Note: Descriptions are shown in the official language in which they were submitted.
CA 02707209 2010-06-08
1 "METHODS FOR MAXIMUM SHOCK STIMULATION WITH MINIMUM
2 VOLUME, MINIMUM RATE AND CONTROLLED FRACTURE GROWTH"
3
4 FIELD OF THE INVENTION
The invention relates to methodology for shock stimulation of formation
6 and more particularly to methods of introducing fracturing fluids during
shock
7 stimulation for minimizing fluid injection and controlling created fracture
dimensions for
8 improving the production of hydrocarbons from the formation.
9
BACKGROUND OF THE INVENTION
11 Conventional fluid fracturing of subterranean formations comprises
12 positioning a tool in a cased wellbore traversing a formation to be
fractured. The
13 tool straddles perforations in the cased wellbore. Fluid is pumped down a
tubular
14 conduit from surface to the subterranean tool at a flow rate and pressure
sufficient
to hydraulically fracture the formation.
16 The exact nature of the resulting fractures is not fully known and will
17 vary for different formations. As set forth in US Patent 4,995,463 to Kramm
et al.,
18 issued in 1991, the fracture mechanics and fluid flow behavior in cleated,
coal bed
19 methane (CBM) formations is substantially different that those in sandstone
and the
like which are more conventionally known for oil and gas operations.
21 A known method for hydraulically fracturing formations comprises
22 exposing the formation to gradually greater and greater hydraulic pressures
where
23 at least one fracture is formed by pumping a fluid. The pumping continues
until
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1 either the extent of planned fracturing is achieved or proppant used to hold
the
2 created fractures open bridge off in the fracture(s) or perforation(s). It
is believed
3 that some formations are less effectively fractured using such known and
common
4 processes.
In general, the compaction of a formation made up of any kind of
6 mineralogy (such as coal, sandstone, other, or a combination thereof), is
related to
7 the overburden weight and force of the rock above it. Typically, at an
overburden
8 rock gradient about 22 kPa/m in many geographical areas, the deeper below
the
9 earth's surface of the formation, the more vertical force you have on the
said
formation. A portion of the vertical force will also transfer into a
horizontal
11 component as well through a rock property called Poisson's ratio which
relates
12 vertical strain to horizontal strain. Additional horizontal force(s)
through regional
13 stress and/or strain are also possible from faulting, local mountain ranges
or other
14 reasons. The various forces on a formation from various sources and
directions will
cause compaction which usually causes both a loss of permeability and
porosity.
16 As a result, the general rule is the deeper the formation, the lower
17 permeability and porosity potential; the shallower the formation, the
higher the
18 permeability and porosity potential. When formations have more porosity,
the well
19 storage volume of hydrocarbons is increased for more asset value by
reserves
bookings. When formations have more permeability, the hydrocarbons in the
21 storage volume will flow at higher rates to the well to result in more cash
flow by
22 hydrocarbon sales. Both cash flow and asset value of a well can be
important in the
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1 economics of recovering natural resources from the earth rather than leaving
them
2 abandoned there for the life of the well. Industry prefers to drill wells in
a region to
3 intersect a local area of a target formation that is present to maximize
permeability
4 and porosity so that cash flow, assets and economics are high enough to
allow
recovery of hydrocarbons as opposed to abandon them in the earth.
6 CBM, as well as other naturally fractured or shear inducible
7 formations, can be particularly affected by compaction as the volume
contained in
8 the natural fractures, otherwise known as cleats for CBM, is affected by the
forces
9 that compact them. The more compaction on natural fractures, the less
retained
porosity and permeability that those natural fractures contain which directly
affects
11 well economic evaluations. The natural fractures and cleats usually have a
much
12 higher permeability and porosity than the bulk (otherwise known as matrix)
13 formation rock. In both the case of natural fractures or matrix formation
rock,
14 increasing compaction forces can negatively affect permeability and
porosity.
In general, shallow formations have a higher tendency to have enough
16 permeability and porosity to be economic even to the point of not needing
to be
17 hydraulically fractured for methane or other hydrocarbons to be conducted
to the
18 well bore and produced from the wellhead. In many cases, perforating holes
to
19 connect the reservoir and well bore sometimes followed by a small volume of
acid is
all that is required to reach economic rates to produce a well. The acid, if
required,
21 dissolves the small amount of damage, otherwise known as skin, which
impedes
22 flow of well according to Darcy's equation as known to those skilled in the
art.
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1 There are many scenarios where formations do not respond in an
2 acceptable fashion in terms of hydrocarbon production to perforating and
acidizing
3 alone. As known to those skilled in the art, examples of some of these
scenarios
4 can include under-pressured, or simply low pressured, formations not having
enough pressure to adequately flow liquids, such as acid, brines or fracturing
fluid
6 out of the formation and well bores which can cause a fluid or water block
that
7 prevents hydrocarbons from flowing to the well from the formation.
8 Another example can be sub-irreducibly water saturated reservoirs
9 absorbing water, if present, to damage the formation and reduce permeability
very
drastically to drop the methane flow rates below economically viable rates.
One
11 instance in which this effect occurs is very close to the well due to
drilling fluid and
12 cement damage causing a skin effect. If the well is fractured with water
based
13 fluids, even water foams or water emulsions, the newly created fractures
will result
14 with a skin effect also that is severe enough on the fracture face that
there is not
significant economic improvement over the removal of the skin that was
originally
16 near the well.
17 Swelling clay mineralogy(s) in the formation can also absorb water in
18 acid or fracturing fluids that will partly or completely block hydrocarbon
flow within
19 the formation by filling in the porosity thus reducing the permeability
below
economically viable rates, sometimes even to zero flow.
21 Another example are migrating clays and fines in the formation can
22 mobilize through injection of acid or fracturing fluids and accumulate to
partly or
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1 completely plug flow paths in the formation and thus reducing the
permeability
2 below economically viable rates. Through density and/or viscosity as the
liquids
3 flow back to the well, these blocks can accumulate in the proppant pack,
natural
4 fractures or matrix pore throats.
Another example can include relative permeability reductions to the
6 conductivity of hydrocarbons to the well bore after the stimulation which
can
7 increase the capillary pressure and flow back of the fracturing fluid from
the
8 formation.
9 In the case of conventional fracturing with fluids, the interface between
created intersecting cracks and hydraulic fractures can be impaired,
preventing
11 significant flow of hydrocarbon into the hydraulic fracture from the
formation and
12 thus the well. In the case of only perforating, the interface created
between the
13 formation and well bore can be impaired, preventing significant flow of
14 hydrocarbons into the well from the formation.
In general, formations are accessed by drilling open hole(s),
16 cementing casing in the open hole(s) and perforating the well to create a
17 communication interface between the formation and the well, also known as
skin,
18 which is the impediment of hydrocarbon flow according to Darcy's law. In
the stage
19 of drilling of a well, a damaged area of varying thickness can be created
as the
drilling mud leaks into the formation before the drilling mud plugs the
formation and
21 the drilled open hole interface. In the stage of cementing a well, there
can be a
22 damaged interface of varying thickness as the cement displaces the mud,
only to
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1 leave cement filtrate in the formation and a cement interface between the
formation
2 and the casing. In the case of perforating a well, there is a very thin
interface of
3 damaged formation that impairs the flow of methane into a well bore.
4 In some circumstances, there are limited options to removing the
effect of an interface or skin, by any chosen common conventional means. The
6 limitations can be for several factors or reasons as known to those skilled
in the art
7 including, but not limited to: 1) the formation is above the base of ground
water (has
8 fresh water aquifers below the formation) and thus there are restrictions to
the
9 injection of foreign material. Government regulations often are involved in
whether
these formations can be stimulated, and if they can be stimulated, how they
can be
11 stimulated. In some regions the restrictions are at 200 m or shallower,
unless the
12 government has specifically made the limit deeper due to environmental,
fresh
13 water existing deeper than 200 m or other reasons. 2) A first injection
well A is
14 close to an adjacent second well B such that pressure generated during
injection in
well A will negatively affect well B. Well B might be a fresh water supply
well or a
16 petroleum well that is either active or not active. 3) The cost of
injecting into the
17 formation does not meet the economical criteria based on the achieved
results. The
18 cost of injecting into a well contains both fixed service costs related to
injection rate
19 and variable costs related to injection volume. 4) The formation is so
shallow that
there is concern that injection might reach the surface. 5) The injected
volume
21 could cause fractures in the target formation that, rather than extending
laterally
22 through the target formation, might grow up or down and communicate with
another
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1 formation (e.g. to an aquifer that is not to be stimulated nor made to
communicate
2 with the well bore). 6) Concerns of ground impact due to the large area
required by
3 the commonly large number of storage vessels and pump trucks.
4 In the context of shallow dry CBM, as is known to those skilled in the
art, commercial and economical production of methane is only after stimulating
such
6 formations by means of high rate nitrogen injection through coiled tubing.
In many
7 cases volumes of nitrogen used are 5,000 scm of nitrogen gas per formation
and
8 pumped at rates of 1,000 scm/min to 1,500 scm/min. In many areas of oil and
gas,
9 but particularly in the region where the field trials were done, there are
environmental and surface access concerns as many of the wells are on farm
land
11 that grows food. Some specific perceived concerns are the noise pollution,
road
12 safety for domestic traffic, dust creation that wind carries off to live
stock breathing it
13 in, and the crop that is forfeited because of the large area required by
the storage
14 vessels and pump trucks. Some of the equipment used are storage vessels for
liquid nitrogen, for which the higher total required volumes of gas require
more
16 vessels of liquid nitrogen. Increased road traffic occurs as some nitrogen
storage
17 vessels are so heavy that they need to be hauled to and from the well
empty, and
18 smaller liquid nitrogen transport vessels are then required to make several
round
19 trips to fill the empty storage vessels.
Accordingly, particularly in the area of the unique fracture mechanics
21 of CBM, there is still a need for economical fracturing techniques which
maximize
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1 effectiveness to the target formation while minimizing risk to adjacent
formations or
2 environmental issues.
3
4 SUMMARY OF THE INVENTION
As stated above, for many formations, including shallow CBM, it has
6 been the conventional approach to use large volumes of injected nitrogen per
7 formation and high rates of injection. Concerns arising from such large
injection
8 volumes include adjacent formation communication, undesirable fractures,
9 environmental issues, surface access issues, or other issues.
A shock stimulation apparatus and methodology was previously
11 disclosed in Canadian Patent 2,565,697, by Collins et al., and issued July
22, 2008.
12 The shock stimulation applies a shock of an initial volume of nitrogen and
then
13 follows with large injection rates and volumes of nitrogen in accordance
with
14 conventional wisdom. Due to the high friction to the flow of stimulation
fluids in
conveyance strings such as coiled tubing, conveyance of stimulation fluid to
the
16 formation is otherwise severely restricted if not for accumulation and
surge release
17 technique.
18 In a broad aspect of the present invention, a shock fracturing method
19 comprises isolating a target formation at a set of perforations in a cased
well,
accumulating a stimulation fluid (such as inert nitrogen gas) to a threshold
pressure,
21 releasing the stimulation fluid to communicate with and shock fracture the
formation,
22 and thereafter substantially discontinuing flow of the stimulation fluid to
minimize
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1 formation damage. As usual, the fracturing promotes subsequent hydrocarbon
flow
2 through the interface between the formation and well bore while the methods
of the
3 invention controlling the distance of stimulation from the well and into the
formation.
4 One approach is to access the formation with coiled tubing extending
downhole through the wellbore for conveying a tool to the formation, the tool
having
6 an uphole seal and a downhole seal spaced uphole and downhole of the
perforation
7 tunnel interfaces for isolation thereof; and blocking the coiled tubing at
the tool for
8 accumulating the stimulation fluid at the threshold pressure in the coiled
tubing; and
9 suddenly opening the bore of the conveyance string at the tool for releasing
the
stimulation fluid through a port in the tool to surge release into the
perforation tunnel
11 interfaces.
12 In one embodiment of the invention as applied specifically for shallow
13 dry CBM formations, the formation is first shocked and then injection is
minimized
14 thereafter with only minimal volume or substantially no follow-up injection
of
nitrogen. Contrary to the prior art approach of continued injection at high
rates,
16 embodiments of the present invention minimize the post-shock volumes of
nitrogen
17 which results in fewer nitrogen pumps, fewer nitrogen storage vessels,
reduced
18 costs and maximum effect is gained with minimum or no risk to the target
formation,
19 adjacent formations or the environment.
In another aspect of the invention, a method for unblocking the
21 perforation tunnel in subterranean formations penetrated by a wellbore
comprising
22 isolating perforation tunnel interfaces in the subterranean formation,
accumulating a
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1 small amount of stimulation fluid (such as inert nitrogen gas) to a
threshold pressure
2 while isolated from the perforation tunnel interface, and releasing the
stimulation
3 fluid to communicate with the isolated perforation tunnels to promote
hydrocarbon
4 flow through the interface between the formation and well while controlling
the
distance of stimulation into the formation .
6 In one preferred embodiment, after the initial release or shock of
7 stimulation fluid from the conveyance string or coiled tubing, the injection
of
8 stimulation fluid into the coiled tubing, is discontinued after an
additional 1500 scm
9 (standard cubic metres at 14 psia and 15 C) is pumped. In yet another
preferred
embodiment, the injection of stimulation fluid into the coiled tubing ceases
after
11 release of the accumulated stimulation fluid.
12
13 BRIEF DESCRIPTION OF THE DRAWINGS
14 Figure 1 illustrates a schematic of the pressure and flow rates of
stimulation fluids during a shock treatment with immediate discontinuance of
the
16 fracturing volumes;
17 Figure 2 illustrates a schematic of the pressure and flow rates of
18 stimulation fluids during a shock treatment with minimal flow of post-shock
volumes
19 of stimulation fluids;
Figure 3A illustrates the production over time for a shallow CBM well
21 (perforation intervals of less than a depth of 200 m) according to a second
example
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1 well, stimulated using an embodiment of the present invention and compared
to
2 neighboring wells within a one mile radius;
3 Figure 3B illustrates the production over time for a CBM well according
4 to a second example well and compared to neighboring wells within a one mile
radius;
6 Figure 4A illustrates the production over time for a CBM well closely
7 adjacent to a nearby abandoned well according to a third example well,
stimulated
8 using an embodiment of the present invention and compared to neighboring
wells
9 within a one mile radius;
Figure 4B illustrates the production over time for the CBM well
11 according to Fig. 4A, and normalized by the number of formations that were
treated;
12 and
13 Figure 4C illustrates the production over time for the CBM well
14 according to Fig. 4A, and normalized by the amount of nitrogen pumped into
the
well.
16
17 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
18 In fracturing or stimulation operations, a target formation is isolated for
19 receiving pressurized stimulation fluids. The target formation is typically
traversed by
a cased well, the casing having been perforated at the target formation,
establishing
21 communication between the well and the formation. Gaseous fluids such as
nitrogen,
22 are delivered downhole through the well to the formation at a rate which
exceeds the
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1 fluid loss into the formation. Thus tubing pressure and bottom hole pressure
increase
2 where, typically, at a certain pressure, the formation fractures and fluid
rates are
3 usually increased for a period to accommodate increased flow into the
fractures. The
4 increased fluid rates and continued injection results in large volumes of
stimulation
fluid which results in the corresponding risk and costs set forth above.
6 For formations such as shallow coal bed methane (CBM), embodiments
7 of the present invention are employed to obviate the risks and costs of
conventional
8 stimulation operations.
9 With reference to Fig. 1, instead of the high volume and high injection
rates of the prior art, stimulation fluid is accumulated before release to the
formation.
11 Fracturing fluid, such as gaseous nitrogen, is pumped down coiled tubing to
a shock
12 tool for building or accumulating pressure to a pre-determined threshold
pressure
13 which is usually tuned to the formation, including formation depth and
lithology. The
14 shock tool has a fluid outlet which straddles by isolating seals so as to
direct
stimulation fluid, when released, from the outlet to the isolated formation
between the
16 isolating seals. As shown in Fig. 1, the tubing pressure correspondingly
rises as the
17 fluid is pumped into the closed coiled tubing. The bottomhole pressure
between the
18 casing and the tool remains at formation pressure as the coil tubing
pressure builds at
19 surface and at the tool.
At the threshold pressure, the shock tool opens, and there is a sudden
21 release of the fracturing fluid from the fluid outlet to impact the
formation. Substantially
22 immediately, the bottomhole pressure rises and the tubing pressure falls
and
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1 equilibrates to substantially the same pressure as the accumulated
stimulation fluid
2 applying the full fracturing pressure to the formation and dissipates
therein. It is
3 believed that a CBM formation is particularly favourably affected by a shock
4 application of the fracturing fluid. The predetermined fracturing pressure
accumulated
at the shock tool can be above the fracture gradient of the formation or above
the
6 overburden weight of about 22 kPa/meter of depth or both. For example,
fracturing
7 fluid pressure for a formation depth of about 600 meters could be initially
set for about
8 21 MPa.
9 In another embodiment, with reference to Fig. 2, after the shock tool
opens and there is a sudden release of the fracturing fluid, a further flow of
stimulation
11 fluid is continued for a short period, adjusted to accommodate the
formation.
12 Accordingly, as set forth in Fig. 1, after the initial release or shock of
13 stimulation fluid from the conveyance string or coiled tubing, the
injection of
14 stimulation fluid into the coiled tubing, and accordingly into the
formation, is
discontinued substantially immediately. In the embodiment of Fig. 2, after the
initial
16 release or shock of stimulation fluid, and a minimum additional or extra
volume of
17 stimulation fluid is injected, for example, a further 600 to 1500 scm
(standard cubic
18 metres at 14 psia and 15 C) can be pumped into the formation.
19
13
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1 FIRST EXAMPLE WELL
2 A non-producing first example well was stimulated using an embodiment
3 of the present invention. The resulting production was compared to three
4 neighbouring wells within a radius of one mile of the first example well.
The first example well was characterized by having 17 sets of
6 perforations in a shallow formation. The perforations intervals are
illustrated in Table 1
7 as listed in the "Perforated Interval" column. Casing (114.3 mm, 14.14 kg/m,
J-55
8 casing) for the first example well was isolated below 623 m. Prior to the
stimulation,
9 this first example well was not producing.
At the job site, all truck-mounted equipment was positioned and
11 connected in accordance with standard operating practice. A shock
stimulation tool
12 according to CA Patent 2,565,697 was fit to coiled tubing and positioned
adjacent
13 the formation for stimulation. The coiled tubing was pressure tested and
had a
14 maximum working pressure set for the job.
Each set(s) of perforations were isolated in turn starting with the deepest
16 zone first, and subsequently moving shallower in the well. Each specified
perforation
17 interval was isolated using zonal isolation cups. Surface equipment pumped
nitrogen
18 gas into the coiled tubing, acting as a coiled tubing accumulator, being
temporarily
19 blocked by the shock tool. For each selected and isolated perforation
interval, the
shock tool was fired, with the associated shock fracturing resulting, and
according to
21 an embodiment of the invention, an extra but minimum volume of nitrogen was
22 pumped thereafter into the formation.
14
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1 Table 1 lists the surface pump rate, the volume pumped until shock tool
2 firing and the extra volume pumped after the shock tool was fired. The
fracture
3 initiation or breakdown pressure was also observed and reported.
4 Historically, the total nitrogen used per shallow CBM formation zone,
including the release of the accumulated nitrogen using a shock tool and
subsequent
6 extra volumes pumped thereafter, has been about 3500 to 5000 scm. As shown
in
7 Table 1 below, Applicant instead used lesser total volumes (Vol to Firing +
Extra Vol)
8 of about 1700 to 3200 scm.
9 Table 1: First Example Well - Stimulation information
Perforation Interval Vol to Firing Extra Vol Surface Rate Breakdown
m scm scm scm/min Pressure (MPa)
356.8 m to 357.2 m 1383 1842 1133 29.55
312.1 m to 312.6 m 1490 1536 1152 31.52
294.4 m to 294.9 m 1315 387 1045 29.02
287.9 m to 288.4 m 1327 1697 1145 27.37
246.6 m to 247.6 m 971 1290 1142 24.88
203.3 m to 204.3 m,
199 m to 199.9 m 1254 1433 1129 26.5
193.3 m to 194.3 m 1209 787 1067 26.38
175.2 m to 175.7 m 1370 1453 1157 26.35
163.7 m to 164.5 m 1348 843 1091 27.2
147.8 m to 148.3 m 1393 604 1065 27.6
134.2 m to 134.5 m 1413 1047 1091 28.3
122.3 m to 122.8 m 1250 754 1014 26.38
109.3 m to 109.8 m 1275 974 1107 26.68
103.5 m to 105 m 1244 1448 1151 25.13
98 m to 98.4 m 1311 1190 1135 27
11 Gas flow rates from the well after fracturing initially averaged 5.17X103
12 m3/day.
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1 Neighbouring shallow CBM wells, within a radius of one mile, had an
2 initial average production of 1.99 X103 m3/day, 4.48 X103 m3/day, 5.12 X103
m3/day
3 and 6.65 X103 m3/day.
4 Accordingly, this example first well had better initial production than 75%
of the neighbouring wells, or 13.3% better than the average production while
using
6 14.3 to 26.5% less nitrogen than historical treatments. This magnitude of
nitrogen
7 savings can be in the order of 1/3 of the cost of the fracturing program.
8 The Energy Resources Conservation Board (ERCB) of Alberta, Canada
9 has issued Directive 027 which states that one must not conduct fracturing
operations
at depths less than 200 m unless they have fully assessed all potential
impacts prior to
11 initiating a fracturing program. Such assessment ensures protection of
water wells
12 and shallow aquifers. Further, it is expected that nitrogen pumping volume
should be
13 restricted to 15,000 scm/m of coal unless prior ERCB approval is obtained.
14 Note that nine of the 17 perforations intervals were less than the 200m
threshold. Applicant believes this program for this first example well met
such
16 restrictions for shallow CBM formations, had an average nitrogen volume per
meter of
17 coal of about % of the 15,000 scm maximum, and further obtained production
from
18 otherwise inaccessible formation reserves, had a reduced surface footprint,
and
19 reduced road traffic.
16
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1 SECOND EXAMPLE WELL
2 The second example well was characterized by having 22 sets of
3 perforations in shallow, dry Edmonton formation and Belly River formation
coals as
4 shown in Table 2 in the "Perforated Interval" column. Casing (114.3 mm,
14.14 kg/m,
J-55 casing) for the first well was isolated at total depth of 817 m. Prior to
the
6 stimulation, the well was not producing.
7 At the job site, all truck-mounted equipment was positioned and
8 connected in accordance with standard operating practice. A shock
stimulation tool
9 according to Assignee's CA Patent 2,565,697 was fit to coiled tubing and
positioned
adjacent the formation for stimulation. The coiled tubing was pressure tested
and
11 had a maximum working pressure set for the job.
12 Each set(s) of perforations were isolated in turn starting with the deepest
13 zone first, and subsequently moving shallower in the well. Each specified
perforation
14 interval was isolated using zonal isolation cups. Surface equipment pumped
nitrogen
gas into the coiled tubing, acting as a coiled tubing accumulator, being
temporarily
16 blocked by the shock tool. For each selected and isolated perforation
interval, the
17 shock tool was fired, with the associated shock fracturing resulting, and
according to
18 an embodiment of the invention, an extra but minimum volume of nitrogen was
19 pumped thereafter into the formation.
Table 2 lists the surface pump rate, the volume pumped until shock tool
21 firing and the extra volume pumped after the zone fired. The initiation or
breakdown
17
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1 pressure was also observed and reported. These rates used were substantially
lower
2 than the 1000 to 1500 scm/min industry common practise for shallow CBM
formations.
3
4 Table 2: Second Example Well - Stimulation information
Vol to
Firing Extra Vol Surface Rate Breakdown
Perf Interval (m) scm scm scm/min Pressure (MPa)
791.7 m to 792.2 m 1907 534 615 42.0
786.3 m to 786.8 m 1259 1427 1018 32.0
514.6 m to 515.1 m 1068 750 789 38.5
488 m to 488.5 m 1165 871 775 33.5
483.7 m to 484.2 m 1044 771 789 30.7
471 m to 472 m 308 3205 1162 10.0
453.7 m to 454.2 m 1132 1626 752 36.2
426 m to 427.5 m 995 3789 976 22.0
416mto418m,
414 m to 416 m 1537 9456 1234 26.2
410.5 m to 411 m 699 1798 1098 18.8
392.1 m to 393.1 m 639 3376 1128 18.3
387 m to 388 m,
383.5 m to 385 m 680 6578 1210 18.5
375.9 m to 376.4 m,
373.9 m to 374.9 m,
371.4 m to 371.9 m 705 6559 1190 19.6
362.7 m to 363.2 m 793 2211 1079 23.2
332 m to 332.5 m 799 1256 693 24.1
319.4 m to 320.9 m 784 4456 1167 20.3
282.2 m to 282.7 m 861 528 701 27.7
277.1 m to 277.6 m 828 1064 790 23.7
6 Gas production from neighbouring wells within a one mile radius of the
7 second example well are given in Figs. 3A and 3B. Gas flow rates from the
second
8 example well after fracturing initially averaged 8.0 X103 m3/day during the
first 2
9 months. All shallow CBM wells within a radius of one mile had initial
average
production (for the first 2 months in X103 m3/day) of 3.3, 4.6, 4.6, 6.2, 7.3,
7.5, 9.0,
11 10.3, and 13.3. This example well had better initial production than 67% of
the wells
18
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1 within a one mile radius, or 8.8% better than the average production while
injecting a
2 total (for all intervals stimulated with nitrogen) of 67,400 scm of nitrogen
gas where the
3 typical industry standard ranges would have been from about 55,000 to
110,000 scm.
4 The average nitrogen surface injection rate utilized was 4.6% to 36.5% lower
than the
typical industry standard for shallow, dry CBM in the area, and the lowest
rate utilized
6 was 38.5% to 59% lower. In addition, this example well had a reduced surface
7 footprint and reduced road traffic due to requiring less nitrogen pump
capacity than
8 standard practises in the area on shallow, dry coal.
9
THIRD EXAMPLE WELL
11 The third example well was characterized by having 13 sets of
12 perforations in shallow, dry Edmonton formation and Bearpaw formation coals
as
13 shown in Table 3 in the "Perforated Interval" column. The casing (114.3 mm,
14.14
14 kg/m, J-55 casing) was had a total depth of 353 m. Prior to the
stimulation, the well
was not producing.
16 In the immediate area was an abandoned well 36 m away where there
17 was concern of communication to which an appropriate engineering design was
done.
18 Very low total volumes of nitrogen were applied to avoid breakthrough to
the
19 abandoned well. Illustrative of the risks includes the ERCB Directive 027
which
restricts fracturing wells adjacent water wells and requires a minimum
horizontal offset
21 of 200 m.
19
CA 02707209 2010-06-08
1 At the job site, all truck-mounted equipment was positioned and
2 connected in accordance with standard operating practice. The 83 mm, 8.037
kg/m,
3 QT-700 coiled tubing was pressure tested to 50 MPa and had a maximum working
4 pressure of 42 MPa for the job. The stimulation was pumped down coiled
tubing
utilizing zonal isolation cups and shock tool in the casing.
6 Each set(s) of perforations were isolated in turn starting with the deepest
7 zone first, and subsequently moving shallower in the well. Nitrogen gas was
8 introduced to the coiled tubing accumulator. Table 3 lists the surface pump
rate, the
9 volume pumped until shock tool firing and the extra volume pumped after the
shock
tool fired. The breakdown pressure was also observed and reported. These rates
11 used were extremely low compared to the 1000 to 1500 scm/min industry
common
12 practise for shallow CBM formations. Figs. 4A, 4B and 4C illustrate the
resulting
13 production form the third example well post-stimulation.
14
Table 3: Third Example Well - Stimulation information
Vol to
Firing Extra Vol Surface Rate Breakdown Pressure
Perf Interval (m) (scm) (scm) scm/min (MPa)
314.9 m to 315.2 m,
311.7 m to 312.6 m 443 1167 300 18.0
305.4 m to 305.7 m 541 371 300 22.0
297.5 m to 298 m 389 621 300 15.8
289.8 m to 291 m 453 561 300 18.4
231.3 m to 231.8 m 470 542 300 19.1
224.6 m to 225.8 m 455 552 300 18.5
207.3 m to 207.8 m,
205.8 m to 207 m 450 557 300 18.3
192.7 m to 194.6 m 458 555 300 18.6
176.7 m to 177.5 m,
172.8 m to 175.9 m 455 553 300 18.5
162.6 m to 163.1 m 441 566 300 17.9
CA 02707209 2010-06-08
1
2 Gas production from all shallow, dry coal wells within a one mile radius
3 of the example well is given in Figure 4B, which has filtered out the wells
with deep,
4 dry coals that are commingled and normalized the production to the number of
target
formations in the well. Gas flow rates from the example well after fracturing
initially
6 averaged 1.03 X103 m3/day during the first 6 months. For the first 6 months,
all
7 comparison wells had an average production of 0.97, 1.86 and 2.15 X103
m3/day.
8 This third example well had better initial production than 33% of the
comparison wells,
9 or 38% worse than the average production while injecting a total of 10,600
scm of
nitrogen gas (78% less volume on average) where the comparison wells received
11 from 60,155 scm, 46,480 scm and 40,620 scm of nitrogen gas. If the
comparison well
12 production was normalized on the example well injection volume of nitrogen
of 10,600
13 scm as in Figure 4C, the average production during the first 6 months would
be 0.27,
14 0.40 and 0.41 X103 m3/day. When normalized on nitrogen injection volume,
the
example well is better than 100% of the offset wells and has 186% better
average
16 production. The average nitrogen surface injection rate utilized was 70% to
80%
17 lower than the typical industry standard for shallow, dry CBM in the area.
18 Note that three of the 13 perforations intervals were less than the 200m
19 threshold. Further, there were no issues with communication with the nearby
well 36
m away. In addition, this third example well was successfully treated and
within the
21 guidelines for shallow wells affected by government regulations, treated
without
22 communication to nearby wells affected by government regulations, reduced
surface
21
CA 02707209 2010-06-08
1 footprint and reduced road traffic due to requiring less nitrogen pump
capacity and
2 less total volume than the nearby comparison wells.
3
22
