Note: Descriptions are shown in the official language in which they were submitted.
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OPERATING WELLS IN GROUPS IN SOLVENT-DOMINATED RECOVERY PROCESSES
FIELD OF THE INVENTION
[0001] The present invention relates generally to well operations in solvent-
dominated in situ hydrocarbon recovery processes.
BACKGROUND OF THE INVENTION
[0002] Solvent-dominated in situ oil recovery processes are those in which
chemical
solvents are used to reduce the viscosity of the in situ oil. A minority of
commercial viscous
oil recovery processes use solvents to reduce viscosity. Most commercial
recovery schemes
rely on thermal methods such as Cyclic Steam Stimulation (CSS, see, for
example, U.S.
Patent No. 4,280,559) and Steam-Assisted Gravity Drainage (SAGD, see, for
example U.S.
Patent No. 4,344,485) to reduce the viscosity of the in situ oil. As thermal
recovery
technology has matured, practioners have added chemical solvents, typically
hydrocarbons,
to the injected steam in order to obtain additional viscosity reduction.
Examples include
Liquid Addition to Steam For Enhancing Recovery (LASER, see, for example, U,S,
Patent
No. 6,708,759) and Steam And Vapor Extraction processes (SAVEX, see, for
example, U.S.
Patent No. 6,662,872). These processes use chemical solvents as an additive
within an
injection stream that is steam-dominated. Solvent-dominated recovery processes
are a
possible next step for viscous oil recovery technology. In these envisioned
processes,
chemical solvent is the principal component within the injected stream. Some
non-
commercial technology, such as Vapor Extraction (VAPEX, see, for example, R.
M. Butler &
I. J. Mokrys, J. of Canadian Petroleum Technology, Vol. 30, pp. 97-106) and
Cyclic Solvent-
Dominated Recovery Process (CSDRP, see, for example, Canadian Patent No.
2,349,234)
use injectants that may be 100%, or nearly all, chemical solvent.
[0003] Solvent-dominated processes are different from steam-dominated
processes
in several respects. In steam-dominated processes, viscous fingering does not
typically
occur. Heat transfer dominates over mass transfer, blunting viscous finger
formation. Other
differences include the phase of the injectant - always gaseous for steam-
dominated
processes and gaseous or liquid for solvent-dominated processes. Additionally,
solvent is,
by definition, at least partially miscible with oil, and steam is not. In
their totality, these
differences lead to fundamentally different challenges in well spacing,
operation, and
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orientation, primarily due to a desire to control viscous fingering in solvent-
dominated
processes.
[0004] At the present time, solvent-dominated recovery processes (SDRPs) are
rarely used to produce highly viscous oil. Highly viscous oils are produced
primarily using
thermal methods in which heat, typically in the form of steam, is added to the
reservoir.
Cyclic solvent-dominated recovery processes (CSDRPs) are a subset of SDRPs. A
CSDRP
is typically, but not necessarily, a non-thermal recovery method that uses a
solvent to
mobilize viscous oil by cycles of injection and production. Solvent-dominated
means that the
injectant comprises greater than 50% by mass of solvent or that greater than
50% of the
produced oil's viscosity reduction is obtained by chemical solvation rather
than by thermal
means. One possible laboratory method for roughly comparing the relative
contribution of
heat and dilution to the viscosity reduction obtained in a proposed oil
recovery process is to
compare the viscosity obtained by diluting an oil sample with a solvent to the
viscosity
reduction obtained by heating the sample.
[0005] In a CSDRP, a viscosity-reducing solvent is injected through a well
into a
subterranean viscous-oil reservoir, causing the pressure to increase. Next,
the pressure is
lowered and reduced-viscosity oil is produced to the surface through the same
well through
which the solvent was injected. Multiple cycles of injection and production
are used. In
some instances, a well may not undergo cycles of injection and production, but
only cycles of
injection or only cycles of production.
[0006] CSDRPs may be particularly attractive for thinner or lower-oil-
saturation
reservoirs. In such reservoirs, thermal methods utilizing heat to reduce
viscous oil viscosity
may be inefficient due to excessive heat loss to the overburden and/or
underburden and/or
reservoir with low oil content.
[0007] References describing specific CSDRPs include: Canadian Patent No.
2,349,234 (Lim et al.); G. B. Lim et al., "Three-dimensional Scaled Physical
Modeling of
Solvent Vapour Extraction of Cold Lake Bitumen", The Journal of Canadian
Petroleum
Technology, 35(4), pp. 32-40, April 1996; G. B. Lim et al., "Cyclic
Stimulation of Cold Lake
Oil Sand with Supercritical Ethane", SPE Paper 30298, 1995; US Patent No.
3,954,141
(Allen et al.); and M. Feali et al., "Feasibility Study of the Cyclic VAPEX
Process for Low
Permeable Carbonate Systems", International Petroleum Technology Conference
Paper
12833, 2008.
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[0008] The family of processes within the Lim et al. references describes
embodiments of a particular SDRP that is also a cyclic solvent-dominated
recovery process
(CSDRP). These processes relate to the recovery of heavy oil and bitumen from
subterranean reservoirs using cyclic injection of a solvent in the liquid
state which vaporizes
upon production. The family of processes within the Lim et al. references may
be referred to
as CSPTM processes.
[0009] Other descriptions of solvent-based processes are also disclosed in the
literature.
[0010] Allen et al. (U.S. Patent No. 3,954,141) disclose a multiple solvent
heavy oil
recovery method. They write (col.3, lines 49-51), "It is desirable that the
solvent mixture
enter the formation as a liquid." They go on to write (col. 4, lines 11-13),
"As the solvent
mixture is injected into the well it spreads radially outward from the
injection well and
dissolves into viscous petroleum." This description does not consider viscous
fingering.
Consequently, Allen et al. do not discuss ways to minimize the adverse effects
of viscous
fingering.
[0011] Upreti et. al. (Energy & Fuels 2007, 21, 1562-1574) wrote a review
article
discussing the current state of understanding of Vapor Extraction (VAPEX), by
far the most-
studied solvent-dominated viscous oil recovery process. In VAPEX (p. 1564), "A
vaporized
solvent is injected into the injection well at pressures slightly less than or
equal to the
saturation vapor pressure." Injection at "pressures slightly less than or
equal to the
saturation vapor pressure," avoids the high pressure and consequent steep
pressure
gradients that exacerbate viscous fingering. The authors discuss well
arrangement briefly
(p. 1564), "For many heavy oil and bitumen reservoirs, the use of horizontal
wells over short
distances is a preferred choice so as to avoid high injection pressures and
channeling of the
solvents." (see also Turta et al., J. Canadian Petroleum Technology, vol. 43,
pp. 29-37,
2004). Upreti concludes (pg. 1573) that more research is needed for VAPEX,
especially in
the areas of, "... solvent mixing and absorption and heavy oil and bitumen,
well
configurations, ...".
[0012] Additional patents that disclose methods for the recovery of viscous
oil using
solvent-dominated recovery processes include:
U.S. Patent No. 6,883,607 Nenniger et al;
U.S. Patent No. 6,318,464 Mokrys;
U.S. Patent No. 5,899,274 Frauenfeld et al.; and
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U.S. Patent No. 4,362,213 Tabor.
[0013] These patents do not detail the arrangement, orientation, and operation
of
wells to reduce viscous fingering.
[0014] The phenomenon of viscous fingering is discussed in, for example,
Cuthiell et.
al. 2003 (J. Canadian Petroleum Technology, vol. 42, pp. 41-49, 2003) and
Cuthiell et. al.
2006 (J. Canadian Petroleum Technology, vol. 45, pp. 29-39, 2006). In
particular, Cuthiell et.
aL 2006 describe the importance of viscous fingering for cyclic and non-cyclic
solvent-
dominated processes. Cuthiell et al. 2006 disclose (p. 29) that, "miscible
fingering is
suppressed by transverse dispersion and by gravity," however, Cuthiell et al.
2006 does not
discuss well orientation and layout.
[0015] Jorgensen (U.S. Patent No. 7,165,616) discloses a "Method of
controlling the
direction of propagation of injection fractures in permeable formations".
Jorgensen does not
discuss viscous fingering, but is instead concerned with the control of
fracturing (col. 1, lines
41-43), "... the present invention aims to enable control of the propagation
of such fracture in
such a manner that the fracture has a controlled course...". Therefore,
Jorgensen does not
disclose well arrangements and operations for controlling solvent fingering.
[00161 Therefore, there is a need for an improved well operation for solvent-
dominated recovery processes for controlling viscous fingering.
SUMMARY OF THE INVENTION
[0017] In one aspect, the present invention provides a method of recovering
hydrocarbons, for example viscous oil, from an underground reservoir using a
cyclic solvent-
dominated recovery process. A viscosity reducing solvent is injected into a
set of wells
completed in the reservoir. The solvent is allowed to mix with, and at least
partially dissolve
into, the oil. The pressure in the reservoir is then reduced to produce oil
and solvent. These
steps are repeated as required. The well operation is tailored to cyclic
solvent-dominated
recovery processes for managing viscous fingering and unfavorable producer to
injector
interactions. Generally, wells are operated as groups, with wells in the same
group operating
in-synch. Groups of wells may be separated by a buffer zone from other groups
of wells if
the two groups are operated out-of-synch.
[0018] In a first aspect, the present invention provides a method of operating
a cyclic
solvent-dominated process for recovering hydrocarbons from an underground
reservoir
through a set of wells divided into groups of wells, the method comprising:
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(a) initiating and subsequently halting injection, into one of the groups of
wells, of
an amount of a viscosity reducing solvent;
(b) initiating and subsequently halting production, from the one of the groups
of
wells, of at least a fraction of the solvent and the hydrocarbons from the
reservoir, and
(c) cyclically repeating steps (a) and (b) for the groups of wells;
wherein:
each of the groups comprises two or more wells and no well is common
between two groups; and
wells of the same group are operated substantially in-synch.
[0019] The following features may be present. The wells of the same group may
undergo opposite flow operation of injection or production for less than 10%
of fluid flow on a
mass basis, or less than 5%, or less than 1 %. For at least 80% of fluid flow
on a mass basis,
a single well of at least one group may undergo injection and production while
remaining
wells within the at least one group are idle. A single well of at least one of
group may
undergo injection and production while remaining wells within the at least one
group are idle.
The wells of the same group may undergo the same flow operation of injection
or production
for more than 80% of fluid flow on a mass basis, or more 90%, or more than
95%. More than
80% of the wells of the same group may undergo the same flow operation of
injection or
production for more than 80% of an operational time period. All wells of the
same group may
undergo the same flow operation of injection or production for more than 80%
of an
operational time period. Adjacent well groups may be operated substantially
out-of-synch.
Wells of adjacent well groups may undergo opposite flow operation of injection
or production
for more than 10% of fluid flow on a mass basis. Wells of adjacent well groups
may undergo
opposite flow operation of injection or production for more than 25% of fluid
flow on a mass
basis, or more than 50%, or more than 75%, or more than 90%. Immediately after
halting
injection of the solvent, at least 25 mass % of the injected solvent may be in
a liquid state in
the reservoir. At least 25 mass % of the solvent in step (a) may enter the
reservoir as a
liquid. At least 50 mass % of the solvent in step (a) may enter the reservoir
as a liquid. Each
well within the set of wells may be oriented within 30 of horizontal within
the underground
reservoir. Within the underground reservoir, the wells in the set may be
arranged within 20
of a common horizontal straight line. The single common straight line may be
within 20 of a
maximum horizontal stress direction within the reservoir. For at least 25% (or
at least 50%)
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of the time period between injecting and subsequently halting injection for a
group of wells,
an adjacent group of wells may have at least one well producing; and for at
least 25% (or at
least 50%) of the time period between producing and subsequently halting
producing for a
group of wells, an adjacent group of wells may have at least one well
injecting. The well
groups may be separated by buffer zones for limiting well-to-well interaction,
wherein buffer
zones contain no flowing wells. The buffer zones may constitute less than or
equal to one
third of a sum of an area of the groups, or equal to or less than 10% of a sum
of an area of
the groups. Two wells may be separated by an infill well used for increasing
hydrocarbon
production prior to and/or during operation. Two wells may be separated by an
infill well for
increasing reservoir pressure prior to and/or during operation, for limiting
well-to-well
interaction. Water may be injected into the infill well. At least certain
buffer zones may be
geological buffer zones. The geological buffer zones may be channel
boundaries. Each
group may comprise a single row of wells. The hydrocarbons may be a viscous
oil having an
in situ viscosity of greater than 10 cP at initial reservoir conditions. A
common wellbore may
be used for both the injection and the production. An idle period may exist
subsequent to
halting injection and prior to initiating production. The solvent may comprise
ethane,
propane, butane, pentane, carbon dioxide, or a combination thereof. The
solvent may
comprise greater than 50 mass % propane.
[0020] 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
[0021] Embodiments of the present invention will now be described, by way of
example only, with reference to the attached Figures, wherein:
Fig. 1a is an illustration of adequate field sweep in an inter-well region;
Fig. 1 b is an illustration of poor field sweep in an inter-well region due to
disproportionate injection in the heel of one well;
Fig. 1 c is an illustration of poor field sweep in an inter-well region due to
solvent channeling through a finger that connects two wells;
Fig. 2 is an illustration of an example of in-synch and out-of-synch flow
operations for two wells;
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Fig. 3 is an illustration of an example of a well arrangement in accordance
with
a disclosed embodiment;
Fig. 4 is an illustration of a well arrangement and operation in accordance
with
a disclosed embodiment;
Fig. 5 is an illustration of a well arrangement and operation;
Fig. 6 is another illustration of a well arrangement and operation;
Fig. 7 is still another illustration of a well arrangement and operation;
Fig. 8 is still another illustration of a well arrangement and operation;
Fig. 9a is an illustration of a well orientation with respect to a stress
field, in
accordance with a disclosed embodiment;
Fig. 9b is an illustration of the stresses on a lateral finger; and
Fig. 10 is still another illustration of a well arrangement and operation in
accordance with a disclosed embodiment.
DETAILED DESCRIPTION
[0022] The term "viscous oil" as used herein means a hydrocarbon, or mixture
of
hydrocarbons, that occurs naturally and that has a viscosity of at least 10 cP
(centipoise) at
initial reservoir conditions. Viscous oil includes oils generally defined as
"heavy oil" or
"bitumen". Bitumen is classified as an extra heavy oil, with an API gravity of
about 10 or
less, referring to its gravity as measured in degrees on the American
Petroleum Institute
(API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about
10 . The terms
viscous oil, heavy oil, and bitumen are used interchangeably herein since they
may be
extracted using similar processes.
[0023] In situ is a Latin phrase for "in the place" and, in the context of
hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example, in
situ temperature means the temperature within the reservoir. In another usage,
an in situ oil
recovery technique is one that recovers oil from a reservoir within the earth.
[0024] The term "formation" as used herein refers to a subterranean body of
rock that
is distinct and continuous. The terms "reservoir" and "formation" may be used
interchangeably.
[0025] During a SDRP, a reservoir accommodates the injected solvent and non-
solvent fluid by compressing the pore fluids and, more importantly in some
embodiments, by
dilating the reservoir pore space when sufficient injection pressure is
applied. Pore dilation is
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a particularly effective mechanism for permitting solvent to enter into
reservoirs filled with
viscous oils when the reservoir comprises largely unconsolidated sand grains.
Injected
solvent fingers into the oil sands and mixes with the viscous oil to yield a
reduced viscosity
mixture with significantly higher mobility than the native viscous oil.
Without intending to be
bound by theory, the primary mixing mechanism is thought to be dispersive
mixing, not
diffusion. Preferably, injected fluid in each cycle replaces the volume of
previously
recovered fluid and then adds sufficient additional fluid to contact
previously uncontacted
viscous oil. Preferably, the injected fluid comprises greater than 50% by mass
of solvent.
[0026] In the case of a CSDRP, on production, the pressure is reduced and the
solvent(s), non-solvent injectant, and viscous oil flow back to the same well
and are
produced to the surface. As the pressure in the reservoir falls, the produced
fluid rate
declines with time. Production of the solvent/viscous oil mixture and other
injectants may be
governed by any of the following mechanisms: gas drive via solvent
vaporization and native
gas exsolution, compaction drive as the reservoir dilation relaxes, fluid
expansion, and
gravity-driven flow. The relative importance of the mechanisms depends on
static properties
such as solvent properties, native GOR (Gas to Oil Ratio), fluid and rock
compressibility
characteristics, and reservoir depth, but also depends on operational
practices such as
solvent injection volume, producing pressure, and viscous oil recovery to-
date, among other
factors. In a SDRP that is not cyclic, production occurs through another well.
[0027] During an injection/production cycle, the volume of produced oil should
be
above a minimum threshold to economically justify continuing operations. In
addition to an
acceptably high production rate, the oil should also be recovered in an
efficient manner. One
measure of the efficiency of a CSDRP is the ratio of produced oil volume to
injected solvent
volume over a time interval, called the OISR (produced Oil to Injected Solvent
Ratio).
Typically, the time interval is one complete injection/production cycle.
Alternatively, the time
interval may be from the beginning of first injection to the present or some
other time interval.
When the ratio falls below a certain threshold, further solvent injection may
become
uneconomic, indicating the solvent should be injected into a different well
operating at a
higher OISR. The exact OISR threshold depends on the relative price of viscous
oil and
solvent, among other factors. If either the oil production rate or the OISR
becomes too low,
the CSDRP may be discontinued. Even if oil rates are high and the solvent use
is efficient, it
is also important to recover as much of the injected solvent as possible if it
has economic
value. The remaining solvent may be recovered by producing to a low pressure
to vaporize
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the solvent in the reservoir to aid its recovery. One measure of solvent
recovery is the
percentage of solvent recovered divided by the total injected. In addition,
rather than
abandoning the well, another recovery process may be initiated. To maximize
the economic
return of a producing oil well, it is desirable to maintain an economic oil
production rate and
OISR as long as possible and then recover as much of the solvent as possible.
[0028] The OISR is one measure of solvent efficiency. Those skilled in the art
will
recognize that there are a multitude of other measures of solvent efficiency,
such as the
inverse of the OISR, or measures of solvent efficiency on a temporal basis
that is different
from the temporal basis discussed in this disclosure. Solvent recovery
percentage is just one
measure of solvent recovery. Those skilled in the art will recognize that
there are many other
measures of solvent recovery, such as the percentage loss, volume of
unrecovered solvent
per volume of recovered oil, or its inverse, the volume of produced oil to
volume of lost
solvent ratio (OLSR).
[0029] Solvent composition
[0030] The solvent may be a light, but condensable, hydrocarbon or mixture of
hydrocarbons comprising ethane, propane, or butane. Additional injectants may
include
CO2, natural gas, C3+ hydrocarbons, ketones, and alcohols. Non-solvent co-
injectants may
include steam, hot water, or hydrate inhibitors. Viscosifiers may be useful in
adjusting
solvent viscosity to reach desired injection pressures at available pump rates
and may
include diesel, viscous oil, bitumen, or diluent. Viscosifiers may also act as
solvents and
therefore may provide flow assurance near the wellbore and in the surface
facilities in the
event of asphaltene precipitation or solvent vaporization during shut-in
periods. Carbon
dioxide or hydrocarbon mixtures comprising carbon dioxide may also be
desirable to use as
a solvent.
[0031] In one embodiment, the solvent comprises greater than 50% C2-C5
hydrocarbons on a mass basis. In one embodiment, the solvent is primarily
propane,
optionally with diluent when it is desirable to adjust the properties of the
injectant to improve
performance. Alternatively, wells may be subjected to compositions other than
these main
solvents to improve well pattern performance, for example CO2 flooding of a
mature
operation.
[0032] Phase of injected solvent
[0033] In one embodiment, the solvent is injected into the well at a pressure
in the
underground reservoir above a liquid/vapor phase change pressure such that at
least 25
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mass % of the solvent enters the reservoir in the liquid phase. Alternatively,
at least 50, 70,
or even 90 mass % of the solvent may enter the reservoir in the liquid phase.
Injection as a
liquid may be preferred for achieving high pressures because pore dilation at
high pressures
is thought to be a particularly effective mechanism for permitting solvent to
enter into
reservoirs filled with viscous oils when the reservoir comprises largely
unconsolidated sand
grains. Injection as a liquid also may allow higher overall injection rates
than injection as a
gas.
[0034] In an alternative embodiment, the solvent volume is injected into the
well at
rates and pressures such that immediately after halting injection into the
injection well at
least 25 mass % of the injected solvent is in a liquid state in the
underground reservoir.
Injection as a vapor may be preferred in order to enable more uniform solvent
distribution
along a horizontal well. Depending on the pressure of the reservoir, it may be
desirable to
significantly heat the solvent in order to inject it as a vapor. Heating of
injected vapor or
liquid solvent may enhance production through mechanisms described by "Boberg,
T.C. and
Lantz, R.B., "Calculation of the production of a thermally stimulated well",
JPT, 1613-1623,
Dec. 1966. Towards the end of the injection cycle, a portion of the injected
solvent, perhaps
25% or more, may become a liquid as pressure rises. Because no special effort
is made to
maintain the injection pressure at the saturation conditions of the solvent,
liquefaction would
occur through pressurization, not condensation. Downhole pressure gauges
and/or reservoir
simulation may be used to estimate the phase of the solvent and other co-
injectants at
downhole conditions and in the reservoir. A reservoir simulation is carried
out using a
reservoir simulator, a software program for mathematically modeling the phase
and flow
behavior of fluids in an underground reservoir. Those skilled in the art
understand how to
use a reservoir simulator to determine if 25% of the injectant would be in the
liquid phase
immediately after halting injection. Those skilled in the art may rely on
measurements
recorded using a downhole pressure gauge in order to increase the accuracy of
a reservoir
simulator. Alternatively, the downhole pressure gauge measurements may be used
to
directly make the determination without the use of reservoir simulation.
[0035] Although preferably a SDRP is predominantly a non-thermal process in
that
heat is not used to reduce the viscosity of the viscous oil, the use of heat
is not excluded.
Heating may be beneficial to improve performance or start-up. For start-up,
low-level
heating (for example, less than 100 C) may be appropriate. Low-level heating
of the solvent
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prior to injection may also be performed to prevent hydrate formation in
tubulars and in the
reservoir. Heating to higher temperatures may benefit recovery.
[0036] Synchronization
[0037] Generally, an aspect of the present invention provides a method for
recovering hydrocarbons, for instance viscous oil, from an underground
reservoir, using a
solvent-dominated recovery process. Whether cyclic or non-cyclic, a viscosity
reducing
solvent is injected and oil and solvent are produced. Unlike steam-dominated
recovery
processes, solvent-dominated recovery processes cause viscous fingering which
should be
controlled. By operating wells within a group in-synch and operating wells in
adjacent groups
out-of-synch, viscous fingering can be controlled.
[0038] Much of the research literature and patents that discuss viscous oil
recovery
processes focus on idealized processes as if they would be carried out for a
single well. For
steam-dominated recovery schemes, the viscous oil recovery process appropriate
for a
single well is often the recovery process appropriate for a multi-well
development because
well-well interactions are not strongly affected by well-to-well viscous
fingering and recovery
of the injectant (water) is not required. However, for solvent-dominated
recovery schemes,
the desired process for a multiwell development is different than for single
well development.
As solvent is injected into the formation, solvent fingers form which can,
relatively early in the
life of the field, stretch out 100 meters or more and connect up with other
wells. If the well
injection and production cycles are not sufficiently synchronized, solvent may
rapidly flow
from one well to the other when one is on production and the other is on
injection and have a
negative impact on solvent efficiency and consequent oil recovery. Loss of
solvent is also a
risk that should be mitigated.
[0039] Figure 1 shows how viscous fingering can lead to poor field sweep in a
solvent-dominated process. The figure is a series of top views of a subsurface
region of a
reservoir penetrated by two horizontal wells. The left portion of Figs. 1 a,
1b, and 1c show the
inter-well region at the end of an injection cycle and the right portion of
Figs. 1 a, 1 b, and 1 c
show the inter-well region at the end of a production cycle. Each of the three
Figures
contains one or two wells (100) undergoing synchronized flow operations, a
previously swept
portion of the reservoir (101), a region invaded by solvent during the current
cycle (102), and
the remaining unswept viscous oil (103). Fig. 1a shows that adequate solvent
conformance
is obtained if the wells are synchronized and there is no poorly managed
fingering. All of the
fingers are of roughly equal size. As a result, although some residual oil
(103) may remain,
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the sweep is adequate. Fig. 1 b shows the resulting field sweep if there is
uncontrolled
fingering close to the heel (top portion in figure) of the well. The amount of
unswept oil (103)
may be substantial in this case. Fig. Ic shows the resulting field sweep if
there is
uncontrolled fingering at some point along the well, perhaps due to
asynchronous operation
or the presence of a high permeability streak. Again, the amount of unswept
oil (103) may
be substantial in this case. One of the two wells is colored white (well 104)
to indicate that it
has been operated out-of-synch with well 100.
[0040] The term "in-synch" means that wells, or groups of wells, are
undergoing the
same flow operation, where a flow operation is injection, production, soaking,
or idling.
Conversely, the term "out-of-synch" means that two wells or groups of wells
are not
undergoing the same flow operation at the same time. Figure 2 illustrates the
concept of
synchronized vs. unsynchronized operations using two wells and three flow
operations. The
flow operations are producing (200), injecting (201), and soaking (or idle)
(202). If the two
wells are undergoing the same flow operation they are said to be in-synch
(203). If they are
not undergoing the same flow operation they are out-of-synch (204).
[0041] Injection is the process of flowing fluid from the surface towards the
reservoir.
Production is the process of flowing fluid from the reservoir towards the
surface. Idling is the
process of not flowing a well, and soaking is a special case of idling where a
well idles after it
has recently undergone injection.
[0042] Injection and production are considered to be opposite flow operations.
Injection and soaking (or idling) are considered to be different, but not
opposite, flow
operations. Likewise, production and soaking (or idling) are considered to be
different, but
not opposite, flow operations. This distinction is important since opposite
flow operations of
nearby wells can significantly contribute to undesirable channeling.
[0043] In addition to describing whether wells are in-synch or out-of-synch at
a given
time, we can say that wells are "substantially in-synch", if they are
undergoing the same flow
operation of injection or production for more than 80% of fluid flow on a mass
basis. Fluid
flow means the amount of fluid injected and produced over the wells of
interest. For
example, if during an operational period there is a group of three wells of
which two are
injecting and one is producing, the wells are substantially in-synch during
the operational
time period if the mass of fluid injected divided by the sum of the mass of
fluid injected and
produced is greater than 80%. Even though the producing well is out-of-sync
for all of the
time period, because the producing well flows at a flow rate that is low
compared to the
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CA 02703319 2010-05-05
injecting wells, the interaction is not particularly unfavorable. In
alternative embodiments,
this value of 80% becomes 90%, or 95%.
[0044] Wells are also "substantially in-synch" if they are undergoing opposite
flow
operations for less than 10% of fluid flow on a mass basis. For example, if
during an
operational time period there is a group of four wells of which two remain
idle during the time
period, one injects for a time and produces for a time, and another produces
for the entire
time period, the wells are substantially in-synch during the operational time
if the mass of
fluid that flowed while the wells had opposite flow behavior divided by the
total mass of fluid
that flowed during the entire time period is less than 10%. In alternative
embodiments, this
value of 10% becomes 5%, or 1%. Wells are "substantially in-synch" if either
of the above
two criteria is met, or if both of the above two criteria are met.
[0045] While it is preferred that every well of a group undergo the same flow
operation of injection or production for more than 80% of the time, it may be
acceptable to
have, say, one or two of wells in the group undergoing different, and even
opposite, flow
operations provided that the remaining wells maintain even higher levels of
synchronization,
such as being synchronized for more than 90%, or more than 95% of the time.
[0046] The special case of a single well within a group undergoing injection
or
production while all other wells in the group are idle is also considered to
be "substantially in-
synch" because for the duration of injection or production there is not an
opposite flow
behavior occurring within the group. In one embodiment, for at least 80% of
fluid flow on a
mass basis, a single well within at least one group undergoes injection and
production while
the remaining wells within the at least one group are idle.
[0047] Wells are "substantially out-of-synch" if more than 10% of fluid flow
on a mass
basis occurs during opposite flow operation of injection or production. In
alternative
embodiments, this value of 10% becomes 25%, 50%, 75%, or 90%. Adjacent well
groups
are "substantially out-of-synch" if wells of adjacent well groups undergo
opposite flow
operation of injection or production for more than 10% of fluid flow on a mass
basis. In
alternative embodiments, this value of 10% becomes 25%, 50%, 75%, or 90%.
[0048] While "substantially in-synch" and "substantially out-of-synch" have
been
defined using fluid flow on a mass basis, one way to achieve this is by using
time
synchronization. For example, during "substantially in-synch" operation, wells
within a group
can undergo the same flow operation of injection or production for more than
80%, more than
90%, or more than 95% of an operational time, and/or wells within a group can
undergo
-13-
CA 02703319 2010-05-05
opposite flow operations of injection or production for less than 10%, less
than 5%, or less
than 1% of an operational time. Likewise, during "substantially out-of-synch"
operation, wells
of adjacent groups can undergo opposite flow operation of injection or
production for more
than 10%, more than 25%, more than 50%, more than 75%, or more than 90% of an
operational time. Time synchronization is a convenient, but not essential, way
to achieve
mass flow synchronization and therefore in the discussion that follows most of
the discussion
relates to time synchronization.
[0049] Prior descriptions of CSDRPs have not addressed how to operate a
multiwell
application. Furthermore, descriptions of solvent-dominated processes other
than CSDRPs
have also not described how to space, arrange, and orient wells undergoing
solvent injection.
[0050] Well orientation is notable because two nearby wells can experience
injector-
to-producer channeling of injected solvent if they are operated out-of-synch.
Channeling is a
fluid flow phenomenon in which fluid flowing from one point to another
strongly prefers to flow
along a particular route. In an oil recovery process, channeling may be
detrimental because
it prevents the injectant from flowing through and consequently sweeping oil
from a large
area of the reservoir. Even though injected solvent and injected steam both
have adverse
mobility ratios when injected into highly viscous oil, the channeling effect
is particularly acute
in solvent-dominated processes, more so than in steam-based processes, and
more so than
is generally appreciated by those skilled in the art.
[0051] Viscous fingers typically follow pressure gradients, moving from
regions of
relatively higher to relatively lower pressure. If neighboring wells inject
simultaneously, and
at about the same pressure, then there is no pressure gradient to drive flow
from one well to
another. Therefore, one channeling minimization strategy is to have all the
wells in the field
synchronized. Although effective at maximizing solvent efficiency and field
sweep, this
strategy may be impractical for several reasons. First, solvent is preferably
supplied to the
field at a relatively constant rate to minimize transportation cost. Second,
various wells will
perform differently due to geologic and other heterogeneities.
[0052] Several approaches to minimize channeling and therefore improve field
sweep
are discussed herein. None have the drawback of full synchronization across
the field. All
variants may be combined with the principal approach. The approaches are:
1. Principal approach: Division of a set of wells into groups using buffer
zones with
operational synchronization within each group (but not between groups);
2. Reduce buffer size and operate neighboring groups more nearly in-synch;
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CA 02703319 2010-05-05
3. Regardless of grouping strategy, orient wells with regard to geological
considerations;
4. Create artificial buffers using pressure maintenance wells;
5. Allow individual wells within a group to idle or soak.
Divide up the wells into -groups and synchronize the wells within a group
[0053] The principal approach is to divide up the wells into groups and
synchronize
the wells within a group and offset the synchronization with other groups to
increase the
uniformity of solvent demand. These groups can be largely isolated from each
other by
having undeveloped buffer zones between the groups. For instance, these buffer
zones may
be 200 meters or more wide to largely ensure isolation. The value "200 meters"
is provided
merely by way of example and the size of suitable buffer zones will depend on
certain
factors, such as geologic factors and injection rates.
[0054] An example of a group-based well arrangement compatible with
synchronized
operations is shown in Fig. 3. The illustration is a top view perspective of
the subsurface
region comprising the horizontal wells (301). The well length (302) is shown.
In Fig. 3, four
wells are shown in one group (304), although the groups could comprise as few
as two wells
or more than four wells. The group of wells (304) is enclosed by a thin, black
line. The wells
within the group are separated from one another by some distance, termed the
"well spacing"
(303). The group of four wells is part of a field development which includes
many groups.
Together the groups are referred to as a "set". The "set" does not necessarily
include all
wells in a particular operation. A portion of three neighboring groups (305,
306, and 307) is
shown in Fig. 3, but the set could comprise more groups. For the purposes of
associating a
reservoir region with a group of wells, a dotted line (300) has been drawn to
indicate the
reservoir region that may reasonably be expected to contain injected solvent
associated with
the group of wells, and is referred to herein as a "block boundary". The wells
within a block
boundary are not necessarily drilled from the same well pad. The groups are
separated by
separation distances, a side-to-side separation distance separating groups
along the length
of the wells, and an end-to-end separation distance, separating groups at the
toe and heel
portions of the well. The double-ended arrow 308 indicates the length of the
side-to-side
separation distance and double-ended arrow 309 indicates the length of the end-
to-end
separation distance. If the separations are large enough, a buffer zone is
created that
contains a reservoir region that remains uninvaded by solvent. The width of
the side-to-side
-15-
CA 02703319 2010-05-05
buffer zone is indicated by the double ended arrow 310 and the end-to-end
buffer zone 313.
During the course of operation, solvent (filling dotted area 311) may invade a
portion of or the
entire region bounded by the block boundary. The reservoir region outside the
block
boundary is the buffer zone. An alternate way to define the width of the side-
to-side buffer
zone is to subtract the well spacing (303) from the side-to-side separation
distance (308).
The areas that are uninvaded by solvent are not denoted with any special
pattern and are left
as whitespace (312). In subsequent figures, both side-to-side and end-to-end
buffer zones
may be referred to collectively.
[0055] Fig. 4 shows a well arrangement and operation according to one
embodiment.
The arrangement of wells in Fig.4 is similar to the arrangement in Fig.3 and
includes
bounded groups of horizontal wells of some length separated by buffers. For
brevity and
clarity, labels are not affixed to all components of Fig 4. In Fig. 4, the
wells are grouped into
groups of 10 wells each. Of course, the value "10 wells" is merely provided by
way of
example. Groups may be as small as a well pair (2 wells) or as large as the
solvent supply
allows, for example, up to about 16. Wells within a given group of wells are
synchronized or
nearly so, preferably in-synch for more than 80%, more than 90%, or more than
95% of the
time, or alternatively where one well within a group is not producing while
another well in the
group is injecting. Wells within a group may be unsynchronized for short
periods of time of
up to perhaps a few weeks, but it is preferred to operate synchronously during
most of the
operational life of the wells, which my be a period of years. Fig. 4 shows 10
wells (401 a) of
group 401 and 10 wells (402a) of group 402. The 10 wells (401a) within one
group (401) are
synchronized with each other or nearly so. All ten wells within the group have
the same
shading (whitespace as fill). The black-colored wells (402a) in neighboring
group 402 are
"out-of-synch" with the wells (401 a) but are in-synch within their own group
(402). The wells
(403a, 404a) of the other two groups (403, 404) are in-synch with the wells of
group 402 and
out-of-synch with the wells (401 a) of group 401. The groups are separated by
the side-to-
side (405) and end-to-end (406) separation distances. Research using reservoir
simulation
indicates that side-to-side and end-to-end buffer zones of widths 410 and 413,
respectively,
may prevent undue well-to-well interaction (i.e. channeling), should the wells
in a neighboring
group be out-of-synch.
[0056] Though the buffer zones are desirable to prevent undue well
interaction, the
prevention or reduction of well interaction comes at a cost because oil
recovery is higher
inside the block boundary (400) than in the buffer region. Recovery is highest
in the region
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CA 02703319 2010-05-05
between wells of the same group. The buffer region, by design, is entirely or
mostly not
invaded by solvent (412). In order to maximize overall field recovery, it is
desirable that the
area of the block (enclosed by the dotted line 400) be substantially larger
than the area of the
neighboring buffer zones. A larger number of wells per group and long well
length aid in
increasing the area that comprises a block. It is preferred that buffers
comprise no more
than one third, or no more than 10%, of the combined area of a block and its
neighboring
buffer zones. One way to estimate the fraction of the area occupied by the
buffers is to a)
multiply the length of each side of the four-sided block boundary (400) by the
width of the
buffer zone on that side (for example, lengths 413 and 410) b) divide the area
by 2 to
account for it being shared between two groups c) add the resulting areas for
all four sides
together to get the total buffer zone area and then d) divide the total buffer
zone area by the
sum of the total buffer zone area and the area enclosed by the block boundary.
Those
skilled in the art will recognize alternate ways to estimate a fraction of
area occupied by the
buffers. There is a balance between obtaining synchronization over a large
area and
increasing net solvent demand uniformity. The arrangement of Fig. 4 shows one
way to
obtain a preferred balance. If there is no neighboring group (there are no
neighboring wells)
or the neighboring groups are kept somewhat synchronized, the size of the
illustrated side-
to-side separation could be reduced to the interwell spacing without
significant negative
impact to field recovery.
[0057] While well groups are often shown and discussed herein to be separated
by
buffer zones, this is not essential. For instance, two well groups may be
separated by one or
more wells undergoing a different, but not opposite, flow behavior for a
substantial portion of
the operation. Injection and production are defined as opposite flow behavior.
Flow
behaviors that are not opposite are 1) idling with any other of the flow
behaviors or 2)
soaking with any of the other flow behaviors. Effectively, wells undergoing
idling or soaking
act as buffers. It is acceptable to soak or idle in conjunction with injection
and production.
[0058] Selection of the block size is important for reducing solvent storage,
fully
utilizing a constant solvent supply, and maintaining high field sweep. The
block size
depends on the number of wells, their length, the well spacing, and the length
of the buffers
that separate wells. In synchronized operation, the number of blocks is
controlled by the
ratio of producers to injectors. The number of blocks is equal to the number
of groups.
[0059] Wells operated within a group are expected to interact and within the
group, if
the wells are in-synch or nearly in-synch, high recovery can be achieved.
Buffers need to be
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CA 02703319 2010-05-05
sized so that wells from different groups will not significantly interact. The
average number of
wells on production per well on injection during a period of field operation
depends on the
solvent recovery factor (SR) and the ratio of the average injection (Q;,,;) to
average production
rates (Qprod) over the operational period,
number of producers per injector = SR(Q;nj/Qprod)=
[0060] For example, if average injection rate over several injection phases is
500m3
solvent/day/well, average solvent production rate over several production
phases is
100m3/day/well, average solvent recovery over several cycles is 80%, and wells
are not
soaked, then there should be 4 wells (0.80 x 500/100) on production for every
well on
injection.
[0061] In order to maintain synchronization and a high block area to buffer
area ratio,
4-10 wells is a good size for a group of synchronized wells. Therefore, using
a 4:1
producer/injector ratio, a field of 30 wells might be designed with 5 groups
of 6 wells each
such that 4 groups of wells (24 wells total) are on production and one group
(6 wells total) is
on injection. The group of 6 wells on injection will require 2400 m3/day (24
wells x 100
m3/day/well) of recycled solvent plus 600m3/day of makeup solvent volume.
[0062] Preferred arrangements and/or operations can be further defined by
understanding what is not preferred. Figs. 5 to 8 all show arrangements and/or
operations
that are not preferred. For brevity and clarity, labels are not affixed to all
elements of Figs. 5
to 8. Figs. 5 to 8 contain many of the same elements (for example, wells,
block boundaries,
and buffers) as Figs. 3 and 4. Where important for discussion, individual
elements of the
Figs. are labeled.
[0063] Fig. 5 shows a well arrangement and operation with buffers that is
sufficient
for isolating synchronized groups, but the groups are too small, and
consequently the total
area of the block as defined by the block boundary (500) is small in
comparison to the area
of the buffers. The in-synch well group (501) and neighboring well group (502)
that is out-of-
synch with 501 (but in-synch within 502) are shown. The recovery efficiency
from such an
arrangement and operation will be less than that shown in Fig. 4.
[0064] Fig. 6 shows an inefficient use of buffer zones. The wells (600a, 601
a) of two
neighboring groups (600 and 601) are synchronized both within the groups and
between the
groups. If the wells are being operated such that two neighboring groups are
always or
nearly synchronized, there is no need for a sizeable buffer (606) to separate
them. The wells
of groups 602 and 603 are synchronized with each other, but not with groups
600 and 601.
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CA 02703319 2010-05-05
The buffer separating group 600 from 601 and separating 602 from 603 is not
needed. Its
presence lowers field sweep.
[0065] Fig. 7 shows poor operation of a well group (701). The wells within the
group
(701) are not fully synchronized. Injector wells (701a) are out-of-synch with
producer wells
(701 b) within the same group. As a result, channeling of solvent from the
injectors to the
producers may occur, as indicated by presence of solvent (711) fingering. It
is highly
undesirable to be injecting and producing from wells within the same group. In
the remaining
three synchronized groups in the figure, no channeling is observed.
[0066] Fig. 8 shows an operation of a group (801) that is less efficient.
Wells within
the same group (801) are immediately adjacent but not synchronized. Wells (801
a) are
injecting while the neighboring wells (801 b) within the group are producing
Such wells
should be separated by a buffer or kept more nearly in-synch. Some channeling
of solvent
(811) is observed from the injectors (801 a) to the producers (801 b). Neither
the injection
(801 a) wells or the producing wells (801 b) are in-synch with the unlabeled
wells in Fig 8.
Reduce buffer size and operate neighboring groups more nearly in-synch
[0067] Alternatively, the buffer zones may be significantly reduced in width
if
neighboring groups are only slightly out-of-synch. In this concept, the total
portion of time in
which two neighboring groups are in-synch is substantial, that is, more than
50% of the time
(or more than 30%, more than 40%, more than 60%, or more than 70% of the
time). These
values could equally be applied on a fluid flow mass basis. Two wells or two
groups are said
to be "in-synch" if they are undergoing the same flow operation, where a flow
operation is
injection, production, soaking, or idling. A particularly advantageous way to
define well
groups is to define a row of horizontal wells as a group. Fig. 2 illustrates
the concept of
synchronization for individual wells, but the concept is also applicable to
groups of wells.
[0068] This is somewhat similar to the "megarow strategy" employed for cyclic
steam
stimulation (CSS) at Cold Lake, Alberta, Canada (see Society of Petroleum
Engineering
(SPE), Reference No. 25794). However, this approach still leads to significant
communication between groups of wells and inefficient use of steam (or
solvent) late in the
field life. The "megarow strategy" as used for CSS is not directly
translatable to CSDRPs
since it is for rows of vertical wells and the preferred mode of operation for
CSDRP wells
uses relatively horizontal wells.
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CA 02703319 2010-05-05
Orient wells with respect to geologic considerations
[0069] The geological stress state can impact the growth of the viscous
fingers that
may connect wells. To retard lateral finger growth, wells may be oriented
along the maximum
horizontal stress direction within the reservoir. As a result, the fluid
pressure within a lateral
finger must work against the maximum horizontal stress (and the overburden
stress) to open
up more void space to further allow finger growth. Thus, the greater the
horizontal stress,
the more finger growth is retarded since the amount of energy expenditure
required to grow a
finger is greater. In contrast, if the well orientation is opposite to the
preferred orientation,
namely, aligned along the minimum horizontal stress direction, the fluid
pressure within
lateral fingers is working against the minimum horizontal stress and the
overburden stress to
open up more void space. By comparing these two well orientations, one can see
that the
preferred well orientation results in larger resistance for opening up the
void space in lateral
fingers, and hence delaying the communication among well groups.
[0070] Figs. 9a and 9b show the orientation of a well (90) in relation to the
geologic
stress state. The orientation retards finger growth, and, when combined with
the well
arrangement shown in Figure 4, is a desired well layout for solvent-dominated
processes
with viscous fingering. In Figs. 9a and 9b, Shmax, and Shmin are the maximum
(91) and
minimum stress (92), respectively. A cross-sectional view of the lateral
finger is shown in
Figure 9b. It shows that the stresses applied on the lateral finger (93) are
Shmax and the
overburden stress (94). This orientation with respect to the stress states is
the preferred in
situ stress combination and will result in maximum compressive loading to
suppress finger
growth. The solvent chamber (95) is also shown and denoted with a diagonal
pattern.
Create artificial buffers using pressure maintenance wells
[0071] Channeling may be minimized by separating out-of-synch well operations
with
buffer zones, synchronizing well operations, and/or careful placement with
respect to the
geological stress state. A further means of minimizing channeling, containing
the injected
solvent within a pattern of wells, and thereby improving field sweep is
targeted conditioning
of the reservoir stress state using pressure maintenance injection wells. This
is
accomplished by increasing reservoir pressure prior to and/or during
operations where
injection and production take place in adjacent wells.
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CA 02703319 2010-05-05
[0072] Fig. 1 Oa shows the channeling that may occur in the absence of a
pressure
buffer should two wells be undergoing opposite flow operations, namely one
well on injection
and another on production, while being separated by an insufficient buffer
zone. The solvent
(1011) fingers from the injector (1001) to the producer (1002). Fig. 1 Ob
illustrates the use of
a pressure maintenance injector well to minimize channeling within a group of
five wells. Fig.
1 Ob shows a well arrangement that is the same as Fig. 1 Oa, except that an
additional injector
well (1004) is present. In the Fig. 1 Ob the well is shown as a new well,
which may be
purposefully drilled, in this case midway between the two groups, but that
need not be the
case. The Fig. 1 Ob also shows the injectant (1006), typically water.
Alternatively, a
particular well(s) within the existing group may be specifically designated to
provide a
pressure buffer. The purpose of the pressure maintenance wells is to condition
reservoir
stress. The fluid injection causes a localized increase in reservoir pressure.
The pressure
increase results in increased compressive loading of the formation, thereby
suppressing
finger growth from adjacent solvent injection wells. The buffer well injection
pressure should
not exceed the fracture pressure of the formation. The use of a non-solvent
(for example,
water) for injection minimizes pressure leak off to the formation when the
injection is halted
because the non-solvent is not miscible with the oil or hydrocarbon solvent.
This lack of
miscibility assists in the ability to hold the targeted pressure increase for
the required
duration. Non-solvents such as water are also typically cheaper than solvents.
[0073] Alternatively, an inefficient or lower cost solvent could be used in
place of a
non-solvent to provide the reservoir conditioning. Use of a solvent enables
some heavy oil
production when the pressure buffer is no longer required and the buffer well
produced.
[0074] The injection volume of the non-solvent or inefficient solvent
increases with
subsequent pressure conditioning operations due to the increased voidage in
the reservoir
created by the production of oil. Therefore the production of the buffer well,
if desired, would
need to sufficiently lag the adjacent CSDRP wells so as not to adversely
affect the
production of the CSDRP wells.
[0075] Pressure maintenance by injection need not be constrained to the target
hydrocarbon-bearing reservoir. In the case where gas or water zones are
adjacent
(overlying / underlying or edge) to the hydrocarbon-bearing reservoir, it may
be beneficial for
pressure maintenance wells to target the adjacent gas/water zones in order to
increase
formation pressure and suppress the solvent finger growth into the vicinity of
potential 'thief
zones of injected solvent.
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CA 02703319 2010-05-05
[0076] The field may contain a large set of wells. The subset of wells used as
pressure maintenance wells need not be fixed through the life of the field
operation. As part
of the evolving reservoir depletion plan new buffer wells may be drilled,
existing injection or
production wells may be converted to buffer wells, or buffer wells may be
retired or converted
to injection or production wells. All of these changes may enhance recovery.
In particular,
buffer wells may need to be placed between injecting and producing wells as a
CSDRP field
operation matures. Such placement assists solvent containment by removing or
reducing
the steep pressure gradient that may exist between CSDRP wells undergoing
opposite flow
operations.
[0077] The procedure of drilling a new well offset to an existing well or
drilling a new
well between two existing wells is often called infill drilling. A pressure
maintenance well is
therefore a kind of infill well. The drilling of other types of infill wells,
such as wells whose
purpose is to produce oil or inject solvent, may also be advantageous.
[0078]
Well layout alternatives
[0079] The arrangement in Fig. 4 may be varied. For instance, the wells need
not be
parallel or perpendicular to the boundary and buffer, and may deviate by, for
instance, up to
30 . Also, Fig. 4 shows the neighboring groups (403, 404) as synchronized with
group 402,
but because of the good buffer zone isolation, the neighboring groups could be
injecting or
producing in an out-of-synch manner. Each group does not necessarily have to
have the
same number of wells. Likewise, the buffer zones need not be the same size
over the field.
[0080] In Figs. 3 through 10 all of the block boundaries were shown as
rectangular
and the side-to-side and end-to-end separations were shown as equal on both
sides of a
group. The block boundaries need not be rectangular and the separations need
not be
equal. For example, there may be geological features such as 'channel
boundaries' that may
be utilized to reduce separation between groups on one side of a group. These
geological
features act as artificial buffers, eliminating the need to leave a
substantial buffer. Boundary
dimensions may be adjusted to account for communication or stress trends. If
communication is detected between wells of different groups, injection volumes
may be
reduced on the communicating boundary wells. In order to detect such
communication there
may be pressure monitoring of boundary or observation wells. If measurements
of the stress
state indicate that viscous fingering may be enhanced, the buffer size may be
increased on
one side of a group. The presence of significant fractures may also be a
reason to increase
-22-
CA 02703319 2010-05-05
the size of the buffers. "Geological buffer zone" as used herein means a
naturally occurring
zone acting as a buffer zone, such as a sealing fault or channel boundary. A
"channel
boundary" as used herein means the boundary between two rock formations, one
rock
formation consisting of a channel filled with relatively permeable rock, and
the other
formation consisting of a different and less permeable rock. A sealing fault
is a fault that
effectively seals off flow from one side of the fault of the other.
[0081]
Allowing individual wells to within a group to idle or soak
[0082] Regardless of the particular orientation and grouping strategy, a
scheme for
overcoming some of the drawbacks associated with group synchronization or near-
synchronization is desirable. One such drawback is that synchronization can
reduce overall
efficiency by extending production or injection from wells no longer
efficiently performing. In
one embodiment, specific wells within a group are temporarily shut-in. In
particular, if during
production, a specific well within a group starts producing gas at rate above
a pre-set value,
the well is temporarily shut-in until the overall performance of the entire
group to which the
well belongs reaches a pre-set threshold (for example, gas production rate or
total oil
production rate). In this way, overall efficiency of solvent use (for example,
produced oil to
injected solvent ratio) may be improved by preventing a poorly performing well
or a fast
producing well from overly-dictating the cycle schedule for the set of wells
to which it
belongs.
[0083] Table 1 outlines the operating ranges for CSDRPs of some embodiments.
The present invention is not intended to be limited by such operating ranges.
[0084] Table 1. Operating Ranges for a CSDRP.
Parameter Broader Embodiment Narrower Embodiment
Injectant volume Fill-up estimated pattern pore Inject, beyond a pressure
volume plus 2-15% of threshold, 2-15% (or 3-8%) of
estimated pattern pore volume; estimated pore volume.
or inject, beyond a pressure
threshold, for a period of time
(for example weeks to
months); or inject, beyond a
pressure threshold, 2-15% of
-23-
CA 02703319 2010-05-05
estimated pore volume.
Injectant Main solvent (>50 mass%) C2- Main solvent (>50 mass%) is
composition, C5. Alternatively, wells may be propane (C3).
main subjected to compositions
other than main solvents to
improve well pattern
performance (i.e. CO2 flooding
of a mature operation or
altering in situ stress of
reservoir).
Injectant Additional injectants may Only diluent, and only when
composition, include C02 (up to about 30%), needed to achieve adequate
additive C3+, viscosifiers (for example injection pressure.
diesel, viscous oil, bitumen,
diluent), ketones, alcohols,
sulphur dioxide, hydrate
inhibitors, and steam.
Injectant phase & Solvent injected such that at Solvent injected as a liquid,
and
Injection the end of injection, greater most solvent injected just under
pressure than 25% by mass of the fracture pressure and above
solvent exists as a liquid in the dilation pressure,
reservoir, with no constraint as Pfracture > Pinjection > Pdilation
to whether most solvent is > PvaporP.
injected above or below
dilation pressure or fracture
pressure.
Injectant Enough heat to prevent Enough heat to prevent hydrates
temperature hydrates and locally enhance with a safety margin,
wellbore inflow consistent with Thydrate + 5 C to Thydrate
Boberg-Lantz mode +50 C.
Injection rate 0.1 to 10 m3/day per meter of 0.2 to 2 m3/day per meter of
completed well length (rate completed well length (rate
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CA 02703319 2010-05-05
expressed as volumes of liquid expressed as volumes of liquid
solvent at reservoir conditions). solvent at reservoir conditions).
Rates may also be designed to
allow for limited or controlled
fracture extent, at fracture
pressure or desired solvent
conformance depending on
reservoir properties.
Threshold Any pressure above initial A pressure between 90% and
pressure reservoir pressure. 100% of fracture pressure.
(pressure at
which solvent
continues to be
injected for either
a period of time
or in a volume
amount)
Well length As long of a horizontal well as 500m - 1500m (commercial well).
can practically be drilled; or the
entire pay thickness for vertical
wells.
Well Horizontal wells parallel to Horizontal wells parallel to each
configuration each other, separated by some other, separated by some regular
regular spacing of 60 - 600m; spacing of 60 - 320m.
Also vertical wells, high angle
slant wells & multi-lateral wells.
Also infill injection and/or
production wells (of any type
above) targeting bypassed
hydrocarbon from surveillance
of pattern performance.
Well orientation Orientated in any direction. Horizontal wells orientated
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CA 02703319 2010-05-05
perpendicular to (or with less than
30 degrees of variation) the
direction of maximum horizontal in
situ stress.
Minimum Generally, the range of the A low pressure below the vapor
producing MPP should be, on the low pressure of the main solvent,
pressure (MPP) end, a pressure significantly ensuring vaporization, or, in the
below the vapor pressure, limited vaporization scheme, a
ensuring vaporization; and, on high pressure above the vapor
the high-end, a high pressure pressure. At 500m depth with pure
near the native reservoir propane, 0.5 MPa (low) - 1.5 MPa
pressure. For example, (high), values that bound the 800
perhaps 0.1 MPa - 5 MPa, kPa vapor pressure of propane.
depending on depth and mode
of operation (all-liquid or limited
vaporization).
Oil rate Switch to injection when rate Switch when the instantaneous oil
equals 2 to 50% of the max rate declines below the calendar
rate obtained during the cycle; day oil rate (CDOR) (for example
Alternatively, switch when total oil/total cycle length). Likely
absolute rate equals a pre-set most economically optimal when
value. Alternatively, well is the oil rate is at about 0.8 x
unable to sustain hydrocarbon ODOR. Alternatively, switch to
flow (continuous or injection when rate equals 20-40%
intermittent) by primary of the max rate obtained during
production against the cycle.
backpressure of gathering
system or well is "pumped off"
unable to sustain flow from
artificial lift. Alternatively, well
is out-of-synch with adjacent
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CA 02703319 2010-05-05
well cycles.
Gas rate Switch to injection when gas Switch to injection when gas rate
rate exceeds the capacity of exceeds the capacity of the
the pumping or gas venting pumping or gas venting system.
system. Well is unable to During production, an optimal
sustain hydrocarbon flow strategy is one that limits gas
(continuous or intermittent) by production and maximizes liquid
primary production against from a horizontal well.
backpressure of gathering
system with/or without
compression facilities.
Oil to Solvent Begin another cycle if the Begin another cycle if the OISR of
Ratio OISR of the just completed the just completed cycle is above
cycle is above 0.15 or 0.3.
economic threshold.
Abandonment Atmospheric or a value at For propane and a depth of 500m,
pressure which all of the solvent is about 340 kPa, the likely lowest
(pressure at vaporized. obtainable bottomhole pressure at
which well is the operating depth and well
produced after below the value at which all of the
CSDRP cycles propane is vaporized.
are completed)
[0085] In Table 1, embodiments may be formed by combining two or more
parameters and, for brevity and clarity, each of these combinations will not
be individually
listed.
[0086] In the context of this specification, diluent means a liquid compound
that can
be used to dilute the solvent and can be used to manipulate the viscosity of
any resulting
solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-
bitumen (and
diluent) mixture, the invasion, mobility, and distribution of solvent in the
reservoir can be
controlled so as to increase viscous oil production.
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CA 02703319 2012-01-17
[0087] The diluent is typically a viscous hydrocarbon liquid, especially a C4
to C20
hydrocarbon, or mixture thereof, is commonly locally produced and is typically
used to thin
bitumen to pipeline specifications. Pentane, hexane, and heptane are commonly
components of such diluents. Bitumen itself can be used to modify the
viscosity of the
injected fluid, often in conjunction with ethane solvent.
[0088] In certain embodiments, the diluent may have an average initial boiling
point
close to the boiling point of pentane (36 C) or hexane (69 C) though the
average boiling
point (defined further below) may change with reuse as the mix changes (some
of the
solvent originating among the recovered viscous oil fractions). Preferably,
more than 50%
by weight of the diluent has an average boiling point lower than the boiling
point of decane
(174 C). More preferably, more than 75% by weight, especially more than 80% by
weight,
and particularly more than 90% by weight of the diluent, has an average
boiling point
between the boiling point of pentane and the boiling point of decane. In
further preferred
embodiments, the diluent has an average boiling point close to the boiling
point of hexane
(69 C) or heptane (98 C), or even water (100 C).
[0089] In additional embodiments, more than 50% by weight of the diluent
(particularly more than 75% or 80% by weight and especially more than 90% by
weight)
has a boiling point between the boiling points of pentane and decane. In other
embodiments, more than 50% by weight of the diluent has a boiling point
between the
boiling points of hexane (69 C) and nonane (151 C), particularly between the
boiling
points of heptane (98 C) and octane (126('C).
[0090] By average boiling point of the diluent, we mean the boiling point of
the diluent
remaining after half (by weight) of a starting amount of diluent has been
boiled off as
defined by ASTM D 2887 (1997), for example. The average boiling point can be
determined by gas chromatographic methods or more tediously by distillation.
Boiling
points are defined as the boiling points at atmospheric pressure.
[0091] In the preceding description, for purposes of explanation, numerous
details
are set forth in order to provide a thorough understanding of the embodiments
of the
invention. However, it will be apparent to one skilled in the art that these
specific details
are not required in order to practice the invention.
[0092] The invention is recited in the claims and should not be limited to
preferred
embodiments described herein.
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