CA2875846C - System and method for operating an infill and/or a step-out well for in situ bitumen recovery - Google Patents

Abstract

A method is provided for injecting solvent into a bitumen reserve at a well. The well is located adjacent at least one steam assisted gravity drainage (SAGD) well pair in the bitumen reserve, and includes an infill well or a step-out well. The method includes injecting a first solvent into the bitumen reserve at the well, wherein a region of the bitumen reserve near the well is at a first temperature. The method also includes, at a later time when the region of the bitumen reserve is at a second temperature higher than the first temperature, injecting a second solvent into the bitumen reserve at the well, wherein the second solvent has a higher boiling point than the first solvent and the first and second solvents are operable to reduce the viscosity of the bitumen in the reserve.

Description

SYSTEM AND METHOD FOR OPERATING AN INFILL AND/OR A STEP-OUT WELL FOR IN
SITU BITUMEN RECOVERY
TECHNICAL FIELD
[0001] The following relates to systems and methods for operating infill wells and/or step-out wells for in situ bitumen recovery.
DESCRIPTION OF THE RELATED ART

[0002] Bitumen is known to be considerably viscous and does not flow like conventional crude oil. As such, bitumen is recovered using what are considered non-conventional methods.
For example, bitumen reserves are typically extracted from a geographical area using either surface mining techniques, wherein the overburden is removed to access the underlying pay (e.g., ore-containing bitumen) and transported to an extraction facility; or using in situ techniques, wherein subsurface formations (containing the pay), e.g., oil sands, are heated such that the bitumen is caused to flow into one or more wells drilled into the pay while leaving formation rock in the reservoir in place. Both surface mining and in situ processes produce a bitumen containing fluid that is subsequently sent to an upgrading and refining facility, to be refined into one or more petroleum products such as gasoline and jet fuel.

[0003] Bitumen reserves that are too deep to feasibly permit bitumen recovery by mining techniques are typically accessed by drilling wellbores into the hydrocarbon bearing formation (i.e. the pay) and applying an in situ bitumen recovery process.

[0004] There are various in situ technologies available, such as steam driven or in situ combustion-based techniques. However, currently Steam Assisted Gravity Drainage (SAGD) is considered to be the most popular and effective in situ process. SAGD is an enhanced oil recovery process whereby a long horizontal steam injection well is located above a long horizontal production well. Injected steam forms a steam chamber above the SAGD well pair, heating the reservoir rock and reservoir fluids. Heated bitumen plus condensed steam flows down the sides of the steam chamber towards the production well. The condensed steam and bitumen are then lifted to surface with a downhole pump or by gas lift. SAGD
typically operates at elevated pressures and elevated temperatures, e.g., with temperatures exceeding 190 C.
Once at surface the bitumen and water are separated from one another in treatment vessels that operate at relatively high temperatures (e.g., 170 C). Bitumen is sent to refineries, while 22656988.1 , produced water is recycled. The reservoir rock (typically unconsolidated rock, i.e., sand) that once contained the bitumen remains in place, and is not produced to surface.

[0005] SAGD has become an increasingly popular method for extracting bitumen from oil sand reservoirs that are too deep for surface mining, largely due to the high recovery factor from SAGD. In situ techniques such as SAGD are normally used to access deeper pay wherein wellbores are drilled from the surface into the subsurface hydrocarbon-bearing formation. While vertical wellbores can be drilled deep enough to access the oil sands, bitumen recovery from vertical wells has not been found to be as effective as SAGD, which utilizes horizontally drilled wells.

[0006] Typically, multiple SAGD well pairs are drilled from surface into the subsurface hydrocarbon-bearing formation to cover a particular geographical area. While each SAGD well pair operates to heat bitumen on each side of the steam injector well, there often exists an area between adjacent SAGD well pairs where bitumen cannot be easily extracted using the SAGD
well pairs due to the way in which the steam chambers develop for each well pair. To access these areas between adjacent SAGD well pairs, infill wells have been used, which are drilled into areas between SAGD well pairs. Step-out wells, which are located adjacent a single SAGD
well pair, e.g., at the outer edges of a SAGD operation, can also be used to access areas beyond the SAGD well pair steam chambers. During early production stages, the infill wells are heated from diffused heat from the surrounding SAGD chambers. The temperature around the infill wells and step-out wells therefore increase with time but in the early stages the temperature can be too low to have a meaningful effect on mobilizing the bitumen.
SUMMARY

[0007] In one aspect, there is provided a method for injecting solvent into a bitumen reserve at a well located adjacent at least one steam assisted gravity drainage (SAGD) well pair in the bitumen reserve, the well comprising an infill well or a step-out well. The method comprises:
injecting a first solvent into the bitumen reserve at the well, wherein a region of the bitumen reserve near the well is at a first temperature; and at a later time when the region of the bitumen reserve is at a second temperature higher than the first temperature, injecting a second solvent into the bitumen reserve at the well, wherein the second solvent has a higher boiling point than the first solvent and the first and second solvents are operable to reduce the viscosity of the bitumen in the reserve.

22656988.1

[0008] In another aspect, the first solvent is selected based at least in part on the first temperature and the second solvent is selected based at least in part on the second temperature.

[0009] In yet another aspect, there is provided a method for injecting solvent into a bitumen reserve at a well located adjacent at least one steam assisted gravity drainage (SAGD) well pair in the bitumen reserve, the well comprising an infill well or a step-out well.
The method comprises: determining a first temperature of the bitumen reserve in a region near the well;
based on the first temperature, selecting a first solvent and injecting the first solvent into the bitumen reserve using the well; at a later time, determining a second temperature of the region, where the second temperature is higher than the first temperature; based on the second temperature, selecting a second solvent and injecting the second solvent into the bitumen reserve using the well; wherein: the first solvent and the second solvent are operable to reduce the viscosity of bitumen in the reserve; and a first diffusion boundary of the first solvent at the first temperature is a greater distance from the well than a second diffusion boundary of the second solvent at the second temperature, such that a lesser volume of the second solvent penetrates the bitumen reserve than the first solvent.

[0010] An advantage of the diffusion controlled mobilization process described herein stems from the process beginning earlier (that is, at lower temperatures) with relatively lighter solvents, which can reduce the steam-to-oil ratio (SOR). By increasing the surrounding temperature of the infill or step-out well, progressively heavier solvents are then used. An advantage of this lighter to heavier progression of solvents comes from the nature of the diffusion mechanism in lighter versus heavier solvents. That is, at the early stages in which the temperature of the area surrounding the infill or step-out well is lower, the correspondingly lighter solvents are used, which are less costly in comparison to heavier solvents. The diffusion boundary layer can be significantly larger for lighter solvents, meaning that the correspondingly larger solvent loss is offset by the lower cost. As such, for early stages in which SAGD operators have less control over aspects of the process such as temperature variations along the infill or step-out well, less expensive solvents are being used. Moreover, heavier solvents can be injected at higher pressures due to steam chamber advancement and higher steam chamber pressures and, as such, the solvent is contained around the infill or step-out wells thus further reducing solvent loss. As a result, operating at a relatively lower pressure than the steam chamber pressure can further limit solvent loss and improve pad economics.

22656988.1 BRIEF DESCRIPTION OF THE DRAWINGS

[0011] Embodiments will now be described by way of example only with reference to the appended drawings wherein:

[0012] FIG. 1 is a cross-sectional elevation view of a SAGD production site;

[0013] FIG. 2 is a cross-sectional elevation view of a SAGD production site having multiple SAGD well-pairs;

[0014] FIG. 3 is a cross-sectional elevation view of a SAGD production site having multiple SAGD well-pairs, multiple single infill wells, and a step-out well;

[0015] FIG. 4 is a cross-sectional elevation view of a SAGD production site having multiple SAGD well-pairs, multiple infill well-pairs, and a step-out well;

[0016] FIG. 5 is a cross-sectional elevation view of adjacent SAGD well-pairs and illustrating heat diffusion towards a single infill well between the SAGD well-pairs;

[0017] FIG. 6 is a cross-sectional elevation view of adjacent SAGD well-pairs and illustrating a temperature profile towards a single infill well between the SAGD well-pairs;

[0018] FIG. 7 is a chart illustrating a series of vapor pressure-temperature curves and a series of corresponding solvent injection stages for a diffusion controlled mobilization process;

[0019] FIG. 8 is a chart illustrating a series of mixed bitumen and solvent viscosity-temperature curves at the edge of an infill well and viscosity changes for different stages of a diffusion controlled mobilization process at varied injection pressures;

[0020] FIG. 9 is a chart illustrating a series of mixed bitumen and solvent viscosity-temperature curves at the edge of an infill well and viscosity changes for different stages of a diffusion controlled mobilization process at a constant injection pressure;

[0021] FIGS. 10(a) to 10(g) are cross-sectional elevation views of adjacent SAGD well-pairs during operation of a diffusion controlled mobilization process for a single infill well between the SAGD well pairs; and

[0022] FIG. 11 is a flow chart illustrating operations performed in a diffusion controlled mobilization process for extracting bitumen at an infill well.

22656988.1 DETAILED DESCRIPTION

[0023] There is provided a method of operating an infill or step-out well for in situ bitumen recovery from a bitumen reserve, wherein the infill or step-out well is located adjacent at least one SAGD well pair in the bitumen reserve. A solvent can be injected at the infill or step-out well when a region of the bitumen reserve near the infill or step-out well is at a first temperature.
A second solvent can be injected at the infill or step-out well when the region of the bitumen reserve is at a second temperature greater than the first temperature. The second solvent has an associated boiling point that is higher than the boiling point of the first solvent.

[0024] In some implementations, the method includes recovering bitumen at the infill or step-out well. The method also can include, in other implementations, injecting at least one additional solvent at the infill or step-out well as the region of the bitumen reserve near the infill or step-out well increases in temperature beyond the second temperature. In such implementations, each additional solvent comprises a higher boiling point than a previously injected solvent.

[0025] In other implementations, the method includes determining the first temperature and the second temperature in order to determine the first and second solvents to be used. For example, at least one of the first temperature and the second temperature can be determined via simulation or modeling a temperature profile in the bitumen reserve relative to the at least one SAGD well pair. Similarly, the first temperature and the second temperature can be determined by obtaining a measurement from a temperature sensing device located in or near the region of the bitumen reserve.

[0026] Turning now to the figures, FIG. 1 illustrates an example of a SAGD
production site at a surface location 12 in a particular geographical region. The SAGD
production site 10 is positioned to allow one or more SAGD well-pairs 14 to be drilled from the surface location 12 towards a bitumen reserve (i.e., the pay 24). The one or more SAGD well-pairs 14 include an injector well 16 configured to inject steam into the pay 24, positioned above a producer well 18 configured to recover a bitumen-containing fluid that has been mobilized by the injected steam.
The injector well 16 is typically located about 4 to 6 meters above the producer well 18, although a shorter or longer distance is possible, as is a lateral offset. The one or more SAGD well-pairs 14 are drilled vertically into the overburden 22 towards and into the underlying pay 24, and as they are drilled become oriented substantially horizontally, such that the producer well 18 is 22656988.1 above but near the formation 26 underlying the pay 24 (hereinafter the "underlying formation 26"). The one or more SAGD well pairs 14 are operated using surface production equipment 20. After determining the surface location 12 and production site 10, and determining where the one or more SAGD well-pairs 14 will be located at the production site 10 (e.g., by conducting typical computer simulations using geological and reservoir data), the corresponding locations of the production site 10 are drilled, as is known in the art.

[0027] After drilling the wells 16, 18, the surface production equipment 20 is installed in one or more production facilities for operating the one or more SAGD well pairs 14. Completing a particular well for production can involve several steps, as is known in the art. To access the target pay 24, perforating is performed to create holes through the well's casing and cement, which can be performed before or after production tubing is installed in the wells 16, 18.
Alternatively, the pay section of the well can be lined with a slotted liner or other form of sand control that is not cemented in place. The liner can utilize packers and inflow or ICDs that divide the injector or production wells into segments. The production tubing is then installed using the service rig. In addition to production tubing, the operator may install downhole instrumentation that can include temperature sensors, pressure sensors or fiber optic cable.
Once the tubing has been landed, a wellhead is installed over the production casing.

[0028] Typically, multiple SAGD well pairs 14 are drilled from the surface location 12 into the subsurface hydrocarbon-bearing formation to recover bitumen within the particular geographical area. FIG. 2 illustrates multiple SAGD well pairs 14 used to extract a targeted region of the pay 24, the view in FIG. 2 being towards and along the ends of the horizontal portions of the injector and producer wells 16, 18. It will be appreciated that three SAGD well pairs 14 are shown for illustrative purposes only and more or fewer SAGD well pairs 14 can be employed in different implementations.

[0029] As illustrated in FIG. 2, during production, each SAGD well pair 14 develops a steam chamber 30 as high pressure steam is injected into the injector well 16, as is known in the art.
The steam chamber 30 grows vertically and horizontally in the formation containing the pay 24, e.g., as shown in FIG. 2. The steam injected into the injector well 16 heats the bitumen in the pay 24 reducing the viscosity of the bitumen which allows bitumen containing fluid to flow along the wall of the steam chamber 30 down towards and into the lower producer well 18 with the 22656988.1 assistance of gravity. That is, the mobilized bitumen flows into the producer well 18 along with any water resulting from the condensation of the injected steam (i.e. bitumen containing fluid).

[0030] While each SAGD well pair 14 operates to heat bitumen to each side of the steam injector well, there typically exists an "inter-well-pair region" (denoted by numeral 32) between adjacent SAGD well pairs 14 where bitumen cannot be easily extracted using the SAGD well pairs 14 due to the way in which the steam chambers 30 develop for adjacent well pairs 14. For example, adjacent steam chambers 30a, 30b may coalesce near the top as the steam chambers 30a, 30b grow horizontally, with bitumen being stranded below. The distance between adjacent SAGD well pairs 14 can also be affected by efforts to economically balance the costs associated with having more SAGD well pairs 14 against both heat losses to the overburden 22 when the SAGD well pairs 14 are spaced far from each other, and the ability of the SAGD well pairs 14 to drain the targeted pay 24 when spaced in this way.
It should be noted that the inter-well-pair regions 32 are in contrast to interwell regions, which typically refer to the regions between the injector well 16 and producer well 18 of a SAGD
well pair 14.

[0031] FIG. 2 illustrates a first inter-well-pair region 32a located between a first SAGD well pair 14a and a second SAGD well pair 14b, and a second inter-well-pair region 32b located between the second SAGD well pair 14b and a third SAGD well pair 14c in this illustrative example. To produce bitumen in these areas between adjacent SAGD well pairs 14, infill wells 40 are used, which are drilled into the inter-well-pair regions 32 between the adjacent SAGD
well pairs 14 as illustrated in FIG. 3.

[0032] Turning now to FIG. 3, a first infill well 40a is located between the first SAGD well pair 14a and the second SAGD well pair 14b in the first inter-well-pair region 32a, and a second infill well 40b is located between the second SAGD well pair 14b and the third SAGD well pair 14c in the second inter-well-pair region 32b. Typically the infill wells 40 are positioned approximately halfway between adjacent SAGD well pairs 14 although other locations are possible depending, e.g., on the physical characteristics of the inter-well-pair regions 32.

[0033] Although the examples described below are directed towards producing bitumen at infill wells 40 located between adjacent SAGD well pairs 14, it can be appreciated that the principles described herein can equally be applied to step-out wells 44, as illustrated in FIG. 3.
The step-out well 44 is similar in configuration in this example to the infill wells 40a, 40b but is located adjacent a single SAGD well pair 14 as opposed to being located between two SAGD

22656988.1 well pairs 14. For example, a step out well 44 can be positioned at the outer edges of the geographical region of the pay 24 being produced that is beyond either of the outermost SAGD
well pairs 14. In the implementation shown in FIG. 3, the step-out well 44 is located at a distance d2 from the third SAGD well pair 14c, which is less than a distance dl between the infill well 40b and the third SAGD well pair 14c. The distance d2 is chosen to be less than dl in this example since only the third SAGD well pair 14c contributes diffused heat in the area of the step-out well 44 with correspondingly less heat contribution than that contributed to an infill well 40, which is situated between two SAGD well pairs 14.

[0034] To increase early-time bitumen production at the infill wells 40a, 40b, solvent is injected into the infill wells 40a, 40b according to a diffusion controlled mobilization process.
The solvent injection at the infill wells 40a, 40b can occur without steam having been injected into the reserve through the infill wells 40a, 40b, such that a bitumen containing fluid can be produced from a region of the bitumen reserve in the absence of steam injection into the region of the bitumen reserve, e.g., during such an early-time bitumen production phase. It can be appreciated that the solvent can be heated similar to the NSolvTM process, with the heated solvent being injected. The solvent is injected in a liquid state and penetrates the pay 24 surrounding the infill wells 40a, 40b before vaporizing at deeper zones, thereby creating a region of solvent 42a, 42b around each infill well 40a, 40b. Each region of solvent 42 has a diffusion boundary 43 at the periphery of the region 42. The diffusion boundary 43 represents substantially the outermost boundary of the region of solvent 42, within which diffusion of the solvent occurs. The diffusion boundary 43 can be used to determine a relative volume that would be consumed, for different solvents being injected (as described in greater detail below).
Therefore, the larger the region of solvent 42 defined by the diffusion boundary 43, the larger the volume of solvent that penetrates the pay 24, and the higher volume of solvent that would be consumed. As such, injected solvents having a closer diffusion boundary 43 and smaller region of solvent 42 consume less injected solvent. In the example shown in FIG. 3, the first infill well 40a includes a first region of solvent 42a with a corresponding diffusion boundary 43a at the periphery of the first region of solvent 42a. Similarly, the second infill well 40b includes a second region of solvent 42b with a corresponding diffusion boundary 43b at the periphery of the second region of solvent 42b. Moreover, in this example, the step-out well 44 can also be operated according to the diffusion controlled mobilization process described herein, and includes a region of solvent 46 with a corresponding diffusion boundary 45.

22656988.1

[0035] The implementation shown in FIG. 3 illustrates a single infill well 40 and single step-out well 44 configuration in which a cyclic solvent injection process is used.
For a cyclic solvent injection process, solvent is injected for a first period of time to create the region of solvent 42, 46, followed by a second period of time during which bitumen is mobilized and produced at the same infill well 40 and step-out well 44 respectively.

[0036] As illustrated in FIG. 4, it can be appreciated that an infill well pair 50 can also be used in other implementations. Shown in FIG. 4 are a first infill well pair 50a, having a first solvent injector well 52a and a first infill producer well 54a; and a second infill well pair 50b, having a second solvent injector well 52b and a second infill producer well 54b. With an infill well pair 50, the solvent is injected into the injector wells 52a, 52b, and bitumen is produced at the producer wells 54a, 54b. The infill well pair 50 also develops a region of solvent 53 from the injection of solvent into the pay 24, with a corresponding diffusion boundary 55 at the periphery of the region of solvent 53. In the example shown in FIG. 4, the first infill well pair 50a creates a first region of solvent 53a having a first diffusion boundary 55a, and the second infill well pair 50b creates a second region of solvent 53b having a second diffusion boundary 55b. Similar to the configuration shown in FIG. 4, a step-out well pair 56 can also be employed adjacent the third SAGD well pair 14c. The step-out well pair 56 includes a solvent injector well 58 and a production well 60. The step-out well pair 56 creates a region of solvent 57 having a diffusion boundary 59.

[0037] As discussed above, adjacent SAGD well pairs 14 contribute to an increasing temperature around an infill well 40 (or infill well pair 50) and a step-out well 44 (or step-out well pair 56). However, during the early stages of SAGD well production, the temperature surrounding the infill wells 40 (or infill well pairs 50) and step-out wells 44 (or step-out well pairs 56) is relatively low and therefore only mobilizes the surrounding bitumen to some extent. As illustrated in the upper view A of FIG.5, heat diffusion 70 caused by development of the steam chambers 30a, 30b in adjacent SAGD well pairs 14a, 14b exhibits a temperature profile 74 as shown in view B of FIG. 5 wherein the temperature near the SAGD steam chambers 30a, 30b tapers towards the infill well 40. It can be appreciated that a similar tapering effect would be experienced with respect to a step-out well 44 (or step-out well pair 56) with heat diffusion 70 being contributed from a single SAGD well pair 14.

22656988.1

[0038] The temperature at the location of the infill wells 40 (or infill well pairs 50) and step-out wells 44 (or step-out well pairs 56) is a function of several parameters, such as the progressing velocity at the edge of the steam chamber 30, steam injection temperature, initial reservoir temperature, distance from steam chamber 30 (d1 in FIG. 3), and steam injection pressure. Assuming that conduction is the only heat mechanism in a SAGD
reservoir, according to Butler (Butler, R.M., "Thermal Recovery of Oil and Bitumen", Englewood Cliffs, New Jersey, 1997) the temperature at any location in front of the edge of the steam chamber 30 can be given by the following expression:
( T ¨Tr Ux r U pr pr _________________ = exp _____________ = exp x 1

[0039]
Tst r ¨T ();
KThermal

[0040] where, T is the temperature at a location in front of the edge of the steam chamber, Tr is the initial reservoir temperature, Tst is the steam injection temperature, is the distance from the edge of the steam chamber, Ux is the moving velocity of the steam chamber interface, K is the reservoir thermal conductivity, cpr is the reservoir heat capacity, pr is the reservoir density, and ICThermal is the thermal diffusivity of the bitumen. It can be appreciated that while Equation 1 can be used for estimations of temperature beyond the steam chamber edge, temperatures at or near infill wells 40 (or infill well pairs 50) and step-out wells 44 (or step-out well pairs 56) can also be evaluated using monitoring and/or measurement techniques, e.g., by having thermocouples, fiber optic cabling, or other temperature sensing devices incorporated along the length of the infill wells 40 (or infill well pairs 50) and step-out wells 44 (or step-out well pairs 56), e.g., inside the liner casing.

[0041] The introduction of solvents into the infill well 40, step-out well 46, infill injection well 52, or solvent injection well 58 enables production to occur at the infill wells 40 (or infill well pairs 50) and step-out wells 44 (or step-out well pairs 56) at an earlier stage compared to production techniques where solvent injection is not employed. In one embodiment, the solvent is injected at a lower pressure than the steam injection pressure in the adjacent SAGD steam chambers 30. Injecting the solvent at a lower pressure than the steam injection pressure can contribute to enhancing the containment of the injected solvent around the infill well 40, since the pressure difference between the solvent injection pressure and the steam injection pressure 22656988.1 hinders or otherwise mitigates the migration of the injected solvent within the formation. In other words, the pressure gradient created in the region between the steam chamber and the injection point of the solvent can advantageously inhibit the solvent from migrating to other portions of the formation, thus enabling a more efficient recovery of the solvent and the mobilized bitumen containing fluids. For example, in the embodiment shown in FIG. 6, view A, the solvent injection pressure Pso is less than the steam pressure Pst in the first and second steam chambers 30a, 30b. Similar principles apply to an infill well pair 50 shown in FIG. 6, view B.

[0042] It has been recognized that the presently described diffusion controlled mobilization process can utilize a set of multiple solvents having different "weights"
(i.e. being relatively lighter and relatively heavier), each of the solvents having a corresponding boiling point. An example of such a set of solvents is a set of alkane-based solvents. The diffusion controlled mobilization process can contribute to earlier production at infill and step-out wells 40, 44, while minimizing solvent loss and the costs associated with the solvents, by progressing from lighter to heavier solvents as the temperature surrounding the infill and step-out wells 40, 44 rises.
The diffusion controlled process can achieve this by utilizing solvents from the set according to current (or estimated to be current) temperatures near the infill well 40 (or infill well pair 50) and step-out well 44 (or step-out well pair 56). For example, a relatively lighter alkane such as propane (i.e. relatively lower carbon solvent) can be injected into the infill well 40 at an early stage, and at subsequent temperature thresholds, progressively heavier alkanes such as butane, etc. (i.e. progressively higher carbon solvent) can be injected according to the increasing temperature around the infill well 40. In general, less solvent is required at higher temperatures, since heavier solvents used at higher temperatures intrinsically have relatively small diffusion boundaries.

[0043] An example of a set of solvents having multiple levels and associated boiling points is a set of alkanes ranging from a relatively lighter alkane such as methane to a relatively heavier alkane such as heptane, e.g., a set of solvents including methane (CH4), ethane (C2116), propane (C3H8), butane (C4H10), pentane (C51-112), hexane (C6H14), and heptane (C7I-116), etc.
Other examples of sets of solvents can be selected from n (normal) and iso-alkanes according to the boiling points of such solvents. Similarly, other sets of solvents can be chosen from the following solvents, based on the boiling points and, in some cases the costs, of the respective solvents, for example: naphtha, toluene, xylene, benzene, diesel, natural gas, etc.

22656988.1

[0044] In the present example, the solvent is selected based on the temperature and pressure at which the solvent is in the liquid state. As previously described, the solvent is injected in the liquid state, e.g., from a truck at surface 12. It is expected that near the end of the injection stage for a particular solvent, due to an increase in temperature surrounding the infill wells 40, the solvent will be in a gaseous state where the temperature is higher than the condensation temperature of the solvent under a given pressure. As such, the liquid solvent initially diffuses into the formation at a larger flux due a larger concentration that is exposed to the bitumen. Once the solvent is vaporized, the flux of solvent diffusion decreases due to less solvent being available at the interface with the bitumen. The mobilized bitumen, due to solvent dissolution in the surrounding bitumen is produced in a mixture of liquid solvent and bitumen.

[0045] Accordingly, as the temperature surrounding the infill well 40 is increased, heavier carbon solvents are generally used, since the condensation temperature of such solvents tend to be higher when compared to that of lighter solvents under a given pressure.
As will be appreciated, the use of heavier solvents at higher temperatures generally ensures that a liquid solvent is exposed to the bitumen, thereby creating a liquid-liquid interface between the solvent and the bitumen which enables larger diffusion and dissolution resulting in larger production of bitumen from the formation. In other words, lighter carbon solvents are generally used during the early stages of SAGD production when temperatures surrounding the infill well 40 are lower and more solvent is required to mobilize the bitumen. As such, where the diffusion boundary 43, 55 is further from the infill well 40 during use of the lower carbon solvents, and thus more solvent is used, losses are attributed to the less costly solvents, which can improve pad economics.

[0046] For constant boundary conditions, the diffusion boundary ( 6Diff ) can be defined as 8Diff = V4Dt , where 6Diff is the diffusion length, boundary or front (referred to herein as "diffusion boundary"), and D is a diffusion coefficient or diffusivity in dimensions of [length2 time-1], for example m2/sec . The diffusion boundary provides a measure of how far the concentration has propagated in the x-direction by diffusion in time t (Bird, R.B., Stewart, W.E., Lightfoot, E.N., "Transport Phenomena", John Wiley & Sons, 1976).

[0047] The Wilke-Chang equation (Wilke C.R., Chang, P., "Correlation Of Diffusion Coefficients in Dilute Solutions", A.I.Ch.E. Journal, 1: 264-270, 1955) can be used for estimating 22656988.1 =
the diffusivity of nonelectrolytes (i.e., hydrocarbon solvent) in an infinitely dilute solution (i.e., bitumen):
Vc (T+273.15)

[0048] D=7.4 x10¨ ________________ =
[1Bitu v Solv

[0049] where D is diffusion coefficient (cm2/sec), 4:13 is association factor of bitumen, MBitu is molecular weight of bitumen (i.e., 500-550), JtBjtu is viscosity of the bitumen (cP) and Vsov is molal volume of solvent at normal boiling point (cc/g.mole). Based on current available data, the temperature dependence of the diffusion coefficient can be assumed to be linear.
Linear correlation is proposed in other correlations such as Stokes-Einstein (Einstein, Albert, Ann. Phys. 17, 549, 1905 and Miller C.C., "The Stokes-Einstein Law for Diffusion in Solution", Proceedings of the Royal Society of London. Series A, Containing Papers of a Mathematical and Physical Character, Vol. 106, No. 740, pp. 724-749, 1924) or close to linear in other correlations such as in Sitaraman (Sitaraman R., Ibrahim S. H., Kuloor N. R.
"A Generalized Equation for Diffusion in Liquids" J. Chem. Eng. Data, 1963, 8 (2), pp 198-201 doi:10.1021/je60017a017). The formulae suggested above for calculating the diffusion coefficient are expected to hold true for low-viscosity liquids but to introduce error for a high-viscosity solvent. However, the solute (i.e., bitumen) the solvents use in the present diffusion controlled mobilization process are light and less than 10 cP viscosity.

[0050] The Wilke-Chang equation shows that by increasing the temperature surrounding the infill well, the diffusion increases linearly. It is noted that since the diffusion is increasing inversely by viscosity of the bitumen ( mu ), the diffusion reduces for higher temperatures.

[0051] An increase in diffusion means that more solvent is diffusing and 8Diff (diffusion length) is increasing by heating up the area surrounding the infill wells 40.
This can be interpreted as solvent loss with no return. In the present diffusion controlled mobilization process, by increasing the temperature in the area surrounding the infill wells, a heavier solvent can be used. The advantage of using a heavier solvent is to reduce diffusion after an increase in temperature at the infill well surroundings. One can examine this using Wilke-Chang equation by substituting greater molal volume (Vsov ). This limits solvent loss at larger temperatures. In the present diffusion controlled mobilization process, rather than using a 22656988.1 heavier solvent at the lower temperatures, the use of the progressively heavier solvents beginning with a lighter solvent enables the mobilization of a larger volume of bitumen at any time, since in early-stages the process allows lighter components to mobilize the bitumen further away from the infill wells. The lighter solvents mobilize the deeper bitumen zones and, at a later time, the heat reaches closer to the infill well surroundings at which time a heavier solvent can be used to mobilize bitumen closer to the infill wells 40. It can be appreciated that the infill wells 40 are generally located at the furthest distance from the steam chambers 30.
Therefore, as time progresses, and the steam chambers 30 increase in size, the area surrounding the infill wells 40 should be mobilized to a greater extent, which is desirable. The diffusion controlled mobilization process described herein provides the capability of controlling diffusion boundaries at any stage during production.

[0052] It can be appreciated that the relative volume of solvent that penetrates the pay 24 can also be modeled according to dispersion of the solvent, which is a combination of diffusion and convection and has a linear relationship with diffusion. That is, the relative volume of each type of solvent can also be modeled by way of a dispersion boundary. Such a dispersion boundary can be estimated using a constant multiplier applied to the above-described diffusion coefficient D, as would be understood by those skilled in the art.

[0053] As shown in FIG. 7, the sequence of solvent injection stages in the illustrated implementation follows vapor pressure-temperature curves. At each stage, a particular solvent is selected according to the temperature (e.g., to select a heavier solvent as the temperature increases). FIG. 7 illustrates that for the solvent injection process, the solvent is injected as a liquid, e.g., from a truck at surface 22, and as a result of an increasing temperature, the solvent vaporizes for part of each stage. Vaporized solvent has less solubility due to having less concentration of the solvent being exposed to the bitumen, which decreases the efficiency of the solvent. The decrease in efficiency is shown in FIGS. 8 and 9. At the time of experiencing the decrease in efficiency, a heavier solvent should then be used to increase the efficiency and continue to mobilize bitumen to a lower viscosity as can be seen in FIGS. 8 and 9.

[0054] An advantage of the diffusion controlled mobilization process described herein stems from the process beginning earlier (that is, at lower temperatures) with relatively lighter solvents such as C3 and C4. By increasing the surrounding temperature of the infill well 40, progressively heavier solvents are then used, e.g., C6 and C7. The advantage of this lighter to 22656988.1 heavier progression of solvents comes from the nature of the diffusion mechanism in lighter versus heavier solvents. That is, at the early stages in which the temperature of the area surrounding the infill well 40 is lower, the correspondingly lighter solvents are used such as C3 and C4, which are less expensive in comparison to heavier solvents such as C6 and C7. The diffusion boundary layer 43 can be significantly larger for lighter solvents, meaning that the correspondingly larger solvent loss is offset by the lower cost. As such, for early stages in which SAGD operators have less control over aspects of the process such as temperature variations along the infill well 40, less expensive solvents are being used.
However, as the pay 24 surrounding the infill well 40 continues to be heated, heavier solvents are used. The closer diffusion boundary 43 inherent in the heavier components means that less of the more expensive solvent is lost. For example, solvents such as C6 and C7 typically have a diffusion boundary 43 of a few centimeters when compared to lighter solvents where the diffusion boundary 43 can be up to 10 meters. Heavier solvents are injected at higher pressures due to steam chamber advancement and higher steam chamber pressures and, as such, the solvent is contained around the infill wells 40 thus further reducing solvent loss. As a result, operating at a relatively lower pressure than the steam chamber pressure can further limit solvent loss.

[0055] As shown in FIG 8 a heavier solvent used at a higher temperature decreases viscosity which is not attainable with lighter solvents. The temperature at the infill wells 40 is increasing simultaneously with an increase in pressure. In early stages of production, the lighter components can be injected with a lower pressure and for larger components, the pressure can be increased to assist with containment of the lighter solvents. It may be noted that in reservoirs with higher water mobility, pressure may rise more quickly in which case the injection pressure should be kept constant during the process. FIG 9 illustrates the diffusion controlled mobilization process for constant injection, which boosts the production by decreasing viscosity, but can result in solvent loss at the early stages.

[0056] FIGS. 10(a) to 10(g) illustrate an example implementation of the diffusion controlled mobilization process in which a set of solvents is cycled as an expected or detected temperature near an infill well 40 is increased during SAGD production.

[0057] FIG. 10(a) illustrates the beginning of a SAGD operation in which the first SAGD
well pair 14a and the second SAGD well pair 14b have been drilled but have not yet begun production. In FIG. 10(b), the first and second steam chambers 30a, 30b begin to develop after 22656988.1 start-up of the SAGD well pairs 14a, 14b during which the respective inter-well regions between the SAGD injector and production wells 16, 18 are heated. In addition to developing the steam chambers 30a, 30b, the steam injected at the injector wells 16a, 16b contributes to heat diffusion 70 into the pay 24 beyond the steam chambers 14a, 14b and towards the inter-well-pair region 32a. An infill well 40 can be drilled at a particular stage of production for the SAGD
well pairs 14a, 14b, e.g., as shown in FIG. 10(c).

[0058] By monitoring, simulating, measuring, or estimating the temperature profile between adjacent SAGD well pairs 14a, 14b; after detecting a first temperature threshold A as illustrated in FIG. 10(d), solvent injection commences at the infill well 40. Since the temperature near the infill well 40 at the early stages is relatively low, a lighter solvent such as propane (C3 in FIG.
10(e)) can be selected and used. While the diffusion boundary 43 for C3 is further from the infill well 40 and a larger region of solvent 42 develops (with a correspondingly larger amount of C3 solvent used), the cost associated with C3 is lower than heavier, higher carbon solvents, which are required at higher temperatures. Therefore, the amount of solvent used, and any losses associated with use of the C3 solvent would be offset by the lower cost.

[0059] As the temperature surrounding the infill well 40 continues to increase during SAGD
production at the adjacent SAGD well pairs 14a, 14b, a heavier solvent such as butane (C4 in FIG. 10(f)) is selected. The diffusion boundary 43 is closer to the infill well for the heavier solvent resulting in a relatively smaller region of solvent 42 and correspondingly less solvent being used in this stage.

[0060] Therefore, less of the more costly solvent is used, and losses are reduced when compared to a prior stage which uses a lighter solvent. Moreover, since the progressively heavier solvents are progressively more contained around the infill well 40, the ability to recover and recycle the solvents is also increased as the heavier and more costly solvents are used.

[0061] FIG. 10(g) illustrates yet another stage, in this example using hexane (C6 in FIG.
10(g)) with a relatively closer diffusion boundary 43 thus further minimizing losses of costlier solvents as the temperature continues to increase.

[0062] As illustrated in FIGS. 10(b) through 10(g), the steam chambers 30a, 30b continue to enlarge while the SAGD well pairs 14a, 14b are in production. Since mobilization of the bitumen in the pay 24 surrounding the infill well 40 can begin earlier by using solvents that are effective at lower temperatures, the bitumen surrounding the infill wells is mobilized more 22656988.1 quickly and less steam is used, resulting in an improved steam-to-oil ratio (SOR), and providing an additional economic benefit. Furthermore, pay 24 can be produced in the inter-well-pair regions 32 prior to the steam chambers 30a, 30b coalescing, which can also contribute to an improved SOR by reducing the amount of time required to operate the SAGD well pairs 14.

[0063] Turning now to FIG. 11, a flow chart is provided illustrating an example of the diffusion controlled mobilization process described herein. In this example, optional step 102 can be performed in a planning process which includes determining when to drill one or more single infill well(s) 40 (or infill well pairs 50) and/or one or more step-out wells 44 (or step-out well pairs 56). It will be appreciated that the infill and step-out wells 40, 44 can also be drilled according to a production schedule and/or can exist at the time of commencing SAGD
operations. I will also be appreciated that the following principles equally apply to infill well pairs 50 and step-out wells and well pairs 56, 56. For ease of illustration, the following example refers to operation of a single infill well 40.

[0064] A start-up temperature at which to begin drilling the infill well 40 can also be used to determine when to begin drilling the infill well 40, at which time the infill well 40 is drilled when the start-up temperature is estimated or measured at step 102. It can be appreciated that step 102 is optional in that in at least some implementations, the process described herein can be applied to already drilled infill wells 40 and step-out wells 46. Similarly, infill and step-out wells 40, 46 in at least some implementations are drilled according to other factors such as the availability of equipment and other scheduling constraints.

[0065] At step 104, the temperature near the infill well 40 is determined, e.g., via measurements using temperature sensors, simulations, mathematical modeling or predictions, etc. In early production, a lower threshold may be used to trigger the injection of the solvent at the infill well 40. At step 106 a solvent is selected according to the determined temperature and solvent is injected at the infill well 40 at a lower pressure than the steam pressure in the steam chambers 30a, 30b of the adjacent SAGD well pairs 14a, 14b at step 108.

[0066] Bitumen is then extracted at the infill well 40 at step 110 and, if applicable, solvent is recovered at step 112, which can be reused in step 108 during the stage associated with the selected solvent. That is, the recovered solvent can be used while the same type of solvent is being injected at step 108. The process repeats by determining a next temperature at which to begin using a higher carbon solvent.

22656988.1

[0067] For simplicity and clarity of illustration, where considered appropriate, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
In addition, numerous specific details are set forth in order to provide a thorough understanding of the examples described herein. However, it will be understood by those of ordinary skill in the art that the examples described herein may be practiced without these specific details. In other instances, well-known methods, procedures and components have not been described in detail so as not to obscure the examples described herein. Also, the description is not to be considered as limiting the scope of the examples described herein.

[0068] It will be appreciated that the examples and corresponding diagrams used herein are for illustrative purposes only. Different configurations and terminology can be used without departing from the principles expressed herein. For instance, components and modules can be added, deleted, modified, or arranged with differing connections without departing from these principles.

[0069] The steps or operations in the flow charts and diagrams described herein are just for example. There may be many variations to these steps or operations without departing from the principles discussed above. For instance, the steps may be performed in a differing order, or steps may be added, deleted, or modified.

[0070] Although the above principles have been described with reference to certain specific examples, various modifications thereof will be apparent to those skilled in the art as outlined in the appended claims.

22656988.1

Claims (19)

Claims:

1. A method for injecting solvent into a bitumen reserve at a well located adjacent at least one steam assisted gravity drainage (SAGD) well pair in the bitumen reserve, the well comprising an infill well or a step-out well, the method comprising:
injecting a first solvent into the bitumen reserve at the well, wherein a region of the bitumen reserve near the well is at a first temperature; and at a later time when the region of the bitumen reserve is at a second temperature higher than the first temperature, injecting a second solvent into the bitumen reserve at the well, wherein the second solvent has a higher boiling point than the first solvent and the first and second solvents are operable to reduce the viscosity of the bitumen in the reserve, and wherein the first solvent is selected based at least in part on the first temperature and the second solvent is selected based at least in part on the second temperature.

2. The method of claim 1, further comprising producing a bitumen containing fluid from the vicinity of the well.

3. The method of claim 1, further comprising injecting at least one additional solvent at the well as the region of the bitumen reserve near the well increases in temperature beyond the second temperature, wherein each additional solvent comprises a higher boiling point than a previously injected solvent.

4. The method of claim 1, further comprising determining the first temperature and the second temperature.

5. The method of claim 4, wherein at least one of the first temperature and the second temperature is determined via simulation or modeling a temperature profile in the bitumen reserve relative to the at least one SAGD well pair.

6. The method of claim 4, wherein at least one of the first temperature and the second temperature is determined by obtaining a measurement from a temperature sensing device located in or near the region of the bitumen reserve.

7. The method of claim 1, wherein the first and second solvents are injected at a lower pressure than a steam chamber pressure associated with the at least one SAGD
well pair.

8. The method of claim 1, wherein the first and second solvents are selected from a plurality of alkane solvents.

9. The method of claim 8, wherein the alkane solvents comprise at least two of methane, ethane, propane, butane, pentane, hexane, and heptane.

10. The method of claim 1, wherein the first and second solvents are selected from the group: n-alkanes, iso-alkanes, naphtha, toluene, xylene, benzene, diesel, and natural gas.

11. The method of claim 1, wherein the well comprises a single well configured to inject solvent according to a cyclic solvent injection process wherein the single well injects the first and second solvents and produces a bitumen containing fluid.

12. The method of claim 1, wherein the well is configured to inject the first and second solvents, and a second well vertically offset from the well is configured to produce a bitumen-containing fluid from the bitumen reserve.

13. The method of claim 1, further comprising recovering solvent from a bitumen containing fluid produced at the well and reusing at least a portion of recovered solvent to inject back into the bitumen reserve.

14. A method for injecting solvent into a bitumen reserve at a well located adjacent at least one steam assisted gravity drainage (SAGD) well pair in the bitumen reserve, the well comprising an infill well or a step-out well, the method comprising-determining a first temperature of the bitumen reserve in a region near the well;
based on the first temperature, selecting a first solvent and injecting the first solvent into the bitumen reserve using the well;
at a later time, determining a second temperature of the region, where the second temperature is higher than the first temperature;
based on the second temperature, selecting a second solvent and injecting the second solvent into the bitumen reserve using the well;

wherein:
the first solvent and the second solvent are operable to reduce the viscosity of bitumen in the reserve; and a first diffusion boundary of the first solvent at the first temperature is a greater distance from the well than a second diffusion boundary of the second solvent at the second temperature, such that a lesser volume of the second solvent penetrates the bitumen reserve than the first solvent.

15. The method of claim 14, further comprising:
producing a bitumen containing fluid from the bitumen reserve in the vicinity of the well.

16. The method of claim 15, further comprising:
ceasing injection of solvent into the well; and operating the well as a production well, wherein the bitumen containing fluid is produced from the well.

17. The method of claim 15, wherein the bitumen containing fluid is produced from a second well that is vertically displaced lower in the bitumen reserve relative to the well.

18. The method of claim 15, wherein the bitumen containing fluid is produced from the bitumen reserve without steam having been injected into the reserve through the well.

19. The method of claim 15, wherein the bitumen containing fluid is produced from a region of the bitumen reserve in the absence of steam injection into the region of the bitumen reserve.