Note: Descriptions are shown in the official language in which they were submitted.
CA 02799098 2012-11-09
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METHOD AND SYSTEM FOR TREATING A SUBTERRANEAN FORMATION
BACKGROUND
[0001] Hydraulic fracturing and/or matrix acidizing oil and gas wells are
often used to stimulate
production out of more than one layer in the same wellbore. There are many
techniques used to
insure that the stimulation treatment is isolated from the other layer(s).
These techniques have
various levels of cost, complexity, reliability, and time consumption. The
limited entry technique
is less than optimum as it involves placing entry points in the formation
without validation of
fluid placement efficiency prior to stimulating.
FIGURES
[0002] Figure 1 is a sectional view of a tool in a wellbore.
[0003] Figure 2 is a sectional view of a tool in a wellbore.
[0004] Figure 3 is a plot of pressure as a function of injection rate.
[0005] Figure 4 is a sectional view of a tool in a wellbore.
[0006] Figure 5 is a sectional view of a wellbore.
[0007] Figure 6 is a plot of pressure as a function of injection rate.
[0008] Figure 7 is a sectional view of a tool in a wellbore.
[0009] Figure 8 is a sectional view of a wellbore.
SUMMARY
[0010] Embodiments of the invention relate to a method to treat a subterranean
formation
comprising a wellbore including introducing a tool to a wellbore in a region
of low permeability
or damage, treating the region of low permeability or damage with a fluid,
simultaneously
measuring a fluid pressure drop and volume of fluid flow in a particular
region, and moving the
tool to another region. Embodiments of the invention relate to a method to
treat a subterranean
formation comprising a wellbore including introducing to a wellbore a tool in
a region of low
permeability or damage, treating the region of low permeability or damage with
a fluid,
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introducing a diversion agent, and moving the tool to another region wherein
the fluid comprises
a tracer.
DESCRIPTION
[0011] At the outset, it should be noted that in the development of any such
actual embodiment,
numerous implementation-specific decisions must be made to achieve the
developer's specific
goals, such as compliance with system related and business related
constraints, which will vary
from one implementation to another. Moreover, it will be appreciated that such
a development
effort might be complex and time consuming but would nevertheless be a routine
undertaking for
those of ordinary skill in the art having the benefit of this disclosure. In
addition, the
composition used/disclosed herein can also comprise some components other than
those cited.
In the summary of the invention and this detailed description, each numerical
value should be
read once as modified by the term "about" (unless already expressly so
modified), and then read
again as not so modified unless otherwise indicated in context. Also, in the
summary of the
invention and this detailed description, it should be understood that a
concentration range listed
or described as being useful, suitable, or the like, is intended that any and
every concentration
within the range, including the end points, is to be considered as having been
stated. For
example, "a range of from 1 to 10" is to be read as indicating each and every
possible number
along the continuum between about 1 and about 10. Thus, even if specific data
points within the
range, or even no data points within the range, are explicitly identified or
refer to only a few
specific, it is to be understood that inventors appreciate and understand that
any and all data
points within the range are to be considered to have been specified, and that
inventors possessed
knowledge of the entire range and all points within the range. The statements
made herein
merely provide information related to the present disclosure and may not
constitute prior art, and
may describe some embodiments illustrating the invention.
[0012] Embodiments of the invention may make a system where multiple zones can
be treated
with less wellbore operations, more reliable and predictable, and all along at
less cost and time
using the limited entry technique. Embodiments of the invention are an
improvement on the
established process of limited entry zone stimulation and resolve the
disadvantages of
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unpredictability, efficiency, and validation of multiple zones being
stimulated. This is a method
where each entry point can be tested for fluid acceptance quickly, reliably,
and inexpensively.
[0013] This is a method to simultaneously stimulate and/or acidize multiple
zones or multiple
fractures in the same zone. The process involves a zone well that will have
each zone or several
grouped zones to be treated together so that the treatment is isolated and not
going to the
previously treated/ perforated zones. This gives more control over how each
zone will deliver its
production.
1. The process will start out as a conventional limited entry design to
determine the proper
and optimum amount of stimulations per fracture to be created.
2. Then, the initial entry hole or slot will into one zone. Ideally, this will
be at in the zone of
lowest fracture pressure to be treated. However it is effective in any
potential fracture
point where it is desirable to restrict the flow. This entry will then be
created at some
point equal to or less in entrance area than the design for this point.
(Figure 1). Some
embodiments may benefit from the use of a tracer during this step.
3. The perforating or jetting device will be left in the hole to continue
operations (Figure 2),
while pumping at various rates and pressure is observed and recorded. This
will give the
entry rates into the fracture verses pressure (Figure 3) for calibration of
the fracture
created with real time rates as a function of time. The pressures should be in
the operating
range of the anticipated treatment for maximum accuracy.
4. Next, the perforating or slotting device is moved to the second fracture
point and the
process (steps 2- and 3) is repeated. This time the rates are increased to
achieve the same
pressure range (figures 4, 5, 6). The difference in the rates at same
pressures (first rates
from second) is the fluid rate going into the second zone. That is, the
difference indicates
real time fluid behavior. Some embodiments may perform a perforation step,
then an
injection step. Some additional embodiments may perform an injection step,
followed by
a perforation step.
5. The process can be repeated in more zones until the maximum allowable rate
is achieved
for the zones. Some embodiments may benefit from the use of a diverter
treatment step.
6. If it is desirable to put a larger portion of the treatment in a zone
verses another then with
the slotting or perforating device still in the wellbore, add another entry
point(s).
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7. If it is determined that the limited number of entry points for treatment,
would restrict oil
or gas production, then with the perforating or slotting device already in the
wellbore, add
holes.
8. The achieve a lower surface treating pressure the perforating or slotting
device maybe
removed from the well during the main fracture treatment. Also, Figure 7
illustrates how
the tool may be sized to facilitate fluid flow through the wellbore. Figure 8
illustrates a
clean-up step for some embodiments of the invention.
9. If maximum rate is achieved and there are intervals still needing to be
fractured or
stimulated, then the conventional diversion or plugging materials, packers, or
bridge
plugs can be used to isolate these zones.
10. To expedite the process, the steps 2 through 5 can be made without
stopping the pumping
or fracturing treatment. In this version the initial holes are generated, the
allowable
treating pressure is met, holes in other (or same zone) are placed while
maintaining
pressure. The difference is the rate at the new holes. Process is repeated
until desired all
zones are treating properly or maximum rate is achieved.
[0014] Embodiments of the present invention also allow measurement of a
diverter's
effectiveness in diverting stimulation and scale treatment fluids from a high
permeability layer to
a low permeability layer, or from a high pressure zone to a low pressure zone,
or from a layer
which has a higher fluid mobility to a layer which has a lower fluid mobility.
Embodiments of
the invention can also be used to evaluate the effectiveness or a diverter to
place the injected
chemicals more evenly across layers which have different properties and can
affect chemical
placement. The method allows calculation of volume of fluid injected in the
low perm layer vs.
the high perm layer, or in the high pressure zone vs. low pressure zone, or in
the layer where the
fluid has a higher mobility vs. layer where fluid has a lower mobility, and
the extent of clean-up,
or flow back after the well is put back on production. That is, the different
pressure profiles as
illustrated by Figures 3 and 6 show how more perforations and/or fractures
influence the
resulting observed pressure and provide a way to estimate flow profile and
pressure along the
wellbore.
[0015] The method allows calculation of volume of fluid injected in the low
permeability layer
vs. the high permeability layer and the extent of clean-up after the well is
put back on
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production. Consider a stimulation treatment designed for two reservoir zones
intersected by a
wellbore. Assume that the top zone is a high perm zone (or a low pressure
zone, or a zone
where fluid mobility is higher) and the bottom zone is a low perm zone (or a
high pressure zone,
or a zone where fluid mobility is lower). The objective is to measure the
volume of stimulation
fluid, or scale inhibition fluid that is injected in the both zones (evaluate
diverter efficiency) and
to determine the effectiveness of clean-up during flow back. Also, this method
allows an
alternative to the conventional method using distributed temperature sensors
(DTS).
[0016] To verify the effectiveness of this system (or the limited entry
technique), consider a
stimulation treatment designed for two reservoir zones intersected by a
wellbore. Assume that
the top zone is a high perm zone and the bottom zone is a low perm zone. The
objective is to
measure the volume of stimulation fluid that is injected in the low perm zone
(to evaluate
diverter efficiency) and to determine the effectiveness of clean-up during
flow back. The
evaluation as per embodiments of the present invention would comprise of the
following steps:
1. Inject stimulation fluid Si with tracer T 1.
2. Inject diverter stage.
3. Inject stimulation fluid S2 with tracer T2.
4. Position downhole sampling device, such as compact production sampler
cartridge with
multiple sample bottles, between top and the bottom zone.
5. Flow back the well and collect surface samples and downhole samples during
flow back
and record flow rate during flow back.
6. Analyze composition of the surface and downhole samples.
7. Determine volume of stimulation fluid injected in the lower zone during the
first stage
(Si fluid) by analyzing the tracer Ti concentration in the surface sample vs.
the
downhole sample.
8. Determine volume of stimulation fluid injected during the second
stimulation stage (S2
fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T2.
9. Integrate the flow rates to compute fluid volumes.
10. Compare results from 7 to 9 to determine the effectiveness of diverter
stage.
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11. Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0017] The tracer concentrations can be measured by monitoring a fluid
property related to the
concentration, such as, pH, resistivity, density, color etc. The measurements
can be made at a
single point or at multiple points in the flow path. They can be made in real-
time and used in
improving the design of the treatment or they can be stored to memory and
analyzed later for
improving future designs.
[0018] The tracer used in monitoring diversion can come from the formation
itself. For
example, it is possible that in a carbonate reservoir the low permeability
zones have more
dolomite CaMg(C03), while the high permeability zones have more limestone
(CaCO3). In this
case the, Ca and Mg can serve as tracers and their concentrations in the flow
back fluid can be
used to determine the diverter efficiency.
[0019] Once the measurement of the tracer concentration is made, the methods
of United States
Patent Number 7658226 which is incorporated by reference herein in its
entiretycan be used to
calculate the diverter efficiency. Additional embodiments may benefit from the
alternatives
described in United States Patent Application Number 12/635,002, filed
December 10, 2009,
entitled, "Method of Determining End Member Concentrations," and incorporated
by reference
herein in its entirety.An alternative method for computing diversion
efficiency is by simulating
the entire process by assuming a certain diverter efficiency and then
comparing the calculated
concentrations against the measured values and then iteratively adjusting the
diverter efficiency
until a good match is obtained between the calculated and measured values.
[0020] ---- Variation 1
Can combine the above with a PLT positioned above the lower zone.
[0021] ---- Variation 2
1) Inject stimulation fluid Si with tracer Ti
2) Inject stimulation fluid mixed with diverted stage S2 with tracer T2
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3) Position downhole sampling device, such as compact production sampler
cartridge with
multiple sample bottles, between top and the bottom zone.
4) Flow back the well and collect surface samples and downhole samples during
flow back
and record flow rate during flow back.
5) Analyze composition of the surface and downhole samples
6) Determine volume of stimulation fluid injected in the lower zone during the
first stage
(Si fluid) by analyzing the tracer Ti concentration in the surface sample vs.
the
downhole sample.
7) Determine volume of stimulation fluid injected during the second
stimulation stage (S2
fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T2.
8) Integrate the flow rates to compute fluid volumes.
9) Compare results from 6 to 8 to determine the effectiveness of diverter
stage.
10) Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0022] ---- Variation 3
Can combine the above (variation 2) with a PLT positioned above the lower
zone.
[0023] ---- Variation 4
1) Inject stimulation fluid which has been mixed with diverter chemical Si
with tracer Ti
2) Inject post stimulation fluid S2 (e.g. displacement fluid, post flush
fluid, overflush fluid)
with tracer T2
3) Position downhole sampling device, such as compact production sampler
cartridge with
multiple sample bottles, between top and the bottom zone.
4) Flow back the well and collect surface samples and downhole samples during
flow back
and record flow rate during flow back.
5) Analyze composition of the surface and downhole samples
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6) Determine volume of stimulation fluid injected in the both zones during the
first stage
(Si fluid) by analyzing the tracer Ti concentration in the surface sample vs.
the
downhole sample.
7) Determine volume of post stimulation fluid injected during the second stage
(S2 fluid) by
analyzing the tracer concentration in the surface sample vs. the downhole
sample for
Tracer T2.
8) Integrate the flow rates to compute fluid volumes.
9) Compare results from 6 to 8 to determine the effectiveness of diverter
chemicals.
10) Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0024] ---- Variation 5
Can combine the above (variation 4) with a PLT positioned above the lower
zone.
[0025] ---- Variation 6
1) Inject pre stimulation fluid Si (e.g. reservoir conditioning or pre-
conditioning fluid) with
tracer T 1
2) Inject the main stimulation fluid mixed with chemical diverter S2 with
tracer T2
3) Position downhole sampling device, such as compact production sampler
cartridge with
multiple sample bottles, between top and the bottom zone.
4) Flow back the well and collect surface samples and downhole samples during
flow back
and record flow rate during flow back.
5) Analyze composition of the surface and downhole samples
6) Determine volume of pre stimulation fluid injected in the lower zone during
the first
stage (Si fluid) by analyzing the tracer Ti concentration in the surface
sample vs. the
downhole sample.
7) Determine volume of main stimulation fluid injected during the second
injection stage
(S2 fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T2.
8) Integrate the flow rates to compute fluid volumes.
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9) Compare results from 6 to 8 to determine the effectiveness of chemical
diverter which
was mixed with the main treatment fluid.
10) Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0026] ---- Variation 7
Can combine the above (variation 4) with a PLT positioned above the lower
zone.
[0027] ---- Variation 8
Can combine steps 1 to 2 in Variations 2, 4 and 6 above with the following:
3. Flow back the well and collect surface samples during flow back and record
flow rate
during flow back.
4. Analyze composition of the surface samples
5. Determine volume of stimulation fluid injected in the lower zone during the
first stage
(Si fluid) by analyzing the tracer Ti concentration in the surface sample
6. Determine volume of post stimulation fluid injected during the second stage
(S2 fluid) by
analyzing the tracer concentration in the surface sample for Tracer T2.
7. Integrate the flow rates to compute fluid volumes.
8. Compare results from 5 to 7 to determine the effectiveness of diverter
chemicals.
9. Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0028] ---- Variation 9
1) Inject pre stimulation fluid Si (e.g. reservoir conditioning or pre-
conditioning fluid) with
tracer T 1
2) Inject the main stimulation fluid mixed with chemical diverter S2 with
tracer T2
3) Inject post stimulation fluid S3 (e.g. reservoir conditioning or pre-
conditioning fluid)
with tracer T3
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4) Position downhole sampling device, such as compact production sampler
cartridge with
multiple sample bottles, between top and the bottom zone.
5) Flow back the well and collect surface samples and downhole samples during
flow back
and record flow rate during flow back.
6) Analyze composition of the surface and downhole samples
7) Determine volume of pre stimulation fluid injected in the lower zone during
the first
stage (Si fluid) by analyzing the tracer Ti concentration in the surface
sample vs. the
downhole sample.
8) Determine volume of main stimulation fluid injected during the second
injection stage
(S2 fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T2.
9) Determine volume of post stimulation fluid injected during the third
injection stage (S3
fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T3.
10) Integrate the flow rates to compute fluid volumes.
11) Compare results from 7 to 10 to determine the effectiveness of chemical
diverter which
was mixed with the main treatment fluid.
12) Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0029] ---- Variation 10
Can combine steps 1 to 3 in Variation 9 above with the following:
4. Flow back the well and collect surface samples during flow back and record
flow rate
during flow back.
5. Analyze composition of the surface samples
6. Determine volume of pre stimulation fluid injected in the lower zone during
the first
stage (Si fluid) by analyzing the tracer Ti concentration in the surface
sample vs. the
downhole sample.
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7. Determine volume of main stimulation fluid injected during the second
injection stage
(S2 fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T2.
8. Determine volume of post stimulation fluid injected during the third
injection stage (S3
fluid) by analyzing the tracer concentration in the surface sample vs. the
downhole
sample for Tracer T3.
9. Integrate the flow rates to compute fluid volumes.
10. Compare results from 6 to 9 to determine the effectiveness of diverter
chemicals.
11. Determine the clean-up efficiency of each zone by integrating flow rate of
retrieved
stimulation fluid from each zone.
[0030] ---- Variation 11
Can combine the above (Variation 9 and variation 10) with a PLT positioned
above the lower
zone.
[0031] ---- Variation 12
Can combine all the above, with chemical return profile analyses usually
sampled at topside to
evaluate diverter efficiency and treatment efficiency.
[0032] ---- Variation 13
Can combine all the above with flowback properties (rates and concentration)
and flow profile of
tagged chemicals that may be present in the pre, main and / or post treatment
fluid to evaluate
diverter efficiency and treatment efficiency over the long term.
[0033] Also, when the composition of the downhole fluid sample and the surface
fluid sample is
analyzed one should analyze the full composition. For example, in addition to
looking for Ti
and T2, one should look for Ca, Mg ions as well as any component from the
diverter stage. Most
likely the low perm formation will be different in composition (may contain
more dolomite) then
analysis of Ca/Mg concentration would allow one to calculate the flow rate
from the low perm
zone without the need for a PLT. The analysis for the components of the
diverter may also lead
to a similar result. The concentration of Ti and T2 does not have to be
constant. The use of
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step, or a ramp in Ti and T2 concentration is also possible. The use of mass
balance tracer T3
can also be used to confirm the amount of stimulation fluid produced back.
[0034] The preceding description has been presented with reference to some
illustrative
embodiments of the Inventors' concept. Persons skilled in the art and
technology to which this
invention pertains will appreciate that alterations and changes in the
described structures and
methods of operation can be practiced without meaningfully departing from the
principle, and
scope of this invention. Accordingly, the foregoing description should not be
read as pertaining
only to the precise structures described and shown in the accompanying
drawings, but rather
should be read as consistent with and as support for the following claims,
which are to have their
fullest and fairest scope.
[0035] Furthermore, none of the description in the present application should
be read as
implying that any particular element, step, or function is an essential
element which must be
included in the claim scope: the scope of patented subject matter is defined
only by the allowed
claims. Moreover, none of these claims are intended to invoke paragraph six of
35 USC 112
unless the exact words "means for" are followed by a participle. The claims as
filed are intended
to be as comprehensive as possible, and no subject matter is intentionally
relinquished,
dedicated, or abandoned.
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