U.S. patent application number 14/564685 was filed with the patent office on 2015-06-11 for plunger lift systems and methods.
The applicant listed for this patent is BIG GREEN TECHNOLOGIES INC.. Invention is credited to ROBERT W. HUGHES.
Application Number | 20150159473 14/564685 |
Document ID | / |
Family ID | 53270635 |
Filed Date | 2015-06-11 |
United States Patent
Application |
20150159473 |
Kind Code |
A1 |
HUGHES; ROBERT W. |
June 11, 2015 |
PLUNGER LIFT SYSTEMS AND METHODS
Abstract
Methods and systems for increasing the length of time of
effectiveness for the plunger lifting liquid load from a gas well,
by allowing the plunger to stay ahead of the liquid inflow into the
wellbore. The methods and systems involve a plunger control logic
which uses measurements of the liquid load pressure, the casing
pressure, the line pressure, and the tubing pressure to time the
opening and closing of various valves, in order to optimize the
lifting of the liquid load to surface.
Inventors: |
HUGHES; ROBERT W.; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
BIG GREEN TECHNOLOGIES INC. |
Calgary |
|
CA |
|
|
Family ID: |
53270635 |
Appl. No.: |
14/564685 |
Filed: |
December 9, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61913737 |
Dec 9, 2013 |
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Current U.S.
Class: |
166/250.01 |
Current CPC
Class: |
F04B 47/12 20130101;
E21B 43/121 20130101 |
International
Class: |
E21B 43/12 20060101
E21B043/12; E21B 41/00 20060101 E21B041/00; E21B 47/06 20060101
E21B047/06 |
Claims
1. A method of producing liquid load from a horizontal section of a
well having a casing in its vertical section, the horizontal
section and the vertical section being connected by a heel, and the
well having a plunger lift system installed therein, the plunger
lift system comprising: a tubing string with an upper end and a
lower end, and having a plunger slidably movable therebetween, the
tubing string and the casing defining a casing string therebetween,
the tubing string being in fluid communication with a line via a
tubing valve, the tubing string disposed in the vertical section,
with its lower end at or near the heel and having an inlet, the
tubing string having a tubing pressure and the line having a line
pressure, and the casing string being in fluid communication with
the line via a casing valve, the casing string having a casing
pressure, the method comprising: (a) keeping the tubing valve and
the casing valve closed for an initial off time; (b) determining a
potential energy pressure at the expiry of the initial off time;
(c) opening tubing valve for a pre-set time; (d) comparing a
plunger arrival time with a preselected range and: (i) keeping the
tubing valve open if the plunger arrival time is within the
preselected range; (ii) reducing an after-flow time if the plunger
arrival time is above the preselected range; or (iii) increasing
the after-flow time if the plunger arrival time is below the
preselected range; (e) closing the tubing valve at the expiry of
the after-flow time; (f) determining a liquid load pressure; (g)
keeping the tubing valve and the casing valve closed for the
initial off time; (h) opening the tubing valve partially when the
difference between the casing pressure and the line pressure is
substantially equal to the potential energy pressure, and keeping
the tubing valve open for a pre-set burping time; (i) closing the
tubing valve at the expiry of the pre-set burping time; (j) opening
the tubing valve when the difference between the casing pressure
and the line pressure is substantially equal to the potential
energy pressure; and (k) comparing the plunger arrival time with
the preselected range and: (i) reducing the pre-set burping time
and/or increasing a potential energy pressure time, if the plunger
arrival time is above the preselected range; (ii) increasing the
liquid load pressure and/or pre-set burping time, if the plunger
arrival time is below the preselected range; or (iii) comparing the
casing pressure with a flowing clean casing pressure or a lowest
recorded casing pressure, if the plunger arrival time is within the
preselected range.
2. The method of claim 1 further comprising repeating steps (a) to
(f) until the plunger arrival time is within the preselected range
for at least five consecutive cycles.
3. The method of claim 1 further comprising comparing a load
allowed pressure with a load allowed set point, if the casing
pressure is substantially equal to the flowing clean casing
pressure or the lowest recorded casing pressure.
4. The method of claim 3 further comprising closing the tubing
valve when the load allowed pressure is substantially equal to the
load allowed set point.
5. The method of claim 1 further comprising throttling open the
casing valve if the casing pressure is substantially equal to the
flowing clean casing pressure or the lowest recorded casing
pressure.
6. The method of claim 5 further comprising closing the casing
valve when the casing pressure is substantially equal to a casing
pressure rise set point.
7. The method of claim 6 further comprising closing the tubing
valve when a load allowed pressure is substantially equal to a load
allowed set point.
8. The method of claim 4 further comprising repeating steps (a) to
(k).
9. The method of claim 7 further comprising repeating steps (a) to
(k).
10. The method of claim 1 wherein the inlet is a standing
valve.
11. The method of claim 1 wherein the inlet is a siphon string
extending into at least a portion of the horizontal section.
12. The method of claim 1 further comprising monitoring the liquid
level in the well.
13. The method of claim 11 wherein the plunger lift system further
comprises a liquid level monitor.
Description
PRIORITY APPLICATION
[0001] This application claims priority to U.S. provisional
application Ser. No. 61/913,737, filed Dec. 9, 2013.
FIELD OF THE INVENTION
[0002] The invention relates to plunger lift systems and methods
for liquid production in a gas well, particularly a deviated or
horizontal gas well.
BACKGROUND OF THE INVENTION
[0003] Plunger lift systems have been used in vertical natural gas
wells to produce liquid when gas production is compromised by
liquid loading. These plunger lift systems are utilized to
artificially lift and extract liquid out of a gas well (at surface)
once flow rates decline below critical rates resulting in decreased
gas production.
[0004] Critical rate is generally defined as the minimum flow rate
below which liquids cannot be continually produced (brought to
surface) in a gas well. If these liquids are not lifted to surface,
they settle in the wellbore, thus restricting and impeding the
production of natural gas as the gas has to "bubble flow" through
the liquids. At this point, the well is in a liquid loading stage.
If not dealt with, liquid loading will increase hydrostatic back
pressure on the reservoir and reduce the near well gas relative
permeability, leading to progressively reduced gas production from
the well or even the inability to produce gas (in economical
volumes). Artificial lift methods need to be utilized to decrease
liquid loading and achieve increased gas production.
[0005] Due to continual reduction of reservoir pressure in a
producing well, the majority of gas wells will eventually achieve a
liquid loading state and, in turn, will require intervention and
deployment of artificial lift production techniques to re-establish
higher natural gas production rates.
[0006] FIG. 1 depicts a typical production depletion curve
associated with gas wells, and some recognized technologies and
techniques used to enhance production are described with reference
to FIG. 1. FIG. 1 shows two curves: an actual decline curve of a
gas well ("DC.sub.A") and a natural decline curve of the gas well
("DC.sub.N"). IG denotes the incremental gain in production
required to bring the well from DC.sub.A to DC.sub.N.
[0007] At stage 20, the gas well is a free flowing gas well
("FFGW"), which is the initial stage of the gas well that has been
brought on to production. Production is either with casing
production only or with a tubing production string installed upon
initial well completion.
[0008] At or around stage 22, switching valve technology ("SVT") is
used to enable the well to (i) produce up the casing and tubing
simultaneously, (ii) shut in tubing and flow casing, or (iii) shut
in casing and flow tubing. If the tubing production string is not
installed at stage 20, the tubing production string is installed
subsequently to utilize SVT.
[0009] At or around stage 24, SVT with stop cocking ("SVTSC") may
be used to allow the well to close the tubing and casing
simultaneously, thereby enabling the well to build up energy to
lift liquids when the tubing or casing valves are opened.
[0010] At or around stage 26, SVT with plunger lift optimization
technology ("SVTPLOT") allows SVT to be used with a plunger lift
system, which is installed in the tubing production string at or
around stage 26.
[0011] At or around stage 28, plunger lift optimization technology
("PLOT") enables the well to only flow up the tubing string. In
this embodiment, the casing valve is closed as the casing is only
used to allow the well to build up potential energy once the well
is closed.
[0012] At or around stage 30, artificial lift technology ("ALT"),
e.g. down hole pumps, is used to lift liquid when the well requires
excessive shut in time to build up potential energy to lift the
liquid and the plunger.
[0013] In FIG. 1, liquid loading starts in a gas well once the flow
rate falls below the critical rate for that particular gas well
configuration. It is therefore important to understand the degree
of liquid loading by measuring the hydrostatic pressure produced
from the build-up of liquid.
SUMMARY OF THE INVENTION
[0014] In accordance with an aspect of the present invention, there
is provided a method of producing liquid load from a horizontal
section of a well having a casing in its vertical section, the
horizontal section and the vertical section being connected by a
heel, and the well having a plunger lift system installed therein,
the plunger lift system comprising: a tubing string with an upper
end and a lower end, and having a plunger slidably movable
therebetween, the tubing string and the casing defining a casing
string therebetween, the tubing string being in fluid communication
with a line via a tubing valve, the tubing string disposed in the
vertical section, with its lower end at or near the heel and having
an inlet, the tubing string having a tubing pressure and the line
having a line pressure, and the casing string being in fluid
communication with the line via a casing valve, the casing string
having a casing pressure, the method comprising:
[0015] (a) keeping the tubing valve and the casing valve closed for
an initial off time;
[0016] (b) determining a potential energy pressure at the expiry of
the initial off time;
[0017] (c) opening tubing valve for a pre-set time;
[0018] (d) comparing a plunger arrival time with a preselected
range and: (i) keeping the tubing valve open if the plunger arrival
time is within the preselected range; (ii) reducing an after-flow
time if the plunger arrival time is above the preselected range; or
(iii) increasing the after-flow time if the plunger arrival time is
below the preselected range;
[0019] (e) closing the tubing valve at the expiry of the after-flow
time;
[0020] (f) determining a liquid load pressure;
[0021] (g) keeping the tubing valve and the casing valve closed for
the initial off time;
[0022] (h) opening the tubing valve partially when the difference
between the casing pressure and the line pressure is substantially
equal to the potential energy pressure, and keeping the tubing
valve open for a pre-set burping time;
[0023] (i) closing the tubing valve at the expiry of the pre-set
burping time;
[0024] (j) opening the tubing valve when the difference between the
casing pressure and the line pressure is substantially equal to the
potential energy pressure; and
[0025] (k) comparing the plunger arrival time with the preselected
range and: (i) reducing the pre-set burping time and/or increasing
a potential energy pressure time, if the plunger arrival time is
above the preselected range; (ii) increasing the liquid load
pressure and/or pre-set burping time, if the plunger arrival time
is below the preselected range; or (iii) comparing the casing
pressure with a flowing clean casing pressure or a lowest recorded
casing pressure, if the plunger arrival time is within the
preselected range.
[0026] It is to be understood that other aspects of the present
invention will become readily apparent to those skilled in the art
from the following detailed description, wherein various
embodiments of the invention are shown and described by way of
illustration. As will be realized, the invention is capable for
other and different embodiments and its several details are capable
of modification in various other respects, all without departing
from the spirit and scope of the present invention. Accordingly the
drawings and detailed description are to be regarded as
illustrative in nature and not as restrictive.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] Referring to the drawings, several aspects of the present
invention are illustrated by way of example, and not by way of
limitation, in detail in the figures, wherein:
[0028] FIG. 1 is an exemplary graph showing the typical decline of
production in a gas well;
[0029] FIG. 2 is a schematic view of the system according to one
embodiment of the present invention;
[0030] FIG. 3 is a front view of a sample wellhead enclosure;
[0031] FIG. 4 is a flow chart of a timer mode phase according to an
embodiment of the present invention;
[0032] FIG. 5 is a flow chart of a "burping" process according to
an embodiment of the present invention;
[0033] FIG. 6 is a schematic view of the system during the
"burping" process;
[0034] FIG. 7 is a schematic view of the system wherein the well is
shut in;
[0035] FIG. 8 is a schematic view of the system wherein the well is
producing;
[0036] FIG. 9a is a liquid load production method according to one
embodiment of the present invention;
[0037] FIG. 9b is a liquid load production method according to
another embodiment of the present invention; and
[0038] FIG. 10 is a schematic view of a system according to another
embodiment of the present invention.
DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS
[0039] The description that follows and the embodiments described
therein, are provided by way of illustration of an example, or
examples, of particular embodiments of the principles of various
aspects of the present invention. These examples are provided for
the purposes of explanation, and not of limitation, of those
principles and of the invention in its various aspects. In the
description, similar parts are marked throughout the specification
and the drawings with the same respective reference numerals. The
drawings are not necessarily to scale and in some instances
proportions may have been exaggerated in order more clearly to
depict certain features.
[0040] Measuring the hydrostatic pressure of the liquid load and
lifting the liquid load to surface with a plunger lift system
enables the plunger to stay ahead of the liquid inflow into the
wellbore, thus increasing the length of time of effectiveness for
the plunger lift system. To optimize this, the plunger lift system
is preferably controlled from above ground using control algorithms
and logic (referred to herein as "Plunger Control logic" or
"Plunger Control unit").
[0041] The use of supervisory control and data acquisition
("SCADA") systems in the natural gas production industry is used to
achieve improved gas well production through automation. The
present invention includes the addition of a Plunger Control unit
to a remote terminal unit ("RTU"), which is the control box or
"onsite brain" of any SCADA system. For existing SCADA systems, the
addition of a Plunger Control unit to the RTU may be achieved on a
cost effective basis.
[0042] Although many types of plungers may be used in a plunger
lift system, a conventional plunger may be used for the purposes
the present invention, in conjunction with the Plunger Control
logic. Other types of plungers may be used with modifications to
the Plunger Control logic.
I. Timing for Installation of Plunger Control Logic System
[0043] On a newly drilled and completed gas well, it may be
economically beneficial to install at the time of completion the
Plunger Control unit, as well as some or all of the above-ground
instrumentation and controls, wellhead enclosure, RTU, SCADA
system, cabling, piping, etc.
[0044] A natural gas producer can determine whether to flow the
well up the casing only or to install a tubing production string as
part of the initial well completion. This determination is done on
a well-by-well basis, considering calculated gas volumes,
calculated liquid volumes, type(s) of liquid, well configuration
and other reservoir characteristics.
[0045] Once the well advances to the liquid loading stage (i.e.
stage 24 in FIG. 1), the tubing string (if not already installed),
plunger, lubricator and down hole bumper spring assembly are
installed, as well as any necessary above-ground instrumentation
and controls, etc., in order to implement the present invention. If
already installed upon initial well completion as discussed above,
the above-ground instrumentation and controls, etc., are already in
place and ready for deployment.
[0046] Effective use of a plunger lift system is extended until a
decision to exercise a down hole pump technology is considered.
Also, installation of most or all of the invention as part of the
new well drill and/or completion capital cost may: (i) eliminate
costly additions to the well when gas and liquid production is
lower, (ii) decrease the operating cost of the well and/or (iii)
decrease the barrel of oil equivalent (BOE) operating factor.
[0047] With reference to FIG. 1, the present invention may be
installed at or around stage 24, when the liquid loading stage
begins Installing the present invention at an early stage (i.e. the
beginning of the liquid loading stage) allows the incremental gain
to be captured at an earlier stage in the well's life cycle,
thereby permitting the well to follow its natural decline curve
while potentially deferring extra capital costs (such as
installation of a down hole pump).
II. Horizontal or Deviated Gas Wells
[0048] Horizontal or deviated wells are common in shale gas plays,
which, in many cases, are "liquid rich" (i.e. gas condensates).
Where the liquids are comprised of condensates, not only is gas
production reduced and compromised upon the occurrence of liquid
loading of the well, production of condensates is also curtailed
and left in the well bore. In light of the market price for
condensates, production thereof is often available in economical
volumes, and can be advantageous to achieving expeditious cost
recovery associated with the implementation, for example, of the
invention pertaining to the Plunger Control logic described herein.
For purposes hereof and as the context may require, the term
"horizontal well" includes horizontal gas wells and deviated gas
wells.
[0049] In a horizontal well, reducing bottom hole flowing pressure
by reducing hydrostatic pressure in the vertical and deviation zone
of the well bore decreases back pressure on the reservoir.
[0050] In accordance with an embodiment of the present invention,
two systems and methods of removing liquid load in a horizontal
well using the Plunger Control algorithms in a SCADA system are
described herein.
System A: Tubing String into the Deviation Zone
[0051] Determining where to land a plunger lift system in a
horizontal well is an important task as the deeper the plunger is
landed the more liquid load may be lifted to surface. In most
horizontal wells, the horizontal leg of the well bore generally has
some less restricted gas production as the liquids tend to drop to
the lower part of the well bore. Therefore, by lifting the liquid
load in the vertical and heel section of the horizontal well can:
(i) decrease the back pressure on the reservoir, (ii) increase the
gas flow from the horizontal section, and (iii) keep the top
perforations of the well semi-dry.
[0052] FIG. 2 shows the components for a plunger lift System A for
use with the plunger lift landing methods described hereinbelow.
For existing wells, some of the components of the System may
already be installed or present at the gas well.
[0053] A well 20 has a substantially vertical section connected to
a substantially horizontal section by a heel 22. System A comprises
a tubing production string 24 that is provided down hole, in the
vertical section. The annulus formed between the outer surface of
string 24 and the inner surface of the well casing defines a casing
production string 26. A lower end of the string 24, extending into
a portion of the heel 22, includes an inlet, which in this
embodiment is a standing valve 17, a plunger 16, and a lift bumper
spring assembly (not shown). Standing valve 17 may be part of a
standard plunger lift standing valve system, and is preferably
installed below the plunger lift bumper spring assembly to allow
liquids to be held in the tubing string when the well is shut in.
Further, plunger control algorithms may be used with a variety of
different plungers.
[0054] The casing production string 26 is selectively in
communication with a gathering system GS (not shown) via a line 30.
Line 30 includes a casing pressure transmitter 11, a casing valve
14, a line pressure transmitter 12, and a multi-variable
transmitter 15 ("MVT"). Line 30 may include a check valve 28.
[0055] The upper end of string 24 is in communication with variety
of above-ground equipment, including a plunger arrival switch 9, a
tubing pressure transmitter 10, and line 30 via a tubing valve
13.
[0056] The plunger arrival switch 9 detects when the plunger lift
travels past the switch. The plunger arrival switch is preferably
installed between a flow tee 32 and the bypass piping 34 below a
lubricator spring (not shown) at or near the upper end of string
24.
[0057] The tubing pressure transmitter 10 detects the pressure in
the tubing production string 24 in gauge pressure. The casing
pressure transmitter 11 detects the pressure in the casing
production string 26 in gauge pressure. The line pressure
transmitter 12 detects the pressure in the gathering system
pressure at the point of access of the well to the gathering system
in gauge pressure. Preferably, the line pressure transmitter 12 is
installed downstream of check valve 28.
[0058] Tubing valve 13 allows the selective opening and restriction
of fluid communication between string 24 and the GS in a stepping
action as required by the Plunger Control logic. Preferably, tubing
valve 13 is electrically actuated. Casing valve 14 allows the
selective opening and restriction of fluid communication between
casing production string 26 and the GS in a stepping action as
required by the Plunger Control logic. Preferably, casing valve 14
is electrically actuated.
[0059] The MVT 15 measures gas production from the well, preferably
in compliance with American Gas Association (AGA) gas measuring
standards.
[0060] The system includes an antenna 2, which may be a directional
or omni antenna, and may be used on a cell phone or spread spectrum
radio or the like. If there is an existing SCADA system at the well
site, the antenna is likely already previously installed.
[0061] While there may be various alternate power sources, solar
power is commonly used with SCADA systems. In one embodiment, at
least one solar panel 3 is included in the system. The solar panel
3 is preferably sized according to the location of the well, with
sizing also being a function of the instrumentation required. If
there is an existing SCADA system at the well site, the solar panel
may be previously installed, though any existing solar panel may be
upgraded to accommodate additional power requirements for the
additional instrumentation of the present invention.
[0062] An RTU with battery(ies) 4 is preferably housed in a cabinet
for protection from outdoor climate conditions. The battery is
preferably sized according to the location, power requirements, and
autonomy (i.e. how many days without battery charging from the
solar panel 3 can the system handle). If an existing SCADA system
is installed, the RTU is likely already on site. The battery may be
upgraded to accommodate additional power requirements for the
instrumentation.
[0063] A Plunger Control unit 5 may be installed in close proximity
to the RTU, for example inside or outside the RTU cabinet. The
Plunger Control unit 5 controls the plunger control logic. The
Plunger Control unit acts as a "slave" to the RTU and communicates
(most commonly) via a modbus protocol.
[0064] Cables 6, 7, and 8 are used to electrically connect the
various components of the system. In one embodiment, cable 6
connects the MVT 15 to the RTU 4; cable 7 connects each of the
casing pressure transmitter 11 and the casing valve 14 to the RTU;
and cable 8 connects each of the plunger arrival switch 9, tubing
pressure transmitter 10, line pressure transmitter 12, and tubing
valve 13 to the RTU.
[0065] The system may include a wellhead enclosure 1 for enclosing
one or more components of the system. In the illustrated embodiment
shown in FIG. 2, the plunger arrival switch, tubing pressure
transmitter, casing pressure transmitter, line pressure
transmitter, tubing valve, casing valve, MVT, and a portion of
cables 6, 7, and 8 are housed in enclosure 1. The enclosure 1 is
for minimizing any potential adverse effects of weather on the
components. A sample wellhead enclosure is shown in FIG. 3, but of
course other types of enclosures may be used. Optionally, a
catalytic heater may also be used to protect the components from
extremely low temperatures.
Plunger Lift Control Logic
[0066] The methods of the present invention involve determining
where to land the plunger lift system in the deviation zone of the
well. The determination of where to land the plunger lift system in
the deviation zone helps optimize the unloading of liquid from a
horizontal gas well. To help determine where to land the plunger
lift system, it is preferred that the following data be obtained
for evaluation and assessment prior to installation of the plunger
lift system: [0067] a candidate well; [0068] a current well profile
in respect of the candidate well; [0069] flow and pressure data
preferably for the last 30 days of the producing candidate well;
[0070] prior to installing the plunger lift system, a "fluid shot"
in the well bore should be performed and given to the equipment
supplier to ensure the liquid level is as close to the heel as
possible; and [0071] the liquid in the well is cleaned or swabbed
out until the depth of the liquid (calculated by the fluid shot) is
close to or equal to the expected landed depth of the plunger. The
casing pressure is then monitored and recorded--this pressure is
referred to herein as the "clean casing pressure" (P.sub.CC). After
the plunger lift system is installed, a "fluid shot" is performed
again when the well is not flowing, and the well is swabbed out as
required to the bumper spring assembly. This will calculate the
P.sub.CC. The well is then allowed to flow for a short period of
time and the casing pressure is recorded again--this pressure is
referred to herein as the "flowing clean casing pressure"
(P.sub.FCC).
[0072] The flowing clean casing pressure P.sub.FCC is a pressure
value based on the configuration of the particular well and is a
function of various factors, including all pressures in the well
due to restrictions, friction loss, liquids, plunger, etc., that
are observed when the well is flowing after the initial
installation of the plunger lift system.
[0073] The plunger lift system may be installed with a qualified
wire line crew with accurate instruments to measure the landing
depth of the plunger.
[0074] The well is preferably left in the shut in part of the
plunger cycle when the plunger installation is complete. When the
plunger installation is complete, a new fluid shot is preferably
performed to ensure additional liquid load has built up or
accumulated.
i) Timer Mode Phase
[0075] After installing the plunger, the well is ready to proceed
to a timer mode phase. The purpose of starting the well in the
timer mode phase is to stabilize and prepare the well prior to
proceeding with the implementation and/or commissioning of any
production optimization techniques, such as using the Plunger
Control unit and related equipment and materials.
[0076] FIG. 4 shows a process flow chart for the timer mode phase
100. The gas well is preferably shut in for an initial off time
T.sub.i of the plunger algorithm (step 102). The initial off time
T.sub.i is preferably at least equal to the amount of time for the
plunger to drop to a bumper spring assembly generally anchored in
an XN or R Nipple at the lower end of the tubing string 24, plus
about 25%. For example, if the average plunger drop time is about
30 minutes, the initial off time T.sub.i would be about 37.5
minutes.
[0077] The plunger lift suppliers guide usually provides average
drop times of the supplied plunger (i.e. about 60 meters per minute
is considered an average time).
[0078] Once the initial off time has been reached, the Plunger
Control unit reads and captures the potential energy pressure
P.sub.U (step 104). The potential energy pressure P.sub.U is the
difference between the casing pressure P.sub.C, as determined by
the casing pressure transmitter, and the line pressure P.sub.L, as
determined by the line pressure transmitter, at this stage. This is
the potential energy available to lift the plunger to surface.
[0079] At step 106, a command is then sent by the Plunger Control
unit to open the tubing valve 13 for a pre-set time, which is
customized for each individual well. The pre-set time is the
plunger arrival time (i.e. time for the plunger 16 to vertically
travel in the tubing string 24 from the bumper spring assembly to
the plunger arrival switch 9) plus a calculated after-flow time, as
described below. If the well has not run a plunger lift system
before, a rule of thumb is to make the after-flow time about 50% of
what the shut in time is initially set at. However, if the plunger
lift system was not installed in the well before, a qualified
operator should be on site on the first few arrivals to slow down
the plunger by pinching the tubing valve if the plunger is arriving
excessively fast (early).
[0080] The plunger arrival time is monitored and recorded as
"early" "fast", "slow" or "non-arrival". The goal is to try to
obtain consistent normal plunger arrivals (i.e. arrival time
between "fast" and "slow") within a narrow range of times. For
example, if the plunger supplier suggests a normal arrival time of
about 10 minutes, based on depth of the well (wherein the average
arrival time for a conventional plunger is about 260
meters/minute), the normal arrival range may be set at
approximately 9.8 minutes ("fast" arrival) to approximately 10.2
minutes ("slow" arrival). If the arrival time is in this range
(step 108), the well is then allowed to flow in the tubing
production string until the after-flow time expires (step 110).
[0081] If the arrival time is not in this range (steps 108 and
116), adjustments to the after-flow time (i.e. time of producing
the well after the plunger passes the plunger arrival switch) are
then made automatically by the Plunger Control unit. Using the
above example, if the plunger arrival time is above 10.2 minutes,
the after-flow time is reduced (step 118); conversely, if the
arrival time is below 9.8 minutes, the after-flow is increased
(step 120). After adjustments to the after-flow time are made, the
well is then allowed to flow in the tubing production string until
the after-flow time expires (step 110).
[0082] When the after-flow time expires, a command is sent from the
Plunger Control unit to close the tubing valve 13 (step 112) to
allow the plunger to fall to the bumper spring assembly and the
Plunger Control unit captures and records the liquid load pressure
P.sub.LL (step 114). The liquid load pressure P.sub.LL is the
casing pressure P.sub.C minus the tubing pressure P.sub.T.
[0083] In a preferred embodiment, once the liquid load pressure is
measured, the well is shut in again (step 102), so that the timer
mode phase restarts to cycle the plunger until a minimum of five
consecutive normal plunger arrivals have been realized. Once at
least five consecutive plunger arrivals have been achieved within
the normal arrival time range, the Plunger Control unit then
averages the P.sub.LL and P.sub.U values captured from each
consecutive normal arrival. The averaged P.sub.LL and P.sub.U
values from the at least five consecutive normal arrivals then
become the constants used for the next phases, as described below.
When at least five consecutive plunger arrivals have been recorded,
the Plunger Control unit makes no further adjustments to the
after-flow time, and the Plunger Control unit indicates and records
that the gas well is stabilized.
ii) Burping Phase
[0084] After the well is stabilized, the plunger lift system is
controlled on the liquid load and required potential energy
pressure values, P.sub.LL and P.sub.U, which have been previously
captured and recorded in the timer mode phase as discussed
above.
[0085] With reference to FIGS. 5 to 8, the burping process 200
begins with the initial off time T.sub.i (step 202) and, once
reached, continues to keep the tubing valve 13 closed (step 206)
until the real-time difference between the P.sub.C and P.sub.L is
substantially equal to or greater than the potential energy
pressure P.sub.U, as determined in the timer mode phase (step 204).
When the potential energy pressure is met (step 204), the Plunger
Control unit sends a command to partially open the tubing valve 13
(e.g. about 20%) for the pre-set "burping" time, usually in the
range of about 10 to about 30 seconds, (step 208), as shown in FIG.
6, thereby initiating the "burping phase" of the well to force more
liquid load (denoted by "L" in the Figures) into the tubing
production string. This step is referred to as "burping", wherein
the plunger rises up string 24 off the bumper spring assembly.
[0086] The tubing valve 13 is only partially opened (e.g. about
20%) to allow the potential energy buildup in the casing to
disperse slowly. The more the valve 13 is opened, the quicker the
potential energy buildup is released. By opening tubing valve 13
only partially in the burping phase reduces the potential energy
buildup time thereafter (i.e. when the tubing valve 13 is closed
after the burping phase.
[0087] The rise of the plunger generates negative pressure on the
standing valve 17, causing valve 17 to be unseated, thereby
allowing some liquid load into the tubing string 24 from the
well
[0088] After the pre-set "burping" time, tubing valve 13 is closed
and shut in (step 210), as shown in FIG. 7, until the real-time
difference between the casing pressure P.sub.C and the line
pressure P.sub.L is substantially equal to the potential energy
pressure P.sub.U, as determined in the tinier mode phase (step
214). When valve 13 is closed, the plunger eventually lowers to
reach the bumper spring assembly. The lowering of the plunger
increases fluid pressure above the standing valve, which causes the
standing valve to return to its seat, thereby restricting liquid
load into the tubing string 24.
[0089] Once the potential energy pressure P.sub.U is met (step
214), the Plunger Control logic sends a command to tubing valve 13
to open same to about 100%, as shown in FIG. 8, and allow the valve
stay open at about 100% (step 216). Almost simultaneously, the
Plunger Control logic checks that casing valve 14 is closed (step
218), and if not, the Plunger Control logic closes casing valve 14
(step 220). The Plunger Control logic may include an option to
allow the tubing valve to be throttled back to reduce the plunger
velocity before it contacts the lubricator spring, which may help
reduce wear and tear of the lubricator spring.
[0090] With reference to FIG. 8, when tubing valve 13 is open, the
plunger rises from the bumper spring assembly to the upper end of
the tubing string, passing the plunger arrival switch 9 along the
way. The plunger arrival time is monitored and recorded as "early"
"fast", "slow" or "non- arrival". The goal is to maintain
substantially consistent normal plunger arrivals (i.e. an arrival
time between "fast" and "slow") in a narrow range of times as
previously set up in the timer mode phase. If the arrival time is
not in this range (step 222), adjustments to (i) the liquid load
pressure value P.sub.LL (as determined in the timer mode phase) or
the potential energy pressure time T.sub.U (i.e. time of producing
the well after the plunger passes the plunger arrival switch)
and/or (ii) the pre-set "burping" time are made automatically by
the Plunger Control logic. For example, if the arrival time is slow
(step 224), the pre-set "burping" time is reduced and/or the
potential energy pressure time T.sub.U is increased by the Plunger
Control logic (step 226); conversely, if the arrival time is fast
(step 224), the liquid load pressure value P.sub.LL is increased
and/or the pre-set "burping" time is increased (step 228).
[0091] The rise of plunger 16 causes standing valve 17 to open,
thereby allowing fluid load into the tubing string 24. The well is
then allowed to produce in the tubing string, lifting gas and
liquids from the well to surface via string 24. While the gas well
is producing, the Plunger Control logic is continuously or
periodically monitoring the flow rate in string 24, the line
pressure P.sub.L, and the build-up of liquid load in the well. As
mentioned above, liquid load pressure P.sub.LL is the difference
between the casing pressure P.sub.C and the tubing pressure
P.sub.T. Monitoring the line pressure at the same time as the
liquid load pressure helps ensure that any fluctuations in the
liquid load pressure are not effected by above-surface line
pressure fluctuations.
[0092] The casing pressure is monitored by the Plunger Control
logic, and when the casing pressure P.sub.C reaches the previously
calculated flowing clean casing pressure or the lowest casing
pressure observed (which is monitored and recorded) (step 230),
production continues in the tubing production string 24 and/or in
the casing production string in an after-flow mode as outlined in
methods 1 and 2 below.
iii) After-flow Mode
Method 1 (Process 300)
[0093] With reference to FIGS. 7 and 9a, as long as the line
pressure P.sub.L stays below the tubing pressure P.sub.T, the well
continues to flow via the tubing string 24. The Plunger Control
logic monitors the difference between the real-time casing pressure
P.sub.C and tubing pressure P.sub.T.
[0094] A load allowed set point P.sub.LASP is pre-set in the
Plunger Control logic. The load allowed set point P.sub.LASP is
equal to the liquid load pressure P.sub.LL (as determined and
adjusted in the burping phase) plus the flowing clean casing
pressure P.sub.FCC previously observed and recorded.
[0095] A load allowed pressure P.sub.LA, calculated by the Plunger
Control unit in real-time, is equal to the real-time difference
between the casing pressure P.sub.C and tubing pressure P.sub.T
plus the P.sub.FCC (as determined previously). When the load
allowed pressure P.sub.LA reaches and/or exceeds the load allowed
set point P.sub.LASP (step 302), the Plunger Control logic sends a
command to close tubing valve 13 (step 304), as shown in FIG. 7,
and the real-time load allowed pressure P.sub.LA is recorded (step
306).
[0096] This concludes the first cycle of the system, after which
the plunger drops to the bumper spring assembly, as shown in FIG.
7, and the Plunger Control unit starts the next cycle of the system
(process 200) by shutting in the well for the initial off time
T.sub.i (step 202).
Method 2 (Process 400)
[0097] With reference to FIGS. 7, 8, and 9b, the Plunger Control
logic sends a command to the casing valve 14 to start to partially
throttle open same (step 402), allowing gas in the well to produce
up the casing and/or tubing strings until the casing pressure
reaches a casing pressure rise set point P.sub.CRSP, assuming the
line pressure remains substantially steady. The casing pressure
rise set point P.sub.CRSP is generally a pressure that is slightly
above the already observed P.sub.FCC, e.g. about 5 kPa above the
P.sub.FCC. The P.sub.CRSP is pre-set in the Plunger Control logic.
If the plunger arrival time is fast, the P.sub.CRSP is increased.
If the plunger arrival time is slow, the P.sub.CRSP is
decreased.
[0098] The amount of time the casing pressure rises from the
flowing clean casing pressure P.sub.FCC to the casing pressure rise
set point P.sub.CRSP or the lowest casing pressure observed
determines the degree of throttling in the casing valve 14, which
can be determined through routine experimentation.
[0099] Once the casing pressure rise set point has been reached
(step 412), the Plunger Control logic sends a signal to close the
casing valve 14 (step 414), so that well fluid is only allowed to
produce through the tubing string 24, as shown in FIG. 8. As long
as the line pressure P.sub.L stays below the tubing pressure
P.sub.T, the well continues to flow via the tubing string 24. The
Plunger Control logic monitors the difference between the real-time
casing pressure P.sub.C and tubing pressure P.sub.T.
[0100] When the load allowed pressure P.sub.LA reaches and/or
exceeds the load allowed set point P.sub.LASP (step 416), the
Plunger Control logic sends a command to close tubing valve 13
(step 418), as shown in FIG. 7, and the real-time load allowed
pressure P.sub.LA is recorded (step 420).
[0101] This concludes the first cycle of the system, after which
the plunger drops to the bumper spring assembly, as shown in FIG.
7, and the Plunger Control unit starts the next cycle of the system
(process 200) by shutting in the well for the initial off time
T.sub.i (step 202).
[0102] In a preferred embodiment, for both Methods 1 and 2, these
cycles continue until at least five consecutive normal arrivals
have occurred, indicating that the well has been stabilized by
processes 200, and 300 or 400. When at least five consecutive
plunger arrivals have been recorded, the Plunger Control unit makes
no further adjustments to the pre-set burping time or to T.sub.U,
and the Plunger Control unit indicates and records that the gas
well is stabilized. Once the well is stabilized, the Plunger
Control logic continues to increase the liquid load pressure
P.sub.LLincrementally to help optimize production time and minimize
shut in time.
[0103] If the plunger arrival times start to stray out of the
normal plunger arrival range, the Plunger Control logic stops
increasing the liquid load pressure P.sub.LL. If the plunger
arrivals are consistently slow, the Plunger Control logic reverts
back to processes 300 or 400 to re-stabilize the well.
System B: Liquid Load Siphon String
[0104] According to another embodiment of the present invention,
the above described Plunger Control logic may be used with a system
that uses a liquid load siphon string (LLSS) instead of a standing
valve at the lower end of the tubing production string.
[0105] With reference to FIG. 10, a System B comprises an antenna
2, solar panel 3, RTU with batteries 4, plunger control unit 5,
cables 6, 7, and 8, plunger arrival switch 9, tubing pressure
transmitter 10, casing pressure transmitter 11, line pressure
transmitter 12, tubing valve 13, casing valve 14, MVT 15, a plunger
16 within a tubing string 24, an optional switch 28, and line 30,
all as described above with respect to System A. A lower portion of
the tubing string is placed down a well 120, with its lower end at
or near the kick off point 23 of the deviation zone and above the
heel 22 of the horizontal section of the well.
[0106] The tubing string of System B has an inlet, which in this
embodiment is a LLSS 117 extending from the lower end of the tubing
string 24 to at least a portion of the horizontal section of the
well. The LLSS 117 allows fluid communication between the
horizontal section of the well and the tubing string 24. Since the
LLSS extends further into the well than a typical plunger lift
system, the LLSS may allow access to well liquids at greater
depths. The LLSS 117 may be a standard siphon string commonly used
in the gas production industry.
[0107] System B further comprises a liquid level monitor 118, an
instrument configured to measure the real time liquid level in the
well bore. Monitor 118 may assist in ensuring that the level of the
liquid in the well bore does not completely flood the siphon string
117. The potential casing energy build up when the well is shut in
required to "u tube" the liquid through the siphon string is
minimal if the liquid level is monitored in real time.
[0108] Optionally, the liquid level monitor may also be used with
System A for collecting real time well liquid level data.
[0109] System B uses the same Plunger Control logic, including
Methods 1 and 2, as described above for landing the plunger lift
system at the below the kick off point of the deviation zone and
above the heel of the horizontal well.
[0110] The LLSS is preferably used in horizontal wells that are
deviated (i.e. where the angle at the heel is gradual and the
horizontal section is not at 90 degrees, but toe up, with respect
to the vertical section of the well), because it is difficult to
predict if the lower end of the LLSS may land in any solids
accumulated on the bottom half of the horizontal section, which may
block and/or obstruct the entrance to the LLSS.
[0111] Another concern is adding back pressure to the reservoir as
a certain amount of potential energy built up in the casing is
required (i.e. more than in System A above) to "u-tube" the liquid
load up the siphon string and into the tubing production
string.
[0112] However, if the well meets the abovementioned deviated well
criteria and has strong reservoir pressure that builds up potential
gas energy quickly therein when shut in, then System B may be
considered and applied, as System B may produce greater amounts of
liquids on each plunger cycle along with an increase in gas
production.
[0113] The previous description of the disclosed embodiments is
provided to enable any person skilled in the art to make or use the
present invention. Various modifications to those embodiments will
be readily apparent to those skilled in the art, and the generic
principles defined herein may be applied to other embodiments
without departing from the spirit or scope of the invention. Thus,
the present invention is not intended to be limited to the
embodiments shown herein, but is to be accorded the full scope
consistent with the claims, wherein reference to an element in the
singular, such as by use of the article "a" or "an" is not intended
to mean "one and only one" unless specifically so stated, but
rather "one or more". All structural and functional equivalents to
the elements of the various embodiments described throughout the
disclosure that are known or later come to be known to those of
ordinary skill in the art are intended to be encompassed by the
elements of the claims. Moreover, nothing disclosed herein is
intended to be dedicated to the public regardless of whether such
disclosure is explicitly recited in the claims. No claim element is
to be construed under the provisions of 35 USC 112, sixth
paragraph, unless the element is expressly recited using the phrase
"means for" or "step for".
* * * * *