CA2898065C - Pressure cycling with mobilizing fluid circulation for heavy hydrocarbon recovery - Google Patents

Abstract

The invention provides processes for initiating hydrocarbon production in a well, involving circulating a mobilizing fluid in the wellbore to apply a reservoir stimulation pressure to a region of the formation adjacent to the well, and concomitantly cycling the reservoir stimulation pressure between a high wellbore circulation pressure and a low wellbore circulation pressure, so as to oscillate a pressure gradient in the region of the formation adjacent to the wellbore. Aspects of the invention involve the use of heated mobilizing fluids, such as steam, as well as alternative mobilizing agents such as organic solvents.

Description

PRESSURE CYCLING WITH MOBILIZING FLUID CIRCULATION FOR HEAVY
HYDROCARBON RECOVERY
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering, including the start-up and initial stages of thermal recovery processes, such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) systems in heavy oil reservoirs.
BACKGROUND OF THE INVENTION

[0002] Some subterranean deposits of viscous hydrocarbons can be extracted in situ by lowering the viscosity of the petroleum to mobilize it so that it can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands. The in situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by injecting a heated fluid such as steam into the reservoir formation from an injection well, for example, in SAGD or CSS processes (see Butler, Roger (1991), Thermal Recovery of Oil and Bitumen, Englewood Cliffs: Prentice-Hall).

[0003] A typical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, in which two wells are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. The steam condenses and gives up its latent heat to the formation, heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby mobilized, and drain by gravity toward the production well with an aqueous condensate. In this way, the injected steam initially mobilises the in-place hydrocarbon to create a "steam chamber" in the reservoir around and above the horizontal injection well. The term "steam chamber" accordingly refers to the volume of the reservoir which is saturated with injected steam and from which mobilised oil has at least partially drained. Mobilized viscous hydrocarbons are recovered continuously through the production well. The conditions of steam injection and of hydrocarbon production may be modulated to control the growth of the steam chamber, to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilised hydrocarbons.

[0004] CSS generally involves injecting steam into a formation, permitting injected fluids to soak, and then producing fluids including mobilized hydrocarbons.
A variation of CSS is described for example in Canadian Patent No. 1,144,064 issued 5 April 1983 to Esso Resources Canada Limited, wherein a hydrocarbon solvent is injected into the formation as part of the CSS process.

[0005] The start-up stage of the SAGD process establishes thermal and hydraulic communication between the injection and production wells. At initial reservoir conditions, there is typically negligible fluid mobility between wells due to high bitumen viscosity. Communication is achieved when bitumen between the injector and producer is mobilized to allow for bitumen production. A
conventional start-up process involves establishing interwell communication by simultaneously circulating steam through each injector well and producer well. High-temperature steam flows through a tubing string that extends to the toe of each horizontal well.
The steam condenses in the well, releasing heat and resulting in a liquid water phase which flows back up the casing-tubing annulus. Injection pressures may be adjusted during start-up, for example to increase pressures so as to dilate an oil sand formation in the region of a circulating injection well, as described in Canadian Patent No. 2,757,125 issued 25 March 2014 to FCCL Partnership. Solvents may be used to stimulate start-up, with solvent injection either prior to or after steam injection during the start-up stage. Start-up solvents may for example include xylene, toluene, diesel, butane, pentane, hexane, diluent, condensate, or combinations thereof (see Canadian Patent No. 2,698,898 issued 23 October 2012 to FCCL Partnership).

[0006] In the ramp-up stage of the SAGD process, after communication has been established between the injection and production wells during start-up (usually over a limited section of the well pair length), production begins from the production well. Steam is continuously injected into the injection well (usually at constant pressure) while mobilized bitumen and water are continuously removed from the production well (usually at constant temperature). High pressure injection during the initial phase of SAGD operations has been thought to be important to accelerate a ramp-up in production (Li et al., Journal of Canadian Petroleum Technology, Vol. 48, No.1, January 2009). During this period the zone of communication between the wells is expanded axially along the full well pair length and the steam chamber grows vertically up to the top of the reservoir. The reservoir top may be a thick shale (overburden) or some lower permeability facies that causes the steam chamber to stop rising. When the interwell region over the entire length of the well pair has been heated and the steam chamber that develops has reached the reservoir top, the bitumen production rate typically peaks and begins to decline while the steam injection rate reaches a maximum and levels off.

[0007] In conventional SAGD, after ramp-up, the steam chamber has essentially achieved full height (although it is typically still rising slowly through or spreading around lower permeability zones in some locations) and lateral growth becomes the dominant mechanism for recovering bitumen. As the steam chamber widens, overburden heat losses typically begin to consume an increasing portion of the heat from injected steam leading to declining bitumen production rates at steady steam rates (or in some cases, steady bitumen rates with increasing steam rates).
Typically steam injection at the injector well is controlled so as to maintain a target steam chamber pressure during this phase. As the emulsion drains to the production well fluid withdrawal rates are controlled to ensure the well remains submerged in bitumen and steam condensate. Submergence prevents the steam that overlies the liquid zone from breaking through to the production well, which can short-circuit the SAGD process and potentially damage the wellbore.

[0008] Alternative primary recovery processes may be used that employ thermal and non-thermal components to mobilise oil. A wide variety of processes have been described that use hydrocarbon solvents in addition to steam, or in place of steam, in processes analogous to conventional SAGD, or in processes that are alternatives to SAGD. For example, Canadian Patent Number 2,299,790 describes methods for stimulating heavy oil production using a propane vapor. Unheated hydrocarbon vapours have been proposed for use to dissolve and displace heavy oils in a process known as VAPEX (Butler and Mokrys, J. Can. Petro. Tech. 1991,30; U.S.
Pat. No, 5,407,009). Processes for cyclic steam stimulation of vertical wells using hydrocarbon solvents have been described (Leaute and Carey, J. Can. Petro.
Tech., Vol. 46, No. 9, pp. 22-30, 2007). Field trials have also been reported for solvent assisted processes that involve the use of butane, added to injected steam after a period of conventional SAGD (Gupta et al., Paper No. 2002-299, Can.
Intl.
Pet. Conf., Calgary, Alberta, June 11-13, 2002; and, Gupta and Gittins, Paper No.
2005-190, Can. Intl. Pet. Conf., Calgary, Alberta, June 7-9, 2005).

[0009] In the context of the present application, various terms are used in accordance with what is understood to be the ordinary meaning of those terms.
For example, "petroleum" is a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase. In the context of the present application, the words "petroleum" and "hydrocarbon" are used to refer to mixtures of widely varying composition. The production of petroleum from a reservoir necessarily involves the production of hydrocarbons, but is not limited to hydrocarbon production. Similarly, processes that produce hydrocarbons from a well will generally also produce petroleum fluids that are not hydrocarbons.
In accordance with this usage, a process for producing petroleum or hydrocarbons is not necessarily a process that produces exclusively petroleum or hydrocarbons, respectively. "Fluids'', such as petroleum fluids, include both liquids and gases.
Natural gas is the portion of petroleum that exists either in the gaseous phase or is in solution in crude oil in natural underground reservoirs, and which is gaseous at atmospheric conditions of pressure and temperature. Natural Gas may include amounts of non-hydrocarbons.

[0010] It is common practice to segregate petroleum substances of high viscosity and density into two categories, "heavy oil" and "bitumen". For example, some sources define "heavy oil" as a petroleum that has a mass density of greater than about 900 kg/m3. Bitumen is sometimes described as that portion of petroleum that exists in the semi-solid or solid phase in natural deposits, with a mass density greater than about 1000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pas) measured at original temperature in the deposit and atmospheric pressure, on a gas-free basis. Although these terms are in common use, references to heavy oil and bitumen represent categories of convenience, and there is a continuum of properties between heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen herein include the continuum of such substances, and do not imply the existence of some fixed and universally recognized boundary between the two substances. In particular, the term "heavy oil" includes within its scope all "bitumen" including hydrocarbons that are present in semi-solid or solid form.

[0011] A reservoir is a subsurface formation containing one or more natural accumulations of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" or "tar sand" reservoir is generally comprised of strata of sand or sandstone containing petroleum. A "zone" in a reservoir is merely an arbitrarily defined volume of the reservoir, typically characterised by some distinctive property. Zones may exist in a reservoir within or across strata, and may extend into adjoining strata. In some cases, reservoirs containing zones having a preponderance of heavy oil are associated with zones containing a preponderance of natural gas. This "associated gas" is gas that is in pressure communication with the heavy oil within the reservoir, either directly or indirectly, for example through a connecting water zone.

[0012] A "chamber" within a reservoir or formation is a region that is in fluid communication with a particular well or wells, such as an injection or production well. For example, in a SAGD process, a steam chamber is the region of the reservoir in fluid communication with a steam injection well, which is also the region that is subject to depletion, primarily by gravity drainage, into a production well SUMMARY OF THE INVENTION

[0013] Aspects of the invention involve initiating hydrocarbon production in a well having a wellbore in a subterranean formation bearing a heavy oil, by concomitantly circulating a mobilizing fluid and cycling the wellbore circulation pressures of the mobilizing fluid. The mobilizing fluid may accordingly be circulated in the wellbore to apply a reservoir stimulation pressure to a region of the formation adjacent to the well, wherein circulation comprises injecting the mobilizing fluid into __ the well and producing the mobilizing fluid from the well. Concomitantly, the reservoir stimulation pressure may be cycled between a high wellbore circulation pressure and a low wellbore circulation pressure, so as to oscillate a pressure gradient in the region of the formation adjacent to the wellbore. The wellbore circulation pressure accordingly oscillates between alternative states:
i) an outward pressure gradient from higher wellbore circulation pressures to lower surrounding formation pressures when mobilizing fluid injection pressure is increased to the high wellbore circulation pressure;
and, ii) an inward pressure gradient from higher surrounding formation pressures to lower wellbore circulation pressures when mobilizing fluid injection pressure is decreased to the low wellbore circulation pressure.
The step of cycling of the reservoir stimulation pressures may be repeated, so as to mobilize the heavy oil in the region of the formation adjacent to the well to provide mobilized heavy oil. In this way, mobilized heavy oil may be produced along with produced mobilizing fluid from the well.

[0014] The mobilizing fluid may for example be a heated fluid that delivers thermal energy to the region of the formation adjacent to the well, such as steam.
Alternatively, the mobilizing fluid may be, or include, an organic solvent.

[0015] The high wellbore circulation pressure may for example be greater than initial bottom hole reservoir pressure. Similarly, the low wellbore circulation pressure may be lower than initial bottom hole reservoir pressure. In selected embodiments, the formation may for example be an oil sands formation, and the high wellbore circulation pressure may be a dilation pressure sufficient to dilate the oil sands in the region of the formation adjacent to the well.

[0016] The well to be stimulated may be a member of a well pair, each of the wells having horizontal segments that are generally parallel, and are vertically spaced apart by an inter-well region of the formation. One or both of the wells of the well pair may be subject to the circulating, cycling and repeating steps, which may be carried out so as to establish fluid communication between the wells of the well pair. For example, the well pair may form paired injection and production wells of a steam assisted gravity drainage well pair, and the circulating, cycling and repeating steps may be carried out during the start-up phase of a steam assisted gravity drainage production system.

[0017] Where aspects of the invention are implemented in the context of a start-up phase of a SAGD recovery system, this may be followed by a recovery phase for removing fluids from the subterranean formation. The recovery phase may for example include:
a) forming a steam chamber in the reservoir, the steam chamber bearing heavy oil and a non-condensing gas, the steam chamber having a peripheral zone of mobile hydrocarbons, wherein:
i) the generally horizontal segment of the production well is in fluid communication with the zone of mobile hydrocarbons;
ii) the generally horizontal segment of the injection well is in fluid communication with the steam chamber, generally parallel to and vertically spaced apart above the horizontal segment of the production well; and, iii) one or more mobile fluid regions provide fluid communication between the horizontal segments of the injection well and the production well in the inter-well region;
b) injecting an injection fluid comprising from about 1% to about 20% by mass butane with steam through the horizontal segment of the injection well at a selected bottom hole injection pressure, and at a bottom hole injection temperature, so that the injection fluid is substantially in a gaseous state at the injection pressure, so as to concurrently mobilize the heavy oil, mobilize non-condensing gas, and vertically expand the steam chamber; and, c) recovering the mobilized hydrocarbons and non-condensing gas from the reservoir through the production well, thereby removing non-condensing gases from the steam chamber.

[0018] The injection step of the recovery process may for example be carried out with a selected proportion of butane, at the selected bottom hole injection temperature and bottom hole injection pressure, so as to vertically expand the steam chamber at a rate higher than the rate of vertical steam expansion in the absence of butane. For example, the bottom hole injection pressure may be at or above 3000 kPa.
BRIEF DESCRIPTION OF THE DRAWINGS

[0019] Figure 1 is a graph illustrating cumulative oil production in embodiments of Example 1.

[0020] Figure 2 is a graph illustrating cumulative steam injection in embodiments of Example 1.

[0021] Figure 3 is a graph illustrating cumulative steam oil ratios in embodiments of Example 1.

[0022] Figure 4 is a graph illustrating enthalpy in place in embodiments of Example 1.

[0023] Figure 5 is a cross sectional view of an exemplary completion for an injector well.

[0024] Figure 6 is a cross sectional view of an exemplary completion for a production well, illustrating an embodiment employing gas lift.

[0025] Figure 7 is a cross sectional view of an exemplary completion for a production well, illustrating an embodiment employing an electronic submersible pump (ESP).

[0026] Figures 8A and 8B illustrate simulated reservoir methane saturation conditions, in terms of the gaseous mole fraction of methane times total gas saturation, in effect illustrating methane saturation in the gas phase. This is illustrated in a three dimensional view sliced along the plane of the well.
Both images illustrate the same point in time in alternative scenarios. Figure 8A
illustrates methane saturations within the reservoir when conventional SAGD is used during ramp-up, with no solvent addition. Figure 8B illustrates methane saturations within the reservoir when solvent, butane, is used in addition to steam during the ramp-up phase. A comparison of Figures 9A and 9B illustrates that solvent addition during ramp-up removes methane from the margins of the growing steam chamber, enabling the steam chamber to grow more quickly and evenly.

[0027] Figures 9A and 9B illustrate simulated reservoir temperature conditions, with a three dimensional view sliced along the plane of the well. Both images illustrate the same point in time in alternative scenarios. Figure 9A
illustrates temperatures within the reservoir when conventional SAGD is used during ramp-up, with no solvent addition. Figure 9B illustrates temperatures within the reservoir when solvent, butane, is used in addition to steam during the ramp-up phase.
The starbursts indicate points of steam injection. Injection pressures in the illustrated embodiment were 4500kPa. The solution GOR used in the simulation was about 8, and the simulation assumed large diameter tubing.

[0028] Figure 10 is a graphic summary of simulated oil production rates and cumulative steam oil ratios, over time, for an exemplary recovery process of the invention, compared to alternative processes. The exemplified well has a high pressure (4500kPa) gas lift phase followed by 2500kPa steady steaming period.
Blowdown is shown at 60% well recovery factor (RF). Three scenarios are shown:
full life SAGD (base case), late SAP (i.e. SAGD-only during gas lift ramp-up phase), early SAP (inject butane early - during ramp up). The simulation parameters are for a formation having 20m Pay, an 800m long well pair, with 100m spacing between well pairs.
DETAILED DESCRIPTION OF THE INVENTION

[0029] In one aspect, the invention provides aspects of an in situ hydrocarbon recovery start-up process. In select embodiments, a mobility-enhancing agent, such as a heated fluid, for example steam, is continuously circulated in a well, down, along and back up a wellbore that is open to the reservoir. Concurrent with circulation of the mobility-enhancing agent on a continuous basis, variations in wellbore pressure ranging between selected upper and lower pressure limits are imposed. The imposed pressure variations cause the circulating mobility-enhancing agent within the reservoir/wellbore system to move in a manner such that more rapid penetration of the reservoir by the mobility-enhancing agent is achieved when compared with that achieved using traditional steam circulation. As a result, start-up, as evidenced by early oil production, is accelerated.

[0030] In one aspect of the invention, the means by which hydrocarbon production start-up occurs involves the superposition of two concurrent mechanisms ¨ continuous circulation of a mobility-enhancing agent along a wellbore, and the imposition of a cyclic, or cycle-like, variation in wellbore pressure between specific upper and lower limits. The cyclic variation may be repetitive, and the pressure limits may be adjusted in alternative cycles or during a selected pressure cycle.

[0031] The upper pressure limit during this combined cycling-circulation process may be greater than or less than the reservoir pressure. Similarly, the lower pressure limit during this combined cycling-circulation process may be greater than or less than the reservoir pressure, albeit less than the upper pressure limit. In some embodiments, to effect or enhance the cycling-circulation process, artificial lift methods may be employed to produce fluids from the well, such as a pump or gas lift system.

[0032] In alternative embodiments, the imposed variation in wellbore pressure as a function of time may be either periodic or aperiodic.

[0033] The mobility-enhancing mechanism of the present invention may involve introduction of thermal energy into the reservoir, and/or it may involve introduction of substances which mix with the heavy oil to reduce viscosity. In the case of the first type of mobility-enhancing mechanism, one common means of introducing thermal energy into a reservoir involves the use of a heated mobilizing fluid such as steam. Other examples of mobility-enhancing mechanisms which involve introduction of thermal energy include hot water, electrical heating, and in situ combustion (i.e., introduction of an oxidant). In the case of the second type of mobility-enhancing mechanism, a common means of reducing the viscosity of the oil involves the introduction of a solvent that is at least partially miscible with some portion of the heavy oil or bitumen. Other examples of mobility enhancing mechanisms which may be non-thermal include surfactants. Alternatively, combinations of these two types of mechanism for increasing oil mobility may be utilized.

[0034] Pressure cycling, particularly with highly compressible circulating fluids, such as steam and/or solvent, involves a transient fluid flow regime.
Accordingly, to carry out concurrent pressure cycling, even over those time periods during a single cycle when the pressure may be maintained optionally at a relatively constant level, there will be variations in the rates at which fluids are circulated. In selected embodiments, pressures may for example be controlled by monitoring and adjusting a rate of mobilizing fluid injection into the well, and/or a rate of mobilizing fluid production from the well. For example, the mobilizing fluid pressure may be controlled by adjusting the rate of injection and/or the rate of production, to vary a bottom-hole wellbore circulation pressure in the well. Selected embodiments may involve monitoring a difference between a measure of mobilizing fluid injection and a measure of mobilizing fluid production, such as rates or volumes of injection and production.

[0035] In selected embodiments, methods of the invention may be carried out so as to provide more rapid hydrocarbon production start-up, as defined for example by acceleration of mobilized oil production from a well, compared to a start-up where the cycling mechanism is absent. In the specific instance where thermal energy, such as steam, is employed to accelerate start-up, that accelerated start-up may for example be associated with an increase in the enthalpy which is transferred from the wellbore into the reservoir, both during the start-up procedure, and residually after the start-up phase has been completed.

[0036] Alternative embodiments of the invention may be deployed in a wide variety of reservoir settings. As illustrated in the exemplary embodiments, in the case of a reservoir containing a viscous hydrocarbon which is contiguous with, and in hydraulic contact with, a high mobility zone, such as a water zone, process of the invention may be adapted by suitably controlling the pressure limits of the cycling procedure. The robustness and adaptability of selected methods of the invention are similarly exemplified by exemplified embodiments in which a solvent is injected along with steam. In these embodiments, the results achieved parallel the results obtained using steam as the only mobilizing fluid. Accordingly, application of pressure cycling concurrent with circulation of the steam/solvent fluid improves performance when compared with the case where there is no concurrent cycling of said fluid. Also, where concurrent cycling is employed with a steam/solvent fluid mix, exemplified performance is better than with concurrent cycling employing steam only. The exemplified embodiments illustrate that mobilizing fluid circulation with concurrent pressure cycling is a start-up approach which results in start-up performance improvement compared with circulation at sustained pressure, irrespective of whether the circulation fluid involves steam only, or steam plus solvent, and irrespective of whether the viscous hydrocarbon reservoir is in hydraulic contact with a high mobility zone. Further, if the circulating mobilization fluid is steam plus solvent, then even in the case of a sustained circulation pressure, the presence of the solvent is beneficial in terms of performance improvement ¨ illustrating benefits available from early use of solvents in the start-up process.

[0037] Following start-up in accordance with various aspects of the invention, a recovery process may be implemented which continues to use the same mobilizing agent as that used in the start-up, or an alternative mobilizing agent may be deployed. For example, start-up may be carried out using steam, and steam may then be used during the subsequent recovery process (such as a SAGD or CSS
process). Alternatively, one my employ steam plus solvent during the start-up process, and continue using those same fluids during the subsequent recovery process (such as a conventional solvent-aided process). Alternatively, steam may be used for start-up, and then the recovery process may be continued by switching to the use of steam plus solvent, for example during ramp-up of a SAGD
process. In contrast, steam plus solvent may be used for start-up, and then the recovery process may switch to the use of steam.

[0038] Various aspects of the recovery processes of the invention involve the drilling of SAGD well pairs. In general terms, in selected embodiments, these well pairs may for example be drilled in keeping with the following parameters.
There may be approximately 5 m depth separation between the injection well and production well. The SAGD well 10 pair may for example average approximately m in length. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the SAGD base. If saline bottom water exists (without a shale break) placement may vary to optimize recovery.

[0039] Alternative aspects of the invention involve completing wells in various configurations. Exemplary completions for injector, producer on gas lift and producer on electronic submersible pump (ESP) are shown in Figures 5, 6 and 7 respectively.
[0039A] Figure 5 shows an injection well (100), in which is shown: H-

40 ST&C
surface casing (339.7 mm 71.43 kg/m), L-80 QB2 production casing (244.5 mm 59.53 kg/m), outer tubing (101) (139.7 mm tubing; 114.3 mm tubing), a liner hanger (102), inner tubing (103) (73.0 mm tubing; 60.3 mm tubing; 73.0 mm tubing) and a liner (177.8 mm 39.7 / 34.2 kg/m L-80 /K55 QB2). Liner slotting includes a first slot just past the liner hanger (102) and a last slot at the toe.
[0039B] Figure 6 shows a production well (200), in which is shown: H-ST&C surface casing (339.7 mm 71.43 kg/m), a L-80 QB2 production casing (244.5 mm 59.53 kg/m), outer tubing (201) (139.7 mm tubing), an instrument string (202) (31.7 mm coil), inner tubing (203) (73.0 mm tubing), a liner hanger (204) and a liner (177.8 mm 38.7 / 34.2 kg/m L-80 /K55 QB2). Liner slotting includes a first slot just past the liner hanger (204) and a last slot at the toe.

[0039C] Figure 7 shows a production well (300), in which is shown H-40 ST&C surface casing (339.7 mm 71.43 kg/m), L80 0B2 production casing (244.5 mm 59.53 kg/m), production tubing (301) (114.3 mm tubing; ESP ¨ landed @ heel), a bubble tube (302) (48.3 mm Ii tbg landed @ heel), a scab liner string (303) (244.5 mm Schlumberger MH hanger;
114.3 mm; UPP;
88.9 mm), a liner hanger top (304) and a liner (177.8 mm 34.23 / 38.69 kg/m L80 QB2). Liner slotting includes a first slot just past the liner hanger and a last slot at the toe.
[0040] In alternative aspects, the invention provides processes for removing fluids from subterranean formations, and in particular for removing hydrocarbons and non-condensing gases from a vertically expanding steam chamber during the ramp-up phase of a solvent assisted SAGD process.

[0041] In selected embodiments, the arrangement of wells within a formation will follow the pattern of typical SAGD process. As such, the reservoir will have within it a steam chamber with a peripheral zone of mobile hydrocarbons. A generally horizontal segment of a production well will be in fluid communication with the zone of mobile hydrocarbons, and a generally horizontal segment of an injection well will be in fluid communication with the steam chamber. The horizontal segment of the injection well will generally be parallel to and vertically spaced apart above the horizontal segment of the production well. As established during the start-up phase of a SAGD process, there will typically be one or more mobile fluid regions - 13a -Date recue / Date received 2021-12-10 providing fluid communication between the horizontal segments of the injection well and the production well.

[0042] Aspects of the invention involve injecting steam with a selected amount of hydrocarbon solvent, for example from about 1% to about 20% by mass butane.
Injection typically takes place through the horizontal segment of the injection well, at a selected bottom hole injection pressure, typically less than the formation fracture pressure, such as 3000 kPa. Conditions are typically selected so that injection fluids enter predominantly in a gaseous form. In this way, the injected fluids mobilize the heavy oil and may also mobilize non-condensing gas within the reservoir. The mobilization of fluids gives rise to the expansion of the steam chamber, for example by vertical expansion during ramp-up.

[0043] Mobilized hydrocarbons are collected from the reservoir through the production well. Non-condensing gas mobilized from the steam chamber may also be recovered, thereby removing non-condensing gases that might otherwise form insulating layers within the steam chamber. In some embodiments, the production well may be throttled to adjust production conditions, for example by maintaining the temperature of the produced bitumen stream just below saturated steam conditions, to prevent production of steam.

[0044] In selected embodiments, the injection of fluids is carried out with a selected proportion of solvent, such as a non-aqueous solvent or organic solvent (including hydrocarbon solvents, C3 to C8 alkanes, ethers such as dimethyl ether or alcohols such as ethanol, or mixtures thereof) at a selected injection temperature and injection pressure, so as to vertically expand the steam chamber at a rate higher than the rate of vertical steam expansion in the absence of solvent (such as butane). In this way, the ramp-up phase of a solvent assisted SAGD process may be carried out more quickly, speeding the arrival of peak hydrocarbon production.
In addition, or in the alternative, processes of the invention may be carried out so as to provide improved steam chamber conformance, so that the solvent, such as butane, removes methane gas from the formation so that it is produced at the producer well, thereby facilitating the development of a more uniformly distributed steam chamber along the length of the wellbore.

[0045] Although various embodiments of the invention are disclosed herein, many adaptations and modifications may be made within the scope of the invention in accordance with the common general knowledge of those skilled in this art. Such modifications include the substitution of known equivalents for any aspect of the invention in order to achieve the same result in substantially the same way. Numeric ranges are inclusive of the numbers defining the range. The word "comprising" is used herein as an open-ended term, substantially equivalent to the phrase "including, but not limited to", and the word "comprises" has a corresponding meaning. As used herein, the singular forms "a", "an" and "the" include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to "a thing" includes more than one such thing. Citation of references herein is not an admission that such references are prior art to the present invention. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.
Examples

[0046] These examples illustrate various aspects of the invention, evidencing a variety of reservoir configurations and operating conditions. Selected examples are illustrative of advantages that may be obtained compared to alternative start- up techniques, and these advantages are accordingly illustrative of particular embodiments and not necessarily indicative of the characteristics of all aspects of the invention.

Date recue / Date received 2021-12-10 Example 1: CSS

[0047] This example relates to a relatively homogeneous oil sand of moderate thickness penetrated by a single horizontal well. The well undergoes steam start-up, after which the well is operated using the cyclic steam stimulation (CSS) recovery process. In practice, conventional SAGD would generally be excluded as the follow-up recovery process for reservoirs of this kind, because of the relatively thin oil sands pay zone.
Three start-up alternatives, all involving steam circulation, were simulated.
In one case, there is no pressure cycling, and the circulation pressure is maintained at a relatively high level (overbalanced case). In a second case, again there is no pressure cycling, and the circulation pressure is maintained at a relatively low level (underbalanced case). In the third case, processes of the invention are employed so that, concurrent with the steam circulation, the circulation pressure is cycled between a high pressure limit (equal to that of the overbalanced case) and a low pressure limit (equal to that of the underbalanced case). Following each of these three start-up alternatives, the well is subject to cyclic steam stimulation, and the performance results are compared.

[0048] Pressures and pressure limits during circulation for the three start-up cases are:
1. Sustained Circulation Pressure - overbalanced operation: 5,000 kPa;
2. Sustained Circulation Pressure - underbalanced operation: 400 kPa;
3. Circulation Pressure Limits during Concurrent Cycling: Upper 5,000 kPa - Lower 400 kPa.

[0049] The salient characteristics of the reservoir, as simulated, in all three start-up cases are:
Initial reservoir pressure 2500 kPa Oil Sand Thickness 12 m Oil Viscosity 50,000 cp Horizontal Permeability 2,500 mD
Vertical Permeability 750 mD

Porosity 0.275 Irreducible Water Saturation 0.50

[0050] Start-up was performed for 60 days for each of the three start-up alternatives listed above. That is, in alternative 1, a sustained (i.e., constant) steam circulation pressure of 5,000 kPa was maintained for the 61 day start-up period. In alternative 2, a sustained circulation pressure of 400 kPa was maintained for the 61 day start-up period. And in alternative 3, circulation was maintained throughout the 61 day start-up period, but with concurrent cycling of the circulation pressure between the 5,000 kPa and 400 kPa limits. Specifically, in alternative 3, nine cycles involving, for each cycle, three days at the high pressure limit and three days at the low pressure limit were carried out, corresponding to a total elapsed time since inception of 54 days. Subsequently, steam was injected at the high pressure limit for six days, after which the well's pressure was reduced to 400 kPa and the well was produced for 24 days (total elapsed time 84 days).

[0051] Following the foregoing start-up stages, five post start-up CSS
injection/production cycles were carried out. During each cycle, steam was injected at 5,500 kPa for a period of time, as illustrated in Table 1A, which summarizes the CSS schedule, after which the well was placed on production at a bottomhole pressure of 400 kPa. Total elapsed time for both the cyclic circulation start-up period and the subsequent recovery process involving Low Pressure Cyclic Steam Stimulation (LPCSS) was just over one year.

Table 1A: Cyclic Steam Stimulation Schedules Cycle # Injection Soak (days) Production Total (days) (days) (days)

[0052] For the three start-up alternatives described above, followed by the five 5 CSS cycles, Figures 1,2,3 and 4 illustrate respectively the Cumulative Oil Production, the Cumulative Steam Injection, the Cumulative Steam / Oil Ratio (CSOR) and the Cumulative Residual Enthalpy within the reservoir. For closer comparison of outcomes, the cumulative oil produced during start-up for the three alternatives and the cumulative steam-oil ratio after one year of operation are also tabulated in Table 1B.
Table 1B: Performance Comparison for Case 1, Start-up Alternatives 1, 2 and 3 Post Start-up Cyclic Start-up* Cum Start-up Stimulation Cum. Oil SOR @
ALTERNATIVE Circulating Fluid Injection Fluid Pro. M3 365 Days 1. Overbalanced sustained pressure circulation J5000 K_paL Steam Steam 0 _______ 3.60 2. Underbalanced sustained pressure circulation (400 kPa) Steam Steam 326 3.60 3. Concurrent Cycling between 5000 & 400 kPa Steam Steam 349 3.40 * Start-up period in all cases is 61 days.

[0053] As indicated, throughout most of the first year, the alternative for which pressure is cycled during start-up circulation (i.e., alternative 3) results in greater oil production during the start-up period when compared with the non-cycling start-up alternatives, with that advantage in accelerated oil production carried through at least the first year of operation. Correspondingly, while cumulative steam/oil ratios for the three alternatives are comparable after one year, throughout most of that year the steam requirement per barrel of oil produced is noticeably less for alternative 3.
Example 2

[0054] This example relates to a relatively homogeneous oil sand of sufficient thickness and quality to justify the application of conventional SAGD, or of related solvent-aided recovery processes, following start-up. The salient reservoir properties are as follows:
Initial reservoir pressure 3000 kPa Oil Sand Thickness 45 m Oil Viscosity 2,000,000 cp Horizontal Permeability 6000 mD
Vertical Permeability 4200 mD
Porosity 0.33 Irreducible Water Saturation 0.215

[0055] The following alternative start-up techniques prior to implementation of the SAGD or Solvent-Aided recovery processes were simulated:
1. Sustained steam circulation at 5000 kPa (overbalanced);
2. Sustained steam circulation at 5000 kPa with added Butane injection (overbalanced);
3. Sustained steam circulation at 2000 kPa (underbalanced);
4. Cyclic (5000/4000 kPa) with concurrent steam circulation;
5. Cyclic (5000/4000 kPa) with concurrent steam circulation (injector only);
6. Cyclic (5000/4000 kPa) steam circulation with added Butane injection;
7. Cyclic (5000/4000 kPa) steam circulation with added Butane injection;
8. Cyclic (5000/400 kPa) steam circulation.

[0056] Characteristics of these alternative embodiments were as follows.
Where steam is the only injected start-up fluid, oil produced during start-up for the alternatives where a sustained pressure is applied during circulation (alternatives 1 and 2) is less than the start-up oil produced for the corresponding alternatives where steam circulation occurs with concurrent pressure cycling (alternatives 3, 4 and 5). The results are summarized in Table 2 below, for the following cases:
Circulation Only - No Cycling:
1. Overbalanced Circulation (5000 kPa at producer; 4800 at injector) 2. Overbalanced Circulation with Added Butane (5000 kPa at both wells) followed by SAP
3. Underbalanced Circulation (2000 kPa at producer; 1800 at injector) Circulation with Concurrent Cycling:
4. Cycling between 5000 & 4000 kPa (both wells) 5. Cycling between 5000 & 4000 kPa (injector only) 6. Cycling between 5000 & 4000 kPa with Added Butane (both wells) 7. Cycling between 5000 & 4000 kPa with Butane (both wells) followed by SAP
8. Cycling between 5000 & 400 kPa (both wells) Table 2: Start-up Performance Comparison ¨ M. Zeman Simulations RECOVERY STARTUP*
CIRCULATING PROCESS CUM OIL Cum SOR
Case FLUID INJECTION FLUID PROD M3 @ 365 D
1 Steam Steam 315 2.02 2 Steam + Butane Steam + Butane 546 1.35 3 Steam Steam 536 2.16 4 Steam Steam 570 2.18 5 Steam Steam 618 2.25 6 Steam + Butane Steam 1395 2.04 7 Steam + Butane Steam + Butane 1395 1.68 8 Steam Steam 1179 2.24 * Start-up period in all cases is 60 days.

[0057] Where steam plus a solvent (butane) is injected during start-up, the same directional outcome is again evident. That is, oil produced during start-up is much greater for the alternatives where concurrent cycling is employed (alternatives 6 and 7) than for the operation based on sustained pressure during start-up (alternative 2).

[0058] These embodiments illustrate selected advantages of concurrent circulation and pressure cycling over sustained pressure circulation irrespective of whether the injected fluids involve steam only or steam plus solvent.
Comparisons between cases involving steam only and the corresponding cases employing steam plus solvent are also illustrative. Specifically, recovery process operations with steam plus solvent (e.g., Solvent-Aided Process) achieve lower steam-oil ratios than the corresponding steam-only recovery process operations (e.g., SAGD).
Example 3: Oil sands reservoirs with overlying water ¨ steam only.

[0059] This example compares, for two different reservoirs, SAGD start-up performance using aspects of the present invention (i.e., circulation plus concurrent pressure cycling), with circulation in which there is no concurrent pressure cycling.
A common feature of both reservoirs is that the bitumen zone is directly overlain by, and in hydraulic contact with a mobile water zone. All of the alternative approaches for Example 3 involve steam only as the injected circulating fluid. The alternative approaches presented in Example 3 involve operation at generally lower maximum pressures than the maximum pressures employed in cases 1 and 2. This reflects an intentional limitation of the maximum pressures for the two reservoirs in Example 3 to avoid premature or unwanted breakthrough of injected steam into the overlying water zone.

[0060] Table 3 summarizes the Example 3 outcomes of simulations for both reservoirs using four different start-up alternatives. The first start-up alternative includes both wells in the pair and involves circulation at higher pressure with no pressure cycling. Alternatives 2 and 3 practice the present invention in that pressure cycling is concurrent with circulation. Alternative 4 involves circulation at lower pressure with no cycling. Alternatives 2, 3 and 4 reflect an embodiment wherein the start-up procedure is implemented at the producer only. The alternative embodiments are summarized below:
Reservoir A with overlying water:
1. Conventional High Pressure Circulation (Both Wells) 2. Cyclic Low Pressure Circulation (Producer Only) 3. Cyclic High Pressure Circulation (Producer Only) 4. Low Pressure Circulation (Producer Only) Reservoir B with overlying water:
1. Conventional High Pressure Circulation (Both Wells) 2. Cyclic Low Pressure Circulation (Producer Only) 3. Cyclic High Pressure Circulation (Producer Only) 4. Low Pressure Circulation (Producer Only) Simulation Alternatives ¨ Details:
1. Conventional High Pressure Circulation. No cycling.
= Circulate both wells = Producer pressure 2800 (Reservoir A), 2300 (Reservoir B);
Injector pressure 2600kPa (A), 2100kPa (B) 2. Cyclic Low Pressure Circulation = Circulate producer only = 5 day cycles varying pressure between 500 and 1500 kPa (reservoirs A and B) 3. Cyclic High Pressure Circulation = Circulate producer only = Cycling pressures - Reservoir A 500-2800kPa; Reservoir B
500-2300kPa 4. Low Pressure Producer Only Circulation. No cycling.
= Circulate producer only at 1500 kPa Table 3: Performance Comparison Start-up Start-up SAGD
Cum. Oil Period Cum.
Case Prod. M3 Months SOR
1 Reservoir A 107 3 2.68 2 Reservoir A 850 4 2.24 3 Reservoir A 1135 4 2.26 4 Reservoir A 549 __________ 5 2.59 1 Reservoir B 57 3 2.12 1 2 Reservoir B 1325 3 1.37 3 Reservoir B 1945 3 1.36 L4 Reservoir B 635 3 1.34

[0061] The results indicate that, for both reservoirs A and B, oil produced during start-up is significantly higher for the operations which employ the method of the present invention (i.e., in which circulation and pressure cycling are concurrent) than for the cases where there is no concurrent pressure cycling. Also, when practicing the present invention, cumulative steam-oil ratio performance is as good as, and in some instances better than, performance achieved using the alternative approaches which do not practice the present invention.
Example 4: Solvent Ramping Following Start-up

[0062] One aspect of the invention involves the use of a non-aqueous or organic .. solvent, such as a hydrocarbon solvent, such as a C3 to 08 alkane, an ether, such as dimethyl ether, or an alcohol, such as ethanol, or mixtures thereof, to remove a non-condensing gas from a SAGD steam chamber, with or without pressure cycling. Selected embodiments of the invention use butane as the solvent. In alternative embodiments, mixtures of alkanes and/or other organic or hydrocarbon solvents may be used. For example, a mixture of solvents may be selected such that the mixture approximates the properties of a selected solvent, such as butane, such as the density-increasing and/or viscosity-reducing properties of butane.

[0063] The use of solvents in aspects of the invention may be particularly .. advantageous during the ramp-up phase of a SAGD process, for example following a pressure cycling start-up phase, which may be carried out so as to remove layers of non-condensing gas from the upper regions of an expanding steam chamber.
This effect is illustrated in Figure 8, which shows the mobilization and displacement of methane in an expanding steam chamber in a solvent assisted process, Figure 8B, in contrast to a SAGD process using steam alone, Figure 8A. In this way, processes of the invention can be used to attenuate the insulating effect of non-condensing gases, allowing for more rapid and uniform steam chamber expansion, particularly vertical expansion. This is illustrated in Figure 9, in which a comparison of Figures 9A and 9B illustrates that solvent addition during ramp-up increases the conformance of the steam chamber and decreases the amount of time required for the chamber to develop to the top of the oil-containing strata of the reservoir.
Alternative simulations at injection pressures of approximately 3000kPa have similarly exemplified that the addition of solvent during ramp-up increases the conformance of the steam chamber and decreases the amount of time required for the chamber to develop to the top of the oil-containing strata.

[0064] Figure 10, summarizes the surprising effects of introducing a hydrocarbon solvent during the ramp-up phase of a SAGD process. The initiation of a solvent aided process immediately following circulation start-up provides dramatic improvements to the performance of the well pair. By improving the steam chamber rise rate and conformance, the time each well pair operates in the ramp up mode of operation is reduced. The ramp-up stage is energetically expensive, generally involving higher steam demand, relatively high pressure, for example up to 5,400 kPag bottom hole pressure (BHP). By accelerating ramp-up, peak oil production rates may occur earlier in the process, which in turn accelerates the next phase of the wellpair life, steady steaming, which requires less steam.

Claims (19)

1. A method of initiating hydrocarbon production in a well having a wellbore in a subterranean formation bearing a heavy oil, the method comprising:
a) circulating a mobilizing fluid in the wellbore to apply a reservoir stimulation pressure to a region of the formation adjacent to the well, wherein circulation comprises injecting the mobilizing fluid into the well and producing the mobilizing fluid from the well; and concomitantly, b) cycling the reservoir stimulation pressure between a high wellbore circulation pressure and a low wellbore circulation pressure, so as to oscillate a pressure gradient in the region of the formation adjacent to the wellbore, providing:
i) an outward pressure gradient from higher wellbore circulation pressures to lower surrounding formation pressures when mobilizing fluid injection pressure is increased to the high wellbore circulation pressure; and, ii) an inward pressure gradient from higher surrounding formation pressures to lower wellbore circulation pressures when mobilizing fluid injection pressure is decreased to the low wellbore circulation pressure; and, c) repeating the cycling of the reservoir stimulation pressures, so as to mobilize the heavy oil in the region of the formation adjacent to the well to provide mobilized heavy oil.

2. The method of claim 1, further comprising producing the mobilized heavy oil with produced mobilizing fluid from the well.

3. The method of claim 1 or 2 wherein the mobilizing fluid comprises a heated fluid that delivers thermal energy to the region of the formation adjacent to the well.

4. The method of claim 3, wherein the mobilizing fluid comprises steam.

5. The method of any one of claims 1 to 4, wherein the mobilizing fluid comprises an organic solvent, a non-aqueous solvent, a hydrocarbon solvent, a to 08 alkane solvent, an ether solvent, a dimethyl ether solvent, an alcohol solvent, an ethanol solvent, or solvent mixtures thereof.

The method of any one of claims 1 to 5, wherein the high wellbore circulation pressure is greater than initial bottom hole reservoir pressure.

7. The method of any one of claims 1 to 5, wherein the high wellbore circulation pressure is lower than initial bottom hole reservoir pressure.

8. The method of any one of claims 1 to 7, wherein the low wellbore circulation pressure is lower than initial bottom hole reservoir pressure.

9. The method of any one of claims 1 to 7, wherein the low wellbore circulation pressure is higher than initial bottom hole reservoir pressure.

10. The method of any one of claims 1 to 9, wherein the formation is an oil sands formation, and the high wellbore circulation pressure is a dilation pressure sufficient to dilate the oil sands in the region of the formation adjacent to the well.

11. The method of any one of claims 1 to 10, wherein the well is a member of a well pair having first and second wells, the first and second wells each having horizontal segments that are generally parallel, and are vertically spaced apart by an inter-well region of the formation.

12. The method of claim 11, wherein both wells of the well pair are subject to the circulating, cycling and repeating steps.

13. The method of claim 11 or 12, wherein the circulating, cycling and repeating steps are carried out so as to establish fluid communication between the wells of the well pair.

14. The method of any one of claims 11 to 13, wherein the first well is an injection well and the second well is a production well, the well pair forming paired injection and production wells of a steam assisted gravity drainage well pair.

15. The method of claim 14, wherein the circulating, cycling and repeating steps are carried out during the start-up phase of a steam assisted gravity drainage production system.

16. The method of claim 15, wherein the circulating, cycling and repeating steps of the start-up phase are followed by a recovery phase for removing fluids from the subterranean formation, the recovery phase comprising:
a) forming a steam chamber in the reservoir, the steam chamber bearing heavy oil and a non-condensing gas, the steam chamber having a peripheral zone of mobile hydrocarbons, wherein:
i) the generally horizontal segment of the production well is in fluid communication with the zone of mobile hydrocarbons;
ii) the generally horizontal segment of the injection well is in fluid communication with the steam chamber, generally parallel to and vertically spaced apart above the horizontal segment of the production well; and, iii) one or more mobile fluid regions provide fluid communication between the horizontal segments of the injection well and the production well in the inter-well region;
b) injecting an injection fluid comprising from about 1% to about 20%
by mass organic solvent with steam through the horizontal segment of the injection well at a selected bottom hole injection pressure, and at a bottom hole injection temperature, so that the injection fluid is substantially in a gaseous state at the injection pressure, so as to concurrently mobilize the heavy oil, mobilize non-condensing gas, and vertically expand the steam chamber; and, c) recovering the mobilized hydrocarbons and non-condensing gas from the reservoir through the production well, thereby removing non-condensing gases from the steam chamber.

17. The method of claim 16, wherein the organic solvent is butane.

18. The process of claim 16 or 17, wherein the injecting step of the process is carried out with a selected proportion of butane, at the selected bottom hole injection temperature and bottom hole injection pressure, so as to vertically expand the steam chamber at a rate higher than the rate of vertical steam expansion in the absence of butane.

19. The process of any one of claims 16 to 18, wherein the bottom hole injection pressure is at or above 3000 kPa.