Note: Descriptions are shown in the official language in which they were submitted.
CA 02931900 2016-06-02
SAGD WELL CONFIGURATION
FIELD OF THE INVENTION
[001] This invention relates to oil recovery and more specifically to
exploiting the thermal
properties of well bores in oil recovery.
BACKGROUND OF THE INVENTION
[002] Over the last two centuries, advances in technology have made our
civilization
completely oil, gas & coal dependent. Whilst gas and coal are primarily use
for fuel oil is
different in that immense varieties of products are and can be derived from
it. A "brief' list of
some of these products includes gasoline, diesel, fuel oil, propane, ethane,
kerosene, liquid
petroleum gas, lubricants, asphalt, bitumen, cosmetics, petroleum jelly,
perfume, dish-washing
liquids, ink, bubble gums, car tires, etc. In addition to these oil is the
source of the starting
materials for most plastics that form the basis of a massive number of
consumer and industrial
products.
[003] Table 1 below lists the top 15 consuming nations based upon 2008 data in
terms of
thousands of barrels (bbl) and thousand of cubic meters per day. Figure 1A
presents the
geographical distribution of consumption globally.
Nation (1000 bbl/day) (1000 m3/day)
1 United States 19,497.95 3,099.9
2 China 7,831.00 1,245.0
3 Japan 4,784.85 760.7
4 India 2,962.00 470.9
Russia 2,916.00 463.6
6 Germany 2,569.28 408.5
7 Brazil 2,485.00 395.1
8 Saudi Arabia 2,376.00 377.8
9 Canada 2,261.36 359.5
South Korea 2,174.91 345.8
11 Mexico 2,128.46 338.4
12 France 1,986.26 315.8
13 Iran (OPEC) 1,741.00 276.8
14 United Kingdom 1,709.66 271.8
Italy 1,639.01 260.6
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Table 1: 2008 Oil Consumption for Top 15 Consuming Nations
[004] In terms of oil production Table 1B below lists the top 15 oil producing
nations and the
geographical distribution worldwide is shown in Figure 1B. Comparing Table lA
and Table 1B
shows how some countries like Japan are essentially completely dependent on
oil imports whilst
most other countries such as the United States in the list whilst producing
significantly are still
massive importers. Very few countries, such as Saudi Arabia and Iran are net
exporters of oil
globally.
Nation (1000 bbl/day) Market Share
1 Saudi Arabia 9,760 11.8%
2 Russia 9,934 12.0%
3 United States 9,141 11.1%
4 Iran (OPEC) 4,177 5.1%
China 3,996 4.8%
6 Canada 3,294 4.0%
7 Mexico 3,001 3.6%
8 UAE (OPEC) 2,795 3.4%
9 Kuwait (OPEC) 2,496 3.0%
Venezuela (OPEC) 2,471 3.0%
11 Norway 2,350 2.8%
12 Brazil 2,577 3.1%
13 Iraq (OPEC) 2,400 2.9%
14 Algeria (OPEC) 2,126 2.6%
Nigeria (OPEC) 2,211 2.7%
Table 2: Top 15 Oil Producing Nations
[005] In terms of oil reserves then these are dominated by a relatively small
number of nations
as shown below in Table 3 and in Figure IC. With the exception of Canada the
vast majority of
these oil reserves are associated with conventional oil fields. Canadian
reserves being dominated
by Athabasca oil sands which are large deposits of bitumen, or extremely heavy
crude oil,
located in northeastern Alberta, Canada. The stated reserves of approximately
170,000 billion
barrels is based upon only 10% of total actual reserves, these being those
economically viable to
recover in 2006.
Nation Reserves (1000 bbl) Share
1 Saudi Arabia 264,600,000 19.00%
2 Canada 175,200,000 12.58%
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3 Iran 137,600,000 9.88%
4 Iraq 115,000,000 8.26%
Kuwait 104,000,000 7.47%
6 United Arab Emirates 97,800,000 7.02%
7 Venezuela 97,770,000 7.02%
8 Russia 74,200,000 5.33%
9 Libya 47,000,000 3.38%
Nigeria 37,500,000 2.69%
11 Kazakhstan 30,000,000 2.15%
12 Qatar 25,410,000 1.82%
13 China 20,350,000 1.46%
14 United States 19,120,000 1.37%
Angola 13,500,000 0.97%
Table 3: Top 15 Oil Reserve Nations
[006] Therefore in the vast majority of wells are drilled into oil reservoirs
to extract the crude
oil. An oil well is created by drilling a hole 5 to 50 inches (127.0 mm to
914.4 mm) in diameter
into the earth with a drilling rig that rotates a drill string with a bit
attached. After the hole is
drilled, sections of steel pipe (casing), slightly smaller in diameter than
the borehole, are placed
in the hole. Cement may be placed between the outside of the casing and the
borehole to provide
structural integrity and to isolate high pressure zones from each other and
from the surface. With
these zones safely isolated and the formation protected by the casing, the
well can be drilled
deeper, into potentially more unstable formations, with a smaller bit, and
also cased with a
smaller size casing. Typically wells have two to five sets of subsequently
smaller hole sizes
drilled inside one another, each cemented with casing.
[007] Oil recovery operations from conventional oil wells have been
traditionally subdivided
into three stages: primary, secondary, and tertiary. Primary production, the
first stage of
production, produces due to the natural drive mechanism existing in a
reservoir. These "Natural
lift" production methods that rely on the natural reservoir pressure to force
the oil to the surface
are usually sufficient for a while after reservoirs are first tapped. In some
reservoirs, such as in
the Middle East, the natural pressure is sufficient over a long time. The
natural pressure in many
reservoirs, however, eventually dissipates such that the oil must then be
pumped out using
"artificial lift" created by mechanical pumps powered by gas or electricity.
Over time, these
"primary" methods become less effective and "secondary" production methods may
be used.
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[008] The second stage of oil production, secondary recovery, is usually
implemented after
primary production has declined to unproductive levels, usually defined in
economic return
rather than absolute oil flow. Traditional secondary recovery processes are
water flooding,
pressure maintenance, and gas injection, although the term secondary recovery
is now almost
synonymous with water flooding. Tertiary recovery, the third stage of
production, commonly
referred to as enhanced oil recovery ("EOR") is implemented after water
flooding. Tertiary
processes use miscible and/or immiscible gases, polymers, chemicals, and
thermal energy to
displace additional oil after the secondary recovery process becomes
uneconomical.
[009] Enhanced oil recovery processes can be classified into four overall
categories: mobility
control, chemical, miscible, and thermal.
= Mobility-control processes, as the name implies, are those based
primarily on
maintaining a favorable mobility ratio. Examples of mobility control processes
are
thickening of water with polymers and reducing gas mobility with foams.
= Chemical processes are those in which certain chemicals, such as
surfactants or
alkaline agents, are injected to utilize interfacial tension reduction,
leading to
improved displacement of oil.
= In miscible processes, the objective is to inject fluids that are
directly miscible with
the oil or that generate miscibility in the reservoir through composition
alteration. The
most popular form of a miscible process is the injection of carbon dioxide.
= Thermal processes rely on the injection of thermal energy or the in-situ
generation of
heat to improve oil recovery by reducing the viscosity of oil.
[0010] In the United States, primary production methods account for less than
40% of the oil
produced on a daily basis, secondary methods account for about half, and
tertiary recovery the
remaining 10%.
[0011] Bituminous sands, colloquially known as oil sands or tar sands, are a
type of
unconventional petroleum deposit. The oil sands contain naturally occurring
mixtures of sand,
clay, water, and a dense and extremely viscous form of petroleum technically
referred to as
bitumen (or colloquially "tar" due to its similar appearance, odour, and
colour). These oil sands
reserves have only recently been considered as part of the world's oil
reserves, as higher oil
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prices and new technology enable them to be profitably extracted and upgraded
to usable
products. They are often referred to as unconventional oil or crude bitumen,
in order to
distinguish the bitumen extracted from oil sands from the free-flowing
hydrocarbon mixtures
known as crude oil
[0012] Many countries in the world have large deposits of oil sands, including
the United
States, Russia, and various countries in the Middle East. However, the world's
largest deposits
occur in two countries: Canada and Venezuela, each of which has oil sand
reserves
approximately equal to the world's total reserves of conventional crude oil.
As a result of the
development of Canadian oil sands reserves, 44% of Canadian oil production in
2007 was from
oil sands, with an additional 18% being heavy crude oil, while light oil and
condensate had
declined to 38% of the total.
[0013] Because growth of oil sands production has exceeded declines in
conventional crude oil
production, Canada has become the largest supplier of oil and refined products
to the United
States, ahead of Saudi Arabia and Mexico. Venezuelan production is also very
large, but due to
political problems within its national oil company, estimates of its
production data are not
reliable. Outside analysts believe Venezuela's oil production has declined in
recent years, though
there is much debate on whether this decline is depletion-related or not.
[0014] However, irrespective of such issues the oil sands may represent as
much as two-thirds of
the world's total "liquid" hydrocarbon resource, with at least 1.7 trillion
barrels ( 270x109m' ) in
the Canadian Athabasca Oil Sands alone assuming even only a 10% recovery rate.
In October
2009, the United States Geological Service updated the Orinoco oil sands
(Venezuela) mean
estimated recoverable value to 513 billion barrels (81.6x109m3) making it "one
of the world's
largest recoverable" oil deposits. Overall the Canadian and Venezuelan
deposits contain about
3.6 trillion barrels (570x109m3) of recoverable oil, compared to 1.75 trillion
barrels (
280x109 m3)of conventional oil worldwide, most of it in Saudi Arabia and other
Middle-Eastern
countries.
[0015] Because extra-heavy oil and bitumen flow very slowly, if at all, toward
producing wells
under normal reservoir conditions, the oil sands must be extracted by strip
mining and processed
or the oil made to flow into wells by in situ techniques, which reduce the
viscosity. Such in situ
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techniques include injecting steam, solvents, heating the deposit, and/or
injecting hot air into the
oil sands. These processes can use more water and require larger amounts of
energy than
conventional oil extraction, although many conventional oil fields also
require large amounts of
water and energy to achieve good rates of production. Accordingly, these oil
sand deposits were
previously considered unviable until the 1990s when substantial investment was
made into them
as oil prices increased to the point of economic viability as well as concerns
over security of
supply, long term global supply, etc.
[0016] Amongst the reasons for more water and energy of oil sand recovery
apart from the initial
energy expenditure in reducing viscosity is that the heavy crude feedstock
recovered requires
pre-processing before it is fit for conventional oil refineries. This pre-
processing is called
'upgrading', the key components of which are:
1. removal of water, sand, physical waste, and lighter products;
2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization
(HDS) and
hydrodenitrogenation (HDN); and
3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR).
[0017] As carbon rejection is very inefficient and wasteful in most cases,
catalytic hydrocracking
is preferred in most cases. All these processes take large amounts of energy
and water, while
emitting more carbon dioxide than conventional oil.
[0018] Amongst the category of known secondary production techniques the
injection of a fluid
(gas or liquid) into a formation through a vertical or horizontal injection
well to drive
hydrocarbons out through a vertical or horizontal production well. Steam is a
particular fluid that
has been used. Solvents and other fluids (e.g., water, carbon dioxide,
nitrogen, propane and
methane) have also been used. These fluids typically have been used in either
a continuous
injection and production process or a cyclic injection and production process.
The injected fluid
can provide a driving force to push hydrocarbons through the formation, or the
injected fluid can
enhance the mobility of the hydrocarbons (e.g., by reducing viscosity via
heating) thereby
facilitating the release of the more mobile hydrocarbons to a production
location. Recent
developments using horizontal wells have focused on utilizing gravity drainage
to achieve better
results. At some point in a process using separate injection and production
wells, the injected
fluid may migrate through the formation from the injection well to the
production well thereby
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"contaminating" the oil recovered in the sense that additional processing must
be applied before
the oil can be pre-processed for compatibility with convention oil refineries
working with the
light oil recovered from conventional oil well approaches..
[0019] Therefore, a secondary production technique injecting a selected fluid
and for producing
hydrocarbons should maximize production of the hydrocarbons with a minimum
production of
the injected fluid, see for example U.S. Patent 4,368,781. Accordingly, the
early breakthrough of
the injected fluid from an injection well to a production well and an
excessive rate of production
of the injected fluid is not desirable. See for example Joshi et al in
"Laboratory Studies of
Thermally Aided Gravity Drainage Using Horizontal Wells" (AOSTRA J. of
Research, pages
11-19, vol. 2, no. 1, 1985). It has also been disclosed that optimum
production from a horizontal
production well is limited by the critical velocity of the fluid through the
formation. This being
thought necessary to avoid so-called "fingering" of the injected fluid through
the formation, see
U.S. Patent 4,653,583, although in US Patent 4,257,650 it is disclosed that
"fingering" is not
critical in radial horizontal well production systems.
[0020] The foregoing disclosures have been within contexts referring to
various spatial
arrangements of injection and production wells, which can be classified as
follows: vertical
injection wells with vertical production wells, horizontal injection wells
with horizontal
production wells, and combinations of horizontal and vertical injection and
production wells.
Whilst embodiments of the invention described below can be employed in all of
these
configurations the dominant production methodology today relates to the
methods using
separate, discrete horizontal injection and production wells. This arises due
to the geological
features of oil sands wherein the oil bearing are typically thin but
distributed over a large area.
Amongst the earliest prior art for horizontal injection wells with horizontal
production well
arrangements are U.S. Patents 4,700,779; 4,385,662; and 4,510,997.
[0021] Within the initial deployments the parallel horizontal injection and
production wells
vertically were aligned a few meters apart as disclosed in the aforementioned
article by Joshi.
Associated articles include:
= Butler et al in "The gravity drainage of steam-heated heavy oil to
parallel horizontal
wells" (J. of Canadian Petroleum Technology, pages 90-96, 1981);
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= Butler in "Rise of interfering steam chambers" (J. of Canadian Petroleum
Technology,
pages 70-75, vol. 26, no. 3, 1986);
= Ferguson et at in "Steam-assisted gravity drainage model incorporating
energy recovery
from a cooling steam chamber" (J. of Canadian Petroleum Technology, pages 75-
83, vol.
27, no. 5, 1988);
= Butler et al in "Theoretical Estimation of Breakthrough Time and
Instantaneous Shape of
Steam Front During Vertical Steamflooding," (AOSTRA J. of Research, pages 359-
381,
vol. 5, no. 4, 1989); and
= Griffin et al in "Laboratory Studies of the Steam-Assisted Gravity
Drainage Process," (51h
Advances in Petroleum Recovery & Upgrading Technology Conference, June 1984,
Calgary, Alberta, Canada (session 1, paper 1).
[0022] Vertically aligned horizontal wells are also disclosed in U.S. Patents
4,577,691;
4,633,948; and 4,834,179. Staggered horizontal injection and production wells,
wherein the
injection and production wells are both laterally and vertically spaced from
each other, are
disclosed in Joshi in "A Review of Thermal Oil Recovery Using Horizontal
Wells" (In Situ, Vol.
11, pp211-259, 1987); Change et al in "Performance of Horizontal-Vertical Well
Combinations
for Steamflooding Bottom Water Formations," (CIM/SPE 90-86, Petroleum Society
of
CIM/Society of Petroleum Engineers) as well as US Patents 4,598,770 and
4,522,260.
[0023] Amongst other patents addressing such recovery processes are US Patents
5,456,315'
5,860,475; 6,158,510; 6,257,334; 7,069,990; 6,988,549; 7,556,099; 7,591,311
and US Patent
Applications 2006/0,207,799; 2008/0,073,079;
2010/0,163,229, 2009/0,020,335;
2008/0,087,422; 2009/0,255,661; 2009/0,260,878; 2009/0,260,878;
2008/0,289,822;
2009/0,044,940; 2009/0,288,827; and 2010/0,326,656. Additionally there are
literally hundreds
of patents relating to the steam generating apparatus, drilling techniques,
sensors, etc associated
with such production techniques as well as those addressing combustion
assisted gravity
drainage etc.
[0024] The first commercially applied process was cyclic steam stimulation,
commonly referred
to as "huff and puff", wherein steam is injected into the formation, commonly
at above fracture
pressure, through a usually vertical well for a period of time. The well is
then shut in for several
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months, referred to as the "soak" period, before being re-opened to produce
heated oil and steam
condensate until the production rate declines. The entire cycle is then
repeated and during the
course of the process an expanding "steam chamber" is gradually developed
where the oil has
drained from the void spaces of the chamber, been produced through the well
during the
production phase, and is replaced with steam. Newly injected steam moves
through the void
spaces of the hot chamber to its boundary, to supply heat to the cold oil at
the boundary.
[0025] However, there are problems associated with the cyclic process
including:
= fracturing tends to occur vertically along a direction dictated by the
tectonic regime present
in the formation;
= steam tends to preferentially move through the fractures and heat
outwardly therefrom so
that developed chamber tends to be relatively narrow;
= low efficiency with respect to steam utilization; and
= there are large bodies of unheated oil left in the zone extending between
adjacent wells
with their linearly extending steam chambers.
[0026] Accordingly, the cyclic process relatively low oil recovery. As such,
as described in
Canadian Patent 1,304,287, a continuous steam process has become dominant
approach, known
as steam-assisted gravity drainage ("SAGD"). The approach exploiting:
= a pair of coextensive horizontal wells, one above the other, located
close to the base of the
formation;
= the formation between the wells is heated by circulating steam through
each of the wells at
the same time to create a pair of "hot fingers";
= when the oil is sufficiently heated so that it may be displaced or driven
from one well to the
other, fluid communication between the wells is established and steam
circulation through
the wells is terminated;
= steam injection below the fracture pressure is initiated through the
upper well and the lower
well opened to produce draining liquid; and
= the production well is throttled to maintain steam trap conditions and to
keep the
temperature of the produced liquid at about 6-10 C below the saturation steam
temperature at the production well.
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[0027] This ensures a short column of liquid is maintained over the production
well, thereby
preventing steam from short-circuiting into the production well. As the steam
is injected, it rises
and contacts cold oil immediately above the upper injection well. The steam
gives up heat and
condenses; the oil absorbs heat and becomes mobile as its viscosity is
reduced. The condensate
and heated oil drain downwardly under the influence of gravity. The heat
exchange occurs at the
surface of an upwardly enlarging steam chamber extending up from the wells.
This chamber
being constituted of depleted, porous, permeable sand from which the oil has
largely drained and
been replaced by steam.
[0028] The steam chamber continues to expand upwardly and laterally until it
contacts the
overlying impermeable overburden and has an essentially triangular cross-
section. If two
laterally spaced pairs of wells undergoing SAGD are provided, their steam
chambers grow
laterally until they contact high in the reservoir. At this stage, further
steam injection is
terminated and production declines until the wells are abandoned. The SAGD
process is
characterized by several advantages, including relatively low pressure
injection so that fracturing
is not likely to occur, steam trap control minimizes short-circuiting of steam
into the production
well, and the SAGD steam chambers are broader than those developed by the
cyclic process.
[0029] As a result oil recovery is generally better and with reduced energy
consumption and
emissions of greenhouse gases. However, there are still limitations with the
SAGD process
which need addressing. These include the need to more quickly achieve
production from the
SAGD wells, the need to completely and evenly heat the formation between the
vertically spaced
wells to increase the immediate and overall oil recovery percentage, to reduce
the temperature of
the produced emulsion at the point of production in the heel of the producer
and thereby make
mechanical pumping operation more efficient; and provide efficient SAGD
operations over
deeper oil sand formations.
[0030] In SAGD the velocity of bitumen falling through a column of porous
media having equal
pressures at top and bottom can be calculated from Darcy's Law, see Equation
1.
k P g
T T q = 0 0 0 (1)
U 0
110
where 1(0 is the effective permeability to bitumen and go is the viscosity of
the bitumen. For
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Athabasca bitumen at about 200 C and using 5 as the value Darcy's effective
permeability, the
resulting velocity will be about 40 cm/day. Extending this to include a
pressure differential then
the equation for the flow velocity becomes that given by Equation 2.
k Pg k AP
OTT+ = 0 + 0
U 0
110
where AP is the pressure differential between the two well bores and L is the
interwell well bore
separation. For a typical interwell spacing this results in the value given in
Table 1 below.
AP (psia) koAlpoL koPog 1,u0 =Uoq U+
0 U0+ lUog
(cm/day) (cm/day) (cm/day)
0.00 0.000 39.4 39.4 1.00
0.01 0.046 39.4 39.5 1.00
0.10 0.427 39.4 39.9 1.01
1.00 4.410 39.4 43.8 1.11
10.00 44.200 39.4 83.6 2.12
50.00 220.8 39.4 260.0 6.60
Table 1: Increased Bitumen Velocity under Pressure Differential
[0031] It is evident from the data presented in Table 1 that a more efficient
and even heating of
the zone between the wells pairs will aid in initial start up as well as
overall performance of both
the injector well bore and the producer well bore. Considering the Athabasca
oil sands about 20
percent of the reserves are recoverable by surface mining where the overburden
is less than 75 m
(250 feet). It is the remaining 80 percent of the oil sands that are buried at
a depth of greater than
75 m where SAGD and other in-situ technologies apply.
[0032] Accordingly, the inventor has established a beneficially well pad array
design that may be
exploited to advance production from SAGD wells by increasing the total heated
area between
vertically spaced wells and provide SAGD operating over deeper oil sand
formations. All of the
prior art relating to SAGD suggests that at least one injection well be
positioned above at least on
production well so that the injected fluids in the upper well can flow by
gravity to the lower
production well.
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[0033] These horizontal SAGD well pairs generally extend for a substantial
horizontal distance
into the reservoir, upwards of 800 meters is not uncommon for the length of a
SAGD well. This
well arrangement and process creates a number of problems as the SAGD well
pair is generally
vertically spaced about 5-6 meters apart so that fluid communication can be
established in a
relatively short time frame, generally in 3-6 months. Very hot steam with a
temperature of 300
degrees Celsius is injected into the formation to heat the immobile oil. The
well pad arrangement
is such that both the injector wells and the producer wells are drilled and
completed from the
same pad, with one well positioned above the other. It is desirable to drill
as many well pairs as
possible from a single well pad for economical reasons so the ancillary
injection and production
equipment that is required can be easily tied into the completed wells.
[0034] The current SAGD well pair array results in extremely hot steam, gases
or fluids be
injected into the injection well which is located almost immediately above the
production well
and then for the production well to produce the heated emulsion. Anyone
skilled in the art can
contemplate that over the length of the injection well, the point of
injection, the heel, the heel
will always be the hottest point in the well bore and conversely the tip or
end of the well, the toe
of the injection well, will be the coolest point of the well bore. Similarly,
the same holds true for
the production well as the heated fluid must flow to the production point of
the well, which is
also located in the heel of the well. So in both cases the heel is the hottest
point in the well bores
and the toe is the coolest. This creates a myriad of problems as it is
desirable to heat the entire
injection well bore evenly without creating hot spots in either well.
[0035] SAGD is a continuous process that requires injection and production to
occur
simultaneously so while the very hot fluid is being injected approximate to
heel of the production
well, the production well must produce the very hot emulsion that is draining
into the production
well bore and accumulating at the heel of the production well bore. This
creates a very hot zone
around both well bore heels which prevents the desired result of even heating
of the entire
injection well bore while at the same time maintaining a very hot zone at the
heel of the
production well bore which makes it very difficult for mechanical pumping
operations to work
effectively due to the extreme heat of both the emulsion and the entire zone
around both well
bore heels. Ideally, it would be desirable to provide for a well pair
arrangement that would better
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take advantage of the inherent thermal properties of both the injection well
and the production
well.
SUMMARY OF THE INVENTION
[0036] It is the object of this invention is to mitigate the issues associated
with the production of
the heated emulsions by arranging the well pair array so that the well pairs
are still easily
positioned at the appropriate vertical separations as dictated by the
reservoir conditions, and
allowing for the completions and tie ins of all wells to the central surface
production facility
without placing the heel of the injection well above the heel of the
production well. This can be
done quite simply by drilling injection wells and production wells from the
same well pads but in
opposite directions to each other. For example at well pad number one the
injectors may run
south in the reservoir and the producers would then run north. These in fact
would not be well
pairs until the same drilling operations occurred at well pads number two and
three, where, for
better clarity all injectors would run south from each well pad and all
producers would run north
from each well pad. The end result is that each becomes a well pair but they
are now opposingly
aligned with the heel of one positioned over the toe of the other. Conversely,
and as a preferred
embodiment, each well pad would contain only producer wells and tie ins and
injector wells and
tie ins.
[0037] This could be done modularly so that each well pad is set up for each
single operation. In
this embodiment in one area of the reservoir one would have the producer
module which would
be linked to all the producers drilled from that well pad. On an opposing area
of the reservoir
would be the injector well module which would be linked to all the injector
wells drilled from
that well pad. This arrangement would facilitate tie ins to the surface
facility and reduce CAPEX
costs due to the easily repeatable modular set ups. If one were to drill in
multiple directions from
a producer well pad module then one would require at least one injector well
pad module per
each production well drilled direction so as to mate up each producer well
with a corresponding
injector well.
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[0038] This array creates beneficial results in that now the heat of the
injection which is greatest
at the heel of the injector, is now located proximate to the coldest point of
the producer, the toe
of the producer, so that thermally the hottest point of the array is now
located above the coldest
point of the producer. Once production has started and the heated emulsion is
now collecting at
the heel of the producer the producer heel becomes its hottest point which
will dramatically aid
in the heating of the coldest point of the injector well bore, the toe. The
end result is more
efficient use of the thermal properties of both well bores.
[0039] Another benefit to the above noted well arrangement is that now the
heel of the producer
will remain much cooler without having the heel of the injector directly above
it, which should
facilitate improved mechanical pumping operations due to the cooler
environment created by the
arrangement.
[0040] In accordance with an embodiment of the invention there is provided a
method
comprising:
drilling a first well within an oil bearing structure from one well pad;
drilling a second well within the oil bearing structure in predetermined
relationship with the first
well from a second well pad;
according to a schedule injecting a heated mobilizing fluid into at least one
of the first or second
wells under first predetermined conditions;
operating the wells as a SAGD well pair so that the lower of the two wells
extracts oil from the
oil bearing structure.
[0041] In accordance with an embodiment of the invention there is provided
drilling a first well within an oil bearing structure from one well pad;
drilling a second well within the oil bearing structure so that the heel of
the second well is
located proximate to the toe of the first well from a second well pad;
according to a schedule injecting a heated mobilizing fluid into the first and
second wells under
first predetermined conditions;
operating the wells as a SAGD well pair so that the lower of the two wells
extracts oil from the
oil bearing structure.
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[0042] Other aspects and features of the present invention will become
apparent to those
ordinarily skilled in the art upon review of the following description of
specific embodiments of
the invention in conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0043] Embodiments of the present invention will now be described, by way of
example only,
with reference to the attached Figures, wherein:
[0044] Figure lA depicts the geographical distribution of consumption
globally;
[0045] Figure 1B depicts the geographical distribution worldwide of oil
production;
[0046] Figure 1C depicts the geographical distribution worldwide of oil
reserves;
[0047] Figure 2 depicts a typical SAGD well pair orientation;
[0048] Figures 3A and 3B depict outflow control devices according to the prior
art of Forbes in
US Patent Application 2008/0,251,255 for injecting fluid into an oil bearing
structure;
[0049] Figure 4 depicts a SAGD process according to the prior art;
[0050] Figure 5 depicts a SAGD well pad;
[0051] Figure 6 depicts a typical modern SAGD well pair array;
[0052] Figure 7 depicts a well pad orientation and layout according to an
embodiment of the
invention;
[0053] Figure 8 is a table of typical SAGD operating parameters.
DETAILED DESCRIPTION
[0054] The present invention is directed to thermal oil recovery and more
specifically to
exploiting down hole thermal properties in oil recovery.
[0055] As discussed supra SAGD accordingly embodiments of the invention employ
an
injection well bore and a production well bore.
[0056] Now referring to Figure 4 there is depicted there are depicted SAGD
process cross-
section according to the prior art wherein a pair of wells are viewed in cross-
section according to
standard process. Accordingly in each case there are shown a pair of wells
420, consisting of an
upper steam injection well and lower production well. These are disposed into
the reservoir 410.
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CA 02931900 2016-06-02
This oil sand layer 410 being disposed beneath rock overburden 470 that
extends to the surface.
In the standard SAGD process both injection and production occur at
approximately the same
point in the well bore heel 430 and 440 resulting in cooler points radiating
outward from that
point until the toe 450 and 460 of the well is reached.
[0057] Now referring to Figure 5 there is indicated typical SAGD surface
equipment 530 for
injecting into injection wells 510 and producing from production wells 520 all
from a single well
pad.
[0058] Now referring to Figure 6 wherein groups of wells are disposed across
the oil sands. Each
group of wells each consisting of a vertically-spaced well pair comprising an
injector well and a
producer well pair 620.
[0059] The well configuration of each well pair 620 corresponds to a
conventional SAGD well
pair with multiple well pairs drilled from a single well pad 610.
[0060] Referring to Figure 7 the SAGD wells are orientated according to an
embodiment of the
invention wherein upper well 770 is depicted as substantially parallel with
each lower well 780.
However, it is understood variations may arise through the local geology and
topography of the
reservoir within which a plurality of wells are drilled. Lower well 780 is
defined to be adjacent
and associated with upper well 770 as a functional set. Additional upper and
lower wells can be
similarly disposed in the array.
[0061] The wells 770 and 780 are formed in a conventional manner using known
techniques for
drilling horizontal wells into a formation. The size and other characteristics
of the well and the
completion thereof are dependent upon the particular structure being drilled
as known in the art.
The upper horizontal wells 770 may be established near an upper boundary of
the formation in
which they are disposed, and the lower horizontal wells 780 may be disposed
towards a lower
boundary of the formation.
[0062] Each lower horizontal well 780 is vertically spaced a distance from its
respectively
associated upper horizontal wells 770 (e.g., lower well 780 relative to each
of upper wells 770)
for allowing fluid communication, and thus fluid drive to occur, between the
two respective
upper and lower wells. Preferably this vertical spacing is the maximum such
distance through the
implementation of the method according to embodiments of the present
invention.
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CA 02931900 2016-06-02
[0063] The present invention is not limited to any specific dimensions because
absolute spacing
distances depend upon the nature of the formation in which the wells are
formed as well as other
factors such as the specific gravity of the oil within the formation.
Accordingly, in initiating the
wells to production a fluid is flowed into the one or more upper wells 770 and
lower wells 780 in
a conventional manner, such as by injecting in a manner known in the art. The
fluid is one which
improves the ability of hydrocarbons to flow in the formation so that they
more readily flow both
in response to gravity and a driving force provided by the injected fluid.
Such improved mobility
can be by way of heating, wherein the injected fluid has a temperature greater
than the
temperature of hydrocarbons in the formation so that the fluid heats
hydrocarbons in the
formation.
[0064] A particularly suitable heated fluid is steam having any suitable
quality and additives as
needed.
[0065] As the fluid is being injected via surface equipment 750 and 760 into
both the lower
well(s) 780 and the upper well(s) 770 to increase the temperature in the
region, the first section,
the heel, of both the upper well 720 and lower well 710 are heated rapidly and
via convection
they also begin to heat the area around the toe 730 and 740 of each respective
well bore. As
injection continues both wells 770 and 780 linearly increase in temperature so
that as the heels
710 and 720 reach maximum temperature the excess heat is continually
transferred further and
further down the well bore until ideally there is now even heating of both
well bores along their
entire length allowing for faster SAGD start up with fewer localized hot spots
and more efficient
recovery rates. At that point lower well 780 is switched to production via
surface equipment 750.
[0066] Figure 8 depicts typical SAGD operating parameters as is known in the
prior art.
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