U.S. patent application number 16/302649 was filed with the patent office on 2019-05-02 for apparatus and method for pumping fluid in a borehole.
The applicant listed for this patent is METROL TECHNOLOGY LIMITED. Invention is credited to Leslie David JARVIS, Shaun Compton ROSS.
Application Number | 20190128080 16/302649 |
Document ID | / |
Family ID | 56410582 |
Filed Date | 2019-05-02 |
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United States Patent
Application |
20190128080 |
Kind Code |
A1 |
ROSS; Shaun Compton ; et
al. |
May 2, 2019 |
APPARATUS AND METHOD FOR PUMPING FLUID IN A BOREHOLE
Abstract
A method to manipulate a well, comprising running an apparatus
having a container and an electrically powered pump into the well.
The well is isolated, and a wireless control signal, such as an
electromagnetic or acoustic signal, is sent to operate the pump in
response in order to pump fluid from within the container to the
surrounding portion of the well. The apparatus may comprise a
pressure balancing means, such as a floating piston between two
ports of the container, and/or an in well charging means.
Inventors: |
ROSS; Shaun Compton;
(Aberdeen, Aberdeenshire, GB) ; JARVIS; Leslie David;
(Stonehaven, Aberdeenshire, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
METROL TECHNOLOGY LIMITED |
Aberdeen, Aberdeenshire |
|
GB |
|
|
Family ID: |
56410582 |
Appl. No.: |
16/302649 |
Filed: |
May 26, 2017 |
PCT Filed: |
May 26, 2017 |
PCT NO: |
PCT/GB2017/051517 |
371 Date: |
November 18, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/06 20130101;
E21B 49/00 20130101; E21B 33/12 20130101; E21B 47/07 20200501; E21B
49/081 20130101; E21B 43/26 20130101; E21B 27/02 20130101; E21B
43/04 20130101; E21B 43/11 20130101; E21B 34/06 20130101 |
International
Class: |
E21B 27/02 20060101
E21B027/02; E21B 47/06 20060101 E21B047/06; E21B 49/00 20060101
E21B049/00; E21B 33/12 20060101 E21B033/12; E21B 49/08 20060101
E21B049/08 |
Foreign Application Data
Date |
Code |
Application Number |
May 26, 2016 |
GB |
1609286.8 |
Claims
1. A method to manipulate a well, comprising: providing an
apparatus in the well below an annular sealing device the annular
sealing device engageing with one of an inner face of casing and a
wellbore in the well, and being at least 100 m below a surface of
the well; and wherein a connector is provided connecting the
apparatus to the annular sealing device, the connector being above
the apparatus and below the annular sealing device; the apparatus
comprising: a container having a volume of at least 1 litre (l); a
port to allow fluid communication between a portion of the
container and a surrounding portion of the well; an electrically
powered pump configured to direct fluids to/from the container
from/to the surrounding portion of the well; a battery to supply
electrical power to the pump; a control mechanism to control the
pump, and comprising a communication device configured to receive a
control signal for operating the pump; running the apparatus into
the well; then, isolating the port of the apparatus from a surface
of the well; sending a control signal to the communication device
at least in part by a wireless control signal transmitted in at
least one of the following forms: electromagnetic and acoustic;
operating the pump in response to said control signal and pumping
fluid from within the container to the surrounding portion of the
well; and wherein at least one pressure sensor is provided in the
well below the annular sealing device, the at least one pressure
sensor coupled to a wireless transmitter; and wherein data is
transmitted from the transmitter to above the annular sealing
device.
2. A method as claimed in claim 1, wherein the apparatus is
connected to a tubular before the pump is operated.
3. (canceled)
4. A method as claimed in claim 1, wherein the electrical pump is a
positive displacement pump, optionally a reciprocating piston pump
which is reciprocated at least five times.
5. A method as claimed in claim 1, wherein the fluid pumped into
the surrounding portion of the well includes at least 1 l of fluid
added to the apparatus before it was run into the well.
6. A method as claimed in claim 1, wherein the fluid is one of an
acid, breaker fluid, tracer, gelling chemical and inhibitor.
7. A method as claimed in claim 1, including using the apparatus to
conduct at least one of an interval injectivity test, permeability
test, pressure test, hydraulic fracturing test, a barrier test, a
chemical delivery operation, and well/reservoir treatment such as
an acid treatment.
8. A method as claimed in claim 7, wherein the apparatus is used to
conduct a pressure test, the pressure test being conducted on a
barrier by the apparatus being provided below the barrier, the pump
being operated causing fluid to be released from the container to
increase pressure below the barrier, and the pressure below the
barrier is then monitored.
9. A method as claimed in claim 8, further comprising a charging
system having a valve on at least one of the and another port, the
method including providing gas in the container, exposing the gas
to well pressure via said port to compress the gas, closing said
port with said valve to resist fluid and pressure communication
from the well into the container, using the compressed gas to
facilitate the pump to release fluid from the container into the
well, and; wherein optionally before the barrier is set, the well
is pressurised from surface to further increase the pressure in the
well and further compress the gas in the container, the valve at
the port being closed before the pressure from the surface is
reduced.
10.-13. (canceled)
14. A method as claimed in claim 1, wherein the container has at
least one of a floating piston and bladder separating a first and a
second section in the container and sealing them from each other
within the container, the first section being in fluid
communication with the port.
15.-28. (canceled)
29. A method as claimed in claim 1, wherein the port of the
apparatus is provided above a second annular sealing device.
30. A method as claimed in claim 29, including conducting a short
interval test wherein the packer element of the annular sealing
device and a packer element of the second annular sealing device
are less than 30 m apart, or less than 10 m apart, optionally less
than 5 m apart, more optionally less than 2 m, less than lm or less
than 0.5 m; and there is at least one communication path from the
well to the reservoir between the packer elements.
31. (canceled)
32. A method as claimed in claim 1, wherein the apparatus is
deployed into the well in the same operation as deploying the
annular sealing device into the well.
33. A method as claimed in claim 32, wherein the apparatus is
conveyed on one of tubing, drill pipe and casing/liner.
34.-36. (canceled)
37. A method as claimed in claim 1 further comprising conducting a
procedure on the well, wherein the procedure includes at least one
of a build-up test, drawdown test, connectivity tests such as one
of, an interference test and pulse test, drill stem test (DST),
extended well test (EWT), hydraulic fracturing, minifrac, pressure
test, flow test, well/reservoir treatment such as an acid
treatment, permeability test, injection procedure, gravel pack
operation, perforation operation, image capture, string deployment,
workover, suspension and abandonment.
38. A method as claimed in any claim 1, wherein the well comprises
an array of discrete temperature sensors or a distributed
temperature sensor.
39. A method as claimed in claim 1, wherein the container has a
volume of at least 5 l at least 50 l, optionally at least 100
l.
40. (canceled)
41. A method as claimed in claim 1, wherein the well includes
casing/liner, and the container takes up the whole cross-section of
the casing/liner.
42. (canceled)
43. A method as claimed in claim 1, wherein in addition to the
container, there is at least one secondary container having a
volume of at least 1 l, the at least one secondary container having
a control device for controlling communication between the
secondary container and the surrounding portion of one of the well
and other portion of the apparatus, wherein the control device
includes at least one of a mechanical valve and a latch assembly,
and wherein at least one secondary container has a different
pressure than a surrounding portion of the well.
44.-55. (canceled)
56. A method to manipulate a well by conducting a short interval
test, comprising: providing a pressure sensor in the well;
providing an apparatus in the well, the apparatus comprising a
container having a volume of at least 5 litres and a port to allow
fluid and optionally pressure communication between a portion of an
inside of the container and an outside of the container; the port
of the apparatus being below a first portion of a packer element
and above a second portion of a or the packer element, said
portions spaced apart from each other by up to 10 m thus defining a
short interval, and each engaging with an inner face of casing or
wellbore in the well, and being at least 100 m below a surface of
the well; the short interval including at least one communication
path between the well and the formation; the apparatus further
comprising: a pump adapted to move fluid from the surrounding
portion of the well into at least a portion of the container via
the port; a control mechanism comprising a communication device
configured to receive a control signal for moving the valve member;
deploying the apparatus into the well on a tubular, sending a
control signal from outwith the short interval to the control
mechanism at least in part by a wireless control signal transmitted
in at least one of the following forms: electromagnetic, acoustic,
inductively coupled tubulars and coded pressure pulsing; operating
the pump in response to said control signal to allow fluid to enter
the container; and, drawing in at least 5 litres of fluid into the
container from the well.
Description
[0001] This invention relates to an apparatus and method for
pumping fluid in a borehole or well.
[0002] Boreholes are commonly drilled for a variety of reasons in
the oil and gas industry, not least to function as wells to recover
hydrocarbons, but also as test wells, observation wells or
injection wells.
[0003] On occasion, it may be necessary to deploy fluid into the
well. For example, an acid treatment may be conducted where a
chemical, often hydrochloric acid based, is deployed in a well in
order to remove or mitigate blockages or potential blockages, such
as scale, in the well. This can also be used to treat perforations
in the well.
[0004] In order to deploy the acid treatment, fluid may be pumped
from surface through the tubing. However this may not accurately
direct the fluid to the specific area of the well or formation
required.
[0005] In order to more accurately deploy fluid into a required
area of the well, coiled tubing may be used. A 2'' diameter coiled
tube, for example, can be deployed into the well. The acid
treatment is then pumped down the tube and exits into the well at
the appropriate area.
[0006] Whilst generally satisfactory, the inventors of the present
invention have noted that deploying fluids in such a manner can be
capital intensive requiring considerable rig time and large volumes
of fluid. When using coiled tubing, many thousands of feet is often
required (depending on the well depth). Moreover it is a
time-consuming process to launch the coiled tubing, deploy the
fluid, and then recover the coiled tubing. Sometimes coiled tubing
cannot access parts of the well due to the configuration of the
bottom hole assembly, and may not be able to deploy the fluid to
the particular area intended.
[0007] A number of other fluids may be deployed in a well, such as
a tracer or breaker fluid.
[0008] Hydraulic fracturing or various pressure tests, such as an
interval injectivity test and a permeability test, can also be
carried out using pressure applied from surface. However certain
portions of the well may be isolated from the surface, or it may
not be possible to isolate certain portions of the well from other
portions, whilst maintaining pressure connection to the
surface.
[0009] The inventors of the present invention have sought to
mitigate one or more of the problems of the prior art.
[0010] According to a first aspect of the present invention, there
is provided a method to manipulate a well, comprising: [0011]
providing an apparatus, the apparatus comprising: [0012] a
container having a volume of at least 1 litre; [0013] a port to
allow fluid communication between a portion of the container and
the surrounding portion of the well; [0014] an electrically powered
pump configured to direct fluids to/from the container from/to the
surrounding portion of the well; [0015] a battery to supply
electrical power to the pump; [0016] a control mechanism to control
the pump comprising a communication device configured to receive a
control signal for operating the pump; [0017] running the apparatus
into the well; [0018] optionally isolating the port of the
apparatus from a surface of the well; [0019] sending a control
signal to the communication device at least in part by a wireless
control signal transmitted in at least one of the following forms:
electromagnetic, acoustic, inductively coupled tubulars and coded
pressure pulsing; [0020] operating the pump in response to said
control signal and optionally pumping fluid from within the
container to the surrounding portion of the well.
[0021] As described in more detail below, the apparatus may include
a wireless communication device and/or a floating piston within the
container (for example to pressure balance or for charging).
[0022] Thus, according to a second aspect, the present invention
also provides an apparatus comprising: [0023] a container having a
volume of at least 1 litre; [0024] a port to allow fluid
communication between a portion of the container and the
surrounding portion of the well; [0025] an electrically powered
pump configured to direct fluids to/from the container from/to the
surrounding portion of the well; [0026] a battery to supply
electrical power to the pump; [0027] a control mechanism to control
the pump comprising a communication device configured to receive a
control signal for operating the pump, said communication device
being a wireless communication device; and, [0028] a floating
piston or bladder in the container.
[0029] The pump may be provided at the port.
[0030] Often, the pump is operated to pump fluid from within the
container to the surrounding portion of the well. Often this is at
least one litre or more than five litres of fluid which has been
added to the container at the surface before the apparatus is run
into the well. This fluid may be used to treat the
well/reservoir.
[0031] The electrical pump is preferably a positive displacement
pump such as a piston pump, gear type pump, screw pump, diaphragm,
lobe pump; especially a piston or gear pump. Alternatively the pump
may be a velocity pump such as a centrifugal pump.
[0032] The pump may be operable to pump fluids at a rate of 0.01
cc/s to 20 cc/s.
[0033] The pump operation or rate can be controlled in response to
a further control signal being received by the wireless
communication device (or this may be an instruction in the original
signal).
[0034] The step of sending a control signal to the communication
device is normally after the step of isolating the port of the
apparatus from the well but for certain embodiments, it may be
before.
[0035] The entire apparatus, and not just the port of the
apparatus, may be isolated from the surface of the well.
[0036] Isolating the port of the apparatus from the surface of the
well means preventing pressure or fluid communication between the
port and the surface of the well.
[0037] Isolation can be achieved using the well infrastructure and
isolating components. Isolating components comprise packers, plugs
such as bridge plugs, valves, and/or the apparatus. In contrast,
well infrastructure comprises cement in an annulus, casing and/or
other tubulars. In certain embodiments, more than one isolating
component can isolate the port of the apparatus from the surface of
the well. For example, a packer may be provided in an annulus and a
valve provided in a central tubing and together they isolate the
port of the apparatus from the surface of the well. In such cases
the uppermost extent of the well section that contains the port of
the apparatus is defined by the uppermost isolating component.
[0038] Isolating the port of the apparatus from the surface of the
well involves isolating the section of the well containing the port
downhole, such that the uppermost isolating component in that
isolated well section is at least 100 m from the surface of the
well, optionally at least 250 m, or at least 500 m.
[0039] The port of the apparatus is typically at least 100 m from
the uppermost isolating component in the same section of the well.
In certain embodiments, the port of the apparatus is at most 500 m
from the uppermost isolating component in the same section of the
well, optionally at most 200 m therefrom.
[0040] The well or a section thereof may be shut in, at surface or
downhole, after the apparatus has been run and before operating the
pump.
[0041] The step of isolating the port of the apparatus from the
surface of the well may include shutting in at least a section of
the well. For example the well can be shut in above the port of the
apparatus, which isolates the port of the apparatus from the
surface of the well.
[0042] For other embodiments at least a section of the well can be
shut in separate to this isolating step, for example, below the
apparatus, or the well may have been shut in at an earlier
date.
[0043] Isolating the port of the apparatus from the surface of the
well, and optionally shutting in the well, can reduce the volume
exposed to the apparatus which then focuses the released fluid to
the intended area.
[0044] The isolating components may be upper isolating components,
and lower isolating components may be used to isolate a section of
the well from a further section therebelow.
[0045] Thus embodiments of the present invention allow the release
of fluids in a lower isolated section of a well where it may not
have hitherto been possible, convenient or indeed safe to do so
using conventional means such as fluid control lines to
surface.
[0046] The well may be a production well.
Pressure Balancing Means
[0047] The apparatus may comprise a pressure balancing means. The
port may be a first port, and a second port may be provided in the
apparatus between the container and a surrounding portion of the
well, the first and second ports separated within the apparatus by
a pressure balancing device such as a bladder or a floating
piston.
[0048] In a first embodiment with a pressure balancing means, the
pump is normally provided at one of the ports (preferably the first
port), the fluid being pumped to/from the container is provided
between the floating piston and said first port. An opposite side
of the floating piston is exposed to well pressure via the second
port, thus balancing the pressure on both sides of the floating
piston.
[0049] In a second embodiment with a pressure balancing means, the
pump is provided between said floating piston and the first port
and a second floating piston is provided between the pump and the
first port. The pump is thus between the two floating pistons. The
first floating piston functions as a pressure balancing means and
the second floating piston controls fluid ingress/egress from the
container through the first port. A control fluid is provided in
the container, between the respective floating pistons, and this
control fluid can be pumped by the pump, which in turn causes the
second floating piston to move and direct fluid to be expelled or
drawn into the container, between the first port and the second
floating piston.
[0050] The second embodiment is particularly suited for apparatus
where fluid can be both expelled and drawn in (in either order)
since the pump is operating on a controlled fluid.
[0051] For embodiments with pressure balancing means, the pump can
then direct fluids in or out of the container with less or with no
requirement to overcome a pressure differential between the
container and the surrounding portion of the well.
[0052] Pressure balancing means is not essential. Embodiments used
for barrier testing from below a barrier may especially be used
without one. Nevertheless, in such a case, it is preferred to have
a small (variable) amount of gas at, for example, more than 100
psi, within the container to stop the pump acting against a vacuum.
Indeed, a higher pressure, such as over 1000 psi also helps the
pump operate.
[0053] In any case, the pump can pump the fluid directly i.e. the
fluid moving to/from the surrounding portion of the well to the
container; or indirectly for example the control fluid which acts
on the fluid moving to/from the surrounding portion of the well
indirectly, for example via a floating piston, to the
container.
Pump Options
[0054] The electrical pump may drive another pump which in turn
moves the fluid to/from the container from/to the surrounding
portion of the well. This second pump need not be electrical;
rather the `prime mover` is electrical.
[0055] The pump may comprise a piston with a motorised lead screw
option, akin to a syringe.
[0056] A single stroke of such a piston or lead screw may be
sufficient in certain applications, although for other applications
the piston is reciprocated.
[0057] This single stroke option is particularly suited to smaller
volume applications (for example up to 5 litres) and also where
either side of the piston is pressure balanced with the well.
[0058] In other embodiments, pumps with a piston or lead screw are
reciprocated multiple times, such as reciprocated at least five
times or for certain applications hundreds of times or many more
times.
[0059] For applications where the piston is reciprocated, the
piston stroke may sweep the volume of the container. Alternatively,
also for reciprocated pistons, the piston may draw fluid from or
expel fluid to a further chamber within the apparatus. The further
chamber may be many times, such as at least two times, larger than
the volume that the piston stroke sweeps.
[0060] The pump can function as a meter and so monitor the volume
of fluid travelling to/from the container from/to the surrounding
portion of the well. For example the apparatus can count the
reciprocations of the pump, and using the volume of the pump,
calculate the amount of fluid being moved.
Valves
[0061] The apparatus may comprise a mechanical valve assembly which
normally has a valve member. The valve may be integral to the pump
especially where the mechanical valve assembly comprises a check
valve.
[0062] Alternatively it may be driven by the control mechanism
electro-mechanically, or electro-hydraulically via porting.
[0063] The mechanical valve assembly may be at one end of the
apparatus, especially at one of the ports. However it may be in its
central body. One may be provided at each end.
[0064] The valve may resist fluid entry or may resist fluid exit
from the container, depending on whether the pump is intended to
expel or draw fluids in.
[0065] A choke may be integrated with the mechanical valve assembly
or it may be in a flowpath comprising one of the ports and the
mechanical valve assembly. The valve member may function as a
choke. Where a plurality of valve members are provided, multiple
different sizes of chokes may be provided. Thus, for certain
embodiments, the mechanical valve assembly comprises a variable
valve member, which itself can function as a choke and indeed it
can be varied in situ (that is, in the well). For example, a choke
disk may be used, which may be rotatably mounted with different
sizes of apertures to provide a variable choking means.
Outlet Tube
[0066] The first port may comprise a tube with a plurality of
openings. Nozzles can also be provided in order to direct its
effects towards the communication paths for example.
[0067] The openings, for example at least three, may be spaced
apart from each other in the same direction as the well, for
example in a direction substantially parallel to the well, or in a
spiral shape, the shape having an axis also generally parallel to
the well. The tube may be a small diameter tube (for example
1/4-3/4'' outer diameter), which may extend over the communication
paths. A rotating inner/outer sleeve or other means may be used to
selectively open or close the openings.
[0068] There may be a plurality of valve members, optionally
controlling openings of different sizes and/or at different
locations. Each different valve member may be independently
controlled or two or more groups of openings may be controlled by
separate valves. For example, groups of openings may be provided on
a separate tube, each group being controlled by a valve. The method
may then direct the fluid to a particular area.
Container Options
[0069] The apparatus may be elongate in shape. It may be in the
form of a pipe. It is normally cylindrical in shape.
[0070] Whilst the size of the container can vary, depending on the
nature of the well in which it will be used, the container may have
a volume of at least 5 litres (l), optionally at least 50 l or
optionally at least 100 l. The container may have a volume of at
most 3000 l, normally at most 1500 l, optionally at most 500 l.
[0071] Thus the apparatus may comprise a pipe/tubular (or a sub in
part of a pipe/tubular) housing the container and other components
or indeed the container may be made up of tubulars, such as tubing,
drill pipe, liner or casing joined together. The tubulars may
comprise joints each with a length of from 3 m to 14 m, generally 8
m to 12 m, and nominal external diameters of from 23/8'' (or
27/8'') to 7''.
[0072] References to `casing` includes `liner` unless stated
otherwise.
[0073] The apparatus may be configured to pump at least 1 litre,
optionally at least 5 litres, optionally at least 10 litres, more
optionally at least 50 litres of fluid to/from the container
from/to an outside thereof.
Secondary Containers
[0074] In addition to the container (sometimes referred to below as
a `primary container`) there may be one or more secondary
containers, optionally each with respective control devices
controlling fluid communication between the respective secondary
container and the surrounding portion of the well or other portion
of the apparatus.
[0075] The control devices of the secondary containers may include
pumps, mechanical valves and/or latch assemblies.
[0076] A piston may be provided in one or more of the secondary
containers. It may, for certain embodiments, function as the
valve.
[0077] Alternatively, a floating piston may be controlled
indirectly by the control device such as the valve. In some
embodiments, the piston may be directly controlled by the latch
assembly.
[0078] The latch assembly can control the floating piston--it can
hold the floating piston in place against action of other forces
(for example well pressure) and is released in response to an
instruction from the control mechanism.
[0079] Thus a secondary container can have a mechanical valve
assembly (such as those described herein) or latch assembly, rather
than a pump, which regulates fluid communication between that
secondary container and a surrounding portion of the well. The
control device may or may not be provided at a port.
[0080] Thus there may be one, two, three or more than three
secondary containers. The further control devices for the secondary
containers may or may not move in response to a control signal, but
may instead respond based on a parameter or time delay. Each
control device for the respective secondary container can be
independently operable. A common communication device may be used
for sending a control signal to a plurality of control devices.
[0081] The contents of the containers may or may not be miscible at
the outlet. For example one container can have a polymer and a
second container a cross linker, when mixed, in use, in the well
form a gel or otherwise set/cure. The containers can be configured
differently, for example have different volumes or chokes etc.
[0082] The containers may have a different internal pressure
compared to the pressure of the surrounding portion of the well. If
less than a surrounding portion of the well, they are referred to
as `underbalanced` and when more than a surrounding portion of the
well they are referred to as `overbalanced`.
[0083] Thus (an) underbalanced or overbalanced secondary
container(s) and associated secondary port and control device may
be provided, the secondary container(s) each preferably having a
volume of at least five litres and, in use, having a pressure
lower/higher than the surrounding portion of the well normally for
at least one minute, before the control device is activated
optionally in response to the control signal. Fluids surrounding
the secondary container can thus be drawn in (for underbalanced
containers), optionally quickly, or fluids expelled (for
overbalanced containers).
[0084] Thus, a plurality of primary and/or secondary containers or
apparatus may be provided each having different functions, the
primary container being controlled by a pump, one or more secondary
containers may be underbalanced and one or more secondary
containers may be overbalanced.
[0085] This can be useful, for example, to partially clear a filter
cake using an underbalanced container, before deploying an acid
treatment onto the perforations using the container controlled by a
pump.
[0086] Alternatively, for a short interval manipulation, a skin
barrier could be removed from the interval by an underbalanced
container, and/or by acid release from an overbalanced container;
and then the apparatus including the pump can be used to pump fluid
from the interval.
[0087] Fluid from a first chamber within the container can go into
another to mix before being released/expelled.
Other Apparatus Options
[0088] In addition to the control signal, the apparatus may include
pre-programmed sequences of actions, for example a pump starting
and stopping, or a change in valve member position; based on
parameters for example time, pressure detected or not detected or
detection of particular fluid or gas. For example, under certain
conditions, the apparatus will perform certain steps
sequentially--each subsequent step following automatically. This
can be beneficial where a delay to wait for a signal to follow on
could mitigate the usefulness of the operation.
[0089] The apparatus may have a mechanism to orientate it
rotationally.
[0090] Normally the ports are provided on a side face of the
apparatus although certain embodiments can have the ports provided
in an end face.
Annular Sealing Device
[0091] The apparatus may be provided in the well below an annular
sealing device, the annular sealing device engaging with an inner
face of casing or wellbore in the well, and being at least 100 m
below a surface of the well.
[0092] For certain embodiments, the annular sealing device is one
of the isolating components.
[0093] A connector is optionally also provided connecting the
apparatus to the annular sealing device, the connector being above
the apparatus and below the annular sealing device.
[0094] The control signal may be sent from above the annular
sealing device to the apparatus below the annular sealing device
often in its wireless form.
[0095] The annular sealing device may be at least 300 m from the
surface of the well. The surface of the well is the top of the
uppermost casing of the well. The annular sealing device is a
device which seals between two tubulars (or a tubular and the
wellbore), such as a packer element or a polished bore and seal
assembly. The packer element may be part of a packer, bridge plug,
or liner hanger, especially a packer or bridge plug.
[0096] A packer includes a packer element along with a packer upper
tubular and a packer lower tubular along with a body on which the
packer element is mounted.
[0097] The packer can be permanent or temporary. Temporary packers
are normally retrievable and are run with a string and so removed
with the string. Permanent packers on the other hand, are normally
designed to be left in the well (though they could be removed at a
later time).
[0098] A sealing portion of the annular sealing device may be
elastomeric, non-elastomeric and/or metallic.
[0099] It can be difficult to control apparatus in the area below
an annular sealing device between a casing/wellbore and an inner
production tubing or test string, especially independent of the
fluid column in the inner production tubing. Thus embodiments of
the present invention can provide a degree of control in this area,
through the combination of the pump and the wireless control.
[0100] This annular sealing device(s) may be wirelessly controlled.
Thus where appropriate, they may be expandable and/or retractable
by wireless signals.
[0101] In some embodiments, kill fluid may be present inside tubing
in the well above the annular sealing device before the apparatus
is activated.
Connector
[0102] The connector is a mechanical connection (as opposed to a
wireless connection) and may comprise, at least in part, a tubular
connection for example some lengths of tubing or drill pipe. It may
include one or more of perforation guns, gauge carriers,
cross-overs, subs and valves. The connector may comprise or consist
of a threaded connection. The connector does not consist of only
wireline, and normally does not include it.
[0103] Normally the connector comprises a means to connect to the
annular sealing device, such as a thread or dogs.
[0104] The connector may be within the same casing that the annular
sealing device is connected to.
[0105] The connector may comprise a plug for example in the tubing
(which is separate from the annular sealing device which may also
comprise a plug).
[0106] The control signal may be sent from above the annular
sealing device.
Signals
[0107] The wireless control signal is transmitted in at least one
of the following forms: electromagnetic, acoustic, inductively
coupled tubulars and coded pressure pulsing and references herein
to "wireless", relate to said forms, unless where stated
otherwise.
[0108] The signals may be data or command signals which need not be
in the same wireless form. Accordingly, the options set out herein
for different types of wireless signals are independently
applicable to data and command signals. The control signals can
control downhole devices including sensors. Data from sensors may
be transmitted in response to a control signal. Moreover data
acquisition and/or transmission parameters, such as acquisition
and/or transmission rate or resolution, may be varied using
suitable control signals.
[0109] The communication device may comprise a wireless
communication device. In alternative embodiments, the communication
device is a wired communication device and the wireless signal
transmitted in other parts of the well.
Coded Pressure Pulses
[0110] Pressure pulses include methods of communicating from/to
within the well/borehole, from/to at least one of a further
location within the well/borehole, and the surface of the
well/borehole, using positive and/or negative pressure changes,
and/or flow rate changes of a fluid in a tubular and/or annular
space.
[0111] Coded pressure pulses are such pressure pulses where a
modulation scheme has been used to encode commands and/or data
within the pressure or flow rate variations and a transducer is
used within the well/borehole to detect and/or generate the
variations, and/or an electronic system is used within the
well/borehole to encode and/or decode commands and/or the data.
Therefore, pressure pulses used with an in-well/borehole electronic
interface are herein defined as coded pressure pulses. An advantage
of coded pressure pulses, as defined herein, is that they can be
sent to electronic interfaces and may provide greater data rate
and/or bandwidth than pressure pulses sent to mechanical
interfaces.
[0112] Where coded pressure pulses are used to transmit control
signals, various modulation schemes may be used to encode control
signals such as a pressure change or rate of pressure change,
on/off keyed (OOK), pulse position modulation (PPM), pulse width
modulation (PWM), frequency shift keying (FSK), pressure shift
keying (PSK), amplitude shift keying (ASK), combinations of
modulation schemes may also be used, for example, OOK-PPM-PWM. Data
rates for coded pressure modulation schemes are generally low,
typically less than 10 bps, and may be less than 0.1 bps.
[0113] Coded pressure pulses can be induced in static or flowing
fluids and may be detected by directly or indirectly measuring
changes in pressure and/or flow rate. Fluids include liquids,
gasses and multiphase fluids, and may be static control fluids,
and/or fluids being produced from or injected in to the well or a
section thereof, for example when it is not isolated from the
surface of the well.
Signals--General
[0114] Preferably the wireless signals are such that they are
capable of passing through a barrier, such as a plug or said
annular sealing device, when fixed in place, and therefore
preferably able to pass through the isolating components.
Preferably therefore the wireless signals are transmitted in at
least one of the following forms: electromagnetic, acoustic, and
inductively coupled tubulars.
[0115] EM/Acoustic and coded pressure pulsing use the well,
borehole or formation as the medium of transmission. The
EM/acoustic or pressure signal may be sent from the well, or from
the surface. If provided in the well, an EM/acoustic signal can
travel through any annular sealing device, although for certain
embodiments, it may travel indirectly, for example around any
annular sealing device.
[0116] Electromagnetic and acoustic signals are especially
preferred--they can transmit through/past an annular sealing device
without special inductively coupled tubular infrastructure, and for
data transmission, the amount of information that can be
transmitted is normally higher compared to coded pressure pulsing,
especially receiving data from the well.
[0117] Therefore, the communication device may comprise an acoustic
communication device and the wireless control signal comprises an
acoustic control signal and/or the communication device may
comprise an electromagnetic communication device and the wireless
control signal comprises an electromagnetic control signal.
[0118] Similarly the transmitters and receivers used correspond
with the type of wireless signals used. For example an acoustic
transmitter and receiver are used if acoustic signals are used.
[0119] Where inductively coupled tubulars are used, there are
normally at least ten, usually many more, individual lengths of
inductively coupled tubular which are joined together in use, to
form a string of inductively coupled tubulars. They have an
integral wire and may be formed tubulars such as tubing, drill pipe
or casing. At each connection between adjacent lengths there is an
inductive coupling.
[0120] The inductively coupled tubulars that may be used can be
provided by N O V under the brand Intellipipe.RTM..
[0121] Thus, the EM/acoustic or pressure wireless signals can be
conveyed a relatively long distance as wireless signals, sent for
at least 200 m, optionally more than 400 m or longer which is a
clear benefit over other short range signals. Embodiments including
inductively coupled tubulars provide this advantage/effect by the
combination of the integral wire and the inductive couplings. The
distance travelled may be much longer, depending on the length of
the well.
[0122] Data and commands within the signal may be relayed or
transmitted by other means. Thus the wireless signals could be
converted to other types of wireless or wired signals, and
optionally relayed, by the same or by other means, such as
hydraulic, electrical and fibre optic lines. In one embodiment, the
signals may be transmitted through a cable for a first distance,
such as over 400 m, and then transmitted via acoustic or EM
communications for a smaller distance, such as 200 m. In another
embodiment they are transmitted for 500 m using coded pressure
pulsing and then 1000 m using a hydraulic line.
[0123] Thus whilst non-wireless means may be used to transmit the
signal in addition to the wireless means, preferred configurations
preferentially use wireless communication. Thus, whilst the
distance travelled by the signal is dependent on the depth of the
well, often the wireless signal, including relays but not including
any non-wireless transmission, travel for more than 1000 m or more
than 2000 m. Preferred embodiments also have signals transferred by
wireless signals (including relays but not including non-wireless
means) at least half the distance from the surface of the well to
the apparatus.
Different wireless signals may be used in the same well for
communications going from the well towards the surface, and for
communications going from the surface into the well.
[0124] Thus, the wireless signal may be sent to the communication
device, directly or indirectly, for example making use of in-well
relays above and/or below any annular sealing device. The wireless
signal may be sent from the surface or from a wireline/coiled
tubing (or tractor) run probe at any point in the well optionally
above any annular sealing device. For certain embodiments, the
probe may be positioned relatively close to any annular sealing
device for example less than 30 m therefrom, or less than 15 m.
Acoustic
[0125] Acoustic signals and communication may include transmission
through vibration of the structure of the well including tubulars,
casing, liner, drill pipe, drill collars, tubing, coil tubing,
sucker rod, downhole tools; transmission via fluid (including
through gas), including transmission through fluids in uncased
sections of the well, within tubulars, and within annular spaces;
transmission through static or flowing fluids; mechanical
transmission through wireline, slickline or coiled rod;
transmission through the earth; and transmission through wellhead
equipment. Communication through the structure and/or through the
fluid are preferred.
[0126] Acoustic transmission may be at sub-sonic (<20 Hz), sonic
(20 Hz-20 kHz), and ultrasonic frequencies (20 kHz-2 MHz).
Preferably the acoustic transmission is sonic (20 Hz-20 khz).
[0127] The acoustic signals and communications may include
Frequency Shift Keying (FSK) and/or Phase Shift Keying (PSK)
modulation methods, and/or more advanced derivatives of these
methods, such as Quadrature Phase Shift Keying (QPSK) or Quadrature
Amplitude Modulation (QAM), and preferably incorporating Spread
Spectrum Techniques. Typically they are adapted to automatically
tune acoustic signalling frequencies and methods to suit well
conditions.
[0128] The acoustic signals and communications may be
uni-directional or bi-directional. Piezoelectric, moving coil
transducer or magnetostrictive transducers may be used to send
and/or receive the signal.
EM
[0129] Electromagnetic (EM) (sometimes referred to as Quasi-Static
(QS)) wireless communication is normally in the frequency bands of:
(selected based on propagation characteristics) [0130] sub-ELF
(extremely low frequency) <3 Hz (normally above 0.01 Hz); [0131]
ELF 3 Hz to 30 Hz; [0132] SLF (super low frequency) 30 Hz to 300
Hz; [0133] ULF (ultra low frequency) 300 Hz to 3 kHz; and, [0134]
VLF (very low frequency) 3 kHz to 30 kHz.
[0135] An exception to the above frequencies is EM communication
using the pipe as a waveguide, particularly, but not exclusively
when the pipe is gas filled, in which case frequencies from 30 kHz
to 30 GHz may typically be used dependent on the pipe size, the
fluid in the pipe, and the range of communication. The fluid in the
pipe is preferably non-conductive.
[0136] U.S. Pat. No. 5,831,549 describes a telemetry system
involving gigahertz transmission in a gas filled tubular
waveguide.
[0137] Sub-ELF and/or ELF are preferred for communications from a
well to the surface (for example over a distance of above 100 m).
For more local communications, for example less than 10 m, VLF is
preferred. The nomenclature used for these ranges is defined by the
International Telecommunication Union (ITU).
[0138] EM communications may include transmitting communication by
one or more of the following: imposing a modulated current on an
elongate member and using the earth as return; transmitting current
in one tubular and providing a return path in a second tubular; use
of a second well as part of a current path; near-field or far-field
transmission; creating a current loop within a portion of the well
metalwork in order to create a potential difference between the
metalwork and earth; use of spaced contacts to create an electric
dipole transmitter; use of a toroidal transformer to impose current
in the well metalwork; use of an insulating sub; a coil antenna to
create a modulated time varying magnetic field for local or through
formation transmission; transmission within the well casing; use of
the elongate member and earth as a coaxial transmission line; use
of a tubular as a wave guide; transmission outwith the well
casing.
[0139] Especially useful is imposing a modulated current on an
elongate member and using the earth as return; creating a current
loop within a portion of the well metalwork in order to create a
potential difference between the metalwork and earth; use of spaced
contacts to create an electric dipole transmitter; and use of a
toroidal transformer to impose current in the well metalwork.
[0140] To control and direct current advantageously, a number of
different techniques may be used. For example one or more of: use
of an insulating coating or spacers on well tubulars; selection of
well control fluids or cements within or outwith tubulars to
electrically conduct with or insulate tubulars; use of a toroid of
high magnetic permeability to create inductance and hence an
impedance; use of an insulated wire, cable or insulated elongate
conductor for part of the transmission path or antenna; use of a
tubular as a circular waveguide, using SHF (3 GHz to 30 GHz) and
UHF (300 MHz to 3 GHz) frequency bands.
[0141] Suitable means for receiving the transmitted signal are also
provided, these may include detection of a current flow; detection
of a potential difference; use of a dipole antenna; use of a coil
antenna; use of a toroidal transformer; use of a Hall effect or
similar magnetic field detector; use of sections of the well
metalwork as part of a dipole antenna.
[0142] Where the phrase "elongate member" is used, for the purposes
of EM transmission, this could also mean any elongate electrical
conductor including: liner; casing; tubing or tubular; coil tubing;
sucker rod; wireline; drillpipe; slickline or coiled rod.
[0143] A means to communicate signals within a well with
electrically conductive casing is disclosed in U.S. Pat. No.
5,394,141 by Soulier and U.S. Pat. No. 5,576,703 by MacLeod et al
both of which are incorporated herein by reference in their
entirety. A transmitter comprising oscillator and power amplifier
is connected to spaced contacts at a first location inside the
finite resistivity casing to form an electric dipole due to the
potential difference created by the current flowing between the
contacts as a primary load for the power amplifier. This potential
difference creates an electric field external to the dipole which
can be detected by either a second pair of spaced contacts and
amplifier at a second location due to resulting current flow in the
casing or alternatively at the surface between a wellhead and an
earth reference electrode.
Relay
[0144] A relay comprises a transceiver (or receiver) which can
receive a signal, and an amplifier which amplifies the signal for
the transceiver (or a transmitter) to transmit it onwards.
[0145] There may be at least one relay. The at least one relay (and
the transceivers or transmitters associated with the apparatus or
at the surface) may be operable to transmit a signal for at least
200 m through the well. One or more relays may be configured to
transmit for over 300 m, or over 400 m.
[0146] For acoustic communication there may be more than five, or
more than ten relays, depending on the depth of the well and the
position of the apparatus.
[0147] Generally, less relays are required for EM communications.
For example, there may be only a single relay. Optionally
therefore, an EM relay (and the transceivers or transmitters
associated with the apparatus or at the surface) may be configured
to transmit for over 500 m, or over 1000 m.
[0148] The transmission may be more inhibited in some areas of the
well, for example when transmitting across a packer. In this case,
the relayed signal may travel a shorter distance. However, where a
plurality of acoustic relays are provided, preferably at least
three are operable to transmit a signal for at least 200 m through
the well.
[0149] For inductively coupled tubulars, a relay may also be
provided, for example every 300-500 m in the well.
[0150] The relays may keep at least a proportion of the data for
later retrieval in a suitable memory means.
[0151] Taking these factors into account, and also the nature of
the well, the relays can therefore be spaced apart accordingly in
the well.
[0152] The control signals may cause, in effect, immediate
activation, or may be configured to activate the apparatus after a
time delay, and/or if other conditions are present such as a
particular pressure change.
Electronics
[0153] The apparatus may comprise at least one battery optionally a
rechargeable battery. The battery may be at least one of a high
temperature battery, a lithium battery, a lithium oxyhalide
battery, a lithium thionyl chloride battery, a lithium sulphuryl
chloride battery, a lithium carbon-monofluoride battery, a lithium
manganese dioxide battery, a lithium ion battery, a lithium alloy
battery, a sodium battery, and a sodium alloy battery. High
temperature batteries are those operable above 85.degree. C. and
sometimes above 100.degree. C. The battery system may include a
first battery and further reserve batteries which are enabled after
an extended time in the well. Reserve batteries may comprise a
battery where the electrolyte is retained in a reservoir and is
combined with the anode and/or cathode when a voltage or usage
threshold on the active battery is reached.
[0154] The control mechanism is normally an electronic control
mechanism and the communication device is normally an electronic
communication device.
[0155] The battery and optionally elements of the control
electronics may be replaceable without removing tubulars. They may
be replaced by, for example, using wireline or coiled tubing. The
battery may be situated in a side pocket.
[0156] The apparatus, especially the control mechanism, preferably
comprises a microprocessor. Electronics in the apparatus, to power
various components such as the microprocessor, control and
communication systems, and optionally the valve, are preferably low
power electronics. Low power electronics can incorporate features
such as low voltage microcontrollers, and the use of `sleep` modes
where the majority of the electronic systems are powered off and a
low frequency oscillator, such as a 10-100 kHz, for example 32 kHz,
oscillator used to maintain system timing and `wake-up` functions.
Synchronised short range wireless (for example EM in the VLF range)
communication techniques can be used between different components
of the system to minimize the time that individual components need
to be kept `awake`, and hence maximise `sleep` time and power
saving.
[0157] The low power electronics facilitates long term use of
various components of the apparatus. The control mechanism may be
configured to be controllable by the control signal up to more than
24 hours after being run into the well, optionally more than 7
days, more than 1 month, or more than 1 year or up to 5 years. It
can be configured to remain dormant before and/or after being
activated.
Sensors
[0158] The apparatus and/or the well (above and/or especially below
the annular sealing device) may comprise at least one pressure
sensor. The pressure sensor may be below the annular sealing device
and may or may not form part of the apparatus. It can be coupled
(physically or wirelessly) to a wireless transmitter and data can
be transmitted from the wireless transmitter to above the annular
sealing device or otherwise towards the surface. Data can be
transmitted in at least one of the following forms:
electromagnetic, acoustic, inductively coupled tubulars especially
acoustic and/or electromagnetic as described herein above.
[0159] Such short range wireless coupling may be facilitated by EM
communication in the VLF range.
[0160] Optionally the apparatus comprises a volume or level
indicator such as an empty/full indicator or a proportional
indicator arranged to determine the volume or level of fluid in the
container. A means to recover the data from the volume indicator is
also normally included. The apparatus may comprise a pressure
gauge, arranged to measure internal pressure in the container. The
communication device may be configured to send signals from the
pressure gauge optionally wirelessly.
[0161] Preferably at least temperature and pressure sensors are
provided. A variety of sensors may be provided, including
acceleration, vibration, torque, movement, motion, radiation,
noise, magnetism, corrosion; chemical or radioactive tracer
detection; fluid identification such as hydrate, wax and sand
production; and fluid properties such as (but not limited to) flow,
density, water cut, for example by capacitance and conductivity, pH
and viscosity. Furthermore the sensors may be adapted to induce the
signal or parameter detected by the incorporation of suitable
transmitters and mechanisms. The sensors may also sense the status
of other parts of the apparatus or other equipment within the well,
for example valve member position or motor rotation of the
pump.
[0162] An array of discrete temperature sensors or a distributed
temperature sensor can be provided (for example run in) with the
apparatus. Optionally therefore it may be below the annular sealing
device. These temperature sensors may be contained in a small
diameter (for example 1/4'') tubing line and may be connected to a
transmitter or transceiver. If required any number of lines
containing further arrays of temperature sensors can be provided.
This array of temperature sensors and the combined system may be
configured to be spaced out so the array of temperature sensors
contained within the tubing line may be aligned across the
formation, for example the communication paths; either for example
generally parallel to the well, or in a helix shape.
[0163] The array of discrete temperature sensors may be part of the
apparatus or separate from it.
[0164] The temperature sensors may be electronic sensors or may be
a fibre optic cable.
[0165] Therefore in this situation the additional temperature
sensor array could provide data from the communication path
interval(s) and indicate if, for example, communication paths are
blocked/restricted. The array of temperature sensors in the tubing
line can also provide a clear indication of fluid flow,
particularly when the apparatus is activated. Thus for example,
more information can be gained on the response of the communication
paths--an upper area of communication paths may have been opened
and another area remain blocked and this can be deduced by the
local temperature along the array of the temperature sensors.
[0166] Such temperature sensors may also be used before, during and
after pumping the fluid and therefore used to check the
effectiveness of the apparatus.
[0167] Moreover, for certain embodiments, multiple longitudinally
spaced containers are activated sequentially, and the array of
temperature sensors used to assess the resulting flow from
communication paths.
[0168] Data may be recovered from the pressure sensor(s), before,
during and/or after the pump is operated in response to the control
signal. Recovering data means getting it to the surface. Data may
be recovered from the pressure sensor(s), before, during and/or
after a perforating gun has been activated in the well.
[0169] The data recovered may be real-time/current data and/or
historical data.
[0170] Data may be recovered by a variety of methods. For example
it may be transmitted wirelessly in real time or at a later time,
optionally in response to an instruction to transmit. Or the data
may retrieved by a probe run into the well on wireline/coiled
tubing or a tractor; the probe can optionally couple with the
memory device physically or wirelessly.
Memory
[0171] The apparatus especially the sensors, may comprise a memory
device which can store data for recovery at a later time. The
memory device may also, in certain circumstances, be retrieved and
data recovered after retrieval.
[0172] The memory device may be configured to store information for
at least one minute, optionally at least one hour, more optionally
at least one week, preferably at least one month, more preferably
at least one year or more than five years.
[0173] The memory device may be part of sensor(s). Where separate,
the memory device and sensors may be connected together by any
suitable means, optionally wirelessly or physically coupled
together by a wire. Inductive coupling is also an option. Short
range wireless coupling may be facilitated by EM communication in
the VLF range.
Well/Reservoir Treatment
[0174] Manipulation of the well may be done by delivering chemical
or acid treatment to the well. The chemicals delivered may be a
mixture of different substances.
[0175] For certain embodiments therefore, the container comprises a
chemical or other fluid to be delivered, such as an acid, and
"acid" treatments such as "acid wash" or "acid injection" can be
conducted. This may comprise hydrochloric acid or other acids or
chemicals used for such so-called acid treatments. The
chemical/treatment fluid could be treatment or delivery of the
fluids to the well or the formation, such as scale inhibitor,
methanol/glycol; or delivering gelling or cutting agents for
example bromine trifluoride, breaker fluid, tracer or a chemical or
acid treatment.
[0176] The method may be used to clear or extend communication
paths or clear the well of any type of debris. This may improve
well flow preferably after the isolation from the surface has been
removed and/or be used to clear a portion of the well prior to or
after perforating or at other times.
[0177] Communication path(s) can be perforations created in the
well and surrounding formation by a perforating gun. In some cases,
use of a perforating gun to provide communication path(s) is not
required. For example the well may be open hole and/or it may
include a screen/gravel packs, slotted sleeve or a slotted liner or
has previously been perforated. References to communication path(s)
herein include all such examples where access to the formation is
provided and is not limited to perforations created by perforating
guns.
[0178] Acid wash normally treats the face of the wellbore, or may
treat scale within a wellbore. Acids may be directed towards the
specific communication paths that are damaged, for example by using
openings in a tube.
[0179] A conventional acid set-up and treatment conducted from
surface is a time-consuming and therefore expensive process.
Instead of a conventional acid treatment the method according to
the invention may be performed to try to mitigate debris. `Debris`
may include perforation debris and/or formation damage such as
filter cake.
[0180] The apparatus may be used to deliver chemicals such as
tracers or breaker fluids. Chemical barriers may also be deployed,
or precursors to a chemical barrier for example cement type
material. As an alternative to cement, a solidifying cement
substitute such as epoxies and resins, or a non-solidifying cement
substitute may be used such as Sandaband.TM.. References herein to
cement include such cement substitutes.
[0181] An advantage of such embodiments is being able to deploy
chemicals in parts of a well in which it may not be possible to
deploy, or viably deploy, using conventional means.
[0182] The method described herein may also be used to conduct a
hydraulic fracturing or a minifrac operation.
[0183] In certain embodiments, the apparatus can be used to
disrupt, inhibit and/or reverse the settling out and partial
solidification of well fluids in parts of the well, especially the
annulus.
[0184] The apparatus is suitable for both openhole and perforated
sections and can be run with or without a perforation device.
Barrier Test
[0185] The apparatus may be provided below a barrier (such as
certain annular sealing devices described herein) and the well
manipulated such that a pressure test carried out therebelow, when
fluid is deployed. The increased pressure caused by fluid being
pumped into this area, stresses the barriers and so can be used to
test the upper barrier. Indeed, it stresses it in the direction it
is intended to withstand positive pressure, and so is a more
effective direction of testing, compared with testing it from
above.
[0186] Thus, for some methods, there need not be communication
between the formation and the well. For example a pressure test may
be conducted in a closed area in the well, for example between
barriers or annular sealing devices, i.e. there being no
communication paths in the well between the barriers or two annular
sealing devices and the adjacent formation.
[0187] For example, a lower barrier bridge or cement plug is
typically installed in a well to act as a primary barrier to the
reservoir and is exposed, on its lower side, to reservoir pressure.
Then a short distance above is a secondary barrier, often another
bridge plug or cement plug. Such a secondary barrier can be tested
from therebelow in accordance with the procedures set out
herein.
[0188] This compares to known methods of reducing the hydrostatic
head above such a barrier. This known test is time consuming and
removes the safety barrier of the hydrostatic head, compromising
well control.
[0189] The apparatus may hang off the secondary barrier.
[0190] The secondary barrier can be set after the apparatus is
deployed into the well and charged.
[0191] One or more secondary containers, described herein above,
may be provided having an underbalance of pressure. This may be
used to test the secondary barrier from below, or to draw in, at
least in part, the volume of fluid added from the primary container
after a test which added fluid has been completed.
[0192] Similarly, one or more secondary containers, described
herein above, may be provided having an overbalance of pressure.
This may be used to test the secondary barrier from below, or to
replace, at least in part, the volume of fluid removed from the
section between the two barriers after a test which removed fluid
has been completed.
[0193] A discrete temperature array may be deployed in the section
between the barriers, or in a ring or helix above or below the
barriers to assist in identifying the location of any leak
detected.
Charging Means
[0194] For certain embodiments including those used for such a
barrier test, the apparatus may surprisingly have an in-situ
charging means, even though for barrier tests, the pressure
surrounding the apparatus is being increased by the pump pumping
fluids into this area.
[0195] The charging means comprises a valve controlling a port.
Preferred embodiments have a gas separated from the fluid by a
floating piston. The valve is opened when pressure surrounding the
apparatus is higher than the pressure of the gas. It is therefore
charged. The charged gas then acts on the fluid to be deployed into
the surrounding portion of the well to assist the pump to deploy
the fluids.
[0196] The port may be used to deploy fluid and charge the gas.
Alternatively, separate ports may be provided.
[0197] The charging means has some similar features to the pressure
balancing means: the port may be a first port, and a second port
may be provided in the apparatus between the container and a
surrounding portion of the well, the first and second ports
separated within the apparatus by a floating piston.
[0198] Where separate ports are provided, the valve may be a
one-way valve such that when open, it allows fluid communication
from the well into the container, but resists such communication
from the container into the well. In a closed position it resists
communication in both directions.
[0199] For certain embodiments, the gas is compressed even more, by
imposing a pressure from or close to the surface of the well
(before the barrier is set) so that the charging means allows for
greater compression of the gas. The compressed gas is then sealed
in by closing the valve, then at least some of the additional
pressure imposed from surface is removed, and the barrier to be
tested is set. The gas acts on the fluid to be deployed from the
container into the well which facilitates the pump to expel fluids
into the surrounding portion of the well.
[0200] However, increasing the well pressure from the surface is
not preferred or is limited for certain embodiments, for example
where pressure activated tools are present in the well.
[0201] Additionally or alternatively, gas in the apparatus may be
pressurised at the surface before it is launched, to similarly
facilitate the pump for such an operation or for other applications
within the scope of the present invention.
Deployment
[0202] An annular sealing device may or may not be present in the
well.
[0203] For certain embodiments, the apparatus may be deployed with
an annular sealing device or after an annular sealing device is
provided in the well following an earlier operation. In the former
case, it may then be provided on the same string as the annular
sealing device and deployed into the well therewith. In the latter
case, it may be retro-fitted into the well and optionally below the
annular sealing device. In this example, it is normally connected
to a plug or hanger, and the plug or hanger in turn connected
directly or indirectly, for example by tubulars, to the annular
sealing device. The plug may be a bridge plug, wireline lock,
tubular/drill pipe set barrier, shut-in tool or retainer such as a
cement retainer. The plug may be a temporary or permanent plug.
[0204] Also, the apparatus may be provided in the well and then an
annular sealing device deployed and set thereabove and then the
method described herein performed after the annular sealing device
is run in.
[0205] The container may be sealed at the surface, and then
deployed into the well. `At surface` in this context is typically
outside of the well although it could be sealed whilst in a shallow
position in the well, such as up to 30 metres from the surface of
the well, that is the top of the uppermost casing of the well. Thus
the apparatus moves from the surface and is positioned in the well
with the container sealed, before operating the pump. Depending on
the particular embodiment and the deployment method, it may be run
in a well with no annular sealing device, or with the annular
sealing device already thereabove or move past a previously
installed annular sealing device.
[0206] For certain embodiments, the entire apparatus may be below
the annular sealing device, as opposed to a portion of the
apparatus.
[0207] The first port of the apparatus may be provided within 100 m
of a communication path between the well and the reservoir,
optionally 50 m or 30 m. If there is more than one communication
path, then the closest communication path is used to determine the
spacing from the first port of the apparatus. Optionally therefore,
the first port in the container may be spaced below communication
paths in the well.
[0208] In certain embodiments, the apparatus may be run on a
tubular string, such as a test, completion, suspension,
abandonment, drill, tubing, casing or liner string. Alternatively,
the apparatus may also be conveyed into the well on wireline or
coiled tubing (or a tractor). The apparatus may be an integral part
of the string.
[0209] The apparatus is typically connected to a tubular before it
is operated. Therefore whilst it may be run in by a variety of
means, such as wireline or tubing, it is typically connected to a
tubular such as production tubing or casing when in the well,
before it is operated. This provides flexibility for various
operations on the well.
[0210] The connection may be by any suitable means, such as by
being threaded, gripped, latched etc. onto the tubular. Thus
normally the connection between the tubular takes some of the
weight of the apparatus, albeit this would not necessarily happen
in horizontal wells.
[0211] The apparatus may be provided towards or at the lowermost
end of a lowermost casing or liner. The container may be defined,
at least in part, by the casing or liner. Therefore the lowermost
part of the container may be within 100 m of the bottom of the well
and indeed may be the bottom of the casing.
[0212] The string may be deployed as part of any suitable well
operation, including drilling, well testing, shoot and pull,
completion, work-over, suspension and/or abandonment operation.
[0213] The string may include perforating guns, particularly tubing
conveyed perforating guns. The guns may be wirelessly activatable
such as from the wireless signals.
[0214] In such a scenario, there may not be straightforward access
below guns to the lower zone(s). Thus when run with such a string,
embodiments of the invention provide means to pump fluids into such
a zone.
[0215] A plurality of apparatus described herein may be run on the
same string. For example spaced apart and positioned within a
section or isolated sections. Thus, the apparatus may be run in a
well with multiple isolated sections adjacent different zones. When
the port of the apparatus is isolated from the surface of the well,
flow may continue from a separate zone of the well, which is not in
pressure communication with the port, and not isolated from the
surface of the well.
[0216] The apparatus may be dropped off an associated carrying
string after the pump has been operated or for any other reason
(for example it is not required and is not possible or useful to
return it to surface). Thus it is not always necessary to return it
to the surface.
[0217] A variety of arrangements of the apparatus in the well may
be adopted. The apparatus may be positioned substantially in the
centre of the well. Alternatively the apparatus may be configured
as an annular tool to allow well flow through the inner tubular,
normally before the well is isolated, after the isolation is
removed, or from another section. Therefore, the container is
formed in an annular space between two tubes and the well can flow
through the inner tube.
[0218] In other embodiments, the apparatus can be offset within the
well, for example attached/clamped onto the outside of a pipe or
mounted offset within a pipe. Thus it can be configured so
apparatus or other objects (or fluid flow) can move through the
bore of the pipe without being impeded. For example it may have a
diameter of 13/4 inches offset inside a 4'' inner diameter outer
pipe. In this way, one or more wireline apparatus can still run
past it, as can fluid flow.
[0219] Other apparatus may not provide an arrangement to allow flow
past--for example, the container may take up the whole
cross-section of the tubing. In one embodiment, below an annular
sealing device and beneath communication paths, flow is directed
through an annulus between tubing and casing. This may be above or
below perforating guns where flow is already normally directed
through the tubing/casing annulus.
[0220] For certain embodiments, the apparatus may be deployed in a
central bore of a pre-existing tubular in the well, rather than
into a pre-existing annulus in the well. An annulus may be defined
between the apparatus and the pre-existing tubular in the well.
[0221] The apparatus may be run into the well as a permanent
apparatus designed to be left in the well, or run into the well as
a retrievable apparatus which is designed to be removed from the
well.
Short Interval
[0222] The method to manipulate the well according to the earlier
aspects or the third aspect (detailed below) of the invention, may
include the method of conducting a short interval test and so the
first port may be isolated in a short interval. The pump member can
be activated in response to the control signal normally to pump
fluid from (or possibly into) the short interval thereby
manipulating the well.
[0223] In contrast to the earlier embodiments where the first port
of the apparatus is provided between two barriers and pressure
tests conducted, the short interval is normally in communication
with the reservoir through at least one communication path.
[0224] According to a third aspect of the present invention there
is provided a method to manipulate a well by conducting a short
interval test, comprising: [0225] providing a pressure sensor in
the well; [0226] providing an apparatus in the well, the apparatus
comprising a container having a volume of at least 5 litres and a
port to allow fluid and optionally pressure communication between a
portion of an inside of the container and an outside of the
container; [0227] the port of the apparatus being below a first
portion of a packer element and above a second portion of a or the
packer element, said portions spaced apart from each other by up to
10 m thus defining a short interval, and each engaging with an
inner face of casing or wellbore in the well, and being at least
100 m below a surface of the well; [0228] the short interval
including at least one communication path between the well and the
formation; [0229] the apparatus further comprising: [0230] a pump
adapted to move fluid from the surrounding portion of the well into
at least a portion of the container via the port; [0231] a control
mechanism comprising a communication device configured to receive a
control signal for moving the valve member; [0232] deploying the
apparatus into the well on a tubular, [0233] sending a control
signal from outwith the short interval to the control mechanism at
least in part by a wireless control signal transmitted in at least
one of the following forms: electromagnetic, acoustic, inductively
coupled tubulars and coded pressure pulsing; [0234] operating the
pump in response to said control signal to allow fluid to enter the
container; and, [0235] drawing in at least 5 litres of fluid into
the container from the well.
[0236] In alternative embodiments, pressure in the container may be
reduced compared to an outside of the container, such as the
surrounding portion of the well, and rather than a pump, a valve
can be used to control the reduced pressure in order to draw fluids
into the container. Further embodiments have both options.
[0237] The short interval may be defined by one packer element
shaped to seal a (relatively small) interval formed from a recess
within, or the shape of, the overall packer element. Thus for such
embodiments, said first and second portions of a packer element
belong to the same packer element. A first packer may therefore
include the first and second portions of the packer element, for
example a single circular packer element.
[0238] In other embodiments, the short interval is defined between
packer elements such as the packer element described more generally
herein above and a further packer element. For such embodiments
said first and second portions of packer elements are separate
packer elements. For such embodiments, a first packer may therefore
include the first portion of the packer element, and a second
packer may include said second portion, which is a different packer
element.
[0239] Thus there can be a second packer element where at least the
port of the apparatus is positioned above the second packer
element. The entire apparatus may be positioned above said second
packer element. The second packer element may be wirelessly
controlled. Thus it may be expandable and/or retractable in
response to wireless signals.
[0240] Thus in contrast with the first aspect of the invention, the
port of the apparatus in the third aspect is below the first packer
element (a form of annular sealing device) whereas in the first
aspect of the invention the apparatus is below the annular sealing
device.
[0241] The short interval, i.e. the distance between two annular
sealing devices, may be less than 10 m, optionally less than 5 m or
less than 2 m, less than 1 m, or less than 0.5 m. These distances
are taken from the lowermost point of the first packer element, and
the uppermost point of the second packer element. Thus this can
limit the volume and so the apparatus is more effective when the
first port is exposed to the limited volume.
[0242] The wireless signal may be sent from outwith the short
interval to the control mechanism entirely in its said wireless
form.
[0243] Inflatable packers may comprise said packer elements
especially for openhole applications. For such openhole
applications, the packer elements used in the short interval test
may be relatively long, that is 1-10 m, optionally 3-8 m. This is
because the pressure drop in the formation may cause flow around
the packer element. Increasing the length of the packer element
reduces the risk of this occurring.
[0244] In preferred embodiments, fluid to/from the container is
pumped gradually over several seconds (such as 5-10 seconds), or
longer (such as 2 minutes-6 hours) or even very slow (such as 1-7
days).
[0245] For certain embodiments, such a test can provide an initial
indication on the reservoir response to an injection/hydraulic
fracturing operation, and may reduce the requirement to conduct a
larger scale injection/hydraulic fracturing test.
[0246] Sensors optionally record the pressure especially of the
formation for example at the port or outside the apparatus.
[0247] One or both of the packer element(s) may be part of an
annular sealing device, described more generally herein.
[0248] The packer(s) may be resettable, so that it/they may be set
in a first position and a first test may be performed, then
disengaged, moved and reset in a different position, where a second
test may be performed. Such a procedure is especially suitable in
an openhole section of the well.
[0249] The packer(s) used in a short interval manipulation may also
be deployed as part of a drill stem test (DST) string. For example,
when performing a drill stem test, a short interval test may be
conducted in a section of the well above or below the section being
tested in the DST.
[0250] Where space permits, a perforating device such as a
perforating gun may be provided in the short interval. This short
interval manipulation is also particularly suitable to being
performed in an openhole section.
[0251] In order to conduct a short interval test, at least one
packer is preferably deployed on a tubular, such as drill pipe,
casing and optionally coiled tubing.
[0252] The apparatus may be part of a string which includes a drill
bit. The packer(s) may be mounted on said string, and activated to
engage with an outer well casing or wellbore.
[0253] There may be a connector, as described herein more
generally, connecting the apparatus to the first packer, the
connector optionally being above the apparatus and below the first
packer element.
[0254] The outside of the container according to the third aspect
of the invention is a surrounding portion of the well between the
first and second portions of the packer element(s).
[0255] The method described herein may be used to conduct an
interval injectivity, permeability, pressure, hydraulic fracturing,
minifrac or similar test/manipulation.
[0256] In one embodiment, the well may be manipulated by conducting
a flow test. Flow from the reservoir is produced into the short
interval, and proceeds through the apparatus. The resulting pump
rate can be used to control and/or estimate the flow rate from the
reservoir.
[0257] Optional features described above with respect to the first
and second aspects of the invention are optional features with
respect to the third aspect of the invention. For example, a
floating piston and dump chamber are especially useful in
embodiments in accordance with the third aspect of the invention.
For example the container having volumes of at least 50 litres (l),
optionally at least 100 l and optionally a volume of at most 3000
l, normally at most 1500 l, optionally at most 500 l.
Further Procedure
[0258] The method to manipulate the well, may be a method to clear
the well especially by delivering fluids such as chemicals,
optionally in preparation for a test or further procedure.
[0259] According to a further aspect of the present invention there
is provided a method to conduct a procedure or test on a well,
comprising: [0260] conducting the method to manipulate the well or
formation, as described herein; [0261] conducting a procedure/test
on the well, the procedure/test includes one or more of a build-up
test, drawdown test, connectivity tests such as an interference
test or pulse test, a drill stem test (DST), extended well test
(EWT), hydraulic fracturing, mini frac, pressure test, flow test,
well/reservoir treatment such as an acid treatment, permeability
test, injection procedure, gravel pack operation, perforation
operation, image capture, string deployment, workover, suspension
and abandonment.
[0262] The test is normally conducted on the well before removing
the apparatus from the well, if it is removed from the well.
[0263] Embodiments of said further aspect may improve the pressure
or fluid communication across the face of the formation and improve
the performance of the tests/procedures. Thus the method of the
invention can improve the reliability and/or quality of data
received from subsequent testing or improve other procedures.
[0264] The method to conduct a test/procedure on the well may also
include perforating the well. However, the method of the present
invention may be independent from operation of the guns. The well
may be openhole and/or pre-perforated.
[0265] The apparatus may be used to clear the surrounding area, for
example by expelling a clear fluid, before images are captured.
[0266] The procedure may be a drill stem test (DST). Thus a DST
string and the annular sealing device are deployed as part of the
DST. After the final DST flow period or build up has been
conducted, a valve controlling flow into the DST test string is
closed. The valve is normally below the annular sealing device
though for certain embodiments it may be thereabove. The valve may
be controlled by said control signals. The portion of the DST
string above the valve (often above the annular sealing device) can
then, optionally, be removed. The well below the annular sealing
device can then be monitored as described herein. Notably the
underbalanced container may be activated when required, such as at
a much later date. Moreover, communication paths below the annular
sealing device between the well and the reservoir need not have
been contaminated by kill fluid, and so better connectivity with
reservoir can be maintained, providing more useful data when
conducting such connectivity tests. If the well is abandoned by
cementing above the annular sealing barrier (and normally adding a
further barrier) the wireless signals may still be used to monitor
the well below the annular sealing device. Data recovery before,
during or after the apparatus being activated is normally achieved
through wireless signals.
[0267] A pulse test is a type of connectivity test where a pressure
pulse is sent from one well/isolate section to another, and the
relatively subtle pressure wave detected in the second well. It can
then be inferred whether and to what extent the reservoir (or a
particular zone) is open and allows pressure communication between
these wells/isolated sections. This can be useful to determine the
optimum strategy for extracting fluids from the reservoir.
[0268] Another connectivity test is an interference test which
monitors longer term affects at an observation well following
production (or injection) in a separate well, and useful data can
also be obtained regarding the reservoir between the wells or
isolated sections, such as connectivity, permeability, and storage
capacity.
[0269] For such connectivity tests, the well being manipulated
according to embodiments of the present invention is the observing
well/sections. Thus the method described herein may include
observing for pressure changes in the well/section as part of a
connectivity test.
[0270] For certain other embodiments however, the method of
manipulating the well may be the well--particularly the isolated
section--from where pulses are sent using the apparatus. For
example, in a multi-lateral well, the apparatus may send a pressure
pulse from one side-track of the same well to another. Side tracks
(or the main bore) of wells which are isolated from each other are
defined herein as isolated sections.
Miscellaneous
[0271] The well may be a subsea well. Wireless communications can
be particularly useful in subsea wells because running cables in
subsea wells is more difficult compared to land wells. The well may
be a deviated or horizontal well, and embodiments of the present
invention can be particularly suitable for such wells since they
can avoid running wireline, cables or coiled tubing which may be
difficult or not possible for such wells.
[0272] References herein to perforating guns includes perforating
punches and drills, which are used to create a flowpath between the
formation and the well.
[0273] The surrounding portion of the well, is the portion of the
well surrounding the apparatus immediately before the pump is
activated in response to the control signal. More precisely it is
the pressure of the fluid at or `surrounding` the first port.
[0274] The volume of the container is its fluid capacity.
[0275] Transceivers, which have transmitting functionality and
receiving functionality, may be used in place of the transmitters
and receivers described herein.
[0276] Unless indicated otherwise, any references herein to
"blocked" or "unblocked" includes partially blocked and partially
unblocked.
[0277] All pressures herein are absolute pressures unless stated
otherwise.
[0278] The well is often an at least partially vertical well.
Nevertheless, it can be a deviated or horizontal well. References
such as "above" and below" when applied to deviated or horizontal
wells should be construed as their equivalent in wells with some
vertical orientation. For example, "above" is closer to the surface
of the well through the well.
[0279] A zone is defined herein as formation adjacent to or below
the lowermost barrier or annular sealing device, or a portion of
the formation adjacent to the well which is isolated in part
between barriers or annular sealing devices and which has, or will
have, at least one communication path (for example perforation)
between the well and the surrounding formation, between the
barriers or annular sealing devices. Thus each additional barrier
or annular sealing device set in the well defines a separate zone
except areas between two barriers or annular sealing devices (for
example a double barrier) where there is no communication path to
the surrounding formation and none are intended to be formed.
[0280] "Kill fluid" is any fluid, sometimes referred to as "kill
weight fluid", which is used to provide a hydrostatic head
typically sufficient to overcome reservoir pressure.
[0281] Embodiments of the present invention will now be described,
by way of example only, with reference to the accompanying figures
in which:
[0282] FIG. 1 is a schematic view of a first apparatus which may be
used in the method of the present invention;
[0283] FIG. 2 is a schematic view of a second apparatus including a
floating piston in accordance with the present invention;
[0284] FIG. 3 is a schematic view of a well with multiple zones,
illustrating methods in accordance with the present invention;
[0285] FIG. 4 is a schematic view of a well illustrating further
methods in accordance with the present invention;
[0286] FIG. 5 is a schematic view of a further apparatus including
a floating piston and a control container in accordance with the
present invention;
[0287] FIG. 6a is a schematic view illustrating the FIG. 5
apparatus used in a short interval test in accordance with the
present invention;
[0288] FIG. 6b is a schematic view of the apparatus used in a
further short interval test in an uncased section of a well;
[0289] FIG. 7 is a schematic view of a further embodiment of the
apparatus including a charging means in accordance with the present
invention;
[0290] FIG. 8 is an alternative apparatus having a charging means
in accordance with the present invention; and,
[0291] FIG. 9 is an alternative apparatus where a well casing
defines part of the container.
[0292] FIG. 1 shows an apparatus 60 in accordance with the present
invention in the form of a modified pipe, comprising a container
68, a side opening 61, an electrically powered pump 62 in the
opening 61, a control mechanism comprising a pump controller 66 and
wireless transceiver 64, and a battery 63.
[0293] The pump 62 is configured to pump fluids from/to the
container 68 to/from a surrounding portion of the well (outside the
apparatus 60) thus selectively allowing fluid communication between
a portion of the container 68 and the surrounding portion of the
well.
[0294] The pump 62 is controlled by the pump controller 66. The
transceiver 64 is coupled to the pump controller 66 and is
configured to receive a wireless control signal.
[0295] The components of the control mechanism (the transceiver 64
and the pump controller 66 which controls the pump 62) are normally
provided adjacent each other, or close together as shown; but may
be spaced apart.
[0296] In the illustrated embodiment, the container 68 comprises
liquid 90 to be deployed into the well, and a gas 92, such as
nitrogen thereabove. In such embodiments, a wireless signal is
received by the transceiver 64 instructing the pump 62 to operate
and pump the fluid 90 from the container 68 into the surrounding
portion of the well. The gas 92 expands as the liquid 90 is
directed into the well.
[0297] In some embodiments, the apparatus 60 can be used for tracer
discharge.
[0298] FIG. 2 shows an embodiment of an apparatus 160. Like parts
with the FIG. 1 embodiment are not described in detail but are
prefixed with a `1`. The apparatus 160 comprises a chamber 168 with
a floating piston 174, a dynamic seal 175 between the floating
piston 174 and the container's inner bore and a check valve 177 and
a pump 162 both provided in an opening 161 to the container 168.
Significantly, a pressure balancing port 173 is also provided
between the container 168 and the surrounding portion of the well,
on the opposite side of the floating piston 174 from the opening
161. A battery 163, transceiver 164 and pump controller 166 are
also provided.
[0299] The check valve 177, when in an open position, resists fluid
flow from the well into the container 168 but allows fluid flow
from the container into the well. The pump 162 is controlled by the
pump controller 166. A communication device in the form of a
transceiver 164 is coupled to the pump controller 166 and is
configured to receive a wireless control signal, such as from an
operator at the surface of the well.
[0300] In the present embodiment, the pressure balancing port 173
allows the pump 162 to have a lower rating as it only needs to
overcome a relatively small pressure difference to move the fluid
between the container 168 and the well; not a larger pressure
difference for embodiments without such a port, which also need to
overcome the difference in pressure between the container 168 and
the well.
[0301] In use, the portion of the container 168 above the floating
piston 174 is filled with liquid to be deployed. The sequence
begins with the check valve 177 in a closed position and the pump
162 switched off. An operator at the surface of the well sends a
wireless signal to the transceiver 164 coupled to the pump
controller 166 which instructs the pump 162 to turn on and the
check valve 177 consequently opens. The pump 162 then begins moving
the liquid from the container 168 above the floating piston 174
into the surrounding portion of the well. As the fluid is expelled
from the container 168, fluid from the well enters the chamber 171
via the pressure balancing port 173.
[0302] The rate at which the liquid in the container 168 above the
floating piston 174 is expelled into the surrounding portion of the
well is controlled by the speed at which the pump 162 operates.
[0303] In other embodiments, the check valve allows fluid flow from
the well into the container but resists fluid flow from the
container into the well. In such embodiments, the pump directs
fluid from the surrounding portion of the well into the container
for example, to conduct an inflow test. In such embodiments, the
inlet port and pressure balancing port are normally open onto
portions of the well isolated from each other.
[0304] In an alternative FIG. 2 embodiment there is no pressure
balancing port. However the floating piston is present which seals
a gas containing section, from a fluid/liquid containing section
which is between the port and the floating piston.
[0305] FIG. 3 shows a multi-zone well 114 comprising a liner hanger
129 and liners 112a and 112b, and two sets of apparatus 260 and
60.
[0306] The apparatus 60 has been previously described. It may be
orientated in use as drawn in FIG. 1, or as shown in FIGS. 3 and 4
with a pipe (not shown) within the container 68 provided to draw
liquid from a bottom of the container 68 to the opening 61 when the
pump 62 operates.
[0307] The apparatus 260 is similar to apparatus 60, 160 and can
have the configuration described for apparatus 60 in FIG. 1 or
apparatus 160 of FIG. 2. Like parts with earlier embodiments are
not described in detail but are prefixed with a `2`.
[0308] Additionally, apparatus 260 also comprises an outlet tube
135, which has multiple openings or outlets 137 through which fluid
can be released onto an adjacent upper slotted liner 154a.
[0309] The well 114 has its own well apparatus 110 which comprises
two packer elements 122a & 122b which splits the well into a
plurality of isolated sections. A first, upper, section comprises
the upper packer element 122a, a wirelessly controlled upper sleeve
valve 134a, the upper apparatus 260 and the upper slotted liner
154a. The sleeve valve 134a, together with the packer 122a are the
isolating components which isolate the port of the apparatus 60a'
from the surface of the well.
[0310] A second, lower, section comprises the lower packer element
122b, a wirelessly controlled lower sleeve valve 134b, the lower
apparatus 60 and a lower slotted liner 154b. For this second
section, the sleeve valve 134b, together with the packer 122b are
the isolating components which isolate the port of the apparatus
60a'' from the surface of the well. Moreover, they also function as
lower isolating components for the first upper section.
[0311] The slotted liners 154a, 154b create communication paths
between the inside of the liner 112a and the adjacent
formation.
[0312] Isolating the sections from each other provides useful
functionality for manipulating each adjacent zone individually
though this is not an essential feature of the invention. For
example, the valve 134a in the upper section can be closed to
isolate the upper apparatus 60a' from surface of the well, whilst
flow continues from the zone adjacent the second lower section.
[0313] The well 114 further comprises a packer such as a swell
packer 128 between an outer surface of the liner 112a and a
surrounding portion of the formation. The upper tubular 118 and
lower tubular 116 are continuous and connected via the upper packer
element 122a and the lower packer element 122b. Portions of the
upper tubular 118 and lower tubular 116 thus serve as connectors to
connect the upper apparatus 260 and lower apparatus 60 to the
packer elements 122a, 122b respectively.
[0314] Instrument carriers 140, 141 and 146 are provided in each
section and also above the packer element 122a. Each instrument
carrier comprises a pressure sensor 142, 143, and 148 respectively,
and a wireless relay 144, 145, and 149 respectively.
[0315] In use, fluid flows through the lower slotted liner 154b and
into the lower tubular 116 via the lower sleeve valve 134b. The
flow continues through the lower tubular 116 past the lower packer
element 122b, the upper apparatus 260 and instrument carrier 146
before continuing through the upper tubular 118 towards the
surface. The upper apparatus 260 (in contrast to the lower
apparatus 60) does not take up the full bore of the upper tubular
118 and so fluid can flow therepast from below without being
diverted outside of the upper tubular 118.
[0316] From an upper zone, the well flows through the slotted liner
154a and into the upper tubular 118 via the sleeve valve 134a. The
flow continues through the upper tubular 118, past the upper packer
element 122a towards the surface.
[0317] The flow may be from the upper zone adjacent the well 114
only, the lower zone adjacent the well 114 only, or may be
co-mingled, that is produced from the two zones simultaneously. For
example, fluids from the slotted liner 154b combine with further
fluids entering the well 114 via the upper slotted liner 154a to
form a co-mingled flow.
[0318] The apparatus 260 functions as described for earlier
embodiments of the apparatus save that it distributes liquid onto
the upper slotted liner 154a. It is activated when the outlets 137
are isolated from the surface of the well such as prior to flowing
the well, or after flowing the well. A wireless signal is sent from
a controller (not shown) to a pump controller via a transceiver and
a pump operates to expel fluid from the container to the
surrounding portion of the well (or vice versa). The apparatus 260
is particularly suited to deploying acid for an acid treatment, as
it can distribute the fluid over the slotted liner 154a via the
tube 135. Optionally pressure in the well can be increased by
conventional means to "inject" the acid into the formation.
[0319] The apparatus 60 is activated as previously described.
[0320] Thus embodiments of the apparatus are particularly suited to
delivering fluids into the well in a controlled manner such as
tracers. Radioactive or chemical tracers may be added and detected
elsewhere in the well or at surface, for example to gain more
information on fluids produced from separate zones, when co-mingled
flow is occurring.
[0321] FIG. 4 illustrates a method of the present invention used
during a drill stem test (DST) operation. Two apparatus 60 and 260
are provided in two different sections of a well 214, the sections
separated by an annular sealing device in the form of a packer
element 222.
[0322] The apparatus 60 is provided above the packer element 222.
Above the packer element 222, the well 214 includes a tubing 218
and a casing 212, with an annulus 291 therebetween. A tester valve
230 and a circulation valve 231 are also provided. In use, the
annulus 291 between the tubing 218 and the casing 212 above the
packer element 222 includes well fluids which may be relatively
dense fluid or mud, especially for high pressure wells. The present
inventors have noted that under certain circumstances, the mud may
become particularly dense and indeed partially solidify, close to
the packer element 222, for example as the heavier components
settle due to gravity or other forces. The transmission of pressure
signals close to or through this substance is more
difficult--signals may only be received intermittently or not at
all. For example, transmission of signals to a tester 230 or
circulation 231 valve can be inhibited.
[0323] The apparatus 60 therefore functions to pump fluid out of
the container 68 to disrupt, inhibit and/or reverse the settling
out and partial solidification of well fluids in the annulus.
Signals to the tester valve 230 or circulation valve 231 above the
apparatus 60 are thereafter more reliable.
[0324] A variety of alternatives can be provided. The pump may be
operated intermittently so that the disruption can be repeated at
spaced apart times. Further containers or indeed apparatus may also
be used for the same purpose.
[0325] The apparatus 260 is provided below a perforating gun 250.
Two outlet tubes 135, 136 extend from opening 261a of the apparatus
260 over the perforating gun 250. The tubes 135, 136 can have
multiple outlets 137 as shown, or alternatively a single outlet,
for example to deploy a tracer. Each tube 135, 136 has a valve 265a
which can be independently controlled to direct fluid from the
container 268a onto selectively different portions of the
perforation interval 252. Both tubes 135, 136 are controlled by the
same pump 262a. Further valves may be added to provide independent
control to each opening. The tubing 218 and perforating gun 250
serve as a connector to connect the apparatus 260 to the annular
sealing device 222.
[0326] A discrete temperature array 253 is provided adjacent to the
perforations 252 and connected to a controller 255. In this
embodiment the discrete temperature array has multiple discrete
temperature sensors along the length of a small diameter tube.
[0327] After isolation from the surface of the well, the apparatus
260 is activated wirelessly causing the pump 262a to start, which
can direct fluid, such as acid or tracer, onto the
perforations.
[0328] The two apparatus 60, 260 illustrated in FIGS. 3 and 4 can
be used independently of each other in single or multiple zone
wells and are illustrated in the same figure and same well for
brevity.
[0329] A further embodiment 360 of apparatus suitable for use in
the method of the invention is shown in FIG. 5. Like parts with
earlier embodiments are not described in detail but are prefixed
with a `3`.
[0330] The apparatus 360 comprises a container 368 having a
floating piston 374 with seals 375 and a pump 362. A valve 377
(optionally a check valve) is provided in an opening 361 of the
container 368.
[0331] The apparatus 360 also comprises other components which are
not shown, including a battery, a pump controller and a transceiver
for wireless signals.
[0332] In contrast to the FIG. 2 embodiment, the pump 362 is
provided in a central portion, between the container 368 and a
control container 380. The control container 380 has a second
floating piston 382, along with seals 383; and below the second
floating piston 382 a port 373 is provided to allow a pressure
balance between the control container below the second floating
piston 382 and the surrounding portion of the well.
[0333] A control fluid is provided above the second floating piston
382 whilst a fluid to be expelled is provided in the container 368
above the floating piston 374. In use, a wireless signal is sent to
the pump 362 via the transceiver and pump controller, and the pump
362 pumps control fluid from the control container 380 into the
container 368, below the floating piston 374. This in turn moves
the floating piston 374 and expels the fluid in the container 368
to the surrounding portion of the well.
[0334] The pump 362 can also operate in a reverse direction to that
described. The control fluid is pumped from the container 368 below
the floating piston 374 into the control container 380 thus drawing
well fluids into the container 368 above the floating piston
374.
[0335] The apparatus 360 can be cycled between expelling and
drawing in fluids indefinitely. An advantage of such an apparatus
is that the pump pumps a `clean` control fluid rather than the well
fluids which are much more variable in their physical properties
which may affect the flow rate and any related data.
[0336] In alternative embodiments, rather than a port 373 allowing
pressure balance, the section below the second floating piston may
be sealed and pre-charged with gas under pressure.
[0337] FIG. 6a shows one application of the FIG. 5 apparatus for
use with a short interval test using the apparatus 360. The packers
322a and 322b are set in the casing 312, and a perforating tool 350
receives a wireless signal to activate and punch a hole 352 in the
casing 312 and adjacent formation 351.
[0338] The apparatus 360 then receives a control signal to start
the pump 362 to pump control fluid from the control container 380
into the container 368 below the piston 374, which in turn expels
fluids in the container 368 above the piston 374. In this way, an
injection test can be carried out, during which the build-up of
pressure can be monitored using pressure sensor(s). Data from the
pressure sensor(s) can be transmitted wirelessly, for example by
acoustic or electromagnetic signals, to the surface to monitor the
results of the test.
[0339] Optionally a tube with multiple exits can be provided at the
opening 361 to distribute fluids over an area, such as a plurality
of communication paths.
[0340] Optionally the pump 362 can be reversed to draw in fluids
from the well. Moreover, a variety of alternatives are available
for such a procedure. In one embodiment, the pump 362 can be
stopped and started before the container 368 has expelled its
contents (or if operating in reverse, before it has been filled
with well fluid) and this start/stop sequence can be repeated. In
one embodiment, an operator can unseat the packers 322a, 322b,
reposition the apparatus 360, re-seat the packers 322a, 322b, and
then conduct the procedure again.
[0341] In one alternative embodiment, a second container is
provided at a different pressure to the surrounding portion of the
well, for example it may be underbalanced. This may be activated
to, for example, purge the surrounding area of debris before the
apparatus 360 is operated. Such a further container having a
different pressure, may be combined with other embodiments
described herein.
[0342] FIG. 6b shows a similar short interval test using a well
apparatus 310b, apparatus 360b in an uncased/openhole section of
well 315.
[0343] In this embodiment a single packer 322c is provided with an
opening 394 aligned with a port 361b of the apparatus and so a
portion of the packer is above the port 361b and a portion of the
packer is below the port 361b, thus isolating a short interval. The
apparatus 360b also comprises a pump 362b and a valve 377b in close
proximity to each other. A pressure gauge 395b monitors the
pressure of the interval and is powered by a battery 363b.
[0344] The short interval test or other manipulation can be
conducted following the same procedure described with respect to
FIG. 6a.
[0345] In certain situations, it may be useful to control the
interval for instance to add `kill` fluid. Optionally therefore, a
sleeve valve 330 can be provided between the tubing string 318 and
surrounding annulus 291A which can be opened to allow pressure
connectivity between the interval and the string above, for example
to allow kill fluid to enter the interval.
[0346] Certain embodiments of the invention may be used to conduct
a barrier test in a well. They are placed beneath the sealed
barrier, and then expel fluids in order to increase the volume
below the barrier and so stress the barrier in order to test
it.
[0347] FIG. 7 shows apparatus 460a with a charging means in
accordance with the present invention and which is particularly
suited to such barrier tests. Like parts with earlier embodiments
are not described in detail but are prefixed with a `4`.
[0348] The apparatus 460a, comprises a container 468a, a pump 462a
in a port 461a and a side port 473a with a valve 477a. The
container has a floating piston 474a separating a first liquid
containing section 491a from a second gas containing section
492a.
[0349] In use, the apparatus 460a may be deployed with the floating
piston 474a positioned such that around three quarters of the
container 468a is the gas containing section 492a and around one
quarter is the liquid containing section 491a. As the apparatus is
moved deeper into the well, the increased well pressure, will cause
movement of the floating piston 474a and compression of the
gas.
[0350] The apparatus is positioned below the barrier to be tested,
with the valve 477a open and well fluids are received into the
first section 491a of the container 468a compressing or `charging`
the gas in the second section 492a to the surrounding well
pressure. The valve 477a is then closed.
[0351] When the barrier (not shown) is in place, the pump 462a is
operated to pump the fluid from the first section 491a of the
container 468a into the surrounding portion of the well. The
compressed gas in the second section 492a of the apparatus 460a
acts on the liquid in the first section 491a so that it is
substantially at well pressure before the further action of the
pump 462a, thus facilitating the pump 462a to operate (compared to
pumping a liquid having an atmospheric pressure). In this way, a
lower pump rating may be used.
[0352] The barrier can be formed before or after the apparatus is
charged.
[0353] For certain embodiments, the pressure may be stored as
described when the well pressure is increased from the surface,
which will further charge the apparatus. This may be done by
applying pressure or before circulating heavy fluids in the well's
hydrostatic head for lighter fluids. It may take advantage of the
well pressure changing for some other reason/operation or be done
intentionally to increase the charge to the apparatus. In such
circumstances, the charging would normally take place before the
barrier is set.
[0354] FIG. 8 shows an apparatus 460b which is a modified version
of the apparatus 460a where the charging means facilitates
deploying a specific fluid in the well (for example acid). Like
parts will not be described again in detail but will be suffixed
with a `b` rather than an `a`.
[0355] In common with the FIG. 7 embodiment, the FIG. 8 apparatus
460b comprises a pump 462b in a port 461b, a floating piston 474b
within a container 468b, a first liquid containing section 491b and
a second gas containing section 492b.
[0356] In contrast to the FIG. 7 embodiment, a valve 477b in the
apparatus 460b is provided in a second port 473b at an opposite end
to the pump 462b. Moreover a second floating piston 482b is
provided in the container 468b between the second port 473b and the
first floating piston 474b, to define a third `charging` section
493b of the container 468b.
[0357] The apparatus 460b can be similarly charged via the second
port 473b and the apparatus 460b operated in the same manner as
that described above with respect to apparatus 460a. A benefit of
the FIG. 8 apparatus over the FIG. 7 apparatus is that the liquid
expelled from the liquid containing section 491b can be chosen for
an alternative (or additional) purpose than pressure testing, for
example acid treatment, rather than using liquid from the well.
[0358] In FIG. 9 an alternative embodiment of an apparatus 560 with
a container 568 is illustrated. Common features, for example pump
565 and valve 562, with earlier embodiments are not described again
in detail for brevity but use the same latter two digits as
reference numerals with a `5` prefix. In contrast to earlier
figures the container 568 is in part defined by the surrounding
casing 512 and outlet tube 535 with openings 537 is secured to a
portion of the casing 512 above the container 568 by clamps 596.
Such an apparatus 560 is normally run on the casing 512 when
completing the well. An advantage of such an embodiment is that the
container can have larger volumes without running further tubing
into the well. The apparatus 560 may have flow bypass 597 for
cementing during completion or for circulating during deployment.
Such embodiments are useful for deploying treatments to a toe of a
deviated well.
[0359] It will be appreciated that the method according to the
invention can be carried out using a variety of apparatus 60, 160,
260, 360, 360b, 460a, 460b, 560 and the examples using these
different apparatus in different contexts are not limiting, and the
different apparatus can be used in the different positions shown in
the FIGS. 3, 4, 6a, 6b and 9 wells.
[0360] Modifications and improvements can be incorporated herein
without departing from the scope of the invention. For example
various arrangements of the container and electronics may be used,
such as electronics provided in the apparatus below the
container.
* * * * *