Note: Descriptions are shown in the official language in which they were submitted.
CA 02875034 2014-12-17
METHOD, SYSTEM AND APPARATUS FOR COMPLETING AND OPERATING
NON-THERMAL OIL WELLS IN HIGH TEMPERATURE RECOVERY PROCES SES
FIELD OF THE INVENTION
The present invention relates to a method, system and apparatus for completing
and operating a
well for the production of viscous hydrocarbons from a heavy oil bearing
formation. More
particularly, it relates to completion of a non-thermally cased well for the
purpose of injecting of
a mixture of high temperature combustion gases and steam into the formation.
BACKGROUND OF THE INVENTION
Heavy oil is produced throughout the world using non-thermally completed wells
to recover cold
viscous hydrocarbons from formations. Primary cold recovery methods often
result in production
of less than 10% of the original oil in place due to reservoir pressure
depletion and loss of a drive
mechanism, and due the extremely high viscosity of the oil which restricts
flow through the
formation. In North America alone, 10's of 1000's of heavy oil wells have been
drilled and
following a number of years of primary production have been shut-in or
suspended awaiting
development and implementation of an economic secondary recovery mechanism.
Many of these
wells have been completed and operated using a recovery process of "Cold Heavy
Oil
Production with Sand" commonly referred to as CHOPS. The production of sand
along with cold
heavy oil in CHOPS wells results in the production of voids and pathways
commonly referred to
as "worm holes" and massively enhanced permeability because of the remolding
and plastic
deformation that takes place. These worm holes and areas of enhanced
permeability serve are
conduits for the introduction of fluids into the formation including steam,
solvents and non-
condensable gasses at pressures below fracture or virgin pressure of the
formation.
In one cyclic secondary recovery technique, steam is first injected into a
thermally completed
well, after which heavy oil is produced from the same well following a short
period of time
during which the formation is allowed to soak, commonly referred to as "cyclic
steam
stimulation" or CSS. In another cyclic secondary recovery technique, a non-
condensable gas
such as methane, flue gas or nitrogen is compressed, heated and saturated with
water prior to
injection into a CHOPS well. The non-condensable gas serves to pressure the
formation thereby
providing a drive mechanism for production of the heavy oil. The latent heat
of condensation
released as the water of saturation changes from the vapor phase to the liquid
phase provides
energy to heat the formation. Following pressuring and heating of the
formation, the well is
recompleted to convert it from an injection well to a producing well and
placed on production.
In the prior art, for these CSS secondary recovery techniques a well is
preferentially equipped
with insulated tubing plus an isolation packer for the purpose of injecting
the hot fluids into a
formation. The isolation packer is installed between the tubing and annulus at
the bottom of the
well for the purpose of preventing hot fluids introduced into the well via the
insulated tubing
from entering the CHOPS well annulus where the fluids could otherwise heat the
non-thermal
casing and cement above their maximum design operating temperature. Following
completion of
the injection cycle and before the well can be placed on production, the
insulated tubing and
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associated packer isolating the annulus must first be removed so that gas
which is separated from
the heavy oil at the bottom of the well can be produced up the annulus.
Following removal of the
isolation packer, conventional or insulated production tubing is reinstalled
in the well, a bottom-
hole pump is installed in the well and oil flowing into the well from the
formation is pumped to
the surface via the production tubing.
Petroleum industry operating experience has confirmed that injection of non-
condensable gas or
solvent can be an effective method of reestablishing a drive mechanism in
pressure depleted
heavy oil reservoirs, and that injection of steam is an effective method of
heating a formation to
reduce heavy oil viscosity and thereby increase the flow rate of fluids from
the formation.
Canadian Patent Application 2,747,766 describes a pressurized Submerged
Combustion
Vaporizer (hereafter referred to as a SCV) for the purpose of producing a
reservoir heating and
pressurizing fluid consisting of both steam and water saturated combustion
gases for use in
recovery of viscous hydrocarbons and bitumen. Prior field operating experience
confirms that
injecting these hot fluids into an existing heavy oil reservoir is an
effective hybrid secondary
recovery mechanism. An efficient and cost effective method of implementing
secondary
recovery is to utilize existing shut-in and suspended CHOPS wells and related
field and site
infrastructure for this purpose.
Many CHOPS wells are not completed with production casing and cement that is
capable of
withstanding the high temperature that would occur in the well annulus during
injection of
thermal fluids. Accordingly, a new method, system and apparatus is required
whereby non-
thermal CHOPS or other wells can be recompleted and operated so that the
temperature of the
casing and cement is maintained within maximum operation temperature limits
during
continuous injection of very hot fluids at temperatures up to 350 C.
Furthermore, it is
advantageous to develop a CHOPS well completion method and operating system
and apparatus
that does not require the installation of an isolation packer to prevent hot
fluids introduced into a
well via the insulated tubing from entering the CHOPS well annulus.
Elimination of the packer
provides the added benefit and advantage of substantially reduced well
recompletion work for
cyclic secondary recovery processes due to the fact that the insulated tubing
installed for the
injection phase can also be used for the subsequent production phase.
Relatively new advances in design and manufacture of high efficiency vacuum
insulated tubing
have made it possible to continuously inject fluids at temperatures up to 140
C in non-thermally
completed heavy oil wells, at the same time maintaining the temperature of the
well casing and
cement within maximum temperature limits. In this case, the heavy oil well is
equipped with a
bottom-hole packer between the tubing and annulus to isolate and prevent the
hot injected fluids
from entering the annulus and overheating the non-thermal casing and cement.
This same type of high efficiency vacuum insulated tubing has also been used
in high
temperature thermal recovery processes in which high pressure steam is
injected into formations
for the recovery of heavy oil and bitumen. In these cases, the injection and
production wells are
equipped with thermal grade casing and cement which are capable of handling
the high
temperatures. Use of insulated versus conventional production tubing in these
thermally
completed wells provides the benefit of reduced heat loss from the tubing to
the overburden
during injection of the steam and increased overall efficiency of the thermal
recovery process.
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Some thermal project operators have further reduced heat loss to the
overburden by placing a
static blanket of nitrogen or other non-condensable gas in the annular space
between the casing
and insulated tubing. A further benefit of utilizing insulated tubing and
blanket gas in thermally
completed wells is that it reduces the thermal stresses in casing strings and
therefore reduces
potential for casing failure.
Deficiencies of the Prior Art
None of the prior art literature discloses a method, system and apparatus to
pressurize and heat a
formation containing heavy oil or bitumen by recompleting an existing CHOPS or
other non-
thermal heavy oil well with insulated tubing but without the above referenced
isolation packer,
thereby permitting the concurrent continuous injection of both tubing conveyed
heating fluids
and annulus conveyed cooling fluids into the formation.
None of the prior art discloses a method, system and apparatus for injecting a
mixture of high
pressure steam and combustion gas fluids into a formation via an insulated
tubing string installed
in a well, at the same time continuously injecting a cooling fluid into the
well annulus between
the insulated tubing and casing for the purpose of maintaining casing and
cement temperatures
within maximum temperature limits, which cooling fluid is subsequently mixed
at the bottom of
the well with the products injected via the tubing, following which the entire
mixture is
introduced into the formation.
None of the prior art discloses a method of producing a well annulus cooling
fluid having the
same composition as a SCV or other direct contact steam generator's outlet
product, the cooling
fluid being produced by extracting and cooling a small side-stream of the
outlet product and
injecting it into a well annulus.
None of the prior art discloses a method for preventing hot fluids injected
into the bottom of a
well via an insulated tubing from entering and flowing backwards and up into
the well annulus
by injecting a continuous stream of cooling water, non-condensable gas,
solvents, hydrocarbons,
CO2, nitrogen and flue gas or any combination or mixture thereof into the
annulus at the top of
the well, thereby providing both cooling of the annulus, casing and adjacent
cement plus
directing and ensuring the flow of all injected fluids is downwards and into
the formation.
SUMMARY OF THE INVENTION
The present invention provides an oil recovery method, system and apparatus
which are uniquely
applicable to recovery of viscous hydrocarbons from a formation. It is an
advantage of the
present invention that it overcomes prior art deficiencies, providing a means
of injecting high
temperature fluids into a formation using wells that are not completed with
production casing
and cement capable of withstanding the high temperatures, without the risk of
casing and cement
failure due to the high temperature of the injected fluids. A further
advantage of the present
invention is that it also provides a means of reducing temperatures and
therefore stresses
imposed on well casing and cement in thermally completed wells as it does for
non-thermally
completed wells.
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In accordance with the present invention, a length of insulated tubing is
installed in a well and
landed adjacent to the hydrocarbon containing formation for the purpose of
injecting hot fluids
such as steam and hot gases into the formation. In the prior art, in cases
where heavy oil wells
are completed without the benefit of thermal casing and cement, a packer is
installed between the
tubing and casing immediately above the formation to isolate and prevent the
hot injected fluids
from entering the annulus and heating the non-thermal casing. In accordance
with the design of
the present invention, a packer is not installed between the tubing and casing
and instead a
continuous stream of pressurized cooling fluids is introduced into the well
annulus between the
insulated tubing and casing. Injection of these cooling fluids provide a
positive downward flow
from the top of the well, through the annulus, and into the bottom of the well
where it mixes with
the high temperature fluids injected via the insulated tubing after which the
entire mixture is
injected into the formation. The aforementioned cooling fluids serve the
purpose and advantage
of maintaining casing and cement temperatures within maximum design operating
temperature
limits plus prevent the hot fluids injected into the bottom of a well via the
insulated tubing from
entering and flowing backwards and up into the well annulus.
In the preferred embodiment to the present invention, when used in conjunction
with a SCV as
described in Canadian Patent Application 2,747,766, a small side-stream of the
SCV steam-
combustion gas product is cooled and introduced into the well annulus for the
purpose of
removing heat from the annulus and preventing hot injected fluids from
entering the annulus at
the bottom of the well. Depending on the enhanced oil recovery process
employed, other cooling
fluids can be used to maintain the well annulus within temperature limits plus
provide a positive
downward flow to prevent hot injected fluids from flowing backwards and up
into the annulus,
including water, solvents, hydrocarbons, CO2, nitrogen and other non-
condensable gases.
This invention in its broadest application relates to a method, system and
apparatus for thermal
recovery of viscous heavy oil and bitumen from subsurface deposits throughout
the world using
non-thermally completed wells. More specifically, throughout Western Canada's
heavy oil belt
thousands of partially depleted non-thermal CHOPS heavy oil wells are either
suspended or near
the end of their primary production life, and many of these wells can be
recompleted and
operated for thermal enhanced oil recovery by employing the present invention.
BRIEF DESCRIPTION OF THE DRAWING
These and other features and advantages of the present invention will become
apparent from the
following detailed description of the accompanying drawing.
FIG. 1 is a simplified pictorial representation showing a SCV or other system
for production of
formation heating fluids and annulus cooling fluids, in conjunction with a
method and apparatus
for injecting high temperature fluids into a formation using a non-thermal
well. Included is a
cross section elevation view of a typical non-thermally completed CHOPS well.
In this drawing
the CHOPS well is shown as recompleted with vacuum insulated tubing and
configured for the
purpose of injecting steam and combustion gases into a subsurface formation
during an injection
cycle and for production of oil during a subsequent production cycle.
CA 02875034 2014-12-17
Fuel 1 is combusted in the presence of air 3 or oxygen 4 in a SCV 5. The
products of
combustion are mixed with water 2 in a direct contact steam generation
process, producing a
thermal fluid product 6 for heating a formation. Where the product is produced
by a direct
contact SCV steam generator 5, the heating fluid stream 6 consists of both
steam and combustion
gases. The SCV 5 is advantageous for this purpose since it produces steam to
heat the formation
plus non-condensable gases for pressurizing the formation. The SCV system
produces an
annulus cooling fluid 7 having the same composition as the SCV outlet product
stream 6 by
incorporating an internal process whereby a small side stream of product is
extracted and cooled
prior to introduction into the well annulus 8. This is an ideal embodiment:
variations are possible
depending on the enhanced oil recovery process selected. Alternatively, the
formation heating
fluids 6 consist of steam produced in a conventional boiler, hot water, hot
hydrocarbons, hot flue
gases, hot gases and solvents, or any combination of these and other thermal
fluids. The annulus
cooling fluids 7 can consist of any fluids that are suitable for the purposes
of removing heat from
the annulus 8, preventing flow of hot injected fluids from entering the
annulus at the bottom of
the well, and for injection into the formation 12 for enhanced oil recovery
purposes.
A further advantage of using a SCV to produce formation heating fluids 6 in
larger projects is
that it can be configured and operated so that the combustion gas product is
mostly CO2. This
can be achieved by incorporating a low pressure oxygen separation PSA process
and feeding the
SCV burner with oxygen 4 instead of air 3. The CO2 can be injected along with
the steam to
enhance an oil recovery process, or be recovered for other EOR or
sequestration purposes.
A typical CHOPS well consists of a bore hole that is drilled into and through
a heavy oil
containing formation, after which it is equipped with a steel casing 9 that is
cemented in place
and perforated to allow oil into the well bore. The well is then completed
with a string of
conventional tubing, downhole pump and surface pump drive system. To
recomplete the CHOPS
well for thermal operation, the conventional tubing and pump is removed, and a
string of
insulated tubing 10, preferentially vacuum insulated tubing known as VIT, is
installed inside the
well casing 9. A progressive cavity pump 11 also known as a PCP is either
mounted on the end
of the insulated tubing 10 before it is installed in the well, or
alternatively a through-tubing PCP
and rods are installed after the tubing is in place. To commence heating of
the formation in wells
where a PCP is installed, the rotor is lifted out of pump stator to permit
injection of hot fluids
through the pump 11 and into the formation. Primary CHOPS production from
wells results in
heavy oil reservoir formations containing void spaces or areas of enhanced
permeability referred
to as "wormholes" 12 which serve as conduits for the introduction of heating
and pressurizing
fluids into the formation. To heat and pressure the formation, heating fluids
6 and annulus
cooling fluids 7 are injected into the bottom of the well 9 where they mix to
form a combined
fluid 13 which flows into the formation through wormholes 12.
After sufficient combined fluid 13 has been injected to achieve the desired
pressure and
temperature in the oil reservoir formation, in a typical cyclic injection-
production well operation
known as "huff-and-puff' the well is placed on production. At the end of the
injection cycle,
followed by a suitable length of temperature "soak" time, the direction of
flow in the formation
and well is reversed. Initially and without the need for artificial lift, gas,
oil and water may flow
up the insulated tubing 10 simply by opening the tubing production valve
installed on a
conventional wellhead and allowing produced fluids to flow to a production
tank. Once the
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initial flow has declined, the pump 11 is activated for the purpose of lifting
liquids out of the
well. For the above well completion method, the PCP rotor which was lifted out
of the pump
stator for the injection cycle is now inserted back into the pump stator and
the pump placed in
operation. Concurrently, non-condensable gas that is produced along with the
oil and water is
separated from the liquids at the bottom of the well and produced up the
annulus 8.
Optionally, if the near well bore fluid stabilized temperature exceeds the
temperature limit of the
well's non-thermal casing and cement 9, before the pump 11 is placed in
operation a selected
amount of cooling fluid such as water, liquid carbon dioxide or nitrogen is
introduced into the
well to lower the near well bore fluid temperature.
Another application of the present invention is for enhanced oil recovery from
formations where
heavy oil exists without the benefit of wormholes. In this application,
injected fluids 6 and 7 can
are used in a conventional flood enhanced recovery process whereby hot
injected fluids are used
to pressurize and heat the formation, initiating a flood drive mechanism
whereby heavy oil is
pushed towards surrounding wells where it is produced.
A further application of the present invention is use in establishment of a
CHOPS production
mechanism in suspended heavy oil wells that do not have wormholes due to
having been
previously produced in a manner that prevented sand from being produced along
with the oil. In
this application, fluids 6 and 7 are injected to re-pressure the partially
depleted formation up to
its original pressure. The formation is then allowed to cool enough to achieve
desired heavy oil
viscosity, and then the well is placed on production by maintaining the low
well bore pressure
necessary to initiate CHOPS production. The production of sand along with the
viscous oil
results in the creation of worm holes 12 in the formation which following a
period of CHOPS
production can be used for introduction of heating and pressurizing fluids for
further enhanced
oil recovery.
CLAIMS
What is claimed is:
1. A method for enhancing the recovery of viscous hydrocarbons from subsurface
formations containing heavy oil deposits or bitumen deposits, comprising:
(a) employing known methods of producing high pressure steam, hot combustion
gases
and other hot fluids for the purpose of heating and pressuring a subsurface
hydrocarbon bearing formation;
(b) equipping and operating a non-thermally cased heavy oil well for use in a
thermal oil
recovery process, without the requirement for installing a bottom hole packer
between
the well tubing and the annulus which prior to the present invention has been
required
to prevent hot tubing injected fluids from flowing up and into the annulus.
(c) employing an existing well bore or establishing at least one vertical or
horizontal bore
hole complete with casing extending from the surface of the earth to at least
the
bottom of the subsurface formation, the well and casing being completed with
perforations or other means of connection between the well bore and the
formation;
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