U.S. patent application number 14/418390 was filed with the patent office on 2015-11-26 for reduced emissions method for recovering product from a hydraulic fracturing operation.
This patent application is currently assigned to MILLENNIUM STIMULATION SERVICES LTD.. The applicant listed for this patent is MILLENNIUM STIMULATION SERVICES LTD.. Invention is credited to Grant W. NEVISON, Robert Rodney ROSS.
Application Number | 20150337639 14/418390 |
Document ID | / |
Family ID | 50149304 |
Filed Date | 2015-11-26 |
United States Patent
Application |
20150337639 |
Kind Code |
A1 |
NEVISON; Grant W. ; et
al. |
November 26, 2015 |
REDUCED EMISSIONS METHOD FOR RECOVERING PRODUCT FROM A HYDRAULIC
FRACTURING OPERATION
Abstract
A fracturing fluid mixture is used to hydraulically fracture
underground formations in a reservoir, by mixing at least natural
gas and a base fluid to form the fracturing fluid mixture, and
injecting the fracturing fluid mixture into a well. Within the
fracturing fluid mixture, the natural gas composition and content
are selected such that a recovered gas component of a well stream
is within the inlet specification of an existing gas processing
facility, and the well stream has a wellhead flowing pressure that
is sufficient to flow the well stream to surface, or have a flowing
pressure that meets capture system inlet pressure requirements of
the processing facility. The wellhead flowing pressure or the
flowing pressure at the capture system inlet can be increased by
adding natural gas to the fracturing fluid, which has the effect of
reducing the bottom hole flowing pressure.
Inventors: |
NEVISON; Grant W.; (Bragg
Creek, CA) ; ROSS; Robert Rodney; (Armstrong,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
MILLENNIUM STIMULATION SERVICES LTD. |
Calgary, Alberta |
|
CA |
|
|
Assignee: |
MILLENNIUM STIMULATION SERVICES
LTD.
Calgary
AB
|
Family ID: |
50149304 |
Appl. No.: |
14/418390 |
Filed: |
August 23, 2012 |
PCT Filed: |
August 23, 2012 |
PCT NO: |
PCT/CA2012/000798 |
371 Date: |
August 10, 2015 |
Current U.S.
Class: |
166/250.03 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/34 20130101 |
International
Class: |
E21B 43/34 20060101
E21B043/34; E21B 43/26 20060101 E21B043/26 |
Claims
1. A method for hydraulically fracturing a formation in a reservoir
using a fracturing fluid mixture comprising natural gas and a
fracturing base fluid and for recovering after the fracturing, a
well stream from a well fluidly coupled to the reservoir and to a
surface processing facility, the method comprising: (a) defining
flow back requirements for flowing the well stream from the well
and into the processing facility; (b) determining a natural gas
composition of the fracturing fluid mixture from the determined
flow back requirements that results in a composition of a gas
component of the well stream that is compatible with gas
composition requirements of the processing facility; (c)
determining a natural gas content of the fracturing fluid mixture
from the determined flow back requirements that results in a
wellhead flowing pressure sufficient to flow the well stream at
least to surface; (d) forming the fracturing fluid mixture having
the determined natural gas composition and content; (e) during a
formation fracturing stage, injecting the fracturing fluid mixture
into the well to fracture the formation; and during a flow back
stage, flowing the gas component of the well stream from the well
into the processing facility, wherein at least some of the well
stream includes the injected natural gas in the fracturing fluid
mixture.
2. A method as claimed in claim 1 wherein in step (c) the natural
gas content is determined which also results in a well stream
pressure at a capture system inlet that at least meets inlet
pressure requirements of the processing facility.
3. A method as claimed in claim 2 wherein the well stream includes
native reservoir gases, and at least some of the native reservoir
gases and injected natural gases are flowed into the processing
facility.
4. A method as claimed in claim 2 wherein the well stream includes
native reservoir liquids and the method further comprises
separating a liquid component comprising the native reservoir
liquids from the well stream using flow back equipment fluidly
coupled between the well and the processing facility.
5. A method as claimed in claim 2 wherein the flow back
requirements include pressure losses associated with flow back
equipment fluidly coupled between the well and the processing
facility.
6. A method as claimed in claim 5 wherein the processing facility
is configured to process gases and liquids, and the method further
comprises in step (b): determining a natural gas composition of the
fracturing fluid mixture from the determined flow back requirements
that results in a composition of a gas component and a liquid
component of the well stream that are compatible with gas and
liquid composition requirements of the processing facility; and in
step (f): during a flow back stage, flowing the gas and liquid
components of the well stream from the well into the processing
facility, wherein at least some of the well stream includes the
injected natural gas in the fracturing fluid mixture.
7. A method as claimed in claim 6 wherein the flow back equipment
comprises a solids separator and the method further comprises
separating solids from the well stream using the solids separator
prior to flowing the gas and liquid components to the processing
facility.
8. A method as claimed in claim 5 wherein the flow back equipment
comprises a gas-liquid flow separator, and the method further
comprises: separating a gas component from the flow back fluids
using the gas-liquid flow separator and then flowing the gas
component to the processing facility.
9. A method as claimed in claim 5 wherein the flow back equipment
includes a three-phase separator and the method further comprises
using the three-phase separator to separate a gas component, a
water component, and an oil component from the well stream.
10. A method as claimed in claim 9 further comprising flowing the
separated gas component to the processing facility, flowing the
water component to a water treatment or a disposal facility or to a
water storage tank, and flowing the oil component to an oil
processing facility, a sales facility, or an oil storage tank.
11. A method as claimed in claim 1 further comprising separating a
gas component from the well stream using flow back equipment
fluidly coupled between the well and the processing facility, and
compressing the gas component using a compressor of the flow back
equipment to a pressure that at least meets inlet pressure
requirements of the processing facility.
12. A method as claimed in claim 11 further comprising after
separation of the gas component and before compression, recovering
condensing water from the separated gas component using the flow
back equipment until the gas component meets inlet requirements of
the compressor.
13. A method as claimed in claim 12 wherein the flow back equipment
further comprises a natural gas liquids recovery or scrubbing unit
and the method further comprises after separation of the gas
component and before compression, using the natural gas recovery or
scrubbing unit to remove condensing liquids from the gas component
until the gas component meets inlet requirements of the
compressor.
14. A method as claimed in claim 1 wherein the fracturing base
fluid is an aqueous fluid.
15. A method as claimed in claim 1 wherein the fracturing base
fluid is a hydrocarbon based fluid.
16. A method as claimed in claim 1 wherein the flow back
requirements include a maximum fracturing base fluid flow rate that
results in a recovered fracturing base fluid volume that is within
specifications of a water storage tank and the method further
comprises separating water from the well stream using surface flow
back equipment fluidly coupled between the well and the processing
facility, and storing the water in the water storage tank.
17. A method as claimed in claim 1 wherein during the flow back
stage, the gas component of the well stream is flowed from the well
into the processing facility without venting or flaring.
18. A method for hydraulically fracturing a formation in a
reservoir using a fracturing fluid mixture comprising natural gas
and a base fluid and for recovering after the fracturing, a well
stream from a well fluidly coupled to the reservoir and to a
surface processing facility, the method comprising: (a) defining
flow back requirements for flowing the well stream from the well
and into the processing facility; (b) determining a natural gas
content of the fracturing fluid mixture from the determined flow
back requirements that results in a surface flowing pressure
sufficient to flow the well stream to surface and which meets inlet
pressure requirements of the processing facility; (c) forming the
fracturing fluid mixture having the selected natural gas content;
(d) during a formation fracturing stage, injecting the fracturing
fluid mixture into the well to fracture the formation; and (e)
during a flow back stage, flowing at least a gas component of the
well stream from the well into the processing facility, wherein at
least some of the well stream includes the injected natural gas in
the fracturing fluid mixture.
19. A method as claimed in claim 18 further comprising determining
a natural gas composition of the fracturing fluid mixture from the
determined flow back requirements that results in a composition of
the gas component of the well stream that is compatible with gas
composition requirements of the processing facility.
20. A method as claimed in claim 18 further comprising processing
the gas component of the well stream using surface flow back
equipment fluidly coupled between the well and the processing
facility until the composition of the gas component meets gas
composition requirements of the processing facility.
Description
FIELD
[0001] This invention relates generally to a reduced emissions
method for hydraulically fracturing a formation in an underground
reservoir using a fracturing fluid mixture and recovering product
from the reservoir.
BACKGROUND
[0002] When employing hydraulic fracturing to fracture a
hydrocarbon formation in an underground reservoir, large quantities
of liquids and proppant materials are injected into the reservoir.
At the end of the fracturing treatment, the fracture system and
reservoir are completely saturated with the fracturing fluid. To be
produced, oil and gas must either flow around or through the
fracture fluid saturated rock and fracture system such that the
fracture fluid must be sufficiently removed from the pathway in
order to not impair flow. To remove the fracturing fluids from the
reservoir and fractures, a pressure differential is induced within
the wellbore to draw the fracturing fluids out of the reservoir and
fractures. In this manner the fracturing fluids are removed, or
flowed back until sustained, stable and sufficient oil and gas
production is achieved.
[0003] Once the well is placed on production, the flow of native
reservoir fluids is directed from the well to a processing facility
where the produced fluids are processed to a suitable specification
for sales or reuse in some manner. Processing at the processing
facility for natural gas may include liquids separation,
dehydration, natural gas liquids capture, compression, plus
contaminates removal for components such as carbon dioxide,
nitrogen, sulfur, hydrogen sulfide and oxygen. The processing
facility can be located in the vicinity of the wellbore or a remote
location and fluidly coupled to the wellbore by a pipeline.
Further, the processing facility may be applied to process native
reservoir fluids from a single well, or multiple wells.
[0004] The processing facility is typically configured with the
capacity and capability to process a fluid composition of primarily
native reservoir fluids and at a prescribed inlet pressure, but
this configuration is typically not suitable for processing a
composition that includes well effluent such as fracturing fluids
or the inlet pressures available during fracture fluids recovery.
Most commonly, due to capacity and capability limitations of
processing facilities, recovery of the injected fracturing fluids
is accomplished by simply opening the well to atmosphere. Common to
post-fracturing recovery, the water and proppant components of the
effluent are separated from the gas component by temporary
fracturing flow back equipment primarily comprised of a choke to
control pressure, phase separation for solids, liquids and gases,
storage and or processing for the liquids and a vent or flare to
atmosphere as an outlet for the gas stream. The flow back equipment
is often comprised of an open-ended conduit directing flow to a pit
where the liquids and solids are separated and captured within the
pit while gases are vented or burned to atmosphere. This technique
maximizes the pressure differential induced within the wellbore to
draw the fracturing fluids out of the reservoir plus eliminates the
complexities, costs, upsets and damage that may be encountered by
attempting to direct the post-fracture well stream to the
production facilities.
[0005] For example consider a well which produces at least natural
gas and has had nitrogen energized water based fracturing treatment
completed. The processing facility has been configured to process
the native well stream, which generally contains at least natural
gas with 25 lb/MMscf water, 7 vol % carbon dioxide, 1 vol %
nitrogen, 0 vol % sulfur, hydrogen sulfide and oxygen and with a
heating content of 1025 Btu/ft3, all of which is to enter the
processing facility at a minimum pressure of 75 psig. The
processing facility is then configured to process this native gas
to a sales specification with a target composition and condition
not exceeding 7 lb/MMscf for water, 2-3 vol % for carbon dioxide, 3
vol % for nitrogen, 50 mg/m3 of sulfur, 15 mg/m3 of hydrogen
sulfide and 0.4 vol % of oxygen with a heating value in the range
of 950 to 1150 Btu/ft3 at an outlet pressure of 600 psi. As such,
the processing facility is configured with capacity to remove at
least 20 lb/MMscf water, through a dehydration process, and 5 vol %
carbon dioxide, through an amine carbon dioxide capture system,
from the native natural gas, and then compress the natural gas to
the required outlet pressure of 600 psig. The facility will not be
configured to remove nitrogen, sulfur, sulfur dioxide, or oxygen
from the native gas, or to modify the heating content; as these
components of the native natural gas are within sales
specification. Following the fracturing treatment and during the
flow back stage, the well is flowed to remove the fracturing fluids
from the reservoir. This is completed using temporary fracturing
flow back equipment until such time as sufficient native reservoir
fluids are included within the well stream such that the well
stream is within the capability of the processing facility to
process to the sales specification. This is commonly referred to as
the well being `cleaned-up` where sufficient fracturing load fluid
has been recovered and the well is placed `on production`. This
post-fracture clean-up process or flow back stage may take two or
more weeks to complete which is a relatively short time in the life
of the well and does not warrant alteration of the processing
facility to permit processing the post-fracture well stream.
Initially during flow back of the fracturing fluids, the well
stream will be comprised of virtually 100% injected fracturing
materials, such as water, proppant and nitrogen gas. This gas
component of this initial well stream ("gas stream"), containing
nitrogen content in excess of the capability of the processing
facility cannot be directed to the facility and is, by necessity
vented or flared until the content is at or below 3%. As an
alternative to venting or flaring the high nitrogen content gas
stream, the recovered gas stream can be processed for nitrogen
removal prior to entering the processing facility inlet by adding,
for example, a temporary nitrogen capture membrane system. This
membrane system may by necessity include dehydration to remove
excess water vapor within the gas, compression to drive the gas
across the membrane, venting of the separated nitrogen to
atmosphere and finally additional compression of the separated
natural gas to meet the minimum inlet pressure of the processing
facility.
[0006] Due to the large amount of liquids typically found in a
post-fracturing well stream, the pressure of the gas stream may be
insufficient to meet the inlet pressure requirement of the
processing facility even though the content of the gas stream may
be within composition specification. The excessive liquids
contained within the flow back well stream, while flowing up the
wellbore from the reservoir and to surface, exhibits higher flowing
pressure losses. This causes a reduction in the flowing pressure to
surface, often to below the inlet pressure requirement of the
processing facility. Again, this necessitates venting or flaring of
the gas stream until the water content is reduced such that
pressure of the stream from the well is sufficient to overcome the
minimum inlet pressure of the processing facility. As an
alternative, should the gas composition be within the processing
facility inlet specification while the pressure is too low to meet
the inlet pressure requirement, a temporary gas compressor can be
applied to sufficiently increase the pressure to meet the inlet
pressure requirement to avoid venting or flaring. At least
dehydration for water vapor removal prior to compression is likely
needed in order for the gas component of the well stream to meet
the compressor's inlet requirements.
[0007] Further, should the flowing pressure losses be such that the
fluids will not readily flow to surface unassisted, load fluid
recovery techniques can be deployed to move fluids to surface
during the flow back stage. Two examples of such techniques are
swabbing and gas-lifting. Both techniques tend to be costly,
complex and time consuming and are add-on processes to the flow
back operation following the fracturing treatment. Swabbing
involves moving mechanical devices up the wellbore to cause liquids
in the wellbore to be lifted to surface. Gas-lifting involves
inserting a tubing string or coiled tubing inside the well casing
to a specified depth then injecting gas such as nitrogen or natural
gas into the tubing or annular space between the tubing and
wellbore to cause liquids to move to surface. Gas-lifting can
involve extensive surface equipment such as compressors to
pressurize the gas, and dehydration and cooling equipment to treat
the gas prior to compression.
[0008] While there are known techniques available for processing a
well stream at surface and to pressurize the well stream to a
sufficient processing facility inlet pressure, these techniques can
be environmentally harmful, and include techniques like venting or
flaring gases to atmosphere, and depositing liquids into open pits.
These temporary techniques also tend to require complicated and
expensive surface equipment, which also can introduce significant
pressure losses, thereby compromising the pressure differential
induced within the wellbore to draw the fracturing fluids out of
the reservoir.
[0009] Significantly reducing or eliminating venting, flaring and
the water applied during hydraulic fracture completion operations
is generally difficult, expensive, complex and ineffective, yet
important to the environment and ultimate sustainability of
existing well completion techniques. The oil and gas industry would
benefit from an effective, cost efficient, and reduced emissions
method to induce flow back behaviors after hydraulic
fracturing.
SUMMARY
[0010] A fracturing fluid mixture is used to hydraulically fracture
underground formations in a reservoir, by mixing at least natural
gas and an aqueous or hydrocarbon-based fracturing base fluid to
form the fracturing fluid mixture, and injecting the fracturing
fluid mixture into a well. The well is fluidly coupled to the
reservoir and to a surface processing facility. Within the
fracturing fluid mixture, the natural gas composition and content
are selected such that a recovered gas component of a well stream
is within the inlet specification of the processing facility, and
the well stream has a wellhead flowing pressure that is sufficient
to flow the well stream to surface, or have a flowing pressure that
meets capture system inlet pressure requirements of the processing
facility. The wellhead flowing pressure or the flowing pressure at
the capture system inlet can be increased by adding natural gas to
the fracturing fluid, which has the effect of reducing the wellbore
flowing pressure losses.
[0011] According to one aspect of the invention there is provided a
method for hydraulically fracturing the formation in the reservoir
using the fracturing fluid mixture and for recovering a well stream
from the well that comprises the following steps:
[0012] (a) defining flow back requirements for flowing the well
stream from the well and into the processing facility;
[0013] (b) determining a natural gas composition of the fracturing
fluid mixture from the determined flow back requirements that
results in a composition of a gas component of the well stream that
is compatible with gas composition requirements of the processing
facility;
[0014] (c) determining a natural gas content of the fracturing
fluid mixture from the determined flow back requirements that
results in a wellhead flowing pressure sufficient to flow the well
stream at least to surface, or a well stream pressure at a capture
system inlet that at least meets inlet pressure requirements of the
processing facility.
[0015] (d) forming the fracturing fluid mixture having the selected
natural gas composition;
[0016] (e) during a formation fracturing stage, injecting the
fracturing fluid mixture into the well to fracture the formation;
and
[0017] (f) during a flow back stage, flowing the gas component of
the well stream from the well into the processing facility, wherein
at least some of the well stream includes the injected natural gas
in the fracturing fluid mixture.
[0018] The well stream can also include native reservoir gases, in
which case at least some of the native reservoir gases and injected
natural gases are flowed into the processing facility. The well
stream can also include native reservoir liquids in which case the
method further can comprise separating a liquid component
comprising the native reservoir liquids from the well stream using
flow back equipment fluidly coupled between the well and the
processing facility.
[0019] During the flow back stage, the gas component of the well
stream can be flowed from the well into the processing facility
without any venting or flaring, thereby eliminating or at least
reducing harmful emissions released into the environment.
[0020] The processing facility can be configured to process gases
and liquids in which case the method further comprises determining
a natural gas composition of the fracturing fluid mixture from the
determined flow back requirements that results in a composition of
a gas component and a liquid component of the well stream that are
compatible with gas and liquid composition requirements of the
processing facility; and during the flow back stage, flowing the
gas and liquid components of the well stream from the well into the
processing facility, wherein at least some of the well stream
includes the injected natural gas in the fracturing fluid
mixture.
[0021] The flow back requirements can include pressure losses
associated with flow back equipment fluidly coupled between the
well and the processing facility. The flow back equipment can
comprise a solids separator in which case the method further
comprises separating solids from the well stream using the solids
separator prior to flowing the gas and liquid components to the
processing facility. Alternatively, the flow back equipment can
comprise a gas-liquid flow separator in which case the method
further comprises separating a gas component from the flow back
fluids using the gas-liquid flow separator and then flowing the gas
component to the processing facility. Alternatively, the flow back
equipment can include a three-phase separator in which case the
method further comprises using the three-phase separator to
separate a gas component, a water component, and an oil component
from the well stream. The separated gas component can be flowed to
the processing facility, the water component can be flowed to a
water treatment or disposal facility or to a water storage tank,
and the oil component can be flowed to an oil processing facility,
a sales facility, or an oil storage tank.
[0022] When the well stream at the capture system inlet is not at a
pressure that meets the inlet pressure requirements of the
processing facility, the method can further comprise compressing
the gas component of the well stream using a compressor to a
pressure that at least meets inlet pressure requirements of the
processing facility. If necessary, condensing water can be
recovered from the separated gas component using the flow back
equipment until the gas component meets inlet requirements of the
compressor. Also if necessary, condensing liquids can be removed
from the gas component using a natural gas recovery or scrubbing
unit to remove until the gas component meets inlet requirements of
the compressor.
[0023] The flow back requirements can also include a maximum
fracturing base fluid flow rate that results in a recovered
fracturing base fluid volume that is within specifications of a
water storage tank, in which case the method further comprises
separating water from the well stream using surface flow back
equipment fluidly coupled between the well and the processing
facility, and storing the water in the water storage tank.
[0024] According to another aspect of the invention, there is
provided a method for hydraulically fracturing a formation in a
reservoir and for recovering a well stream from the well,
comprising:
[0025] (a) defining flow back requirements for flowing the well
stream from the well and into the processing facility;
[0026] (b) determining a natural gas content of the fracturing
fluid mixture from the determined flow back requirements that
results in a surface flowing pressure sufficient to flow the well
stream to surface and which meets inlet pressure requirements of
the processing facility;
[0027] (c) forming the fracturing fluid mixture having the selected
natural gas content;
[0028] (d) during a formation fracturing stage, injecting the
fracturing fluid mixture into the well to fracture the formation;
and
[0029] (e) during a flow back stage, flowing at least a gas
component of the well stream from the well into the processing
facility, wherein at least some of the well stream includes the
injected natural gas in the fracturing fluid mixture.
[0030] The method can comprise determining a natural gas
composition of the fracturing fluid mixture from the determined
flow back requirements that results in a composition of the gas
component of the well stream that is compatible with gas
composition requirements of the processing facility. Alternatively,
the method can further comprise processing the gas component of the
well stream using surface flow back equipment fluidly coupled
between the well and the processing facility until the composition
of the gas component meets gas composition requirements of the
processing facility.
BRIEF DESCRIPTION OF DRAWINGS
[0031] FIG. 1 is a schematic plan view of equipment for injecting a
fracturing fluid mixture containing natural gas into a wellbore
formation according to one embodiment of the invention;
[0032] FIG. 2a and FIG. 2b shows an underground reservoir with
fracture fluid injection into, and fracture fluid removal from, the
underground reservoir;
[0033] FIG. 3 is a flowchart illustrating the steps for a method of
fracturing a formation using the fracturing fluid mixture and the
equipment shown in FIG. 1, then flowing back the applied fracturing
fluid mixture to capture the flow back effluent from the well;
[0034] FIG. 4 is a diagram illustrating the main components of
fracturing fluid flow back equipment according to an embodiment of
a natural gas mixture fracture treatment for capture of fracturing
and native gases to a processing facility;
[0035] FIG. 5 is a diagram that illustrates the main components of
fracturing fluid flow back equipment according to an embodiment of
a natural gas mixture fracture treatment for separation of liquids
from the flow back well stream with recovery of gases to a
processing facility;
[0036] FIG. 6 is a diagram that illustrates the main components of
fracturing fluid flow back equipment according to an embodiment of
a natural gas mixture fracture treatment for separation of liquids
from the flow back well stream with compression of gases prior to
entry into a processing facility;
[0037] FIG. 7 is a diagram showing the reduction in commingled
fluid density achieved by adding natural gas to water over a range
of pressures at a temperature of 60.degree. C.;
[0038] FIG. 8 is a diagram showing the reduction in commingled
fluid density achieved by adding natural gas to a 39 API fracturing
oil over a range of pressures at a temperature of 60.degree.
C.;
[0039] FIG. 9 is a diagram illustrating the bottom hole flow
pressure resulting from a range of natural gas addition ratios to
water for an example well flowing at a liquid rate of 200
m.sup.3/day; and
[0040] FIG. 10 is a diagram illustrating the pressure and density
profile within an example wellbore at a chosen natural gas addition
ratio.
DETAILED DESCRIPTION
[0041] In this description, various terms are used to describe the
pressures at different locations in the reservoir and wellbore;
these terms are ascribed a meaning as generally understood by one
skilled in the art. The following provides a generalized summary of
the relationships between these terms: [0042] Bottom hole flowing
pressure (BHFP)=wellhead flowing pressure+wellbore hydrostatic
pressure+wellbore flowing friction pressure; [0043] Wellhead
flowing pressure (WHFP)=capture system entry pressure+surface
equipment pressure losses; [0044] Capture system inlet pressure
means the pressure at the inlet of a processing facility or a
pipeline coupled to the processing facility; [0045] Surface
equipment pressure losses mean the pressure losses of flow back
fluids flowing through surface flow back equipment; [0046]
BHFP=reservoir pressure-drawdown pressure [0047] Drawdown
pressure=viscous flowing forces pressure loss+capillary forces
pressure loss
[0048] The embodiments described herein relate to a method for
hydraulically fracturing a formation in a reservoir and capturing
flow back fluids from the reservoir, that comprises selecting a
natural gas content of a fracturing fluid mixture that will be
sufficient to achieve a desired wellhead flowing pressure that is
sufficient to flow a well stream to surface, or have a flowing
pressure at a capture system inlet that meets pressure requirements
of a processing facility. Furthermore, the composition of the
natural gas is selected to provide a composition of the well stream
that is compatible with composition requirements of the processing
facility. The wellhead flowing pressure and flowing pressure at the
capture system inlet can be increased by adding natural gas, which
has the effect of reducing the flowing pressure losses within the
wellbore.
[0049] The fracturing fluid mixture is used to hydraulically
fracture underground formations in a reservoir, and involves mixing
at least natural gas and a fracturing base fluid to form the
fracturing fluid mixture then injecting the fracturing fluid
mixture into a well that extends through the reservoir and to a
formation to be fractured. The fracturing fluid mixture is then
flowed back to surface from the reservoir along with native
reservoir fluids and the well effluent gases (collectively "well
stream") and then directed to a pipeline or processing
facility.
[0050] The fracturing base fluid can comprise an aqueous or
hydrocarbon well servicing fluid, as well as a proppant and one or
more viscosifiers to impart viscosity to the mixture. The volume of
natural gas added to the fracturing fluid mixture is manipulated so
that the mixture has certain behaviors during the fracturing
operation and subsequent fracturing fluids flow back operation. For
the flow back operation these behaviors include a certain density,
flowing characteristic and composition that achieves a particular
flowing rate and surface pressure during flow back to permit
capture of the well effluent gases to a pipeline or processing
facility.
[0051] This fracturing base fluid is combined with a gaseous phase
natural gas stream to form the fracturing fluid mixture. Dependent
upon the nature of the fracturing base fluid, the natural gas
component of the mixture can be marginally or highly miscible in
the well servicing fluid. The resulting fracturing fluid mixture is
injected into the underground formation to create fractures or to
enhance existing fractures. As will be discussed in greater detail
below, the quantity of the natural gas applied to the conventional
hydrocarbon well servicing fluid is manipulated to create desired
behaviors of the fracturing fluid mixture during the fracturing
flow back operation, with the objective of improving performance of
the fracturing flow back operation such that flow back fluids can
be effectively and economically captured. More particularly, the
quantity of natural gas can be manipulated to reduce the
hydrostatic and flowing pressures in the wellbore, therefore
decreasing the required bottom hole flowing pressure for a desired
wellhead flowing pressure and flowing pressure at the capture
system inlet. The quantity of natural gas can also be manipulated
to reduce the liquid content of the base fluid when an aqueous or
hydrocarbon base fluid is used in the fracturing fluid mixture,
such that a manageable amount of the liquid can be captured in a
tank or other closed system of the surface flow back equipment or
which meets compositional requirements of a processing facility and
thus can be flowed directly to the processing facility.
[0052] As used in this disclosure, natural gas means methane
(CH.sub.4) alone or blends of methane with other gases such as
other gaseous hydrocarbons which may be present in commercial
supplies of natural gas. Natural gas is often a variable mixture of
about 85% to 99% methane (CH.sub.4) and 1% to 15% ethane
(C.sub.2H.sub.6), with further decreasing components of propane
(C.sub.3H.sub.8), butane (C.sub.4H.sub.10) and pentane
(C.sub.5H.sub.12) with traces of longer chain hydrocarbons. Natural
gas, as used herein, may also contain inert gases such as carbon
dioxide and nitrogen in varying degrees. Natural gas is in a
gaseous state at standard conditions of 60.degree. F. and 1
atmosphere with a critical temperature near -82.degree. C. As will
be described in greater detail below, the natural gas will be above
its critical temperature throughout the fracturing formation
operation and thus will be in a gaseous phase throughout the
operation.
[0053] As used in this disclosure, the well servicing fluid serves
as the fracturing base fluid in the fracturing fluid mixture and
may mean any aqueous based or liquid hydrocarbon fluid. Aqueous
based fluids may be comprised of water with brine, acid or
methanol. Liquid hydrocarbon fluids are those containing alkanes
and or aromatics that are applied to well servicing, stimulation or
hydraulic fracturing.
[0054] Referring to FIG. 1, the embodiments described herein
utilize formation fracturing equipment 2 to inject the fracturing
fluid mixture into the reservoir. The embodiments can utilize flow
back equipment 3 as shown in FIG. 1 to recover the flow back
fluids, or optionally, the equipment shown in FIG. 4, 5 or 6.
[0055] More particularly, FIG. 1 illustrates one configuration of
formation fracturing equipment 2 and flow back equipment 3 for
applying and recovering a natural gas and well servicing fluid
mixture in a closed system fracturing operation.
[0056] The formation fracturing equipment 2 includes the following
well servicing preparing and pressurizing equipment 4: Frac liquid
tanks 12 for containing the well servicing fluid fracturing base
fluid), a chemical addition unit 14 for containing and applying
viscosifying chemicals, and a proppant storage unit 16 for
containing and applying doppant needed for the operation. The well
servicing fluid, viscosifying chemicals, and doppant are combined
within a fracturing blender 18 to form a prepared well servicing
fluid then fed to base fluid fracturing pumpers 17 where the
prepared well servicing fluid a pressured to fracturing conditions.
The formation fracturing equipment 2 also includes the following
natural gas preparation equipment 22: Mobile storage vessels 24 or
storing natural gas in the form of liquefied natural gas (LNG). LNG
fracturing pumpers 26 for pressurizing the LNG to fracturing
conditions, and heating the LNG to a desired application
temperature. The formation fracturing equipment 2 also includes
components 30 for combining the prepared well servicing fluid with
the gaseous natural gas stream to form the fracturing fluid mixture
and subsequently directing this mixture to a wellhead 32. The
combined fluids then travel down the wellbore and into the
formation to fracture the interval.
[0057] The flow back equipment 3 as shown in FIG. 1 is for
receiving and capturing the fracturing and produced reservoir
fluids (well stream) that flow up the wellbore and out of the
wellhead 32 after completion of the fracturing treatment. In this
embodiment, the well stream is directed from the wellhead 32,
through a conduit coupled to the wellhead, past a choke 5, and to a
gas-liquid flow separator 36. Pressure from the wellhead 32 and to
the flow separator 36 is managed using the choke 5. Optionally, a
sand or solids rap (not shown) may be placed downstream of the
wellhead 32 and upstream of the choke 5 to prevent proppant or
solids from flowing into the flow back equipment 3. Optionally, the
flow back equipment 3 does not include the separator 36; instead,
all of the well stream can be directed to a gas & liquids
pipeline (not shown) for off-site processing provided that such
well stream meets the compositional requirements of the pipeline
and the processing facility coupled to the pipeline. If present,
the gas-liquid flow separator 36 separates the recovered gas and
liquid components of the well stream. The recovered liquid
component includes the well servicing fluid and produced native
reservoir liquids, and are directed to a liquids recovery tank 38.
Instead of the liquids recovery tank 38, recovered liquids can be
directed to a liquids pipeline (not shown) for processing should
such processing facility exist. The recovered gas component,
including the applied natural gas and produced native reservoir
gases, is directed to a gas pipeline 40, where it is directed to a
processing facility (not shown) for processing and sale. In this or
a similar manner, an environmentally closed fracturing system can
be created and applied permitting hydraulic fracturing and recovery
without venting or flaring of gases by a vent/flare 42 and feeding
liquids to an open pit.
[0058] The fracturing and flow back operations in accordance with
one embodiment will now be described with reference to FIGS. 2a and
2b and FIG. 3.
[0059] As shown in FIG. 2a, a fracturing fluid mixture 204 is
injected into and down a wellbore 201 through perforations 205 and
into an underground reservoir 202 to create single or multiple
hydraulic fractures 203 radiating from the wellbore 201 and
penetrating the reservoir 202 (while FIG. 2a depicts a symmetrical
bi-wing fracture created in a vertical wellbore penetrating the
underground reservoir, the same effect can apply to non-symmetrical
multiple fractures created in either a vertical or horizontal
wellbore). With injection for fracture creation, some or all of the
fracturing fluid mixture 204 leaks from the fracture 203, referred
to as "leak-off" 206, and into the reservoir 202, referred to as
the `invaded zone` within the reservoir 202. Upon creating
sufficient hydraulic fractures, injection is stopped, the well is
shut-in and the injected fracturing fluid mixture 204 dissipates
into the underground reservoir 202 as equilibrium is approached or
reached and the fractures 203 close on the proppant. The applied
fracturing fluid mixture saturates the fractures and underground
reservoir within the invaded zone following fracturing fluid
injection.
[0060] In order to begin production of native reservoir fluids, the
fracturing fluid mixture must be sufficiently removed from the
fractures 203 and underground reservoir 202. The well is opened and
as shown in FIG. 2b, a well stream 210 is often comprised of
injected fracturing fluid and native reservoir fluid, and flows
from the underground reservoir 202 through the fractures 203 and up
the wellbore 201. If sufficient reservoir pressure exists to
overcome the capillary and viscous flowing forces holding the
fluids in place inside the reservoir (collectively "reservoir
resistive effects"), as well as the bottom hole flowing pressure,
the well stream 210 will flow from the reservoir 202 and fractures
203 up the wellbore 201, through any surface flow back equipment
and into the processing facility (or into a pipeline for flow to a
remotely located processing facility). As noted above, the bottom
hole flowing pressure comprises frictional losses of the flow from
the perforations to surface ("flowing friction pressure"), plus the
hydrostatic pressure, plus any surface equipment pressure losses,
and the capture system inlet pressure.
[0061] If the reservoir pressure cannot overcome the existing
reservoir resistive effects and bottom hole flowing pressure, a
certain amount of natural gas can be added to a fracturing fluid
mixture to increase the wellhead flowing pressure such that the
well stream 210 can overcome any surface flow back equipment
pressure losses and still have a sufficient pressure at the capture
system inlet to meet inlet pressure requirements for a pipeline or
processing facility. More particularly, natural gas in the
fracturing fluid serves to reduce the liquid content placed into
the reservoir during the fracturing operation, lessen capillary and
viscous flowing forces within the invaded zone and created
fractures, and, by reduction of liquids in the returning flow
stream, reduce the density and hence the hydrostatic pressure of
the fluids flowing in the wellbore. The liquid content can be
optionally reduced to a level which meets pipeline and processing
facility compositional requirements, or at least to a level which
can be captured by closed storage tanks, thereby avoiding the need
to expose the liquids to the environment by depositing into an open
pit.
[0062] FIG. 3 shows a series of steps carried out by a formation
fracturing and flow back operation that are common to each
embodiment. At step 301, well flow back and surface capture flow
conditions are determined for a subject well and reservoir, which
include: [0063] well properties including: the depth, temperature
and pressure of the reservoir comprising the formation ("reservoir
depth", "reservoir temperature" and "reservoir pressure"); [0064]
wellbore properties including casing outer diameter, surface
roughness and wall thickness [0065] fracturing conditions including
bottom hole fracturing pressure, and the fracturing base fluid
characteristics including composition and density; and [0066] well
flow back conditions including bottom hole flowing temperature and
wellhead flowing temperature.
[0067] At step 302, flow back requirements for both equipment and
performance are defined, and then certain properties of the
fracturing fluid mixture 204 are determined that are required to
achieve these defined requirements during the flow back operation.
The flow back requirements include: [0068] equipment flow back
requirements including: the processing facility inlet pressure
requirement, pressure losses suffered by flow back fluids flowing
through the flow back equipment 3 (which can be dictated by the
flow back surface equipment configuration), and a target fluid
entry pressure above the pipeline or processing facility inlet
pressure requirement; and [0069] performance flow back requirements
including: maximum water flow back rate, maximum gas flow back
rate, target flow back pressure drawdown, target bottom hole
drawdown (flowing) pressure, and the composition of the gases
and/or liquids to be flowed into a pipeline or processing
facility.
[0070] At step 303, the natural gas composition and content of the
fracturing fluid mixture is determined that will achieve the
defined flow back requirements during the fracturing flow back
operation. This determination is achieved by defining a
relationship between bottom hole flowing pressure and natural
gas-to-base fluid ratio, using as inputs: the well flow back and
surface capture flow conditions for the subject well and reservoir
as well as the defined flow back requirements. Once this
relationship has been determined, a natural gas-to-base fluid ratio
is selected for a bottom hole flowing pressure that is below the
reservoir pressure minus a drawdown pressure. Then the amount of
natural gas and base fluid that needs to be mixed to form the
fracturing fluid mixture that achieves this determined natural
gas-to-base fluid ratio is determined. The composition of the
injected natural gas is selected to ensure the flow back fluids,
i.e. the combined flow of recovered injected gas, native reservoir
gas and any fracturing induced contaminants meet or exceed pipeline
specifications or the inlet requirements for the gas processing
facility.
[0071] At step 304, the hydraulic fracture treatment is completed
on the well in the reservoir 202 where the selected fracturing
fluid mixture 204 is prepared and injected having the determined
natural gas composition and content along with the base fluid.
[0072] At step 305, a well stream comprising the injected
fracturing fluid mixture is flowed back from the reservoir 202 at
the selected bottom hole flowing pressure and the selected flow
rate such that the recovered well stream meet the flow back
requirements and result in surface pressures that permit capture
and processing of at least a recovered gas component of the well
stream during the flow back operation.
[0073] When defining the flow back requirements per step 302,
consideration can be given to the processing facility inlet
pressure and compositional requirements. For example, a maximum gas
flow rate can be dictated by the capacity and capability of the
processing facility to process the flow back gases to meet or
exceed the sales specification, and a maximum fracturing base fluid
(e.g. water) flow rate and total base fluid recovered can be
dictated by the ability for a closed captured system to capture and
store water. By specifying flow back requirements that meet both
the pipeline or processing facility pressure and compositional
requirements, the amount of surface flow back equipment can be
reduced, thereby potentially saving time and cost when compared to
conventional processes that require treatment of the well stream
prior to meeting compositional requirements and/or compression of
flow back gases to meet pressure requirements. Further, by being
able to flow the well stream directly to the processing facility,
potentially environmentally adverse actions like venting and
flaring can be reduced or avoided altogether.
[0074] In one embodiment, the composition requirements of the
processing facility can be met by selecting a fracturing fluid
mixture that comprises a natural gas composition which meets
pipeline gas composition specification. In this embodiment, the
base fluid can be water or a liquid hydrocarbon, which can be
separated from the well stream by a gas-liquid separator in the
surface flow back equipment. The remaining well stream thus
contains the natural gas component of the fracturing fluid mixture,
as well as native reservoir fluids. Since the processing facility
is already configured to handle the composition of native reservoir
fluids, and since the natural gas composition is selected to meet
processing facility compositional requirements, the remaining well
stream should be able to flow directly to the processing facility
with only phase separation by the surface flow back equipment
3.
[0075] Determining the natural gas content to achieve the defined
flow back requirements per step 303 will now be discussed in more
detail with reference to FIGS. 7 to 10. FIG. 7 illustrates a
reduction in commingled fluid density that can be achieved by
adding natural gas to water, e.g. when a fracture fluid mixture
comprises natural gas and an aqueous base fluid. Commingled fluid
density determines the hydrostatic pressure exerted at the
underground reservoir by fluids contained within a wellbore.
Comingled fluid density also determines the total amount of water
that is likely to be applied and hence can be recovered during the
flow back stage; the information can dictate the capacity of any
storage tanks provided to store the water prior to disposal or
further processing. In FIG. 7, a range of pressures from 1,000 kPa
to 60,000 kPa at a temperature of 60.degree. C. is presented as an
illustration of density at selected natural gas and water ratios.
The natural gas to water ratios range from no added gas to gas
added at a ratio of 1,000 sm.sup.3 of natural gas for each m.sup.3
of water. Similar density reductions at other pressures,
temperatures, gas ratios and aqueous based liquids can be achieved.
As shown in FIG. 7, water has a relatively consistent density of
approximately 1,000 kg/m.sup.3 at temperature and pressure such
that a hydrostatic gradient of approximately 9.8 kPa/m is
exhibited. For a 2,000 m well, this results in a hydrostatic
pressure of 19,600 kPa at the base of the wellbore. Wellbore
flowing friction pressures create addition pressure loss and add to
the total bottom hole flowing pressure such that flow back rates
without sufficient reservoir pressure can be very low or
nonexistent and extend the flow back period. If the bottom hole
flowing pressure nearly matches the reservoir pressure, the
pressure differential available to overcome reservoir resistive
forces, i.e. viscous flowing forces, capillary pressures and
relative permeability effects, is minimal and fluid removal from
the fracture system and reservoir is compromised. In contrast, with
a natural gas ratio of 400 sm.sup.3/m.sup.3 liquid, the density can
vary from .about.60 kg/m.sup.3 at 1,000 kPa to 630 kg/m.sup.3 at
60,000 kPa resulting in a density reduction from about 40% to 95%
with a corresponding reduction in hydrostatic pressure exhibited by
the fluid column on the underground reservoir. As a result, the
bottom hole flowing pressure is reduced and the pressure
differential with the reservoir pressure is increased.
[0076] FIG. 8, similar to FIG. 7 is a diagram provided for
illustration of the reduction in commingled fluid density that can
be achieved by adding natural gas to a hydrocarbon based well
servicing fluid to form a fracturing fluid mixture. The effect
differs from that with water in that the natural gas is highly
soluble in the hydrocarbon based well servicing fluid. Due to the
solubility all added gas may be dissolved within the hydrocarbon
based well servicing fluid at higher pressures--the mixture is
above the bubble point at the composition and corresponding
pressure and temperature. This effect is illustrated on the figure
by the linear increase of density for a given gas to liquid ratio
with increasing pressure such as that seen at 50 sm.sup.3/m.sup.3
liquid beginning at approximately 6,000 kPa. With some hydrocarbon
well servicing fluids at higher natural gas ratios, the behavior of
the resulting mixture can be tailored to achieve a very low density
super critical fluid mixture with no liquids, or a condensing
mixture with only a very small fraction of liquids. Like FIG. 7,
FIG. 8 can be used to calculate the total amount of hydrocarbon
base fluid that is likely to be applied and can be recovered during
the flow back stage, which can dictate the capacity of storage
tanks used to store the base fluid prior to further processing.
[0077] FIG. 9 is a graph of bottom hole flowing pressure and
natural gas-to-water ratios at certain specified well flow back and
surface capture flow conditions and at certain defined flow back
requirements. FIG. 9 also graphs natural gas flowing rate and
natural gas-to-water ratio under the same conditions. This graph
was generated by a commercially available multiphase flow simulator
program common in the industry, such as GLEWPro.TM., using the well
flow back and surface capture conditions and flow back requirements
as provided in Example 1 below.
[0078] Examination of FIG. 9 shows a curve indicating bottom hole
pressures as high as 27,200 kPa when no gas is added to as low as
5,025 kPa with gas added at 500 sm.sup.3/m.sup.3 water. With no gas
addition, it can be seen that the bottom hole fluid pressure far
exceeds the reservoir pressure and flow back will not occur under
these conditions. The natural gas content required to meet the
defined flow back requirements per step 303 is determined by
identifying in FIG. 9 the natural gas to water ratio required to
lower the bottom hole flowing pressure to below a pressure that is
the difference between the reservoir pressure and a drawdown
pressure that overcomes the reservoir resistive effects at the
desired recovery rate. In a manner as known in the art, a target
flow back pressure drawdown percentage can be selected which is
expected to be sufficient to overcome the predicted reservoir
resistive effects. This selected drawdown percentage can be used to
calculate the pressure drawdown. The bottom hole flowing pressure
required to flow fluids to the processing facility can be
determined by subtracting the drawdown pressure from the reservoir
pressure. Once the required bottom hole flowing pressure is
determined, the required natural gas-to-water ratio can be
determined from FIG. 9, and a suitable fracturing fluid mixture
(using water as the base fluid) having this ratio can be used to
perform the fracturing operation.
[0079] As will be discussed in Example 1 below, the target drawdown
percentage used in FIG. 9 is 60%, resulting in a target drawdown
pressure of 10,395 kPa. The target bottom hole flow pressure is
thus 6930 kPa, and the required natural gas-to-water ratio is thus
250 sm.sup.3/m.sup.3. At this target bottom hole flow pressure, the
natural gas flow rate to surface is about 50,000 sm.sup.3/day and
the liquid flow rate to surface was defined in the flow back
requirement as 200 m.sup.3/day. Assuming the originally defined
flow back requirements meet the pipeline and processing facility
composition requirements, then it is expected that this gas flow
rate and its composition are compatible with the processing
facility specifications and that the well stream can be flowed
directly to the processing facility (or via a pipeline) or with
only phase separation of liquids if the processing facility is
configured to process gas.
[0080] As noted above, the addition of natural gas reduces the
bottom hole flowing pressure by reducing the hydrostatic pressure.
However, the behavior of commingled fluids flowing within a
wellbore is complex and does not readily lend itself to simple
calculations and computer programs are utilized to compute the
behaviors. In fact, the pressure will vary along the wellbore which
compresses or expands the gas phase and alters the density which
impacts the resulting hydrostatic. Similarly for flowing friction
within the wellbore, the friction pressure losses of the commingled
fluid vary with the relative volume of gas present where again the
relative volume of gas present varies with pressure along the
wellbore.
[0081] In addition to selecting the natural gas content in the
fracturing fluid to cause the well stream to meet processing
facility inlet pressure requirements, the natural gas composition
is also selected to ensure the flow back fluids meet compositional
requirements for flow into the processing facility. Manipulation of
the methane content in the natural gas up to a purity approaching
100% can be considered to ensure the well stream meets
compositional requirements. Alternatively, to target a requirement
for a higher than normal heating value content in the return gases,
the injected natural gas composition can be selected to contain
only 85% methane with the ethane and propane content increased to
increase the heating value. Similar manipulations to the content of
other components can be completed to meet a wide range of flow back
composition target requirements. For example, a fracturing induced
contaminant may include carbon dioxide released from an acid based
treatment completed on a carbonate formation. In this instance, the
content of the natural gas in the fracturing fluid may be increased
in order to dilute the carbon dioxide content of the fracturing
fluid to meet the inlet requirements. Alternatively, stripping of
light ends into the recovered gas stream from an oil based
fracturing treatment during flow back may result in too high a
heating value such that a injected gas methane content approaching
100%, or alternatively an increased nitrogen content is used to
reduce the recovered gas heating value
[0082] In the manner described above, applying a selected natural
gas composition and content to fracturing fluids serves to permit
flow back of the fracturing liquids and capture of the flow back
gases into a pipeline or processing facility with no or minimal
venting and flaring. The gas content is manipulated at least to
ensure flow from the reservoir 202 and up the wellbore 201 with
sufficient pressure at surface for phase separation, if needed, and
for the recovered gas component of the well stream to enter the
processing facility without compression. Further, the injected
natural gas composition is manipulated to ensure the composition of
the gas component of the well stream meets or exceeds the inlet
requirements for the pipeline or processing facility. This can
eliminate the requirement, complexity and the cost associated with
inducing well stream flow by methods such as swabbing and gas-lift.
It also eliminates the need to treat and compress the gas component
prior to entry to the processing facility. Further, the composition
of the gas component is managed to ensure the cost, complexity and
complications of pre-processing for the removal of contaminants
such as nitrogen and carbon dioxide are avoided. As discussed
below, the flow back gases can be easily recovered without
specialized surface flow back equipment or systems such as
dehydrators, membrane gas separators, amine towers, refrigeration
units, placement of an additional tubing string, injection for
gas-lift, swabbing and compression of gases for re-injection or for
inlet into processing facilities. In some applications the natural
gas content added to the fracturing fluid may be restricted and all
processing and flow back criteria may not be met. In those cases,
application of natural gas in the fracturing fluid may serve to
reduce the specialized surface equipment needed rather than
eliminate it.
[0083] According to another embodiment and referring to FIG. 4, the
surface flow back equipment 3 is configured to provide complete
recovery of the post-fracturing well stream, including the injected
natural gas and native reservoir fluids, which is then directed to
a processing facility 404 configured to process both liquids and
gases. In this embodiment, an optional sand trap 403 is provided
where solids such as proppants can be removed from the well stream
prior to entry to the processing facility 404. The flowing pressure
at a wellhead 401 must be sufficient to overcome pressure losses
through a conduit 405, the sand trap 403, across a choke 402 and a
conduit 406 at the flow back rate while maintaining sufficient
pressure to meet the pressure requirement at the inlet to the
processing facility 404. The natural gas content of the injected
fracture fluid mixture is manipulated to ensure an adequate
wellhead pressure exists at the desired flow back conditions. This
configuration is particularly applicable to flow back to processing
facilities capable of processing both liquids and gases such as is
often found at oil producing wells, or liquids-rich gas wells.
[0084] According to another embodiment and referring to FIG. 5, the
surface flow back equipment 3 is configured to recover the
post-fracturing well stream such that the well stream is separated
into its phases for capture and only the gas component is directed
to a gas pipeline or processing facility 504; the liquid component
is directed to separate capture systems potentially comprised of at
least storage, pipeline transport, processing, treatment or
disposal. In this embodiment, the flow back equipment 3 shown in
FIG. 4 is expanded to include a 3-phase separator 507 where the
gas, water and oil components are separated into a gas component
for flow through a gas conduit 508 to the gas pipeline/gas
processing facility 504, a water component for flow through a water
conduit 509 to a water treatment/disposal facility 510 and an oil
component for flow through an oil conduit 511 to an oil
processing/sales facility 512. Optionally, a 4-phase separator (not
shown) can be applied in place of the 3-phase separator 507 where
solids are also captured within the 4-phase separator and a sand
trap 503 would thus not be required. Alternatively, if the well
stream comprises only gas and water, a 2-phase separator (not
shown) could be used in place of the 3-phase separator 507.
[0085] Alternatively, the water and oil components can be stored in
respective temporary storage tanks (not shown) for transport by
truck or other means to a disposal, processing or sales
facility.
[0086] As noted above, recovered natural gas, comprised of injected
natural gas and natural gas native to the reservoir ("native
natural gas") are directed via the gas conduit 508 to the pipeline
or processing facility inlet 504. The pipeline 504 may serve to
transport natural gas to an off-site facility (not shown) for
processing or sales or optionally be directed to an on-site capture
facility such as, for example, processing and storage as compressed
or liquefied natural gas. Separated liquid oil, including oil which
may be used as the fracturing base fluid is directed via the oil
conduit 511 to the oil processing/sales facility 512 which may be a
pipeline or on-site oil processing facility or storage. Similarly,
separated water is directed through the water conduit 509 to the
water treatment/disposal facility 510. This water may be comprised
of water injected for the fracturing treatment or native formation
water and may be treated for re-use for hydraulic fracturing or
other purpose, or disposed by injection in a disposal well (not
shown). The flowing pressure at the wellhead 501 must be sufficient
to overcome pressure losses across the components 502, 505, 503,
506 plus the pressure losses across the separator 507 and conduit
508 at the flow back rate while maintaining sufficient pressure to
meet the pressure requirement at the inlet to pipeline or
processing facility 504. Again, the natural gas content of the
injected fracture fluid mixture is selected to ensure an adequate
wellhead pressure exists at the desired flow back conditions.
[0087] The flow back equipment configuration in this embodiment is
useful for flow back of hydraulic fracture treatments containing
natural gas where a natural gas pipeline or capture system exists
with little or no capacity for liquids in the processing facility.
This is common at lean or dry gas wells or where the produced
liquid content is low and liquids are separated and captured to
storage on-site.
[0088] According to yet another embodiment and referring to FIG. 6,
the surface flow back equipment 3 is configured to recover a
post-fracturing well stream by separating the well stream into a
gas component, a water component and a liquid oil component, and
wherein the gas component does not have sufficient flow back
pressure to meet processing facility requirements. Like the
embodiment shown in FIG. 5, the flow back equipment includes a
conduit 605 which fluidly couples a wellhead 601 to a sandtrap 603.
Another conduit 606 with a choke 602 fluidly couples the sandtrap
603 to a 3-phase separator 607, which separate the well stream into
a gas component for flow through a gas conduit 608 to a gas
pipeline or gas processing facility 604, a water component for flow
through a water conduit 609 to a water treatment or disposal
facility 610, and a liquid oil component for flow through an oil
conduit 611 to an oil processing or sales facility 612. In this
embodiment , the flow back equipment 3 includes a gas dehydrator
613, a motor 614 and a gas compressor 615 all fluidly coupled to
the gas conduit 608 provide sufficient pressurization of the
recovered gas component to meet the pressure requirements at the
inlet to the gas processing facility 604. The gas dehydrator 613 is
deployed to recover condensing water from the gas stream to avoid
damage to the compressor 615. In the case of liquids-rich gas
production, the dehydrator 613 may be replaced or supplemented by a
natural gas liquids recovery or scrubbing unit (not shown) to
remove those condensing liquids from the gas component stream. The
flowing pressure at the wellhead 601 must be sufficient to overcome
pressure losses across the equipment 602, 605, 603, 606, 607, 608,
the gas dehydrator 613, and the conduit 616 at the flow back rate
while maintaining sufficient pressure to meet the inlet pressure
requirement to compressor 615 driven by motor 614. Compressor 615
is operated to increase the pressure of the injected and native
reservoir gases to meet the pressure requirement at the inlet to
pipeline or capture system 604. Again, the natural gas content of
the injected fracture fluid mixture is selected to ensure an
adequate wellhead pressure exists at the desired flow back
conditions. In this instance, the natural gas added to the
fracturing fluid mixture serves to minimize the compressor 615
pressure load, for example where multiple stages of compression are
not desired. Alternatively, the natural gas content is selected to
only ensure flow back from the reservoir 202 and up the wellbore
201.
[0089] This embodiment is useful for flow back of hydraulic
fracture treatments containing natural gas where a natural gas
pipeline or capture system exists with a high pressure inlet or
where sufficient natural gas cannot be added to the fracturing
fluid and additional pressurization is required to meet the inlet
pressure requirement of the pipeline or processing facility. This
embodiment is also applicable where natural gas is directed to a
high pressure pipeline or a processing facility where it is desired
to reduce the required in-system compression. Further, in those
applications where the hydraulic fracturing treatment requirement
restricts the natural gas content, this additional pressurization
is useful to complete capture of the gaseous well effluent.
[0090] In the embodiments shown in FIGS. 5 and 6, a flare (not
shown) may be included to initiate and stabilize flow prior to
directing recovered gases to the inlet of the pipeline or
facilities processing system.
[0091] The following examples are provided for illustration only
and is not intended to limit the scope of the disclosure or
claims.
EXAMPLE 1
[0092] Using an apparatus such as that of FIG. 1, an example
proposed application is given to illustrate the method of FIG. 3.
The objective is to stimulate a gas bearing reservoir at a depth of
2500 m with a 100 tonnes of proppant using a slick water and
natural gas mixture fracturing treatment then capture the well flow
back effluent to the pipeline. The well has perforations at a depth
of 2510.5 m with 114.3 mm casing, no tubing and a bottom hole
temperature of 90.degree. C. In this example, the gas recovered
during the well flow back following the treatment is to be directed
to a pipeline with an inlet pressure of 1,400 kPa. The pipeline
inlet specification for composition is consistent with the injected
fracturing mixture gas composition containing 95% methane or
better. Overall conditions and requirements of the well for
fracturing and flow back are presented in Table 1.
TABLE-US-00001 TABLE 1 Natural Gas Fracturing and Flow Back Example
Description Well Description Reservoir Depth = 2,500 m Perforations
Depth = 2,510.5 m Reservoir Temperature = 90 C. Reservoir Pressure
= 17,325 kPa Wellbore Description Tubing/Casing O.D. = 114.3 mm
Wall Thickness = 9.65 mm Roughness = 0.0400 mm Fracturing
Conditions Bottom Hole Fracturing Pressure = 45,189 kPa Fracturing
Fluid Slick Water Fracturing Fluid Density 1,000 kg/m3 Well Flow
Back Conditions Bottom Hole Flowing Temperature = 75 C. Wellhead
Flowing Temperature = 12 C. Flow Back Requirements - Equipment
Pipeline Pressure = 1,400 kPa Surface Equipment Pressure Losses =
1,000 kPa Target Entry Pressure Above Pipeline = 200 kPa Minimum
Wellhead Flow Pressure = 2,600 kPa Flow Back Requirements -
Performance Maximum Water Flow Rate = 200 m3/day Target Flow Back
Pressure Drawdown = 60% Bottom Hole Drawdown Pressure = 6,930
kPa
[0093] The Well Description and Wellbore Description information of
Table 1 is extracted from drilling and completion records commonly
compiled for wells during their construction. The Fracturing
Conditions data is typically acquired from information common to
the reservoir and area. Again, Well Flow Back Conditions data are
derived from wells in the area, like wells, computer flow
simulation studies or general experience. The Flow Back
Requirements--Equipment data is based upon the equipment that is to
be applied for the flow back operation and knowledge of the
operating conditions of the capture pipeline and used to determine
the Minimum Wellhead Flow Pressure. In this instance, the Minimum
Wellhead Flow Pressure is the sum of the Pipeline Pressure, the
Surface Equipment Pressure Losses and the Target Entry Pressure
Above Pipeline pressure.
[0094] The equipment is specified with the knowledge that the
injected fracturing gas composition is sufficient for entry into
the pipeline or processing facility without specialized treating.
The Flow Back Requirements--Performance are the controllable
targets set for the flow back operation. In this example, the
Maximum Water Flow Rate is set at 200 m3/day and might be a
constraint set by the capacity of the flow back equipment or simply
the capacity to transport and dispose recovered water. In some
cases a minimum water flow rate may be set in order to ensure flow
back of the well is expedited. Alternatively, a gas flow rate
constraint might be set based upon capacity or requirements of the
pipeline or processing facility. The Target Flow Back Pressure
Drawdown is typically based on the draw down needed to effectively
mobilize and flow fluids from the reservoir during the fracturing
treatment flow back operation. This may be based upon experience,
laboratory flow testing of core samples or computer simulation
studies. In this case a 60% draw down is selected resulting in a
pressure differential between the reservoir and the wellbore of
10,395 kPa at a bottom hole flowing pressure of 6,930 kPa.
[0095] As noted above, FIG. 9 is a diagram illustrating the
determined bottom hole flow pressures and corresponding natural gas
flowing rate from a range of natural gas addition ratios to water
for the example well at the specified conditions. A simulator is
configured to the example conditions and inputs include the target
wellhead flowing pressure of 2,600 kPa with a liquid flowing rate
of 200 m.sup.3/day. Within these constraints the natural gas ratio
is varied and the bottom hole flowing pressure to achieve the
target wellhead flowing pressure is determined. Examination of the
diagram shows bottom hole pressures as high as 27,200 kPa when no
gas is added to as low as 5,025 kPa with gas added at 500
sm.sup.3/m.sup.3 water. For the example well with no gas addition,
the bottom hole fluid pressure far exceeds the reservoir pressure
and flow back without gas lift or swabbing cannot be expected. A
natural gas ratio of at least 55 sm.sup.3/m.sup.3 water is needed
just to balance the flowing pressures and the reservoir pressure.
The effect of flowing frictional pressure losses is seen with the
asymptotic behavior of the bottom hole pressure with increasing
natural gas addition at a constant liquid flow rate; as the natural
gas content is increased, the friction pressure increases reducing
the effectiveness of the commingled fluid density reduction
achieved by adding the natural gas. To achieve the target bottom
hole flowing pressure of 6,930 kPa under these conditions, a
Natural Gas to Water Ratio of approximately 250 sm.sup.3/m.sup.3 is
required. The wellhead flowing pressure is estimated at 2,600 kPa
with a liquid rate of 200 m.sup.3/day, a gas rate of 50,000
sm.sup.3/day at a bottom hole flow pressure of 6,930 kPa and meets
the target flow back performance requirements.
[0096] FIG. 10 is a diagram illustrating the pressure and density
profile within the example wellbore at the Natural Gas to Water
Ratio of 250 sm.sup.3/m.sup.3 where the vertical axis is the depth
within the wellbore, the top horizontal axis the flowing pressure
at depth within the wellbore and the lower horizontal axis the
density of the flowing commingled natural gas and water within the
wellbore at depth. The commingled fluid density ranges from 115
kg/m.sup.3 at surface to 218 kg/m.sup.3 at bottom hole conditions
implying a hydrostatic pressure of approximately 4,100 kPa. The
differences between pressure that would result from the commingled
fluid density and the density profile are those resulting from
flowing frictional losses determined in this instance at about 230
kPa. The flowing pressure profile plot at the Natural Gas to Water
Ratio of 250 sm.sup.3/m.sup.3 shows the target bottom hole flowing
pressure of 6,930 kPa at the depth of 2510.5 m and the target
wellhead flowing pressure of 2,600 kPa. In this manner, the minimum
natural gas content of the flow back stream has been selected.
[0097] The selected natural gas content is then applied to the
hydraulic fracturing treatment design resulting in the fracturing
injection schedule of Table 2. The design of the hydraulic fracture
treatment may be completed based upon known performance and
requirements for the reservoir or may be based upon a formal
engineering design utilizing a hydraulic fracture simulator. The
resulting treatment places 100 tonnes of proppant utilizing 128
m.sup.3 of water with 31,990 m.sup.3 of natural gas to create a
total fracturing fluid volume of 230 m.sup.3. This reduces the
water placed into the formation by almost 45% and with that
significantly reduces the surface water handling capacity, time and
requirement. In this instance the fracturing schedule specifies
natural gas is added to the fracturing fluid at the selected ratio
of 250 sm.sup.3 of natural gas per m.sup.3 of water. In applying
the selected natural gas ratio to the fracturing treatment it is
presumed that the reservoir is known to contain only dry natural
gas without native liquids; water or condensates. Should the
reservoir be known to potentially contain or produce native
liquids, the natural gas added ratio could be increased to ensure a
sufficient wellhead flowing pressure exists with these additional
liquids in the flow back stream. A flow back sensitivity
investigation around additional native liquids flow can be applied
to determine the optimum natural gas added increase, if required.
Alternatively, reservoirs can contribute native natural gas to the
flow back further enhancing flow back performance. In that case,
less than the selected minimum amount of natural gas may suffice
for a given reservoir. Though not illustrated in this example, the
applied natural gas content can also be varied throughout the
fracturing treatment as required to best meet the fracture
treatment or flow back requirements. For instance, a pre-pad volume
containing only natural gas may be injected, or a proppant stage or
stages without natural gas may be applied.
TABLE-US-00002 TABLE 2 Natural Gas and Slick Water Fracturing
Treatment Program NATURAL GAS WITH SLICK WATER FRACTURE TREATMENT
Depth = 2510.5 m FG = 18 kPa/m Tubing = 114.3 mm Rate = 5.0 m3/min
Capacity = 0.007417 m3/m WHIP = 48.4 MPa Proppant tonne 100.0 20/40
mesh sand Hole Volume 18.62 m3 Proppant Total 100.0 tonne
Underflush 0.5 m3 Proppant Density 2650 kg/m3 Bottom Hole
Fracturing Pressure = 45.19 MPa Total Rate 5.0 m3/min Bottom Hole
Temperature = 90 deg C. Water Rate 2.8 m3/min Natural Gas Vol
Factor = 312.33 sm3/m3 space NG Rate 695 sm3/min Natural Gas to
Water Ratio = 250 sm3/m3 water Gas Factor 45% Slick Water Proppant
Cumula- Blender Natural Gas Slurry Slick tive Concen- Cumula-
Downhole Conditions Blender Water Slick Slick tration Cumula- tive
Total Conc @ Gas Stage Rate Rate Water Water (kgSA/ Proppant tive
Nat'l Nat'l Nat'l Rate Perfs Frac- Descrip- (m3/ (m3/ Volume Volume
m3 Stage Proppant Gas Rate Gas Stage Gas (m3/ (kgSA/ tion tion min)
min) (m3) (m3) liq) (tonne) (tonne) (sm3/min) (sm3) (sm3) min) m3)
(--) Fill Hole 0.50 0.5 10.3 125 2588 2588 0.90 0.445 Pad 2.78 2.78
14.0 24.3 695 3506 6094 5.00 0 0.445 Start 2.78 2.41 15.0 39.3 720
10.8 10.8 604 3756 9850 5.00 400 0.445 20/40 sand Increase 2.78
2.31 20.0 59.3 960 19.2 30.0 579 5009 14859 5.00 533 0.445 concen-
tration Increase 2.78 2.22 25.0 84.3 1200 30.0 60.0 555 6261 21119
5.00 666 0.445 concen- tration Increase 2.78 2.22 33.4 117.7 1200
40.0 100.0 555 8352 29471 5.00 666 0.445 concen- tration Flush 2.78
2.78 10.1 127.7 695 2518 31990 5.00 0 0.445 treat- ment Volume
Requirment Treatment Bottoms Total Fluid Natural Gas 31,990 sm3
53.3 m3 liq 5 m3 58.3 m3 Slick Water 127.7 m3 15 m3 142.7 m3
[0098] With a fracturing treatment program developed to meet the
application needs, the equipment and required materials are
mobilized to the well site for completion of the fracturing
treatment and flow back operations using natural gas and slick
water. The equipment is spotted and rigged in to complete the
fracturing treatment and materials loaded. In this example, a LNG
based natural gas source and preparation is applied; however any
natural gas source and preparation method may be used. Similarly,
the well servicing preparing and pressurizing equipment shown is
that of common blender and fracturing fluid pumpers, though any
suitable configuration can be applied to prepare and pressure the
liquid based well servicing stream. Upon rigging and loading the
equipment, the pre-treatment preparation requirements for
fracturing with a natural gas and liquid mixture are completed
which may include a hazards orientation, pressure test, safety
meetings and detailed treatment requirement discussions. Upon
completing all pre-treatment requirements, fracture pumping
operations are begun according to the example Natural Gas and Slick
Water Fracturing Treatment Program of Table 2. The liquid, proppant
and chemicals are mixed and pressured with the equipment apparatus
like that displayed in FIG. 1, items 4 while the natural gas is
pressured and prepared with the equipment apparatus like that of
items 22. These prepared streams are then commingled at the mixer
30 and injected into the well as a natural gas and water mixture
which may or may not contain fluid modifying chemicals or
proppants. The mixture then travels down the wellbore 201 of FIG.
2a and into the reservoir 202 to create the underground fractures
203. Upon pumping the hydraulic fracture treatment either as
specified by Table 2, or as adapted to meet the well response
during the fracturing treatment, injection is stopped and the
surface equipment secured.
[0099] At a time deemed suitable for the well being fractured, flow
from the well is initiated to remove the injected fracturing fluids
in order to bring the well on production. Pressure at the wellhead
32 is released to the flow back apparatus items 3 FIG. 1 to induce
flow within the wellbore 201 FIG. 2b, the created fractures 203 and
the invaded zone fluids 207 of injected fracturing liquid, injected
natural gas and native reservoir fluids. The resulting well stream
flow at surface is directed through the choke 5 to the phase
separator 36 where gases, liquids and solids can be separated.
Produced solids may include the fracturing proppant and accumulate
within the separator vessel 36 and removed as needed for space
considerations. Injected and native liquids are accumulated within
the separator 36 and drained into a storage vessel 38. Injected and
reservoir based natural gas are directed from the separator vessel
36 to the gas pipeline 40 for capture and resale. Optionally,
though not preferentially, flare 42 may be utilized to initiate
flow prior to directing natural gas to the pipeline. This may be
necessary to stabilize the flow while adjusting the choke to
achieve the correct flowing inlet pressure through the surface
equipment and into the pipeline. As illustrated in this example,
with natural gas injection as part of the fracturing fluid at a
sufficient ratio and composition, directing the natural gas to the
pipeline or processing facility at sufficient pressure is
accomplished and fracture clean-up without the need to vent or
flare, or with substantial reductions of venting or flaring, can be
achieved. Natural gas within the fracturing fluid permits capture
and sale of injected and native reservoir natural gas.
[0100] Volume replacement of liquids for hydraulic fracturing is
also highly beneficial to minimize recovery liquids handling
requirements, reduce flow back time and for improved well
performance. In this example, a water reduction of 45% is
accomplished by placing a fracture fluid volume of 230 m.sup.3
while only utilizing 128 m.sup.3 of water. In this example,
presuming complete water recovery, a liquid flow back rate of 200
m.sup.3/day is anticipated such that the fracturing liquid can be
recovered in less than 24 hours. Without added natural gas, the
reservoir pressure is seen to be insufficient to flow back water
without an assist such as swabbing or gas-lift. These assisting
techniques will take time to deploy and result in flow back times
that may extend to days rather than hours. This will increase the
cost and complexity of the flow back operation. Additionally, with
less water placed into the reservoir itself, improved flow
performance is expected. Less water in the reservoir results in
less water removal needed to achieve a given production target.
EXAMPLE 2
[0101] Consider for example replacement of a hydraulic fracture
treatment on a well requiring a slick water fracturing treatment to
3,000 m.sup.3. For the slick water fracturing treatment the water
is collected for injection in an open pit replacing the otherwise
required 40 water storage tanks. Following injection and fracture
closure, flow back operations begin where it is presumed the
flowing pressure is just sufficient to permit flow at back pressure
near atmospheric. With expectation for normal post-treatment liquid
recovery, approximately 35% of the injected water would be
recovered to a volume of just over 1,000 m.sup.3. With the near
atmospheric surface flowing pressure, insufficient flowing pressure
exists to direct flow through a separator and all flow is
necessarily directed by piping to an open pit. The water is
collected into the pit while gases are vented to atmosphere or when
possible ignited over the pit. At a presumed maximum attainable
recovery rate of 100 m.sup.3/day, flow back is completed over an
estimated 10 day period. When flow back is deemed complete the
1,000 m.sup.3 of recovered water, contaminated with fracturing
chemicals and dissolved formation products, is withdrawn from the
pit and disposed, or preferentially treated to allow use in a
subsequent fracturing operation. Applying natural gas to a
hydrocarbon based well servicing fluid in replacement of the slick
water can improve the flow back operation as follows: First,
presuming a selected gas added ratio to the hydrocarbon based
fracturing fluid at 450 sm.sup.3/m.sup.3 hydrocarbon liquid, a
3,000 m3 fracture volume requires only 1,430 m.sup.3 of hydrocarbon
fracturing liquid with the remaining 1,570 m.sup.3 comprised of
natural gas. The liquid is collected and stored in approximately 18
liquid storage tanks in preparation for the treatment. Following
injection and fracture closure, the natural gas hydrocarbon mixture
will exhibit a reduced flow back density in the order of 325
kg/m.sup.3 such that the flow back pressure at surface will be in
excess of 5,000 kPa. With a normal expectation for liquids recovery
from an energized hydrocarbon fracturing treatment, approximately
75% of the injected oil would be recovered to a volume of
approximately 1,000 m.sup.3. With sufficient surface flowing
pressure, the flow back can be directed through a phase separator
and the natural gas stream diverted to any available pipeline or
processing facility. With additional flowing pressure available,
the liquid recovery rate can be increased to a presumed 200
m.sup.3/day and the flow back completed over a 5 day period. The
hydrocarbon fracturing liquid recovered in the phase separator is
directed to the recovery tanks for handling towards processing for
sale or re-use. In this or a similar manner, by creating and
injecting a selected hydrocarbon fracturing base liquid containing
a selected natural gas composition and content, a waterless and
environmentally closed fracturing system can be created and
applied.
* * * * *