U.S. patent application number 15/148765 was filed with the patent office on 2017-11-09 for protecting production wells using natural gas injection.
The applicant listed for this patent is Weatherford Technology Holdings, LLC. Invention is credited to Kimberly BARTON, Narayan Jee CHOUDHARY, Frank Eugene GENTRY, Jonathan Max POMERANTZ, Dustin J. STEVENS.
Application Number | 20170321530 15/148765 |
Document ID | / |
Family ID | 60242503 |
Filed Date | 2017-11-09 |
United States Patent
Application |
20170321530 |
Kind Code |
A1 |
GENTRY; Frank Eugene ; et
al. |
November 9, 2017 |
PROTECTING PRODUCTION WELLS USING NATURAL GAS INJECTION
Abstract
A method of protecting a first well from stimulation fluid of a
second well includes shutting in the first well; starting injection
of natural gas into the first well to increase a pressure of the
first well; treating the second well using a stimulation fluid
after starting natural gas injection; and stopping injection of
natural gas.
Inventors: |
GENTRY; Frank Eugene;
(Casper, WY) ; BARTON; Kimberly; (Denver, CO)
; STEVENS; Dustin J.; (Conifer, CO) ; POMERANTZ;
Jonathan Max; (Denver, CO) ; CHOUDHARY; Narayan
Jee; (Lakewood, CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Weatherford Technology Holdings, LLC |
Houston |
TX |
US |
|
|
Family ID: |
60242503 |
Appl. No.: |
15/148765 |
Filed: |
May 6, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/168 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26 |
Claims
1. A method of protecting a first well from stimulation fluid of a
second well, comprising: shutting in the first well; starting
injection of natural gas into the first well to increase a pressure
of the first well; treating the second well using a stimulation
fluid after starting natural gas injection; and stopping injection
of natural gas.
2. The method of claim 1, wherein the pressure of the first well is
allowed to build to a pressure between 100 psi and 1,500 psi prior
to starting injection.
3. The method of claim 1, wherein injection of natural gas
comprises injecting the natural gas using a compressor.
4. The method of claim 3, wherein the natural gas in injected
through a wellhead of the first well.
5. The method of claim 3, where the natural gas is supplied from a
field gathering pipeline or a producing well.
6. The method of claim 3, wherein the natural gas is supplied in a
form as one of liquefied natural gas, compressed natural gas, and
combinations thereof.
7. The method of claim 1, wherein the pressure in the first well is
increased to a built up pressure between 1,000 psi and 1,900
psi.
8. The method of claim 7, wherein treating the second well begins
after the built up pressure of the first well has increased to
between 1,000 psi and 1,900 psi.
9. The method of claim 1, wherein treating the second well begins
after the pressure in the first well has reached equilibrium.
10. The method of claim 1, wherein the pressure in the first well
is increased to a built up pressure between 700 psi and 3,500
psi.
11. The method of claim 9, further comprising maintaining the
pressure in the first well within 30% of built up pressure during
treatment of the second well.
12. The method of claim 1, wherein the natural gas is supplied from
a pressurized vessel.
13. The method of claim 12, wherein the vessel is connected
directly to the first well.
14. The method of claim 1, further comprising producing hydrocarbon
from the first well prior to shutting in the first well.
15. The method of claim 14, further comprising restoring
hydrocarbon production of the first well after stopping injection
of natural gas.
16. A method of protecting a producing well from stimulation fluid
of a treatment well, comprising: injecting natural gas into the
producing well to increase a pressure of the producing well and
fractures in communication with perforations of the producing well;
and fracturing the treatment well after injecting natural gas.
17. The method of claim 16, further comprising shutting in the
producing well prior to injecting natural gas.
18. The method of claim 16, wherein the pressure of the producing
well is allowed to build to a pressure between 100 psi and 1,500
psi prior to starting injection of the natural gas.
19. The method of claim 16, wherein the pressure in the producing
well is increased to a built up pressure between 1,000 psi and
1,900 psi.
20. The method of claim 16, wherein treating the second well begins
after the pressure in the first well has reached equilibrium.
21. The method of claim 16, further comprising increasing a
pressure of the natural gas prior to injecting the natural gas into
the producing well.
22. A method of protecting a producing well from stimulation fluid
of a treatment well, comprising: producing hydrocarbon from the
producing well; shutting in production of the producing well;
injecting natural gas into the producing well after shutting in the
producing well, thereby increasing a pressure of the producing
well; and fracturing the treatment well after injecting natural
gas.
Description
BACKGROUND OF THE INVENTION
Field of the Invention
[0001] Embodiments of the invention generally relate to methods and
apparatus for protecting a well from stimulation fluid.
Particularly, embodiments of the present invention relates to
methods and apparatus for injecting natural gas into a well to
protect the well against stimulation fluid from a neighboring
well.
Description of the Related Art
[0002] In wellbore construction and completion operations, a
wellbore is formed to access hydrocarbon-bearing formations (e.g.,
oil and/or natural gas) by the use of drilling. The drill string is
often rotated by a top drive or rotary table on a surface platform
or rig, and/or by a downhole motor mounted towards the lower end of
the drill string. After drilling to a predetermined depth, the
drill string is removed and a section of casing is lowered into the
wellbore. A cementing operation is then conducted to fill the
annulus with cement. The combination of cement and casing
strengthens the wellbore and facilitates the isolation of certain
areas of the formation behind the casing for the production of
hydrocarbons.
[0003] Additional completion operations are performed to enable
production of well fluids. Examples of such completion operations
include the installation of production tubing and various packers
to define zones in the wellbore. A perforating string may be
lowered into the wellbore and fired to create perforations in the
surrounding casing and to extend perforations into the surrounding
formation.
[0004] A fracturing operation can be performed to enhance the
productivity of a formation. Typically, stimulation fluid is pumped
into the wellbore to fracture the formation so that fluid flow
conductivity in the formation is improved to provide enhanced fluid
flow into the wellbore.
[0005] When a well is undergoing a fracturing operation, the
stimulation fluid may flow toward and undesirably enter a nearby
well. The stimulation fluid may damage the well's hydrocarbon
productivity. In particular, the stimulation fluid can
significantly reduce the hydrocarbon production volumes, thereby
reducing the well's Estimated Ultimate Recovery (EUR) of oil and
natural gas reserves. Also, the producing well may require costly
and time consuming wellbore remediation operations to restore both
wellbore integrity and production capability.
[0006] This problem is exacerbated by more dense drilling
operations. For example, multiple wells have been drilled in close
proximity to each other to increase the production of a reservoir.
One or more of these wells may be an extended reach horizontal
well. Multiple wells have also been drilled on a single drill pad
to increase production.
[0007] There is a need, therefore, for apparatus and methods of
protecting a well from a nearby well undergoing fracturing or
stimulation operations.
SUMMARY OF THE INVENTION
[0008] In one embodiment, a method of protecting a first well from
stimulation fluid of a second well includes shutting in the first
well; starting injection of natural gas into the first well to
increase a pressure of the first well; treating the second well
using a stimulation fluid after starting natural gas injection; and
stopping injection of natural gas.
[0009] In another embodiment, a method of protecting a producing
well from stimulation fluid of a treatment well includes injecting
natural gas into the producing well to increase a pressure of the
producing well and fractures in communication with perforations of
the producing well; and fracturing the treatment well after
injecting natural gas into the producing well.
[0010] In another embodiment, natural gas is injected into a
producing well to act as a barrier against damaging pressure or
physical communication of fluid resulting from a stimulation
operation at a nearby well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0012] FIG. 1 illustrates a hydrocarbon producing field having
multiple wells.
[0013] FIG. 2 illustrate an exemplary producing well configured for
injection of natural gas.
[0014] FIG. 3 illustrates an exemplary pressure graph of a well
undergoing a natural gas injection.
[0015] FIG. 4 illustrates an exemplary pressure graph of an
unprotected well exposed to fluid and pressure communications from
a nearby well undergoing a fracturing operation.
[0016] FIG. 5 illustrates another exemplary pressure graph of a
well undergoing a natural gas injection.
[0017] FIG. 6 illustrates an exemplary wellhead configured for
injection of natural gas.
DETAILED DESCRIPTION
[0018] In one embodiment, methods and apparatus are provided to
protect a producing well from potentially damaging fluid and/or
pressure communications resulting from a stimulation treatment at a
nearby well.
[0019] FIG. 1 illustrates a hydrocarbon producing field having
treatment well 100 and one or more candidate wells 101, 102, 103.
The treatment well 100 may be undergoing a stimulation treatment to
enhance hydrocarbon production of the treatment well 100. In one
embodiment, the treatment well 100 may be injected with stimulation
fluid such as fracturing fluid or acidizing fluid to increase the
effective hydrocarbon drainage area as well as permeability of the
producing formation 130, thereby increasing the recovery of
hydrocarbons from the treatment well 100. Exemplary stimulation
fluids may include fluid or gas systems such as but not limited to
singular applications of or combinations of water, liquid
hydrocarbons, gas, acid, proppant such as sand or solids,
chemicals, and additives that are pumped into a treatment well.
Stimulation fluids can include a gas medium such as but not limited
to nitrogen (N.sub.2), carbon dioxide (CO.sub.2), methane, and
combinations thereof. In one example, stimulation fluid is pumped
down the well and flows out perforations or sleeve ports to create
artificially induced fractures in the producing formation 130. The
treatment well 100 may be a horizontal, vertical, or directional
well.
[0020] The candidate wells 101, 102, 103 may be producing wells
that have been completed and producing hydrocarbons. The candidate
wells 101, 102, 103 may be located at the same or different
distances from the treatment well 100. In some instances, one or
more of the candidate wells is located sufficiently near the
treatment well 100 such that the stimulation fluid and/or treating
pressures from the treatment well 100 may communicate with the
candidate wells. For example, the candidate well 101 is located
sufficiently close such that stimulation fluid from the treatment
well 100 may reach and enter the candidate well 101. While
stimulation fluid may be referred to herein, it is contemplated
that stimulation fluid communicating with the candidate well 101
may include liquid, gas, solids such as proppant, chemicals and
combinations thereof.
[0021] In one embodiment, pressurized gas such as natural gas may
be injected into the candidate well 101 to act as a pressure
barrier to mitigate and/or minimize ingress of the stimulation
fluid and/or treating pressures. In one embodiment, pressure
barrier is a downhole pressure envelope or volume created within
the near wellbore region by the injected natural gas. FIG. 2
illustrates an exemplary candidate well 101 configured for
injection of natural gas. As shown, the candidate well 101 includes
a wellbore 120, which may be supported by casing, and a production
tubing 125 disposed therein. The production tubing 125 extends from
the wellhead downhole to the producing zone 130. An open annulus
may be formed between the casing and the tubing 125. Optionally,
portions of the candidate well 101 may be isolated using, for
example, packers. In addition to stimulation fluid, it is
contemplated the pressure barrier may protect the candidate well
101 from other types of treating fluids flowing from a nearby
treatment well.
[0022] The natural gas utilized for injection may be supplied from
a variety of sources 135. For example, the natural gas may be taken
from a field gas gathering pipeline, another producing well in
close proximity to the candidate well, an onsite production
facility, or a commercial production facility. In another example,
the natural gas may be liquefied natural gas "LNG," compressed
natural gas "CNG," or natural gas liquids "NGL" from a nearby
production facility or a storage vessel. In yet another example,
the natural gas may be stored in a pressurized vessel brought to or
located at the candidate wellsite. A flow meter, or similar device,
may be used to measure the amount of natural gas supplied to the
compressor 141. In one embodiment, the natural gas may be injected
into a portion of or the entire footage of the wellbore 120
immediately adjacent to the producing formation 130.
[0023] In one embodiment, the natural gas may be injected using a
compressor, a pump, or other suitable machine having sufficient
power to inject natural gas to increase the pressure in the
producing formation 130 to establish a pressure barrier for
protecting the candidate well 101. In one example, the compressor
141 is either single stage or multiple stages. The compressor 141
may optionally be provided as an injection compressor skid package
140. In addition to the compressor 141, the skid package 140 may
include gauges 142 for monitoring the suction pressure and the
discharge pressure into the candidate well 101. The skid package
140 may typically include liquid dumps 143 to remove any liquid
build up that may occur in the natural gas. The liquid dump 143 may
be manually or automatically controlled. In one embodiment, a flow
meter 144 may form a part of the skid package 140. Because the
natural gas may come from a variety of sources, the compressor 141
is configured to handle a range of suction pressures from these
sources. Further, the compressor 141 is configured to generate
sufficient discharge pressures to increase the reservoir pressure
sufficiently to create a pressure barrier in the candidate well
101. If additional discharge pressure is required, the skid package
140 may be equipped with additional discharge boosters. In one
embodiment, the compressor 141 can generate discharge pressures
ranging from 80 psi to 4,000 psi. In another embodiment, the
compressor 141 can generate a discharge pressure that increases the
reservoir pressure to a pressure at or below the treating pressure
of the stimulation treatment for the treatment well 100; for
example, between 50% and 100% or between 60% and 90% of the
stimulation treatment pressure. In another embodiment, the
discharge pressure into candidate well 101 is below the treating
pressure of the formation around the wellbore of the treatment
well; for example, between 15% and 50% of the stimulation treatment
pressure. In yet another embodiment, the pressure of the candidate
well 101 is increased from 1.5.times. to 5.times. the shut-in
pressure of the candidate well 101. In one embodiment, the
discharge pressure is less than either the fracture gradient of the
producing formation 130 or the rated pressure limitation of the
existing wellhead assembly and wellbore tubulars within the
candidate well 101.
[0024] While a compressor is disclosed in FIG. 2, the natural gas
may be supplied to the candidate well 101 using any apparatus
capable of supplying pressurized natural gas to increase the near
wellbore reservoir pressure of the candidate well 101. For example,
the natural gas may be stored in a pressurized vessel that is
connected to the wellhead 130 via an injection line. When the
injection line is opened, the pressurized natural gas may flow
through the injection line and enter the candidate well 101 without
passing through a compressor. In another example, the wellhead 130
may be connected to a field gathering pipeline. Natural gas may be
allowed to flow from the pipeline to the candidate well 101 without
passing through a compressor.
[0025] In operation, the candidate well 101 may be injected with
natural gas to increase the near wellbore reservoir pressure of the
candidate well 101 to mitigate and/or minimize ingress of
stimulation fluids and/or pressure from a nearby treatment well
100. Initially, prior to performing a stimulation treatment at the
treatment well 100, the candidate well 101 is shut-in and is
allowed to naturally build up a shut-in pressure. Exemplary shut-in
pressures may be between 100 psi and 1,500 psi. The shut-in
pressure may be allowed to build for a period of a few days to
multiple weeks; for example, 3 days to 12 weeks, or from 1 week to
8 weeks. It must be noted that natural gas may also be injected
into nearby candidate wells 102, 103 to similarly create pressure
barriers to mitigate or minimize communications such as stimulation
fluid and pressure emanating from the treatment well 100.
[0026] After the shut-in pressure is allowed to build, natural gas
may be injected into the candidate well 101. A compressor 141, or
optionally an injection pressure skid package 140, is connected to
the candidate well 101. In particular, the discharge line of the
compressor 141 is connected to the wellhead 130 to provide a flow
path for the injected natural gas. The natural gas source may be
connected to the suction side of the compressor 141. For example, a
field gathering pipeline 135 may be connected to the compressor 141
to supply the requisite amount of natural gas. The natural gas may
optionally be processed before being supplied into the compressor
141. For example, the natural gas may flow through a filter or
dewatering apparatus before entering the compressor. After entering
the compressor 141, the natural gas may go through multiple stages
of compression until the desired discharge pressure is established.
Thereafter, the pressurized natural gas is discharged via the
discharge line into the candidate well 101.
[0027] Pressure in the candidate well 101 may be allowed to build
up before starting the stimulation treatment for treatment well
100. Natural gas is injected into the candidate well 101 to
increase the near wellbore reservoir pressure of the candidate well
101 thereby establishing a pressure barrier to a pressure above the
shut-in pressure. In one embodiment, the pressure in the candidate
well 101 is increased to a pressure between 700 psi and 3,500 psi;
preferably, built up pressure is between 1,100 psi and 2,300 psi.
In one embodiment, the pressure in the candidate well is increased
to a built up pressure at which the pressure in the wellbore is
observed to have leveled off, or in some instances, reached maximum
pressure build up. The length of time required for the injection
build up may be between 2 days and 4 weeks; typically, between 4
days and 14 days.
[0028] In one embodiment, the stimulation treatment of the
treatment well 100 may begin when the pressure in the candidate
well 101 has built up to between 800 psi and 2,100 psi; preferably
between 1,000 psi and 1,900 psi. The pressure of the candidate well
101 may be monitored using the pressure gauge 142. Optionally, the
pressure of the candidate well 101 may be measured using a gauge
132 coupled to the wellhead 130. The stimulation treatment may
begin at the toe section of the treatment well 100 and work toward
the heel section. The stimulation fluid being pumped into the
treatment well may include a fluid and proppant.
[0029] The pressure in the candidate well 101 may be maintained
during the stimulation treatment of the treatment well 100. For
example, the pressure in the candidate well may be maintained
within 30%, within 20%, within 10%, or within 5% above or below the
built-up pressure. Without wishing to be bound by theory, it is
believed that the higher natural gas pressure in the candidate well
101 and the near wellbore environment, e.g., fractures in the
producing formation 130, acts a pressure barrier that deters fluid
or pressure communications, e.g., the flow of the stimulation
fluid, from entering the candidate well 101. In this manner, the
pressure barrier provided by the natural gas may mitigate damages
to the candidate well 101 as a result of any ingress of stimulation
fluid or damaging pressures.
[0030] After completion of the stimulation treatment, the injection
of natural gas into the candidate well 101 is stopped. The injected
natural gas is allowed to remain in the candidate well 101 in a
shut in status until the candidate well 101 is restored to a
producing status. In another embodiment, the reservoir pressure in
the candidate well 101 may be maintained for a period of time after
completion of the stimulation treatment to ensure that potential
fluid or pressure communications from the treatment well 100 or
other treatment wells are minimized or mitigated. In yet another
embodiment, the injection of natural gas is stopped before
completion of the stimulation treatment. For example, the natural
gas injection may be stopped before the completion of the
stimulation treatment if any section, such as the heel section, of
the treatment well 100 is sufficiently far away from the candidate
well 101. In addition, natural gas injection may be stopped before
completion of the stimulation treatment if the near wellbore
reservoir pressure does not significantly deplete or leak off
during shut in period. For example, the near wellbore reservoir
pressure in the candidate well retains at least 80% of the
reservoir pressure at the start of the stimulation treatment;
preferably, at least 90% of the reservoir pressure. In yet another
embodiment, the injection of natural gas into the candidate well
101 may be stopped before commencing the stimulation treatment of
the treatment well 100.
[0031] FIG. 3 illustrates an exemplary pressure graph of a
candidate well in which the production is being shut in and
undergoing a natural gas injection operation as described herein.
At time T1, the candidate well is shut in. In this example, the
pressure of the candidate well at the beginning of shut in is
approximately 200 psi. Between time T1 and time T2, the pressure
builds naturally to 500 psi, at which time natural gas injection
commences. It must be noted the start of the natural gas injection
may be independent from the magnitude of the shut-in pressure. The
discharge pressure increases until it reaches approximately 1,300
psi at time T3. As seen in the graph, the pressure in the candidate
well has generally leveled off by time T3. The discharge pressure
is generally maintained before and during the stimulation
treatment. During the stimulation treatment, ingress of the
stimulation fluid and/or stimulation pressures may cause pressure
increases in the candidate well. In this example, a pressure
increase is seen at time T4, at about 1,600 psi, but eventually
will be deemed to not cause significant damage due to the limited
duration and magnitude of the pressure increase. The pressure does
not increase dramatically as typically seen in unprotected wells.
FIG. 4 illustrates an exemplary pressure graph of an unprotected
well exposed to fluid and pressure communications from a nearby
well undergoing a fracturing operation. As shown, the pressure
increase in an unprotected well caused by ingress of stimulation
fluid is faster in time and higher in magnitude. The gradual
increase shown in FIG. 3 suggests that the pressure arising from
the treatment well is buffered by the pressure barrier created by
natural gas injection into the candidate well. FIG. 5 illustrates
another example of a pressure graph for a candidate well protected
by natural gas injection. In this example, the candidate well
experiences multiple pressure increases caused by ingress of
stimulation fluid or pressure. However, as depicted, the resulting
pressure increases are more gradual and smaller in magnitude when
compared to the unprotected well of FIG. 4. After the completion of
the stimulation treatment, the compressor or injection source may
be shut down at time T5.
[0032] FIG. 6 illustrates another embodiment of a wellhead 230
configured for natural gas injection. The natural gas may be
injected using a compressor 241 having multiple stages. The suction
side of the compressor 241 is connected to a field gathering line
235 to receive natural gas. The natural gas may pass through a
coalescing filter 262 prior to entering the compressor 241.
Separated liquid from the filter 262 or the compressor 241 may be
directed to a production separator/storage tanks 263. Natural gas
is discharged from the compressor 241 to the wellhead 230 via an
injection line 261. A gauge 242, such as a Barton Recorder or other
suitable gauges, may be connected to the injection line 261 to
monitor the discharge pressure into the wellhead 230. The injection
line 261 may have an optional tie-in 271 to the wellhead 230. In
another embodiment, a chemical pump and storage complex 265 may be
connected to the injection line 261 to supply one or more chemicals
to the wellhead 230.
[0033] While the foregoing is directed to embodiments of the
present disclosure, other and further embodiments of the disclosure
may be devised without departing from the basic scope thereof, and
the scope of the invention is determined by the claims that
follow.
* * * * *