Note: Descriptions are shown in the official language in which they were submitted.
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METHOD FOR ALTERING THE STRESS STATE OF A FORMATION
AND/OR A TUBULAR
This application is a continuation in part of U.S. Application Serial No.
60/953,776,
filed on August 3, 2007 and entitled "Method For Altering The Stress State Of
A
Formation," which is incorporated herein by reference.
Field of Invention
The present inventions include method for altering the stress state of a
subterranean
formation having an unstable portion using a tubular element expanded into or
against the
unstable portion.
Background
[0001] Damage to weakly cemented, unconsolidated sands or soft rocks during
the
production and drilling of reservoirs is a costly problem for the oil and gas
industry. Many
of the reservoirs that are easy to drill and produce have already have been
depleted during
past oil and gas production operations leaving much of the existing reserves
in more
expensive, problematic reservoirs. Many of these remaining reservoirs are
mechanically
unstable and generate costly drilling and production problems such as
compaction,
depletion, water production, and formation movement.
[0002] Reservoir compaction occurs when large volumes of gas, oil, and
formation water
are extracted from subsurface reservoirs causing a reduction in the original
pressure in the
reservoir. The phenomenon is described in detail in article entitled An
Introduction To
Reservoir Geomechanics by Colin Sayers and Peter M. T. M. Schutjens published
in The
Leading Edge, Volume 26, Issue 5, pp. 597-601 (May 2007).
[0003] Reservoir compaction occurs because the weight of sediments above the
oil and gas
formation is supported by the rock matrix and the pressurized oil and gas
within the rock
pore space. When a reservoir is depleted, the reduction in pressure transfers
the load to the
depleted formation, causing it to compact and thereby reducing the ability of
the formation
to produce. If subsurface compaction is significant or if the formation is
relatively shallow,
it can result measurable surface subsidence which interferes with existing
drilling and
production infrastructure. Where multiple fields are producing from the same
reservoir or
stratigraphic interval, depressurization can occur on a regional scale,
resulting in
subsidence and land loss in areas between and adjacent to the fields.
Additionally,
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formation compaction can also induce compression and buckling damage within
the
producing interval.
[0004] Wellbores are typically formed in two phases. In the first phase, a
drill string (or
drill pipe) with a drill bit attached to the lower end is rotated by a kelly,
top drive system,
rotary table, or coiled tubing system located at the surface. As the drill bit
creates a hole in
the earth, drilling mud is circulated through the annular space between the
drill string and
the wellbore wall to cool the bit and transport cuttings (rock chips from
drilling) to the
surface. The hydrostatic pressure exerted by the column of mud in the hole
prevents
blowouts that may result when the bit penetrates a high-pressure oil or gas
zone. If the
mud pressure becomes too low, the formation can force the mud from the hole
resulting in
a blowout. Conversely if the mud pressure becomes too high, the differential
pressure
becomes great enough that mud flows into the formation resulting in lost
circulation.
[0005] Lost circulation may also occur when the bit encounters natural
fissures, caverns, or
depleted zones, which provide a newly available space into which the mud can
flow. The
loss of drilling mud and cuttings into the formation results in slower
drilling rates and
plugging of productive formations. In a severe situation, it can cause a
catastrophic loss of
well control. Additionally the loss of fluid to the formation represents a
financial loss that
must be dealt with, and the impact of which is directly tied to the per barrel
cost of the
drilling fluid and the loss rate over time.
[0006] In the next phase of drilling, the drill string and bit are removed and
the wellbore is
lined with a string of pipe known as casing. The casing serves to stabilize
the newly
formed wellbore and facilitate the isolation of certain areas of the wellbore
adjacent to the
hydrocarbon bearing formations. Once the casing is cemented in the wellbore, a
smaller bit
is inserted through the casing and used to drill deeper into the earth. This
process is then
repeated and numerous sections of casing are installed until the desired depth
is reached.
When the well is complete, the entire string of casing resembles an extended,
inverted
telescope in which casings of decreasing diameter are arranged in a nested
configuration.
[0007] As a consequence of this procedure, the casing in the lower interval of
the wellbore
has a significantly smaller diameter than the casing in the upper interval of
the wellbore.
Operators are often required to begin the drilling procedure with a relatively
large initial
borehole to reach planned depths. A larger initial borehole results in
increased costs due to
timing delays, rig time, and handling of equipment. In some cases, the
ultimate depth of a
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well is limited by the initial borehole requirement and certain projects fail
to be recognized
as economical for this reason.
[0008] To overcome this problem, the oil and gas industry has begun to
experiment with
drilling and casing techniques that involve radially expanding individual
casing strings as
they are installed in the well in order to maximize the available diameter.
[0009] Although the use of expandable tubular technology helps reduce the
problem
associating with the telescoping effects of drilling and completing wells,
traditional
problems such as compaction, depletion, water production, and formation
movement still
occur, making many wells into costly and time consuming projects.
[0010] Typical drilling methods for dealing with situations involving
compaction and
depleted reservoirs include drilling with drill string to within a few meters
of the unstable
or depleted reservoir, tripping the drill string out of the hole, running
casing to bottom and
setting it in cement. The objective of this method is to isolate as much of
the overburden as
possible so as to minimize the negative effects of lost returns. Nevertheless,
once the
remainder of the overlying reservoir is drilled and the unstable or depleted
reservoir is
penetrated, the differential pressure will still cause the weighted mud system
to flow into
the low-pressure formation that plugs up the formation.
[0011] Another method is to drill until the bottom of the hole "falls out,"
remove
the drill pipe from the hole, and seal off the losses with a sealing device
such as a cement
plug. After the plug is installed, casing may be run into run into the
borehole to the top of
the loss zone where the reservoir is drilled with a reduced mud weight to
prevent further
losses. Neither of these methods is satisfactory, however, due to the time
required for
pulling the drill pipe and the losses of the weighted mud and cement to the
production
zone.
[0012] US Patent 5,957,225 discloses a method of drilling into a reservoir
formation that is
unstable or depleted relative to adjacent formations comprising drilling into
an area above
the unstable or depleted formation to form a wellbore in that area and running
an elongate
liner assembly having a portion formed of a drillable material and cutters
disposed adjacent
to the bottom of the liner assembly into the wellbore. The liner assembly is
then rotated to
drill through the area above the unstable or depleted formation into the
unstable or depleted
formation to extend the wellbore. The liner assembly is then set in the
wellbore and a drill
bit is run into the wellbore and rotated to cut through the liner portion of
drillable material.
Although this method can minimize well control problems associated with
unstable or
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depleted reservoirs, it does not address the telescoping effect of nesting
casing drilled in
the traditional manner. Additionally, the method requires specialized tools
that are costly to
make and may have uncertainties associated with operation.
[0013] Hence, there remains a need for a technique for drilling through
unstable
formations and avoiding the nested casings that are typically required.
Summary of the Invention
[0014] The present inventions include a method for altering the stress state
of a
subterranean formation having an unstable portion comprising drilling a
borehole in the
formation into the unstable portion of the formation, installing a tubular
element having a
top end and a bottom end across the unstable portion of the formation,
anchoring the top
end and the bottom end of the tubular element to the formation and expanding
the tubular
element thereby inducing compression between the top end and the bottom end.
The
present method also provides a technique for altering the stress state within
the tubular
itself.
[0015] The present methods can be used in a wellbore that traverses a
formation with an
unstable portion. The present methods comprise anchoring a tubular element
above and
below at least a section of the unstable portion of the formation; and
expanding a tubular
element. In some embodiments, a compressive force is applied to the unstable
portion
between the top end and the bottom end of the expanded tubular.
[0016] In other embodiments, three or more anchor points are provided at
predetermined
distances along a tubular and the tubular is expanded between the points. By
providing at
least one anchor point that is located between the lowermost and uppermost
anchor points,
tensile stress that would otherwise accumulate during expansion of the entire
length of the
tubular instead accumulates only along the distance between adjacent anchor
points. This
in turn reduces the maximum tensile strength to which the tubular is subjected
during
expansion. In some embodiments, a compressive force is applied to the
formation between
each pair of anchor points.
Brief Description of the Drawings
[0017] The present invention is better understood by reading the following
description of
non-limitative embodiments with reference to the attached drawings, wherein
like parts of
each of the figures are identified by the same reference characters, and which
are briefly
described as follows:
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Figure 1 is a schematic view of a wellbore traversing a formation with an
unstable
portion.
Figure 2 is a schematic view of the wellbore lined with a tubular element.
Figure 3 is a schematic view of the tubular element expanded into or against
the
formation.
Figure 4 is a side view of one embodiment of an anchoring assembly connectable
the tubular element.
Figure 5 is a cross-sectional view of the anchoring assembly of Figure 4 in a
retracted mode.
Figure 6 is a cross-sectional view of the anchoring assembly of Figure 4 in an
expanded mode.
Figure 7 is a schematic view of an expandable tubular element anchored at
multiple
points.
[0018] It will be understood that the Figures are not to scale and are not
intended to convey
dimensions, relative size of components, or other quantitative aspects of the
invention.
Detailed Description
[0019] In this specification, the term tubular element is meant to include any
tubular to be
expanded. A casing, open hole liner, or other wellbore tubular may be expanded
by the
methods and apparatuses described and claimed herein.
[0020] Referring to Figure 1, a wellbore 100 is shown drilled through a
formation 101.
Formation 101 has an unstable portion 102, which is traversed by wellbore 100.
Unstable
portion 102 may be any type of formation that could pose drilling and
production
challenges. For example, unstable portion 102 may be a portion of the
formation subject to
compaction, depletion, water production, or formation movement.
[0021] Wellbore 100 may be drilled using coiled tubing, expandable drilling
casing, or any
other known method. In this exemplary embodiment, wellbore 100 has been
drilled with a
tubular 103 attached to a drill bit 104. Tubular 103 may be for example,
expandable casing,
expandable liner, conventional casing, or any other known type of drilling
pipe.
Optionally, the portion of the wellbore above unstable portion 102 may be
lined with a
tubular 105.
[0022] Once wellbore 100 is drilled through unstable portion 102, a tubular
element 200
may be installed across unstable portion 102 as shown in Figure 2. Tubular
element 200
may be, for example, a joint of expandable casing, expandable liner, or any
other type of
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drilling tubular. Typically these joints are about 30 to 40 feet (about 9 to
12 meters) in
length; however tubular elements made according to custom specifications may
be used to
suit the application. Alternatively more than one length of tubular element
may be used to
line unstable portion 102.
[0023] Tubular element 200 has a top end 201 and a bottom end 202 that are
anchored to
formation 101. Anchoring to the formation may be any suitable means, including
expansion against the formation. Expansion assembly 203 is run into the hole
with tubular
element 200 or alternatively installed after tubular element 200 is installed.
In alternative
embodiments, expansion assembly 203 and drill bit 104 can be integrated into a
single tool.
In the embodiment shown, expansion assembly 203 comprises an expansion cone
204;
however, many alternative expansion systems, such as are known in the art,
could be
employed.
[0024] Referring to Figure 3, tubular element 200 is expanded against or into
the formation
as shown at 205, using any of the traditional methods of expansion. In one
embodiment,
tubular element 200 may be expanded using the solid expandable tubular (or
SET) method
of expansion. At the bottom of the SET system is a canister, known as the
launcher (not
shown), that contains the expansion cone. The launcher is constructed of thin
wall, high
strength steel that has a thinner wall thickness than the expandable casing.
In this method,
expansion cone 204 may be moved through tubular element 200 by applying a
differential
hydraulic pressure across the cone itself. The differential pressure may be
pumped through
an inner string connected to the cone.
[0025] In another embodiment, tubular element 200 may be expanded using purely
mechanical methods. In this embodiment, expansion assembly 203 may be moved
through
tubular element 200 by applying a direct mechanical pull or push force, such
as is shown at
arrow 206. The mechanical force may applied by either raising (in a "bottom
up"
expansion) or lowering (in a "top down" expansion) the inner string using a
jack or other
surface lifting tool. Alternatively, a downhole jack or gripping tool may be
used to apply
the requisite force.
[0026] Still referring to Figure 3, regardless of which expansion mechanism is
used, radial
expansion of the tubular typically causes axial shorting of the tubular. Thus,
as expansion
assembly 203 moves along the length of tubular element 200, stresses within
the pipe tend
to draw top end 201 and bottom end 202 together. However, because ends 201,
202 are
anchored to formation 101, these stresses result in a force being applied to
the formation,
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which in turn alters the stress state in wellbore 101. Thus, expansion into or
against the
formation creates a compressive force on unstable portion 102 indicated by
arrows 300. If
enough compression is applied, the fracture gradient of the formation may be
increased.
[0027] In addition, if unstable portion 102 is a depleted region of formation
101, the
expanded tubular and compressive force may serve to isolate the unstable
portion from the
rest of the formation. If a depleted region is not isolated, the operator may
encounter lost
circulation problems requiring drilling of another well or other remedial
measures. If
unstable portion 102 is a water producing zone, expanding against or into the
formation
can serve to produce a seal and isolate this zone from the rest of the
formation.
[0028] It will be understood the points at which the expandable tubular
element are
anchored need not be at its ends. Rather, the concepts disclosed herein are
applicable for
any portion of a tubular element that is anchored at more than one point along
its length.
[0029] If the tubular element 200 is to be deliberately anchored at one or
more locations,
the anchoring may be achieved via various known methods. In one embodiment,
tubular
element 200 may include one or more anchoring assemblies 400 located at the
desired
anchoring point(s), such as top end 201 and/or bottom end 202 or at one or
more points
therebetween. Figure 4 depicts one example of a type of anchoring assembly
that could be
used in this application. In the embodiment illustrated, anchoring assembly
400 is attached
to the lower end 202 end of tubular 200. Anchoring assembly 400 comprises one
or more
splines 401, which are initially in a retracted mode shown in Figure 5. When
tubular
element 200 is radially expanded (e.g. by moving expansion cone 203 through
tubular
200), the radially outward force exerted by expansion assembly 203 shifts
splines 401 into
an expanded mode, as shown in Figure 6. In this expanded position, splines 401
engage the
formation, anchoring the tubular element to it. It will be understood that
splines 401 can be
any shape or configuration. Likewise, they may be replaced with any other
engagement
means, including fixed or moveable members extending outwardly from the
surface of
tubular 200, elastomers, teeth, ridges, packers, or the like. In some
embodiments, achoring
may be achieved merely by expansion of the tubular against the borehole wall,
without
additional engaging means.
[0030] After tubular element 200 is expanded and anchored into formation 101,
the
operator may continue drilling the well, by drilling through unstable portion
102 and
extending wellbore 100, or may conduct any other desired downhole operation.
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[0031] While the radial stresses caused by radial expansion stop increasing
when tubular
element 200 reaches the desired expanded diameter, the stresses caused by
axial shorting
may behave differently, particularly if the unexpanded casing is fixed at two
(or more)
points within the borehole, as at 201, 202. Situations in which an unexpanded
casing is
fixed at two or more points within the borehole will be referred to
hereinafter as a "fixed-
fixed" tubular. While an example of a deliberately fixed-fixed tubular is
described above,
a fixed-fixed tubular can occur even if tubular element (or portion thereof)
is not
deliberately fixed at both ends.
[0032] For instance, if the casing becomes stuck to the hole wall before
expansion and its
lower end is deliberately anchored at the beginning of expansion (so that the
expansion
device can be pulled upward from the lower end), a fixed-fixed tubular will
result.
Similarly, if the borehole wall "grabs" the casing at two or more points along
its length, a
fixed-fixed tubular will result. It has been found that is it sometimes
desirable to drill a
hole having a diameter that is close to the expanded diameter of the casing,
thereby
increasing the likelihood that such a sticking contact will occur between the
tubular and the
borehole wall. In addition, there may be instances in which the borehole wall
does not
maintain its integrity and shifts or deforms so that the shape or diameter of
the borehole
changes. In such cases, there is an increased likelihood that the casing will
become fixed at
one or more points in the borehole between the time that is emplaced and the
time that it is
expanded. If there is a delay during this period, the likelihood of
deformation of the
borehole, and thus the likelihood of sticking, increases further. Curved
boreholes and
boreholes in which the wall is unstable and prone to slumping are also more
likely to
produce fixed-fixed situations.
[0033] Similarly, due to varying conditions and properties of the formations,
the wellbore
wall often has ledges or other projections that jut out into the borehole.
This is particularly
common in deviated wells and can frequently cause a problem with tools
becoming stuck
or broken by the ledges or projections. Thus, in one embodiment, projections
in the
wellbore can be utilized to advantage by deliberatly anchoring the tubular
element against
the ledges or projections. In this embodiment, the location of the ledges can
be determined
by performing a conventional logging operation and altering the well design to
align the
anchoring assemblies with the ledges.
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[0034] Advantages of some embodiments of the expanding a fixed-fixed tubular
include
one or of the following:
^ ability to isolate unstable portion of a formation without additional
tripping in
and out of the wellbore,
^ reduction of starting size of wellbore due to use of expandable casing or
liner,
^ ability to stimulate depleted formation,
^ ability to isolate water producing formation,
^ avoiding the requirement to drill another well to get around an unstable
portion
of the formation,
^ sealing mechanism created by anchoring mechanisms eliminates the need for
cement, and
^ reduced drilling costs and rig time.
[0035] However, regardless of whether one or more of the anchor points is
deliberate, it
has been found that in cases where a fixed-fixed tubular occurs, axial
stresses accumulate
as the expansion device moves along the casing from one fixed point to the
other. As axial
stresses accumulate, they may exceed the maximum stress that can be withstood
by the
tubular, causing it to tear or break. Thus, there is a need for a way to
prevent excessive
stress build-up in expanding tubulars that are fixed at more than one point
along their
lengths.
[0036] It has been found that by ensuring that the distance between any two
anchor points
is less than the distance required to accumulate a fatal stress during
expansion, failures due
to expansion can be avoided. This is true regardless of whether the anchor
points are
deliberately placed. Thus, one preferred technique is to determine the axial
distance over
which expansion in a fixed-fixed tubular can be tolerated and then to provide
anchor points
that are closer together than the predetermined distance. This concept is
illustrated
schematically in Figure 7.
[0037] In Figure 7, the lower end of an expandable tubular has been
deliberately anchored
to the formation at anchor point 500, so as to provide a fixed point against
which the
expansion cone (not shown, for simplicity) can be pulled. At some point above
the lower
end, such as at point 502, the tubular may become stuck to the formation,
either
deliberately, or as a result of the partial collapse of an unstable portion of
the borehole
wall. This would create a fixed-fixed tubular in which the distance between
anchor points
500, 502 is indicated by L.
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[0038] Given certain information about the tubular and the expansion ratio, it
is possible to
calculate the maximum length of pipe that could be expanded between two anchor
points
without failing. This distance is indicated in Figure 7 by E. In cases where E
is smaller
than L, it may be desired to add at least one anchor point 504 between anchor
points 500
and 502. In this way, two portions of expandable tubing are formed, having
lengths Si and
S2, both of which are shorter than E. When the tubular of Figure 7 is expanded
the axial
stress accumulates during expansion of each section Si and S2, but does not
exceed L
because it returns to zero, or near-zero, at each intermediate anchor point
504.
[0039] In some embodiments, anchor points having a desired spacing may be
provided as a
preventive measure. In other embodiments, it may be decided to add anchor
points after it
has been determined that the expandable tubular has become stuck in the
borehole,
resulting in an undesired fixed-fixed tubular. The spacing of the anchor
points may or may
not be influenced by the presence, or not, of an unstable portion of the
formation
surrounding the borehole..
[0040] Those of skill in the art will appreciate that many modifications and
variations are
possible in terms of the disclosed embodiments, configurations, materials, and
methods
without departing from the scope of the invention. For example, the number,
size, shape
and/or mechanism of the anchor points can vary widely. Accordingly, the scope
of the
claims appended hereafter and their functional equivalents should not be
limited by
particular embodiments described and illustrated herein, as these are merely
exemplary in
nature and elements described separately may be optionally combined.
