U.S. patent application number 13/074825 was filed with the patent office on 2011-11-10 for operating wells in groups in solvent-dominated recovery processes.
Invention is credited to Adam Coutee, Matthew A. Dawson, Owen J. Hehmeyer, Hao Huang, Robert Kaminsky, Ivan J. Kosik, Jean-Pierre Lebel, Robert Chick Wattenbarger.
Application Number | 20110272152 13/074825 |
Document ID | / |
Family ID | 44900839 |
Filed Date | 2011-11-10 |
United States Patent
Application |
20110272152 |
Kind Code |
A1 |
Kaminsky; Robert ; et
al. |
November 10, 2011 |
Operating Wells In Groups In Solvent-Dominated Recovery
Processes
Abstract
To recover oil, including viscous oil, from an underground
reservoir, a cyclic solvent-dominated recovery process may be used.
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. To control viscous fingering, operational
synchronization is used within groups and not between adjacent
groups.
Inventors: |
Kaminsky; Robert; (Houston,
TX) ; Coutee; Adam; (Cold Lake, CA) ; Dawson;
Matthew A.; (Houston, TX) ; Hehmeyer; Owen J.;
(Houston, TX) ; Huang; Hao; (Houston, TX) ;
Kosik; Ivan J.; (Calgary, CA) ; Lebel;
Jean-Pierre; (Calgary, CA) ; Wattenbarger; Robert
Chick; (Houston, TX) |
Family ID: |
44900839 |
Appl. No.: |
13/074825 |
Filed: |
March 29, 2011 |
Current U.S.
Class: |
166/268 |
Current CPC
Class: |
E21B 43/166 20130101;
E21B 43/30 20130101 |
Class at
Publication: |
166/268 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Foreign Application Data
Date |
Code |
Application Number |
May 5, 2010 |
CA |
2,703,319 |
Claims
1. 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: (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.
2. The method of claim 1 wherein the wells of the same group
undergo opposite flow operation of injection or production for less
than 10% of fluid flow on a mass basis.
3. The method of claim 2 wherein the wells of the same group
undergo opposite flow operation of injection or production for less
than 5% of fluid flow on a mass basis.
4. The method of claim 3 wherein the wells of the same group
undergo opposite flow operation of injection or production for less
than 1% of fluid flow on a mass basis.
5. The method of claim 4 wherein for at least 80% of fluid flow on
a mass basis a single well of at least one group undergoes
injection and production while remaining wells within the at least
one group are idle.
6. The method claim 1 wherein a single well of at least one of
group undergoes injection and production while remaining wells
within the at least one group are idle.
7. The method of claim 1 wherein the wells of the same group
undergo the same flow operation of injection or production for more
than 80% of fluid flow on a mass basis.
8. The method of claim 1 wherein the wells of the same group
undergo the same flow operation of injection or production for more
than 90% of fluid flow on a mass basis.
9. The method of claim 1 wherein the wells of the same group
undergo the same flow operation of injection or production for more
than 95% of fluid flow on a mass basis.
10. The method of claim 1 wherein more than 80% of the wells of the
same group undergo the same flow operation of injection or
production for more than 80% of an operational time period.
11. The method of claim 1 wherein all wells of the same group
undergo the same flow operation of injection or production for more
than 80% of an operational time period.
12. The method of claim 1 wherein adjacent well groups are operated
substantially out-of-synch.
13. The method of claim 1 wherein wells of adjacent well groups
undergo opposite flow operation of injection or production for more
than 10% of fluid flow on a mass basis.
14. The method of claim 1 wherein wells of adjacent well groups
undergo opposite flow operation of injection or production for more
than 25% of fluid flow on a mass basis.
15. The method of claim 1 wherein wells of adjacent well groups
undergo opposite flow operation of injection or production for more
than 50% of fluid flow on a mass basis.
16. The method of claim 1 wherein wells of adjacent well groups
undergo opposite flow operation of injection or production for more
than 75% of fluid flow on a mass basis.
17. The method of claim 1 wherein wells of adjacent well groups
undergo opposite flow operation of injection or production for more
than 90% of fluid flow on a mass basis.
18. The method of claim 1 wherein immediately after halting
injection of the solvent, at least 25 mass % of the injected
solvent is in a liquid state in the reservoir.
19. The method of claim 1 wherein at least 25 mass % of the solvent
in step (a) enters the reservoir as a liquid.
20. The method of claim 1 wherein at least 50 mass % of the solvent
in step (a) enters the reservoir as a liquid.
21. The method of claim 1 wherein each well within the set of wells
is oriented within 30.degree. of horizontal within the underground
reservoir.
22. The method of claim 1 wherein, within the underground
reservoir, the wells in the set are arranged within 20.degree. of a
common horizontal straight line.
23. The method of claim 22 wherein the single common straight line
is within 20.degree. of a maximum horizontal stress direction
within the reservoir.
24. The method of claim 1 wherein for at least 25% of the time
period between injecting and subsequently halting injection for a
group of wells, an adjacent group of wells has at least one well
producing; and for at least 25% of the time period between
producing and subsequently halting producing for a group of wells,
an adjacent group of wells has at least one well injecting.
25. The method of claim 1 wherein for at least 50% of the time
period between injecting and subsequently halting injection for a
group of wells, an adjacent group of wells has at least one well
producing; and for at least 50% of the time period between
producing and subsequently halting producing for a group of wells,
an adjacent group of wells has at least one well injecting.
26. The method of claim 1 wherein the well groups are separated by
buffer zones for limiting well-to-well interaction, wherein buffer
zones contain no flowing wells.
27. The method of claim 26 wherein the buffer zones constitute no
more than one third of a sum of an area of the groups.
28. The method of claim 26 wherein the buffer zones constitute no
more than 10% of a sum of an area of the groups.
29. The method of claim 1 wherein two wells are separated by an
infill well used for increasing hydrocarbon production prior to
and/or during operation.
30. The method of claim 1 wherein two wells are separated by an
infill well for increasing reservoir pressure prior to and/or
during operation, for limiting well-to-well interaction.
31. The method of claim 29 wherein water is injected into the
infill well.
32. The method of claim 26 wherein at least certain buffer zones
are geological buffer zones.
33. The method of claim 32 wherein the geological buffer zones are
channel boundaries.
34. The method of claim 1 wherein each group comprises a single row
of wells.
35. The method of claim 1 wherein the hydrocarbons are a viscous
oil having an in situ viscosity of greater than 10 cP at initial
reservoir conditions.
36. The method of claim 1 wherein a common wellbore is used for
both the injection and the production.
37. The method of claim 1 wherein an idle period exists subsequent
to halting injection and prior to initiating production.
38. The method of claim 1 wherein the solvent comprises ethane,
propane, butane, pentane, carbon dioxide, or a combination
thereof.
39. The method of claim 1 wherein the solvent comprises greater
than 50 mass % propane.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from Canadian patent
application 2,703,319 filed May 5, 2010, entitled Operating Wells
in Groups in Solvent-Dominated Recovery Processes, the entirety of
which is incorporated by reference herein.
[0002] This application contains subject matter related to U.S.
patent application Ser. No. 12/987,714 filed on Jan. 10, 2011,
entitled "Solvent Separation In A Solvent-Dominated Recovery
Process"; U.S. patent application Ser. No. 12/987,720 filed on Jan.
10, 2011, entitled "Hydrate Control In A Cyclic Solvent-Dominated
Hydrocarbon Recovery Process"; U.S. patent application Ser. No.
13/015,350 filed on Jan. 27, 2011, entitled "Use of a Solvent and
Emulsion for In-Situ Oil Recovery" and U.S. patent application Ser.
No. 13/032,293 filed on Feb. 22, 2011, entitled "Method for the
Management of Oilfields Undergoing Solvent Injection".
FIELD OF THE INVENTION
[0003] The present invention relates generally to well operations
in solvent-dominated in situ hydrocarbon recovery processes.
BACKGROUND OF THE INVENTION
[0004] 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. Pat. No. 4,280,559) and
Steam-Assisted Gravity Drainage (SAGD, see, for example U.S. Pat.
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. Pat. No. 6,708,759) and Steam And Vapor Extraction
processes (SAVEX, see, for example, U.S. Pat. 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.
[0005] 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 orientation,
primarily due to a desire to control viscous fingering in
solvent-dominated processes.
[0006] 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.
[0007] 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.
[0008] 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.
[0009] 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; U.S. Pat. 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.
[0010] 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 CSP.TM. processes.
[0011] Other descriptions of solvent-based processes are also
disclosed in the literature.
[0012] Allen et al. (U.S. Pat. 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.
[0013] 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 . . .
".
[0014] Additional patents that disclose methods for the recovery of
viscous oil using solvent-dominated recovery processes include U.S.
Pat. No. 6,883,607 Nenniger et al; U.S. Pat. No. 6,318,464 Mokrys;
U.S. Pat. No. 5,899,274 Frauenfeld et al.; and U.S. Pat. No.
4,362,213 Tabor.
[0015] These patents do not detail the arrangement, orientation,
and operation of wells to reduce viscous fingering.
[0016] 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 describes 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.
[0017] Jorgensen (U.S. Pat. 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.
[0018] Therefore, there is a need for an improved well operation
for solvent-dominated recovery processes for controlling viscous
fingering.
SUMMARY OF THE INVENTION
[0019] 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.
[0020] 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:
[0021] (a) initiating and subsequently halting injection, into one
of the groups of wells, of an amount of a viscosity reducing
solvent;
[0022] (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
[0023] (c) cyclically repeating steps (a) and (b) for the groups of
wells;
[0024] wherein: [0025] each of the groups comprises two or more
wells and no well is common between two groups; and [0026] wells of
the same group are operated substantially in-synch.
[0027] 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.degree. of horizontal within the
underground reservoir. Within the underground reservoir, the wells
in the set may be arranged within 20.degree. of a common horizontal
straight line. The single common straight line may be within
20.degree. of a maximum horizontal stress direction within the
reservoir. For at least 25% (or at least 50%) 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.
[0028] 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
[0029] Embodiments of the present invention will now be described,
by way of example only, with reference to the attached Figures,
wherein:
[0030] FIG. 1A is an illustration of adequate field sweep in an
inter-well region;
[0031] FIG. 1B is an illustration of poor field sweep in an
inter-well region due to disproportionate injection in the heel of
one well;
[0032] FIG. 1C is an illustration of poor field sweep in an
inter-well region due to solvent channeling through a finger that
connects two wells;
[0033] FIG. 2 is an illustration of an example of in-synch and
out-of-synch flow operations for two wells;
[0034] FIG. 3 is an illustration of an example of a well
arrangement in accordance with a disclosed embodiment;
[0035] FIG. 4 is an illustration of a well arrangement and
operation in accordance with a disclosed embodiment;
[0036] FIG. 5 is an illustration of a well arrangement and
operation;
[0037] FIG. 6 is another illustration of a well arrangement and
operation;
[0038] FIG. 7 is still another illustration of a well arrangement
and operation;
[0039] FIG. 8 is still another illustration of a well arrangement
and operation;
[0040] FIG. 9A is an illustration of a well orientation with
respect to a stress field, in accordance with a disclosed
embodiment;
[0041] FIG. 9B is an illustration of the stresses on a lateral
finger; and
[0042] FIGS. 10A and 10B illustrate is still another well
arrangement and operation in accordance with a disclosed
embodiment.
DETAILED DESCRIPTION
[0043] 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.degree. 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.degree. to about 10.degree.. The terms viscous oil, heavy oil,
and bitumen are used interchangeably herein since they may be
extracted using similar processes.
[0044] 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.
[0045] 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.
[0046] 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 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.
[0047] 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.
[0048] 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 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.
[0049] 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).
Solvent Composition
[0050] The solvent may be a light, but condensable, hydrocarbon or
mixture of hydrocarbons comprising ethane, propane, or butane.
Additional injectants may include CO.sub.2, natural gas, C.sub.3+
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.
[0051] In one embodiment, the solvent comprises greater than 50%
C.sub.2-C.sub.5 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 CO.sub.2 flooding of a mature operation.
Phase of Injected Solvent
[0052] 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 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.
[0053] 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, December 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.
[0054] 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.degree. C.) may be
appropriate. Low-level heating of the solvent prior to injection
may also be performed to prevent hydrate formation in tubulars and
in the reservoir. Heating to higher temperatures may benefit
recovery.
Synchronization
[0055] 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.
[0056] 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.
[0057] FIG. 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. 1A, 1B, and 1C show the
inter-well region at the end of an injection cycle and the right
portion of FIGS. 1A, 1B, and 1C 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, the sweep is adequate. FIG. 1B 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. 1C 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).
[0058] 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. FIG. 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).
[0059] 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.
[0060] Injection and production are considered to be opposite flow
operations.
[0061] 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.
[0062] 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 injecting wells,
the interaction is not particularly unfavorable. In alternative
embodiments, this value of 80% becomes 90%, or 95%.
[0063] 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.
[0064] 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.
[0065] 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.
[0066] 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%.
[0067] 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 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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: [0072] 1.
Principal approach: Division of a set of wells into groups using
buffer zones with operational synchronization within each group
(but not between groups); [0073] 2. Reduce buffer size and operate
neighboring groups more nearly in-synch; [0074] 3. Regardless of
grouping strategy, orient wells with regard to geological
considerations; [0075] 4. Create artificial buffers using pressure
maintenance wells; [0076] 5. Allow individual wells within a group
to idle or soak. Divide Up the Wells into Groups and Synchronize
the Wells within a Group
[0077] 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.
[0078] 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 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.
[0079] 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 (401A) 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 (401A) 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 (401A)
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.
[0080] 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
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.
[0081] 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.
[0082] 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.
[0083] 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 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.sub.inj) to average
production rates (Q.sub.prod) over the operational period,
number of producers per injector=SR(Q.sub.inj/Q.sub.prod).
[0084] For example, if average injection rate over several
injection phases is 500 m.sup.3 solvent/day/well, average solvent
production rate over several production phases is 100
m.sup.3/day/well, average solvent recovery over several cycles is
80%, and wells are not soaked, then there should be 4 wells
(0.80.times.500/100) on production for every well on injection.
[0085] 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 m.sup.3/day (24 wells.times.100
m.sup.3/day/well) of recycled solvent plus 600 m.sup.3/day of
makeup solvent volume.
[0086] 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.
[0087] 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.
[0088] FIG. 6 shows an inefficient use of buffer zones. The wells
(600A, 601A) 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. The
buffer separating group 600 from 601 and separating 602 from 603 is
not needed. Its presence lowers field sweep.
[0089] 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 (701B) 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.
[0090] 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 (801A) are injecting while the
neighboring wells (801B) 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 (801A)
to the producers (801B). Neither the injection (801A) wells or the
producing wells (801B) are in-synch with the unlabeled wells in
FIG. 8.
Reduce Buffer Size and Operate Neighboring Groups More Nearly
In-Synch
[0091] 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.
[0092] 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.
Orient Wells with Respect to Geologic Considerations
[0093] 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.
[0094] 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 FIG. 4, is a desired well layout for solvent-dominated processes
with viscous fingering. In FIGS. 9A and 9B S.sup.h.sub.max, and
S.sup.h.sub.min are the maximum (91) and minimum stress (92),
respectively. A cross-sectional view of the lateral finger is shown
in FIG. 9B. It shows that the stresses applied on the lateral
finger (93) are S.sup.h.sub.max 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
[0095] 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.
[0096] FIG. 10A 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. 10B illustrates the use of a pressure maintenance injector
well to minimize channeling within a group of five wells. FIG. 10B
shows a well arrangement that is the same as FIG. 10A, except that
an additional injector well (1004) is present. In the FIG. 10B 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. 10B 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.
[0097] 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.
[0098] 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.
[0099] 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.
[0100] 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.
[0101] 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.
Well Layout Alternatives
[0102] 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.degree.. 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.
[0103] 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 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.
Allowing Individual Wells to within a Group to Idle or Soak
[0104] 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.
[0105] Table 1 outlines the operating ranges for CSDRPs of some
embodiments. The present invention is not intended to be limited by
such operating ranges.
TABLE-US-00001 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 estimated pore volume. Injectant Main
solvent (>50 mass %) C.sub.2- Main solvent (>50 mass %) is
composition, C.sub.5. Alternatively, wells may be propane
(C.sub.3). main subjected to compositions other than main solvents
to improve well pattern performance (i.e. CO.sub.2 flooding of a
mature operation or altering in situ stress of reservoir).
Injectant Additional injectants may Only diluent, and only when
composition, include CO.sub.2 (up to about 30%), needed to achieve
adequate additive C.sub.3+, 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 the Solvent injected as a
liquid, and Injection pressure end of injection, greater than most
solvent injected just under 25% by mass of the solvent fracture
pressure and above exists as a liquid in the dilation pressure,
reservoir, with no constraint as P.sub.fracture >
P.sub.injection > P.sub.dilation > to whether most solvent is
P.sub.vaporP. 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 T.sub.hydrate + 5.degree.
C. to T.sub.hydrate + 50.degree. C. Boberg-Lantz mode Injection
rate 0.1 to 10 m.sup.3/day per meter of 0.2 to 2 m.sup.3/day per
meter of completed well length (rate completed well length (rate
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 500
m-1500 m (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 60-600 m; spacing of 60-320 m. 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 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 500 m depth with pure near
the native reservoir propane, 0.5 MPa (low)-1.5 MPa pressure. For
example, perhaps (high), values that bound the 800 0.1 MPa-5 MPa,
depending kPa vapor pressure of propane. 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 rate declines below the calendar obtained
during the cycle; day oil rate (CDOR) (for example Alternatively,
switch when total oil/total cycle length). absolute rate equals a
pre-set Likely most economically optimal value. Alternatively, well
is when the oil rate is at about unable to sustain hydrocarbon 0.8
.times. CDOR. Alternatively, flow (continuous or switch to
injection when rate intermittent) by primary equals 20-40% of the
max rate production against obtained during the cycle. backpressure
of gathering system or well is "pumped off" unable to sustain flow
from artificial lift. Alternatively, well is out-of-sync with
adjacent well cycles. Gas rate Switch to injection when gas Switch
to injection when gas rate rate exceeds the capacity of the exceeds
the capacity of the pumping or gas venting system. pumping or gas
venting system. Well is unable to sustain During production, an
optimal hydrocarbon flow (continuous strategy is one that limits
gas or intermittent) by primary production and maximizes liquid
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 500 m,
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 below produced after the
value at which all of the CSDRP cycles propane is vaporized. are
completed)
[0106] 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.
[0107] 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.
[0108] The diluent is typically a viscous hydrocarbon liquid,
especially a C.sub.4 to C.sub.20 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.
[0109] In certain embodiments, the diluent may have an average
initial boiling point close to the boiling point of pentane
(36.degree. C.) or hexane (69.degree. 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.degree. 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.degree. C.) or heptane (98.degree. C.), or even water
(100.degree. C.).
[0110] 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.degree. C.) and nonane (151.degree. C.),
particularly between the boiling points of heptane (98.degree. C.)
and octane (126.degree. C.).
[0111] 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.
[0112] 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.
[0113] The above-described embodiments of the invention are
intended to be examples only. Alterations, modifications and
variations can be effected to the particular embodiments by those
of skill in the art without departing from the scope of the
invention, which is defined solely by the claims appended
hereto.
* * * * *