Note: Descriptions are shown in the official language in which they were submitted.
METHOD OF PRODUCING HYDROCARBON FLUIDS
FROM CASING
BACKGROUND OF THE INVENTION
[0001] This section is intended to introduce selected aspects of the art,
which may be
associated with various embodiments of the present disclosure. This discussion
is believed to
assist in providing a framework to facilitate a better understanding of
particular aspects of the
present disclosure. Accordingly, it should be understood that this section
should be read in
this light, and not necessarily as admissions of prior art.
Field of the Invention
[0002] The present disclosure relates to the field of hydrocarbon recovery
operations.
More specifically, the present invention relates to a method of producing
hydrocarbon fluids
from a wellbore. Further still, the invention relates to the production of
fluids through the
production casing without need of production tubing.
Discussion of Technology
[0003] In the drilling of oil and gas wells, a wellbore is formed using a
drill bit that is
urged downwardly at a lower end of a drill string. The drill bit is rotated
while force is
applied through the drill string and against the rock face of the formation
being drilled. After
drilling to a predetermined depth, the drill string and bit are removed and
the wellbore is
lined with a string of casing.
[0004] In completing a wellbore, it is common for the drilling company to
place a series
of casing strings having progressively smaller outer diameters into the
wellbore. These
include a string of surface casing, at least one intermediate string of
casing, and a production
casing. The process of drilling and then cementing progressively smaller
strings of casing is
repeated until the well has reached total depth. In some instances, the final
string of casing
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is a liner, that is, a string of casing that is not tied back to the surface.
The final string of
casing, referred to as a production casing, is also typically cemented into
place.
[0005] To prepare the wellbore for the production of hydrocarbon fluids, a
string of
tubing is run into the casing. A packer is optionally set at a lower end of
the tubing to seal
an annular area formed between the tubing and the surrounding strings of
casing. The tubing
then becomes a string of production pipe through which hydrocarbon fluids flow
from the
reservoir and up to the surface.
[0006] When a hydrocarbon-producing well is first placed on-line, the
formation
pressure is typically capable of driving produced fluids up the wellbore and
to the surface.
Liquid fluids will travel up to the surface through the production tubing,
primarily in the
form of droplets entrained within gas flow. The fluids are received at the
wellhead without
the assistance of so-called artificial lift equipment.
[0007] During the life of the well, the natural reservoir pressure will
decrease as gases
and liquids are removed from the formation. As the natural downhole pressure
of the well
decreases, the gas velocity moving up the well drops below a so-called
critical flow velocity.
In addition, the hydrostatic head of fluids in the wellbore will work against
the formation
pressure and block the flow of in situ gas into the wellbore. The result is
that formation
pressure is no longer able, on its own, to force fluids from the formation and
up the
production tubing in commercially viable quantities.
[0008] In response, various remedial measures have been taken by operators.
One option
is to simply reduce the inner diameter of the production tubing a small
amount, thereby
increasing pressure differential. Another option is to monitor tubing pressure
through the
use of pressure gauges and orifice plates at the surface. U.S. Patent No.
5,636,693 entitled
"Gas Well Tubing Flow Rate Control," issued in 1997, disclosed the use of an
orifice plate
and a differential pressure controller at the surface for managing natural
wellbore flow up
more than one flow conduit.
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[0009] Another technique frequently used by operators is the reciprocation
of a downhole
pump. Such pumps include a first valve that is attached to the bottom of the
tubing string.
Such a valve is referred to as a standing valve. Such pumps also include a
second valve that
is connected to a lower end of a string of sucker rods. Such a valve is
referred to as a traveling
valve.
[0010] In operation, the sucker rods are moved up and down within the
production tubing
in response to mechanical movement of a pumping unit at the surface. Various
types of
pumping units are known, with modern pumping units being fitted with rod pump
controllers
that control pump times and stroke speeds. The sucker rods move the traveling
valve through
upstrokes and down strokes, where fluids are drawn into the traveling valve on
the down
stroke, and then lifted up the production tubing on the upstroke. At the same
time, the
standing valve receives fluids from the surrounding formation during the
traveling valve's
upstroke, and is sealed in response to fluid pressure during the traveling
valve's down stroke.
[0011] The rod string, the traveling valve and the seated valve may
together be referred
to as a "sucker rod pump," or a "rod-drawn pump." The sucker rod pump along
with the
pumping unit at the surface and the production tubing in the wellbore together
comprise a
fluid pumping system.
[0012] As noted, the traveling valve portion of the pump is connected to
the end of the
sucker rod string. Typically, an upper portion of the traveling valve is
threadedly connected
to a plunger, which in turn is connected at the lower end of the sucker rod
string. At the same
time, the standing valve portion of the pump resides along an inner diameter
of the production
tubing, below the traveling valve. Specifically, the standing valve is
connected to a barrel
having a seal assembly.
[0013] The standing valve is typically installed by attaching it to a
running tool at the lower
end of the traveling valve. This means that the standing valve portion is run
into the wellbore
with the traveling valve at the end of the rod string. The standing valve is
lowered until it
reaches a constriction in the production tubing, known as a seating nipple.
Upon reaching a
point of frictional engagement with the seating nipple, the weight of the
traveling valve and
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rod string are released from the surface, down onto the standing valve,
causing the standing
valve to frictionally engage with the seat.
[0014] Many wells today are completed with a horizontal section. This means
the well
will have a vertical section, a horizontal section, and a transitional section
there between. The
horizontal section may be in excess of one mile in length, and sometimes in
excess of two
miles in length. In such wells, it is not practical for the operator to place
the rod string and
valves along the horizontal wellbore section. This is primarily due to the
difficulty in running
production tubing and a rod string across the transitional section (or heel)
of the wellbore.
Accordingly, it is standard practice to run the production tubing only down to
the bottom of
the vertical section (or near the top of the pay zone), or possibly partially
down the transitional
section. In this way, the rod string may reciprocate the traveling valve
without incurring
friction against a "dog leg" in the production tubing.
[0015] During the first year or two of production, the reservoir pressure
will drive
production fluids into the horizontal section of the wellbore and up to the
level of the rod-
drawn valves. However, over time the reservoir pressure will diminish, leaving
the liquids
along the horizontal section of the well below the level of the production
tubing and valves.
[0016] Another problem encountered with the standard completion arrangement
relates
to so-called slug flow. The typical behavior of horizontal wells is to create
slugs of fluid,
followed by a "blow down" period of gas. During a first phase, the horizontal
well is filling
with liquid, hopefully up to a level of the pump intake. Since the liquid
weighs more than
the gas, the gas may become trapped in the horizontal leg, typically at the
higher elevation
points. Once the traps of gas are filled, it begins to escape, pushing the
liquid ahead of it.
The gas will "exhaust" fairly quickly, causing a slug of liquids to move
towards the pump
intake.
[0017] When the gas being held back in "high spots" of the horizontal
portion of the
wellbore begins to expand, it first pushes liquids from the remainder of the
horizontal
wellbore up into the vertical section where the pump is located. The normal
pump-off
controller will correctly calculate high pump fillage, and start running the
pumping unit
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incrementally, i.e., with each cycle, faster until reaching its maximum
allowed speed which
has been pre-set in the algorithm. When the gas arrives, the pump-off
controller will
correctly calculate poor pump fillage, and decrease speed very rapidly, e.g.,
with each cycle,
as poor pump fillage is detrimental to the mechanical life of the rod pumping
system. The
controller may drop the pumping speed all the way down to a pre-set minimum
pumping
speed. The result can be an extreme amount of cycling between maximum and
minimum
speed set-points for the pump-off controller, never converging on an ideal
speed. Even
during the first year of production, this cycle may occur as often as every 15
minutes.
[0018] The above problems may be reduced if not eliminated by placing the
rod string and
valves along the horizontal leg. Therefore, a need exists for a procedure by
which hydrocarbon
fluids may be pumped directly from the horizontal section of a wellbore.
Further, a need exists
for a method of operating a rod-drawn pump wherein the rod string and
connected traveling
valve reside at a selected location along the horizontal section of a
wellbore.
SUMMARY OF THE INVENTION
[0019] A method of producing hydrocarbon fluids from a wellbore is provided
herein. In
one aspect, the method first comprises providing a wellbore. The wellbore has
been completed
to have a horizontal leg, with a string of casing having been placed along the
horizontal leg.
[0020] The casing may be solid joints of production casing that have been
perforated.
Alternatively, the casing may be slotted tubular bodies. Examples of slotted
tubular bodies are
joints of sand screen and joints of slotted liner. In any instance, the
wellbore is exposed to
reservoir fluids and pressure.
[0021] The method also includes running a fluid pumping system into the
wellbore. The
fluid pumping system generally comprises:
a sucker rod string,
a traveling valve residing at a lower end of the sucker rod string, and
a standing valve releasably connected to a lower end of the traveling valve.
Date Recue/Date Received 2020-08-19
[0022] The traveling valve and the standing valve are run into the wellbore
together at the
end of the rod string. The valves are run down the vertical section, across a
transitional section,
and then into the horizontal leg of the wellbore to a selected location (or
"depth"). Beneficially,
the standing valve is releasably connected to a lower end of the traveling
valve.
[0023] The method additionally comprises landing the standing valve into a
seating nipple
along the horizontal section of the wellbore. Specifically, the seating nipple
resides in series
along the casing. The seating nipple may be a specially modified seating
nipple placed along
the casing above the perforations (or above slotted tubular bodies). In this
instance, the seating
nipple will have a reduced inner diameter so that a standard pump barrel can
land in the seating
nipple.
[0024] The method further includes releasing the traveling valve from the
standing valve.
This is done while the fluid pumping system is in the wellbore, i.e., without
pulling the rod
string. Some compressive force is required to be applied to the rod string
from the surface to
urge the standing valve to release the engagement pin. This may be acquired
simply by
dropping weight from the surface.
[0025] In operation, once the seating nipple is landed, a second
compressive force is
applied to the rod string, which is transmitted to the traveling valve and to
the releasable
connection. This causes the releasable connection to open, allowing the rod
string and
traveling valve to be released from the standing valve.
[0026] The method additionally includes mechanically or operatively
connecting a top end
of the rod string to a polished rod. The polished rod is part of a pumping
unit residing at the
surface. In this way, the rod string extends from the polished rod, down into
the vertical section
of the wellbore, across the transitional section, and into the production
casing residing along
the horizontal section of the wellbore.
[0027] It is understood that the operator will manually adjust a location
at which a harness
and clamps supporting the polished rod is secured to the polished rod itself.
This ensures that
the traveling valve will be appropriately spaced above the standing valve.
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[0028] The polished rod is part of a pumping unit which resides at the
surface. The
pumping unit may be either a mechanical pumping unit such as a so-called rod
beam (or
sometimes "rocking beam") unit. Alternatively, the pumping unit may be a
linear pumping
unit that uses hydraulic fluid or pneumatic fluid to cyclically act against a
piston within a
cylinder. In either instance, the pumping unit will use clamps and a harness
to secure the
pumping unit to the polished rod and to produce reciprocating motion of the
downhole
traveling valve above the standing valve.
[0029] Thereafter, the method includes operating the pumping unit at a
surface to produce
hydrocarbon fluids from the production casing. Operating the pumping unit
causes the sucker
rod string and connected traveling valve to reciprocate within the wellbore.
Note that no
production tubing need be placed within the wellbore.
Brief Description of the Drawings
[0030] So that the manner in which the present inventions can be better
understood, certain
illustrations, charts and/or flow charts are appended hereto. It is to be
noted, however, that the
drawings illustrate only selected embodiments of the inventions and are
therefore not to be
considered limiting of scope, for the inventions may admit to other equally
effective
embodiments and applications.
[0031] Figure 1 is a side view of an illustrative wellbore. In this case,
the wellbore is
completed horizontally. A traveling valve is shown at a lower end of a sucker
rod string while
a standing valve is schematically shown in the production casing.
[0032] Figures 2A and 2B represent a single flow chart showing steps for a
method of
producing hydrocarbon fluids from a wellbore, in one embodiment.
[0033] Figure 3 is a perspective view of standing valve puller as may be
used for releasably
connecting a traveling valve to a standing valve in a wellbore. In this view,
an engagement
pin extends into the standing valve puller.
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Date Recue/Date Received 2020-08-19
[0034] Figure 4 is a side view of the holding arm component of the standing
valve puller
of Figure 3. Here, the arms of the holding arm component have been pivoted
into their open
position, ready to receive an engagement pin.
[0035] Figure 5 is an exploded view of the standing valve puller of Figure
1 along with the
engagement pin. Internal components of the standing valve puller are now
visible in exploded-
apart relation.
[0036] Figure 6A is a side view of the standing valve puller and the
engagement pin of
Figure 5. The standing valve puller is in its "latched" position, meaning that
arms of a holding
arm component have pivoted inwardly to engage a stem of the engagement pin.
[0037] Figure 6B is a cross-sectional view of the standing valve puller and
the engagement
pin, taken across Line B-B of Figure 6A. The standing valve puller is again in
its latched
position, enabling the engagement pin to pull the standing valve puller and
connected standing
valve (not shown) from a wellbore.
[0038] Figure 7A is a perspective view of the standing valve puller of
Figure 5.
Components of the standing valve puller are exploded apart. Here, the
engagement pin is not
shown.
[0039] Figure 7B is a side view of the exploded-apart components of the
standing valve
puller of Figure 7A. Of interest, it can be seen that the arms of the holding
arm component are
independent (not connected) pieces.
[0040] Figure 8 is another cross-sectional view of the standing valve
puller of Figure 5.
Here, the standing valve puller is in its latched position.
[0041] Figure 9A is a perspective view of the holding arm component. Here,
both arms of
the holding arm component are shown, in side-by-side arrangement. The holding
arm
component is in the latched position.
[0042] Figure 9B is another perspective view of the holding arm component.
Here, the
arms of the holding arm component are again in their latched position.
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[0043] Figure 10 is a side view of the holding arm component of Figure 9B.
Here, the
arms of the holding arm component have been pivoted into their open position,
ready to receive
an engagement pin. An engagement pin is shown above the holding arm component.
[0044] Figure 11A is a cross-sectional view of a wellbore, with a positive
displacement
pump being run into the horizontal section. A traveling valve and a standing
valve are shown
representing the positive displacement pump, with an engagement pin and a
standing valve
puller connecting the two valves.
[0045] Figure 11B is another cross-sectional view of the wellbore of Figure
11A. The
standing valve has been landed into a seating nipple along the production
casing.
[0046] Figure 11C shows a compressive force being applied to the standing
valve puller,
through the traveling valve. The purpose is to cause the latching arms in the
standing valve
puller to release.
[0047] Figure 11D shows the traveling valve and connected engagement pin
having been
released from the standing valve puller. The traveling valve has been
repositioned in the
wellbore above the standing valve.
[0048] Figure 11E shows the traveling valve being lifted within the
wellbore by a sucker
rod string. Fluid pumping operations have begun.
[0049] Figure 11F shows the traveling valve being lowered within the
wellbore by the
sucker rod string. This is part of the pump cycle for the positive
displacement pump.
[0050] Figure 12 is a cross-sectional view of a wellbore having received a
positive
displacement pump. In this view, a sand screen is placed below the standing
valve, while a
modified seating nipple holds the standing valve in place.
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Detailed Description of Certain Embodiments
Definitions
[0051] For purposes of the present application, it will be understood that
the term
"hydrocarbon" refers to an organic compound that includes primarily, if not
exclusively, the
elements hydrogen and carbon. Examples of hydrocarbon-containing materials
include any
form of oil, natural gas, coal, and bitumen that can be used as a fuel or
upgraded into a fuel.
Hydrocarbons may include other elements, such as, but not limited to,
halogens, metallic
elements, nitrogen, oxygen, and/or sulfur.
[0052] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures
of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may
include a
hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation
conditions, at
processing conditions, or at ambient conditions. Hydrocarbon fluids may
include, for example,
oil, natural gas, condensate, coal bed methane, shale oil, shale gas, and
other hydrocarbons that
are in a gaseous or liquid state.
[0053] As used herein, the term "fluid" refers to gases, liquids, and
combinations of gases
and liquids, as well as to combinations of gases and fine solids, and
combinations of liquids
and fine solids.
[0054] As used herein, the terms "produced fluids," "reservoir fluids" and
"production
fluids" refer to liquids and/or gases removed from a subsurface formation,
including, for
example, a hydrocarbon reservoir, a shale formation or an organic-rich rock
formation.
Produced fluids may include both hydrocarbon fluids and non-hydrocarbon
fluids. Production
fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale
oil, synthesis gas, a
pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water
(including steam).
[0055] As used herein, the term "wellbore fluids" means water, hydrocarbon
fluids,
formation fluids, or any other fluids that may be within a string of
production tubing during a
production operation.
Date Recue/Date Received 2020-08-19
[0056] As used herein, the term "subsurface" refers to geologic strata
occurring below the
earth's surface.
[0057] The term "subsurface interval" refers to a formation or a portion of
a formation
wherein formation fluids may reside. The fluids may be, for example,
hydrocarbon liquids,
hydrocarbon gases, aqueous fluids, or combinations thereof.
[0058] The terms "zone" or "zone of interest" refer to a portion of a
formation containing
hydrocarbons. Sometimes, the terms "target zone," "pay zone," or "interval"
may be used.
[0059] As used herein, the term "formation" refers to any definable
subsurface region
regardless of size. The formation may contain one or more hydrocarbon-
containing layers,
one or more non-hydrocarbon containing layers, an overburden, and/or an
underburden of any
geologic formation. A formation can refer to a single set of related geologic
strata of a specific
rock type, or to a set of geologic strata of different rock types that
contribute to or are
encountered in, for example, without limitation, (i) the creation, generation
and/or entrapment
of hydrocarbons or minerals, and (ii) the execution of processes used to
extract hydrocarbons
or minerals from the subsurface.
[0060] As used herein, the term "wellbore" refers to a hole in the
subsurface made by
drilling or insertion of a conduit into the subsurface. A wellbore may have a
substantially
circular cross section, or other cross-sectional shape. As used herein, the
term "well," when
referring to an opening in the formation, may be used interchangeably with the
term
c`wellbore."
[0061] The terms "tubular" or "tubular member" refer to any pipe, such as a
joint of casing,
a portion of a liner, a joint of tubing, a pup joint, or coiled tubing. The
terms "production
tubing" or "tubing joints" refer to any string of pipe through which reservoir
fluids are
produced.
Description of Specific Embodiments
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Date Recue/Date Received 2020-08-19
[0062] Figure 1 is a side view of a wellbore 100. The wellbore 100 has been
formed for
the purpose of producing hydrocarbon fluids up to a surface 105 in
commercially viable
quantities. The wellbore 100 is formed through an earth subsurface 110, and
down to a
formation 150 where hydrocarbon fluids are found. The formation 150 may be
referred to as
a "pay zone."
[0063] Production fluids flow into the wellbore 100 through openings
provided along the
completion. Such openings may be perforations, or optionally, may be formed
with sand
screens, ICDs, a gravel pack, an open hole, or other completion type. In the
illustrative
arrangement of Figure 1, the end completion is shown with slotted liner 180.
[0064] Fluids are produced to the surface 105 through the use of a pumping
unit 120. The
pumping unit 120 is disposed over a well head 125 which receives the produced
fluids
including hydrocarbon liquids at the surface 105. Typically, the well 100 will
produce
primarily hydrocarbon fluids that are incompressible at surface conditions,
e.g., oil and water,
but there will also be compressible hydrocarbon fluids such as methane, ethane
and steam. So-
called impurities such as hydrogen sulfide and oxygen may also be present
which will need to
be separated out after production to meet pipeline specifications.
[0065] In the example shown in Figure 1, the pumping unit 120 is a
mechanical beam
pump. Of course, it is understood that the pumping unit 120 may alternatively
be a pneumatic
or hydraulic pumping unit. The pumping unit 120 moves a polished rod 122 up
and down at
the surface 105, through the well head 125. The polished rod 122, in turn, is
connected to a
rod string 124 that extends down through the earth subsurface 110.
[0066] The illustrative wellbore 100 of Figure 1 has been completed
horizontally. This
means the wellbore 100 has a vertical section 142 and a horizontal section
146. A transition
section 144, sometimes referred to as a heel or a "build section" or a
"transitional section" is
formed between the vertical 142 and horizontal 146 sections. The horizontal
section 146
extends along the pay zone 150, and terminates at a toe 148.
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[0067] It is observed that advances in drilling technology have enabled oil
and gas
operators to "kick-off" and steer wellbore trajectories from a generally
vertical orientation to
a generally horizontal orientation. The horizontal "leg" of wellbores
completed in North
America now often exceeds a length of one mile, and sometimes two or even
three miles. This
significantly multiplies the wellbore exposure to the pay zone 150.
[0068] It is also noted that horizontal wellbores are frequently formed
along the deposition
plane of a formation. Formation fracturing operations are then conducted in
stages, with
fractures generally propagating vertically into the pay zone. The ability to
replicate multiple
vertical completions along a single horizontal wellbore is what has made the
pursuit of
hydrocarbon reserves from unconventional reservoirs, and particularly shales,
economically
viable within relatively recent times.
[0069] The wellbore 100 is completed using strings of casing. In the
arrangement of
Figure 1, a string of surface casing 128 is shown. In addition, an
intermediate casing string
125 is provided. It is understood that most modern well completions may
include at least one,
and typically two or three, intermediate casing strings 125. Each casing
string 128, 125 will
have a progressively smaller inner diameter. The casing strings are cemented
into place along
most, if not all, of the wellbore completion.
[0070] The wellbore 100 is also completed with a string of production
casing 126. The
production casing 126 extends out along the pay zone 150, passing through the
transitional
section 144 and to the end 148 of the horizontal section 146. The end of the
production casing
represents the perforated portion or sand screen 180.
[0071] It is observed that the wellbore 100 does not include a string of
production tubing.
Production tubing is a standard part of any fluid pumping system. The
production tubing
receives the rod string and connected traveling valve. The production tubing
also receives and
secures a standing valve. The two valves are typically landed in the build
section 144,
preferably as deep as possible. However, in the current disclosure no
production tubing is
required. Instead, the rod string 124 reciprocates within the casing strings
128, 125, 126.
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[0072] Primarily liquids are pumped through the production casing 126 and
to the surface
105, and released through line 132. Primarily gas is produced through the
production casing
126 and is released through line 134.
[0073] At the end of the rod string 124 are two valves. These represent a
traveling valve
162 and a standing valve 164. As discussed above, the traveling valve 162 is
connected at the
end of the rod string 124 (usually by means of a plunger) and moves with the
rod string 124,
while the standing valve 164 is frictionally and releasably secured to a
seating nipple 166
(usually by means of a barrel and circumferential seal member). In the novel
disclosure herein,
the seating nipple 166 is placed in series with the production casing 126.
[0074] In the view of Figure 1, the valves 162, 164 are placed above a
packer 170 and
sealed against a surrounding joint of production casing. The packer 170, in
turn, is connected
to the sand screen 180 and an internal tubular base pipe 175 of. The sand
screen 180 (with the
base pipe 175) is run into the wellbore 100 ahead of the packer 170.
Beneficially, the sand
screen 180 filters solids and fines that enter the wellbore 100 with
production fluids, directing
the filtered production fluids through a central bore 175 of the packer 170
and into the
production casing 126.
[0075] It is desirable to be able to pump fluids up the wellbore 100
without pulling the rod
string 124 and the traveling valve 162. In addition, it is desirable to pump
fluids up the casing
126 without the need of production tubing. Accordingly, a novel method of
producing
hydrocarbon fluids from the casing is provided herein.
[0076] Figures 2A and 2B represent a single flow chart showing steps for a
method 200
of producing fluids from the casing string of a wellbore, in one embodiment.
In one aspect,
the method 200 first comprises providing a wellbore. This step is shown at Box
210. The
wellbore has been completed to have a horizontal leg. A string of production
casing has been
placed along the horizontal leg.
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[0077] It is noted that the step of Box 210 for "providing" a wellbore may
include a service
company contracting to service the wellbore. Alternatively, providing the
wellbore may mean
that an operator produces from the wellbore and services the wellbore itself.
[0078] The method 200 also includes running a string of casing into the
wellbore. This is
provided at Box 220. The casing may be a string of production casing that uses
joints of
standard steel pipe. Multiple joints may be threadedly attached, in series, so
that the pipe
extends thousands of feet along the horizontal section of the wellbore.
[0079] Alternatively, the casing may be one or a few short joints of
casing, followed by
numerous joints of slotted tubular bodies. The slotted tubular bodies may be
joints of slotted
liner. This is seen at Box 230. Where slotted tubular bodies are placed along
the horizontal
section, the operator may also run a packer into the wellbore. The packer may
be placed in
series between the production casing and the slotted tubular bodies. Placement
of such a packer
is shown at 1230 in Figure 12.
[0080] In one aspect, the packer is run into the wellbore separate from the
casing using a
working string. The working string is preferably a coiled tubing string. The
packer is run
down to a selected location along the production casing. The packer is then
set within the
wellbore, preferably along the lowest joint of production casing. Placement of
such a packer
is shown at 170 in Figure I.
[0081] In a more preferred aspect, the packer is threadedly connected to a
sand screen or
to a production casing joint above the sand screen. The sand screen will have
a filter medium
around a slotted base pipe. In this instance, the sand screen is run into the
wellbore with the
production casing, ahead of the packer. Beneficially, the sand screen filters
solids and fines
that enter the wellbore with production fluids, directing the filtered
production fluids through
a central bore of the packer and into the production casing above the packer.
[0082] In one aspect, the packer is equipped with a J-slot mechanism. The J-
slot
mechanism allows the packer to be set through a cycling mechanism, wherein the
cycling takes
place in response to compressive force applied by the working string through
pins, or tabs.
Date Recue/Date Received 2020-08-19
Preferably, the compressive force is a mechanical force applied by letting the
weight down off
of the working string. Thus, in one aspect the method 200 includes operating a
J-slot
mechanism to set the packer in the wellbore. Alternatively, the packer may be
set using a
wireline.
[0083] Once the packer is in place, the working string is disconnected and
is pulled from
the wellbore. Thus, the method 200 further includes disconnecting the working
string from
the packer. Additionally, the method 200 includes pulling the working string
from the
wellbore.
[0084] The method 200 next comprises running a fluid pumping system into
the wellbore.
This is shown in Figure 2A at Box 240. The pumping system generally comprises:
a sucker rod string,
a traveling valve residing at a lower end of the sucker rod string, and
a standing valve releasably connected to a lower end of the traveling valve.
[0085] The traveling valve, the seated valve and the rod string may
together be referred to
as a "sucker rod pump" or "rod-drawn pump."
[0086] The rod string used in the fluid pumping system may be comprised of
steel, at least
along the vertical section of the wellbore. However, low-friction fiberglass
rods are preferred
along the transitional section and the horizontal section of the wellbore.
[0087] The traveling valve and the standing valve are run into the wellbore
together using
a releasable connection. Of interest, the traveling valve and standing valve
are run into the
horizontal leg of the wellbore to a selected location.
[0088] The method 200 also includes landing the standing valve into a
seating nipple along
the horizontal section of the wellbore. This is provided at Box 250. The
seating nipple resides
along the production casing. The seating nipple may be modified to accommodate
the outer
diameter of a standard pump barrel of a standing valve. Alternatively, the
pump barrel may be
16
Date Recue/Date Received 2020-08-19
modified to land into a standard seating nipple placed along the production
casing. In either
instance, the standing valve lands into the production casing rather than into
production tubing.
[0089] The method 200 additionally comprises releasing the standing valve
from the
traveling valve. This means operating the releasable connection in order to
disconnect the
traveling valve from the standing valve. This is provided at Box 260 of Figure
2B. The step
of Box 260 is done while the traveling valve and standing valve are downhole
and without
pulling the rod string out of the well.
[0090] In a preferred embodiment, the releasable connection is a standing
valve puller.
Figure 3 is a perspective view of the standing valve puller 300 of the parent
application. The
standing valve puller 300 is designed to be used to remove a standing valve
(such as standing
valve 164) from a wellbore 100. This is done by using the rod string 124, the
traveling valve
162 and an engagement pin 310, wherein the engagement pin 310 resides at the
lower end of
the traveling valve 162 . Cyclically pushing the engagement pin 310 into the
standing valve
puller 300 alternatingly connects and disconnects the engagement pin 310 from
the standing
valve puller 300. In the present disclosure the standing valve puller 300 is
used to release the
traveling valve from the standing valve while the valves are downhole.
[0091] In operation, the standing valve puller 300 threadedly connects to
the standard
standing valve 164 using the existing threaded opening at the top of the
standing valve 164.
The connection is made by hand at the surface before the standing valve 164 is
run into the
wellbore 100 and seated in the seating nipple 166.
[0092] The standing valve puller 300 will remain connected to the standing
valve 164
within the wellbore 100 during production. At the same time, the engagement
pin 310 remains
connected to the bottom of the traveling valve 162 and, accordingly, will
cycle with the sucker
rods 124. The engagement pin 310 provides a "latch and release" arrangement
with the
standing valve puller 300.
[0093] In a preferred embodiment, the standing valve puller 300 is no more
than 15 to 24
inches in length, measured from a top 322 (shown in Figure 4) of a holding arm
component 320
17
Date Recue/Date Received 2020-08-19
to a bottom 384 (shown in Figure 3) of a threaded end connector. In addition,
the standing valve
puller 300 will have an outer diameter no greater than the outer diameter of
the standing valve
164 itself. For example, the standing valve puller 300 may have an outer
diameter (measured
across the housings 340 / 370) of about 2.0 inches, although a slightly larger
size could be
employed depending on casing I.D. Therefore, the standing valve puller 300
will not create a
restriction to either run-in or to normal wellbore operations.
[0094] The standing valve puller 300 replaces the traditional threaded
connection between
the traveling valve 162 and the standing valve. (The traditional arrangement
is called a "tap-
type puller.")
[0095] Figure 3 shows an engagement pin 310 latched into the standing valve
puller 300.
The engagement pin 310 defines an elongated body comprising a proximal (or
upper) end 312
and a distal (or lower end) 314. (The distal end 314 is seen in Figure 4.)
Between the proximal
end 312 and the distal end 314 is a stem 316. Preferably, the stem 316 is
about three inches in
length.
[0096] In the view of Figure 3, the engagement pin 310 is seen extending
down into the
standing valve puller 300. More specifically, a stem 316 has passed through a
top of the
standing valve puller 300. Applying a downward force onto the engagement pin
310 (applied
through the rod string 124) causes the elongated stem 316 to move down into
the standing
valve puller 300. The standing valve puller 300 is designed in such a way that
the downward
force will cause arms (shown at 325 in Figure 4) at the top of the puller 300
to pivot inwardly
and to latch onto the stem 316. Beneficially, applying the same downward force
to the
engagement pin 310 a second time will cause the arms 325 to pivot away from
the stem 316
and to release the engagement pin 310 from the standing valve puller 300 (seen
in Figure 10).
In this way, a "latch and release" cycle is provided that may be performed
quickly and
repetitively.
[0097] Figure 4 is a perspective view of a holding arm component 320. In
this view, the
individual arms 325 have been pivoted outward into their "released" position.
An engagement
pin 310 is positioned above the holding arm component 320, ready to move down
through a
18
Date Recue/Date Received 2020-08-19
central bore of the standing valve puller 300 and to depress a sliding
component (shown at 330
of Figure 5.
[0098] It is observed that a lower end 324 of each arm 325 includes a
beveled inward
surface 329. The beveled inward surface 329 accommodates the pivoting action
of the arms
325, permitting the arms 325 to pivot outwardly more fully. At the same time,
the beveled
surfaces 329 receive the shoulder 314 when the engagement pin 310 is moved
downwardly
into the standing valve puller 300.
[0099] Of interest, through-openings 327 are shown through each of the arms
325. The
through-openings 327 represent pivot points and are configured to receive a
pivot pin (not
shown). The pivot pins reside proximate a top of the top housing 340 of the
puller 300. The
horizontal pins allow the arms 325 to pivot inwardly and outwardly relative to
the top housing
340.
101001 The proximal end 312 of the engagement pin 310 comprises a somewhat
tubular
body 318. The body 318 serves as a box connector, meaning it offers female
threads 315
within an opening. The body 318 threadedly connects to the lower end of a
running string,
such as coiled tubing or a sucker rod string. More preferably, the body 318
threadedly connects
to the lower end of the traveling valve 162. In this way, the operator can use
the existing rod
string 124 and connected traveling valve 162 to engage the standing valve 164.
Upon latching
into the standing valve puller 300, an upward force is applied to the rod
string 124 in order to
unseat the standing valve 164. Again, this may be done without removing the
rod string 124
from the wellbore 100 beforehand.
[0101] Returning back to Figure 3, additional features of the standing
valve puller 300 are
seen. These include the top housing 340 and the bottom housing 370. One or
more holes 346
are drilled into the top housing 340. Similarly, holes 376 are formed in the
bottom housing
370. These are drain holes that allow fluids to drain from the standing valve
puller 300 as the
standing valve 364 is being pulled from the wellbore 300.
19
Date Recue/Date Received 2020-08-19
101021 When it is desirable to remove the standing valve 364, such as for
maintenance,
repair or replacement, the operator will use the standing valve puller 300 to
latch onto the
engagement pin 310 below the traveling valve 362. Specifically, the shoulder
314 will catch
on the arms 325 of the holding arm component 320. The shoulder 314 will hit
flanges at a
proximal end 322 of the holding arms 320 when in their latched position. The
operator will
then pull the standing valve puller 300 and connected standing valve 364 from
the wellbore
100 together. Thus, the standing valve puller 300 is configured to allow
retrieval of the known
standing valve 164 from the casing 128 using the traveling valve 162 itself,
thereby saving a
trip.
101031 Moving now to Figure 5, Figure 5 offers an exploded view of the
standing valve
puller 300 of Figure 3. Internal components of the standing valve puller 300
are now visible.
These include the holding arm component 320, a sliding component 330, the top
housing 340,
a twisting component 350, a spring 360, the bottom housing 370 and the
threaded connector
380.
101041 Along with the standing valve puller 300 and its components, Figure
5 shows the
engagement pin 310 in its entire length. In Figure 5, the distal end 314 is
now seen. The distal
end 314 defines a shoulder. When the engagement pin 310 is pulled by the
operator from the
surface, the shoulder 314 will catch on the arms 325 of the holding arm
component 320. More
specifically, the shoulder 314 will hit flanges 322 of the holding arms 320
when in their latched
position. This is more readily seen in the side view of Figure 6A, discussed
below.
101051 Referring to the holding arm component 320, it is observed that the
holding arm
component 320 comprises two or more separate arms 325. Each arm 325 has a
proximal end
322 and a distal end 324. As noted, the distal end 322 represents a flange
used to catch the
shoulder 314 of the engagement pin 310 when the holding arm component 320 is
in its latched
position.
[0106] In addition, each arm 325 has a pivot hole 327. As noted above, each
pivot hole
327 is dimensioned to receive a respective horizontal pin (not shown). The
respective pins
Date Recue/Date Received 2020-08-19
reside proximate a top 342 of the top housing 340. The horizontal pins allow
the arms 325 to
pivot inwardly and outwardly relative to the top housing 340.
[0107] The standing valve puller 300 next includes the sliding component
330. The sliding
component 330 comprises a generally tubular body wherein splines 335 are
placed radially
around an outer diameter. As the name implies, the sliding component 330 is
configured to
move (or slide) longitudinally along the standing valve puller 300.
Specifically, the splines
335 slide along channels 346 disposed along an inner diameter of the top
housing 340. A
central channel 346 is seen in Figure 6B.
[0108] Next shown in Figure 5 is the top housing 340. The top housing 340
is a tubular
body comprising a proximal end 342 and a distal end 344. The proximal end 342
includes
pivot holes 347 that receive the horizontal pivot pins. In the preferred
embodiment, two
horizontal pins are used, requiring two pairs of pivot holes 347 located on
each side of the top
housing 340. In this way, the two opposing arms 325 are pivotally supported.
[0109] The proximal end 342 of the top housing 340 defines a pair of
slanted surfaces 343.
The slanted surfaces 343 are dimensioned to receive the respective arms 325
when they are
pivoted outwardly. Preferably, the arms 325 are biased to pivot outwardly
through the use of
respective springs (not shown).
[0110] The distal end 344 of the top housing 340 comprises a male threaded
member. The
male threads at the distal end 344 connect to a proximal end 372 of the bottom
housing 370,
described further below.
101111 Figure 5 next shows a twisting component 350. The twisting component
350 also
represents a somewhat tubular body. The twisting component 350 comprises a
proximal end
352 and a distal end 354. Along the tubular body of the twisting component 350
are
longitudinal slots. The slots alternate between long slots and short slots
(identified as slots 351
and 357, respectively, in Figure 4B). Regardless of their length, the slots
351, 357 are
dimensioned to slidably receive the splines 335 of the sliding component 330.
21
Date Recue/Date Received 2020-08-19
[0112] Next shown in Figure 5 is the spring 360. The spring 360 resides
within the bottom
housing 370. The spring 360 is maintained in compression between a shoulder
382 (visible in
Figure 3B) of the threaded connector 380 and a corresponding shoulder 353
(also visible in
Figure 3B) of the twisting component 350. The spring 360 urges the twisting
component 350
upward against the sliding component 330. Stated another way, the spring 360
is used to bias
the twisting component 350 into engagement with the twisting component 330.
The spring
360 is preferably fabricated from steel.
[0113] Figure 5 next presents the bottom housing 370. As described above,
the bottom
housing 370 is a tubular body having a proximal end 372 and a distal end 374.
The proximal
end 372 comprises female threads configured to connect to the male threaded
end 344 of the
top housing 340. Similarly, the distal end 374 comprises female threads
configured to connect
to male threads at the proximal end 382 of the threaded connector 380.
[0114] It is noted that one or more holes 376 may be drilled into the
bottom housing 370.
This allows the standing valve puller 300 to be flushed out, either after the
puller 300 has been
retrieved to the surface, or in response to a hot oil treatment or chemical
treatment wherein
fluid is injected downhole.
[0115] Finally, Figure 5 shows the threaded connector 380. The threaded
connector 380
provides a means for connecting the standing valve puller 300 with the
standing valve 960.
The threaded connector 380 includes a distal end 384, discussed above in
connection with
Figure 1.
[0116] In the view of Figure 5, the threaded connector 380 is shown as a
separate
component from the bottom housing 370. However, it is understood that the
threaded
connector 380 may be integral to the bottom housing 370, meaning that the
distal end of the
housing 370 is actually the threaded male tip 384.
[0117] Figure 6A is a side view of the standing valve puller 300 of Figure
1. The tubular
housing is shown, with the top housing 340 and bottom housing 370 being
connected. In
addition, the flanges 322 of the arms 325 are shown extending up from the top
housing 340.
22
Date Recue/Date Received 2020-08-19
[0118] Also visible in Figure 6A is the engagement pin 310. It can be seen
that the
shoulder 314 of the engagement pin has engaged the flanges 322 from
underneath. This
indicates that the engagement pin 310 is being pulled upward.
[0119] Figure 6B is a cross-sectional view of the standing valve puller 300
and the
engagement pin 310 of Figure 6A. The view is taken across Line B-B of Figure
6A. In this
view, the standing valve puller 300 is in a latched position, enabling the
shoulder 314 of the
engagement pin 310 to "catch" the flanges 322 of the respective arms 325 and
pull the standing
valve puller 300 and connected standing valve 164 up from a wellbore 100.
[0120] Of interest, Figure 6B shows the spring 360 residing between the
shoulder 383 of
the threaded connector 380 and the shoulder 353 of the twisting component 350.
Here, the
spring 360 is not being compressed. The interrelationship between a distal end
334 of the
sliding component 330 and a proximal end 352 of the twisting component 350 can
also be
inferred. When the sliding component 330 is pushed down through the channels
346 in the top
housing 340, the toothed profile of the distal end 334 of the sliding
component 330 will engage
the mating toothed profile of the proximal end 352 of the twisting component
350. This will
induce a rotation of the twisting component 350, which radially advances the
slots 355 of the
twisting component 350 from long 357 to short 351 to long 357, and so forth.
In one aspect, a
lower end of each of the splines 335 is angled, such as at 45-degrees, to urge
rotation of the
twisting component 350 when the twisting component 350 is acted upon by the
sliding
component 330.
[0121] As the sliding component 330 is forced downward by the engagement
pin 310, it
will rotate the twisting component 350 into a next position. In the latched
position, the sliding
component 330 will be forced upwards from the twisting component 350 into the
holding arm
component 320, under the force of the spring 360 as shown in Figure 3B. This
prevents the
arms 325 from pivoting outwardly into the slanted surfaces 342. In the
disengaged, or released,
position the sliding component 330 will be in a "floating" position. This
position will allow
the arms 325 of the holding arm component 320 to freely pivot. This further
allows the arms
325 to pivot outwardly into the slanted surfaces 342.
23
Date Recue/Date Received 2020-08-19
[0122] It is observed that the downward force of the shoulder 314 of the
engagement pin
310 against the sliding component 330 will cause the distal end 334 of the
sliding component
330 to engage the proximal end 352 of the twisting component 350. Where the
splines 335 of
the sliding component engage the long slots 357 (seen in Figure 7B), the
spring 360 will force
the twisting component 350 upwards along the top housing 340. At the same
time, the sliding
component is prevented from twisting because the splines 335 reside in the
channels 346 along
the inner diameter of the top housing 340.
[0123] Figure 7A is another perspective view of the standing valve puller
300 of Figure
5. Components of the standing valve puller 300 are partially exploded apart
for illustrative
purposes. Here, the engagement pin 310 is not shown. Also visible are two of
the pivot holes
347 in the top housing 340.
[0124] One or more holes 346 may be drilled into the top housing 340,
serving as drain
holes. The drain holes 346 allow fluids to drain from the puller 300 when the
standing valve
164 is being pulled from a wellbore.
[0125] Figure 7B is a side view of the more-fully exploded-apart components
of the
standing valve puller 300 of Figure 7A. Of interest, it can be seen that the
arms 325 of the
holding arm component 320 are independent (not connected) pieces that are able
to pivot
separately.
[0126] Figure 8 is a cross-sectional view of the standing valve puller 300
of Figure 5. The
engagement pin 310 again is not shown. One of the arms 325 is visible
extending up from the
top 342 of the top housing 340. It is observed that in Figure 8, the spring
360 has been
removed. The twisting component 350 is, for illustrative purposes, not being
urged upwardly
against the sliding component 330.
[0127] Figure 9A is perspective view of the holding arm component 320. In
this view,
both arms 325 of the component 320 are presented. The arms 325 are pivoted
inwardly for
illustrative purposes. Of interest, through-openings 327 are shown through
each of the legs
325 for receiving a pivot pin (not shown).
24
Date Recue/Date Received 2020-08-19
[0128] It is noted that the lower end 324 of each arm includes a beveled
inward surface
329. The beveled inward surface 329 of each of the legs 325 accommodates the
pivoting action
of the legs 325, permitting the legs 325 to pivot outwardly more fully into
the beveled upper
surface 342. At the same time, the beveled surfaces 329 receive the shoulder
314 when the
engagement pin 310 is moved downwardly into the standing valve puller 300.
[0129] An upper rear surface 321 of each arm 325 offers a curvilinear
profile. This profile
is intended to match the slope of the slanted surface 343, allowing the arms
325 to rest against
the slanted surface 343 when the arms 325 pivot outwardly.
[0130] Figure 9B is another perspective view of the holding arm component
320. Here,
the holding arm component 320 is again in its latched position.
[0131] Figure 10 is still another perspective view of the holding arm
component 320. In
this view, the individual arms 325 have been pivoted outward into their
"released" position.
An engagement pin 310 is positioned above the holding arm component 320, ready
to move
down through the central bore 305 and to depress the sliding component 330.
[0132] It is again understood that springs (not shown) may be placed behind
the individual
arms 325 in order to bias the arms 325 away from each other. This accommodates
lowering
of the engagement pin 310 through the central bore 305 and into the upper
housing 330.
[0133] Returning to the flow chart of Figure 2B, and particularly Box 260,
it can be seen
that the engagement pin 310 can be released from the standing valve puller 300
by applying a
compressive force to the standing valve puller 300. This is done by slacking
weight off of the
rod string 124, directing gravitational force through the traveling valve 162,
through the
engagement pin 310, and into the standing valve puller 300. This will cause
the arms 325 of
the holding arm component 320 to release, that is to open up as shown in
Figure 4 and 10.
[0134] To demonstrate operation of the releasable connection in the methods
herein,
Figures 11A through 11F are presented. Each figure presents a wellbore 1100 in
a horizontal
orientation. The wellbore 1100 may represent an enlarged portion of the
wellbore 100 of
Date Recue/Date Received 2020-08-19
Figure 1, and particularly the horizontal section 146. However, in this view
standard steel
casing is used as the production casing, with the casing having been
perforated before run-in.
[0135] The wellbore 1100 defines a cylindrical bore 1105 that has been
drilled into an earth
subsurface 110. The cylindrical bore 1105 is lined with a series of steel
casings, with each
string of casing having a progressively smaller outer diameter. In Figures11A-
11F, only the
lowermost string of casing is shown. This is referred to as a production
casing 1110.
[0136] The production casing 1110 extends to proximate a lower end 1108 of
the wellbore
1100. The casing 1110 is cemented into the formation 110 through a column of
cement 1115.
Specifically, the column of cement 1115 is squeezed into an annular area
formed between the
production casing 1110 and the surrounding earth formation 110. In addition,
the casing 1110
and cement column 1115 have been perforated. Illustrative perforations are
shown at 1125.
The perforations 1125 allow reservoir fluids to flow into the wellbore 1100.
It is understood
that in an actual, horizontally-completed well, the casing 1110 will have
multiple perforations,
extending in some cases one to four miles.
[0137] After perforating, the formation 110 is typically acidized and/or
fractured through
the perforations 1125. Hydraulic fracturing consists of injecting water with
friction reducers
or viscous fluids (usually shear thinning, non-Newtonian gels or emulsions)
into a formation
at such high pressures and rates that the reservoir rock parts and forms a
network of fractures.
The fracturing fluid is typically mixed with a proppant material such as sand,
ceramic beads or
other granular materials. The proppant serves to hold the fractures open after
the hydraulic
pressures are released. In the case of so-called "tight" or unconventional
formations, the
combination of fractures and injected proppant substantially increases the
flow capacity, or
permeability, of the treated reservoir.
[0138] Those of ordinary skill in the art will understand that the process
of perforating and
fracturing a well is done in multiple zones. The operator typically perfs and
fracs a first zone
at the end of the wellbore, then sets a plug above the perforations. The
perforating guns are
run back into the hole, and a next zone is perfed and fracked.
26
Date Recue/Date Received 2020-08-19
[0139] In Figure 11A, the wellbore is indicated at 1100A. Here, a positive
displacement
pump is being run into the production casing 1110. Movement of the positive
displacement
pump into the wellbore is indicated at Arrow RI. The positive displacement
pump represents
a traveling valve 1140 and a standing valve 1160. The traveling valve 1140 is
disposed at the
lower end of a sucker rod string 1130. The sucker rods in the string 1130 may
be standard
steel rods; alternatively, they may be fiberglass rods.
[0140] Those of ordinary skill in the art will understand that the
traveling valve 140 is
reciprocated up and down within the wellbore 1100 in response to movement of a
prime mover
at the surface (not shown). Such a prime mover may be, for example, a
hydraulic pumping
unit, a pneumatic pumping unit or a mechanical pumping unit. The present
inventions are not
limited by the manner in which the traveling valve 1140 is reciprocated.
[0141] Also seen in Figure 11A is an engagement pin 310. The engagement pin
310 is
secured to a lower end of the traveling valve 1140 by means of threads within
the box connector
318. The engagement pin 310 will remain in the wellbore 1100 during production
operations.
[0142] The engagement pin 310 is latched into a standing valve puller 300.
This would be
in accordance with the view of Figure 3, discussed above. The standing valve
puller 300 is
threaded into the top of a standing valve 1160. This is done by means of
threaded end 384.
[0143] The standing valve 1160 includes a ball 1167. The ball 1167 is part
of a ball-and-
seat arrangement as is well known in the art. However, in this arrangement the
standing valve
1160 is retrofitted with an elastomeric band 1168 along the outer diameter.
The band 1168
acts as a no-go landing nipple, and is configured to land in a corresponding
seat 1118. The
band 1168 may be supported by metal rings and serves the function of a so-
called pump barrel.
In this case, the elastomeric band 1168 is enlarged to mate with the seat 1118
within the
production casing 1110.
[0144] As an alternative, a standard landing nipple may be used in the pump
barrel that is
part of the standing valve 1160. In that case, a modified seating nipple is
employed. Such an
arrangement is shown and discussed below in connection with Figure 12. In
either
27
Date Recue/Date Received 2020-08-19
arrangement, the production tubing is not present and does not extend down to
the horizontal
section of the wellbore 1100.
[0145] The seat 1118 resides along the inner diameter of the production
casing 1110. The
seat 1118 acts as an internal constriction, or "seating nipple," limiting
downward movement
of the standing valve 1160. The enlarged elastomeric seal ring 1168 on the
outer body of the
standing valve (or pump barrel) also forms a leak proof seal between the
standing valve 1160
and the seating nipple 1118.
[0146] Of interest, the standing valve puller 300 will remain connected to
the standing
valve 1160 while the standing valve 1160 is fixed downhole on the seating
nipple 1118 during
production operations. In addition, the operator may adjust the location of
the polished rod
relative to the pumping unit at the surface, and then land the engagement pin
310 back into the
standing valve puller 300. hi this way, the standing valve 1160 may be
unseated from the
production casing 1110 without pulling the rod string from the wellbore 1100.
Optionally, the
standing valve 1160 may then be raised up the wellbore 1100 and replaced or
serviced.
[0147] Figure 11B is a next side view of the wellbore 1100. This is
indicated at 1100B.
In this view, the traveling valve 1140 and the standing valve 1160 have been
moved further
down the wellbore 1100B. This is again shown by Arrow Ri. The elastomeric band
1168 has
now landed in the seating nipple 1118. Note that the standing valve 1160 is
fixed directly into
the production casing 1110 with no production tubing. The standing valve 1160
is landed into
the casing 1110 above the perforations 1125.
[0148] Figure 11C is a next side view of the wellbore 1100. This is
indicated at wellbore
designation 1100C. In this view, a second compressive force is applied through
the rod string
1130. This is shown at Rc. The rod string 1130 is connected to the traveling
valve 1140
through a connector 1135. The compressive force moves through the connector
1135, through
the traveling valve 1140, and through the engagement pin 310 to unlatch from
the standing
valve puller 300.
28
Date Recue/Date Received 2020-08-19
[0149] In Figure 11C, the standing valve 1160 includes a modified tubing
barrel 1165.
The elastomeric band 1168 extending from the tubing barrel 1165 remains landed
in the seating
nipple 1118.
[0150] Figure 11D is a next side view of the wellbore 1100. This is
indicated at wellbore
designation 1100D. In this view, the traveling valve 1140 and connected
engagement pin 310
having been released from the standing valve puller 300. The traveling valve
1140 has been
repositioned in the wellbore 1100D above the standing valve 1160. The well is
now ready for
production.
[0151] Figure 11E shows the traveling valve 1140 being lifted within the
production
casing 1110 by the sucker rod string 1130. This is indicated at wellbore
designation 1100E.
The upward action of the rod string 1130 causes a ball 1147 in the traveling
valve 1140 to seat.
This, in turn, allows the traveling valve 1140 to raise production fluids up
the casing 1110 and
to a well head and fluid separation equipment (not shown) at the surface.
Arrow Ru indicates
upward movement of the rod string 1130 and connected traveling valve 1140.
Arrow P
indicates an in-flow of production fluids into the wellbore 1100E.
101521 Figure 11E also shows that the standing valve 1160 remains affixed
to the bottom
of the casing 1110. As the traveling valve 1140 pushes production fluids up
the casing 1110,
negative pressure is created below the traveling valve 1140. This causes the
ball 1167
associated with the standing valve 1160 to become unseated, which in turn
pulls production
fluids entering the wellbore 1100E into the standing valve 1160. The
production fluids travel
through ports in the standing valve 1160 and into the casing 1120 as shown by
Arrow S.
[0153] Finally, Figure 11F shows the traveling valve 1140 being lowered
back down the
production casing 1110 by the sucker rod string 1140. This is indicated at
wellbore designation
1100F. Arrow RD demonstrates the downward movement of the sucker rod string
1130.
Downward movement of the connected traveling valve 1140 increases fluid
pressure above the
standing valve 1160, which causes the ball 1167 in the standing valve 1160 to
seat.
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Date Recue/Date Received 2020-08-19
[0154] Figure 11F also shows that the ball 1147 in the traveling valve 1140
has unseated.
This allows production fluids to pass through the traveling valve 1140, and to
flow through
ports and up the casing 1110. Arrow T indicates upward fluid movement through
the traveling
valve 1140.
[0155] Additional components and features of the standing valve puller 300
are described
in U.S. Patent No. 10,605,017 entitled "Unseating Tool for Downhole Standing
Valve." The
novel standing valve puller of the '017 patent allows a service company to
pull the standing
valve at any time while the sucker rods and traveling valve are still in the
wellbore.
Alternatively, a pumper or service company at the wellsite can run the sucker
rod string, the
engagement pin, the standing valve puller and the standing valve into the
wellbore together,
and then release the traveling valve from the standing valve as shown in the
Figure 11 series
of drawings, all in one trip.
[0156] Returning again to Figure 2B, the method 200 additionally includes
mechanically
or operatively connecting a top end of the rod string to a polished rod. This
is shown in Box
270. The polished rod is part of a pumping unit residing at the surface. In
this way, the rod
string extends from the surface, down into a vertical section of the wellbore,
across a
transitional section of the wellbore, and into the production casing residing
along the horizontal
section of the wellbore.
101571 It is understood that the operator will manually adjust a location
at which a harness
and clamps supporting the polished rod is secured to the polished rod itself.
This ensures that
the traveling valve will be appropriately spaced above the standing valve.
Thus, Box 270 of
the method 200 also includes adjusting a position of the polished rod relative
to the pumping
system. Specifically, clamps associated with the pumping rod system are moved
up the
polished rod. The step of Box 220A enables the sucker rod string and connected
traveling
valve to travel lower into the production tubing on a down stroke.
[0158] The polished rod is part of a pumping unit, which resides at the
surface. The
pumping unit may be either a mechanical pumping unit such as a so-called rod
beam (or
sometimes "rocking beam") unit. Alternatively, the pumping unit may be a
linear pumping
Date Recue/Date Received 2020-08-19
unit that uses hydraulic fluid or pneumatic fluid to cyclically act against a
piston within a
cylinder. In either instance, the pumping unit will use clamps and a harness
to secure the
pumping unit to the polished rod and to produce reciprocating motion of the
downhole
traveling valve above the standing valve.
[0159] Finally, the method may comprise producing hydrocarbon fluids from
the
production casing using the fluid pumping system. This is offered in Box 280.
Note that no
production tubing need be placed within the wellbore. Of course, a production
string with a
packer may optionally be installed into the vertical section of the well to
provide a beneficial
pressure differential. However, the rod string will extend well beyond the
packer and into the
horizontal section of the well.
[0160] The pumping unit will provide an upstroke and a down stroke. The
speed at which
the upstroke and the down stroke take place may be preset by the operator and
periodically
adjusted. Alternatively, the speeds may be adjusted by a rod pump controller
located at the
well head in response to real time load cell readings or manual override
settings. Rod pump
controllers will have override minimum speed and maximum speed settings.
[0161] As noted, the horizontal wellbore 1100 shown in the Figure 11 series
of drawings
is completed with production casing. However, a wellbore may be completed
using slotted
liner. In one aspect of the methods herein, the fluids are produced from the
pay zone through
a sand screen. In this instance, the method will include running the sand
screen into the
horizontal leg of the wellbore using a working string. Preferably, a packer is
placed between
the end of the working string and the top end of the sand screen.
[0162] The method next includes setting the packer along the horizontal
section of the
wellbore. This may be done, for example, by operating a J-slot mechanism
associated with the
packer. The J-slot mechanism allows the packer to be set through a cycling
mechanism,
wherein the cycling takes place in response to compressive force applied by
the working string
through pins, or tabs. Preferably, the compressive force is a mechanical force
applied by letting
the weight down off of the working string. Thus, in one aspect the method 200
includes
operating a J-slot mechanism to set the packer in the wellbore.
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Date Recue/Date Received 2020-08-19
[0163] Once the packer is set, the method includes disconnecting the
running string from
the packer. This again may comprise operating the J-slot mechanism by applying
a
compressive force through the working string and against the J-slot mechanism
to release the
working string from the packer. The working string is then removed from the
wellbore.
[0164] This is all done before the fluid pumping system is run into the
wellbore (Box 240)
and the standing valve is landed in a seating nipple (Box 250).
[0165] Figure 12 is a cross-sectional view of a wellbore 1200 having
received a pumping
system. The pumping system includes a sucker rod string 1130, a traveling
valve 1140, and a
standing valve 1160. The traveling valve 1140 and the standing valve 1160 each
represents a
ball-and-seat valve, wherein traveling valve 1140 includes ball 1147 while
standing valve 1160
includes ball 1167.
[0166] As with wellbore 1100, wellbore 1200 represents a horizontal
section, with a string
of production casing 1110 placed within a cylindrical borehole 1105. However,
in lieu of
perforations 1125, wellbore 1200 utilizes joints of tubular bodies 1220 having
slots 1205. The
tubular bodies 1220 may represent joints of sand screen. Alternatively, the
tubular bodies 1220
may represent joints of slotted liner. In either instance, it is understood
that multiple joints of
slotted tubular bodies 1220 may be employed, extending one or even two or
three miles along
the horizontal wellbore 1200. The tubular bodies 1200 extend to a lower end of
the wellbore
1108.
[0167] The standing valve 1160 includes a standard tubing barrel 1165. The
tubing barrel
1165 includes an elastomeric band 1163. The elastomeric band 1263 serves as a
so-called
tubing plunger and is configured to land onto a modified seating nipple 1260.
The seating
nipple 1260 comprises a metal member 1263 that extends into a bore 1205, that
receives the
elastomeric band 1163 to form the fluid seal.
[0168] It is noted that the seating nipple 1260 resides in the wellbore
1200 above the slotted
tubular bodies 1200. It is further noted that no column of cement is placed
between the slotted
tubular bodies 1200 and the borehole 1105. To ensure that wellbore fluids
enter the bore 1205
32
Date Recue/Date Received 2020-08-19
and are pumped to the surface 105, a packer 1230 may be placed above the
tubular bodies
1200. The packer 1230 will include an elastomeric element 1235. The
elastomeric element
1205 is actuated into engagement with the surrounding bore 1105 using a
setting tool (not
shown).
[0169] In the arrangement of Figure 12, the slotted tubular bodies 1220 (in
this case, joints
of slotted liner) are not run into the wellbore on a working string; rather,
they are run into the
wellbore 1200 as part of a continuous threaded string with the production
casing 1110. The
packer 1230 is part of the continuous threaded pipe string. Setting the
sealing element 1235
of the packer 1230 in the wellbore means expanding the sealing element 1235
into engagement
with the surrounding borehole 1105. In this instance, the packer may be an
expandable packer
that is actuated when placed in contact with hydrocarbon or other fluids.
[0170] The wellbore arrangements shown in the Figure 11 series of drawings
an in Figure
12 show ball-and-seat valves for both the traveling valve 1140 and the
standing valve 1160. It
is understood that other valve arrangements may be employed for one or both of
the valves.
For example, due to the horizontal incline of the wellbores, the operator may
prefer to use
mechanical valves. The present methods are not limited by the type of valves
used for the
artificial lift unless so stated in the claims.
[0171] Further, variations of the method of producing hydrocarbon fluids
from a wellbore
may fall within the spirit of the claims, below. It will be appreciated that
the inventions are
susceptible to modification, variation and change without departing from the
spirit thereof.
33
Date Recue/Date Received 2020-08-19
