Note: Descriptions are shown in the official language in which they were submitted.
CA 02639539 2008-10-29
LIQUIFIED PETROLEUM GAS FRACTURING METHODS
TECHNICAL FIELD
[0001] This application relates to the field of LPG fracturing and treatment
systems
and methods.
BACKGROUND
[0002] In the conventional fracturing of wells, producing formations, new
wells or
low producing wells that have been taken out of production, a formation can be
fractured to
attempt to achieve higher production rates. Proppant and fracturing fluid are
mixed in a
blender and then pumped into a well that penetrates an oil or gas bearing
formation. High
pressure is applied to the well, the formation fractures and proppant carried
by the fracturing
fluid flows into the fractures. The proppant in the fractures holds the
fractures open after
pressure is relaxed and production is resumed. Various fluids have been
disclosed for use as
the fracturing fluid, including various mixtures of hydrocarbons, nitrogen and
carbon
dioxide.
[0003] Care must be taken over the choice of fracturing fluid. The fracturing
fluid
must have a sufficient viscosity to carry the proppant into the fractures,
should minimize
formation damage and must be safe to use. A fracturing fluid that remains in
the formation
after fracturing is not desirable since it may block pores and reduce well
production. For this
reason, carbon dioxide has been used as a fracturing fluid because, when the
fracturing
pressure is reduced, the carbon dioxide gasifies and is easily removed from
the well.
[0004] Lower order alkanes such as propane have also been proposed as
fracturing
fluids. Thus, United States patent no. 3,368,627 describes a fracturing method
that uses a
combination of a liquefied C2-C6 hydrocarbon and carbon dioxide mix as the
fracturing
fluid. The mix is designed to have a critical temperature below the formation
temperature,
and after stimulation is completed and the pressure reduced, the mix heats up
to the
formation temperature and is gasified. As a lower order alkane, ethane,
propane, butane and
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CA 02639539 2008-10-29
pentane are inherently non-damaging to formations. However, this patent does
not describe
how to achieve propane or butane injection safely, or how to inject proppant
into the propane
or butane frac fluid. Further, fracturing mixes contemplated by this patent
are not intended to
be left in the formation for long periods of time, since they gasify once
heated to their critical
temperature by the formation. United States patent no. 5,899,272 also
describes propane as a
fracturing fluid, but the injection system described in that patent has not
been
commercialized. Thus, while propane and butane are desirable fluids for
fracturing due to
their volatility, low weight and easy recovery, those very properties tend to
make propane
and butane hazardous, and thus LPG fracturing had been commercially abandoned
by the
industry until proposed by the inventor Dwight Loree in his Patent Cooperation
Treaty
application no. PCT/CA2007/000342 published September 7, 2007 and related
applications.
SUMMARY
[0005] Methods of tailoring a hydrocarbon fracturing fluid for a subterranean
formation are disclosed. Fluid in the subterranean formation has a fluid
temperature. A first
critical temperature of a base hydrocarbon fluid is adjusted for example to a
critical
temperature above the fluid temperature by adding a critical temperature
adjusting fluid such
as a liquefied petroleum gas component to the base hydrocarbon fluid to
produce the
hydrocarbon fracturing fluid. The liquefied petroleum gas component has a
second critical
temperature, and the base hydrocarbon fluid comprises liquefied petroleum gas.
A
hydrocarbon fracturing fluid made by these methods are also disclosed.
[0006] Methods of treating a subterranean formation are also disclosed. A
hydrocarbon fracturing fluid is introduced into the subterranean formation,
the hydrocarbon
fracturing fluid having a critical temperature that is above a fluid
temperature of the
hydrocarbon fracturing fluid when the hydrocarbon fracturing fluid is in the
subterranean
formation, the hydrocarbon fracturing fluid comprising liquefied petroleum
gas. The
hydrocarbon fracturing fluid is subjected to pressures above the formation
pressure.
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[0007] Methods of treating a subterranean formation are also disclosed. A
hydrocarbon fracturing fluid comprising liquefied petroleum gas is introduced
into the
subterranean formation. The hydrocarbon fracturing fluid is subjected to
pressures above the
formation pressure. The hydrocarbon fracturing fluid is then shut-in in the
subterranean
formation for a period of at least 4 hours. The period may be, for example
longer than 12
hours or 24 hours and could be more than two days.
[0008] Methods of treating plural zones of one or more hydrocarbon
reservoirs penetrated by a well are also disclosed. Hydrocarbon fracturing
fluid comprising
liquefied petroleum gas is introduced through the well into a first zone of
the one or more
hydrocarbon reservoirs. The hydrocarbon fracturing fluid is subjected in the
first zone to
pressures above the formation pressure of the first zone. Hydrocarbon
fracturing fluid
comprising liquefied petroleum gas is introduced through the well into a
second zone of the
one or more hydrocarbon reservoirs. The hydrocarbon fracturing fluid is
subjected in the
second zone to pressures above the formation pressure of the second zone. The
hydrocarbon
fracturing fluid is at least partially removed from the first zone and the
second zone.
[0009] A fluid is also disclosed, the fluid comprising hydrocarbon fracturing
fluid at
least partially removed from the subterranean formations of the methods
disclosed herein. A
subterranean formation is also disclosed comprising the hydrocarbon fracturing
fluid
introduced by any of the methods disclosed herein.
[0010] A method of treating under-pressured formations is also disclosed. The
under-pressured subterranean formation has a formation pressure and contains
formation
fluids. A hydrocarbon fracturing fluid comprising liquefied petroleum gas is
prepared, the
hydrocarbon fracturing fluid having a density such that the static pressure of
the hydrocarbon
fracturing fluid at the under-pressured subterranean formation is less than
the formation
pressure. The hydrocarbon fracturing fluid is introduced into the under-
pressured
subterranean formation. The hydrocarbon fracturing fluid is subjected to
pressures above the
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CA 02639539 2008-10-29
formation pressure. The hydrocarbon fracturing fluid is then recovered along
with formation
fluids.
[0011] These and other aspects of the device and method are set out in the
claims,
which are incorporated here by reference.
BRIEF DESCRIPTION OF THE FIGURES
[0012] Embodiments will now be described with reference to the figures, in
which
like reference characters denote like elements, by way of example, and in
which:
[0013] Fig. 1 is a graph of the saturation curve of propane, illustrating a
fracturing
process.
[0014] Fig. 2 is a graph of saturation curves of various mixtures of propane
and
methane.
[0015] Fig. 3 is a schematic of a fracture created by conventional fracturing
techniques.
[0016] Fig. 4 is a schematic of a fracture created by the methods disclosed
herein.
[0017] Fig. 5 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating proppant being loaded
into
proppant supply vessels.
[0018] Fig. 6 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating pressure testing the
lines with inert
gas.
[0019] Fig. 7 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the bleeding off of
inert gas from
the lines, and commencement of the frac.
[0020] Fig. 8 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the loading of frac
fluid in the well.
[0021] Fig. 9 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the completion of a
frac treatment.
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[0022] Fig. 10 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the purging of LPG-
filled lines with
inert gas.
[0023] Fig. 11 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the purging of the
process blender
with inert gas.
[0024] Fig. 12 is a top plan schematic of a fracturing system carrying out an
embodiment of a method as disclosed herein, illustrating the production of
well fluids upon
completion of a frac treatment.
[0025] Fig. 13 is a graph illustrating various specifications for an exemplary
treatment carried out using an embodiment of a method as disclosed herein.
[0026] Figs. 14A-C illustrate a method of treating plural hydrocarbon
reservoirs
penetrated by a vertical well as disclosed herein.
[0027] Fig. 14D illustrates a method of treating plural hydrocarbon zones of a
reservoir penetrated by a horizontal well as disclosed herein.
[0028] Fig. 15 is a graph illustrating the viscosity of water and LPG.
[0029] Fig. 16 is a graph illustrating the surface tension of water and LPG.
[0030] Fig. 17 is a graph illustrating a gelled hydrocarbon fracturing fluid
breaking
after a set amount of time.
[0031] Fig. 18 is a graph of the saturation curve of propane, illustrating the
separator
operating region.
[0032] Figs. 19A-B are tables that illustrate various examples of formations
fractured
using the methods disclosed herein.
[0033] Fig. 20 is a flow schematic illustrating a method of tailoring a
hydrocarbon
fracturing fluid for a subterranean formation, fluid in the subterranean
formation having
a fluid temperature.
[0034] Fig. 21 is a flow schematic illustrating a method of treating a
subterranean
formation with a fracturing fluid that has a critical temperature above the
fluid temperature.
[0035] Fig. 22 is a flow schematic illustrating a further method of treating a
subterranean formation involving shutting-in the fluid for an extended period
of time.
CA 02639539 2008-10-29
[0036] Fig. 23 is a flow schematic illustrating a method of treating plural
zones of
one or more hydrocarbon reservoirs penetrated by a well.
[0037] Fig. 24 is a flow schematic illustrating a further method of tailoring
a
hydrocarbon fracturing fluid for a subterranean formation, fluid in the
subterranean
formation having a fluid temperature.
[0038] Fig. 25 is a flow schematic illustrating a method of treating an under-
pressured subterranean formation having a formation pressure and containing
formation
fluids.
DETAILED DESCRIPTION
[0039] Immaterial modifications may be made to the embodiments described here
without departing from what is covered by the claims.
[0040] Liquefied Petroleum Gases (hereinafter LPG) include a variety of
petroleum
and natural gases existing in a liquid state at ambient temperatures and
moderate pressures.
In some cases, LPG refers to a mixture of such fluids. These mixes are
generally more
affordable and easier to obtain than any one individual LPG, since they are
hard to separate
and purify individually. Unlike conventional hydrocarbon based fracturing
fluids, common
LPGs are tightly fractionated products resulting in a high degree of purity
and very
predictable performance. Exemplary LPGs used in this document include ethane,
propane,
butane, pentane, hexane, and various mixes thereof. Further examples include
HD-5
propane, commercial butane, i-butane, i-pentane, n-pentane, and n-butane. The
LPG mixture
may be controlled to gain the desired hydraulic fracturing and clean-up
performance.
[0041] LPGs tend to produce excellent fracturing fluids. LPG is readily
available,
cost effective and is easily and safely handled on surface as a liquid under
moderate pressure.
LPG is completely compatible with formations and formation fluids, is highly
soluble in
formation hydrocarbons and eliminates phase trapping - resulting in increased
well
production. LPG may be readily and predictably viscosified to generate a fluid
capable of
efficient fracture creation and excellent proppant transport. After
fracturing, LPG may be
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CA 02639539 2008-10-29
recovered very rapidly, allowing savings on clean up costs. Further, LPG may
be recovered
directly to sales gas without flaring. Referring to Figs. 3 and 4, fractures
formed during
fracturing with conventional and LPG fluids, respectively, are contrasted.
Conventional
stimulation techniques incorporate the use of fluids such as oil, water,
methanol, C02, and
N2 for example. Referring to Fig. 3, the effective fracture length 12 is much
shorter than the
created fracture length 14. The effective fracture length 12 refers to the
length of the created
fracture through which well fluids may be produced into the well. This may
occur as a result
of the high surface tension of conventional fluids creating liquid blocks in
the pores of a
formation. Because the conventional fluids are not easily removed from the
formation, the
liquid blocks effectively eliminate a large portion of fracture through which
fluids may
otherwise be produced. Referring to Fig. 4, on the other hand, the effective
fracture length 12
is the same as the created fracture length 14. This is due to the fact that
the LPG fluid may be
cleaned up quickly and completely. The LPG may clean up by vaporization with
natural gas
in the formation, or by dissolving into solution with formation oil, thus
eliminating the
relative permeability flow reduction seen with conventional fluids. The
vaporization of LPG
with natural gas and the extremely low viscosity of LPG permits rapid clean-up
to be
accomplished with minimal drawdown.
[0042] Referring to Fig. 16, the extremely low surface tension of the LPG
eliminates
or at least significantly reduces the formation of liquid blocks created by
fluid trapping in the
pores of the formation. This is contrasted with the high surface tension of
water, which
makes water less desirable as a conventional fluid. LPG is nearly half the
density of water,
and generates gas at approximately 272 m3 gaslm3 of liquid. LPG comprising
butane and
propane has a hydrostatic gradient at 5.1 kPa/m, which greatly assists any
post-treatment
clean-up required, by allowing greater drawdown. This hydrostatic head is
approximately
half the hydrostatic head of water, indicating that LPG is a naturally under
balanced fluid.
Referring to Fig. 15, LPG also has significantly lowered viscosity than water
in an ungelled
state, which further aids in the removal of LPG from a well.
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CA 02639539 2008-10-29
[0043] Referring to Fig. 1, a propane saturation curve is illustrated. The *
indicates
the critical point of propane, and hence the critical temperature as well. The
critical
temperature is understood as the temperature beyond which the fluid exists as
a gas,
regardless of pressure. The region indicated by the reference numeral 10
corresponds to low-
pressure surface handling, which refers to exemplary ranges of pressures and
temperatures
under which LPG is typically stored prior to use in fracturing. Exemplary
critical
temperatures of LPGs are denoted below in Table 1.
[0044] Table 1
LPG Critical Temperature ( C)
Ethane 32
Propane 97
n-Butane 152
Pentane 197
[0045] Referring to Figs. 20 and 24, methods of tailoring a hydrocarbon
fracturing
fluid for a subterranean formation is illustrated. Fluid in the subterranean
formation has
a fluid temperature. This may be the temperature of fluids contained naturally
in the
formation, or the temperature of fracturing or treatment fluids that have been
in the
formation long enough to acclimatize with the formation. Referring to Fig. 20,
in step 100, a
first critical temperature of a hydrocarbon fluid (base fluid) is adjusted to
a critical
temperature above the fluid temperature by adding a critical temperature
adjusting fluid such
as liquefied petroleum gas component having a second critical temperature to
the
hydrocarbon fluid to produce the hydrocarbon fracturing fluid. The hydrocarbon
fluid
comprises liquefied petroleum gas. As a skilled worker would understand, the
formation
temperature of each formation to be fractured is different, as is the fluid
temperature in each
of these formations. Thus, it is desirable to tailor each hydrocarbon fluid
such that it has a
critical temperature that is above the fluid temperature. This customization
of the critical
temperature of the frac fluid composition allows one to improve the recovery
performance of
8
CA 02639539 2008-10-29
the hydrocarbon fracturing fluid within the reservoir under certain
application pressures and
temperatures. In addition, this customization may allow one to maintain or
improve gel
performance during the fracturing operation. Also, the critical temperature
may be adjusted
to at or above the fluid temperature achieved during placement of the
hydrocarbon fracturing
fluid in order to avoid the degradation of the gel performance that may be
experienced as the
fluid temperature approaches or exceeds the mixture critical temperature due
to heating in or
by the formation. In some embodiments, the critical temperature of the
hydrocarbon
fracturing fluid needs only to be just above, for example by a fraction of a
degree, the fluid
temperature, although it could be a degree or more above such as at least 10,
20, 30, 50, 100
or 150, degrees higher than the fluid temperature. The base fluid may be one
or more of
propane, butane and pentane, and to adjust the critical temperature may be
mixed with one or
more of ethane, propane, butane and pentane. Adjusting the relative amounts of
ethane,
propane, butane and pentane allows key fluid performance aspects relating to
recovery of the
fracturing fluid to be maximized, including viscosity, volatility and surface
tension. The
added LPG component may comprise 1-99 lo by volume of the combined base fluid
and LPG
component.
[0046] It may be desirous to produce a hydrocarbon fracturing fluid that has a
critical
temperature that is above the fluid temperature, but not so far above the
fluid temperature
that subsequent removal from the formation is made difficult. The reason for
this is that, as
hydrocarbon liquids and their liquid mixtures approach the critical
temperature, their
properties become increasingly more gas-like and thereby easier to recover
from the
formation. These properties must be balanced, as gel degradation becomes an
issue if the
fluid temperature is too close to the critical temperature. This careful
balance of the critical
temperature is necessary in order to achieve maximum performance of the fluid.
In some
embodiments, the critical temperature of the hydrocarbon fracturing fluid is
within 50
degrees of the fluid temperature. In further embodiments, the critical
temperature of the
hydrocarbon fracturing fluid is within 40 degrees of the fluid temperature. In
other
embodiments, the critical temperature of the hydrocarbon fracturing fluid is
within, for
example 30, 20, 15, 10, 5 or 1 degrees of the hydrocarbon fracturing fluid.
9
CA 02639539 2008-10-29
[0047] In some embodiments, the second critical temperature is higher than the
first
critical temperature. An example of this may occur if the base hydrocarbon
fluid is propane,
and the LPG component added to adjust the first critical temperature is
butane. In some
embodiments, the second critical temperature is lower than the fust critical
temperature, and
the first critical temperature is above the fluid temperature. These
situations may arise when
the first critical temperature is far above the fluid temperature, and a frac
operator desires to
lower the first critical temperature to improve the recovery and performance
of the
hydrocarbon fracturing fluid. In some embodiments, the base fluid comprises
propane and
butane. In these embodiments, the critical temperature adjusting fluid may be,
for example
propane and ethane.
[0048] Referring to Fig. 24, a further method of tailoring a hydrocarbon
fracturing
fluid for a subterra.nean formation is disclosed, fluid in the subterranean
formation having a
fluid temperature. In step 122, a first critical temperature of a base
hydrocarbon fluid is
adjusted by adding a liquefied petroleum gas component having a second
critical
temperature to the base hydrocarbon fluid to produce the hydrocarbon
fracturing fluid. As
before, the base hydrocarbon fluid comprises liquefied petroleum gas. The
first critical
temperature may be adjusted to, for example above the fluid temperature. In
some
embodiments, it may be advantageous to adjust the first critical temperature
to below, for
example slightly below, the fluid temperature. The base hydrocarbon fluid may
comprise one
or more of propane, butane and pentane, and the liquefied petroleum gas
component may
comprise one or more of ethane, propane, butane and pentane.
[0049] The hydrocarbon fracturing fluid produced by the above methods may
comprise at least one gelling agent. The gelling agent may be any suitable
gelling agent for
gelling LPG, including ethane, propane, butane, pentane or mixtures of ethane,
propane,
butane and pentane, and may be tailored to suit the actual composition of the
frac fluid. One
example of a suitable gelling agent is created by first reacting phosphorus
oxychloride and
an alcohol having hydrocarbon chains of 3-7 carbons long, or in a further for
example
CA 02639539 2008-10-29
alcohols having hydrocarbon chains 4-6 carbons long. The orthophosphate acid
ester formed
is then reacted with an aluminum sulphate activator to create the desired
gelling agent. The
gelling agent created will have hydrocarbon chains from 3-7 carbons long or,
as in the
further example, 4-6 carbons long. The hydrocarbon chains of the gelling agent
may be thus
commensurate in length with the hydrocarbon chains of the liquid petroleum gas
used for the
frac fluid. This gelling agent may be more effective at gelling an ethane,
propane or butane
fluid than a gelling agent with longer hydrocarbon chains. The proportion of
gelling agent in
the frac fluid may be adjusted to obtain a suitable viscosity in the gelled
frac fluid. As
indicated above, the hydrocarbon fracturing fluid may comprise at least one
activator. The
gel chemistry employed in the embodiments of this document may result in visco-
elastic
rheology characteristics. In some embodiments, the hydrocarbon fracturing
fluid may further
comprise at least one breaker. Referring to Fig. 17, an exemplary plot of a
gel containing a
tailored breaker is illustrated. The breaker employed in this example has been
tailored to
begin to begin to break after 30-50 minutes, resulting in a full break at
around 65 minutes.
The system may be comprised of the base gel component, an activator and a
breaker. Normal
loadings at 8 L/m3 may result in viscosities of 300 cP to 400 cP at 100 s"1.
Break times have
been achieved from under 30 minutes to in excess of 4 hours. In some of the
other methods
disclosed herein of treating a subterranean formation, longer break times may
be necessary.
The broken fluid viscosity is that of the base LPG fluid (0.05 - 0.2 cP).
[0050] Referring to Fig. 21, a method of treating a subterranean formation is
disclosed. In step 102, a hydrocarbon fracturing fluid is introduced into the
subterranean
formation, the hydrocarbon fracturing fluid having a critical temperature and
comprising
LPG. The critical temperature is above a fluid temperature of the hydrocarbon
fracturing
fluid when the hydrocarbon fracturing fluid is in the subterranean formation.
In step 104, the
hydrocarbon fracturing fluid is subjected to pressures above the formation
pressure. In some
embodiments, the hydrocarbon fracturing fluid is subjected to pressures at or
above
fracturing pressures. The method may further comprise a step of at least
partially removing
the hydrocarbon fracturing fluid from the formation. As described above, the
presence of
LPG in the hydrocarbon fracturing fluid greatly aids this step.
11
CA 02639539 2008-10-29
[0051] In some embod'nnents, the critical temperature of the hydrocarbon
fracturing
fluid is within 100 degrees of the fluid temperature of the hydrocarbon
fracturing fluid when
the hydrocarbon fracturing fluid is in the subterranean formation. In further
embodiments,
the critical temperature of the hydrocarbon fracturing fluid is within 50
degrees of the fluid
temperature of the hydrocarbon fracturing fluid when the hydrocarbon
fracturing fluid is in
the subterranean formation. In even further embod'unents, the critical
temperature of the
hydrocarbon fracturing fluid is within 30 degrees of the fluid temperature of
the hydrocarbon
fracturing fluid when the hydrocarbon fracturing fluid is in the subterranean
formation. It
should be understood that this hydrocarbon fracturing fluid may be the same as
the
hydrocarbon fracturing fluids disclosed throughout this document. Accordingly,
the critical
temperature of the hydrocarbon fracturing fluid may be at least 1, for example
at least 10
degrees higher than the fluid temperature of the hydrocarbon fracturing fluid
when the
hydrocarbon fracturing fluid is in the subterranean formation.
[0052] Referring to Fig. 22, another method of treating a subterranean
formation is
disclosed. In step 106, a hydrocarbon fracturing fluid comprising liquefied
petroleum gas is
introduced into the subterranean formation. In step 108, the hydrocarbon
fracturing fluid is
subjected to pressures above the formation pressure. In step 110, the
hydrocarbon fracturing
fluid is shut-in in the subterranean formation for a period of at least 1
hour. The shutting-in
period may comprise at least two periods combined, for example if the period
was broken up
into two periods due to the addition of extra hydrocarbon fracturing fluid at
the halfway
point. Under conventional fracturing procedures, the hydrocarbon fracturing
fluid may be
shut-in, but only for short periods of time, usually until the fracturing
itself has been
completed. The extending of the shutting-in period disclosed herein following
the fracture
treatment enhances the subsequent clean-up of the fluid due to the mixing of
the fracturing
fluid with the reservoir gas. Mixing of the fracturing fluid with the
reservoir gas results in
vaporization of the fracturing fluid, providing improved fluid recovery
properties from that
of the fracturing fluid alone. Further, allowing this mixing to occur results
in improved clean
up capabilities as a result of the lowered properties of viscosity and density
from that of the
12
CA 02639539 2008-10-29
fracturing fluid alone. The mixing of the fracturing fluid with the reservoir
gas also results in
the mixture having properties that significantly reduces the capillary
pressure of the mixture
from that of the fracturing fluid alone. This further prevents the liquid
block situation
discussed above, and improves the resulting production from the formation into
the well.
[0053] In some embodiments, the hydrocarbon fracturing fluid is shut-in for a
period
of at least 4 hours. In further embodiments, the hydrocarbon fracturing fluid
is shut-in for a
period of at least 7 hours. In further embodiments, the hydrocarbon fracturing
fluid is shut-in
for a period of at least 10 hours. In even further embodiments, the
hydrocarbon fracturing
fluid is shut-in for a period of at least 15 hours. In even further
embodiments, the
hydrocarbon fracturing fluid is shut-in for longer periods, for example a
period of at least 24
hours. The extended shut-in time may be determined in order to maximize the
mixing of the
hydrocarbon fracturing fluid with the reservoir gas in the most efficient
manner possible.
The hydrocarbon fracturing fluid may have a critical temperature that is above
a fluid
temperature of the hydrocarbon fracturing fluid when the hydrocarbon
fracturing fluid is in
the subterranean formation. The hydrocarbon fracturing fluid may be shut in
for a period
longer than 4 hours, 12 hours or 24 hours. The method may further comprise
producing the
hydrocarbon fracturing fluid along with formation fluids to a sales line.
[0054] Referring to Fig. 23, a method of treating one or more plural
hydrocarbon
reservoirs 15 (shown in Fig. 14A-D) penetrated by a well 16 is illustrated.
Figs. 14A-C
illustrate the method being carried out on plural reservoirs in a vertical
well, and in Fig. 14D,
there is shown a horizontal well 16A penetrating multiple zones 70, 72 and 74
of a single
reservoir 18. The description below refers to treatment of multiple reservoirs
penetrated by a
single vertical well, but applies equally to treating multiple portions of a
single reservoir
penetrated by a horizontal well. In each case, zones are treated, the zones
corresponding to
the portions 70, 72 and 74 penetrated by the horizontal well or the multiple
reservoirs 18, 20
or 30 penetrated by the vertical well In the embodiment illustrated in Fig.
14D, a second
hydrocarbon reservoir 20 may also be treated according to the same methods as
an additional
zone 76.
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CA 02639539 2008-10-29
[0055] Referring to Fig. 14A, in step 112 (shown in Fig. 23), hydrocarbon
fracturing
fluid comprising liquefied petroleum gas is introduced through the well 16
into a first
hydrocarbon reservoir 18 of the one or more hydrocarbon reservoirs 15. In step
114 (shown
in Fig. 23), the hydrocarbon fracturing fluid in the first hydrocarbon
reservoir 18 is then
subjected to pressures above the formation pressure of the fust hydrocarbon
reservoir 18.
Referring to Fig. 14B, in step 116 (shown in Fig. 23) hydrocarbon fracturing
fluid
comprising liquefied petroleum gas is introduced through the well 16 into a
second
hydrocarbon reservoir 20 of the plural hydrocarbon reservoirs 15. In step 118
(shown in Fig.
23), the hydrocarbon fracturing fluid in the second hydrocarbon reservoir 20
is subjected to
pressures above the formation pressure of the second hydrocarbon reservoir 20.
Referring to
Fig. 23, in step 120 the hydrocarbon fracturing fluid is at least partially
removed from the
first hydrocarbon reservoir 18 and the second hydrocarbon reservoir 20. It
should be
understood that step 120 may comprise at least partially removing the
hydrocarbon
fracturing fluid from the first hydrocarbon reservoir 18, and at least
partially removing the
hydrocarbon fracturing fluid from the second hydrocarbon reservoir 20. In some
embodiments, step 120 may comprise at least partially removing the hydrocarbon
fracturing
fluid from the second hydrocarbon reservoir 20, and at least partially
removing the
hydrocarbon fracturing fluid from the first hydrocarbon reservoir 18.
Referring to Fig. 14A,
the method may further comprise shutting in the first hydrocarbon reservoir 18
before
introducing hydrocarbon fracturing fluid into the second hydrocarbon reservoir
20. In some
embodiments, the second hydrocarbon reservoir 20 may be shut in prior to the
recovery of
the hydrocarbon fracturing fluids.
[0056] Referring to Figs. 14A-C, an exemplary method of treating plural
hydrocarbon reservoirs 15 is illustrated. Referring to Fig. 14A, at least one
packer 22 may be
used to implement the method. Packers 22 and 24 may be oriented within well 16
in order to
isolate at least first reservoir 18. Steps 112 and 114 are then carried out,
introducing
hydrocarbon fracturing fluid into reservoir 18 and pressuring up to fracture.
It should be
understood that pressures above the formation pressure include pressures above
the
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CA 02639539 2008-10-29
fracturing pressure. After reservoir 18 is fractured, reservoir 18 may be shut-
in with packer
22, and optionally packer 24 if present. In general the first hydrocarbon
reservoir 18 may be
shut-in with at least one packer 22. Referring to Fig. 14B, packers 26 and 28
are then
positioned around second hydrocarbon reservoir 20 as shown. Steps 116 and 118
are then
carried out, introducing hydrocarbon fracturing fluid into reservoir 20 and
pressuring up to
fracture. After reservoir 20 is fractured, reservoir 20 may be shut-in with at
least packer 28,
and optionally packer 26 if present. The shutting in of the first zone may
occur before at least
partially removing the hydrocarbon fracturing fluid from the first zone.
Referring to Fig.
14C, at this stage, a third hydrocarbon reservoir 30 may then be fractured, in
a similar
fashion as illustrated for reservoirs 18 and 20. It should be understood that
these methods
may be used to fracture more than 3 hydrocarbon reservoirs in a formation
penetrated by
well 16.
[0057] After all of the desired reservoirs have been fractured, step 120 may
be
carried out, at least partially removing the hydrocarbon fracturing fluid from
reservoirs 18,
20, and 30. This method may be contrasted with conventional methods, which
involve
flowing back each reservoir individually before fracturing another reservoir.
This method of
sequential fracturing is much more cost effective and time efficient than
conventional
methods. In some embodiments, this method may be used to fracture reservoirs
penetrated
by a branched well, for example fracturing reservoirs in parallel. In other
embodiments,
reservoir 30 may be fractured, followed by reservoirs 18 and 20 respectively.
By leaving the
hydrocarbon fracturing fluid in the first hydrocarbon reservoir 18 while
reservoirs 20 and 30
are being fractured, the fracturing fluid in reservoir 18 is allowed to mix
with formation gas,
making recovery of the fracturing fluid much easier as discussed in more
detail above. In
some embodiments, the shutting in of the second zone occurs before at least
partially
removing the hydrocarbon fracturing fluid from the second zone.
[0058] Each of reservoirs 18, 20, and 30 may be shut-in for extended amounts
of
time as disclosed in this document for example, in order to achieve this
effect. In some
embodiments, the hydrocarbon fracturing fluid introduced into the first
hydrocarbon
CA 02639539 2008-10-29
reservoir 18 is different from the hydrocarbon fracturing fluid introduced
into the second
hydrocarbon reservoir 20. As each reservoir will have different conditions and
temperatures,
it may be desirable to tailor each hydrocarbon fracturing fluid to best
operate in each
respective reservoir. It should be understood that the hydrocarbon fracturing
fluid(s) used in
this method may be the same as the hydrocarbon fracturing fluids disclosed
throughout this
document. This method is illustrated as being carried out using packers, but
other
implements may be used to achieve the same result. In some embodiments, a
single packer
may be used, pulling up the packer to each respective reservoir after
fracturing the previous
one. For example, this method of isolating the intervals may include the use
of plugs, with
appropriate perforation of the wellbore to access the reservoir, or alternate
mechanical
diverting assemblies within the wellbore. Additionally, the process is
applicable to deviated
and horizontal wellbores and may access a single reservoir at multiple points
along that
wellbore. In some embodiments, at least a portion of the well is at least one
of deviated and
horizontal, and at least one of the first hydrocarbon reservoir and the second
hydrocarbon
reservoir is accessible from the portion of the well.
[0059] It should be understood that all of the embodiments and aspects of each
of the
methods disclosed herein may be combined and incorporated into one another. It
should also
be understood that the hydrocarbon fracturing fluid used at any point in this
document may
be the same as the hydrocarbon fracturing fluids disclosed throughout this
document.
[0060] A fluid comprising the hydrocarbon fracturing fluid at least partially
removed
from the subterranean formations of any of the disclosed methods herein is
also disclosed.
Recovering this flowback fracturing fluid is advantageous, as it may in many
cases be of
suitable quality to pump directly to a sales line. Further, in the event that
the fracturing fluids
have been allowed to mix with the formation gas, the recovered fluid may be
even more
valuable. The gas mixture of hydrocarbon fracturing fluid pumped into a gas
bearing
formation that mixes with natural gas in the formation may be recovered
(produced) into a
typical gas collection system. In some embodiments, this collection or
production may
exclude the recovery of the initial returns to the system without extending
the shut-in. In this
16
CA 02639539 2008-10-29
embodiment, a line heater may be employed to allow the recovery of the initial
returns. In
some embodiments, the LPG recovery can be to directed to a pipeline or flare,
for example.
Initial and immediate LPG recovery, certainly wellbore fluids, are typically
recovered as a
liquid, although later fluids may be predominantly gaseous in nature. The
recovery of the
LPG load fluid can be measured accurately with a gas chromatograph or
estimated on dry
gas wells using gas density. Referring to Fig. 18, the separator operating
region 32 illustrates
the phase region at which most of the LPG is recovered. To date, in excess of
90 % of the
LPG load fluid has been recovered on all applications.
[0061] Referring to Fig. 14A, also disclosed is a subterranean formation
(illustrated
by plural hydrocarbon reservoirs 15 for example) comprising the hydrocarbon
fracturing
fluid introduced into the formation by any of the methods disclosed herein.
Because the
formation, in this instance, contains salable product (the hydrocarbon
fracturing fluid and the
formation gas), the formation itself is quite valuable.
[0062] Referring to Figs. 5 - 12, an exemplary process of fracturing with LPG
hydrocarbon fracturing fluid is illustrated. In the following example,
darkened lines in the
drawings refer to lines through which fluid is flowing. Referring to Fig. 5,
an exemplary set-
up includes a treatment control van 34, an N2 storage truck 36, an LPG trailer
38, a chemical
control unit 40, a sand truck 42, an LPG process blender 44, and LPG
fracturing pumps 46A,
46B.
[0063] Treatment control van 34 provides centralized remote operating and
monitoring of the equipment of the fracturing system. Van 34 may be provided
with a Geo-
Sat communication system, which allows for real time internet based monitoring
and VOIP
phone lines to communicate with systems operators. It also provides continuous
environmental monitoring of 4 wireless remote LEL sensors, and wind direction
and speed
for example. Van 34 may perform all of the required calculations, such as the
optimum blend
of LPG components to add to tailor the hydrocarbon fracturing fluid to best
fracture the
17
CA 02639539 2008-10-29
formation, as well as the optimum job program for fracturing multiple
reservoirs, for
example. Calculations and adjustments may be made on the fly, as needed.
[0064] The N2 storage truck may comprise a flameless N2 pumper, which is
incorporated into the process to supply boost pressure to move the LPG product
through the
process, and to purge all equipment to a safe environment prior to and after
the stimulation.
In some embodiments, no centrifugal pumps are may be used in this process. The
LPG
fracturing process blender may be a closed, pressurized system that uses
integrated Process
Logic Control (PLC) to precisely control the addition of proppant to a stream
of Liquid LPG.
Blender 44 may be operated and monitored from the treatment control and
command center
(illustrated as treatment control van 34 for example). Blender 44 may be
provided with two
16 tonne proppant vessels 48A, B, from which proppant may be metered by two
automated
density controlled augers. Monitoring of blender 44 includes monitoring of
clean and slurry
flow rate, Radioactive Densitometer, Inline Process Viscometer, 4 Point load
cell, Pressure
Transducers, and Closed Circuit cameras. The densitometer may determine the
proppant
concentration being added, while the viscometer determines the extent of
gelling.
[0065] Chemical control unit 40 comprises an integrated and automated chemical
addition system, that may be operated by remote or local operation. Control
unit 40 may
comprise six 4 stage progressive cavity pumps monitored with mass flow meters,
in order to
ensure the proper and precise addition of chemicals into blender 44. Such
chemicals include,
for example gelling agents, breakers, activators, and tailoring LPG
components, for example.
Unit 40 may further comprise an LEL monitoring and alarm system for safety
purposes. Unit
40 may be climate controlled with a high rate air exchanger to ensure a safe
working
environment, and may further comprise a drip proof containment system to
protect a user
and the environment from chemicals.
[0066] The system may also comprise an Iron truck (not shown). The iron trnck
may
operate, for example, 100 m of 76.2 mm ( 3 inch) 103.4 MPa Treating Iron.
Also, the iron
truck may comprise hydraulically operated PLC controlled Plug Valves, operated
from
18
CA 02639539 2008-10-29
treatment control van 34 for example. Iron truck may further have an
integrated equipment
emergency shut down system, and a hydraulic accumulator system.
[00671 LPG Fracturing pumps 46A, B, are designed for increased operating range
and redundancy. Pumps 46A, B, may comprise OEM rated 2,500 hhp Caterpillar
motors, and
may be designed to meet 2006 EPA Tier 2 Non-Road Emissions standards. Pumps
46A, B,
may also comprise 7 speed Caterpillar Transmissions, Quint-plex pumps, and
automatic
over-speed emergency shut-down systems. LPG pumps 46A, B may be operated
digitally
from the Treatment Control and Command Centre (illustrated as treatment
control van 34 for
example). Operating features may include: One man operator control of all
pumps from one
integrated operating screen, automatic pressure testing modes, and
automatically adjustments
of individual pump rates based on the total required rate and maximum
pressure.
[0068] Proppant is first loaded from a supply truck (illustrated as sand tnzck
42) into
the two proppant vessels 48A, 48B of the LPG process blender 44 from a
proppant line 50.
Referring to Fig. 6, air is then displaced out of the LPG process blender 44
proppant blender
vessels 48A, B using pressurized N2 gas supplied from N2 storage truck 36. The
LPG trailer
38 is also pressure balanced with the blender 44 using N2 gas. In some
embodiments, plural
LPG sources are supplied, for example in the form of two or more LPG trailers
38. Each
source may carry different LPG components, for example, in order to tailor the
final mixture
of LPG fracturing fluid. All lines are pressure tested with N2, then with LPG,
including lines
52,54 that lead to wellhead 56, sand separation tank 58, and flare stack 60,
however,
wellhead 56 is not pressurized at this point. Referring to Fig. 7, the LPG
pressure is then bled
off to flare stack 60, to complete the pressure test. Valve 62 is thus opened
to open wellhead
56, and the treatment commences, with hydrocarbon fracturing fluid being
provided to
wellhead 56. Referring to Fig. 13, this point may correspond to time =5
minutes on the
graph. At this stage, the LPG being pumped into the well may be ungelled, and
the clean rate
equals the slurry rate. At this stage, steps 102 and 104 of the method
illustrated in Fig. 21 are
being carried out, if the hydrocarbon fracturing fluid has a critical
temperature that is above a
fluid temperature of the hydrocarbon fracturing fluid when the hydrocarbon
fracturing fluid
19
CA 02639539 2008-10-29
is in the subterranean formation. The bottom hole pressure (Meas'd btmh) is
only slightly
higher than the treating pressure, due at least partially to the hydrostatic
head and the
formation pressure. Referring to Fig. 1, the phase of the LPG fluid, if
propane, follows path
A at this stage, as it is passes through blender 44 and through the HP pumps
46A, B, to the
wellhead 56. Referring to Fig. 8, wellhead 56 is then filled with gelled LPG
fluid. Valve 64
is closed, preventing any flow to flare stack 60. At this stage, chemical
control van 34 is
supplying gelling agents and other fracturing chemicals into LPG process
blender 44. In
addition, LPG trailer 38 is supplying LPG to blender 44, and N2 storage truck
36 continues
to provide pressure balancing between LPG trailer 38 and blender 44. Blender
44 blends and
mixes the hydrocarbon fracturing fluid, while LPG fracturing pumps 46A, B are
operating to
pump the fracturing fluid mix into wellhead 56. Chemical control van 34 may
provide a
tailored amount of gelling agents, as well as any additional LPG components
required to
tailor the fracturing fluid to the subterranean formation being fractured. In
some
embodiments, the additional LPG components may be provided by separate LPG
trailers 38
(not shown). As the fracturing continues, the formation is broken down, and a
feed rate is
established. Referring to Fig. 13, this may correspond to time =14 minutes,
where gelled and
proppant loaded fracturing fluid is being pumped into the well. Blender
concentration
indicates the concentration of proppant in the frac fluid. Slurry rate refers
to overall rate of
fluid entering the wellhead 56. Refemng to Fig. 8, a pad of frac fluid may be
pumped down
as per the job program selected, as is illustrated in Fig. 13 from time =0
minutes to time =
12 minutes. Proppant is added to the gelled LPG as per the selected job
program, through
vessels 48A,B. N2 gas replaces the surface volume of the displaced proppant
and LPG in
vessels 48A,B and LPG trailer 38, respectively. The proppant is under flushed
to the
perforations created downhole using the LPG fluid. Referring to Fig. 1, the
phase of the LPG
fluid, if propane, follows path B as it passes from the wellhead 56, through
the tubular, and
into the fractures. As the LPG enters the fracture and leaks-off to the
reservoir conditions,
the LPG fluid follows path C.
[0069] Referring to Fig. 9, upon completion of the treatment, the wellhead 56
is
closed. The supply from LPG trailer 38, proppant supply vessels 48A,B, and
chemical
CA 02639539 2008-10-29
control van 40 are each closed and isolated, for safety precautions. At this
stage, wellhead 56
may be shut-in for an appropriate amount of time, as in the methods disclosed
herein, for
example an extended amount of time. Step 110 of the method illustrated in Fig.
22 may be
carried out at this stage. Referring to Fig. 13, this may correspond to time
=38 minutes, for
example. Referring to Fig. 1, the phase of the LPG fluid, if propane, follows
path D as it
flows back from the reservoir to the surface, becoming more gas-like in the
process.
Referring to Fig. 9, upon completion of the shut-in period, if any, all high-
pressure lines
containing LPG frac fluid may be de-pressurized to flare stack 60. Referring
to Fig. 10, all
LPG-filled lines are then purged with N2 to flare stack 60. Referring to Fig.
11, LPG Process
blender 44 is then purged with N2 to the flare stack 60 via line 66. All of
the LPG fracturing
process equipment is then rigged out. Referring to Fig. 12, given that a flow
line 68 is
available on location, the wellhead 56 can be produced back to the production
facilities
saving the cost of testing equipment, and resulting in no damage, limited
cleanup, and no
disposal.
[0070] It should be understood that the systems disclosed above may be used to
carry
out the methods illustrated and described for Fig. 23. The job program
required for this
would be delegated from treatment control van 34, and would involve
manipulation of the
same system to achieve the goals of the method.
[0071] The LPG fracturing processes disclosed herein should be implemented
with
design considerations to mitigate and eliminate the potential risks, such as
by compliance
with the Enform Document: Pumping of Flammable Fluids Industry Recommended
Practice
(IRP), Volume 8-2002, and NFPA 58 "Liquefied Petroleum Gas Code".
[0072] These methods may be used on sub-normally saturated and under-pressured
reservoirs, including gas, oil and water wells, to eliminate altered
saturations and relative
permeability effects, accelerate clean-up, realize full frac length, and
improve long-term
production. Further, these methods may be used on reservoirs that exhibit high
capillary
pressures with conventional fluids to eliminate phase trapping. These methods
may also be
21
CA 02639539 2008-10-29
used on low permeability reservoirs, which normally require long effective
frac lengths to
sustain economic production, to accelerate clean-up, realize full frac length
quicker, and
improve production. These methods may also be used on recompletions with
recovery
through existing facilities, in order to recover all LPG fluid to sales gas -
thus reducing
clean-up costs, avoiding conventional fluid recovery and handling costs, and
eliminating
flaring. Multiple frac treatments may be completed without the need for
immediate frac
clean-up between treatments, as the extended shut-in simplifies and speeds the
clean-up
without detriment to formation. These methods may also be used in exploration,
as the
pumping of a completely reservoir compatible fluid provides excellent
stimulation plus rapid
cleanup and evaluation, which gives a fast turnaround and zero-damage
evaluation in
potentially unknown reservoir and reservoir fluid characteristics.
[0073] Figs. 19A and B illustrate examples of successful fracturing procedures
carried out using the methods as disclosed herein. Various specifications of
each job are
indicated in those figures.
[0074] Hydraulic fracturing with LPG has been done in the past, but has since
been
deemed too dangerous by others, and as a result, most development in this area
has slowed
or stopped. However, by combining safety techniques, LPG fracturing can be
made safe.
LPG Processes disclosed herein require no load fluids, CO2 or N2 during
initial production
which is less taxing on the production equipment, which results in reduced
well clean-up
time, although in specific instances, there may be additional fluids pumped
with the LPG
fluids.
[0075] Tailoring of the LPG component mix also enhances recovery in under-
pressured reservoirs via the combination of low hydrostatic, mixing with
native reservoir
hydrocarbons, low viscosity and minimized surface tension/capillary pressure.
Under-
pressured refers to the formation pressure being lower than the hydrostatic
pressure at the
formation depth. The density of a hydrocarbon fracturing fluid comprising LPG
may be
adjusted by selection of LPG components to produce a hydrocarbon fracturing
fluid, the
22
CA 02639539 2008-10-29
density of which makes the static pressure of the hydrocarbon fracturing fluid
at the
formation depth less than the formation pressure. All frac fluid components
may be
recovered directly to the sales or pipeline with no flaring or collection of
liquids at surface
by making the hydrostatic pressure of the fracturing fluid in the formation
being treated low
enough for the well to have a flowing pressure that permits clean-up, and
composition
suitable for the pipeline (no C02, N2, methanol or water). Referring to Fig.
25, a method is
disclosed of treating an under-pressured subterranean formation having a
formation pressure
and containing formation fluids. In step 124, a hydrocarbon fracturing fluid
comprising
liquefied petroleum gas is prepared, the hydrocarbon fracturing fluid having a
density such
that the static pressure of the hydrocarbon fracturing fluid at the under-
pressured
subterranean formation is less than the formation pressure. In some
embodiments the
hydrocarbon fracturing fluid is prepared. In step 126, the hydrocarbon
fracturing fluid is
introduced into the under-pressured subterranean formation. In step 128, the
hydrocarbon
fracturing fluid is subjected to pressures above the formation pressure. In
step 130, the
hydrocarbon fracturing fluid is recovered along with formation fluids. In some
embodiments,
the hydrocarbon fracturing fluid has a critical temperature that is above a
fluid temperature
of the hydrocarbon fracturing fluid when the hydrocarbon fracturing fluid is
in the
subterranean formation. In some embodiments, the hydrocarbon fracturing fluid
is subjected
to pressures at or above fracturing pressures. In some embodiments, the
recovered fluids are
directed to a sales line.
[0076] In any of the disclosed embodiments of the methods described here, when
the
fluid in the subterranean formation comprises formation gas such as methane,
the formation
gas mixes with the hydrocarbon fracturing fluid to alter the critical
temperature of the
hydrocarbon fracturing fluid in the subterranean formation. When the critical
temperature is
lowered as for example in the case of mixing with methane, the resulting
transition of the
hydrocarbon fracturing fluid to a more gaseous state assists in expelling the
hydrocarbon
fracturing fluid from the subterranean formation and the well.
23
CA 02639539 2008-10-29
[0077] In particular in the case of an under-pressured gas reservoir, the LPG
mixes
with the reservoir gas, resulting in vaporization and subsequent reduction in
density much
beyond the originally low hydrostatic provided by the LPG fluid by itself.
This benefit is
important when treating under-pressured reservoirs. Thus, Fig. 2 shows the
mixture
properties of propane with methane. The particular lines shown are the vapor-
lines, that
being the pressure temperature relationship below which the mixture exists as
100% vapors.
The end point of each curve is the critical temperature of the mixture. The
mixing desirably
results in a frac-fluid/reservoir composition where the critical temperature
is below the
reservoir temperature. This mixing is intended to occur within the formation
following the
fracturing treatment, during shut-in and subsequent clean-up. Hence, the LPG
mix
is designed to promote mixing with reservoir gas to achieve vaporization as
another primary
mechanism for developing a suitable hydrostatic for ready clean-up. The
hydrostatic is
important as it sets the surface flowing pressure of the well during clean-up.
If the surface
flow pressure is too low, then the well may not have sufficient pressure to
clean-up into the
pipeline. This pipeline pressure may range from under 20 psi to over 1,000 psi
and the well
flow condition must exceed this pressure in order to enter it.
[0078] In the claims, the word "comprising" is used in its inclusive sense and
does
not exclude other elements being present. The indefinite article "a" before a
claim feature
does not exclude more than one of the feature being present. Each one of the
individual
features described here may be used in one or more embodiments and is not, by
virtue only
of being described here, to be construed as essential to all embodiments as
defined by the
claims.
24
