Note: Descriptions are shown in the official language in which they were submitted.
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DISTRIBUTED STEAM GENERATION PROCESS
FOR USE IN HYDROCARBON RECOVERY OPERATIONS
Field of the Invention
The invention relates to thermal recovery methods and systems for heavy
hydrocarbon deposits,
and specifically to such methods and systems requiring steam injection to
mobilize the deposits.
Background of the Invention
In the field of subsurface hydrocarbon production, it is known to employ
various stimulation
procedures and techniques to enhance production. For example, in the case of
heavy oil and
bitumen housed in subsurface reservoirs, conventional drive mechanisms may be
inadequate to
enable production to surface, and it is well known to therefore inject steam
or steam-solvent
mixtures to make the heavy hydrocarbon more amenable to movement within the
reservoir
permeability pathways, by heating the hydrocarbon and/or mixing it with
lighter hydrocarbons or
hot water.
In steam-assisted gravity drainage ("SAGD") and cyclic steam stimulation
("CSS") hydrocarbon
recovery operations, steam is generated at surface by steam generation units
and injected
downhole into a well, where it is subsequently introduced into an underground
hydrocarbon
formation in which the well lies, after which the steam warms bitumen and oil
within the
formation. Thus-warmed hydrocarbon within the formation is mobilized and moves
or is drawn
toward the well, where it is then collected and produced to surface. The
steam, when contacting
cooler subterranean bitumen and oil, typically condenses to water, releasing
latent heat of
condensation and thereby effectively transferring heat to the oil/bitumen.
Due to the foregoing condensation of injected steam to water, and also by
reason that
underground formations typically contain amounts of water in the form of brine
or the like, water
is typically produced to surface with the recovered hydrocarbon. Because
proximate sources of
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water for producing steam for injection downhole are often in very short
supply, or their use
prevented due to governmental restrictions, it is very desirable to use
produced water to generate
steam. Not only is such water (although contaminated) available at site, but
by generating steam
from produced water the disposal costs (which are also impacted by regulatory
limitations) of
such contaminated produced water is reduced.
Typically, water that is produced to surface with the collected hydrocarbon
arrives in the form of
free water and/or water-in-oil emulsions and/or oil-in-water reverse
emulsions. The produced
water must go through a series of processing steps to he useful as boiler
feedwater, such as cle-
w oiling, softening and ion exchange. Typical de-oiler systems include a
free water knock out
("FWKO") vessel, followed by a skim tank, induced gas floatation and finally
an oil removal
filter. The de-oiler system is conventionally used at surface to separate the
recovered
hydrocarbons from the produced water, and the produced water is thereafter
recycled to the
steam generation unit for re-use in converting same to steam for injection
downhole; typically,
however, the produced water contains significant impurities in the form of
inorganic compounds,
such as silica, calcium and magnesium ions, which must be addressed and
controlled before the
de-oiled produced water can be introduced to steam generation units as
feedstock.
Conventional drum boilers operating at circa 2% blowdown cannot typically be
used to generate
steam from the produced water without the use of evaporators to generate high
purity feedwater
due to the concentration of impurities such as calcium, silica, organics and
the like that cause
precipitation and thereby scaling and fouling within boiler tubes during the
boiling of the water,
which thereby very quickly renders the boiler ineffective in transferring heat
to the water to
generate steam and can also rupture boiler tubes due to the generation of hot
spots.
Alternatively, special types of steam generators are commonly used, namely so-
called "once-
through steam generators" ("OTSG" or "OTSGs"), which can better handle higher
amounts of
impurities in the produced water feed stream and generate steam ranging from
65% to 90%
steam quality (10-35 parts water containing the impurities, 65-90 parts steam
vapor). Operating
at this steam quality greatly reduces the dissolved salts which foul and scale
the tubes.
Nevertheless, produced water pre-conditioning steps are still necessary, such
as the warm lime
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softening ("WLS") or hot lime softening ("HLS") process, which injects lime to
reduce water
hardness and alkalinity and precipitates silica and carbonate ions out of the
water, and in
conjunction with a weak acid cation or strong acid cation ion exchange ("WACS"
or "SACS")
process, removes the calcium and magnesium scale generating ions to acceptable
concentrations,
thereby reducing build-up of scale in the OTSG. The major bulk chemicals used
in these
processes are lime (Ca(OH)2), magnesium oxide (MgO), soda ash (Na2CO3),
caustic (NaOH),
and hydrochloric acid (HCI). Minor amounts of coagulant and polymer are used
to aid in solid
separation.
The above-mentioned equipment and systems are conventionally situated in a
large, centrally-
located facility that can produce steam for use at various nearby injection
wells in the target
reservoir. Some current conventional thetinal recovery operations are
accordingly designed
based on the concept of a central processing facility ("CPF") and a plurality
of dispersed well
pads. As can be seen in Figure I, the CPF-pad arrangement I comprises a CPF 2
and well pads
3a, 3b, 3c that are distributed at some appropriate and functional distance
from the CPF 2, and
are in communication with the CPF 2 by means of various pipelines 4 that
transport materials
between each well pad 3 and the CPF 2. By distributing the well pads around
and at a distance
from the CPF, the idea is that the reservoir can be exploited with a complex
central facility (the
CPF) but relatively simple and easy-to-construct well pads at various points
above the reservoir
that can be serviced from the central facility.
Each well pad in such a conventional arrangement essentially functions to
inject steam
downhole, and to recover produced materials and pipe them to the CPF for
processing. Turning
to Figure 2, the CPF 2 and pad 3 are again seen connected by pipes 4. Such
pipes 4
conventionally include a produced materials pipe 5 for sending produced
materials (generally
bitumen, gas, water and solids) from the pad 3 to the CPF 2 for processing as
described above.
Also, the CPF 2 feeds various inputs to the pad 3, such as a steam supply
through a high pressure
steam pipe 6. Other inputs may also need to be supplied from the CPF to the
well pad, as is
known to those skilled in the art.
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However, the requirement for the supply of steam from the CPF to each of the
well pads
introduces a high-pressure pipeline environment. That being the case, certain
civil structural
works are required, such as above-ground racks and expansion loops for the
pipes. In addition,
constructing a very large central facility in a mega project fashion
introduces enhanced costs and
execution risks, both in terms of construction and operation. Smaller and more
modular
equipment would facilitate more rapid installation and execution. Focusing
most of the
processing equipment in one relatively large CPF can negatively impact the
ability to effectively
exploit the reservoir.
It would therefore be desirable to have an arrangement that addresses the
issues arising from
constructing a large CPF to process the materials coming from the wells and
generating steam
while retaining the benefits of the distributed well pad system.
Summary of the Invention
The present invention therefore seeks to provide a novel CPF-pad arrangement
that locates
certain equipment and produced materials treatment at the pads themselves,
including the
generation of steam at each pad for injection and thus avoiding the need for
steam piping from
the CPF. As the high-pressure steam pipeline environment is avoided, pipes
between the CPF
and well pads will be reduced in number and can be buried.
According to a first aspect of the present invention there is provided a
method for generating
steam for use in a subsurface hydrocarbon recovery operation, the operation
comprising a central
processing facility in fluid communication with at least one well pad, the
well pad for servicing a
related hydrocarbon recovery well, the method comprising the steps of:
locating produced materials treatment means and steam generation means at the
well pad:
producing produced materials from the related hydrocarbon recovery well at the
well pad;
treating the produced materials at the well pad to separate water and
hydrocarbon from the
produced materials;
transporting the hydrocarbon from the well pad to the central processing
facility;
feeding the water to the steam generation means to generate steam; and
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injecting the steam into the related hydrocarbon recovery well.
In some exemplary embodiments of the first aspect of the present invention,
gas is separated
from the produced materials and treated using gas treatment means located on
the well pad, for
example for sulphur removal, before piping the gas for re-use as fuel.
In some exemplary embodiments of the first aspect of the present invention,
the hydrocarbon
separated from the produced materials can be subjected to partial upgrading on
the well pad
before being transported to the central processing facility, thus avoiding or
reducing the need for
diluent to enable pipelining of the hydrocarbon. Alternatively, the
hydrocarbon can be subjected
to partial upgrading at the CPF.
According to a second aspect of the present invention there is provided a
system for generating
steam for use in subsurface hydrocarbon recovery, the system comprising:
a central processing facility;
at least one well pad in fluid communication with the central processing
facility;
each well pad adjacent a related hydrocarbon recovery well(s), the related
hydrocarbon recovery
well(s) for producing produced materials;
produced materials treatment means at the well pad for separating gas, solids,
water and
hydrocarbon from the produced materials;
pipeline means for transporting the hydrocarbon from the well pad to the
central processing
facility;
steam generation means at the well pad for generating steam from the water;
and
steam injection means for injecting the steam into the related hydrocarbon
recovery well.
In some exemplary embodiments of the second aspect of the present invention,
the produced
materials treatment means at the well pad is used for separating water, gas,
solids, and
hydrocarbon from the produced materials. The system may further comprise gas
treatment
means at the well pad for treating gas separated from the produced materials,
for example for
sulphur removal, before piping the gas for re-use as fuel.
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In some exemplary embodiments of the second aspect of the present invention,
the system
further comprises a partial upgrading plant at the well pad for partially
upgrading the
hydrocarbon separated from the produced materials before being transported to
the central
processing facility, thus avoiding or reducing the need for diluent to enable
pipelining of the
hydrocarbon. Alternatively, the hydrocarbon can be subjected to partial
upgrading at the CPF.
A detailed description of exemplary embodiments of the present invention is
given in the
following. It is to be understood, however, that the invention is not to be
construed as being
limited to these embodiments.
Brief Description of the Drawings
In the accompanying drawings, which illustrate exemplary embodiments of the
present
invention:
Figure 1 is a simplified view of a conventional prior art arrangement of a
central
processing facility and a plurality of well pads;
Figure 2 is a simplified view of conventional piping of materials between a
well pad and
a central processing facility;
Figure 3 is a simplified schematic view of a first exemplary system in
accordance with
the present invention; and
Figure 4 is a simplified schematic view of a second exemplary system in
accordance with
the present invention.
Exemplary embodiments of the present invention will now be described with
reference to the
accompanying drawings.
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Detailed Description of Exemplary Embodiments
Turning now to Figures 3 and 4, exemplary embodiments of the present invention
are illustrated.
The exemplary embodiments are presented for the purpose of illustrating the
principles of the
present invention, and are not intended to be limiting in any way.
Figure 3 illustrates a first exemplary embodiment of the present invention. A
single well pad 10
is illustrated as being in fluid communication with a CPF (not shown), but it
is to be understood
that in most cases a plurality of well pads 10 would be in communication with
a single CPF. The
well pad 10 comprises a separator 12 and a steam generator 14.
While Figure 3 shows the separator 12 as a single unit, it will be clear to
those skilled in the art
that this would normally represent a number of discrete cooperating pieces of
equipment,
establishing oil removal and water treatment systems. For example, separator
12 can represent a
conventional combination of a FWKO, skim tanks, induced gas flotation, WLS and
WACS units.
A flash-treater could also be employed. Although many different types of
separation
technologies could be used with the present invention as would be clear to
those skilled in the
art, it is preferred that the separator 12 comprise compact and modular units
such as
hydrocyclones, centrifuges and membrane systems, although the separator 12
need not be limited
to either of these technologies.
The function of separator 12 is to take produced material and separate it into
various desired
components. The produced material is normally a mixture of water and
hydrocarbon (in an
emulsion), gas and solids, drawn from the well through line 16 to the
separator 12 intake. The
separator 12 ¨ through whatever process is inherent in the particular type of
separator selected ¨
separates the produced material into four streams: gas, solids, hydrocarbon
and de-oiled water ¨
the latter intended for use in steam production. The solids stream passes
through line 18 to a
landfill or other storage means familiar to those of skill in the art. The gas
stream can be treated
on the well pad 10, for example if it contains H26, and combusted in the steam
generator 14.
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The separator 12 also produces a hydrocarbon output 22, which may be a heavy
hydrocarbon
such as bitumen. Bitumen is normally too heavy to transport by pipeline and it
is therefore
common to dilute it with a diluent, conventionally a lighter hydrocarbon, to
make it amenable to
transport to the CPF for further processing. As can be seen in the embodiment
of Figure 3. a
diluent 32 is piped in from the CPF or from a diluent line and injected into
the hydrocarbon
output line 22 to enable piping to the CPF; however, the use of diluent can be
avoided if hot
bitumen is pipelined, and diluent should therefore be viewed as optional.
Other additives such as
drag reduction additives are also known to those skilled in the art, and may
be considered for use
with this exemplary embodiment, and would be added using a line such as the
chemical line 34.
In addition, chemicals such as a demulsifier may need to be sourced (from the
CPF via pipeline
or by tanker) to enable the desired separation of the produced material. The
introduction of such
chemicals is illustrated as line 34 entering the separator 12.
The final component of the produced material separated by the separator 12 is
the water output
24. As discussed above, there are existing technologies that can be used to
generate water of
sufficient purity to be used as boiler feedstock, and the particular
separation technology must be
selected to match the specification needs of the steam generation technology,
which is within the
knowledge of the skilled person. The water output 24 from the separator 12 is
then fed into the
steam generator 14, producing steam 26; solids 28 and waste water (or boiler
blowdown) 30
would commonly also be produced depending on the steam generation technology
employed.
Any solids 28 and waste water 30 would be disposed of in accordance with
common knowledge
in the field and applicable laws. The steam 26 is injected back into the well
(not shown) to
enable continued production of hydrocarbons as part of the thermal recovery
operation.
Turning now to Figure 4, an alternative embodiment of the present invention is
illustrated.
While similar in most respects to the method illustrated in Figure 3 and as
described above, the
alternative embodiment instead seeks to partially upgrade the separated
hydrocarbon stream
output from the separator 12. In this embodiment, the hydrocarbon stream is
directed to a partial
upgrading plant ("PUP") 36, in which the hydrocarbon is made lighter and more
amenable to
pipeline transport to the CPF. The partially upgraded hydrocarbon stream 38 is
output from the
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PUP 36 and pipelined to the CPF for further processing. In this embodiment,
then, there is
potentially less need for a diluent stream from the CPF, although some diluent
addition as
illustrated in Figure 3 may still be required. The operation of a PUP is
within the knowledge of
the skilled person and will therefore not be described further herein.
As can be readily seen, then, there are numerous advantages provided by the
present invention.
With the elimination of high-pressure steam pipes, pipelines can be buried
between the CPF and
the well pads, reducing the need for above-ground civil works, and on-pad
steam generation can
reduce the risk of steam loss and the need for pipe insulation. The total area
of the CPF itself can
be reduced, possibly by as much as 50% to 75%. Also, as equipment is sized for
a single well
pad, project execution costs and risks can be minimized in many situations.
The foregoing is considered as illustrative only of the principles of the
invention. Thus, while
certain aspects and embodiments of the invention have been described, these
have been
presented by way of example only and are not intended to limit the scope of
the invention. The
scope of the claims should not be limited by the exemplary embodiments set
forth in the
foregoing, but should be given the broadest interpretation consistent with the
specification as a
whole.
