones"). Such pay zones may represent up to about 60
meters (100 feet)
of gross, vertical thickness of subterranean formation. More recently, wells
are being
completed through a hydrocarbon-producing formation horizontally, with the
horizontal
portion extending possibly 5,000, 10,000 or even 15,000 feet.
[0012] When there are multiple or layered formations to be hydraulically
fractured, or a
very thick hydrocarbon-bearing formation (over about 40 meters, or 131 feet),
or where an
extended-reach horizontal well is being completed, then more complex treatment
techniques
are required to obtain treatment of the entire target formation. In this
respect, the operating
company must isolate various zones or sections to ensure that each separate
zone is not only
perforated, but adequately fractured and treated. In this way, the operator is
sure that
fracturing fluid and stimulant are being injected through each set of
perforations and into
each zone of interest to effectively increase the flow capacity at each
desired depth.
[0013] The isolation of various zones for pre-production treatment requires
that the
intervals be treated in stages. This, in turn, involves the use of so-called
diversion methods.
In petroleum industry terminology, "diversion" means that injected fluid is
diverted from
entering one set of perforations so that the fluid primarily enters only one
selected zone of
interest. Where multiple zones of interest are to be perforated, this requires
that multiple
stages of diversion be carried out.
[0014] In order to isolate selected zones of interest, various diversion
techniques may be
employed within the wellbore. In many cases, mechanical devices such as
fracturing bridge
plugs, down-hole valves, sliding sleeves (known as "frac sleeves"), and
baffle/plug
combinations are used.
[0015] A problem sometimes encountered during a "perf-and-frac" process is
the so-
called screen-out. Screen-out occurs when the proppant being injected as part
of the
fracturing fluid slurry tightly packs the fractures and perforation tunnels
near the wellbore.
This creates a blockage such that continued injection of the slurry inside the
fractures requires
pumping pressures in excess of the safe limitations of the wellbore or
wellhead equipment.
Operationally, this causes a disruption in fracturing operations and requires
cessation of
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pumping and cleaning of the wellbore before resumption of operations. In
horizontal well
fracturing, screen-outs disrupt well operations and cause cost overruns.
[0016] Where the operator is pumping slurry while a live perforating gun is
in the hole,
the operator may be able to remedy a screen-out by shooting a new set of
perforations during
pumping. This may be done where a multi-zone stimulation technique is being
employed. In
this instance, the operator sends a signal to a bottom hole assembly that
includes various
perforating guns having associated charges. Examples of multi-zone stimulation
techniques
using such a bottom hole assembly include the "Just-In-Time Perforating"
(JITP) technique
and the "ACT Frac" technique. In these processes, a substantially continuous
treatment of
zones takes place.
[0017] The benefit of the bottom hole assemblies used for JITP and ACT Frac
processes
is that they allow the operator to perforate the casing along various zones of
interest and then
sequentially isolate the respective zones of interest so that fracturing fluid
may be injected
into several zones of interest in the same trip. Fortuitously, each of these
multi-zone
stimulation techniques also offers the ability to create, as needed, proppant
disposal zones to
clean up the wellbore by perforating a new section of rock (JITP) or to simply
circulate
proppant out of the well using the coil tubing in the wellbore (ACT Frac) in
the event of a
screen-out. However, in more traditional completions where a single zone
stimulation is
being conducted or where multiple perforation clusters are being treated at
one time, screen-
outs can require a change-out of completion equipment at the surface and a
considerable
delay in operations.
[0018] Recently, a new type of completion procedure has been developed that
employs
so-called autonomous tools. These are tools that are dropped into the wellbore
and which are
not controlled from the surface; instead, these tools include one or more
sensors (such as a
casing collar locator) that interact with a controller on the tool to self-
determine location
within a wellbore. As the autonomous tool is pumped downhole, the controller
ultimately
identifies a target depth and sends an actuation signal, causing an action to
take place. Where
the tool is a bridge plug, the plug is set in the wellbore at a desired depth.
Similarly, where
the tool is a perforating gun, one or more detonators is fired to send "shots"
into the casing
and the surrounding subsurface formation. Unfortunately, autonomous
perforating guns
cannot be pumped into a wellbore when a screen-out occurs; thus, they fall
into the class of
completions that requires a change-out of completion equipment at the surface
during screen-
out.
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[0019] Additionally, it is observed that even the JITP and ACT-Frac
procedures are
vulnerable to screen-out complications at the highest zone of a perf-and-frac
stage. (This is
demonstrated in connection with Figure 1F, below.)
[0020] Accordingly, a need exists for a process of remediating a wellbore
during a
condition of screen-out without interrupting the pumping process. Further, a
need exists for a
completion technique that enables an autonomous perforating tool to be
deployed in a
wellbore even during a condition of screen-out.
SUMMARY OF THE INVENTION
[0021] The methods described herein have various benefits in the conducting
of oil and
gas drilling and completion activities. Specifically, methods for completing a
well are
provided.
[0022] In one aspect, a method of completing a well first includes forming
a wellbore.
The wellbore defines a bore that extends into a subsurface formation. The
wellbore may be
formed as a substantially vertical well; more preferably, the well is formed
by drilling a
deviated or even a horizontal well.
[0023] The method also includes lining the wellbore with a string of
production casing.
The production casing is made up of a series of steel pipe joints that are
threadedly
connected, end-to-end.
[0024] The method further includes placing a valve along the production
casing. The valve
may be inserted into a casing string or made up integrally with the casing
string. The valve
creates a removable barrier to fluid flow within the bore. Preferably, the
valve is a sliding
sleeve having a seat that receives a ball, wherein the ball is dropped from
the surface to create
a pressure seal on the seat. The sleeve is held in place by shear pins, which
are engineered to
shear when the pressure above the sleeve exceeds a predetermined set point.
This opens the
ports for treatment of the zone or stage. If an estimated screen-out pressure
is exceeded
during treatment, additional shear pins holding the seat will shear, releasing
the valve
downhole. Other types of valves may also be used as described below.
[0025] The method also comprises perforating the production casing. The
casing is
perforated along a first zone of interest within the subsurface formation. The
first zone of
interest resides at or above the valve. The process of perforating involves
firing shots into the
casing, through a surrounding cement sheath, and into the surrounding rock
matrix making up
a subsurface formation. This is done by using a perforating gun in the
wellbore.
[0026] The method next includes injecting a slurry into the wellbore. The
slurry
comprises a fracturing proppant, preferably carried in an aqueous medium.
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[0027] The method further includes pumping the slurry at a pressure
sufficient to move
the valve and to overcome the barrier to fluid flow. This is done in response
to a condition of
screen-out along the first zone of interest created during the slurry
injection. Moving the
valve exposes ports along the production casing to the subsurface formation at
or below the
valve.
[0028] The method additionally includes further pumping the slurry through
the exposed
ports, thereby remediating the condition of screen-out above the valve.
[0029] In one aspect of the method, the valve is a sliding sleeve. In this
instance, moving
the valve to expose ports along the production casing comprises moving or
"sliding" the
sleeve to expose one or more ports fabricated in the sliding sleeve. This may
include the
shearing of set pins.
[0030] In another embodiment, the method further includes placing a
fracturing baffle
along the production casing. The fracturing baffle resides above the sliding
sleeve but at or
below the first zone of interest. The fracturing baffle may be part of a sub
that is threadedly
connected to the production casing proximate the sliding sleeve during initial
run-in. A
rupture disc is then pumped down the wellbore ahead of the slurry. The disc is
pumped to a
depth just above the valve until the disc lands on the fracturing baffle. In
this embodiment,
the rupture disc is designed to rupture at a pressure that is greater than a
screen-out pressure,
but preferably lower than the pressure required to move the valve.
[0031] Optionally, the operator may inject a fluid (such as an aqueous
fluid) under
pressure through the exposed port of the sliding sleeve, thereby creating mini-
fractures in the
subsurface formation below the first zone of interest. This step is done by
the operator before
pumping the rupture disc into the wellbore.
[0032] In another embodiment, the valve is a first burst plug. The first
burst plug will
have a first burst rating. The ports represent perforations that are placed in
the production
casing in a second zone of interest below the first zone of interest. In this
embodiment,
moving the valve to expose ports comprises injecting the slurry at a pressure
that exceeds the
burst rating of the first burst plug. Optionally, in this embodiment, the
method further
includes placing a second and a third burst plug along the production casing
at or below the
second zone of interest, creating a domino-effect in the event of multiple
screen-outs. The
second and third burst plugs will have a burst rating that is equal to or
greater than the first
burst rating.
[0033] In still another aspect, the valve that is moved is a ball-and-seat
valve, while the
ports are perforations earlier placed in the production casing in a second
zone of interest
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below the first zone of interest. In this instance, moving the valve to expose
ports comprises
injecting the slurry at a pressure that causes the ball to lose its pressure
seal on the seat.
Causing the ball to lose its pressure seal may define causing the ball to
shatter, causing the
ball to dissolve, or causing the ball to collapse.
[0034] In a preferred embodiment, perforating the production casing
comprises pumping
an autonomous perforating gun assembly into the wellbore, and autonomously
firing the
perforating gun along the first zone of interest. The autonomous perforating
gun assembly
comprises a perforating gun, a depth locator for sensing the location of the
assembly within
the wellbore, and an on-board controller. "Autonomously firing" means pre-
programming
the controller to send an actuation signal to the perforating gun to cause one
or more
detonators to fire when the locator has recognized a selected location of the
perforating gun
along the wellbore. In one aspect, the depth locator is a casing collar
locator and the on-
board controller interacts with the casing collar locator to correlate the
spacing of casing
collars along the wellbore with depth according to an algorithm. The casing
collar locator
identifies collars by detecting magnetic anomalies along a casing wall.
[0035] It is observed that the perforating gun, the locator, and the on-
board controller are
together dimensioned and arranged to be deployed in the wellbore as an
autonomous unit. In
this application, "autonomous unit" means that the assembly is not immediately
controlled
from the surface. Stated another way, the tool assembly does not rely upon a
signal from the
surface to know when to activate the tool. Preferably, the tool assembly is
released into the
wellbore without a working line. The tool assembly either falls
gravitationally into the
wellbore, or is pumped downhole. However, a non-electric working line such as
slickline
may optionally be employed.
[0036] In another aspect, an autonomous perforating gun assembly is
deployed in the
wellbore after a condition of screen-out has been remediated. The perforating
gun assembly
is used to fire a new set of perforations along the first zone of interest. In
this way, a new
fracturing process may be initiated in that zone of interest.
BRIEF DESCRIPTION OF THE DRAWINGS
[0037] So that the present inventions can be better understood, certain
drawings, charts,
graphs, and/or flow charts are appended hereto. It is to be noted, however,
that the drawings
illustrate only selected embodiments of the inventions and are therefore not
to be considered
limiting of scope, for the inventions may admit to other equally effective
embodiments and
applications.
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[0038] Figures 1A through IT present a series of side views of a lower
portion of a
wellbore. The wellbore is undergoing a completion procedure that uses
perforating guns and
ball sealers in stages. This is a known procedure.
[0039] Figure 1A presents a wellbore having been lined with a string of
production
casing. Annular packers are placed along the wellbore to isolate selected
subsurface zones.
The zones arc identified as "A," "B" and "C."
[0040] Figure 1B illustrates Zone A of the wellbore having been perforated.
Further,
fractures have been formed in the subsurface formation along Zone A using any
known
hydraulic fracturing technique.
[0041] Figure 1C illustrates that a plug has been set adjacent a packer
intermediate
Zones A and B. Further, a perforating gun is shown forming new perforations
along Zone B.
[0042] Figure 1D illustrates a fracturing fluid, or slurry, being pumped
into the wellbore,
with artificial fractures being induced in the subsurface formation along Zone
B.
[0043] Figure 1E illustrates that ball sealers have been dropped into the
wellbore,
thereby sealing perforations along Zone B. Further, a perforating gun is now
indicated along
Zone C. The casing along Zone C is being perforated.
[0044] Figure 1F illustrates fracturing fluid, or slurry, being pumped into
the wellbore.
Artificial fractures are being induced in the subsurface formation along Zone
C.
[0045] Figures 2A through 2F present a series of side views of a lower
portion of a
wellbore. The wellbore is undergoing a completion procedure that uses
perforating guns and
plugs in stages. This is a known procedure.
[0046] Figure 2A presents a wellbore having been lined with a string of
production
casing. Annular packers arc placed along the wellbore to isolate selected
subsurface zones.
The zones are identified as "A," "B" and "C."
[0047] Figure 2B illustrates Zone A of the wellbore having been perforated
using a
perforating gun. A plug has been run into the wellbore with the perforating
gun.
[0048] Figure 2C illustrates that fractures have been formed in the
subsurface formation
along Zone A using a fracturing fluid. Proppant is seen residing now in an
annular region
along Zone A.
[0049] Figure 2D illustrates that a second plug has been set adjacent a
packer
intermediate Zones B and C. Further, a perforating gun is shown forming
perforations along
Zone B.
[0050] Figure 2E illustrates that fracturing fluid is being pumped into the
wellbore, with
artificial fractures being induced in the subsurface formation along Zone B.
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[0051] Figure 2F illustrates that a third plug has been set adjacent a
packer intermediate
Zones B and C. Further, a perforating gun is shown forming perforations along
Zone C.
[0052] Figures 3A through 3F present a series of side views of a lower
portion of a
wellbore. The wellbore is undergoing a completion procedure that uses
perforating guns,
fracturing sleeves and dropped balls, in stages. This is a known procedure.
[0053] Figure 3A presents a wellbore having been lined with a string of
production
casing. Annular packers are placed along the wellbore to isolate selected
subsurface zones.
The zones are identified as "A," "B" and "C."
[0054] Figure 3B illustrates that a ball has been dropped onto a fracturing
sleeve in Zone
A.
[0055] Figure 3C illustrates that hydraulic pressure has been applied to
open the
fracturing sleeve in Zone A by pumping a fracturing fluid into the wellbore.
Further,
fractures are being induced in the subsurface formation along Zone A. Proppant
is seen
residing now in an annular region along Zone A.
[0056] Figure 3D illustrates that a second ball has been dropped. The ball
has landed on
a fracturing sleeve in Zone B.
[0057] Figure 3E illustrates that hydraulic pressure has been applied to
open the
fracturing sleeve in Zone B by pumping a fracturing fluid into the wellbore.
Further,
fractures are being induced in the subsurface formation along Zone B. Proppant
is seen
residing now in an annular region along Zone B.
[0058] Figure 3F illustrates that a third ball has been dropped. The ball
has landed on a
fracturing sleeve in Zone C. Zone C is ready for treatment.
[0059] Figures 4A through 4F present a series of side views of a lower
portion of a
wellbore. The wellbore is undergoing a completion procedure that uses a valve,
wherein
actuating or moving the valve exposes a port along the production casing in a
novel
application.
[0060] Figure 4A presents the wellbore with a sliding sleeve threadedly
connected in line
with a string of production casing. A ball is being pumped into the wellbore
to actuate the
sliding sleeve.
[0061] Figure 4B illustrates that the ball has landed onto a seat of the
sliding sleeve. The
sleeve has been actuated, exposing a port. In addition, a hydraulic fluid has
been pumped
into the wellbore to open small fractures.
[0062] Figure 4C is another view of the wellbore of Figure 4A. Here, a
rupture disc is
being pumped down the wellbore.
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[0063] Figure 4D illustrates that the rupture disc has landed on a baffle
seat. The seat is
upstream from the sliding sleeve. In addition, the production casing has been
perforated
above the baffle seat.
[0064] Figure 4E is another view of the wellbore of Figure 4A. Here, a
fracturing fluid
is being pumped down the wellbore and through the perforations. Fractures are
being formed
in the subsurface formation.
[0065] Figure 4F illustrates that the fracturing fluid continues to be
pumped down the
wellbore in response to a condition of screen-out at the perforations. Pumping
pressure has
caused the rupture disc to be breached, allowing slurry to move down the
wellbore and
towards the exposed ports.
[0066] Figures 5A and 5B illustrate an alternate completion method for a
perforated
wellbore. Here, a rupture disc is again landed on a baffle seat. However,
rather than using a
sliding sleeve, the wellbore is separately perforated below the rupture disc.
[0067] Figure 5A presents the wellbore with a rupture disc landed on a
baffle seat. The
wellbore has received perforations both above and below the baffle seat. The
subsurface
formation is being fractured through the upper perforations.
[0068] Figure 5B is another view of the wellbore of Figure 5A. Fracturing
fluid
continues to be pumped down the wellbore in response to a condition of screen-
out at the
upper perforations. Pumping pressure has caused the rupture disc to be
breached, allowing
slurry to move down the wellbore and towards the lower perforations.
[0069] Figure 5C presents the wellbore with a ball landed in a frac plug.
The wellbore
has received perforations both above and below the frac plug. The subsurface
formation is
being fractured through the upper perforations.
[0070] Figure 5D is another view of the wellbore of Figure 5C. Fracturing
fluid
continues to be pumped down the wellbore in response to a condition of screen-
out at the
upper perforations. Pumping pressure has caused a seat along the frac plug to
be sheared off,
allowing slurry to move down the wellbore and towards the lower perforations.
[0071] Figures 6A and 6B illustrate another alternate completion method for
a perforated
wellbore. Here, a rupture disc is again landed on a baffle seat. Additionally,
a second lower
rupture disc is landed on a baffle seat below a lower set of perforations.
[0072] Figure 6A presents the wellbore with an upper rupture disc landed on
an upper
baffle seat. The wellbore has received perforations both above and below the
upper baffle
seat. The subsurface formation is being fractured through the upper
perforations.
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[0073] Figure 6B is another view of the wellbore of Figure 6A. Fracturing
fluid
continues to be pumped down the wellbore in response to a condition of screen-
out at the
upper perforations. Pumping pressure has caused the upper rupture disc to be
breached,
allowing slurry to move down the wellbore and towards the lower perforations.
[0074] Figures 7A and 7B illustrate an alternate completion method for a
perforated
wellbore. Here, a ball-and-scat valve is used in the wellbore. The wellbore is
separately
perforated below the valve.
[0075] Figure 7A presents the wellbore with a collapsible ball landed on
the seat. The
wellbore has received perforations both above and below the seat. The
subsurface formation
is being fractured through the upper perforations.
[0076] Figure 7B is another view of the wellbore of Figure 7A. Fracturing
fluid
continues to be pumped down the wellbore in response to a condition of screen-
out at the
upper perforations. Pumping pressure has caused the ball to collapse, allowing
slurry to
move down the wellbore and towards the lower perforations.
[0077] Figure 8 is a flow chart illustrating steps for a method of
completing a well, in
one embodiment. The method uses a valve that may be actuated to expose a set
of ports
below perforations, thereby remediating a condition of screen-out.
DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS
Definitions
[0078] As used herein, the term "hydrocarbon" refers to an organic compound
that
includes primarily, if not exclusively, the elements hydrogen and carbon.
Hydrocarbons may
also include other elements, such as, but not limited to, halogens, metallic
elements, nitrogen,
oxygen, and/or sulfur. Hydrocarbons generally fall into two classes:
aliphatic, or straight
chain, hydrocarbons; and cyclic, or closed ring, hydrocarbons, including
cyclic terpenes.
Examples of hydrocarbon-containing materials include any form of natural gas,
oil, coal, and
bitumen that can be used as a fuel or upgraded into a fuel.
[0079] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures
of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation
conditions, at
processing conditions, or at ambient conditions (15 C to 20 C and 1 atm
pressure).
Hydrocarbon fluids may include, for example, oil, natural gas, coalbed
methane, shale oil,
pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other
hydrocarbons that are in a
gaseous or liquid state.
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[0080] As used herein, the terms "produced fluids" and "production fluids"
refer to
liquids and/or gases removed from a subsurface formation, including, for
example, an
organic-rich rock formation. Produced fluids may include both hydrocarbon
fluids and non-
hydrocarbon fluids. Production fluids may include, but are not limited to,
oil, natural gas,
pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon
dioxide, hydrogen
sulfide, and water (including steam).
[0081] As used herein, the term "fluid" refers to gases, liquids, and
combinations of gases
and liquids, as well as to combinations of gases and solids, combinations of
liquids and
solids, and combinations of gases, liquids, and solids.
[0082] As used herein, the term "gas" refers to a fluid that is in its
vapor phase at 1 atm
and 15 C.
[0083] As used herein, the term "oil" refers to a hydrocarbon fluid
containing primarily a
mixture of condensable hydrocarbons.
[0084] As used herein, the term "subsurface" refers to geologic strata
occurring below the
earth's surface.
[0085] As used herein, the term "formation" refers to any definable
subsurface region.
The formation may contain one or more hydrocarbon-containing layers, one or
more non-
hydrocarbon containing layers, an overburden, and/or an underburden of any
geologic
formation.
[0086] The terms "zone" or "zone of interest" refer to a portion of a
formation containing
hydrocarbons. Alternatively, the formation may be a water-bearing interval.
[0087] For purposes of the present application, the term "production
casing" includes a
liner string or any other tubular body fixed in a wellbore along a zone of
interest, which may
or may not extend to the surface.
[0088] As used herein, the term "wellbore" refers to a hole in the
subsurface made by
drilling or insertion of a conduit into the subsurface. A wellbore may have a
substantially
circular cross section, or other cross-sectional shapes. As used herein, the
term "well," when
referring to an opening in the formation, may be used interchangeably with the
term
"wellbore."
Description of Selected Specific Embodiments
[0089] The inventions are described herein in connection with certain
specific
embodiments. However, to the extent that the following detailed description is
specific to a
particular embodiment or a particular use, such is intended to be illustrative
only and is not to
be construed as limiting the scope of the inventions.
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[0090] Certain aspects of the inventions are also described in connection
with various
figures. In certain of the figures, the top of the drawing page is intended to
be toward the
surface, and the bottom of the drawing page toward the well bottom. While
wells historically
have been completed in substantially vertical orientation, it is understood
that wells now are
frequently inclined and/or even horizontally completed. When the descriptive
terms "up" and
"down" or "upper" and "lower" or similar terms are used in reference to a
drawing or in the
claims, they are intended to indicate relative location on the drawing page or
with respect to
claim terms, and not necessarily orientation in the ground, as the present
inventions have
utility no matter how the wellbore is orientated.
[0091] Wellbore completions in unconventional reservoirs are increasing in
length.
Whether such wellbores are vertical or horizontal, such wells require the
placement of
multiple perforation sets and multiple fractures. Known completions, in turn,
require the
addition of downhole hardware which increases the expense, complexity, and
risk of such
completions.
[0092] Several techniques are known for fracturing multiple zones along an
extended
wellbore incident to hydrocarbon production operations. One such technique
involves the
use of perforating guns and ball sealers run in stages.
[0093] Figures 1A through 1F present a series of side views of a lower
portion of an
extended wellbore 100. The wellbore 100 is undergoing a completion procedure
that uses
perforating guns 150 and ball sealers 160 in stages.
[0094] First, Figure lA introduces the wellbore 100. The wellbore 100 is
lined with a
string of production casing 120. The production casing 120 defines a long
series of pipe
joints that are threadedly coupled, end-to-end. The production casing 120
provides a bore
105 for the transport of fluids into the wellbore 100 and out of the wellbore
100.
[0095] The production casing 120 resides within a surrounding subsurface
formation 110.
Annular packers are placed along the casing 120 to isolate selected subsurface
zones. Three
illustrative zones are shown in the Figure 1 series, identified as "A," "B"
and "C." The
packers, in turn, are designated as 115A, 115B, 115C, and 115D, and are
generally placed
intermediate the zones.
[0096] It is desirable to perforate and fracture the formation along each
of Zones A, B
and C. Figure 1B illustrates Zone A having been perforated. Perforations 125A
are placed
by detonating charges associated with a perforating gun 150. Further,
fractures 128A have
been formed in the subsurface formation 110 along Zone A. The fractures 128A
are formed
using any known hydraulic fracturing technique.
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[0097] It is observed that in connection with the formation of the
fractures 128A, a
hydraulic fluid 145 having a proppant is used. The proppant is typically sand
and is used to
keep the fractures 128A open after hydraulic pressure is released from the
formation 110. It
is also observed that after the injection of the hydraulic fluid 145, a thin
annular gravel pack
is left in the region formed between the casing 120 and the surrounding
formation 110. This
is seen between packers 115A and 115B. The gravel pack beneficially supports
the
surrounding formation 110 and helps keeps fines from invading the bore 105.
[0098] As a next step, Zone B is fractured. This is shown in Figure 1C.
Figure 1C
illustrates that a plug 140 has been set adjacent the packer 115B intermediate
Zones A and B.
Further, the perforating gun 150 has been placed along Zone B. Additional
charges
associated with the perforating gun 150 are detonated, producing perforations
125B.
[0099] Next, Figure 1D illustrates that a fracturing fluid 145 is being
pumped into the
bore 105. Artificial fractures 128B are being formed in the subsurface
formation 110 along
Zone B. In addition, a new perforating gun 150 has been lowered into the
wellbore 100 and
placed along Zone C. Ball sealers 160 have been dropped into the wellbore.
[00100] Figure 1E illustrates a next step in the completion of the multi-zone
wellbore 100.
In Figure 1E, the ball sealers 160 have fallen in the bore 105 and have landed
along Zone B.
The ball sealers 160 seal the perforations 125B.
1001011 It is also observed in Figure 1E that the perforating gun 150 has been
raised in the
wellbore 100 up to Zone C. Remaining charges associated with the perforating
gun 150 are
detonated, producing new perforations 125C. After perforating, a fracturing
fluid 145 is
pumped into the bore 105 behind the perforating gun 150.
[00102] Finally, Figure 1F illustrates the fracturing fluid 145 being pumped
further into
the wellbore 100. Specifically, the fracturing fluid 145 is pumped through the
new
perforations 125C along Zone C. Artificial fractures 128C have been induced in
the
subsurface formation 120 along Zone C. The firing charges in the perforating
gun 150 are
now spent and the gun is pulled out of the wellbore 100.
[00103] The multi-zone completion procedure of Figures 1A through 1F is known
as the
"Just-In-Time Perforating" (JITP) process. The JITP process represents a
highly efficient
method in that a fracturing fluid may be run into the wellbore with a
perforating gun in the
hole. As soon as the perfs are shot and fractures are formed, ball sealers are
dropped. When
the ball sealers seat on the perforations, a gun is shot at the next zone.
These steps are
repeated for multiple zones until all guns are spent. A new plug 140 is then
set and the
process begins again.
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[00104] The JITP process requires low flush volumes and offers the ability to
manage
screen-outs along the zones. However, it does require that multiple plugs be
drilled out in an
extended well. In addition, even this procedure is vulnerable to screen-out at
the highest zone
of a multi-zone stage. In this respect, if a screen-out occurs along
illustrative Zone C during
pumping, clean-out operations will need to be conducted. This is because the
slurry 145
cannot be completely pumped through the perforations 125C and into the
formation, due to
the presence of the ball sealers 160 along Zone B and the bridge plug 140
above Zone A.
[00105] An alternate completion procedure that has been used is the
traditional "Plug and
Perf' technique. This is illustrated in Figures 2A through 2F. The Figure 2
drawings
present a series of side views of a lower portion of a wellbore 200. The
wellbore 200 is
undergoing a completion procedure that uses perforating plugs 240 and guns 250
in stages.
[00106] Figure 2A presents a wellbore 200 that has been lined with a string of
production
casing 220. The wellbore 200 is identical to the wellbore 100 of Figure 1A.
The wellbore
200 is lined with a string of production casing 220. The production casing 220
provides a
bore 205 for the transport of fluids into the wellbore 200 and out of the
wellbore 200. The
production casing 220 resides within a surrounding subsurface formation 210.
[00107] Annular packers are again placed along the casing 220 to isolate
selected
subsurface zones, identified as "A," "B" and "C." The packers, in turn, are
designated as
215A, 215B, 215C, and 215D.
[00108] In order to complete the wellbore 200, Zones A, B, and C are each
perforated. In
Figure 2B, a perforating gun 250 has been run into the bore 205. The gun 250
has been
placed along Zone A. Perforations 225A have been formed in the production
casing 120 by
detonating charges associated with the perforating gun 250.
[00109] Along with the perforating gun 250, a plug 240A has been set. In
practice, the
plug 240A is typically run into the bore 205 at the lower end of the
perforating gun on the
wireline 255. In other words, the plug 240A and the gun 250 are run into the
wellbore 200
together before the charges are detonated.
[00110] Next, a fracturing fluid 245 is injected into the newly-formed
perforations 225A.
The fracturing fluid 245, with proppant, is injected under pressure in order
to flow through
the perforations 225A and into the formation 210. In this way, artificial
fractures 228A are
formed.
[00111] Figure 2C illustrates that fractures 228A have been formed in the
subsurface
formation 210 along Zone A. Proppant is now seen residing in an annular region
along Zone
A. Thus, something of a gravel pack is formed.
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[00112] In the completion method of the Figure 2 series of drawings, the
process of
perforating and fracturing along Zone A is repeated in connection with Zones B
and C.
Figure 2D illustrates that a second perforating gun 250 and a second plug 240B
having been
run into the wellbore 200. The gun 250 is placed along Zone B while the plug
240B is set
adjacent packer 215B. Further, charges associated with the perforating gun 250
have been
detonated, forming new perforations 225B along Zone B.
[00113] Next, a fracturing fluid 245 is injected into the newly-formed
perforations 225B.
The fracturing fluid 245, with proppant, is injected under pressure in order
to flow through
the perforations 225B and into the formation 210. In this way, and as shown in
Figure 2E,
new artificial fractures 228A are formed.
[00114] The "Plug and Pert" process is repeated for Zone C. Figure 2F
illustrates that a
third perforating gun 250 has been lowered into the bore 205 adjacent Zone C,
and a third
plug 240C has been set adjacent a packer intermediate Zones B and C. Further,
the
perforating gun 250 is shown forming perforations along Zone C. It is
understood that
fractures (not shown) are then created in the subsurface formation 210 along
Zone C using a
fracturing fluid (also not shown).
[00115] In order to perforate multiple zones, the "Plug and Pert" process
requires the use
of many separate plugs. Those plugs, in turn, must be drilled out before
production
operations may commence. Further, the "Plug and Pert" process requires large
flush volumes
and is also vulnerable to screen-out. In this respect, if a screen-out occurs
along any zone
during pumping, clean-out operations will need to be conducted. This is
because the slurry
cannot be completely pumped through the perforations and into the formation,
or further
down the wellbore, due to the presence of the bridge plug (such as plug 240C)
immediately
below the target zone.
[00116] Yet another completion procedure that has been used involves the
placement of
multiple fracturing sleeves (or "frac sleeves") along the production casing.
This is known as
"Ball and Sleeve" completion. The Ball and Sleeve technique is illustrated in
Figures 3A
through 3F. The Figure 3 drawings present a series of side views of a lower
portion of a
wellbore 300. The wellbore 300 is undergoing a completion procedure that uses
frac sleeves
321 in stages.
[00117] First, Figure 3A introduces the wellbore 300. The wellbore 300 is
identical to the
wellbore 100 of Figure 1A. The wellbore 300 is lined with a string of
production casing 320
that provides a bore 305 for the transport of fluids into and out of the
wellbore 300. Annular
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packers 315A, 315B, 315C, 315D are placed along the casing 320 to isolate
selected
subsurface zones. The zones are identified as "A," "B" and "C."
[00118] In the completion processes shown in the Figure 1 and the Figure 2
series, each
of Zones A, B, and C is sequentially perforated. However, in the completion
process of the
Figure 3 series, frac sleeves 321A, 321B, 321C are used. The frac sleeves
321A, 321B,
321C are sequentially opened using balls 323A, 323B, 323C. This causes ports
to be
exposed along the production casing 320.
[00119] Looking now at Figure 3B, it can be seen that frac sleeve 321A has
been placed
along Zone A. A ball 323A has been dropped into the wellbore 300 and landed
onto a seat
associated with the frac sleeve 321A.
[00120] Figure 3C illustrates that hydraulic pressure has been applied to open
the
fracturing sleeve 321A. This is done by pumping a fracturing fluid 345 into
the bore 305. As
shown in Figure 3C, the fracturing fluid 345 flows through the frac sleeve
321A, into the
annular region between the production casing 320 and the surrounding
subsurface formation
310, and into the formation 310 itself. Fractures 328A are being induced in
the subsurface
formation 310 along Zone A. Additionally, proppant is seen now residing in the
annular
region along Zone A.
[00121] Tn the completion method of the Figure 3 series of drawings, the
process of
opening a sleeve and fracturing along Zone A is repeated in connection with
Zones B and C.
Figure 3D illustrates that a second ball 323B has been dropped into the
wellbore 300 and
landed on a sleeve 321B. The sleeve 321B resides along Zone B.
[00122] Figure 3E illustrates that hydraulic pressure has been applied to open
the
fracturing sleeve 321B. This is done by pumping a fracturing fluid 345 into
the wellbore 300.
Fractures are being induced in the subsurface formation 310 along Zone B.
Proppant is seen
residing now in an annular region along Zone B.
[00123] The "Ball and Sleeve" process is repeated for Zone C. Figure 3F
illustrates that a
third ball 323C has been dropped into the bore 305. The ball 323C has landed
onto the frac
sleeve 321C adjacent Zone C. It is understood that fractures (not shown) are
then created in
the subsurface formation 310 along Zone C.
[00124] The use of the sleeves 321A, 321B, 321C as shown in the Figure 3
series reduces
the flush volumes needed for completion. This, in turn, reduces the
environmental impact.
At the same time, the use of multiple sleeves creates a higher hardware risk
and a higher risk
of screen-out. If a screen-out occurs along any zone during pumping, clean-out
operations
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will need to be conducted. This is because the slurry cannot be completely
pumped through
the perforations and into the formation, due to the presence of the sealed
sleeve.
[00125] As the need for "pinpoint stimulation" has gained recognition, the
number of
stages may increase in the future for a given well length. However, experience
with single
zone stimulation has shown that as the wellbore is divided into smaller
treated segments, the
risk of screen-out increases. This means that the chance of pumping into
easily treatable rock
decreases. Recovery from screen-out upset for a frac-sleeve-only completion is
very costly
and usually involves well intervention and removal (i.e., destruction) of the
hardware placed
in the well during drilling operations.
[00126] For these and perhaps other reasons, it is desirable to modify the
procedures
presented in the processes of the Figure 1 series, the Figure 2 series, and
the Figure 3 series.
Specifically, it is desirable to replace the wellbore plugs and sleeves with a
valve that creates
a fluid barrier, but wherein the fluid barrier can be selectively removed
using increased
pumping pressures to expose a port through the production casing. In this way,
the slurry
may be pumped through the then-exposed port. This enables the continuous
pumping of
fracturing fluids in the wellbore even when a screen-out occurs.
[00127] Various methods for providing a valve in the wellbore that removes the
barrier to
fluid flow downhole are provided and are described below.
[00128] Figures 4A through 4F present a series of side views of a lower
portion of a
wellbore 400. The wellbore 400 is undergoing a completion procedure that
includes
perforation and fracturing of at least one zone of interest. The wellbore 400
defines a bore
405 that has been formed through a subsurface formation 410. In the
illustrative Figure 4
series, the wellbore 400 is being completed in a horizontal orientation.
[00129] Figure 4A introduces the wellbore 400. The wellbore 400 is being
completed
with a string of production casing 420. The production casing 420 represents a
series of steel
pipe joints threadedly connected, end-to-end. The production casing 420
provides path for
fluids into and out of the wellbore 400.
[00130] An annular region 415 resides between the production casing 420 and
the
surrounding rock matrix of the subsurface formation 410. The annular region
415 is filled
with cement as is known in the art of drilling and completions. Where so-
called swell-
packers are used in the annular region 415 (see, for example, packers 115A,
115B, 115C, and
115D of the Figure 1 set of drawings), the annular region 415 would not be
cemented.
[00131] A frac sleeve 440 has been placed along the production casing 420. The
frac
sleeve 440 defines a hydraulically-actuated valve. This may be, for example,
the Falcon
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Hydraulic-Actuated Valve of Schlumberger limited, of Sugar Land, Texas. The
frac sleeve
440 includes a seat 442. The seat 442 which is dimensioned to receive a ball
450. In the
view of Figure 4A, the ball 450 has been dropped and is traveling down the
wellbore 400, as
indicated by Arrow B, towards the seat 442. Upon landing on the seat 442, the
ball 450 will
seal a through-opening 445 in the sleeve 440.
[00132] As shown in Figure 4A, the wellbore 400 also includes a baffle seat
462. The
baffle seat 462 defines a sub that is threadedly connected in-line with the
production casing
420. The baffle seat 462 is dimensioned to receive a rupture disc, shown in
Figures 4C and
4D at 460.
[00133] Figure 4B presents a next view of the wellbore 400. Here, the ball 450
has landed
on the seat 442 of the frac sleeve 460. The ball 450 provides a substantial
pressure seal,
creating a fluid barrier in the bore 405.
[00134] Figure 4B also illustrates that the frac sleeve 440 has been moved.
This means
that pressure has been applied by the ball 450 against the seat 462, causing
the sleeve 440 to
shift, thereby exposing one or more ports 455. Pressure is applied by the
injection of fluid
into the wellbore and the application of fluid pressure using pumps (not
shown) at the
surface.
[00135] It can also be seen that some degree of fracturing has taken place. At
least one
small fracture 458, or "mini-fracture," has been created in the subsurface
formation 410 as a
result of the injection of fluids under pressure. Preferably, the fluid is a
brine or other
aqueous fluid that invades the near-wellbore region.
[00136] Referring now to Figures 4C and 4D together, Figure 4C illustrates the
placement of a rupture disc 460 in the bore 405. The rupture disc 460 is being
pumped
downhole as indicated by Arrow D. In Figure 4D, the rupture disc 460 has
landed on the
baffle seat 462. The baffle seat 462 resides proximate the frac sleeve 440 and
just above the
newly-exposed flow ports 455.
[00137] The rupture disc 460 includes a diaphragm or other pressure-sensitive
device. The
pressure device has a burst rating. When the pressure in the bore 405 goes
above the burst
rating, the disc 460 will rupture, permitting a flow of fluids there through.
Until bursting, the
disc 460 creates a barrier to fluid flow through the bore 405.
[00138] Also seen in Figure 4D is a new set of perforations 478. The
perforations 478
have been formed through the casing 420 and into the subsurface formation 410.
The
perforations were shot using a perforating gun (not shown). The perforating
gun may be a
select fire gun that fires, for example, 16 shots. The gun has associated
charges that detonate
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in order to cause shots to be fired from the gun and into the surrounding
production casing
420. Typically, the perforating gun 420 contains a string of shaped charges
distributed along
the length of the gun 420 and oriented according to desired specifications.
[00139] Alternatively, the perforating gun may be part of an autonomous
perforating gun
assembly, such as that described in U.S. Patent Publ. No. 2013/0062055. The
autonomous
perforating gun assembly is designed to be released into the wellbore 400 and
to be self-
actuating. In this respect, the assembly does not require a wireline and need
not otherwise be
mechanically tethered or electronically connected to equipment external to the
wellbore. The
delivery method may include gravity, pumping, or tractor delivery.
[00140] The autonomous perforating gun assembly generally includes a
perforating gun, a
depth locator, and an on-board controller. The depth locator may be, for
example, a casing
collar locator that measures magnetic flux as the assembly falls through the
wellbore.
Anomalies in magnetic flux are interpreted as casing collars residing along
the length of the
casing string. The assembly is aware of its location in the wellbore by
counting collars along
the casing string as the assembly moves downward through the wellbore.
[00141] The on-board controller is programmed to send an actuation signal. The
signal is
sent to the perforating gun when the assembly has reached a selected location
along the
wellbore. In the case of Figure 4B, that location is a depth that is above the
frac sleeve 440
and along a zone of interest. To confirm location, the controller may be pre-
programmed
with a known casing or formation log. The controller compares readings taken
in real time
by the casing collar locator or other logging tool with the pre-loaded log.
[00142] The autonomous assembly may also include a power supply. The power
supply
may be, for example, one or more lithium batteries, or battery pack. The power
supply will
reside in a housing along with the on-board controller. The perforating gun,
the location
device, the on-board controller, and the battery pack are together dimensioned
and arranged
to be deployed in a wellbore as an autonomous unit.
[00143] The autonomous assembly defines an elongated body. The assembly is
preferably
fabricated from a material that is frangible or "friable." In this respect, it
is designed to
disintegrate when charges associated with the perforating gun are detonated.
[00144] The completion assembly is preferably equipped with a special tool-
locating
algorithm. The algorithm allows the tool to accurately track casing collars en
route to a
selected location downhole. U.S. Patent Appl. No. 13/989,726, filed on 24 May
24 2013,
discloses a method of actuating a downhole tool in a wellbore. That patent
application is
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entitled "Method for Automatic Control and Positioning of Autonomous Dovvnhole
Tools."
The application was published as U.S. Patent Publ. No. 2013/0255939.
[00145] According to that U.S. Patent Publ. No. 2013/0255939, the operator
will first
acquire a CCL data set from the wellbore. This is preferably done using a
traditional casing
collar locator. The casing collar locator is run into a wellbore on a wireline
or electric line to
detect magnetic anomalies along the casing string. The CCL data set correlates
continuously
recorded magnetic signals with measured depth. More specifically, the depths
of casing
collars may be determined based on the length and speed of the wireline
pulling a CCL
logging device. In this way, a first CCL log for the wellbore is formed.
[00146] In practice, the first CCL log is downloaded into a processor which is
part of the
on-board controller. The on-board controller processes the depth signals
generated by the
casing collar locator. In one aspect, the on-board controller compares the
generated signals
from the position locator with a pre-determined physical signature obtained
for wellbore
objects from the prior CCL log.
[00147] The on-board controller is programmed to continuously record magnetic
signals as
the autonomous tool traverses the casing collars. In this way, a second CCL
log is formed.
The processor, or on-board controller, transforms the recorded magnetic
signals of the second
CCL log by applying a moving windowed statistical analysis. Further, the
processor
incrementally compares the transformed second CCL log with the first CCL log
during
deployment of the downhole tool to correlate values indicative of casing
collar locations.
This is preferably done through a pattern matching algorithm. The algorithm
correlates
individual peaks or even groups of peaks representing casing collar locations.
In addition, the
processor is programmed to recognize the selected location in the wellbore,
and then send an
activation signal to the actuatable wellbore device or tool when the processor
has recognized
the selected location.
[00148] In some instances, the operator may have access to a wellbore diagram
providing
exact information concerning the spacing of downhole markers such as the
casing collars.
The on-board controller may then be programmed to count the casing collars,
thereby
determining the location of the tool as it moves downwardly in the wellbore.
[00149] In some instances, the production casing may be pre-designed to have
so-called
short joints, that is, selected joints that are only, for example, 15 or 20
feet in length, as
opposed to the "standard" length selected by the operator for completing a
well, such as 30
feet. In this event, the on-board controller may use the non-uniform spacing
provided by the
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short joints as a means of checking or confirming a location in the wellbore
as the completion
assembly moves through the casing.
[00150] In one embodiment, the method further comprises transforming the CCL
data set for
the first CCL log. This also is done by applying a moving windowed statistical
analysis. The first
CCL log is downloaded into the processor as a first transformed CCL log. In
this embodiment,
the processor incrementally compares the second transformed CCL log with the
first transformed
CCL log to correlate values indicative of casing collar locations.
[00151] It is understood that the depth locator may be any other logging
tool. For example, the
on-board depth locator may be a gamma ray log, a density log, a neutron log,
or other formation
log. In this instance, the controller is comparing readings in real time from
the logging tool with
a pre-loaded gamma ray or neutron log. Alternatively, the depth locator may be
a location sensor
(such as IR reader) that senses markers placed along the easing (such as an IR
transceiver). The
on-board controller sends the actuation signal to the perforating gun when the
location sensor has
recognized one or more selected markers along the casing.
[00152] In one embodiment, the algorithm interacts with an on-board
accelerometer. An
accelerometer is a device that measures acceleration experienced during a
freefall. An
accelerometer may include multi-axis capability to detect magnitude and
direction of the
acceleration as a vector quantity. When in communication with analytical
software, the
accelerometer allows the position of an object to be confirmed.
[00153] Additional details for the tool-locating algorithm are disclosed in
U.S. Patent Publ. No.
2013/0255939, referenced above.
[00154] In order to prevent premature actuation, a series of gates is
provided. U.S. Patent Appl.
No. 14/005,166 describes a perforating gun assembly being released from a
wellhead. That
application was filed on 13 September 2013, and is entitled "Safety System for
Autonomous
Downhole Tool." The application was published as U.S. Patent Publ. No.
2013/0248174. In
particular, reference is made to Figure 8 and the corresponding discussion of
the gates in that
published application.
[00155] After perforations are shot, the operator begins a formation
fracturing operation.
Figure 4E demonstrates the movement of slurry 470 through the bore 405. Slurry
is pumped
downhole as indicated by Arrows S. As the slurry 470 reaches the perforations,
the slurry invades
the subsurface formation 410, creating tunnels and tiny fractures 478 in the
rock.
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[00156] It is observed that slurry is prevented from moving down to the flow
ports 458 in
the frac sleeve 440 by the rupture disc 460. Of importance, the rupture disc
460 is designed
to have a burst rating that is higher than an estimated formation parting
pressure. Ideally, the
operator or a completions engineer will pre-determine an anticipated formation
parting
pressure based on geo-mechanical modeling, field data, and/or previous
experiences in the
same field. A rupture disc having a burst rating sufficiently above the
formation parting
pressure is selected to avoid accidental break-through during pumping.
[00157] Finally, Figure 4F illustrates that a condition of screen-out has
occurred. Sand or
other proppant material has become tightly packed in the perforations 475 and
fractures 478,
even to the point where additional slurry can no longer be pumped. This occurs
when the
aqueous (or other) carrier medium leaks off into the formation, leaving sand
particles in
place.
[00158] The operator at the surface will recognize that a condition of screen-
out has
occurred by observing the surface pumps. In this respect, pressure will
quickly build in the
wellbore, producing rapidly climbing pressure readings at the surface. Under
conventional
operations, the operator will need to back off the pump rate to prevent
wellbore pressures
from exceeding the burst ratings and maximum hoop and tensile stresses of the
casing, and to
prevent damage to surface valves. The operator may then hope flow back the
well, using
bottom hole pressure to try and push the proppant-laden slurry back out of the
well and to the
surface. In known procedures, if the velocity is not sufficient, the proppant
will drop out in
the casing and across the heel of the well, creating a bridge of proppant that
must be removed
mechanically before operations can continue. On the other band, if the
pressure is reduced
too quickly at the surface, the high flow rate of proppant can cause
significant abrasive
damage to valves and piping as it flows through significantly smaller pipe.
[00159] In the novel method demonstrated by the Figure 4 series of drawings,
the problem
of screen-out is self-remediating. In this respect, the excess pressure
created by the pumping
and by the hydrostatic head of the proppant-laden slurry during screen-out
will prompt the
diaphragm in the rupture disc 460 to burst. This fortuitous event has occurred
in Figure 4F.
[00160] It can be seen in Figure 4F that a through-opening 465 has been
created through
the rupture disc 460. Slurry 470 remaining in the wellbore is now moving
through the
through-opening 465. Further, the slurry 470 is moving though the flow ports
455 of the frac
sleeve 440. In this way, the problem of screen-out is remediated.
[00161] In the method of the Figure 4 series of drawings, the rupture disc 460
serves as a
valve. The valve "opens" in response to a wellbore pressure encountered during
the screen-
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out. When the valve 460 opens, the barrier to fluid flow down the wellbore is
removed,
exposing the flow ports 455. This, in turn, relieves the excess wellbore
pressure.
[00162] It is noted that the rupture disc 460 is actually an optional feature
in the method of
the Figure 4 series. The method may be modified by removing the rupture disc
460 and just
using the frac sleeve 440 as the valve that is opened. In this instance, the
sleeve 440 is
maintained in its closed position during the perf-and-frac operation, and only
opens if higher
wellbore pressures indicative of a screen-out occur. The result is that the
flow ports 455 open
in the step of Figure 4E rather than in Figure 4B.
[00163] In another embodiment, a rupture disc is used without a frac sleeve.
Figures 5A
and 5B demonstrate such a method.
[00164] First, Figure 5A illustrates a wellbore 500 undergoing completion. The
wellbore
500 is being completed in a horizontal orientation. The completion of wellbore
500 includes
a string of production casing 520 cemented in place within a surrounding
subsurface
formation 510. Optional cement is shown in an annular area 515 around the
casing 520.
[00165] In this view, the wellbore 500 has been completed along two zones of
interest,
indicated by separate perforations at 575' and 575". The lower zone of
interest, indicated by
perforations at 575', has been fractured. Fractures are shown somewhat
schematically at
578'. The upper zone of interest, indicated by perforations 575", has also
been fractured.
Fractures are shown there at 578".
[00166] In Figure 5A, a rupture disc 560 has been pumped down into the bore
505. The
disc 560 has landed on a baffle seat 562. The baffle seat 562 is located above
the lower zone
of interest and the corresponding perforations 575'. In this way, the rupture
disc 560 resides
between the lower 575' and the upper 575" sets of perforations.
[00167] The rupture disc 560 includes a pressure diaphragm 564. The diaphragm
564 has
a burst pressure that is higher than an anticipated formation fracturing
pressure for the upper
perforations 575". Specifically, the disc 560 is designed to rupture in the
event of a screen-
out during fracturing of the upper perforations 575". Thus, the burst rating
for the rupture
disc 560 and its diaphragm 564 is designed to approximate a pressure that
would be
experienced in the wellbore 500 in the event of a screen-out.
[00168] Figure 5B demonstrates that a condition of screen-out has arisen. It
can be seen
that slurry 570 has moved past the upper perforations 575 and has moved down
the bore 505
towards the lower set of perforations 575'. A buildup of pressure due to
screen-out has
caused the pressure diaphragm 564 to rupture, creating a new through-opening
565 in the
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rupture disc 560. Slurry 570 will proceed to the lower set of perforations
575', as indicated
by Arrows S. Thus, the rupture disc 560 serves essentially as a relief valve.
[00169] In another embodiment, a frac plug is used that may shear off in
response to a
condition of screen-out. Figures 5C and 5D demonstrate such a method.
[00170] First, Figure 5C illustrates the same wellbore 500 as in Figure 5A
undergoing
completion. The wellbore 500 is being completed in a horizontal orientation.
The
completion of wellbore 500 includes a string of production casing 520 cemented
in place
within a surrounding subsurface formation 510. Optional cement is shown in an
annular area
515 around the casing 520.
[00171] In Figure 5C, a frac plug 580 has been placed along the casing 520.
The frac
plug 580 may be, for example, Halliburton's composite frac plug with caged
ball and seat.
The frac plug 580 includes a seat 584 dimensioned to receive a ball 550. A
ball 550 has
landed on the seat 584 above the lower zone of interest and the corresponding
perforations
575'. In this way, the ball 550 resides between the lower 575' and the upper
575" sets of
perforations.
[00172] The frac plug 580 includes shear pins 582 designed to release in
response to a
fluid pressure within the bore 505 that is greater than a screen-out pressure
during fracturing
of the upper perforations 575". This is a pressure that is higher than an
anticipated formation
fracturing pressure for the upper perforations 575". The seat 584 is held with
shear pins
which release the valve (ball 550 and seat 584) when the designed pressure
differential is
exceeded, most likely caused by screen-out of proppant into the upper
formation 575".
[00173] Figure 5D demonstrates that a condition of screen-out has arisen. It
can be seen
that slurry 570 has moved past the upper perforations 575" and has moved down
the bore 505
towards the lower set of perforations 575'. A build-up of pressure due to
screen-out has
caused the pins 582 along the frac plug 580 to shear, allowing sluffy 570 to
proceed to the
lower set of perforations 575', as indicated by Arrows S. The ball 550 and
seat 584 are
falling in the wellbore 500. Thus, the ball-and-seat arrangement of the
releasable frac plug
580 serves essentially as a relief valve.
[00174] In another embodiment, two rupture discs are used between the upper
and lower
zones of interest, without a frac sleeve. Figures 6A and 6B demonstrate such a
method.
[00175] First, Figure 6A illustrates a wellbore 600 undergoing completion. The
wellbore
600 is being completed in a horizontal orientation. The completion of wellbore
600 includes
a string of production casing 620 cemented in place within a surrounding
subsurface
formation 610. Optional cement is shown in an annular area 615 around the
casing 620.
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[00176] In Figure 6A, the wellbore 600 has been completed along two zones of
interest,
indicated by separate perforations at 675' and 675". The lower zone of
interest, indicated by
perforations at 675', has been fractured. Fractures are shown somewhat
schematically at
678'. The upper zone of interest, indicated by perforations 675", has also
been fractured.
Fractures are shown there at 678".
[00177] In Figure 6A, an upper rupture disc 660" has been pumped down into the
bore
605. The disc 660" has landed on an upper baffle seat 662". The upper baffle
seat 662" is
located above the lower zone of interest and the corresponding perforations
675'. In this
way, the rupture disc 660" resides between the upper 675" and the lower 675'
sets of
perforations.
[00178] The upper rupture disc 660" includes a pressure diaphragm 664". The
diaphragm 664" has a burst pressure that is higher than an anticipated
formation fracturing
pressure for the formation 610. Specifically, the disc 660" is designed to
rupture in the event
of a screen-out during fracturing of the upper perforations 675". Thus, the
burst rating for
the rupture disc 660" and its diaphragm 664" is designed to approximate a
pressure that
would be experienced in the wellbore 600 in the event of a screen-out.
[00179] The wellbore 600 also includes a lower rupture disc 660'. The lower
rupture disc
660' has been previously pumped down into the bore 605 ahead of the upper
rupture disc
660". The lower rupture disc 660' is dimensioned to pass through the upper
baffle seat 662"
and land on a lower baffle seat 662'. The lower baffle seat 662' is located
below the lower
zone of interest and the corresponding perforations 675'.
[00180] The lower rupture disc 660' also includes a pressure diaphragm 664'.
The
diaphragm 664' has a burst pressure that is higher than the burst rating for
the upper rupture
disc 660". Specifically, the disc 660' is designed to withstand even an
anticipated screen-out
during fracturing of the upper perforations 675".
[00181] Figure GB demonstrates that a condition of screen-out has arisen. It
can be seen
that slurry 670 has moved past the upper perforations 675" and has moved down
the bore
605 towards the lower set of perforations 675'. A buildup of pressure due to
screen-out has
caused the pressure diaphragm 664' in the upper rupture disc 660" to rupture,
creating a new
through-opening 665" in the rupture disc 660". The lower rupture disc 660'
remains in-tact,
and forces the slurry 670 to enter the lower set of perforations 675', as
indicated by Arrows
S.
[00182] As can be seen, the first rupture disc 660" again serves essentially
as a relief
valve.
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[00183] In another embodiment, a frac plug having a removable ball is used
without a frac
sleeve. Figures 7A and 7B demonstrate such a method.
[00184] First, Figure 7A illustrates another wellbore 700 undergoing
completion
procedures. The wellbore 700 is being completed in a horizontal orientation.
The
completion of wellbore 700 includes a string of production casing 720 cemented
in place
within a surrounding subsurface formation 710. Optional cement is shown in an
annular area
715 around the casing 620.
[00185] In the view of Figure 7A, the wellbore 700 is again being completed
along two
zones of interest, indicated by separate perforations at 775' and 775". The
lower zone of
interest, indicated by perforations at 775', has been fractured. Fractures are
shown somewhat
schematically at 778'. The upper zone of interest, indicated by perforations
775", has also
been fractured. Fractures are shown there at 778".
[00186] In Figure 7A, a ball-and-seat valve 760 has been placed along the
subsurface
formation 710. The valve 760 comprises a sub that is threadedly connected in-
line with the
production casing 720. The valve 760 has a seat 762 that is dimensioned to
receive a ball
750. It can be seen in Figure 7A that a ball 750 been dropped into the bore
705 and has
landed on the seat 762, thereby creating a pressure seal that prevents fluid
flow further down
the bore 705.
[00187] The ball-and-seat valve 760 is located above the lower zone of
interest and the
corresponding perforations 775'. At the same time, the valve 760 resides below
the upper
zone of interest and the corresponding perforations 775".
[00188] The ball 750 is uniquely fabricated from a material than collapses in
response to
pressure. Rather than having a burst pressure, it has a collapse pressure. The
collapse
pressure is the pressure at which the ball 750 will collapse or break or
dissolve. In the
arrangement of Figures 7A and 7B, this pressure is higher than an anticipated
formation
fracturing pressure for the subsurface formation 710. Specifically, the ball
750 is designed to
collapse in the event of a screen-out during fracturing of the upper
perforations 775". Thus,
the collapse rating for the ball 750 is designed to approximate a pressure
that would be
experienced in the wellbore 700 in the event of a screen-out.
[00189] In Figure 7A, a slurry 770 is being pumped down the bore 705. This
forms the
upper set of fractures 778". However, Figure 7B demonstrates that a condition
of screen-out
has arisen at the level of these fractures 778". It can be seen that slurry
770 has moved past
the upper perforations 775" and has moved down the bore 705 towards the lower
set of
perforations 775'. A buildup of pressure due to screen-out has caused the ball
(750) to
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collapse, crumble, disintegrate, and/or dissolve, creating a new through-
opening 765 in seat
762. Slurry 770 will proceed to the lower set of perforations 775' as
indicated by Arrows S.
Thus, the ball-and-seat valve 760 serves essentially as a relief valve.
[00190] Beneficially for this embodiment, the downstream pressure need not be
known by
the completions engineer (or operator) in order to define the optimal pressure
to create the
leak path. The treatment pressure acts only on the pressure internal to the
ball 750, which
causes it to collapse or destruct. This, in turn, allows fluids to bypass the
collapsed ball 750.
[00191] The methods of the present invention can be presented in flow chart
form. Figure
8 represents a flow chart showing steps for a method 800 of completing a well,
in one
embodiment. In connection with the method, a condition of screen-out along the
wellbore is
remediated.
[00192] The method 800 first includes forming a wellbore. This is shown at Box
810.
The wellbore defines a bore that extends into a subsurface formation. The
wellbore may be
formed as a substantially vertical well; more preferably, the well is drilled
as a deviated well
or, even more preferably, a horizontal well.
[00193] The method 800 also includes lining at least a lower portion of the
wellbore with a
string of production casing. This is provided at Box 820. The production
casing is made up
of a series of steel pipe joints that are threadedly connected, end-to-end.
[00194] The method 800 further includes placing a valve along the production
casing.
This is indicated at Box 840. The valve creates a removable barrier to fluid
flow within the
bore. Preferably, the valve is a sliding sleeve having a seat that receives a
ball, wherein the
ball is dropped from the surface to create a pressure seal on the seat. Other
types of valves
may also be used as noted below.
[00195] The method 800 also comprises perforating the production casing. This
is shown
at Box 850. The casing is perforated along a first zone of interest within the
subsurface
formation. The first zone of interest resides at or above the valve. The
process of perforating
involves firing shots into the casing, through a surrounding annular region
(that may or may
not have a cement sheath), and into the surrounding rock matrix making up a
subsurface
formation. This is done by using a perforating gun in the wellbore.
[00196] The method 800 next includes injecting a slurry into the wellbore.
This is
provided at Box 860. The slurry comprises a proppant, preferably carried in an
aqueous
medium. The slurry is injected in sufficient volumes and at sufficient
pressures as to form
fractures in the subsurface formation along the zone of interest.
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[00197] The method 800 further includes pumping the slurry at a pressure
sufficient to
move the valve and to overcome the barrier to fluid flow. This is seen at Box
870. The
pumping is done in response to a condition of screen-out along the first zone
of interest
created during the slurry injection. Moving the valve exposes ports along the
production
casing to the subsurface formation at or below the valve.
[00198] In one aspect of the method, the valve is a sliding sleeve. In this
instance, moving
the valve to expose ports along the production casing comprises moving or
"sliding" the
sleeve to expose one or more ports fabricated in the sliding sleeve.
Optionally, the operator
may inject a fluid (such as an aqueous fluid) under pressure through the
exposed port before
perforating the casing. This creates mini-fractures in the subsurface
formation below the first
zone of interest adjacent the sliding sleeve. In this instance, the operator
will then place a
rupture disc on top of the sliding sleeve to seal the bore to slurry during
fracturing.
[00199] In another embodiment, the method 800 further includes placing a
fracturing
baffle along the production casing. The fracturing baffle resides above the
frac valve but at
or below the first zone of interest. The fracturing baffle may be part of a
sub that is
threadedly connected to the production casing proximate the valve during
initial run-in. A
rupture disc is then pumped down the wellbore ahead of the slurry. The disc is
pumped to a
depth just above the valve until the disc lands on the fracturing baffle. In
this embodiment,
the rupture disc is designed to rupture at a pressure that is greater than a
screen-out pressure,
but lower than the pressure required to move the valve.
[00200] In an alternative arrangement, the rupture disc itself is the
valve. In this
arrangement, the fracturing valve is not used; instead, a second rupture seat
is placed below
the lower zone of interest. Thus, the rupture disc that serves as the valve is
an upper burst
plug, while the other rupture disc is a lower burst plug.
[00201] In another embodiment, the valve is a first burst plug. The first
burst plug will
have a first burst rating. The ports represent perforations that are placed in
the production
casing in a second zone of interest below the first zone of interest. In this
embodiment,
moving the valve to expose ports comprises injecting the slurry at a pressure
that exceeds the
burst rating of the first burst plug. Optionally, in this embodiment the
method further
includes placing a second and a third burst plug along the production casing
at or below the
second zone of interest, creating a domino-effect in the event of multiple
screen-outs. The
second and third burst plugs will have a second burst rating that is equal to
or greater than the
first burst rating. When a burst plug is ruptured, a new through-opening is
created through
the burst plug, wherein the barrier to fluid flow has been removed.
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[00202] In still another aspect, the valve that is moved is a ball-and-seat
valve, while the
ports are perforations earlier placed in the production casing in a second
zone of interest
below the first zone of interest and below the valve. In this instance, moving
the valve to
expose ports comprises injecting the slurry at a pressure that causes the ball
to lose its
pressure seal on the seat. Causing the ball to lose its pressure seal may
define causing the
ball to shatter, causing the ball to dissolve, or causing the ball to
collapse.
[00203] The method 800 additionally includes further pumping the slurry
through the
exposed ports. This is shown at Box 880. In this way, the condition of screen-
out is
remediated. Stated another way, the "screened out" slurry is disposed of
downhole in a
"proppant disposal zone."
[00204] Preferably, the method 800 also includes the step of estimating a
screen-out
pressure along the zone of interest. This is provided at Box 830. This
determining step is
preferably done before the valve is placed along the production casing in the
step of Box 840.
The reason is so that the operator knows what type of valve to use and what
pressure rating or
burst rating is needed for the valve.
[00205] In a preferred embodiment of the method 800, the step of Box 850,
which
involves perforating the production casing, comprises pumping an autonomous
perforating
gun assembly into the wellbore and autonomously firing the perforating gun
along the first
zone of interest. The autonomous perforating gun assembly comprises a
perforating gun, a
depth locator for sensing the location of the assembly within the wellbore,
and an on-board
controller. "Autonomously firing" means pre-programming the controller to send
an
actuation signal to the perforating gun to cause one or more detonators to
fire when the
locator has recognized a selected location of the perforating gun along the
wellbore. In one
aspect, the depth locator is a casing collar locator and the on-board
controller interacts with
the casing collar locator to correlate the spacing of casing collars along the
wellbore with
depth. The casing collar locator identifies collars by detecting magnetic
anomalies along a
casing wall.
[00206] In another aspect, the on-board depth locator is a formation log such
as a gamma
ray log, a density log, or a neutron log. In this instance, the controller is
comparing readings
in real time from the logging tool with a pre-loaded formation log.
Alternatively, the depth
locator may be a location sensor (such as an IR reader) that senses markers
placed along the
casing (such as an IR transceiver). The on-board controller sends the
actuation signal to the
perforating gun when the location sensor has recognized one or more selected
markers along
the casing.
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[00207] It is observed that the perforating gun, the locator, and the on-board
controller are
together dimensioned and arranged to be deployed in the wellbore as an
autonomous unit. In
this application, "autonomous unit" means that the assembly is not immediately
controlled
from the surface. Stated another way, the tool assembly does not rely upon a
signal from the
surface to know when to activate the tool. Preferably, the tool assembly is
released into the
wellbore without a working line. The tool assembly either falls
gravitationally into the
wellbore or is pumped downhole. However, a non-electric working line, such as
slickline,
may optionally be employed to retrieve the autonomous tool.
[00208] It is preferred that the location sensor and the on-board controller
operate with
software in accordance with the locating algorithm discussed above.
Specifically, the
algorithm preferably employs a windowed statistical analysis for interpreting
and converting
magnetic signals generated by the casing collar locator (or, alternatively, a
formation log). In
one aspect, the on-board controller compares the generated signals with a pre-
determined
physical signature obtained for the wellbore objects. For example, a log may
be run before
deploying the autonomous tool in order to determine the spacing of the casing
collars or the
location of formation features. The corresponding depths of the casing collars
or formation
features may be determined based on the speed of the wireline that pulled the
logging device.
[00209] When an autonomous perforating gun assembly is used for completing a
horizontal wellbore, the operator may install a hydraulically-actuated valve
at the toe of the
well. The hydraulically-actuated valve may be installed, for example, just
upstream from a
frac baffle ball-and-seat device. Additional seats or frac baffle rings, etc.,
may be installed
further upstream of the hydraulically-actuated valve in progressively smaller
sizes from top to
bottom.
[00210] Preparation of the well for treatment begins by pumping down a first
ball. The
ball seats on the lowest, or deepest, seat below the hydraulically-actuated
valve. Once seated,
the casing is pressured up to a "designed" set point. For example, a 10,000
psi surface
pressure may be reached by pumping an aqueous fluid. This pressure (acting on
a ball landed
on the seat) causes the hydraulically-actuated valve to open, exposing one or
more ports
along the casing. Once the ports are exposed, hydrostatic and pumping
pressures cause a
small opening to be formed in the subsurface formation adjacent the valve.
Fresh water
continues to be pumped to create a "mini" fracture in the formation. Such a
fracture is shown
at 458 in Figure 4B.
[00211] It is noted that the process of forming the "mini" fracture 458
affords the operator
with a real-time opportunity to evaluate the rock mechanics of the subsurface
formation.
-31-
Specifically, the operator is able to determine a level of pressure generally
needed to initiate
fractures. This may be used as part of the "estimating" step of Box 830
described above. The
operator will understand that the screen-out pressure will be somewhere
significantly above this
initial formation-parting pressure. The operator may then select a proper
sealing device, such as
the rupture disc 460 of Figure 4C or the collapsible ball 750 of Figure 7A,
for use in the well.
[00212] The sealing device is pumped down the wellbore until it is seated on
the seat (or baffle
ring) 462 just above the open hydraulically-actuated valve. In this condition,
the sealing device
creates a barrier to fluid flow through the bore of the well. At the same
time, and as described
above, the sealing device creates a "relief valve" that may be opened by the
pressure and "fluid
hammer" of a screen-out condition.
[00213] When a condition of screen-out occurs, the hydraulically-actuated
valve may be self-
actuated. The valve opens to provide a path for the proppant-laden fluid in
the wellbore to be
swept from the wellbore. The slurry flows through the ports, through the mini
fracture, and into
the subsurface formation at fracture treatment rates. A new autonomous
perforating gun assembly
may then be placed in the wellbore, pumped down, and then used to re-perforate
the trouble zone.
Alternatively, the new autonomous perforating gun assembly may be pumped
downhole to a new
zone of interest for the creation of perforations along the new zone.
[00214] Once the new zone is perforated, the well is ready for the next stage
of fracture
treatment. This is accomplished by then pumping down another removable sealing
device and
placing it in a seat upstream of the hydraulically-actuated valve. Placement
of the sealing device
will force fluids into the new set of perforations.
[00215] It is observed that the wellbore may be designed with more than one
seat. Each seat
resides above a different set of perforations, or above an open sleeve.
Multiple sealing devices, or
plugs, may be landed on the seats, in succession, with each having a
progressively higher pressure
rating. The multiple plugs are capable of "domino-ing" if needed during upset
conditions. This
also creates a large number of available slurry disposal zones, allowing
autonomous perforating
gun assemblies to be pumped into the wellbore for the perforating of the
sequential zones without
the need of wireline tractors or coiled tubing operations.
[00216] The following arc non-limiting examples of embodiments of the subject
matter
disclosed herein.
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[00217] Example 1. A method of completing a well, comprising: forming a
wellbore, the
wellbore comprising a bore extending into a subsurface formation; lining at
least a lower portion
of the wellbore with a string of production casing; placing a valve along the
production casing, the
valve creating a removable barrier to fluid flow within the bore; perforating
the production casing
along a first zone of interest within the subsurface formation, the first zone
of interest residing at
or above the valve; injecting a slurry into the wellbore, the slurry
comprising a fracturing proppant;
in response to a condition of screen-out along the first zone of interest
during the injecting,
pumping the slurry at a pressure sufficient to move the valve and overcome the
barrier to fluid
flow, thereby exposing ports along the production casing to the subsurface
formation at or below
the valve; and further pumping the slurry through the exposed ports, thereby
remediating the
condition of screen-out.
[00218] Example 2. The method of Example 1, wherein the wellbore is completed
along the
subsurface formation in a horizontal orientation.
[00219] Example 3. The method of either of Examples 1 or 2, wherein the valve
is a ball-and-
seat valve or a ball-and-cage valve.
[00220] Example 4. The method of either of Examples 1 or 2, wherein: the valve
is a sliding
sleeve; and moving the valve to expose ports along the production casing
comprises moving the
sliding sleeve to expose one or more ports fabricated in the sliding sleeve.
[00221]
Example 5. The method of either of Examples 1 or 2, wherein: the valve is a
rupture
disc; the ports reside adjacent a sliding sleeve below the first zone of
interest: and the method
further comprises: pumping an aqueous fluid down the wellbore to move the
sliding sleeve, thereby
exposing the ports along the production casing; before injecting the slurry,
further injecting the
aqueous fluid under pressure through the exposed ports, thereby creating
fractures in the
subsurface formation below the first zone of interest adjacent the sliding
sleeve for receiving the
slurry; placing a baffle seat along the production casing, the seat residing
above the sliding sleeve
but at or below the first zone of interest; pumping the rupture disc down the
wellbore ahead of the
slurry to a depth proximate the valve; and landing the rupture disc on the
baffle seat, thereby
creating the barrier to fluid flow; and moving the valve comprises bursting
the rupture disc,
wherein the rupture disc is designed to rupture at a pressure that is greater
than a screen-out
pressure.
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[00222] Example 6. "fhe method of either of Examples 1 or 2, wherein: the
valve is a first burst
plug having a first burst rating; the ports are perforations placed in the
production casing in a
second zone of interest below the first zone of interest; and moving the valve
to expose ports
comprises injecting the slurry at a pressure that exceeds the burst rating of
the first burst plug.
[00223] Example 7. The method of Example 6, further comprising: placing a
second burst plug
along the production casing at or below the second zone of interest, the
second burst plug having
a second burst rating.
[00224] Example 8. The method of Example 7, wherein the second burst rating is
equal to or
greater than the first burst rating.
[00225] Example 9. The method of either of Examples 1 or 2, wherein: the
valve is a ball-and-
seat valve; the ports are perforations placed in the production casing in a
second zone of interest
below the first zone of interest; and moving the valve to expose ports
comprises injecting the slurry
at a pressure that causes the ball to lose its pressure seal on the seat, or
shearing pins to cause the
seat to shear off and move lower in the wellbore below the ports.
[00226] Example 10. The method of Example 9, wherein causing the ball to lose
its pressure
seal comprises causing the ball to shatter, causing the ball to dissolve, or
causing the ball to
collapse.
[00227] Example 11. The method according to any one of Examples 1-10, further
comprising:
estimating a screen-out pressure along the first zone of interest prior to
placing the valve along the
production casing.
[00228] Example 12. The method according to any one of Examples 1-11, further
comprising:
milling out the valve after the condition of screen-out has been remediated.
[00229] Example 13. The method according to any one of Examples 1-11, further
comprising:
in response to failure of the valve, resizing the valve and running in a new
resized valve.
[00230] Example 14. The method of Example 1, further comprising: placing a
valve along the
production casing along a second zone of interest below the first zone of
interest, the valve along
the second zone of interest also creating a removable barrier to fluid flow
within the bore; and in
response to the condition of screen-out along the first zone of interest
during the injecting, pumping
the slurry at a pressure sufficient to move the valve along the second zone of
interest and overcome
the barrier to fluid flow, thereby exposing ports along the production casing
to the subsurface
formation at or below the valve along the second zone of interest; and wherein
further pumping
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the slurry through the exposed ports, thereby remediating the condition of
screen-out, comprises
pumping the slurry through exports ports along the second zone of interest.
[00231] Example 15. The method according to any one of Examples 1-14, wherein:
the valve
is a first burst plug having a first burst rating; the ports are perforations
placed in the production
casing below the zone of interest; and moving the valve to expose ports
comprises injecting the
slurry at a pressure that exceeds the burst rating of the first burst plug,
thereby allowing the slurry
to bypass the first burst plug and invade the subsurface formation through the
perforations; and
the method further comprises placing a second burst plug along the production
casing below the
perforations, the second burst plug having a second burst rating that is equal
to or greater than the
first burst rating.
[00232] Example 16. The method according to any one of Examples 1-15, wherein:
the valve
is a frac plug having a seat configured to receive a ball; the ports are
perforations placed in the
production casing below the zone of interest; and moving the valve to expose
ports comprises:
dropping a ball onto the seat before formation fracturing begins; injecting
the slurry at a pressure
that exceeds the shear rating of pins along the frac plug in response to a
condition of screen-out,
thereby allowing the ball and seat to shear off of the frac plug and move
lower in the wellbore
below the perforations residing below the zone of interest.
[00233] As can be seen, improved methods for remediating a condition of screen-
out are
provided herein. While it will be apparent that the inventions herein
described are well calculated
to achieve the benefits and advantages set forth above, it will be appreciated
that the inventions
arc susceptible to modification, variation and change without departing from
the spirit thereof.
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