U.S. patent application number 16/165478 was filed with the patent office on 2019-02-14 for hydraulically powered downhole piston pump.
The applicant listed for this patent is HANSEN DOWNHOLE PUMP SOLUTIONS, AS. Invention is credited to Tarald Gudmestad, Henning Hansen, James Lindsay.
Application Number | 20190048695 16/165478 |
Document ID | / |
Family ID | 58745287 |
Filed Date | 2019-02-14 |
![](/patent/app/20190048695/US20190048695A1-20190214-D00000.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00001.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00002.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00003.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00004.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00005.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00006.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00007.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00008.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00009.png)
![](/patent/app/20190048695/US20190048695A1-20190214-D00010.png)
View All Diagrams
United States Patent
Application |
20190048695 |
Kind Code |
A1 |
Hansen; Henning ; et
al. |
February 14, 2019 |
HYDRAULICALLY POWERED DOWNHOLE PISTON PUMP
Abstract
A wellbore pump includes a receptacle for a pump formed into a
wellbore production tubing. A pump includes a seal engageable with
an interior surface of the receptacle. The seal has a pump rod
passing sealingly through the seal. The pump rod has a piston in
sealing engagement with an interior of the tubing on each side of
the seal. A power fluid line is in hydraulic connection to an
interior of the production tubing above and below the seal. A well
fluid inlet port is disposed between one of the pistons. A
longitudinally spaced apart check valve is disposed in the wellbore
production tubing above an upper one of the pistons.
Inventors: |
Hansen; Henning; (Dolores,
ES) ; Gudmestad; Tarald; (N.ae butted.rbo, NO)
; Lindsay; James; (Glasgow, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HANSEN DOWNHOLE PUMP SOLUTIONS, AS |
Bryne |
|
NO |
|
|
Family ID: |
58745287 |
Appl. No.: |
16/165478 |
Filed: |
October 19, 2018 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
PCT/IB2017/052341 |
Apr 24, 2017 |
|
|
|
16165478 |
|
|
|
|
62328811 |
Apr 28, 2016 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 43/121 20130101;
F04B 53/02 20130101; F04B 53/144 20130101; E21B 43/129 20130101;
E21B 34/08 20130101; F04B 47/04 20130101; E21B 2200/04
20200501 |
International
Class: |
E21B 43/12 20060101
E21B043/12 |
Claims
1. A wellbore pump, comprising: a receptacle for a pump formed as
part of a wellbore production tubing; a pump comprising a seal
engageable with an interior surface of the receptacle, the seal
having a pump rod passing sealingly through the seal, the pump rod
having a piston in sealing engagement with an interior of the
tubing on each side of the seal, the seal and the piston directly
in sealing engagement with an interior surface of the receptacle; a
power fluid line having hydraulic connection to an interior of the
production tubing above and below the seal; a well fluid inlet port
disposed between one of the pistons and the seal; and a
longitudinally spaced apart check valve disposed in the wellbore
production tubing above the piston disposed above the seal.
2. The wellbore pump of claim 1 wherein the check valve is disposed
in a piston connected to the pump rod.
3. The wellbore pump of claim 1 further comprising a fluid inlet
check valve in sealing engagement with the well fluid inlet
port.
4. The wellbore pump of claim 1 further comprising a filter
covering the well fluid inlet port.
5. The wellbore pump of claim 1 further comprising a well fluid
discharge line in fluid communication with the interior of the
production tubing above the longitudinally spaced apart check
valve.
6. The wellbore pump of claim 5 further comprising an additional
check valve disposed in the production tubing above the well fluid
discharge line.
7. The wellbore pump of claim 6 further comprising well gas inlet
ports in the production tubing at a position above the additional
check valve.
8. The wellbore pump of claim 6 wherein the additional check valve
is operable in two fluid flow directions.
9. The wellbore pump of claim 1 further comprising well gas inlet
ports in the production tubing above the longitudinally spaced
apart check valve.
10. The wellbore pump of claim 1 further comprising an lower inlet
check valve assembly coupled to a bottom end of the production
tubing below the pump and arranged such that fluid is drawn into
the bottom of the tubing by the pump and is discharged to an
additional fluid discharge line in fluid communication with the
interior of the tubing above the bottom end of the production
tubing.
11. The wellbore pump of claim 1 wherein the pump is insertable
into and retrievable from the receptacle using at least one of
wireline, coiled tubing and a semi-still spoolable
rodconveyance.
12. A wellbore pump, comprising: a pump piston disposed in a pump
power chamber arranged to be coupled to a wellbore production
tubing or wellbore casing, the pump piston comprising check valves
and flow passages therein enabling well fluid to be drawn into a
pump chamber below the pump piston and a lower pump chamber adapter
connecting the power chamber to the production tubing or the
wellbore casing, the check valves and flow passages arranged to
discharge well fluid into the production tubing above an upper pump
chamber adapter connecting the wellbore tubing to the pump chamber,
the upper and lower adapters comprising check valves and/or fluid
flow passages to alternatingly discharge fluid from the pump
chamber into each of the production tubing or wellbore casing and a
well fluid return line.
13. A wellbore pump, comprising: a pump power piston and pump
piston assembly disposed in a pump body connected to a wellbore
production tubing, the pump body comprising an upper cylinder and a
lower cylinder disposed on opposed longitudinal sides of a center
passage through which a piston may move; a first control line
communication with the upper cylinder between fluid seals and a
bottom of the upper piston; a second hydraulic control line in
communication with the lower cylinder; wiper seals on an exterior
of each of the upper piston and the lower piston;. Longitudinal
ends of the pump body corresponding pump pistons each may defining
a respective upper pump chamber and a lower pump chamber; check
valves configured to admit well fluid to the lower pump chamber
when it is expanded and configured to discharge well through a
discharge line and into the wellbore tubing; and corresponding
check valves for the upper pump chamber arranged such that
enlargement and reduction of the volume of the upper pump chamber
by corresponding motion of the upper piston will cause fluid to be
drawn into the upper pump chamber and discharged therefrom,
respectively.
14. The wellbore pump of claim 13 wherein one of the check valves
for the lower pump chamber is disposed in an adapter coupled to a
lower end of the wellbore pump.
15. The wellbore pump of claim 13 wherein a fluid discharge line
couples an outlet of the lower pump chamber to the production
tubing located above the wellbore pump.
16. The wellbore pump of claim 13 wherein one of the check valves
for the lower pump chamber is disposed in an upper adapter coupling
the wellbore pump to the production tubing.
17. The wellbore pump of claim 16 wherein one of the check valves
for the upper pump chamber is disposed in the upper adapter.
18. A wellbore fluid pump, comprising: a first pump housing coupled
to a production tubing by an upper adapter, the upper adapter
comprising a check valve disposed therein or in fluid communication
therewith, the upper adapter having an internal passage connecting
a pumped fluid discharge line to an interior of a check valve seat
whereby fluid discharged through the pumped fluid discharge line
flows through an internal passage to the check valve and upwardly
through the production tubing; a power chamber defined within the
first pump housing longitudinally between the upper adapter and a
power fluid inlet port through the wall of the pump housing, a part
of the first pump housing corresponding to the power chamber having
an enlarged internal diameter section corresponding to a length of
the power chamber; a piston disposed within the first pump housing,
an upper end of the piston in fluid communication with hydraulic
power fluid moved under pressure into the pump housing above the
top of the piston through a power fluid passage in the upper
adapter; a first hydraulic control line coupled to the power fluid
passage to enable moving the piston downwardly in the first pump
housing; a bottom end of the piston comprising a similar fluid
seal; and a pump chamber defined between the bottom end of the
piston within the first pump housing and a lower adapter coupled to
a lower end of the pump housing, the lower adapter comprising an
intake check valve and a discharge check valve disposed in the
lower adapter or in fluid communication therewith. a bore through
the piston at an upper end to a position on the exterior surface of
the piston below dynamic seals on the piston, the bore comprising a
relief valve in the bore proximate a top of the piston whereby
hydraulic power fluid pressure on a second control line used to
move the piston upward in the first pump housing when increased to
a pressure higher than operating pressure after the piston reaches
the upper end of the pump housing lifts the relief valve followed
by opening a corresponding relief valve in the upper adapter to
cause trapped gas to exit from the power chamber, through the
piston and the relief valves 1710A, 1704A, and then into the
production tubing above the upper adapter. Should we add a claim
referring to this claim that check valves can be hydraulically
coupled to the adapters, but necessarily not mechanically coupled
to said adapter? (Thinking that if someone move check valves away
from the adapters, but still use such check valves, it is easy to
not be in breach with this claim.) Also, should the gas relief
function be removed from this claim, as it is included below in
claim 20?
19. The wellbore pump of claim 18 further comprising at least one
additional pump comprising an upper adapter, a second pump housing,
a piston and a lower adapter and check valves coupled at or in
fluid communication with the upper adapter to a lower end of the
first pump housing.
20. The pump of claim 18 further comprising a gas dump valve
coupled hydraulically to a wellbore pump discharge chamber, the gas
dump valve operable to release trapped gas by applying hydraulic
pressure to the first and second control lines as a pressure above
an operating pressure to move the piston.
21. The wellbore pump of claim 18, further comprising a bore
through the piston at an upper end to a position on the exterior
surface of the piston below dynamic seals on the piston, the bore
comprising a relief valve in the bore proximate a top of the piston
whereby hydraulic power fluid pressure on a second control line
used to move the piston upward in the first pump housing when
increased to a pressure higher than operating pressure after the
piston reaches the upper end of the pump housing lifts the relief
valve followed by opening a corresponding relief valve in the upper
adapter to cause trapped gas to exit from the power chamber,
through the piston and the relief valves, and then into the
production tubing above the upper adapter.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] Continuation of International (PCT) Application No.
PCT/IB2017/052342 filed on Apr. 24, 2018. Priority is claimed from
U.S. Provisional Application No. 62/328,811 filed Apr. 28, 2018.
Both the foregoing applications are incorporated herein by
reference in their entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not Applicable
NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT
[0003] Not Applicable.
BACKGROUND
[0004] This disclosure relates to the field of pumping systems for
deep oil-, gas and water transporting wellbores. More specifically,
the present disclosure relates to describes a single-acting as well
as a double-acting pump system where the main parts of the pump are
replaceable without a need for retrieving tubulars in the wellbore
to change out pump components.
[0005] A number of different types of pumps are known to be used in
deep wellbores, for example sucker rod-driven pumps and electric
submersible pumps. However, there is a need for a lower complexity
pump that can be installed and retrieved by light well
intervention, such as for example wireline, coiled tubing or
self-positioning. See, for example, International Patent
Application Publication No. WO/2012/170112.
[0006] There is also a need for wellbore pumps that do not utilize
sucker rods reciprocated in the wellbore from the surface to the
pump, particularly in highly inclined or deviated wellbores. In
such wellbores, wear and tear on the sucker rods or production
tubing may result in the need for frequent repairs.
[0007] Horizontal wellbores have become very common, and to achieve
better fluid production rates and total fluid recovery, pumps are
known to be placed into the horizontal section of such wellbores.
Pumps using sucker rods are challenging in such conditions, mainly
due to wear and tear as described above, but also due to
differential pressure induced sticking between the sucker rods and
the production tubing. A pump which does not use sucker rods to
drive the pump clearly would have a number of advantages for such
wellbore applications.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 shows an example embodiment of a wellbore tubing
configured to receive a pump. The illustration is for a well
producing gas, where the pump may be used to retrieve produced
water accumulated in the bottom or the well.
[0009] FIG. 2 illustrates a filter to prevent debris in a fluid
entry into the pump can be installed by for example wireline, when
the well has been completed with wellbore equipment as illustrated
in FIG. 1. The filter is to be placed where the fluid intake to the
pump is located, and would typically be deployed into the well by
wireline or similar technique.
[0010] FIG. 3 illustrates an example embodiment of a pump shaft
system with attached pistons installed into the wellbore, for
example by wireline. The system can be locked in place into the
preinstalled pump receiver.
[0011] FIG. 4 illustrates the shaft/pistons seal assembly of an
example embodiment of a pump. A static piston seal is illustrated
so that the inside of this can be understood, where a dynamic seal
within the static piston seal can be observed.
[0012] FIG. 5 illustrates a wireline type plug installed above a
fluid discharge port coupled to a tube transporting wellbore fluid
to the surface. The area between the wireline plug and the top
dynamic piston on the shaft/piston assembly creates a pump chamber
for wellbore fluids to be pumped toward the surface.
[0013] FIG. 6 shows that by alternatingly pressurizing chambers
above and below the static seal component, fluids trapped in the
pump chambers will be pushed towards the surface through the
discharge port and tube to surface.
[0014] FIGS. 7A and 7B show an example embodiment of a single
acting pump with two power fluid lines and an extending lower
rod.
[0015] FIG. 8 illustrates a variation of the pump system shown in
FIGS. 7A and 7B that operates as a double acting pump.
[0016] FIGS. 9A and 9B illustrate a dual acting, dual power fluid
line pump system.
[0017] FIG. 10 and FIG. 11 illustrate a single acting, dual power
fluid line pump system in the upper and lower positions,
respectively. This pump is not wireline replaceable.
[0018] FIG. 12 illustrates a hollow shaft pump that enables
operation using only 1 power fluid line to drive the pump. Force
required to return the dynamic pump element is obtained from the
hydrostatic pressure of fluid in the well. By moving a standing
valve to radial ports below a traveling valve along with a hollow
shaft, the number of fluid lines required may be minimized.
[0019] FIGS. 13A, 13B, 13C and 13D illustrate a dual acting pump
where a centrally located tube arrangement transports wellbore
fluids from the pump intake to fluid compression chambers,
whereafter fluid is discharged through a centrally located
tube.
[0020] FIG. 14 illustrates a traveling piston and check valve
system for the pump illustrated in FIGS. 13A through 13D.
[0021] FIGS. 15A and 15B illustrate a hydraulically operated pump
having two power fluid lines extending to the pump from the
surface
[0022] FIGS. 16A, 16B, 16C, 16D and 16E illustrate the sequential
and repeated operation of the pump illustrated in FIGS. 15A and
15B.
[0023] FIGS. 17A, 17B and 17C illustrate a wellbore pump where
produced fluids are discharged from the bottom of the pump, and
where there is a function built in to dump any trapped gas from the
pump chamber.
[0024] FIGS. 17D through 17H show additional features that may be
used in some embodiments of a pump as shown in and explained with
reference to FIGS. 17A, 17B and 17C.
[0025] FIG. 18 illustrates a pump as shown in FIGS. 17A through
17C, where the pump is extended by attaching a similar pump module
below the pump of FIGS. 17A through 17C, thus doubling the fluid
lift capacity of the pump.
[0026] FIG. 19 illustrates a pump as shown in FIG. 18 wherein a gas
dump is provided for the hydraulic control lines.
DETAILED DESCRIPTION
[0027] The present disclosure relates to a well pump where a
production tubing forms the pump housing, while an inner pump
system comprising, for example, pistons, check valves, etc., may be
installed and retrieved by light well intervention. Such a well
pump may provide significant cost savings in pump maintenance and
repair. Such a pump may provide ready access to the wellbore below
the pump for interventions such as well logging, among other
intervention operations. This may be of particular interest for
areas where heavy weight interventions, such as using a workover
rig or the like to pull out and rerun the production tubing are
very costly. Offshore small size production platforms, for example,
may be one application where workover rig cost is important. Also,
limited crane capacity, no cost efficient derrick available, etc.,
play a significant role in raising the cost. It should be noted
that the pump described in this disclosure also can be deployed in
a wellbore wherein the pump has an external housing, for example
connected to the lower end of a tubular hung into the wellbore,
where the tubular needs to be retrieved to surface to retrieve the
pump.
[0028] Also, this disclosure describes variations of a hydraulic
operated downhole pump, using one or two control lines from
surface, as well as being single-acting and dual-acting.
[0029] The present disclosure also describes how trapped gas in a
production fluid filled pump chamber can be released, to avoid or
minimize risk of gas locking. In addition, the present disclosure
describes how wellbore fluids can be kept and discharged from an
area below a dynamic seal, to minimize exposure of seals and
sealing area to abrasive particles, sand and debris.
[0030] FIG. 1 shows an example embodiment of a wellbore tubing 110
configured to receive components of a well fluid pump. The
components will be explained in more detail with reference to FIG.
3. In the present example embodiment, the wellbore 101 may be used
for producing gas. The pump may be used to lift produced water
accumulated proximate the bottom of the wellbore 101. This is
generally referred to as gas well dewatering or gas well
deliquification.
[0031] The wellbore 101 may comprise a casing or liner 100 to
hydraulically isolate formations outside the casing or liner 100,
and to maintain mechanical integrity of the wellbore 101. In the
present example embodiment a liner 100 extends from the bottom of
the wellbore 101 to above the bottom of a surface casing 104.
Perforations 102 may be made in the liner 100 within a formation
that produces hydrocarbons such as natural gas. The wellbore tubing
110 may extend to the surface of the wellbore 101. The wellbore
tubing 110 may comprise segments ("joints") shown at 110A and 110B
each having a polished interior surface for receiving the pump
components (FIG. 3). The upper polished joint 110A has an internal
diameter which may be substantially the same as all the tubing 110
above the upper polished joint 110A. The lower polished joint 110B
may be a smaller internal diameter than the upper polished joint
110A. The tubing 110 may comprise gas inflow ports 106 at a
longitudinal position above the pump components when such
components are locked in place inside the polished joints 110A,
110B.
[0032] A hydraulic control line 116 may be mounted on the exterior
of the wellbore tubing 110 and may extend from a source of
pressurized hydraulic fluid (not shown) at the surface to each of
two power fluid inflow ports 114. The power fluid inflow ports 114
are used to route hydraulic fluid under pressure to the pump
components described with reference to FIG. 3, where pressurized
hydraulic fluid drives a shaft/piston system (FIG. 3) to travel up
and down, resulting in the pumping of fluids to the surface through
a discharge tube 108 mounted externally on the tubing 110. The
discharge tube 108 may extend to the surface. The "housing" for the
pump comprises the upper 110A and lower 110B polished joints of
tubing.
[0033] The polished joints 110A, 110B may comprise well fluid
inflow ports 112 at a convenient location at the connection between
the upper 110A and lower 110B polished joints. As shown in FIG. 2,
the well fluid inflow ports 112 may comprise internal screens or
filters 118 to assist in excluding solids in the wellbore fluid
from being drawn into and possibly damaging the pump
components.
[0034] It should be understood that the gas inflow ports 106 could
be located higher up in the wellbore tubing than as illustrated in
FIG. 1 and FIG. 2. FIG. 2 also shows a possible embodiment wherein
an annular seal and liner hanger 120 is disposed in an annular
space between the surface casing 104 and the liner 100. FIG. 2 also
shows a possible embodiment wherein an annular space between the
tubing 110 and the interior of the liner 100 is sealed by an
annular seal or packer 122. The packer 122 may comprise through
ports for the hydraulic control line 116 and the discharge line
108.
[0035] The filter 118 may be installed and retrieved by, for
example wireline, when the well has been configured with wellbore
equipment as illustrated in FIG. 1. In other embodiments, a filter
may be incorporated within or externally on the well fluid inflow
ports 112.
[0036] FIG. 3 illustrates the pump components, i.e., a pump piston
and shaft assembly 300 that may comprise external seals. The pump
piston and shaft assembly 300 may be installed into a receiving
location within the polished tubing joints 110A, 110B, for example,
by wireline or slickline. The pump piston and shaft assembly 300
may be locked in place into the preinstalled pump receiver system
(i.e., polished tubing joints 110A, 110B by the component
containing a static piston and seal 306. Methods and apparatus for
locking a component into place in a wellbore are well known in the
art. One example may be the use of "jarring" (striking axially
downward onto the pump piston and shaft assembly 300 to lock the
static piston 306 in place, as well as shear loose (such as by
breaking shear pins) a piston shaft (301 in FIG. 4) from the static
piston 306 so that the piston shaft (301 in FIG. 4) can travel up
and down when hydraulic power fluid is applied to each of the power
fluid inflow ports (114 in FIG. 1). In some embodiments, the piston
assembly may not need to be mechanically locked in position,
because the hydrostatic pressure above the piston 302 may be
sufficient, in additional to hydraulically locking the shaft
assembly 300 in place by pressurizing the areas between the lower
three seal arrangements 304, 306 and 308.
[0037] FIG. 4 shows the piston and shaft assembly 300 in more
detail. The static piston 306 and its associated internal 306A and
external 306B seals is illustrated so that the function of the
static piston 306 can be better understood. The internal seal 306A
enables the shaft 301 to move up and down within the static piston
306 while preventing movement of fluid across the static piston 306
between the static piston 306 and the exterior of the shaft 301.
The shaft 301 may comprise a top dynamic piston 302 having an
external diameter and external seals 302A to engage the interior of
the upper polished joint (110A in FIG. 1). The shaft may comprise
an intermediate dynamic piston 304 having an external diameter and
seals 304A to sealingly engage an interior of the lower polished
joint (110B in FIG. 1). Between the top dynamic piston 302 and the
intermediate piston 304, the shaft may comprise a transverse flow
port 303 to enable entry of fluid from an annular space between the
top dynamic piston 302 and the intermediate dynamic piston 304 and
within the polished joints (110A, 110B in FIG. 1) into the
transverse flow port 303. The transverse flow port 303 is in fluid
communication with a longitudinal flow port 307 which extends
through the top dynamic piston 302. A check valve 305, such as a
ball and ball seat check valve may be disposed within the
longitudinal flow port 307 to constrain movement of fluid through
the top dynamic piston 302 to only one direction. A check valve
(not shown) may also be implemented in or externally to the fluid
intake ports (112 in FIG. 1), preventing wellbore fluids trapped
between seal stack 302 and 304 from exiting back to the
wellbore.
[0038] A lower dynamic piston 308 with associated external seals
308A may be disposed on the shaft 301 at or proximate the bottom
end of the shaft 301. Referring back to FIG. 3, when hydraulic
fluid is pumped into the one of the power fluid inflow ports 114,
for example, into the one of the power fluid inflow ports in
communication with an upper annular space 311, pressure is exerted
by the hydraulic fluid between the static piston 306 and the
intermediate dynamic piston 304. The exerted pressure causes the
shaft (301 in FIG. 4) to move upwardly. The top dynamic piston 302
moves correspondingly with the shaft (301 in FIG. 4). As the top
dynamic piston 302 moves upwardly with the shaft (301 in FIG. 4),
fluid in the wellbore tubing 110 above the top dynamic piston 302
is lifted because the check valve (305 in FIG. 4) will close. The
lifted fluid may enter the fluid discharge tube 108 wherein the
lifted fluid may move to the surface through the discharge tube
108. To reverse motion of the shaft (301 in FIG. 4), hydraulic
fluid may be pumped into the lower power fluid inflow port 114
thereby pressurizing an annular space 313 longitudinally disposed
between the lower dynamic piston 308 and the static piston 306.
Such pressure in the annular space 313 causes the lower dynamic
piston 308 to move downwardly; the shaft (301 in FIG. 4) moves
correspondingly. As the shaft moves downwardly, fluid may enter the
tubing 110 through the fluid inflow ports 112.
[0039] FIG. 5 illustrates that a wireline type plug 500 may be
installed above an entry port 108A to discharge tube 108, whereby
all fluid moved upwardly by the top dynamic piston 302 is
constrained to enter the discharge tube 108. The volume between the
wireline plug 500 and the top dynamic piston 302 on the piston and
shaft assembly 300 thereby creates a defined pump chamber for
wellbore fluids to be pumped towards the surface. The fluid
discharge port 108A or discharge tube 108 may also be coupled to a
check valve, preventing wellbore fluids flowing back to the
wellbore fluid chamber between the wireline plug 500 and the top
piston 302.
[0040] FIG. 6 shows that by alternatingly pressurizing the annular
spaces above 313 and below 311 the static piston 306, the piston
and shaft assembly 300 may be caused to move upwardly and
downwardly, thereby alternatingly enabling well fluid to flow into
the annular space between the intermediate dynamic piston 304 and
the top dynamic piston 302, and moving the fluid into the discharge
tube 108. As liquid is removed from the wellbore by operating the
piston and shaft assembly 300 as explained above, the hydrostatic
pressure bearing against the formation adjacent to the perforations
102 is correspondingly reduced. Reducing the hydrostatic pressure
may enhance the capacity of the formation to produce gas at 504,
wherein the gas may enter the tubing 110 through gas production
ports 106 disposed above the plug 500. Such gas may enter the
wellbore and flow upwardly in the annular space between the tubing
110 and the liner 100 (or casing if the wellbore is so
configured.
[0041] FIGS. 7A and 7B show another example embodiment of a pump
according to the present disclosure. The wellbore 101 may include a
casing or liner 100 and a surface casing 104, similar to the
wellbore shown in FIGS. 1 and 2. A wellbore tubing 110 may comprise
well fluid inflow ports 112 and upper 110A and lower 110B polished
joints of diameters as described with reference to FIG. 1. A pump
piston and shaft assembly 700 may be inserted into the wellbore
tubing 110 as explained with reference to FIGS. 3 and 4. In the
present example embodiment there may be two hydraulic control lines
116A and 116B each having a respective power fluid inflow port
114A, 114B.
[0042] First referring to FIG. 7A, the pump piston and shaft
assembly in the present example embodiment may comprise an upper
shaft 701 coupled to a lower shaft 701A. The lower shaft 701A may
have a similar outer diameter as the shaft shown in FIG. 4. The
lower shaft 701A passes through a static piston 706 with internal
and external seals substantially as explained with reference to
FIG. 4. The static piston 706 may be positioned in the tubing 110
such that the power fluid inflow ports 114A, 114B are disposed on
opposed sides of the static piston 706. An intermediate dynamic
piston 704 may be secured to the upper end of the lower shaft 701A.
When power fluid (e.g., hydraulic fluid) is applied alternatingly
to the power fluid inflow ports 114A, 114B, hydraulic pressure acts
to move the intermediate dynamic piston 704 (and the lower shaft
701A and upper shaft 701) upwardly, or the lower dynamic piston 708
(and the lower shaft 701A and upper shaft 701) downwardly. Motion
of the lower shaft 701A and upper shaft 701 is used to move an
upper dynamic piston 702 which may be configured substantially as
explained with reference to the upper dynamic piston explained with
reference to FIG. 4. In FIG. 7A, power fluid is applied to the
upper power fluid inflow port 114B, and the intermediate dynamic
piston 704 is moved upwardly as the power fluid pressurizes an
upper annular space 713. As the upper dynamic piston 702 moves
upwardly with the upper shaft 701, fluid may be moved through a
check valve 705 disposed in the tubing 110 above the piston and
shaft assembly 700. Thus in the embodiment of FIGS. 7A and 7B,
pumped fluid may be lifted through the tubing 110 to the surface.
At the same time, one or more integral check valve(s) 702A in the
upper dynamic piston may close, thereby enabling wellbore fluid to
be drawn into the wellbore fluid chamber between the upper piston
702 and the intermediate piston 704 below.
[0043] FIG. 7B shows the embodiment of FIG. 7A wherein power fluid
is applied through hydraulic control line 116A and into the lower
power fluid inflow port 114A, the hydraulic fluid pressure acts
against the lower dynamic piston 708, causing a lower annular space
711 to expand as the lower dynamic piston 708 is moved downwardly
against the hydraulic fluid pressure. The lower shaft 701A and
upper shaft 701 move downwardly corresponding to the downward
motion of the lower dynamic piston 708.
[0044] Another example embodiment of a pump which is dual acting is
shown in FIG. 8. The wellbore 101 may be configured with a liner
100, tubing 110 and surface casing 104 substantially as explained
with reference to FIG. 1. A piston and shaft assembly 800 may be
inserted into and locked in place within the tubing 110
substantially as explained with reference to FIG. 3. The piston and
shaft assembly 800 may comprise a shaft 801, an upper dynamic
piston 802, an intermediate dynamic piston 804, a static piston 806
and a lower dynamic piston 806 similar in configuration to the
shaft and piston assembly as explained with reference to FIGS. 3
and 4.
[0045] The fluid discharge line 108 in FIG. 8 may comprise an upper
inflow port 808A disposed longitudinally through the tubing 110 at
a position just below the place within the tubing 110 wherein a
dual opposed-polarity check valve 816 is disposed. The check valve
816 may be run into and set in place in the tubing 110, for
example, by wireline or slickline. One discharge port of the check
valve 816 is aligned with the upper inflow port 808A. One inlet
port of the check valve 816 is aligned with a well fluid inflow
port 809 coupled to an external well fluid inflow line 809A. A
lower fluid inflow port 808B of the fluid discharge line 108 may
penetrate the tubing 110 at a position just above the well fluid
inflow ports 112. The lower fluid inflow port 808B may comprise a
check valve 817 so that fluid flow is constrained to move only into
the discharge line 108 by the action of the piston and shaft
assembly 801 As power (hydraulic) fluid is alternatingly pumped
into each of the power fluid inflow ports 114, annular spaces 811,
813 on opposed sides of the static piston 806 are alternatingly
pressurized, thereby causing the piston and shaft assembly 801to
move alternatingly upwardly and downwardly. Upward motion of the
piston and shaft assembly 801 causes a first volume 822 disposed
below the upper dynamic piston 802 to expand, thus drawing well
fluid into the volume 822 through the well fluid inlet ports 112.
At the same time, a second volume 820 between the upper dynamic
piston 802 and the check valve 816 contracts, thus displacing the
wellbore fluid in the second volume 820 through the check valve 816
and into the discharge line 108 through the upper fluid inflow port
808A.
[0046] When motion of the piston and shaft assembly is reversed,
the second volume 820 expands, thereby drawing wellbore fluid into
the second volume 820 through the well fluid inflow port 809 from
the well fluid inflow line 809A. Correspondingly, the first volume
822 decreases, thereby causing check valves 821 in the well fluid
inflow ports 112 to close. The fluid is thus constrained to be
moved into the discharge line 108 through the lower well fluid
inflow port 808B. The check valve 816 prevents backflow of
discharged well fluid through the upper well fluid inlet port 808A,
thus the discharged wellbore fluid is constrained to move upwardly
through the discharge line. Gas produced from the formation may
enter the wellbore through gas production ports 106, substantially
as explained with reference to FIG. 6.
[0047] Another example embodiment of a well pump is shown in FIG.
9A. FIG. 9A, the pump piston and shaft assembly in the present
example embodiment may comprise an upper shaft 901 coupled to a
lower shaft 901A. The lower shaft 901A may have a similar outer
diameter as the shaft shown in FIG. 4. The lower shaft 901A passes
through a static piston 906 with internal and external seals
substantially as explained with reference to FIG. 4. The static
piston 906 may be positioned in the tubing 110 such that the power
fluid inflow ports 114A, 114B are disposed on opposed sides of the
static piston 906. An intermediate dynamic piston 904 may be
secured to the upper end of the lower shaft 901A. When power fluid
(e.g., hydraulic fluid) is applied alternatingly to the power fluid
inflow ports 114A, 114B, hydraulic pressure acts to move the
intermediate dynamic piston 904 (and the lower shaft 901A and upper
shaft 901) upwardly, or the lower dynamic piston 908 (and the lower
shaft 901A and upper shaft 901) downwardly. Motion of the lower
shaft 901A and upper shaft 901 is used to move an upper dynamic
piston 902 which may be configured substantially as explained with
reference to the upper dynamic piston explained with reference to
FIG. 7. In FIG. 9A, power fluid is applied to the upper power fluid
inflow port 114B, and the intermediate dynamic piston 904 is moved
upwardly as the power fluid pressurizes an upper annular space (713
in FIG. 7A). As the upper dynamic piston 902 moves upwardly with
the upper shaft 901, a second volume 920 between the upper dynamic
piston 902 and the check valve 905 contracts, such that wellbore
fluid may be moved through a check valve 905 disposed in the tubing
110 above the piston and shaft assembly 900. Thus in the embodiment
of FIG. 9A, pumped fluid may be lifted through the tubing 110 and
into an upper fluid discharge line inflow port 908A. The upper
dynamic piston 902 may comprise integral check valve(s) 902A such
that when the second volume 920 contracts, and a volume below the
upper dynamic piston 902 expands, well fluid may be drawn into the
volume below the upper dynamic piston through the well fluid inflow
ports 112. The drawn in wellbore fluid moves past the upper dynamic
piston 902 into the second volume 920 through the integral check
valve(s) 902A to be discharged through the check valve 905 and into
the tubing 110 as explained above.
[0048] As the piston and shaft assembly 900 is moved downwardly, a
first volume 922 disposed between the lower dynamic piston 908 and
a dual check valve sub 909 contracts. Fluid in the first volume 922
is constrained by the dual check valve sub 909 to move into the
well fluid discharge line 108. In the present example embodiment,
the well fluid discharge line 108 extends to a discharge fluid port
908A in the tubing 110 above the position of the check valve 905.
When the piston and shaft assembly 900 moves upwardly, the first
volume 922 expands, thus drawing wellbore fluid into the first
volume through the dual check valve sub 909. Accordingly, the
example embodiment of the wellbore pump shown in FIG. 9A is dual
acting.
[0049] FIG. 9B shows another embodiment of a wellbore pump similar
to that shown in FIG. 9A. The embodiment of FIG. 9B comprises a
well fluid discharge sub (with integral check valve) 909A coupled
to the exterior of the tubing 110 such that discharged fluid from
the contracting first volume (922 in FIG. 9A) moves into the well
fluid discharge line 108. When the first volume (922 in FIG. 9A)
expands, wellbore fluid may be drawn into the first volume through
a replaceable (e.g., by wireline or slickline) intake check valve
909B disposed in the tubing 110 below the lower dynamic piston (908
in FIG. 9A). In other respects, the wellbore pump shown in FIG. 9B
works substantially the same as the wellbore pump shown in FIG. 9A,
but enables full bore through tubing access with wireline or
slickline tools, etc. by having all pump components and check valve
assemblies retrievable by, e.g., wireline or slickline first.
[0050] FIGS. 10 and 11 show another embodiment of a hydraulically
operated wellbore pump that may be retrofit into an existing
wellbore casing. A pump piston 1009 moves upwardly and downwardly
inside a pump housing 1001. An inlet to a pump chamber formed
between the pump piston 1009 and the housing 1001 is shown at 1002.
A check valve 1008 closes on downward movement of the pump piston
1009 and opens on upward movement thereof. Well fluid may enter the
pump 1000 through a check valve controlled fluid inlet 1002. Power
fluid may be alternatingly applied to two power fluid ports 1004,
1006 to create pressure on opposed sides of a power piston 1014.
The power piston may be coupled to the pump piston 1009 through an
operating rod 1012. Thus, reciprocation of the power piston 1014
results in reciprocation of the pump piston 1009, thereby lifting
wellbore fluid upwardly toward the surface. FIG. 10 shows the pump
1000 in its downstroke end position. FIG. 11 shows the pump 1000 in
its upstroke position.
[0051] FIG. 12 shows his shows a single power line hydraulic pump
which uses hydrostatic head of the fluid column to return the
dynamic pump assembly (power piston 1014 and operating rod 1012)
down. Well fluid path is the same as for the pump shown in FIG. 10
and FIG. 11. Due to the location of the standing valves and a hole
1012A in the operating rod 1012, an additional area and therefore
force helps to push the power piston 1014 downward when hydraulic
control pressure is relieved from the power fluid inlet port
1006.
[0052] FIGS. 13A through 13E show another example embodiment of a
hydraulically operated wellbore pump. In the present example
embodiment, and with reference to FIG. 13A, the wellbore pump 1300
may be coupled at one longitudinal end to a lower end of a wellbore
tubing 1302. The wellbore tubing 1302 may be jointed tubing, coiled
tubing or any other suitable conduit for conducting pumped fluids
1301 from a wellbore (e.g., 101 in FIG. 1) to the surface. A tubing
extension 1302A may be coupled to the other longitudinal end of the
wellbore pump 1300.
[0053] The wellbore pump 1300 may be attached to the lower end of
the wellbore tubing 1302 by an adapter or crossover sub 1304. The
crossover sub 1304 may be connected to one end of a pump housing
1300A. The other end of the pump housing 1300A may be coupled to
one end of a pump power chamber 1305. The pump power chamber 1305
may comprise a power chamber cylinder 1305A coupled to a lower end
of the pump housing 1300A by an upper power chamber adapter 1324A.
A lower end of the power chamber cylinder 1305A may be coupled to a
tubing extension 1302A by a lower power chamber adapter 1324B. The
tubing extension 1302A may comprise fluid inflow ports 1307
disposed at an axial position above the lower end of a fluid intake
tube 1306A.
[0054] The pump power chamber 1305 may comprise a power piston 1310
that sealingly engages an interior wall of the pump power chamber
cylinder 1305A. Hydraulic fluid under pressure may be provided
alternatingly to each of a lower hydraulic control line 1318A
coupled to the pump power chamber cylinder 1305A to a position
below the power piston 1310. In the present example embodiment,
hydraulic fluid pumped through the lower hydraulic control line
1318A may enter the pump power chamber cylinder 1305A through a
lower power fluid inlet 1318B coupled to suitable passageways
formed in the lower power chamber adapter 1324B. Correspondingly,
an upper hydraulic control line 1316A may provide pressurized
hydraulic fluid to a position above the power piston 1310, for
example, through an upper power fluid inlet 1316B with suitable
fluid passageways formed unto the upper power chamber adapter
1324A.
[0055] The fluid intake tube 1306A may sealingly pass through the
power piston 1310 and be attached to the power piston such that
movement of the power piston 1310 as a result or pressurizing each
of the hydraulic control lines 1316A, 1318A will cause the fluid
intake tube 1306A to move correspondingly. FIG. 13A shows the power
piston 1310 in the downwardmost position.
[0056] The fluid intake tube 1306A may be attached to a pump piston
1308 disposed in the pump housing 1300A. The pump piston 1308 may
divide the interior of the pump housing 1300A into an upper pump
chamber 1301A and a lower pump chamber 1301B.
[0057] When hydraulic fluid 1317 is supplied to the upper hydraulic
control line 1316A, causing the power piston 1310 to move
downwardly, the intake tube 1306A and the pump piston 1308 move
correspondingly, thereby decreasing the volume of the lower pump
chamber 1301B. The pump piston 1310 may comprise internal fluid
passages 1308C and check valves 1308A, 1308B, 1308D arranged such
that downward motion of the pump piston 1310 will cause fluid in
the lower pump chamber 1301B to move into the passages 1308C in the
pump piston 1310 and to be discharged through an upper discharge
tube 1306. The upper discharge tube 1306 may extend longitudinally
through the crossover sub 1304 and be sealingly engaged with the
crossover sub 1304. Fluid 1301 discharged through the upper
discharge tube 1306 may be constrained to move upwardly through the
wellbore tubing 1302 by the action of a check valve 1304A in the
crossover sub 1304.
[0058] Conversely, when the power piston 1310 is caused to move
upwardly by application of hydraulic power fluid 1317 to the lower
power fluid inlet 1318B, the fluid intake tube 1306A, power piston
1310, pump piston 1308 and upper discharge tube 1306 move
correspondingly. Thus, the upper pump chamber 1301A volume
decreases. One of the check valves 1308A in the pump piston 1308
constrains the fluid in the upper pump chamber 1301A from entering
the upper discharge tube 1306. At the same time, the fluid in the
upper pump chamber 1301A may move through the check valve 1304A in
the crossover sub 1304 and thus move into the wellbore tubing 1302.
As the lower pump chamber 1301B expands correspondingly, other
check valves 1308D, 1308B in the pump piston 1310 enable wellbore
fluid to be drawn into the lower pump chamber 1301B through the
fluid intake tube 1306A.
[0059] By positioning well fluid inlet ports 1307 in the tubing
extension 1302A above the position of the fluid intake tube 1306A,
a solids trap 1320 may be formed. Solids may tend to settle by
gravity and thus may be largely excluded from entering the fluid
intake tube 1306A. A guide nose 1322 may be used on the end of the
tubing extension 1302A in some embodiments.
[0060] FIG. 13B shows the power piston 1310 being moved upwardly
and corresponding discharge of wellbore fluid from the upper pump
chamber 1301A through the check valve 1304A in the crossover sub
1304 and into the wellbore tubing 1302.
[0061] FIG. 13C shows the power piston 1310 close to its upwardmost
position. FIG. 13D shows the power piston 1310 being moved
downwardly, with corresponding discharge of fluid from the lower
pump chamber 1301B into the upper discharge tube 1306, and thus
into the wellbore tubing 1302.
[0062] FIG. 14 shows the pump piston 1308 of the present example
embodiment in more detail. The pump piston may comprise a fluid
passageway 1308E to the fluid intake tube 1306A, wherein check
valves 1308A, 1308D constrain movement of fluid from the fluid
intake tube 1306A to flow into the upper pump chamber 1301A or the
lower pump chamber 1301B depending on which pump chamber is
expanding. A fluid passage 1308F connects the upper discharge tube
1306 using a check valve 1308B to the upper pump chamber 1301A when
its volume is reduced, thus moving wellbore fluid in the upper pump
chamber 1301A into the upper discharge tube 1306. Correspondingly,
downward movement of the pump piston 1310 will cause the check
valves 1308A, 1308B, 1308D to move fluid from the lower pump
chamber 1301B through the pump piston 1308 and into the upper pump
chamber 1301A, where the fluid will be discharged through the check
valve 1304A in the crossover sub 1304.
[0063] Another embodiment of a hydraulically operated pump is shown
in FIGS. 15A and 15B. Referring to FIG. 15A, a pump power piston
and pump piston assembly 1500 is shown and includes a piston rod
1500B having fluid seals 1500A disposed at a longitudinal position
intermediate an upper pump piston 1502 having seals 1502A on its
exterior surface and a lower pump piston 1504 having seals on its
exterior surface 1504A coupled to the longitudinal ends of the
piston rod 1500B.
[0064] FIG. 15B shows the pump power piston and pump piston
assembly 1500 disposed in a pump body 1510 to form a wellbore fluid
pump 1530. The pump body 1510 includes an upper cylinder 1518A and
a lower cylinder 1518B disposed on opposed longitudinal sides of a
center passage 1510A through which the piston rod 1502 may move.
Movement of the pump power piston and pump piston assembly 1500
within the pump body 1510 may be caused by pumping hydraulic fluid
under pressure through a first control line 1516A that connects to
the upper cylinder 1518A between the fluid seals 1500A and the
bottom of the upper piston 1502. Correspondingly, motion of the
pump power piston and pump piston assembly in the other direction
may be caused by supplying hydraulic fluid under pressure to the
lower cylinder 1518B through a second control line 1516B.
[0065] Each of the upper pump piston 1502 and the lower pump piston
1504 may comprise wiper seals, 1502A and 1504B, respectively.
Longitudinal ends of the pump body 1510 and the corresponding pump
pistons 1502, 1504 may define an upper pump chamber 1510A and a
lower pump chamber 1510B. A fluid intake for the lower pump chamber
1510B may be provided through a check valve 1520 which will admit
fluid to the lower pump chamber 1510B when it is expanded. The
check valve 1520 may cause fluid to be constrained to move through
a discharge line 1518, through a check ball 1514 and into the
wellbore tubing 110. Correspondingly, the upper pump chamber 1510A
may have a fluid intake line 1522 and a discharge through a port
1512 having a check ball 1512A therein. Enlargement and reduction
of the volume of the upper pump chamber 1510A by corresponding
motion of the upper piston 1502 will cause fluid to be drawn into
the upper pump chamber 1510A and discharged therefrom,
respectively.
[0066] FIGS. 16A through 16E show the wellbore fluid pump 1530
explained with reference to FIGS. 15A and 15B in various stages of
its operation to illustrate the operation of the wellbore fluid
pump 1530. In FIG. 16A, the power piston and pump piston assembly
(1500 in FIG. 15A) is being moved downwardly by the action of
hydraulic fluid. Arrows show the respective movements of fluid
into, through and out of the sections of the wellbore fluid pump
1530 as explained with reference to FIG. 15B. FIG. 16B shows the
wellbore fluid pump power piston and pump piston assembly (1500 in
FIG. 15A) continues to be moved downwardly by the action of
hydraulic fluid. In FIG. 16C, the power piston and pump piston
assembly (1500 in FIG. 15A) is at its lowermost position. FIG. 16D
shows the power piston and pump piston assembly (1500 in FIG. 15A)
being moved upwardly by the action of hydraulic fluid under
pressure. Finally, FIG. 16E shows the power piston and pump piston
assembly (1500 in FIG. 15A) again in its upwardmost position.
[0067] FIG. 17A through 17C illustrate a wellbore fluid pump where
produced fluids are discharged from the bottom of the pump, and
where there is a function built in to dump any trapped gas from the
pump chamber. This pump design may also ensure that solids, e.g.,
debris and sand within the produced fluids are kept below dynamic
pump piston areas to increase the lifetime of fluid pressure seals
and the surrounding sealing surfaces. A travelling power piston has
a bore through it from its lower end and a relief valve included in
the top of the power piston. In the case of gas being trapped
within the wellbore fluid pump chamber, hydraulic power fluid
pressure on the one of the control lines used to move the power
piston upward in its bore is increased to a pressure higher than
ordinary operating pressure after the power piston reaches the
upper end of the piston bore. This increased pressure lifts the
relief valve followed by opening a valve in a pump coupling
disposed above the pump chamber, causing any trapped gas to exit
from the pump chamber, through the piston assembly and the relief
valves, and then into the tubular above the pump.
[0068] Referring first to FIG. 17A the wellbore fluid pump 1700 may
comprise a pump housing 1706. The pump housing 1706 may have a
substantially cylindrical bore 1706A on its interior surface. An
upper end of the pump housing 1706 may be coupled to a wellbore
tubing 110 by an upper adapter 1704. The upper adapter 1704 may
comprise a seat 1714A for a ball type check valve 1714. The upper
adapter 1704 may comprise an internal passage 1704B formed therein
which connects a pumped fluid discharge line 1712 to the interior
of the ball seat 1714A. When fluid is discharged through the pumped
fluid discharge line 1712, such fluid flows through the internal
passage 1704B to the ball seat 1714A and then flows upwardly
through the wellbore tubing 110 to the surface.
[0069] A power chamber may be defined within the pump housing 1706
longitudinally between the connection of the pump housing 1706 to
the upper adapter 1704, and a power fluid inlet port 1717 through
the wall of the pump housing 1706. A part of the pump housing 1706
corresponding to the power chamber may have an enlarged internal
diameter section 1706A corresponding to the length of the power
chamber. A piston 1710 may be disposed within the pump housing
1706. An upper end of the piston 1710 may be in fluid communication
with hydraulic power fluid that is moved under pressure into the
pump housing 1706 above the top of the piston 1710 through a power
fluid passage 1704C in the upper adapter. A first hydraulic control
line 1716A is coupled to the power fluid passage 1704C to enable
moving the piston 1710 downwardly in the pump housing 1706 by
applying power fluid, e.g., hydraulic fluid under pressure to the
power fluid passage 1704C. The bottom end of the piston 1710 may
comprise a wiper 1720 or similar fluid seal. A pump chamber 1708
may be defined between the bottom end of the piston 1710 within the
pump housing 1706 and a lower adapter 1720 coupled to the lower end
of the pump housing 1706.
[0070] The lower adapter 1720 may include an intake check valve
1720A and a discharge check valve 1720B. As indicated by the arrow
in the pump chamber 1720, when the piston 1710 is moved downwardly,
the pump chamber decreases in volume and fluid flow opens the
discharge check valve 1720B wherein discharged fluid enters the
fluid discharge line 1712 and eventually into the wellbore tubing
110 through the upper adapter 1704 as explained above. The intake
check valve 1720A closes during downward movement of the piston
1710. When hydraulic fluid under pressure is moved through a second
hydraulic control line 1716B to the lower power fluid inlet port
1717, the piston 1710 is moved upwardly by such hydraulic fluid
pressure. As the piston 1710 is moved upwardly, the intake check
valve 1720A opens and the discharge check valve 1720B closes,
enabling wellbore fluid to be drawn into the pump chamber 1720 by
increasing the volume of the pump chamber 1720.
[0071] The piston 1710 has a bore 1710B through it from its upper
end to a position on the exterior surface of the piston below
dynamic seals 1710C on the piston 1710. The bore comprises a relief
valve 1710A in the bore 1710B proximate the top of the piston 1710.
In the case of gas being trapped within the power chamber,
hydraulic power fluid pressure on second control line 1716B (used
to move the piston 1710 upward in the pump housing 1706) is
increased to a pressure higher than ordinary operating pressure
after the piston 1710 reaches the upper end of the pump housing
1706. This increased pressure lifts the relief valve 1710 followed
by opening a corresponding relief valve 1704A in the upper adapter
1704, causing any trapped gas to exit from the power chamber,
through the piston 1710 and the relief valves 1710A, 1704A, and
then into the tubular, e.g., the tubing 110 above the upper adapter
1704.
[0072] FIG. 17B shows the piston 1710 being moved downwardly by
applying hydraulic fluid under pressure to the first control line
1716A to discharge fluid from the pump chamber 1720. FIG. 17C shows
the piston 1710 at its downwardmost position, whereupon hydraulic
fluid under pressure is provided to the second control line 1716B
to cause the piston 1710 to move upwardly. Upward movement of the
piston 1710 will expand the pump chamber 1720 to draw wellbore
fluids into the pump chamber 1720 through the intake check valve
1720A.
[0073] In some embodiments, a guide nose 1720C may be coupled to
the bottom of the lower adapter 1720.
[0074] Additional features of a well fluid pump as explained above
with reference to FIGS. 17A through 17C will now be explained with
reference to FIGS. 17D through 17H.
[0075] Referring first to FIG. 17D, hydraulic control pressure
applied to the power piston 1717 may be conducted to the radial
clearance 1708B at the dynamic pump piston 1708. The hydraulic
fluid may move through a hole 1708A in the shaft 1710C and a small
flow restriction device 1708D which allows a small volume of
pressurised fluid to flow across the outer diameter of the pump
piston 1708. The hydraulic fluid under pressure helps to flush any
debris away from the pump cylinder bore 1708E and also act as a
hydrostatic radial bearing. FIG. 17E shows a helical groove 1708F
formed on the outer diameter of the pump piston 1708 to assist full
cleaning of the pump cylinder bore 1708E.
[0076] Two different arrangements may be used in some embodiments.
One embodiment may use a conventional metal plunger with only a
metal to metal clearance. Some embodiments may use elastomeric
seals or the like, located axially at each side of the discharge
port, externally to the pump piston 1708.
[0077] Hydraulic fluid pressure feed to the clearance (1708B in
FIG. 17D) may be on the downstroke to ensure positive pressure
inside a seal chamber to ensure any solids are pushed out and
therefore may help to decrease wear on the pump components.
[0078] Referring to FIG. 17F, to improve reliability an
intermediate seal chamber 1750 may be located between the power
fluid chamber 1752 and pump chamber 1708. This provides clean fluid
that acts as a further buffer to prevent contaminated fluid
entering the power fluid chamber 1752 and associated components,
including power piston 1710. A recirculation line located on the
outer diameter of the pump allows fluid to recirculate during each
stroke. An alternative arrangement uses gas in this chamber.
[0079] The recirculation line is shown at 1756 in FIG. 17G. The
recirculation line 1756 may be formed in a chamber separation
bulkhead 1758 disposed between the power fluid chamber (1752 in
FIG. 17F) and the intermediate seal chamber 1750.
[0080] Referring to FIG. 17H, the power chamber 1752 in some
embodiments may have a smaller diameter than the pump chamber 1708.
This enables much lower flow pressure to the power fluid chamber
1752 and also helps with respect to fluid conduit sizes and
friction loss due to power fluid flow. Surface pump requirements
and cost are major factors in the design.
[0081] FIG. 18 shows a pump 1800 as illustrated in FIG. 17A, where
the pump 1800 is extended by adding a second pump 1800A configured
as explained with reference to FIG. 17A. Such addition may be made
by substituting the lower adapter (1720 in FIG. 1) with another
upper adapter 1804A (as explained with reference to FIG. 17A) on
the bottom of the pump housing 1806. The second pump 1800A may be
connected to the second upper adapter 1804A. The bottom of the
second pump housing 1806A may have a lower adapter 1820 attached
thereto as explained with reference to FIG. 17A. Such arrangement
will double the fluid lift capacity of the pump. Also the lower
chamber incorporates a trapped gas release function as described
with reference to FIG. 17A. One or several additional pumps as
illustrated can be coupled the same way (using additional upper
adapters) in series below the upper pump 1800 for further fluid
lift capability.
[0082] FIG. 19 illustrates a pump similar to the pump as explained
with reference to FIGS. 17A, 17B and 17C, where produced wellbore
fluids are introduced into a chamber below a traveling piston. FIG.
19 illustrates that in the case where it is detected, determined or
suspected that gas is trapped in a wellbore fluid chamber (1708 in
FIG. 17A), both the second control line (1716B in FIG. 17A) as well
as the first control line (1716A) can be pressurized at the same
time. Such pressurization will cause a high pressure bleed valve
1822, set to an opening pressure larger than maximum operating
pressure for moving the main pump piston (1710 in FIG. 17A), to
open a bleed port from where the gas is present, to the outside of
the pump.
[0083] The foregoing function can be implemented with the pump
piston pushing wellbore fluids down as illustrated in FIG. 19, as
well as in pumps with a piston that push wellbore fluids
upwards.
[0084] Also illustrated is a function where pump power fluid can be
used to flush clean the wellbore fluid chamber, by pressurizing the
first control line (1716A in FIG. 17A) at a higher pressure than
the pump operating pressure, so that a valve 1903 within the pump
piston 1710 opens, allowing clean fluid at a high velocity to flow
into the wellbore fluid chamber and exit through the discharge
port. This valve 1903 can be mounted at any location in the piston
1710.
[0085] Although only a few examples have been described in detail
above, those skilled in the art will readily appreciate that many
modifications are possible in the examples. Accordingly, all such
modifications are intended to be included within the scope of this
disclosure as defined in the following claims.
* * * * *