Note: Descriptions are shown in the official language in which they were submitted.
CA 02716446 2010-10-01
EFFECTIVE HORIZONTAL DRILLING THROUGH A HYDROCARBON RESERVOIR
TECHNICAL FIELD
[0001] This document relates to methods of effective horizontal drilling
through a
hydrocarbon reservoir within a subterranean formation.
BACKGROUND
[0002] Many oil reservoirs are found in subterranean formations as thin beds
of
hydrocarbons that extend a relatively long lateral distance. Because of the
wide area covered
by these beds, it has been found to be economical in some cases to drill a
deviated or
horizontal well through the oil reservoir. Referring to Figs. lA-B, an example
of horizontal
drilling through a hydrocarbon reservoir 10 is illustrated. As shown, multiple
wells 11 may
be drilled from the same bore or from individual parent wells 13. Horizontal
wells drilled in
this fashion can produce more oil than a vertical well drilled into the same
reservoir.
[0003] Horizontal wells have other applications as well, such as producing
fractured
reservoirs, formations with water and gas coning problems, waterflooding,
heavy oil
reservoirs, gas reservoirs, and in Enhanced Oil Recovery (EOR) methods such as
thermal
and C02 flooding.
[0004] Despite the growth of horizontal well drilling, horizontal wells have
numerous disadvantages compared to conventionally drilled wells. Firstly,
horizontal wells
cost much more than a vertical well. Some of this cost comes from unique
technical
requirements that may be required for drilling the particular reservoir, such
as a need to case
the well or provide a slotted liner. Secondly, in general only one zone at a
time can be
produced with a horizontal well. Thus, if the reservoir has multiple pay-
zones, especially
with large differences in vertical depth, or large differences in
permeabilities, it is not easy to
drain all the layers using a single horizontal well. Thirdly, horizontal wells
have a relatively
low success rate, with only 2 out of 3 drilled wells in the US achieving
commercial success.
Given the higher startup cost, the low success rate creates extra initial risk
for a project.
Fourthly, as shown in Figs. IA-B, multiple offshoot wells, such as wells 11A,
may be
required in order to fully access the oil in the reservoir. Such wells 11A
represent an extra
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CA 02716446 2010-10-01
cost in technology and expertise. Finally, horizontal drilling is complex and
requires
specialized tools and knowledge, which further add to the high cost and risk
associated with
horizontal and directional drilling.
[0005] 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.
[0006] Conventional fracturing fluids include water, frac oil, methanol, and
others.
However, these fluids are difficult to recover from the formation, with 50 %
of such fluids
typically remaining in a formation after fracturing. Referring to Figs. 3A-B,
these fluids are
also limited to a relatively short maximum effective frac length 12,
irrespective of the length
of the created fracture 14 actually formed. Effective frac length 12 refers to
the extent of the
created fracture 14 through which well fluids may be produced into the well
11.
[0007] Various alternative fluids have been disclosed for use as fracturing
fluids,
including liquefied petroleum gas (LPG), which has been advantageously used as
a
fracturing fluid to simplify the recovery and clean-up of frac fluids after a
frac. Exemplary
LPG frac systems are disclosed in W02007098606 and US 3,368,627. However, LPG
has
not seen widespread commercial usage in the industry, and conventional frac
fluids such as
water and frac oils continue to see extensive use.
SUMMARY
[0008] A method of effective horizontal drilling through a hydrocarbon
reservoir
within a subterranean formation, the method comprising: introducing liquefied
petroleum gas
fracturing fluid through a well into the hydrocarbon reservoir; and subjecting
the liquefied
petroleum gas fracturing fluid in the hydrocarbon reservoir to fracturing
pressures to fracture
the subterranean formation and form fractures extending through the
hydrocarbon reservoir
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CA 02716446 2010-10-01
with an effective frac length greater than 200 meters measured from an
injection point of the
well.
[0009] In various embodiments, there may be included any one or more of the
following features: The hydrocarbon reservoir may be formed within a geologic
formation
and the geologic formation has been previously subject to horizontal drilling.
The
hydrocarbon reservoir may have an average thickness of less than 100 meters
measured
parallel to vertical, where the average thickness is computed over a region
defined by the
actual extent of the fractures. The well may be a vertical well. The well may
be a
directionally drilled well. The well may be a horizontal well. The fractures
may have an
effective frac length greater than 300 meters. The fractures may have an
effective frac length
greater than 500 meters. The fractures may have an effective frac length
greater than 1000
meters. Proppant may be supplied from a proppant supply source into the
liquefied
petroleum gas fracturing fluid prior to introducing the liquefied petroleum
gas fracturing
fluid into the well. The proppant supply source may be rated to hold 200
tonnes or more of
proppant. The proppant supply source may be rated to hold 500 tonnes or more
of proppant.
The proppant supply source may be rated to hold 1000 tonnes or more of
proppant. The
proppant supply source may comprise plural proppant supply sources. The plural
proppant
supply sources may be connected in parallel. Liquid may be added to proppant
in the
proppant supply source. The liquid may comprise liquefied petroleum gas. A
gelling agent
may be supplied into the liquefied petroleum gas fracturing fluid for
assisting carriage of
proppant into the hydrocarbon reservoir. Fracturing may comprise shutting in
the liquefied
petroleum gas fracturing fluid in the well for an extended period of time
sufficient to form
the effective frac length. Shutting in may comprise shutting in for 24 hours
or more. Shutting
in may comprise shutting in for 48 hours or more. Shutting in may comprise
shutting in for a
week or more. The hydrocarbon reservoir may be contained at least in part
within a
sandstone formation. The hydrocarbon reservoir may be contained at least in
part within a
siltstone formation. The hydrocarbon reservoir may be contained at least in
part within a
shale formation.
[0010] These and other aspects of the device and method are set out in the
claims,
which are incorporated here by reference.
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CA 02716446 2010-10-01
BRIEF DESCRIPTION OF THE FIGURES
[0011] 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:
[0012] Fig. IA is a top plan view illustrating the positioning of a plurality
of
horizontal wells drilled through a hydrocarbon reservoir.
[0013] Fig. lB is a side elevation view of the plurality of horizontal wells
of Fig. 1A.
[0014] Fig. 2A is a top plan view illustrating a fracture pattern within a
hydrocarbon
reservoir from a vertical well.
[0015] Fig. 2B is a side elevation view of the fracture pattern of Fig. 2A.
[0016] Figs. 3A-B are schematics of a fracture created by conventional
fracturing
fluids such as oil or water.
[0017] Figs. 4A-B are schematics of a fracture created by fracturing with LPG.
[0018] Fig. 5 is a graph that illustrates the improvement in production
achievable
with LPG fracturing fluids.
[0019] Fig. 6 is a graph showing the improvement in production achieved with
an
LPG fracture treatment.
[0020] Fig. 7 is a graph illustrating the saturation curves for several
liquids, including
propane.
[0021] Figs. 8 and 9 are graphs that illustrate the differences in viscosity
between
various frac fluids.
[0022] Fig. 10 is a graph that illustrates the differences in surface tension
between
various frac fluids.
[0023] Fig. 11 is a side elevation view illustrating a fracture pattern within
a
hydrocarbon reservoir from a horizontal well.
[0024] Fig. 12 is a flow diagram of a method of effective horizontal drilling
through
a hydrocarbon reservoir within a subterranean formation.
DETAILED DESCRIPTION
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CA 02716446 2010-10-01
[00251 Immaterial modifications may be made to the embodiments described here
without departing from what is covered by the claims. Figures are not drawn to
scale.
[0026] LPG may 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 include propane, butane, or various mixtures thereof. As well, exemplary
LPGs also
include isomers of propane and butane, such as iso-butane. Further LPG
examples include
HD-5 propane, commercial butane, and n-butane. The LPG mixture may be
controlled to
gain the desired hydraulic fracturing and clean-up performance. LPG fluids
used may also
include minor amounts of pentane (such as i-pentane or n-pentane), higher
weight
hydrocarbons, and lower weight hydrocarbons such as ethane.
[0027] 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, such as oil or gas reservoirs,
and formation
fluids, and is highly soluble in formation hydrocarbons and eliminates phase
trapping -
resulting in increased well production. LPG may be readily viscosified to
generate a fluid
capable of efficient fracture creation and excellent proppant transport. After
fracturing, LPG
may be recovered very rapidly, allowing savings on clean up costs. In some
embodiments,
LPG may be predominantly propane, butane, or a mixture of propane and butane.
In some
embodiments, LPG may comprise more than 80%, 90%, or 95% propane, butane, or a
mixture of propane and butane.
[0028] Referring to Fig. 12, a method is illustrated of effective horizontal
drilling
through a hydrocarbon reservoir 10 (shown in Fig. 2A) within a subterranean
formation 16
(shown in Fig. 2A). Referring to Figs. 2A-B, in stage 100 (shown in Fig. 12),
LPG fracturing
fluid is introduced through well 18 into the hydrocarbon reservoir 10. In
stage 102 (shown in
Fig. 12), the liquefied petroleum gas fracturing fluid in the hydrocarbon
reservoir 10 is
subjected to fracturing pressures to fracture the subterranean formation 16
and form fractures
CA 02716446 2010-10-01
20 extending through the hydrocarbon reservoir 10 with an effective frac
length 12 greater
than 200 meters, for example greater than 300 meters, 500 meters, 1000 meters
or more,
measured from an injection point 22 of the well 18.
[0029] The methods disclosed herein provide an economical alternative to
horizontal
drilling and are capable of producing wells that are more productive than
conventional
vertical or non-horizontal wells. The method is referred to as effective
horizontal drilling
because it may be used as an economical alternative to horizontal drilling,
for example in a
situation where horizontal drilling would be more economical than conventional
vertical
drilling. For example, the hydrocarbon reservoir 10 that the method is carried
out within may
be formed within a geologic formation, and the geologic formation has been
previously
subject to horizontal drilling. Moreover, the hydrocarbon reservoir 10 may
have an average
thickness 24 of less than 100 meters measured parallel to vertical, where the
average
thickness 24 is computed over a region defined by the actual extent of the
fractures 20. The
hydrocarbon reservoir 10 may be a reservoir suitable for horizontal drilling,
for example
more suitable for horizontal drilling than conventional vertical drilling. The
reservoir 10 may
be formed as a vertically thin but laterally wide bed, such as a blanket or
oil-rim reservoir
that extends laterally a relatively long distance. In one embodiment, the
reservoir 10 may
extend a lateral distance longer than can be drawn from by a vertical well
drilled and
fractured in a conventional fashion with conventional fluids such as frac
oils, water, or
methanol. For example, the reservoir 10 may extend laterally longer than 200
meters, such as
longer than 300 meters, from the well 18 drilled.
[0030] Referring to Figs. 4A-B, unlike other fluids, LPG frac fluids can be
used to
form fractures 20 (shown in Fig. 2B) with effective frac lengths 12 of 200
meters and
greater. As discussed herein, the effective fracture length 12 refers to the
length of the
created fracture through which well fluids may be produced into the well 11.
The created
fracture may be propped along its length 14. Figs. 3A-B and 4A-B contrast
fractures formed
during fracturing with conventional and LPG fluids, respectively. Conventional
stimulation
techniques incorporate the use of fluids such as oil, water, methanol, CO2,
and N2 for
example. Referring to Figs. 3A-B, with conventional fluids the effective
fracture length 12 is
much shorter than the created fracture length 14. Referring to Figs. 4A-B, on
the other hand,
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CA 02716446 2010-10-01
the effective fracture length 12 is the same as the created fracture length
14. Referring to Fig.
10, the much shorter effective frac length 12 formed in Figs. 3A-B occurs at
least partially as
a result of the high surface tension of conventional fluids, such as water as
shown, which
creates 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. These liquid blocks
also represent
damage done to the formation, such as water damage.
[0031] Referring to Fig. 10, by contrast 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 gas/m3 of liquid.
LPG
comprising butane and propane has a hydrostatic gradient at 5.1 kPa/m, which
assists any
post-treatment clean-up required. This hydrostatic head is approximately half
the hydrostatic
head of water, indicating that LPG is a naturally under balanced fluid. Thus,
the low surface
tension of LPG fluid allows LPG frac fluid to be cleaned up quickly and
completely, and
reduces the pressure needed to mobilize fracturing fluid for clean up. The LPG
may also
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.
[0032] Referring to Figs. 8 and 9, the effective frac length extension
achievable with
LPG is also a result of the viscosity of LPG, which is significantly lower
than the viscosity
of water, frac oil, or methanol water, in ungelled states, further aiding in
the removal of LPG
from a well and prevention of formation damage. Significantly, the viscosity
of formation
fluid such as the fluid from the Doe creek reservoir mixed with an equal
amount of LPG is
much closer to the viscosity of LPG than the viscosity of unmixed formation
fluids, as
shown. Thus as injected LPG mixes with formation fluids, the viscosity of the
mixed fluid is
likely to be closer to the lower viscosity of LPG than the formation fluid.
This thinning of
the reservoir fluids also makes LPG excellent for use in tight oil reservoirs.
As well, the
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CA 02716446 2010-10-01
viscosity of a mixture of LPG and formation fluids is much lower than the
viscosity of frac
oil, even frac oil mixed with formation fluids. This reduction of viscosity is
significant for
cleanup, as reduced viscosity means less pressure is required to move fluid
through the
formation. Specifically, an order of magnitude reduction in viscosity results
in an order of
magnitude reduction in the pressure required to move the same volume of fluid
through a
porous media.
[0033] Referring to Fig. 7, the effective frac length extension is also aided
by the
reduced boiling point of LPG and the resulting mixture of LPG and formation
fluids. Again,
mixing of formation fluids such as the Doe creek oil with an equal amount of
propane
reduces the boiling point of the mixture to much closer to that of propane
than of formation
fluid. This reduction in boiling temperature and pressure means that the
mixture will have
reduced viscosity at lower temperatures and pressures, aiding in cleanup and
removal. 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.
[0034] Referring to Fig. 5, a plot of the beneficial increase in production
possible
with a longer effective frac length is shown. Plots 26 and 27 illustrate
theoretical post-
stimulation production from the same well after a fracture job in which
effective frac lengths
of 25% (conventional frac fluids) and 100% (LPG frac fluids), respectively,
are formed. The
difference in the area under plots 26 and 27, illustrates that a larger
proportional effective
frac length results in a larger amount of subsequent hydrocarbon production.
For discussion,
areas 28, 30, and 32 are understood to illustrate the difference in revenue-
producing fluid
production achieved with the two fracture treatments, the areas 28, 30, and 32
being defined
by the dotted boundary lines 34 and 36. The calculations from the graph assume
$4.00/mcf
(mcf = 1000 cubic feet of gas). Area 28 shows an incremental revenue of $57k
(calculated as
12 days x 34 e3m3/day = 408e3m3 or $57k) from zero flaring and rapid clean-up
of LPG frac
to a sales line. Area 28 is drawn from the X-axis of the graph because the
initial production
of fluids after the conventional treatment up to boundary line 34 are flared,
resulting in a
revenue loss of $72k (12 days x $6k = $72k). Thus, area 28 illustrates the
ability to capture
initial flush production of LPG due to less flaring with fast frac fluid
recovery.
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CA 02716446 2010-10-01
[0035] Area 30 shows an incremental revenue increase of $400k over 3 years
(incremental rate/production from 100% effective fracture length accelerated
recovery 20%
increase rate over 3 years resulting in a NPV10 of $ 400k, NPV= net present
value),
corresponding to the time it takes production in plot 26 to decrease to zero
at line 36. Finally,
area 32 shows incremental reserves from the plot 27, corresponding to the time
it takes from
line 36 until production in plot 27 decreases to zero. Of note, the downward
spikes 38 in plot
26 refer to expected costs of $25k each for two coil tubing well interventions
required as a
result of well loading. Taken together, these revenue differences result in
increased
production profits at almost every stage of post-stimulation.
[0036] Referring to Fig. 6, a graph illustrating production from a well (74-
13W6 Doe
Creek Oil Well) treated with an LPG fracture treatment is provided. Time
between initial
production and stimulation (line 40), represents 23 years of production, while
time between
stimulation (line 40) and the time the graph was made (line 42) represents 5
months of
production. The stimulation carried out at line 40 was a 16 tonne LPG
stimulation.
Extrapolated plot 44 represents expected production plotted until the time
that production is
expected to cease (line 46). The incremental reserves expected to be produced
between
stimulation (line 40) and no further production (line 46) represent a net
revenue of $2.3
million (16 % Incremental Reserves : $283k - $243k = $39k BOE, while $39k BOE
x $60 =
$2.3 million, BOE = Barrel Oil Equivalent).
[0037] Referring to Fig. 2B, the composition of the LPG frac fluid may include
non-
LPG components as desired or needed. A stream of LPG may be sent to well 18
from LPG
supply source 56 through lines 50 and 52. The stream of LPG frac fluid may
pass through a
frac pressure pump 54 in the process, required to achieve the desired frac
pressures. Proppant
may be supplied from one or more proppant supply source 48 into the liquefied
petroleum
gas fracturing fluid prior to introducing the liquefied petroleum gas
fracturing fluid into the
well 18, for example prior to the frac pressure pump 54. Proppant supply
sources 48 may
supply proppant through lines 58.
[0038] Because of the massive length of fractures desired, the fracturing
technology
used may be designed to provide what by conventional standards may be
characterized as a
massive amount of proppant and pressure. Thus, the proppant supply source 58
may be rated
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CA 02716446 2010-10-01
to hold 200, 500, 1000 or more tonnes of proppant. As well, plural proppant
supply sources
58 may be connected in parallel, for example as shown with two sources 58.
Proppant supply
source 58 may be any suitable supply source, such as an open-topped hopper or
pressure
vessel. Liquid such as LPG may also be supplied to proppant in the proppant
supply source
58, for example through an inlet (not shown) connected to receive LPG from the
LPG supply
source 56. Liquid such as frac oil may also be used as the liquid added to the
proppant, at
least in minor amounts relative to the amount of LPG in the LPG frac fluid
supplied to the
well 18. Supply source 58 may be adapted to transfer proppant into the stream
of LPG frac
fluid without requiring pressurization of a proppant reservoir (not shown) for
receiving
proppant. Such a supply source 58 may incorporate a positive displacement pump
such as a
progressing cavity pump.
[0039] A gelling agent may be supplied, for example from gellant supply source
60
through line 62, into the liquefied petroleum gas fracturing fluid for
assisting carriage of
proppant into the hydrocarbon reservoir 10. The gelling agent may be any
gelling agent
suitable for gelling the LPG frac fluid, and may be required to carry a
sufficient amount of
proppant. Other chemicals such as activators and breakers may be added.
[0040] In addition to the components discussed, other components not shown may
be
present, like an inert gas supply system for purging components in the system
of flammable
fluids and pressurizing tanks. Components such as a flare stack, sales line,
and LPG
recycling unit may be connected to the system for dealing with recovered
fluids.
[0041] Fracturing may further comprises shutting in the liquefied petroleum
gas
fracturing fluid in the well 18 for an extended period of time, such as 24
hours, 48 hours, or
more, sufficient to form the effective frac length 12. In addition the
extended period may be
longer, such as a week or more. The extended period of time may allow the LPG
to mix with
formation fluids, such as oil and natural gas, as the LPG sits in the
reservoir and travels
along the created fractures. The extended shut-in time may be determined in
order to
optimize the mixing of the fracturing fluid with the reservoir gas to form the
longest
effective frac lengths possible.
[0042] The shutting-in period may comprise more than one period combined, for
example if the period was broken up into two periods due to the addition of
extra fracturing
CA 02716446 2010-10-01
fluid at the halfway point. Under conventional fracturing procedures, the
hydrocarbon
fracturing fluid may be shut-in, but only for minor periods of time, and
usually only 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, and may extend the
effective frac length
12. Mixing of the fracturing fluid with reservoir gas may also result 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 lowered properties of viscosity and density from that of the
fracturing fluid
alone. The mixing of the fracturing fluid with the reservoir gas also results
in the mixture
having properties that significantly reduce 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.
[0043] The hydrocarbon reservoir 10 may be contained at least in part within
one or
more of a sandstone formation, a siltstone formation, and a shale formation.
Such formations
may be tight reservoirs, and may be formed in thin, laterally extensive beds
of porous
material that are excellent locations for hydrocarbons to accumulate in beds.
Such reservoir
beds may be economically drilled with horizontal wells. However, the methods
disclosed
herein may be used to exploit the hydrocarbons contained in such reservoirs in
a manner that
is even more economical than horizontal drilling.
[0044] Referring to Fig. 2B, the well 18 may be a vertical well as shown. A
vertical
well is understood as being any well that deviates 20 degrees or less from
vertical. From a
practical standpoint, all vertically drilled wells will deviate naturally to
some extent. The
portion of the well 18 that directly penetrates hydrocarbon reservoir 10 may
also be a
directionally drilled well, such as the horizontal well 18A shown in Fig. 11.
A directionally
drilled well is understood to be any well that is actively steered in order to
form a deviated
well bore, while a horizontal well is understood as being any well that
deviates more than 70
degrees from vertical.
[0045] Horizontal well 18A is illustrated as being used to carry out the
fracture from
injection point 22. Thus, a directionally drilled well may be used to
penetrate the
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CA 02716446 2010-10-01
hydrocarbon reservoir 10 in order to carry out the fracture techniques
disclosed herein.
Directional drilling may be used with the methods disclosed because it may be
more
economical or even required in some cases to use directional drilling to reach
the
hydrocarbon reservoir 10. For example, directional drilling may be required if
the
hydrocarbon reservoir 10 is located under a mountain, or off shore. As well,
directional
drilling may be economical if multiple wells are drilled from the same surface
location and
are directed to penetrate a reservoir 10 at different locations. The portion
of a directionally
drilled well that penetrates the reservoir 10 may do so in a vertical fashion
in some cases.
[0046] The methods disclosed herein may be more economical than a conventional
horizontal drilling of a reservoir 10 because these methods may obviate the
need to drill a
directional or horizontal well through the reservoir 10. Thus, under the
methods disclosed a
reservoir 10 may simply be penetrated a sufficient distance before fracturing,
rather than the
relatively extensive distance a horizontal well would be expected to penetrate
the same
reservoir 10. The well 18 drilled may in fact only penetrate a small portion
of the reservoir
10, and after performing the methods disclosed herein, may draw formation
fluids from a
sufficient portion, such as the entirety, of the larger reservoir 10.
[0047] Conventional fracturing technology may form fractures with effective
frac
lengths of up to 100 in. However, because 100 in is considered to be the
inherent limit of
effective frac length possible with conventional frac fluids such as frac oils
or water,
fracturing technology has been practically confined to situations where
achievement of a
100m draw from a well is acceptable. For situations where a longer draw was
required,
conventional knowledge may mandate a horizontal well to be drilled. In this
manner,
horizontal drilling has arisen as a more economical alternative for certain
types of reservoirs,
such as blanket reservoirs.
[0048] Thus, the methods disclosed herein represent a paradigm shift in well
fracturing. The methods disclosed herein allow wells to be drilled and treated
with a massive
frac, in order to increase the ability of the well to draw fluids from the
largest radial distance
possible into the well. Because of the massive size of the fracturing
operation, and the use of
LPG, fractures 20 are created with a much longer effective frac length 12 than
those
previously capable of formation. This increases the volume of a hydrocarbon
reservoir 10
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CA 02716446 2010-10-01
from which hydrocarbons may be drawn from into a well 18, and thus increases
the viability
of vertical wells in situations that may otherwise be more economical for
horizontal drilling
applications. This may be more economical than conventional horizontal
drilling, even in
long and thin reservoirs.
[0049] 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".
[0050] 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
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.
[0051] 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.
[0052] The methods disclosed herein may incorporate the initial stage of
drilling the
well 18, for example drilling a vertical well. Other steps not mentioned may
be included in
the method, such as injection of a pad of LPG frac fluid or an acid spearhead
as examples.
[0053] 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
13
CA 02716446 2010-10-01
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.
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