Note: Descriptions are shown in the official language in which they were submitted.
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Improvements in hydrocarbon recovery
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.
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.
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.
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.
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.
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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.
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.
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.
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.
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
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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.
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.
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.
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
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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.
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
Figure 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 Figure 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 Figures 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.
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
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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
5 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
channelled
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 Figure 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.
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.
Accordingly, there are a number of difficulties associated with existing
techniques of
thermal recovery, including for example how to distribute steam uniformly, how
to
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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.
According to a first aspect of the invention there is provided 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.
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.
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.
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
pre-
determined profile of steam injectivity along a length of the injector tubing.
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
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therethrough at a substantially constant flow rate, where the steam in the
injector
tubing is pressurised sufficiently.
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.
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.
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.
The geological formation may be an oil sand and the hydrocarbons to be
recovered
may be viscous hydrocarbons.
The apparatus may take the form of a steam assisted gravity drainage system.
According to a second aspect of the invention there is provided use of an
autonomously
adjustable inflow 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, wherein the thermal oil
recovery
apparatus comprises the thermal hydrocarbon recovery apparatus as described
herein.
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
=
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formation of a steam chamber to safeguard against steam breakthrough and/or
provide
the effect of assured recovery of oil under steam breakthrough conditions.
The second aspect may include further features as defined in relation to the
first aspect
of the invention where appropriate.
According to a third aspect of the invention there is provided a method of
thermal
recovery of hydrocarbons from a geological formation using the thermal
hydrocarbon
recovery apparatus as described herein, the method comprising the steps of:
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;
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
c. injecting steam into the geological formation to heat the hydrocarbons;
d. moving the steam heated hydrocarbons from the geological formation to the
surface;
and
e. using the tubing for carrying out at least one of the steps c and d.
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.
The third aspect may include further steps and features based on features of
the first
and/or second aspects of the invention where appropriate.
According to a further aspect of the present invention there is provided
thermal
hydrocarbon recovery apparatus comprising:
a plurality of autonomous inflow control devices, AlCDs, each said AICD for
autonomously adjusting a flow of fluid through the AICD, each said AICD
provided
to a tubing for location in a wellbore, the AICD being arranged to fluidly
connect a
geological formation with an inside of the tubing, and wherein the tubing
comprises:
injector tubing comprising a plurality of injector tubes for injecting steam
into
the geological formation for heating hydrocarbons, and producer tubing
comprising
a plurality of producer tubes for moving steam heated hydrocarbons from the
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geological formation to the surface,
wherein each said producer tube is provided with at least one AICD
configured to autonomously permit flow of heated oil and water into the
production
tube for movement to the surface but restrict flow of steam through the AICD
from
the formation, at least some of said production AlCDs comprising a housing
defining
a flow path through the AICD and containing a movable disc, arranged so that
movement of fluid along said flow path causes the disc to move by exploiting
the
Bernoulli effect thus controlling the flow of fluid along said flow path;
wherein each said producer tube is provided with a plurality of said AlCDs
spaced apart from each other along a length of the tube;
wherein each said injector tube is provided with a plurality of AlCDs spaced
apart from each other along a length of the injector tube, wherein each AICD
is
configured to permit flow of steam through the control device at a
predetermined
flow rate, wherein said injector AlCDs are arranged to inject steam into a
geological
formation so as to reduce the viscosity of hydrocarbons in the formation, at
least
some of said injector AlCDs comprising a housing defining a flow path through
the
AICD and containing a movable disc, arranged so that movement of fluid along
said
flow path causes the disc to move by exploiting the Bernoulli effect thus
controlling
the flow of fluid along said flow path,
wherein at least one said injector AICD of a said steam injector tube is
configured to have different properties relative to another said injector AICD
of the
said steam injector tube, said properties comprising at least one of size,
dimensions,
materials or scale, wherein the different properties of the injector AlCDs
determine
different respective maximum steam injection flow rates of said AlCDs.
According to a further aspect of the present invention there is provided a
method of
designing a thermal hydrocarbon recovery apparatus as described herein, the
method comprising:
determining, dependent on a first position along a said steam injector tube,
a first at least one property of a said injector AICD; and
determining, dependent on a second position along the said steam injector
tube, a second at least one property of a said injector AICD,
wherein each said determined at least one property comprises at least one
of size, dimensions, materials or scale, and
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wherein the first at least one property and the second at least one property
are to provide different near constant maximum steam injection flow rates of a
said
injector AICD at the first position and a said injector AICD at the second
position.
There will now be described, by way of example only, embodiments of the
invention
with reference to the accompanying drawings, of which:
Figure 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;
Figure 2 is a schematic representation of a prior art injection wellbore with
dual tubing
completion for steam injection;
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Figures 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;
Figure 4A is a plot of prior art fixed construction ICD performance curves for
gas/steam, water and oil;
Figure 4B is a plot of performance curves for gas/steam, water and oil for the
AlCDs
used in embodiments of the present invention;
Figures 5A and 5B are schematic cross-sectional representations showing a
steam
breakthrough scenario in the vicinity of a producer tubing;
Figure 6 is a graph showing the behaviour of operating behaviour for AlCDs
used in an
injector tubing; and
Figure 7 is a schematic representation of an arrangement of pipe sections for
thermal
recovery from a geological formation.
With reference firstly to Figures 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.
In Figures 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
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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
5 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.
10 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.
The AlCDs 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.
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
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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.
Flow control devices that operate based on these or closely similar principles
are
described in W02008/004875, W02009/088292 and W02009/113870.
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 Figures 4A and 4B. In Figure 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 AlCDs 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 Figure 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.
The AlCDs 16f in the producer tubing 16h are designed to discriminate against
the
steam based on the autonomous adjustability of the AlCDs. 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
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12
water through the AlCDs in the rest of the wellbore to meet the withdrawal
rate of the
pump.
As illustrated in Figures 5A and 5B, the fluid discrimination and shut off
functionality of
the AICD is shown. In Figure 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 Figure
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 AlCDs, will
continue to
produce the bitumen and water unhindered until they are 'SHUT' by the
encroaching
steam.
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 AlCDs 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
AlCDs will open and close in response to steam being drawn into those other
sections
at different times.
Turning now to consider the injection tubing with reference to Figure 6, the
graph 30
shows a characteristic performance curve 32 for the AICD, which indicates a
rapidly
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13
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.
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 AlCDs and modifying the population of
such
devices along the well bore.
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14
The AlCDs 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 AlCDs
so that different pressure differentials in different AlCDs 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 AlCDs
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 AlCDs 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.
In the presently described system using AlCDs 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
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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 Figure 7 can be
deployed to
give improved and more cost effective coverage. Constant steam injection rates
can
5 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.
10 In Figure 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
AlCDs. Figure 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
15 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.
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.
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.
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 AlCDs may be fitted to the liner
and/or
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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 AlCDs
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.
Various modifications and improvements may be made within the scope of the
invention herein described.
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