U.S. patent application number 13/578357 was filed with the patent office on 2013-01-03 for hydrocarbon recovery.
This patent application is currently assigned to STATOIL PETROLEUM AS. Invention is credited to Haavard Aakre, Vidar Mathiesen, Rex Man Shing Wat, Bjornar Werswick.
Application Number | 20130000883 13/578357 |
Document ID | / |
Family ID | 44366920 |
Filed Date | 2013-01-03 |
United States Patent
Application |
20130000883 |
Kind Code |
A1 |
Aakre; Haavard ; et
al. |
January 3, 2013 |
HYDROCARBON RECOVERY
Abstract
A thermal hydrocarbon recovery apparatus comprises: a plurality
of steam injector tubes each provided with a plurality of injector
autonomous inflow control devices, AICDs, spaced apart from each
other along the length of each steam injector tube; a plurality of
production tubes each provided with a plurality of production
autonomous inflow control devices, AICDs, spaced apart from each
other along the length of each production tube; wherein said
injector AICDs are arranged to inject steam into a geological
formation so as to reduce the viscosity of hydrocarbons in the
formation; and wherein said production AICDs are arranged to permit
the flow of heated hydrocarbons into said production tubes for
movement to the surface.
Inventors: |
Aakre; Haavard; (Skien,
NO) ; Wat; Rex Man Shing; (Stavanger, NO) ;
Mathiesen; Vidar; (Porsgrunn, NO) ; Werswick;
Bjornar; (Langesund, NO) |
Assignee: |
STATOIL PETROLEUM AS
Stavanger
NO
|
Family ID: |
44366920 |
Appl. No.: |
13/578357 |
Filed: |
January 19, 2011 |
PCT Filed: |
January 19, 2011 |
PCT NO: |
PCT/EP2011/050696 |
371 Date: |
September 21, 2012 |
Current U.S.
Class: |
166/57 |
Current CPC
Class: |
E21B 34/08 20130101;
E21B 43/2406 20130101; E21B 43/12 20130101 |
Class at
Publication: |
166/57 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Foreign Application Data
Date |
Code |
Application Number |
Feb 12, 2010 |
CA |
2692939 |
Claims
1.-18. (canceled)
19. A thermal hydrocarbon recovery apparatus comprising: a
plurality of steam injector tubes each provided with a plurality of
injector autonomous inflow control devices, AICDs, spaced apart
from each other along the length of each steam injector tube; a
plurality of production tubes each provided with a plurality of
production autonomous inflow control devices, AICDs, spaced apart
from each other along the length of each production tube; wherein
said injector AICDs are arranged to inject steam into a geological
formation so as to reduce the viscosity of hydrocarbons in the
formation; and wherein said production AICDs are arranged to permit
the flow of heated hydrocarbons into said production tubes for
movement to the surface.
20. Apparatus as claimed in claim 19, wherein at least one injector
AICD is configured to permit the flow of steam through the injector
AICD at a substantially constant flow rate, once a pressure
differential across the injector AICD exceeds a threshold
value.
21. Apparatus as claimed in claim 20, wherein said substantially
constant flow rate varies over time by less than 10% of a mean
value.
22. Apparatus as claimed in claim 20, wherein for steam in the
temperature range between 150 and 160 degrees centigrade, said
substantially constant flow rate has a mean value of between 0.3
and 10 m.sup.3/hr.
23. Apparatus as claimed in claim 20, wherein for steam in the
temperature range between 150 and 160 degrees centigrade, said
threshold value is a value between 8 kPa and 12 kPa.
24. Apparatus as claimed in claim 19, wherein at least one
production AICD is configured to permit flow of heated hydrocarbons
and condensed water into a production tube but to restrict the flow
of steam into the production tube.
25. Apparatus as claimed in claim 24, wherein said at least one
production AICD is configured so that in the event of steam from
said steam injector tubes reaching the production AICD, the
production AICD autonomously closes so that any steam entering the
production tube via the production AICD is less than 5% by weight
of the total fluid entering the production tube via the production
AICD.
26. An apparatus as claimed in claim 19, wherein at least some of
said injector AICDs comprise a body defining a flow path through
the AICD and defining a recess containing a movable valve body,
arranged so that movement of fluid along said flow path causes the
valve body to move by exploiting the Bernoulli effect thus
controlling the flow of fluid along said flow path.
27. An apparatus as claimed in claim 19, wherein at least some of
said production AICDs comprise a body defining a flow path through
the AICD and defining a recess containing a movable valve body,
arranged so that movement of fluid along said flow path causes the
valve body to move by exploiting the Bernoulli effect thus
controlling the flow of fluid along said flow path.
28. An apparatus as claimed in claim 26, wherein said valve body is
a freely movable valve body.
29. An apparatus as claimed in claim 19, wherein the injector AICDs
of at least one of the steam injector tubes are configured to
inject steam into said formation at substantially the same steam
flow rate.
30. An apparatus as claimed in claim 19, wherein the injector AICDs
of at least one of the steam injector tubes are configured to
inject steam into said formation at different steam flow rates so
that appropriate flow rates can be used for different parts of said
formation.
31. An apparatus as claimed in claim 19, wherein said steam
injector tubes are arranged to extend substantially
horizontally.
32. An apparatus as claimed in claim 19, wherein said production
tubes are arranged to extend substantially horizontally.
33. An apparatus as claimed in claim 19, wherein said geological
formation is an oil sand.
34. An apparatus as claimed in claim 19, wherein said hydrocarbons
to be recovered are bitumen or heavy oil.
35. An apparatus as claimed in claim 19, taking the form of a steam
assisted gravity drainage, SAGD, system.
36. A method for thermal recovery of hydrocarbons from a geological
formation, the method comprising the steps of: a) providing a
thermal hydrocarbon recovery apparatus as claimed in any preceding
claim; b) injecting steam into said geological formation via said
injector AICDs; c) collecting heated hydrocarbons in said
production tubes via said production AICDs; and d) moving said
hydrocarbons to the surface via said production tubes.
Description
[0001] The present invention relates to a thermal hydrocarbon
recovery apparatus and an associated method. In particular, but not
exclusively, the invention relates to thermal hydrocarbon recovery
by steam injection.
[0002] In various locations around the world, significant
hydrocarbon reserves are known to be present in the Earth's
subsurface in oil or tar sands. The hydrocarbons found in these
settings take the form of bitumen or heavy crude oil which is
particularly dense and viscous and does not flow naturally. In
geological settings where lighter hydrocarbons are present, a well
can be drilled into a hydrocarbon bearing formation and
hydrocarbons such as petroleum and gas will readily flow from the
hydrocarbon-bearing geological formation through the well to the
Earth's surface due to higher pressures of the formation compared
with the Earth's surface.
[0003] The viscous bitumen and heavy crude oil is more difficult to
extract, although it is possible to do this using thermal
hydrocarbon recovery techniques. The key principle of thermal
recovery is to heat up the oil sands so that the bitumen or heavy
oil becomes sufficiently viscous that it will flow, allowing it
then to be extracted from the formation in its heated and flowable
condition.
[0004] One technique for doing this involves drilling a well and
then injecting steam through the wellbore into the formation to
heat up the formation and the heavy oil. Thereafter, the oil is
extracted through the wellbore to the surface. Several cycles of
heating and extraction would typically be carried out. The method
typically uses a single wellbore both for injecting the steam and
for extracting and moving the oil to the surface, and is known as a
"huff and puff" system.
[0005] Another known thermal recovery technique is steam assisted
gravity drainage (SAGD). This technique also works on the basis of
injecting steam into the formation, although it makes use of
separate wellbores; a designated "steam injector wellbore" for
injecting the steam and another "producer wellbore" for extracting
or producing the oil to the surface. Typically, horizontal sections
of the steam injector wellbore and the production wellbore run near
to each other in pairs with the steam injector wellbore located
above the producer wellbore.
[0006] As steam is injected into the formation through the injector
wellbore, a steam heated region of the formation above and around
the injector wellbore is formed, known as a steam "chamber". This
causes the heavy oil to heat up and drain downwards under gravity
towards the producer wellbore that has been warmed up during
initial circulation. The drainage of oil allows the steam to rise
up further through the steam chamber toward its periphery enabling
continuous growth of the steam chamber. After releasing its heat
energy the steam then condenses and flows downwards together with
the mobile oil under the influence of gravity to the producing
wellbore beneath.
[0007] Typically, the injector and producer wellbores comprise
horizontal sections that run roughly parallel and horizontally in
the geological formation and are spaced a few metres apart from
each other with the injector wellbore located above the producer
wellbore, for example by a spacing of around 5 m.
[0008] Although the present SAGD technique has benefits in terms of
efficiency and oil recovery rates, there are a number of problems
associated with the SAGD technique as used today. For example, it
can be difficult to control steam breakthrough in the producer
wellbore and to achieve precise `distribution` of steam along the
horizontal injector so that an optimal steam chamber can be
formed.
[0009] In order to extract oil consistently via the producer
wellbore, it is ensured that a layer, trap or sump of condensed
water and the hydrocarbons sought to be extracted is maintained
around the producer wellbore such that steam from the injector
wellbore cannot "short circuit" and break through directly to the
producer wellbore section. However, steam breakthrough may occur if
the heating conditions and steam chamber is not correctly
established. For example, the temperature in the geological
formation around the producer wellbore should be less than that of
the steam chamber (sub-cool) for oil to drain downwards into the
producer wellbore. If not, steam may replace the oil and the
condensed water at the producer well, which is undesirable as it
delays production of hydrocarbons and causes damage to the lift
pumps located in the producer wellbore for pumping the oil to the
surface. Various steps then need to be taken to rectify the
situation.
[0010] In order to avoid steam breakthrough from occurring, various
measures may need to be taken. In particular, the production rate
may need to be limited to maintain the mobile hydrocarbon layer in
the present SAGD technique. This may be done for example by
controlling the lift pump operating inside the production pipe to
control drawdown pressure in the tubing or by reducing the steam
injection from the injector wellbore. Temperature also needs to be
controlled to maintain a fluid trap around the producer tubing.
Specifically, the temperature in the region around the producer
wellbore has to be kept cooler than the steam chamber temperature,
i.e. "sub-cool", in order for a suitable fluid trap to build up and
be maintained.
[0011] Although still viscous enough to flow, the fluid to be
extracted around the producer wellbore is comparatively viscous
which limits extraction efficiency. It is therefore generally
desirable that the steam chamber extends as close as possible to
the producer wellbore to keep the fluid as mobile as possible
without causing steam breakthrough. A balance needs to be kept and
with this in mind, present methods are based on a stand off
distance between he steam injection and the production wellbore of
between around 4 and 6 m in order to help keep temperature
conditions and the "steam chamber" stable and relatively
predictable near the producer wellbore. Again, adjustment of
production or injection rates may be required to maintain
temperature conditions. Using present methods therefore, it can be
difficult to consistently achieve commercial production rates of
heavy oil as the entire well has to be choked back even with
localised steam break through.
[0012] Existing techniques have focused on tackling the above
described issues of steam breakthough using inflow control devices
ICDs with a fixed flow path construction. Known generally as
channel or nozzle type ICDs, these are disposed on the production
tubing or liner to provide fluid connection between the tubing
interiors and the geological formation in specific locations along
the tubing sections. Such ICDs in the producer tubing impose an
additional pressure drop between the formation and the tubing to
hinder steam breakthrough and to maintain the fluid trap around the
tubing. Nevertheless, avoiding steam breakthrough and forming a
suitable sub-cool trap around the producer tubing are significant
challenges associated with present thermal recovery techniques.
[0013] There are also considerations in relation to how the
injector well operates. As mentioned above, it is desired to be
able to create a suitable steam chamber and distribute steam in a
controlled manner. However, it is also important to be able to do
so along the entire length of the wellbores. This again helps to
reduce the risk of steam breakthrough to the production well and
more crucially to avoid localised and unbalanced steam chamber
development.
[0014] For injector wells, a wellbore hydraulic effect occurs,
which limits the length of horizontal tubing usable in the SAGD. In
turn, this means that numerous wells typically need to be drilled
to provide the necessary coverage to thermally recover heavy oil
from a given region. Typically, the maximum length of a horizontal
section for SAGD is around 500-1000 m. This is because the amount
of steam entering the geological formation (exiting the wellbore)
and the amount continuing further downstream inside the wellbore is
significantly dependent on the localised pressure balance, as shown
in
[0015] FIG. 2. At positions earlier along the tubing, there will be
delivered generally higher flow rates at the "heel" section (toward
the wellhead end of the horizontal wellbore section) whilst the
differential pressure and flow rates at locations successively
further away from the pressure source will gradually diminish (due
to a reduced fluid volume in the tubing). The common practice to
address such issues of wellbore hydraulics is to install two
horizontal injection tubing sections of different length, one above
the other (dual tubing completion). Typically, the two injection
tubing sections are run in the same injection wellbore, as shown in
FIG. 2. The injection tubing sections are placed in an overlapping
configuration relative to each other so as to reduce the overall
pressure variability along the wellbore as seen by comparing FIGS.
2a and 2b. It can be seen that a moderately uniform pressure/flow
rate distribution can be achieved along the length of the tubing,
but it can also be seen that the effectiveness of this technique
requires a certain proximity between the end of the upper injector
(at the "heel" of the wellbore and commonly referred as the short
string) and the end of the lower injector tubing (at the "toe" of
the wellbore and commonly referred as the long string). This means
that the required steam chamber conditions may still only be
provided for a relatively limited length of tubing, as defined
between the two injector tubing ends.
[0016] Attempts have been made to tackle the issues of wellbore
hydraulics and uneven steam chamber growth by using fixed flow path
inflow control devices ICDs. These are fitted in the injector
wellbore and are disposed on the tubing or the liner to provide
fluid connection between the respective tubing interiors and the
geological formation in specific locations along the tubing
sections. In the injector tubing, the ICDs provide an outlet for
the steam into the formation. In order to inject steam into the
formation, the injector tubing is pressurised to a pressure above
the formation pressure, and steam can thereby be forced through the
ICDs. Several ICDs are provided along the length of the tubing
allowing steam to be injected at specific locations along the
tubing providing high steam injectivity at those locations. Using
ICDs in the injector tubing imposes an additional pressure drop
between the tubing and the formation. This enables more steam,
which would otherwise `leak off` into a receptive formation, to be
channeled along the injection wellbore through a horizontal section
of the wellbore. However, a problem associated with using these
ICDs in the injector tubing is that the steam flow rate is driven
by the pressure differential, as seen in FIG. 1. Since formation
pressure varies somewhat along the length of the tubing and over
time, a change in the pressure differential can be caused and then,
due to the sensitivity of flow rate to a change in the pressure
differential, it can be hard therefore to control the desired steam
rates so as to form a suitable steam chamber.
[0017] In one form therefore, the technique has been adapted to
make use of the critical flow rate for fixed flow path
orifice/channel and nozzle ICDs, which is a predictable, constant
flow rate known occur at the speed of sound. In these devices, the
steam injection rate is up to a point dependent on the pressure
differential but at this critical flow rate, the steam injection
flow rate cannot be increased any further, even if the pressure
differential is made larger. A drawback is that this requires a
pressure differential to be generated in the tubing of
approximately twice the formation pressure in order to create this
effect using conventional tubing and ICD arrangements. Since the
need of doubling the pressure differential also applies at the toe
section, which is furthest away, it will require significantly
higher overall steam pressure at the wellhead. Injection into the
formation in this critical flow mode requires therefore an
undesirably large amount of energy, and the high speed of the fluid
can impart significant erosion and damage to the equipment. In
addition, the steam exiting the ICDs is typically turbulent and may
require additional diffusers in order to harness and direct the
flow of steam into the formation as required. The use of diffusers
also causes dissipation of energy from the flow. These are
undesirable effects even though such devices can yield a
predictable flow rate.
[0018] Accordingly, there are a number of difficulties associated
with existing techniques of thermal recovery, including for example
how to distribute steam uniformly, how to target steam distribution
to mitigate the impact of geological heterogeneity, and/or how to
target steam distribution for optimal steam chamber growth. An
additional challenge is to avoid excessive steam injection.
[0019] In a first broad form the invention may be defined by the
following paragraphs.
[0020] The invention may provide thermal hydrocarbon recovery
apparatus comprising at least one flow control device for
autonomously adjusting a flow of fluid through the flow control
device, the at least one flow control device provided to a tubing
for location in a wellbore, the flow control device being arranged
to fluidly connect a geological formation with an inside of the
tubing, and wherein the tubing is further arranged for at least one
of: injecting steam into the geological formation for heating
hydrocarbons; and moving steam heated hydrocarbons from the
geological formation to the surface.
[0021] The apparatus may comprise a first, injector tubing for
injecting steam into the geological formation for heating
hydrocarbons, and a second, producer tubing for moving steam heated
hydrocarbons from the geological formation to the surface, wherein
the at least one flow control device may be provided to at least
one of the injector tubing and the producer tubing. At least one
flow control device may be provided to each of the injector tubing
and the producer tubing.
[0022] The producer tubing may be provided with at least one flow
control device configured to autonomously permit flow of heated oil
and water but restrict flow of steam through the flow control
device from the formation. The producer tubing may be provided with
a plurality of said flow control devices spaced apart from each
other along a length of the tubing.
[0023] The injector tubing may be provided with a plurality of said
flow control devices spaced apart from each other along a length of
the injector tubing, wherein each flow control device may be
configured to permit flow of steam through the control device at a
predetermined flow rate. The flow control devices may be arranged
to produce a predetermined profile of steam injectivity along a
length of the injector tubing.
[0024] Different flow control devices may be configured to produce
substantially the same steam flow rate. The flow control devices
may be configured to permit flow of steam therethrough at a
substantially constant flow rate, where the steam in the injector
tubing is pressurised sufficiently.
[0025] The injector tubing may comprise an injector tubing section
arranged to extend substantially horizontally and in spaced
parallel relationship with a producer tubing section of the
producer tubing. The injector tubing and producer tubing may be
spaced apart from one another by a distance of less than 5 m, less
than 4 m, less than 3 m, less than 2 m and/or less than 1 m. For
example, they may be spaced apart by a distance of between around 1
and 2 m.
[0026] The injector tubing may comprise a plurality of steam
injector tubing sections arranged to be located within respective
substantially horizontal wellbore sections, and a connecting
injector tubing section which is arranged to extend between a
surface well head and a subsurface location for fluidly connecting
each of the plurality of steam injector tubing sections with the
surface well head.
[0027] The producer tubing may comprise a plurality of producer
injector tubing sections arranged to be located within respective
substantially horizontal wellbore sections, and a connecting
producer tubing section which is arranged to extend between a
surface well head and a subsurface location for fluidly connecting
each of the plurality of producer injector tubing sections with the
surface well head.
[0028] The geological formation may be an oil sand and the
hydrocarbons to be recovered may be viscous hydrocarbons.
[0029] The apparatus may take the form of a steam assisted gravity
drainage system.
[0030] The invention may also provide use of an autonomously
adjustable flow control device in a thermal oil recovery system in
which steam is injected into a geological formation to heat
hydrocarbons and the steam-heated hydrocarbons are moved from the
geological formation to the surface.
[0031] The use may provide the effect of discriminating against
steam inflow into a tubing of the recovery system which tubing may
be arranged for moving hydrocarbons from the hydrocarbon formation
to the surface. The use may provide the effect of controlling the
formation of a steam chamber to safeguard against steam
breakthrough and/or provide the effect of assured recovery of oil
under steam breakthrough conditions.
[0032] The use may include any features of the apparatus defined
above, where appropriate.
[0033] The invention may also provide a method of thermal recovery
of hydrocarbons from a geological formation, the method comprising
the steps of: [0034] a. providing at least one flow control device
to a tubing, the flow control device arranged to autonomously
adjust a flow of fluid through the flow control device; [0035] b.
locating the tubing in a wellbore, by which the at least one flow
control device is arranged to fluidly connect the geological
formation and an inside of the tubing; and [0036] c. injecting
steam into the geological formation to heat the hydrocarbons;
[0037] d. moving the steam heated hydrocarbons from the geological
formation to the surface; and [0038] e. using the tubing for
carrying out at least one of the steps c and d.
[0039] The method may be a method of assured recovery, or
production, of oil under steam breakthrough conditions. Thus, it
may safeguard production and prevent damage to equipment even if
steam is present against the outer surface of a producer tubing. It
may also be a method of controlling steam chamber formation.
[0040] The method may use any features of the apparatus defined
above, where appropriate.
[0041] In a second form the invention may be defined by the
following numbered paragraphs:
[0042] 1. A thermal hydrocarbon recovery apparatus comprising:
[0043] a plurality of steam injector tubes each provided with a
plurality of injector autonomous inflow control devices, AICDs,
spaced apart from each other along the length of each steam
injector tube; [0044] a plurality of production tubes each provided
with a plurality of production autonomous inflow control devices,
AICDs, spaced apart from each other along the length of each
production tube; [0045] wherein said injector AICDs are arranged to
inject steam into a geological formation so as to reduce the
viscosity of hydrocarbons in the formation; [0046] and wherein said
production AICDs are arranged to permit the flow of heated
hydrocarbons into said production tubes for movement to the
surface.
[0047] 2. Apparatus as defined in paragraph 1, wherein at least one
injector AICD is configured to permit the flow of steam through the
injector AICD at a substantially constant flow rate, once a
pressure differential across the injector AICD exceeds a threshold
value.
[0048] 3. Apparatus as defined in paragraph 2, wherein said
substantially constant flow rate varies over time by less than 10%
of a mean value.
[0049] 4. Apparatus as defined in paragraph 2 or 3, wherein for
steam in the temperature range between 150 and 160 degrees
centigrade, said substantially constant flow rate has a mean value
of between 0.3 and 10 m.sup.3/hr.
[0050] 5. Apparatus as defined in paragraph 2, 3 or 4, wherein for
steam in the temperature range between 150 and 160 degrees
centigrade, said threshold value is a value between 8 kPa and 12
kPa.
[0051] 6. Apparatus as defined in any preceding paragraph, wherein
at least one production AICD is configured to permit flow of heated
hydrocarbons and condensed water into a production tube but to
restrict the flow of steam into the production tube.
[0052] 7. Apparatus as defined in paragraph 6, wherein said at
least one production AICD is configured so that in the event of
steam from said steam injector tubes reaching the production AICD,
the production AICD autonomously closes so that any steam entering
the production tube via the production AICD is less than 5% by
weight of the total fluid entering the production tube via the
production AICD.
[0053] 8. An apparatus as defined in any preceding paragraph,
wherein at least some of said injector AICDs comprise a body
defining a flow path through the AICD and defining a recess
containing a movable valve body, arranged so that movement of fluid
along said flow path causes the valve body to move by exploiting
the Bernoulli effect thus controlling the flow of fluid along said
flow path.
[0054] 9. An apparatus as defined in any preceding paragraph,
wherein at least some of said production AICDs comprise a body
defining a flow path through the AICD and defining a recess
containing a movable valve body, arranged so that movement of fluid
along said flow path causes the valve body to move by exploiting
the Bernoulli effect thus controlling the flow of fluid along said
flow path.
[0055] 10. An apparatus as defined in paragraph 8 or 9, wherein
said valve body is a freely movable valve body.
[0056] 11. An apparatus as defined in any preceding paragraph,
wherein the injector AICDs of at least one of the steam injector
tubes are configured to inject steam into said formation at
substantially the same steam flow rate.
[0057] 12. An apparatus as defined in any preceding paragraph,
wherein the injector AICDs of at least one of the steam injector
tubes are configured to inject steam into said formation at
different steam flow rates so that appropriate flow rates can be
used for different parts of said formation.
[0058] 13. An apparatus as defined in any preceding paragraph,
wherein said steam injector tubes are arranged to extend
substantially horizontally.
[0059] 14. An apparatus as defined in any preceding paragraph,
wherein said production tubes are arranged to extend substantially
horizontally.
[0060] 15. An apparatus as defined in any preceding paragraph,
wherein said geological formation is an oil sand.
[0061] 16. An apparatus as defined in any preceding paragraph,
wherein said hydrocarbons to be recovered are bitumen or heavy
oil.
[0062] 17. An apparatus as defined in any preceding paragraph,
taking the form of a steam assisted gravity drainage, SAGD,
system.
[0063] 18. A method for thermal recovery of hydrocarbons from a
geological formation, the method comprising the steps of: [0064] a)
providing a thermal hydrocarbon recovery apparatus as defined in
any preceding paragraph; [0065] b) injecting steam into said
geological formation via said injector AICDs; [0066] c) collecting
heated hydrocarbons in said production tubes via said production
AICDs; and [0067] d) moving said hydrocarbons to the surface via
said production tubes.
[0068] There will now be described, by way of example only,
embodiments of the invention with reference to the accompanying
drawings, of which:
[0069] FIG. 1 is a plot showing the relationship of differential
pressure versus flow rate for a prior art fixed construction
nozzle/orifice or channel based ICD;
[0070] FIG. 2 is a schematic representation of a prior art
injection wellbore with dual tubing completion for steam
injection;
[0071] FIGS. 3A and 3B provide perspective and end on
representations of a region of the earth's subsurface containing a
thermal hydrocarbon recovery apparatus according to the present
invention;
[0072] FIG. 4A is a plot of prior art fixed construction ICD
performance curves for gas/steam, water and oil;
[0073] FIG. 4B is a plot of performance curves for gas/steam, water
and oil for the AICDs used in embodiments of the present
invention;
[0074] FIGS. 5A and 5B are schematic cross-sectional
representations showing a steam breakthrough scenario in the
vicinity of a producer tubing;
[0075] FIG. 6 is a graph showing the behaviour of operating
behaviour for AICDs used in an injector tubing; and
[0076] FIG. 7 is a schematic representation of an arrangement of
pipe sections for thermal recovery from a geological formation.
[0077] With reference firstly to FIGS. 3A and 3B, there is shown a
process for thermally recovering hydrocarbons from an oil sand by
steam assisted gravity drainage (SAGD). The present examples are
described particularly with reference to the SAGD method, but it
will be appreciated that the invention described herein is equally
applicable to other steam assisted thermal recovery methods
including for example the single tubing cyclical "huff and puff"
method mentioned above or non-cyclic continuous steam drive systems
or the like.
[0078] In FIGS. 3A and 3B, a section of the Earth's subsurface is
shown with an oil sand formation 12 located at depth. An injection
well 14 and a production well 16 are provided one above the other
comprising horizontal injector and producer tubing sections
14h,16h, separated by a vertical spacing of around 5 m. Injection
of steam from the injector tubing section 14h generates a mushroom
shaped heated region or "steam chamber" 18 in the oil sand layer
above and around the wellbore section 14h. After an initial warm up
period a convection process is initiated by which bitumen or heavy
oil in the oil sand is heated and drains downwards whilst the steam
rises through the steam chamber. As it reaches a cooler outer area
of the chamber the steam condenses. The heated bitumen becomes
mobile and drains downward together with condensed water as
indicated by arrows 18a. At the producer tubing section 16h below,
the bitumen or heavy oil is flowable and is drawn into the producer
tubing under formation pressure and/or with assistance of a
production lift pump (not shown) inside the production tubing
section 16h by which the mobilised bitumen or heavy oil together
with the condensed water is returned to the surface production well
head 19.
[0079] In the present invention, the injector tubing section 14h
and the producer tubing section 16h are both fitted with multiple
flow control devices 14f, 16f in the wall of the tubing sections
and are spaced apart from each other along the length of the
respective tubing sections. The tubing referred to here can be a
liner or sand screen (in direct contact with the geological
formation) or an internal tubing that locates inside the
liner/screen. These devices provide fluid connection and passage
between the geological formation 12 and the interiors of the
production and injection tubing sections 14h, 16h. The flow control
devices in this example are so-called autonomous inflow control
devices (AICDs). These devices comprise a housing and a "floating
disc" inside the housing to define a flow path for fluid through
the valve. Importantly, the floating disc creates a flow
restriction. However, the disc is movable within the housing to
alter the flow path restriction.
[0080] The AICDs provide two particular effects, which contribute
to the production of hydrocarbon and the injection of steam.
Firstly, the disc moves in response to the stagnation pressure and
the velocity of fluid. This means that it autonomously adjusts its
position and flow path to conserve energy, following the principles
of Bernoulli's equation. Thus, for a given pressure differential
between the inside of the tubing and the geological formation, the
flow can be choked or shut off altogether when a lower viscosity
fluid is encountered at the restriction, and as the disc moves to
close the flow path due to low pressure. The disc movement is
caused by high stagnation pressure on one side and faster flowing
low viscosity fluid that creates a lower dynamic pressure on the
other.
[0081] Secondly, when the autonomous valve is subjected to
single-phase flow such as steam the floating disc will remain open,
whilst its position within the housing is balanced by the
stagnation pressure created at the back of the disc and the flowing
"dynamic" pressure formed at the front of the disc. The higher the
flow rate, as induced by a larger differential pressure across the
valve, the dynamic flowing pressure at the front of the disc
becomes lower. This pulls the disc closer to its `SHUT` position
and reducing the flow rate automatically. Effectively the
autonomous valve will yield an "almost" constant flow rate once a
threshold maximum differential pressure is reached.
[0082] Flow control devices that operate based on these or closely
similar principles are described in WO2008/004875, WO2009/088292
and WO2009/113870 and relevant parts of the disclosures of those
documents are incorporated herein by reference.
[0083] The flow valves for the production tubing section 16h for
the present SAGD system makes use of the first of these operating
principles, as can be seen with reference firstly to FIGS. 4A and
4B. In FIG. 4B, there is shown a plot 20 of differential pressure
(between the wellbore formation and the drawdown pressure in the
tubing) against flow rate for the AICDs used in the production
tubing section. The plot 20 displays performance graphs for water
20a, oil 20b, and gas/steam 20c showing the flow rate behaviour
through the valve. All of the curves 20a-20c show a rapid increase
in differential pressure whilst flow rate increases. In contrast in
FIG. 4A, the corresponding performance using fixed construction
nozzle/orifice prior art ICDs can be seen in the curves 22a-22c of
plot 22, plotted at the same scale. These show only a very gradual
increase of differential pressure, particularly in the gas curve
22c. As can be seen from the plot 20 for the AICD, the `gas/steam`
flow is choked back and significantly limited due to the movement
of the floating disc.
[0084] The AICDs 16f in the producer tubing 16h are designed to
discriminate against the steam based on the autonomous
adjustability of the AICDs. The AICD is designed to permit flow of
heated oil or liquid bitumen and condensed water through the AICD,
but prevent steam flow. Should any steam break through to the
production tubing section, flow of steam through the AICD will be
blocked off or choked since the viscosity of the steam is
significantly lower than that of the liquid oil or bitumen or
water, which causes the floating disc of the AICD to restrict the
flow path in the valve. The stagnation pressure then keeps the
valve `SHUT` until steam is replaced by oil or liquid flow. As a
result, the risk of drawing steam into the production well bore is
greatly reduced. Damage to the lift pump by steam is avoided whilst
there is adequate inflow of oil and water through the AICDs in the
rest of the wellbore to meet the withdrawal rate of the pump.
[0085] As illustrated in FIGS. 5A and 5B, the fluid discrimination
and shut off functionality of the AICD is shown. In FIG. 5A, the
production tubing section 14h is shown with the AICD 14f provided
in a wall of the section 14h. A layer of molten liquid bitumen plus
water 18t drained from the steam chamber 18 lies along and around
an outer surface of the production tubing section 14h, and is
presented to the AICD. Flow is permitted through the AICD and into
the producer tubing to the well head as indicated. In FIG. 5B, a
steam breakthrough scenario is illustrated, and the AICD has
blocked off the steam due to its sensitivity and discrimination
against low viscosity steam. The remaining parts of the producer
tubing, equipped also with AICDs, will continue to produce the
bitumen and water unhindered until they are `SHUT` by the
encroaching steam. Preferably the AICDs ensure that any steam
entering the production tube is less than 5% by weight of the total
fluid entering the production tube.
[0086] Thus, steam is drawn close to but not through the production
tubing, so as to operate effectively at "zero-subcool". This
improves the overall thermal recovery process, firstly because the
steam injection can be performed more `aggressively` without the
fear of the steam short-circuiting into the production well below.
More heat energy can be used to facilitate the steam chamber growth
and accelerate the recovery of oil. Secondly, since the steam
chamber extends to the close vicinity of the producer tubing
instead of being shielded by an overlying liquid trap that has to
be kept cooler (subcool), a warmer and hence a more effective
drainage process takes place in this critical near well bore
region. The autonomous discrimination against steam flow is also
beneficial in terms of the entire `horizontal` section of the
production well regardless of the elevation of the well trajectory.
For example, when the producer tubing sections are present at
different elevations, sections at a higher elevation may have steam
drawn into it initially, at which point the AICDs close momentarily
and temporarily until water and molten oil build up again and they
re-open. At the same time, sections at other elevations may follow
a different open-close cycle and the AICDs will open and close in
response to steam being drawn into those other sections at
different times.
[0087] Turning now to consider the injection tubing with reference
to FIG. 6, the graph 30 shows a characteristic performance curve 32
for the AICD, which indicates a rapidly increased flow rate for
increased differential pressure. However, above a lower threshold
differential value 34a, the flow rate no longer changes
significantly which means that provided the pressure differential
is somewhere above the threshold, a stable flow rate into the
formation is achieved. In practice therefore, a constant flow rate
of steam is selected and applied under pressure into the injection
tubing to ensure that the pressure differential across the AICD is
above the threshold 34a. The injection pressure is applied to the
tubing at a fixed output level, sufficiently above the threshold
34a to account for and reduce sensitivity to possible variations in
pressure in the formation, which may impact on the pressure
differential. Ideally, the threshold 34a represents the minimum
differential pressure that is required for the AICD located
furthest away from the wellhead. There is defined therefore an
operating region 36 of pressure differentials which ensures flow
through the AICD at the maximum and `near constant` flow rate. This
may be defined based on expected variations in differential
pressure for a given hydrocarbon reservoir scenario. This can also
be defined based on the total length of the injection tubing,
either in a single or `multi-branch` configuration. In general,
each AICD may be configured differently depending on its position
within the system. The operating region extends to an upper
threshold pressure differential 34b. It might be possible to
generate pressure at significantly higher differentials, above an
upper threshold value 34b but it is typically unnecessary to design
the steam injection system in this way since by operating at a
fixed output level in the operating region 36, a constant maximum
flow rate is achievable already.
[0088] Preferably the steam flow rate for each AICD varies over
time by less than 10% of a mean value. The physical properties of
steam, e.g. density, vary with temperature. For steam in the
temperature range 150-160 degrees C., a typical mean steam flow
rate may be between 0.3 and 10 m.sup.3/hr, or between 0.7 and 0.9
m.sup.3/hr, and the threshold value 34a may be between 8 and 12
kPa. The range values quoted here are for steam around a mean
temperature of 155 degrees C., and for the same AICD these range
values will be different at, say 230 degrees C. The appropriate
steam temperature is chosen in the field.
[0089] In addition, there will be the situation when we need to
`target` the steam distribution at different horizontal locations.
Each AICD will have a `near constant` flow rate, but one location
may require 2 to 10 times more steam than another location, for
example.
[0090] It is desirable to raise the injection pressure inside the
injector tubing as high as possible. The higher injection pressure,
whilst producing negligible impact on the injection rate near the
heel of the well bore 14, allows more steam to be pushed forwards
and further downstream towards the toe of the wellbore. This means
that a single, smaller injection tubing can be installed and/or
that a longer injection well, and/or that multiple horizontal
branches can be constructed leading to significant saving in
capital costs. Raising the injection pressure will affect the steam
temperature (higher). This may affect the uniformity of the steam
chamber with higher injection temperature near the heel. However,
the uneven heat input to the formation can be compensated by
appropriately sizing the AICDs and modifying the population of such
devices along the well bore.
[0091] The AICDs in the injector tubing 14h are preferably
individually designed so that each AICD outputs a specific (same or
different) flow rate according to the need for growing the steam
chamber. This may be carried out by adjusting the sensitivities of
the AICDs so that different pressure differentials in different
AICDs produce the respective maximum flow rates. Producing a
specific `near constant` maximum flow rate at each AICD along the
injector tubing also means that steam can be targeted more
precisely along the horizontal well, for example evenly for
homogeneous sand producing a relatively flat injectivity profile
along the length of the wellbore section or specifically
distributed to compensate for the heterogeneity in reservoirs with
other lithologies. Either way, growth of the steam chamber can be
optimised by specifying particular AICD designs for different
positions. The AICD design for the injector tubing takes into
account that pressure in the steam injector tubing is higher at an
upstream end, and that fluid which is not passed into one AICD
flows to successive AICDs downstream, resulting in a reduced
pressure in the tubing and therefore a reduced differential
pressure across each AICD. The AICD are designed therefore to have
a flow rate behaviour such that a maximum and "near constant" flow
rate can be generated for the expected differential pressure for
the particular AICD along the tubing. The size, dimensions and/or
materials may be selected to provide the desired flow behaviour,
and this could apply also to the producer tubing. For example, the
size and dimensions or scale of the AICDs in different positions
along the tubing may be different in order to produce different
flow rate responses when subjected to a pressure differential. This
constant flow rate behaviour is achieved at relatively low
differential pressures, in contrast to the previously used flow
devices that relied on achieving critical flow.
[0092] In the presently described system using AICDs in both the
injection and production wells, it is less critical to provide
exact stand-off (currently 5 m) between the injector pipe sections
and producer pipe sections in order to control the steam chamber
and avoid steam break through to the production tubing. It may
therefore be feasible to use stand-off distances of for example 2
to 3 m. In addition, control of distribution of steam from the
injector tubing is significantly improved and is no longer
sensitive to formation pressure variations along its length. The
pressure needed to deliver a predetermined rate of steam is much
less than double the formation pressure as with existing methods
and injectivity is dependent on deliverability of the steam within
the injector tubing rather than by variations in the reservoir.
Accordingly, dual "toe and "heel" injector pipes are not required,
and limitations on the length of horizontal tubing sections are
greatly removed. This gives a significantly greater freedom of
design of an SAGD or similar system for extracting heavy oils from
oil sands. Tubing sections may be extended further and tubing
configurations as shown in FIG. 7 can be deployed to give improved
and more cost effective coverage. Constant steam injection rates
can be applied to the entire length without the risk of
over-injection at locations which can yield abnormal steam chamber
development, e.g., `dog-bone` shape. In the producer tubing
sections the possibility of steam breakthrough and inflow of steam
into the production tubing is greatly reduced.
[0093] In FIG. 7, a system for thermal recovery of hydrocarbons
from a large geographical region is shown in which the producer and
injector tubing sections are provided with AICDs. FIG. 7 shows
generally an SAGD arrangement 40 which has a plurality of
horizontal injection tubing sections 40s extending away in opposing
directions from a joining pipe section 40j which is also a
horizontal tubing section connecting the horizontal sections 40s.
The joining pipe section 40j is then connected to a well head at
the Earth's surface via a single vertical section 40v.
[0094] The arrangement 40 also includes a plurality of horizontal
producer tubing sections 40p arranged in a similar way and
connected to the surface well head via a single vertical section
40w. The steam injection sections 40s are located above the
production sections 40p to provide the steam assisted drainage
required.
[0095] This arrangement is a significant improvement on existing
wells where the required close control of the production pump and
steam supply dictated that each horizontal section be accompanied
with a vertical section to the relevant well head. Accordingly, the
present invention helps to reduce the infrastructure costs and
overall rate of recovery from oil sands. The impact to the
environment can be greatly improved by minimising the surface
footprint with much reduced number of wellhead and associated
equipment.
[0096] The present description has referred generally to sections
of producer tubing and injector tubing and it will be understood
that these tubings are located, in use, in production and injection
wellbores of the production and injection wells. It will be
appreciated that the producer and/or injector tubing may take the
form of a wellbore liner or sandscreen or the like and that the
AICDs may be fitted to the liner and/or sandscreen. It will also be
appreciated that the producer tubing and/or injector tubing may
take the form of a separate production pipe and/or injector pipe
located, in use, within wellbores provided with a liner and/or
sandscreen or the like, and that the AICDs may be fitted to the
separate production and/or injector pipe. In a variant, the AICD
itself may be fitted with a mesh or the like or be otherwise
arranged to shut out and prevent inflow of sand or other particles
from the formation.
[0097] Various modifications and improvements may be made within
the scope of the invention herein described.
* * * * *