Note: Descriptions are shown in the official language in which they were submitted.
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Tifie: Method and Apparatus for Establishing Fluid Communication
Between Horizontal Wells
FIELD OF THE INVENTION
5 This invention relates the field of hydrocarbon recovery or the
extraction
of oil and the like from underground reservoirs. In particular this invention
relates to methods and apparatuses related to in situ extraction of such
hydrocarbons and most particularly to processes that use a generally
horizontal
well pair that includes an injection well and a production well and requires
fluid
10 communication between the wells.
BACKGROUND OF THE INVENTION
The efficient extraction of heavy hydrocarbons from underground
reservoirs is challenging. Reservoir conditions are highly variable and pose
15 many unique challenges for extraction due to unique characteristics of
the
reservoir. Presently, although new discoveries of conventional oil are still
being
made, there is an increasing need to produce heavy hydrocarbons. The
production of heavy hydrocarbons can involve considerable technical challenges
that have to be overcome for these resources to be economically, sustainably,
and
20 safely recovered.
A prime example of an abundant but technically difficult resource is
found in the oil sands, for example, in Alberta, Canada. Surface mining is
extensively used, but can only economically reach a small fraction of the
total
known resource.
25 Consequently, efforts have been made to develop in-situ technologies
to
recover the other hydrocarbons within the oilsands. These technologies seek to
recover the hydrocarbons from the surface without significant disturbance of
the
surface soil and the arboreal forest as is required with the surface mining
approach. Current in-situ technologies being used commercially or are in
30 development can be classed as thermal, thermal-solvent and solvent only
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processes, with this classification based on the media or energy source used
to
mobilize the heavy, or pay hydrocarbons.
Some in-situ technologies use a pair of generally horizontal wells, one
generally above the other, which are sometimes referred to as a well pair. The
5 upper well is the injection well used for injecting a working fluid such
as water
steam and/or solvent vapour, and the lower well is the production well used
for
pay zone hydrocarbon and working fluid recovery. Recovery processes
employing horizontal wells in such a vertically paired configuration may rely
on
gravity drainage, with the mobilized liquids draining down into the production
10 well from an extraction chamber which is formed around and above the
injection
well by means of continuous working fluid injection.
The start-up phase may be considered to be that part of the extraction
process operation after the wells have been drilled and completed, but before
an
extraction chamber has been developed. In paired horizontal wells of the type
15 used for gravity drainage, the wells are typically drilled in proximity
to a bottom
of a pay zone containing hydrocarbons. If the bitumen is immobile at initial
reservoir conditions, then fluid communication needs to be established between
the wells to permit the drainage to occur from the formation to the production
well. Fluid communication, in this sense, means that fluids can travel under
the
20 influence of gravity, for example, between the upper well and the lower
well so
that, for example, gases injected through the upper injector well can condense
and these condensed liquids can flow down to be removed through the producer
well underneath. If the region between the two wells is filled with immobile
hydrocarbons drainage is blocked thus limiting production of mobile
25 hydrocarbons to the surface. In essence then, fluid communication
involves
removing the immobile, or near immobile hydrocarbons from between the well
pair in a manner that permits fluids to easily drain down to the production
well. If
the liquid drainage is obstructed, then the extraction chamber will just fill
up with
liquid and the ability to deliver working fluid and/or heat to the reservoir
is
30 impaired.
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In the SAGD process, steam is typically circulated in the well bores to
preheat the surrounding reservoir. By means of such heat the hydrocarbons are
rendered somewhat mobile and can be removed from between the well pair. This
approach has some disadvantages for solvent based processes because it
introduces a lot of water into the formation and water can be an effective
barrier
to solvents, and thus impair the contact between solvent and the bitumen.
Further, this would require both solvent and steam processing surface
facilities
which duplicates capital costs.
Canadian Patent Applications 2,691,889 and 2,730,680 relate to solvent
extraction processes in which a solvent gas is circulated in both the
production
well and the injection well to warm the near well bore area. However, these
patent applications teach the use of a solvent gas at a temperature above its
critical temperature. The problem with using gas to establish communication
between the well pair is its relatively low sensible heat content;
consequently, the
start-up process will take a long time to mobilize the pay hydrocarbons
between
the well pair and require high gas flow rates and pressure drops to establish
the
desired temperature rise between the two wells even though a high temperature
is
being used. High pressures can lead to solvent leak off and loss. Further, as
taught in these applications, the high heat creates a de-asphalting effect
that can
lead to deposits. Such deposits, if located between the upper and the lower
well
can cause a reduction in the formation permeability between the wells, leading
to
plugging or poor drainage. Lastly, a high heat, high pressure process will
likely
lead to spot breakthroughs between the well pair or short circuiting, which
will
establish some, but only very limited, localized hydraulic drainage between
the
wells. What is desired is a start-up process that will generally mobilize and
remove substantially all of the pay hydrocarbon from the entire length of the
zone
between the well bores thereby permitting the formation to be freely draining
for
the working fluids without leaving damaging asphaltene deposits behind in the
reservoir region used for well drainage. An improved start-up procedure is
required.
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SUMMARY OF THE INVENTION
What is desired therefore is a start-up method to establish fluid
communication by forming a drainage zone between a pair of horizontal wells
that are to be used in gravity drainage thermal, thermal-solvent, and solvent
based
5 extraction processes. Thus, for any process which can create mobile
fluids within
the formation good drainage rates will lead to good production rates. The
preferred start-up method should mobilize and remove the pay hydrocarbon in
the
inter well bore zone without introducing excess water into the formation or
causing other formation damage such as the deposition of asphaltenes. The
start-
up method should be reasonably quick and reliable to establish good
communication along the length of the well pair with a minimum of blocked or
impervious regions. The total time for the start-up process should be
minimized,
be simple and robust, and at the completion of the start-up process, the in
situ
conditions should be compatible with the desired subsequent working fluid
15 injection conditions. In particular, for example for a heated solvent
process, the
temperature of the formation between the well bores should be compatible with
the operating temperature for the follow on condensing solvent process, for a
smooth hand off between start-up and extraction.
According to the present invention these and other objectives can be met
20 by using a multi-step start-up procedure. A first step is to deliver
heat into each
of the well bores. This can be readily achieved by circulating start-up liquid
such
as a hot hydrocarbon fluid into the toe of the well and back along the annulus
or
vice versa into the heel and back down the annulus or by energizing a heating
element placed in the well bore or by some combination of both. Heat supplied
25 to each of the well bores will be conducted outward from the well bore
and will
eventually raise the temperature of the region between the well bores. The
start-
up procedure involves optionally preheating the near well bore area for
example,
using a resistance electrical heating device inserted into each of the well
bores.
Next, a positive pressure differential can be applied between the injection
and
30 production wells to displace the start-up liquid into the pay
hydrocarbon, to
encourage further mixing, warming, and displacement into the one of the
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production and injection wells where it can be subsequently removed by the
recirculating start-up liquid. The temperature may be reduced or increased
during this stage and recirculation from both wells is carried on until the
pay
hydrocarbon starts to become reasonably mobile, as evidenced by the amount of
pay hydrocarbon content produced to the surface in conjunction with the re-
circulating liquids. At an appropriate time, the production well is put into
production, with artificial lift if required, and the recirculation rate in
the
injection well is gradually reduced in favour of a displacement between the
upper
injection well to the lower production well. This displacement is carried on
until
the mobilized pay hydrocarbon is largely removed from between the wells and
clear communication is established by the start-up liquid. Communication
completeness is determined by the amount of pay hydrocarbon in the
recirculation fluid at the production well. The mobilization and removal of
the
inter-well bore pay hydrocarbon is accomplished whilst substantially avoiding
the
creation of potentially harmful asphaltene deposits in the near well bore
region
since it is a displacement rather than a solvent mobilization. More
specifically,
this goal is achieved by avoiding the use of known deasphalting solvents such
as
propane, butane, pentane and others that cause asphaltene precipitation until
after
the start-up phase is completed. During a following condensing solvent process
for example, where de-asphalting may occur, such de-asphalting will occur at
the
extraction chamber perimeter, will be widely disbursed and will not adversely
affect fluid drainage properties to the production well.
According to one aspect, the present invention provides a method of
establishing fluid communication between a pair of vertically spaced apart
generally horizontal wells located within a pay zone in an underground
hydrocarbon bearing reservoir, said method comprising the steps of:
providing a start-up fluid based heat delivery system in each of said
generally horizontal wells;
circulating a heated displacement start-up fluid in each of said wells at a
first temperature;
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applying a pressure differential between said well bores to encourage
start-up fluid displacement across an inter well bore region from one of said
wells
towards the other to encourage establishing fluid communication between said
well pair;
controlling a viscosity of said start-up fluid through one or both of
temperature and concentration effects to encourage sweeping pay hydrocarbons
out of said inter well bore region; and
transitioning from displacing said start-up fluid to commencing a working
fluid extraction process using gravity drainage.
In one embodiment a pre-heating step of using an electrical downhole
heater may be used. The pre-heat may be an electrical resistance heater, or
any
other downhole heat source which can passively warm the inter well bore area
before fluid is circulated. Optionally, the present invention provides an
electrical
resistance-based pre-heating system in each of said generally horizontal wells
which can be operated simultaneously with start-up fluid circulation.
In a further embodiment there is provided a start-up method for a pair of
vertically offset horizontal wells located within a hydrocarbon bearing
reservoir,
the start-up method comprising the steps of:
circulating, within each well, a heated start-up fluid to heat at least an
inter well bore region by conduction;
applying a pressure differential between said well bores to encourage said
heated start-up fluid to displace across said inter well bore region to
further heat
said inter well bore region and hydro mechanically displace pay hydrocarbons ;
and
increasing a viscosity of said start-up fluid over time to reduce short
circuiting of said start-up fluid through more permeable portions of said
inter
well bore region.
In a further embodiment there is provided a start-up method for
establishing communication between horizontal wells through an inter well bore
region, said start-up method comprising:
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the steps of circulating a heated start-up fluid within each of said wells
and increasing the viscosity of the start-up fluid over time to help
physically
displace and remove pay hydrocarbons from the inter wellbore region.
There is also provided a start-up method for for an in situ solvent
extraction process for extracting hydrocarbons from an underground hydrocarbon
bearing reservoir, said start-up method comprising the steps of:
displacing pay hydrocarbon from a near and inter well bore region to
thereby displace asphaltenes from said near and inter well bore regions to
reduce
asphaltene precipitation in the near and inter well bore regions when said in
situ
solvent extraction process is applied to the underground hydrocarbon bearing
reservoir.
Also, a further embodiment includes a start-up method to remove pay
hydrocarbons from an inter well bore region between horizontal wells, said
start-
up method comprising the steps of:
warming pay hydrocarbons in an inter well bore region,
diluting pay hydrocarbons in said inter well bore region and
draining pay hydrocarbons from an inter well bore region without
significant precipitation of asphaltenes in close proximity to said wells to
improve flowability and drainage of a working fluid through said inter well
bore
region.
A further embodiment includes an apparatus for applying a start-up
method to an inter well bore region between two vertically displaced
horizontal
wells, said apparatus comprising:
a source of non deasphalting start-up fluid above grade;
a heater for heating said start-up fluid;
a well head connection from said source to each of said two vertically
displaced horizontal wells;
a fluid delivery and removal system connected to said well head to permit
said start-up fluid to be circulated along each of said two vertically
displaced
horizontal wells;
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one or more circulating pumps for circulating said start-up fluid from said
source through said heater down into said formation along each of said
vertically
displaced horizontal wells and then back up to the surface;
a conditioner located above grade to remove solids and water if necessary
from said returned start-up fluid, and
sensors to measure one or more of a temperature, a viscosity, and a
composition of said start-up fluid which is returned to the surface.
There is also provided a start-up method to remove pay hydrocarbons
from an inter well bore region between vertically spaced apart horizontal
wells in
a reservoir, said start-up method comprising the steps of:
warming pay hydrocarbons in an inter well bore region with a down hole
heat source, while building surface facilities to be able to circulate a start-
up
fluid.
Lastly, there is also provided a start-up method to remove pay
hydrocarbons from an inter well bore region between vertically spaced apart
horizontal wells in a reservoir, said start-up method comprising the steps of:
placing circulation tubing in each of the two horizontal wells to permit a
displacement start-up fluid to be circulated along each well before
communication is established between said wells, and
circulating said displacement start-up fluid along each well to mobilize
pay hydrocarbons located adjacent to each of said wells through both thermal
and
solvent effects.
BRIEF DESCRIPTION OF THE DRAWINGS
Reference will now be made, by way of example only, to preferred
embodiments of the invention in which:
Figure 1 is an illustration of a horizontal well pair located within a pay
zone of an underground formation;
Figure 2 is a graph showing the change in viscosity of sample pay
hydrocarbon such as bitumen for different temperatures and blends with a
liquid
hydrocarbon such as synthetic crude oil (SCO);
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Figure 3 is a schematic showing the different stages of a start-up
procedure according to the present invention;
Figure 4a is a diagram indicating the well bore and midline temperatures
over time for a typical well pair for a given initial electrical resistance
pre-heating
period;
Figure 4b is a diagram indicating the well bore and midline temperatures
over time for a typical well pair for a given initial start-up liquid
temperature and
flow rate;
Figure 5 is a graph illustrating the temperature at the well bore midline
and the amount of heat energy absorbed by the reservoir over a treatment
period
for a treatment according to the present invention;
Figure 6 is a chart illustrating the effect of well spacing of the well pair
on
the timing of the start-up phase according to the present invention;
Figure 7 is a schematic view of the bitumen phase on one side and the
temperature profile on the other side of at four different times during the
start-up
procedure according to the present invention;
Figure 8 shows the effect of spacing between the well pair on the drainage
time according to the present invention; and
Figure 9 shows the effect of changing the pressure differential on the
drainage time according to the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Figure 1 is a schematic view of a generally horizontal well pair with an
upper well 10 and a lower well 12 that are separated by a well spacing 14.
Midway between the wells 10 and 12 is a mid or centerline 16. The wells 10, 12
are located within an underground formation 18 which includes a pay
hydrocarbon zone 20, with an overburden 19 and an underburden 21. The well
pair 10, 12 are positioned towards the bottom of the pay hydrocarbon zone 20
in
accordance with a conventional positioning of the well pair for gravity
drainage.
The preferred type of pay zone is a heavy hydrocarbon pay zone such as may be
found in the oilsands of Alberta, Canada.
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Although the wells are shown with slanted risers 22, 24, and horizontal
casings 26, 28, it will be appreciated by those skilled in the art that these
are
illustrations only and that in practice the angle of the wells might vary
considerably from this. Thus, in this specification, the terms generally
horizontal
and generally vertical are used to comprehend the field variations that might
be
encountered from horizontal and vertical. Further, in this specification, the
term
near well bore area means an area surrounding a well bore in cross section. As
well, the term inter well bore area means the space between the well pair.
The present invention comprehends providing the well bores with a pre
heating phase which may be electrical resistance heating and or a fluid
delivery
system to provide a heated start-up liquid to the wells in accordance with a
preferred method as described below. In one form of the invention, the
resistance
heating system includes long electrical resistance well bore heaters 27, 29
that
extend along the length of each of the wells having electric power lines 31,
33
which extend to the surface and are connected to a power source. While this is
one form of pre-heating device it will be understood that the present
invention
comprehends other forms of in situ or downhole heater as well. What is desired
is some form of downhole heat that can be used after the wells are completed,
but
before the surface facilities are ready to circulate the start-up fluid.
In Figure 1, the fluid delivery system includes narrow diameter tubes 30,
32, for example 31/2-inch coil tubing, which is fed down the riser portion of
the
well and then fed out towards the toe 34, 36 of each well 10, 12. A second
narrow diameter tube 38, 40, such as the 31/2 inch coil tubing, is also fed
down the
riser portion of each well, but preferably extends only to about a heel 39, 42
of
each well 10, 12. Each of the narrow diameter tubes 30, 32, 38 and 40 are
connected to appropriate above-grade pumps and heaters to allow a circulation
of
liquid down to the toe, back along the casing and then up through the tubes
38, 40
to the surface again in each well 10, 12 as shown by arrows 44. Although this
is
shown as extending from the toe and the heel, the present invention
comprehends
ending the narrow diameter tubes intermediate the ends depending upon the
circumstances.
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In the most preferred embodiment of the invention, the start-up liquid is a
liquid hydrocarbon that is heated above-grade in an appropriate heat exchanger
(not
shown) before being circulated through the wells 10, 12, by, for example, a
pump.
Accordingly, the present invention provides a liquid circulation system for
start-up,
which permits the start-up liquid to be heated above and / or below grade,
pumped
down the tubes 30, 32 of each well and out to the toe, where it is released
into an
annulus formed between the narrow diameter tubing and the well casing. Then
the
fluid is drawn back along the casing towards the heel, where it enters the
second tubes
38, 40, and from there it is brought or pumped up to the surface. The present
invention
comprehends that the circulation direction could be reversed. At the surface
the start-
up liquid can be conditioned to remove solids and water if necessary, reheated
and
then re-circulated back into the wells as described above. Placing the start-
up fluid
well inflow end at the toe or the heel establishes a countercurrent heat
exchange,
between the tubing and the annulus. While countercurrent heat exchange is not
optimal and initially produces large thermal gradients along the well bore,
calculations show that for the preferred embodiment of the invention, within a
week,
the counter-current temperature gradient flattens out and the well bore is
effectively
isothermal, permitting most of the heat in the start-up liquid to be delivered
to the
formation in the near well bore area through conduction.
The preferred method of the present invention is a multiple step process, as
described in more detail below. In an optional first step or phase, which may
or may
not be appropriate in all circumstances a downhole heat source, such a
downhole
heater, for example, an electrical resistance heating device can be placed in
each of
the well bores. Heat from the downhole heater is delivered to the well bore
and in the
case of a resistance electrical heater is transferred into the reservoir
formation by
conduction. Electrical power is supplied to the resistance heating device
located
above grade through an appropriate connection to an electrical power supply.
This is
considered a pre-heating step or phase and is continued until a desired amount
of heat
is delivered to the reservoir. Such a
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preheating step may reduce the time required to transfer heat through start-up
fluid circulation alone.
As for the start-up fluid, assuming that no down hole heater has been
used, in the next step the start-up liquid is heated above grade, and then
simply
circulated within each well for enough time to further increase the reservoir
temperature in the region surrounding the well bores or the near well bore
area.
As the start-up liquid's heat is transferred to the formation through
conduction,
the temperature will gradually rise in the near well bore region in a circular
or
radial pattern around each well bore. The heat and volume lost from the
circulating start-up liquid is made up by a combination of reheating and the
addition of fresh, hot start-up liquid at the surface. It will be appreciated
that the
preferred start-up liquid is one that is compatible with the surface
facilities for the
extraction process. Thus, in the case of a process that uses a working fluid
of a
condensing solvent, the preferred start-up liquid is a form of liquid
hydrocarbon.
Many different start-up liquids are comprehended by the present invention,
provided they meet with certain initial criteria. Most preferably, the start-
up
liquid is hydrocarbon-based so as to avoid using or introducing water into the
formation. Fluids such as SCO, diesel fuel and other refined or upgraded
products are suitable. What is most preferred is a liquid that does not cause
de-
asphalting, will remain a liquid in the temperature and pressure ranges used
in the
start-up process of the present invention, and which is generally available in
the
local area. Liquids are preferred over gases due to their greater
effectiveness in
delivering heat to the reservoir and their greater ability to sweep out or
displace
in situ hydrocarbons located between the well pair.
Of course, the rate of heating will depend on a number of factors,
including the rate of flow and initial temperature of the start-up liquid and
the
initial temperature of the reservoir. According to well understood engineering
principles, the greater the temperature difference between the start-up liquid
and
the reservoir, the more rapid the heating of the reservoir will be. However,
there
may be temperature and pressure limits imposed by the conditions present in
the
reservoir or the desired start-up conditions that must be considered in
defining the
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operating conditions for temperature and pressure. In the event that an
initial pre-
heat is applied with a downhole heater, the start-up fluid must be warmer that
the
near well bore temperature to add heat to the formation. However, the start-up
fluid is also responsible for hydromechanical effects as set out below, namely
the
displacement of the inter well bore pay hydrocarbons even if the heating has
been
adequately done by the electrical heat.
Figure 2 shows a graph that illustrates the calculated change in viscosity
of representative bitumen with both change in temperature and change in
concentration in a preferred hydrocarbon start-up liquid, specifically SCO, in
a
bitumen/SCO blend. The curve 50 is the change in viscosity curve of pure
representative bitumen. Below that are curves 52, 54, 56, 58 and 60, which
represent 90% bitumen/10% SCO to 10% bitumen/90% SCO in changes of 20%
on a per line basis. The line 62 represents the change in viscosity for SCO
over a
range of temperatures. This graph illustrates that there are significant
changes in
viscosity for the bitumen with both a temperature change and a change in SCO
concentration. As can now be understood, the present invention seeks to take
advantage of two ways to reduce viscosity of the bitumen in the inter-well
bore
zone i.e. by both warming and liquid dilution. In some cases, it may be
appropriate to clean out the wells before commencing with the start-up method
of
the present invention. The clean out of the wells is for the purpose of
removing
any material that would impede the easy flow of fluids through the well, such
as
leftover drilling mud or the like, as well as removing any excess free water
that
might be present. A nitrogen or other gas huff-and-puff optionally is
comprehended by the present invention. In this sense a huff-and-puff
pretreatment step involves injecting a gas, up to a certain pressure, and then
releasing the pressure and removing the gas from the area in which it was
applied. In any such clean out preconditioning step, it is important not to
use so
much pressure as to overpressure the formation. Thus, it is preferred to keep
the
"huff' pressure well below a formation fracture pressure and most preferably
below reservoir pressure during the huff and puff step. By being below the
native
reservoir pressure it may be possible to prevent a loss of the pressurized gas
to
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the formation. The clean out gas can also be circulated through the well tubes
to
the toes, then into the annulus and then drawn out again through the well
tubes
located at the heels as described previously to clean the tubes out if needed
or
desired.
Once the clean out step has been completed (if the same is necessary or
advisable), the start-up method can commence. Figure 3 shows a schematic of a
preferred form of the present invention, which has four main stages identified
by
numerals I, II, III and IV across the top and, for ease of reference, the
bottom of
the Figure 3. Plots are provided for the changes in various parameters during
each of the start-up phases. At the top, line 70 is a plot of the temperature
of the
well bores during the four phases for the invention implemented in an oilsands
reservoir as found in Alberta, Canada. Below it is a plot 72 of the
temperature of
the centerline between the two wells for the like implementation, and Line 74
is a
plot of the applied pressure differential between the two wells. The plot 76
identifies the average relative pay hydrocarbon concentration that arises
between
the well bores in the zone to be cleared. The plot 78 shows the average
relative
change in the pay hydrocarbon viscosity at the well-pair centerline during the
start-up phases. While these values are suitable for the representative
bitumen
used in this example, the actual values may vary for other bitumen or pay
hydrocarbon deposits.
The present invention comprehends a further pretreatment step using a
means of delivering heat directly to the formation through a downhole heater
such as an electrical downhole heater. In a preferred embodiment the heater is
in
the form of a long heater element that can run the length of the wells. As can
be
seen from the Figure 3, Stage I involves raising the temperature of the near
to the
inter well bore area. This may be done by a downhole heater, by circulating
hot
start-up fluid or a combination of both. Regardless of the source of the
heating
what is desired is to provide an even heat distribution along the length of
wells to
help warm the inter well hydrocarbons. In the event downhole heaters are used,
one form is to use long heating cables that run the length of the wells to
provide
heat distribution along the length. As the wells are typically drilled prior
to the
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construction of the above grade facilities, the use of a downhole heater with
no
fluid circulation may enable well bore heating to start before the plant might
otherwise be available to begin the start-up fluid circulation phase, thus
beginning pre-heating early and potentially shortening the start-up time. It
is
desirable to top up the well bore with an appropriate fluid like SCO to
enhance
the uniform transfer of electrical heat to the reservoir and avoid the
potential of
overheating during the downhole heater heating step. This also encourages some
near well bore dilution of the pay hydrocarbon which is required for viscosity
reduction as explained in more detail below.
Another option to deliver heat to the formation in the first stage of the
present invention is the circulation of heated liquid, which will further
distribute
the heat along the well length and also carry heat to the formation without
asphaltene precipitation. As can be seen by the temperature graph of the
centerline temperature 72, over this phase, the temperature between the wells
rises from a native reservoir temperature to anywhere between 40 C and 70 C,
most preferably between about 40 C to 50 C. As shown by the plot line 78, the
application of heat will reduce the bitumen viscosity by about 99%. This is
accomplished primarily through the temperature conduction as there is no
appreciable mixing of the start-up liquid and the pay hydrocarbon during this
phase.
The present invention comprehends providing heat by circulating a heated
start-up fluid through each of the producer and the injector wells. Assuming a
500 meter well and a 31/2-inch coiled tubing, the start-up liquid can be
circulated
at a rate of 5000 barrels per day (bpd) per well and an initial temperature of
anywhere between 30 C to 300 C, but in this example at about 120 C. In this
example, the average spacing between the horizontal wells is assumed to be 5.5
meters. Using these values, the temperature increase in the near-well bore
area as
a function of time can be calculated. The length of time required to complete
the
this phase is estimated to be about two to six months, with about three months
being average, but the time being dependent on the amount of downhole heater
pre-heating the start-up fluid temperature, the recirculation flow rate, the
length
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of the wells and the reservoir characteristics. These start-up times are
examples of
what might be suitable, but other start-up times are also comprehended by the
present invention. In choosing the appropriate start-up fluid and temperature,
it is
preferable to avoid de-asphalting conditions in the inter well bore area that
can
damage the porosity of the reservoir formation and inhibit the ability to
establish
communication between the well pair.
It is also highly undesirable to inject hot hydrocarbon based fluid at
pressures well above native reservoir pressures because this can lead to loss
of
confinement and the start-up fluid can be lost from the inter well bore
region.
This displacement can be avoided or mitigated by the use of artificial lift,
so that
the downhole circulating pressure is maintained at or perhaps even below the
native reservoir pressure. During the next step, the temperature of the start-
up
liquid is adjusted to achieve desired operating temperatures for a subsequent
formation treatment while still circulating as per Stage I. The main event of
phase II is the application of a pressure differential between the two well
bores.
Most preferably, the pressure is applied from the upper well to the lower
well, so
that the pay hydrocarbon flows downward assisted by such pressure differential
and the viscosity reduction arising from one or both of a temperature change
and
dilution. A pressure applied from the lower well to the upper well is also
comprehended by this invention. The pressure difference may be applied by
increasing the pressure in one well, reducing the pressure in the other well,
or
both. Adjusting the pressure in both wells allows for the optimization of the
pressure differential between the wells without exceeding a desired maximum
pressure in the reservoir formation. The benefits of the applied pressure
differential can now be better understood, as, for example, as pressure is
applied
to the upper well, it will displace the start-up fluid outwardly. In turn, the
start-
up liquid will displace the pay hydrocarbon downwardly into a warmer region of
the lower well. This displacement further encourages the dissolution and
warming of the pay hydrocarbon so as to reduce its viscosity and enhance the
ability to displace it from between the well pair.
CA 02784582 2016-01-13
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As can be seen from the plot line 76 in Figure 3, the increased start-up
fluid concentration in the pay hydrocarbon and the increased temperature have
the effect of further lowering the pay hydrocarbon viscosity, as shown by the
plot
78. Most preferably, this phase is completed with little or no further
addition of
start-up liquid. This means that the circulating fluid reaching the surface
trends
towards an increasing concentration of pay hydrocarbon content in the start-up
fluid. As can now be appreciated, the rising content of pay hydrocarbon in the
circulating start-up fluid in combination with a decreasing temperature
increases
the viscosity of the start-up fluid and helps to limit the amount of fluid
flowing
between the two horizontal wells, while still allowing a pressure difference
to be
sustained. In this manner, the present invention is better able to
hydraulically
sweep out pay hydrocarbons between the wells. Further, the amount of pay
hydrocarbon present in the start-up liquid can be monitored and used as a
proxy
for how close the process is to establishing communication along the full
length
of the well pairs. The present invention contemplates that there will be a non-
uniform flow rate of start-up fluid between the wells at various locations
along its
length. However, by continuing the process of re-circulating the start-up
fluid,
with the application of moderate pressures over a sufficiently long enough
time
frame, the present invention can provide for the gentle physical displacement
and
removal of the pay hydrocarbon from the inter-well bore area without
asphaltene
deposition.
Now the procedure enters the next stage III of the present invention. As
more and more of the inter-well bore pay hydrocarbon is progressively
mobilized
and displaced, the circulating pumps become rate limited and thus the ability
to
apply a pressure differential may be reduced. Again, it is desirable to
continue to
adjust the temperature of the circulating fluid gradually so as to permit the
formation to assume the design operating temperature for the extraction
process
that follows. This can involve a reduction in start-up fluid temperature.
Also, the
viscosity of the circulating fluids may be increased by allowing a greater pay
hydrocarbons concentration or a lower temperature or both. A higher viscosity
allows a high pressure differential and a more effective sweep of pay
CA 02784582 2016-01-13
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hydrocarbons from the inter well bore region. In the case of a following
solvent
based extraction process, the design operating temperature may generally be
between 20 C to 70 C, most preferably 40 C to 60 C, but again dependent on
the
reservoir conditions. Ideally, the heated start-up liquid-pay hydrocarbon
fluid
mixture that is circulating is almost at the same temperature as the
centerline by
the end of this phase. However, due to the mixing and mobilization of the
start-
up liquid and the pay hydrocarbon there is a higher concentration of start-up
fluid
between the well bores. As can be seen from the plot 78, the viscosity of the
centerline is still further reduced during this next stage as the centerline
fluid
(bitumen) is progressively displaced with the bitumen start-up fluid blend.
The
application of a sustained pressure differential over a sufficiently long time
ensures almost complete mobilization of the pay hydrocarbon in the inter well
bore region. The completion of this stage III can be predicted by numerical
simulation, and/or confirmed by a variety of physical measurements, such as
pressure drop, shut in well bore temperature profiles, fluid properties,
tracer
residence time analysis, etc.
The last stage is stage IV, and it consists of preparing the chamber for
production. At the start of this stage, the centerline temperature is about 60
C or
whatever other temperature is desired to achieve optimum temperature for the
start of the working fluid injection and the fluid between the two well bores
is a
diluted mixture of pay hydrocarbon and start-up fluid with a viscosity between
10
cP and 1000cP.
At this point, the fluid recirculation into the wells is stopped and the
mobilized fluid is drained. A means for lifting the liquids out of the
formation
may be required, such as by using an electrical submersible pump on the
production well. The pump is operated for long enough to permit all of the
fluid
to drain out of the near-well bore area so it can be replaced by the working
fluid
and to thereby establish good hydraulic drainage along the length of the
wells.
This is shown as a dramatic reduction in start-up liquid concentration between
the
wells, and a temperature at the centerline which approaches the temperature of
the well bores indicating an even temperature distribution in within the inter-
well
CA 02784582 2016-01-13
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bore region. In some cases it may be necessary to provide working fluid vapour
to the chamber to provide voidage replacement as the mobilized pay hydrocarbon
is drained. In other cases, the voidage volume may be filled from dissolved
gases
that may naturally evolve from the pay hydrocarbon. If it is necessary to
supply
some working fluid then a small amount of, for example, solvent vapour can be
injected into the well provide some vapour pressure support without reaching a
pressure that causes condensing conditions so as to minimize the risk of
deasphalting the mobilized pay hydrocarbon between the well bores.
When the mobilized pay hydrocarbon is largely drained from the well
bore region then the injection of working fluid can now begin. The working
fluid
is injected from the injection well into the heated, drained chamber and it
traverses the chamber and condenses on the cooler extraction interface,
located at
the periphery of the extraction chamber, where it releases its heat and
reduces the
viscosity of the pay hydrocarbon so that the blend can drain by gravity down
to
the production well. Achieving this condition is mostly a matter of increasing
the
working fluid injection rate so that the chamber pressure is such that
condensing
conditions are achieved. From this point on, normal gravity drainage
production
can proceed. The start-up procedure thus displaces pay hydrocarbon from the
inter well bore area through the combined effects of dilution with start-up
fluid
and raises the temperature. Although 60 C is used in the example, it will be
understood by those skilled in the art that any convenient, condensing vapour
temperature could be selected based on the working fluid being used. What is
desired is to have the temperature of the near-well bore area compatible with
the
desired operating conditions once the start-up process is complete.
It can now be understood that the working fluid may result in the deposit
of immobile asphaltenes with the formation. However, as the start-up stages
have displaced the pay hydrocarbons from the inter and near well bore area,
these
asphaltenes will be located well away from the well bores, and will be
dispersed
through the formation. Thus, it can be appreciated that the present invention
is
intended to reduce the production of the asphaltenes at a location where they
CA 02784582 2016-01-13
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could substantially interfere with the hydraulic drainage properties of the
formation in the vicinity of the production well.
Certain features of the present invention can now be appreciated. For
example, it can be now understood that the present invention warms, dilutes
and
drains the pay hydrocarbon between a pair of generally horizontal wells
without
significant precipitation of asphaltenes in the close proximity of the wells.
This
is intended to ensure good flowability and drainage of the working fluid and
produced fluid both around the wells and between the wells. The pressure
differential is applied between the wells to encourage mixing, for better heat
transfer, and to mobilize the pay hydrocarbon from the well bore area into one
of
the wells so that it can be removed from the reservoir. The start-up liquid
has an
ability to deliver heat efficiently to the formation to encourage a reduction
in the
viscosity of the in situ pay hydrocarbon. Using the toe delivery tube and the
heel
removal tube in each horizontal well encourages the flow of the start-up
liquid
along the length of the wells to even out the heat distribution during the
process
along the full length of the horizontal wells. Figure 4 shows the well bore
and
center line temperatures, after 3 days, 10 days, 90 days and steady state, for
wells
with a working fluid supply temperature of 120 C for a 500 meter well pair and
a
5000 bpd circulation rate. As shown, the temperature in the wells after one
week
is about 105 C and it is estimated that the temperatures reach a steady state
when
the heel is about 110 C and the toe is about 115 C.
The centerline temperature profile (i.e. at the midline 16 of figure 1) is
also shown at different times during the start-up process (in this case
without a
downhole heater pre-heating step). In this same example, the well temperatures
are shown at the start, after ten days, after 30 days, after 80 days and after
115
days. As can be seen, the temperature profiles at the centerline are quite
uniform
despite the large increase in the well bore temperature. This is because it
takes
time for the heat to be conducted out to the mid-point between the well pair.
Figure 5 is a graph of the total heat supplied to the area and the
temperature history over time for this example. The plot line 80 shows the
change in temperature and the plot line 82 shows the rate of heat input in kW.
As
CA 02784582 2016-01-13
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the reservoir surrounding the wells gets warmer, the rate of heat transferred
by
the start-up fluid gets smaller due to a smaller temperature difference. As
shown,
after one week the rate of heat input into the ground is about 500kW per well
pair, after two weeks it might drop to about 400kW and at the end of the
period it
has dropped to 300kW.
Figure 6 shows the estimated effect of start-up fluid temperature on the
warm-up period. According to the present invention, the warm-up period can be
reduced by supplying the start-up fluid at a temperature of 140 C as compared
to
120 C, and reduced even further by supplying start-up fluid at 170 C. The
reduction in start-up time for a well spacing of 5.5 meters on average is
estimated
to be to three months for an operating temperature of 140 C as compared to
well
over four months for a 120 C operating temperature, and two months for 170 C,
as shown by plot line 90. Plot lines 92 and 94 show the start-up time for a
well
pair spacing of 4.5 meters and 6 meters respectively and various operating
temperatures. It will be understood, however, that the end of the start-up
procedure defines a starting temperature for the beginning of extraction. The
higher the temperature of the extraction process, which in some cases is
controlled by selecting an operating pressure and thereby defining a
condensation
temperature, the greater the overall energy requirement for the extraction.
Thus,
the present invention is intended to warm the formation up in the near-well
bore
area to a temperature that is compatible with the extraction process which
follows. In a preferred embodiment the hand-off temperature is equal to the
extraction temperature, but the present invention comprehends that these two
temperatures may also be different, depending upon the extraction process.
Figures 7a to 7d illustrate more clearly the effect on the near- and inter-
well bore areas of the start-up method according to one aspect of the present
invention. These graphs depict temperature profiles over time, and are
estimated
at 30, 60, 85 and 93 days for a test case. The test case is a well of 500
meters in
length, with a start-up liquid temperature of 120 C, a well separation
distance of
5.5 meters, and a differential pressure of 2MPa. On the left hand side of each
drawing is the pay hydrocarbon swept areas and on the right hand side is shown
CA 02784582 2016-01-13
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the estimated temperature contours 100. As can be seen by the thermal
contours,
the temperature wave gradually penetrates outward, further away from the wells
10, 12 in a radial pattern. On the other half of the figures, it can be seen
that the
pay hydrocarbon is gradually swept out of the inter-well bore region over time
with the expansion of swept area, shown as 102, 104, and 106. The exact time
required to displace the pay hydrocarbon and complete the start-up process
will
vary from reservoir to reservoir and will vary along the wells depending on
the
spacing of the horizontal wells at a particular location but the foregoing
illustrates
the effect of the preferred invention on the near-well bore region. For ease
of
illustration, the swept areas are shown for one half of the well bores 10, 12,
although it will be understood by those skilled in the art that the swept area
will
be symmetrically extended on both sides of each of the wells 10, 12.
Figure 8 shows the effect on the sweeping time of the pay hydrocarbon of
well pair separation and start-up fluid operating temperature. The y-axis is
sweeping time in days and the x-axis is the temperature of the start-up fluid.
The
plot lines 110, 112 and 114 show that the closer the well pair 10, 12 is
together,
and the higher the applied temperature, the quicker the sweeping time for this
representative example. Figure 9 shows the effect on sweeping time of start-up
fluid temperature and applied pressure. In this figure, the y-axis is sweeping
time
in days and the x-axis is the temperature of the start-up fluid. Additionally,
the
plot lines 116, 118 and 120 are three different pressure differentials applied
between the wells 10, 12. As can now be appreciated, the present start-up
method can be varied to be made quicker or slower as needed to suit local
reservoir conditions and operating requirements. Generally, the greater the
temperature of the start-up fluid, the faster the displacement can occur,
sweeping
out the pay hydrocarbons. Generally, the closer the well spacing, the faster
the
pay hydrocarbon is removed from the inter-well bore area. Generally, the
higher
the pressure applied between the wells, the faster the desired completion of
sweeping the inter-well bore region of pay hydrocarbon. However, the
individual conditions of the reservoir may provide upper limits to each of
these
parameters. Closer well spacing requires good inflow control into the
production
CA 02784582 2016-01-13
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well to avoid flooding the injector well with liquids. Higher pressure
differentials
require good reservoir integrity to avoid pushing the start-up fluid out, away
from
the inter-well bore area through high permeability routes.
As can now be appreciated, the present invention comprehends using
certain equipment to implement the preferred start-up process. For example,
above grade there is a source of liquid start-up fluid, most preferably a non-
asphaltene hydrocarbon that can be heated by a heater to a predetermined
temperature. Next, there needs to be a pump and a wellhead connection, to
permit the heated hydrocarbons to be circulated through the wells. If the
reservoir integrity is sufficient, that the pump pressure can be used to also
pump
the fluids back out of the well, then that is preferred. However, the present
invention also comprehends that it may be necessary to use well heel pumps to
pump the liquids back up to the surface as a means to reduce the reservoir
pressure to match reservoir containment conditions. Such well heel pumps might
be any form of suitable pumps for artificial lift such as electrical
submersible
pumps. This adds expense and complexity and thus is less preferred except when
to do otherwise would invite a loss of liquids owing to a lack of reservoir
integrity.
The present invention also comprehends using temperature and pressure
sensors and the like to instrument the wells during the start-up process to
provide
monitoring of the progress of the start-up through the different phases. The
present invention also comprehends using temperature and pressure sensors and
the like to instrument observation wells in order to monitor the start-up
process.
Sampling facilities located above grade are also required to monitor the pay
hydrocarbon content of the circulating fluid.
The present invention also comprehends the use of a downhole heat
source such as an electrical resistance heater to use in delivering heat as an
initial
option phase of the start-up process, as noted above.
As can now be appreciated the present invention provides for a warming
of the pay hydrocarbon in the near well bore area by contact with a warm start-
up
liquid, for the purpose of reducing the viscosity of the pay hydrocarbon. In
this
CA 02784582 2016-01-13
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sense, warm means moderate temperatures as opposed to the high temperature
steam at typical reservoir pressures of 1 MPa or higher. Further, the start-up
liquid is dissolved into and mixed with the pay hydrocarbon to further reduce
the
viscosity without being in sufficient quantity or kind that substantive
asphaltenes
are deposited in the inter well bore region. Essentially the present invention
is
aimed at mobilizing and then removing the pay hydrocarbon, largely by
hydraulically sweeping or displacing the same, from the near-well bore area to
establish a working fluid injection and extraction chamber. At the end of the
start-up process, the extracted zone is at or near to the desired temperature
for the
extraction process that follows. The start-up process has been carried out in
the
absence of any water injection. Also, any residual water in the reservoir that
may
have been turned into steam by the warm start-up liquid, will re-condense and
be
removed from the near-well bore region as the liquids are removed in the start-
up
process. Once extraction commences, the asphaltene deposits that may occur
will
be formed at a location distant to the near-well bore region at the extraction
interface and thus will not impede fluid flow in the near well bore region.
Further, the start-up liquid is preferably compatible with the surface
facility that
is located above the reservoir for the purpose of working fluid injection and
pay
hydrocarbon production. Furthermore, the displacement from injector to
producer
could be reversed and the circulating and displacement fluid could be injected
at
other locations besides the toe, and withdrawn at other locations besides the
heel,
as needed.
While the foregoing describes preferred embodiments of the present
invention, it will be understood by those skilled in the art that various
modifications and alterations are possible without departing from the broad
spirit
of the invention as defined in the attached claims. While some of these
variations
have been discussed above, others will be apparent to those skilled in the
art. All
such variations and modifications are comprehended by the present
specification.
