CA3052413A1 - Process for producing hydrocarbons from a subterranean hydrocarbon-bearing formation - Google Patents

Abstract

A process for producing hydrocarbons from a hydrocarbon-bearing formation includes injecting mobilizing fluid into a well. The well has pipe sections coupled together and includes a perforated first pipe section having a first inner diameter through which the mobilizing fluid is injected, a second pipe section coupled to the perforated first pipe section and having a second inner diameter smaller than the first inner diameter, and a perforated third pipe section coupled to the second pipe section and having third inner diameter larger than the second inner diameter.

Mobilizing fluid and the hydrocarbons that flow through perforations in the third pipe section and into ports in production tubing that extends through the pipe sections, are produced. The mobilizing fluid injected into the well is restricted from passing from the perforated first pipe section into the second pipe section by the second inner diameter.

Description

PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION
Technical Field [0001] The present invention relates to the production of hydrocarbons such as heavy oils and bitumen from a hydrocarbon-bearing formation utilizing a single well extending generally horizontally in the hydrocarbon-bearing formation.
Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the northern Alberta oil sands that are not susceptible to standard oil well production technologies. The hydrocarbons in reservoirs of such deposits are too viscous to flow at commercially relevant rates at the virgin temperatures and pressures present in the reservoir. For such reservoirs, thermal techniques may be utilized to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons utilizing spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). In general, a SAGD process may be described as including three stages: the start-up stage; the production stage; and the wind-down (or blowdown) stage. The production stage may be described as including further stages such as, for example, a ramp-up stage and a plateau stage.

[0004] In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well (injector), into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well (producer) that is near the injection well and is vertically spaced from the injection well. The injection and production wells are situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon reservoir to collect the hydrocarbons that flow toward the base of the reservoir.

[0005] The SAGD process is understood to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir and water originally present in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber.
The hydrocarbons, the water originally present, and the aqueous condensate are typically referred to collectively as emulsion. The emulsion accumulates such that the liquid / vapor interface is located below the steam injector and above the producer. The emulsion is collected and produced from the production well. The produced emulsion is separated into dry oil for sales and produced water, comprising the water originally present and the aqueous condensate.

[0006] With the complexity and cost of drilling associated with separate injection and production wells, several approaches to recovery of viscous hydrocarbons utilizing a single well have been proposed. Such approaches include both vertical single well recovery and horizontal single well recovery.

[0007] In such approaches, a mobilizing or displacement fluid, such as steam is utilized. For example, SAGD, or a cyclic steam simulation (CSS) approach in which steam is injected and, after a soaking period, production of the hydrocarbons is carried out, may be utilized.

[0008] Hydrocarbons are commonly left unrecovered, resulting in relatively low recovery. The unrecovered hydrocarbons are due, at least in part, to the difference in viscosity between the mobilizing or displacement fluid and the oil.
Mobilizing or displacing of the more viscous oil, by the less viscous steam tends to promote non-uniform advance of the displacement front, including the development of channels or fingers, and consequent poor overall recovery. This non-uniformity of displacement may be abetted by differences in density between the viscous hydrocarbons and displacing fluids in situations where segregation of the fluids due to the influence of gravity is employed. Such non-uniformity adversely affects recovery, particularly in a process in which the desired direction of displacement is horizontal. Non-uniform displacement resulting in poor recovery has made recovery of hydrocarbons from thin formations, referred to as thin pay zones, less economically favourable or even unfavourable.

[0009] Improvements in recovery of hydrocarbons are desirable.
Summary

[0010] According to an aspect of an embodiment, a process is provided for producing hydrocarbons from a hydrocarbon-bearing formation. The process includes injecting mobilizing fluid into a single well that extends generally horizontally in the hydrocarbon-bearing, from a heel to a toe, the single well having pipe sections coupled together and including a perforated first pipe section having a first inner diameter through which the mobilizing fluid is injected into the hydrocarbon-bearing formation, a second pipe section coupled to the perforated first pipe section and having a second inner diameter that is smaller than the first inner diameter, and a perforated third pipe section coupled to the second pipe section and having third inner diameter that is larger than the second inner diameter. Fluids are produced, including the mobilizing fluid and the hydrocarbons that flow through perforations in the perforated third pipe section and into ports in production tubing that extends through the pipe sections, from a location proximal the toe of the single well to a wellhead of the single well to provide produced fluids to the wellhead. The flow of the mobilizing fluid injected into the single well is restricted from passing from the perforated first pipe section into the second pipe section by the second inner diameter that is smaller than the first inner diameter, relative to an outer diameter of the production tubing.

[0011] According to another aspect of an embodiment, a system is provided for producing hydrocarbons from a hydrocarbon-bearing formation. The system includes a single well extending generally horizontally in the hydrocarbon-bearing formation from a heel to a toe. The single well includes pipe sections coupled together. The pipe sections include a perforated first pipe section having a first inner diameter for the injection of a mobilizing fluid into the hydrocarbon-bearing formation, a second pipe section coupled to the perforated first pipe section and having a second inner diameter that is smaller than the first inner diameter, and a perforated third pipe section coupled to the second pipe section and having a third inner diameter that is larger than the second inner diameter, to facilitate flow of fluids produced from the hydrocarbon-bearing formation into the third pipe section.
The single well also includes production tubing extending from a top of the single well to a location proximal the toe of the single well, the production tubing extending through the pipe sections, a portion of the production tubing within the perforated third pipe section including ports to facilitate the flow of the fluids produced from the hydrocarbon-bearing formation into the production tubing.
The second inner diameter of the second pipe section is sized relative to an outer diameter of the production tubing to inhibit flow of the mobilizing fluid from the first pipe section into the second pipe section.
Brief Description of the Drawings

[0012] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0013] FIG. 1 is a schematic sectional view of a system including a single well in accordance with one example of the present invention;

[0014] FIG. 2 is a schematic sectional view through a portion of the single well in accordance with one example of the present invention;

[0015] FIG. 3 is a schematic sectional view through a portion of a single well in accordance with another example of the present invention;

[0016] FIG. 4 is a flowchart illustrating a process for producing hydrocarbons from a hydrocarbon bearing formation, in accordance with an aspect of the present invention;

[0017] FIG. 5 is a graph showing corresponding temperatures and pressures for suitable solvents for use in the process of FIG. 4;

[0018] FIG. 6 is a simulation diagram illustrating spread of propane in a hydrocarbon-bearing formation after 480 days, according to one example of the process of FIG. 4;

[0019] FIG. 7 is a graph illustrating production rate of oil and solvent over time utilizing the process of FIG. 4.
Detailed Description

[0020] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0021] The disclosure generally relates to a system and a process for producing hydrocarbons from a hydrocarbon-bearing formation. The process includes injecting mobilizing fluid into a single well that extends generally horizontally in the hydrocarbon-bearing, from a heel to a toe, the single well having pipe sections coupled together and including a perforated first pipe section having a first inner diameter through which the mobilizing fluid is injected into the hydrocarbon-bearing formation, a second pipe section coupled to the perforated first pipe section and having a second inner diameter that is smaller than the first inner diameter, and a perforated third pipe section coupled to the second pipe section and having a third inner diameter that is larger than the second inner diameter. Fluids are produced, including the mobilizing fluid and the hydrocarbons that flow through perforations in the perforated third pipe section and into ports in production tubing that extends through the pipe sections, from a location proximal the toe of the single well to a wellhead of the single well to provide produced fluids to the wellhead. The flow of the mobilizing fluid injected into the single well is restricted from passing from the perforated first pipe section into the second pipe section by the second inner diameter that is smaller than the first inner diameter, relative to an outer diameter of the production tubing.

[0022] Referring first to FIG. 1, a schematic view of an example of a system 100 including a single well 102 for use in the process for producing hydrocarbons is shown. The single well 102 includes a generally vertical portion 104 that extends from a wellhead 106 to a heel 108 and a generally horizontal portion 110 that extends between the heel 108 and a toe 112. The system 100 also includes recovery facilities, including a mobilizing fluid recovery facility 114 for recovery of a mobilizing fluid and recycling of the mobilizing fluid for re-injection into the hydrocarbon-bearing formation 116. In the example illustrated in FIG. 1, the generally horizontal portion 110 of the single well 102 extends along a thin hydrocarbon-bearing formation 116 of less than 20 meters in depth, referred to as a thin pay zone. The generally horizontal portion 110 of the single well 102 is generally located in a lower portion of the hydrocarbon-bearing formation 116, i.e., closer to a base than the top of the hydrocarbon-bearing formation, as illustrated for example in FIG. 1.

[0023] A sectional view of an example of a generally horizontal portion 110 of a single well 102 is illustrated in FIG. 2. The single well 102 includes pipe sections coupled together. The pipe sections include a perforated first pipe section 220, a second pipe section 222 coupled to the perforated first pipe section 220, and a perforated third pipe section 224 coupled to the second pipe section 222 and that has a third inner diameter.

[0024] Production tubing 226 extends from the wellhead (shown in FIG. 1), through the perforated first pipe section 220 in the generally horizontal portion 110, the second pipe section 222, and the perforated third pipe section 224, to a location near the toe 112 of the single well 102. In the generally horizontal portion 110, the production tubing 226 includes ports 228 through the sidewall to facilitate the flow of fluids produced from the hydrocarbon-bearing formation, into the production tubing 226.

[0025] The perforated first pipe section 220 has an internal diameter that is larger than the outer diameter of the production tubing 226 for the flow of mobilizing fluid from the wellhead, through the first perforated pipe section 220, and into the hydrocarbon-bearing formation via the perforations in the first perforated pipe section 220. Thus, the perforated first pipe section 220 is sized to facilitate the flow of mobilizing fluid between the production tubing 226 and the perforated first pipe section 220.

[0026] The second pipe section 222 is coupled to the perforated first pipe section 220 and has an internal diameter that is close to that of the outer diameter of the production tubing 226 to inhibit the flow of the mobilizing fluid that flows through the perforated first pipe section 220, into the second pipe section 222. For example, the internal diameter of the second pipe section 222 may be less than about 5mm larger than the outer diameter of the production tubing 226. Thus, the internal diameter of the second pipe section 222 is sufficiently larger for feeding the production tubing 226 through the second pipe section 222, and is sufficiently close in size to the outer diameter of the production tubing 226 to restrict the flow of mobilizing fluid into the second pipe section 222.

[0027] The perforated third pipe section 224 is coupled to the second pipe section 222 and has an internal diameter that is larger than that of the second pipe section 222 to facilitate the flow of produced fluids, including the mobilizing fluid and the hydrocarbons, through perforations in the perforated third pipe section 224 and to the production tubing 226.

[0028] Flow control devices 230 cooperate with the production tubing 226 to control the flow of fluids produced from the hydrocarbon-bearing formation into at least some of the ports 228 in the production tubing 226. Thus, the flow control devices 230 are associated with the ports 228 in the production tubing 226 to selectively open and close the associated ports in the production tubing 226.

[0029] Although the second pipe section 222 is depicted as being very short in the schematic illustration of FIG. 2, the second pipe section 222 may be very long, for example 150 meters, to separate the perforated first pipe section through which mobilizing fluid is injected into the hydrocarbon-bearing formation, from the perforated third pipe section 224 through which fluids from the hydrocarbon-bearing formation flow into the production tubing 226. In one example, the second pipe section 222 may be from about 10 meters to about 150 meters. A second pipe section length of less than about 10 meters, such as 2 meters, may also be successfully implemented. A length of 150 meters may be made of multiple segments joined together, for example, each 10 meters in length such that 15 segments are joined to provide a second pipe section of 150 meters.

[0030] A sectional view of another example of a single well is shown in FIG. 3.
As illustrated in FIG. 3, the length of the second pipe section 222 is longer than that shown in FIG. 2, for example, about 50 meters. Thus, the second pipe section illustrated in FIG. 3 provides a greater separation between the perforated first pipe section 220 and the perforated third pipe section 224. The remaining elements illustrated in FIG. 3 are similar to those described above with reference to FIG. 2 and are not described again herein in detail.

[0031] A flowchart illustrating a process for producing hydrocarbons from a hydrocarbon bearing formation is illustrated in FIG. 4. The process may contain additional or fewer subprocesses than shown or described, and parts of the process may be performed in a different order.

[0032] A mobilizing fluid is injected at 402 via the single well 102. The mobilizing fluid may be a solvent, for example, a solvent having 2 to 8 carbon atoms per molecule, such as propane. The solvent is injected via a liner, which includes the pipe sections referred to above, such that the solvent travels downhole between the liner and the production tubing 226. The solvent enters the perforated first pipe section 220 and, because the inner diameter of the second pipe section 222, to which the perforated first pipe section 220 is coupled, is much smaller than that of the perforated first pipe section 220, and is very close to the outer diameter of the production tubing 226, the flow of solvent is inhibited from entering the second pipe section 222. For example, the solvent flowing from the perforated first pipe section 220 directly into the second pipe section may be 5% or less of the solvent that is injected. Thus, the restriction introduced by the smaller diameter second pipe section 222, by comparison to the perforated first pipe section 220, forces the solvent out of the perforated first pipe section 220 through the perforations, and into the hydrocarbon-bearing formation. Optionally steam may be utilized to mobilize the fluid in addition to solvent or as an alternative to the solvent.

[0033] The solvent is injected in gaseous phase. Suitable solvents may include C3 to C5 hydrocarbons such as, propane, butane, or pentane.
Additionally or alternatively, a C6 hydrocarbon such as hexane may be utilized. A
combination of solvents including C3-C6 hydrocarbons and one or more heavier hydrocarbons may also be suitable in some embodiments. Solvents that are more volatile, such as those that are gaseous at standard temperature and pressure (STP), or significantly more volatile than steam at reservoir conditions, such as propane or butane, or even methane, may be beneficial in some embodiments.

[0034] The properties and characteristics of various candidate solvents are utilized to identify and select a suitable solvent. For a given selected solvent, the corresponding operating parameters during co-injection of the solvent with steam is also selected or determined in view the properties and characteristics of the selected solvent. In particular, the injection temperature is sufficiently high and the injection pressure is sufficiently low to ensure most of the solvent will be injected in the vapour phase into the vapour chamber. In this context, injection temperature and injection pressure refer to the temperature and pressure of the injected fluid in the injection well, respectively. The temperature and pressure of the injected fluid in the injection well may be controlled by adjusting the temperature and pressure of the fluid to be injected before it enters the injection well. The injection temperature, injection pressure, or both, may be selected to ensure that the solvent is in the gas phase upon injection from the injection well into the vapour chamber.

[0035] The mobilizing fluid utilized may be dependent on reservoir. For example, in relatively thin hydrocarbon-bearing formations, a "washing effect"
of bitumen may play a role. This "washing effect" relates to injection of solvent in liquid phase or injection of solvent in the transitional phase from gas to liquid. In this case, the solubility of the injected solvent in oil is relatively fast compared to solvent injected in high temperature gaseous phase conditions. For example, at 3000 kPa solvent butane may be injected at 200 C or into a 200 C steam chamber, yielding a continuous gaseous phase until the solvent cools to about 125 C.
The "washing effect" occurs in situations in which solvent butane is injected at 150 C or into a 150 C steam chamber, resulting in gaseous injection and quick or almost immediate transition of the solvent to the liquid or oleic phase. Such a process may be beneficial in inhibiting or reducing solvent losses to gaseous overburdens by the introduction of the solvent in the liquid phase or transitional phase.
Additionally, the solubility of the solvent in oil may advance viscosity reduction, oil upgrading and increased rate of recovery of the solvent. A temperature of the solvent of at least 60 C is utilized to reduce the viscosity of the oil to advance its flow. With greater formation heights, more gaseous mobilizing fluid may be utilized to recover the oil in the higher areas.

[0036] A graph showing corresponding temperatures and pressures for suitable solvents is illustrated in FIG. 5. Suitable injection pressures and corresponding temperatures are identifiable from the graph of FIG. 5. The dashed line at 3000 Kpa indicates one possible reservoir pressure. To inject solvent in vapour phase, the corresponding temperature for each solvent is indicated utilizing the graph. According to a particular example, propane may be injected at 2000 kPa and 60 C in gaseous phase and once the propane mixes with oil at the interface via solubility or heat-transfer, may be produced in oleic phase.

[0037] Solvents may be selected based on reservoir characteristics such as, the size and nature of the pay zone in the reservoir, properties of fluids involved in the process, and characteristics of the formation within and around the reservoir.
For example, a relatively light hydrocarbon solvent such as propane may be suitable for a reservoir with a relatively thick pay zone, as a lighter hydrocarbon solvent in the vapour phase is typically more mobile within the heated vapour chamber.

[0038] Additionally or alternatively, solvent selection may include consideration of the economics of heating a selected particular solvent to a desired injection temperature.

[0039] For example, lighter solvents, such as propane and butane, are efficiently injected in the vapour phase at relatively low temperatures at a given injection pressure. In comparison, efficient pure steam injection in a SAGD
process typically requires a much higher injection temperature, such as about 200 PC
or higher.

[0040] Heavier solvents also require a higher injection temperature. For example, pentane may be heated to about 190 PC for injection in the vapour phase at injection pressures up to about 3 MPa. In comparison, a light solvent such as propane may be injected at temperatures as low as about 50 to about 70 PC
depending on the reservoir pressure.

[0041] Different solvents or solvent mixtures may be suitable candidates.
For example, the solvent may be propane, butane, or pentane. A mixture of propane and butane may also be used in an appropriate application. It is also possible that a selected solvent mixture may include heavier hydrocarbons in proportions that are, for example, low enough that the mixture still satisfies the above described criteria for selecting solvents.

[0042] In some embodiments, the solvent may include one or more C1-12 alkanes, a natural gas liquid, a condensate, a diluent, or a mixture thereof.
The solvent may also include CO2 or H2 and may include up to 10 wt% impurities.

[0043] The condensate or diluent may include 0-5% C3 alkane, 0-5% iso-C4 alkane, 0-5% n-C4 alkane, 40-50% C5 alkane, 15-25% C6 alkane, 10-20% C7 alkane, 0-15% C8 alkane, or 0-15% C9 alkane. Alternatively, the condensate or diluent may include 25-65% C3 alkane, 35-55% iso- and n-C4 alkanes, or 10-20%
C5+ alkane.

[0044] Dissolution of the solvent in bitumen reduces the viscosity and enhances mobility of the oleic phase. The reduction in viscosity results in the flow of oil, along with the solvent. As solvent injection progresses, the oil flows toward the perforated third pipe section 224. Flow into the production tubing 226 via the ports 228, is controlled at 404, utilizing the flow control devices 230. The first port, closest to the heel 108, may be opened to facilitate the flow of fluids into the production tubing 226 via the first port. As injection and production continues, however, the first port may be closed and the second port, or next port along the length of the production tubing 226, opened. As production continues further, the second port may be closed and a third or next port along the length of the production tubing, opened. Thus, the flow control devices may be utilized to selectively open and close the ports in the production tubing 226 to produce hydrocarbons from ports along the production tubing 226 that are farther from the heel 108, and thus farther from the perforated first pipe section 220 and the second pipe section 222 with time. The discharge coefficient in the flow control devices may be modified to optimize the recovery and advance vapour chamber growth.
For example, the closest port to the heel could be closed as the chamber develops to improve the conformance along the length of the reservoir. This control of the flow control devices also facilitates production of hydrocarbons farther from the injection locations of the perforated first pipe section 220, along the length of the generally horizontal portion 110 of the single well 102.

[0045] In the description above, the production occurs as injection continues.
The injection and production, however, need not be carried out simultaneously.
For example, the production may be carried out after a period of injection. The injection and production therefore may be carried out alternatingly.

[0046] The flow control devices 230 are utilized to control the flow of fluid into the production tubing 226. The hydrocarbons along with the solvent that consolidate at the production tubing 226, are produced to the surface at 406.
The consolidation of liquids including the hydrocarbons and the solvent, limiting the volume of gasses that enter the perforated third pipe section 224 and thus limiting the volume of gasses produced via the production tubing 226.

[0047] The produced fluids may be treated at the surface to separate, at 408, the hydrocarbons produced from the solvent or solvents injected, in the mobilizing fluid recovery facility 114. The solvent may then be recycled back by re-injecting the solvent into the reservoir at 410 for mobilizing further hydrocarbons.

[0048] Advantageously, mobilizing fluid may be injected and mobilized hydrocarbons, along with mobilizing fluid, produced from a single well. The reduced diameter section of pipe, through which mobilizing fluid flow is inhibited may be any suitable length to separate the location or locations at which the mobilizing fluid is injected from the locations at which the fluids are produced. The separation of the injection and production locations in the hydrocarbon-bearing formation facilitates production along the length of the single well. Flow control devices may also be utilized to further facilitate production along the length of the single well. The mobilizing fluid may be a solvent, in the absence of any steam injection, such that steam facilities are not required for production. Gaseous solvent or steam injected reduces bitumen viscosity by heat transfer, and, for solvent, an increasing mol % of solvent in oil results from the solubility and advancing oil production. The present system and process are particularly suitable for recovery of hydrocarbons from thin formations of less than about 20 meters in depth (thickness), referred to as thin pay zones.
EXAMPLES:
Modelling

[0049] Reservoir simulations were performed to demonstrate the process.
Simulation parameters utilized are included in Table 1 below.
Table 1: Simulation Parameters Rich Pay thickness 30m Well Spacing 100m Well Length 800m Symmetry Half symmetry Model grid Block Dimensions 26X16X30 (2mX50mX1m) (X,Y,Z) Porosity 35%

Reservoir Temperature 12c Reservoir Pressure 3 mPa Initial Oil Saturation 0.8 Vertical Permeability 2 Darcy Horizontal Permeability 4 Darcy Methane mole fraction in Oleic 13%
Phase Oil API 9.6

[0050] FIG. 6 illustrates the spread of propane in a hydrocarbon-bearing formation after 480 days, according to another simulation of the process of FIG. 4.
Solvent chamber growth and expansion is shown in FIG. 6 in which conditions were not optimized. Significant development is shown at the heel of the solvent chamber.
Further expansion and growth of the chamber may be effected by optimizing the flow control devices discharge coefficient and the timing at which each opens and closes. FIG. 6 illustrates that solvent and oil are advantageously produced utilizing the present process.

[0051] FIG. 7 illustrates oil and solvent production rates in tonnes/day over time. The low oil rates in this half symmetry model may be increased by advancing the expansion and growth of the chamber by optimization of the flow control devices discharge coefficient and the timing at which each opens and closes.
FIG. 7 shows that steady oil and solvent recovery are possible in thin reservoirs where the SAGD process is not economic due to high steam to oil ratio (SOR) and significant energy losses to the overburden.

Claims (26)

Claims

1. A process for recovering hydrocarbons from a hydrocarbon-bearing formation, the process comprising:
injecting mobilizing fluid into a single well that extends generally horizontally in the hydrocarbon-bearing formation, from a heel to a toe, the single well having pipe sections coupled together and including:
a perforated first pipe section having a first inner diameter through which the mobilizing fluid is injected into the hydrocarbon-bearing formation;
a second pipe section coupled to the perforated first pipe section and having a second inner diameter that is smaller than the first inner diameter; and a perforated third pipe section coupled to the second pipe section and having third inner diameter that is larger than the second inner diameter;
producing fluids including the mobilizing fluid and the hydrocarbons that flow through perforations in the perforated third pipe section and into ports in production tubing that extends through the pipe sections, from a location proximal the toe of the single well to a wellhead of the single well to provide produced fluids to the wellhead, wherein the flow of the mobilizing fluid injected into the single well is restricted from passing from the perforated first pipe section into the second pipe section by the second inner diameter that is smaller than the first inner diameter, relative to an outer diameter of the production tubing.

2. The process according to claim 1, wherein injecting mobilizing fluid comprises injecting a mobilizing gas.

3. The process according to claim 1, wherein the mobilizing fluid comprises a solvent.

4. The process according to claim 3, comprising recovering at least some of the solvent from the produced fluids to provide recovered solvent.

5. The process according to claim 4, comprising recycling the recovered solvent by reinjecting the recovered solvent into the single well.

6. The process according to any one of claims 1 to 5, wherein the mobilizing fluid comprises a solvent having 2 to 8 carbon atoms per molecule.

7. The process according to any one of claims 1 to 5, wherein the mobilizing fluid comprises a solvent having 5 to 7 carbon atoms per molecule.

8. The process according to any one of claims 1 to 7, wherein injecting the mobilizing fluid comprises injecting the mobilizing fluid at a temperature less than 100°C.

9. The process according to any one of claims 1 to 7, wherein injecting the mobilizing fluid comprises injecting the mobilizing fluid at a temperature such that the mobilizing fluid is in gaseous phase upon entry into the hydrocarbon-bearing formation.

10. The process according to any one of claims 1 to 7, wherein injecting the mobilizing fluid comprises injecting the mobilizing fluid at a temperature such that the mobilizing fluid is in gaseous phase upon entry into the hydrocarbon-bearing formation and changes phase to a non-gaseous phase within the hydrocarbon-bearing formation.

11. The process according to any one of claims 2 to 7, wherein the solvent is injected at ambient temperature at the wellhead.

12. The process according to any one of claims 1 to 11, comprising utilizing flow control devices cooperating with the production tubing for controlling the flow of the fluids produced from the hydrocarbon-bearing formation into the ports in the production tubing.

13. The process according to claim 12, comprising operating the flow control devices to selectively open and close the ports in the production tubing to produce the hydrocarbons from locations along the production tubing that are farther from the second pipe section with time.

14. The process according to any one of claims 1 to 13, wherein producing fluids comprises intermittently producing fluids via the production tubing.

15. The process according to any one of claims 1 to 14, wherein injecting and producing are carried out alternatingly.

16. The process according to any one of claims 1 to 15, wherein the second pipe section is not perforated.

17. A system for recovering hydrocarbons from a hydrocarbon-bearing formation, the system comprising:
a single well extending generally horizontally in the hydrocarbon-bearing formation from a heel to a toe, the single well comprising:
pipe sections coupled together and including:

a perforated first pipe section having a first inner diameter for the injection of a mobilizing fluid into the hydrocarbon-bearing formation;
a second pipe section coupled to the perforated first pipe section and having a second inner diameter that is smaller than the first inner diameter; and a perforated third pipe section coupled to the second pipe section and having a third inner diameter that is larger than the second inner diameter, to facilitate flow of fluids produced from the hydrocarbon-bearing formation into the third pipe section;
production tubing extending from a top of the single well to a location proximal the toe of the single well, the production tubing extending through the pipe sections, a portion of the production tubing within the perforated third pipe section including ports to facilitate the flow of the fluids produced from the hydrocarbon-bearing formation into the production tubing, wherein the second inner diameter of the second pipe section is sized relative to an outer diameter of the production tubing to inhibit flow of the mobilizing fluid from the first pipe section into the second pipe section.

18. The system according to claim 17, wherein the mobilizing fluid comprises a mobilizing gas.

19. The system according to claim 17, comprising flow control devices cooperating with the production tubing for controlling the flow of the fluids produced from the hydrocarbon-bearing formation into the ports in the production tubing.

20. The system according to any one of claims 17 to 19, wherein the second inner diameter is sized relative to the outer diameter of the production tubing to inhibit flow of mobilizing fluids from the first pipe section, directly into the second pipe section.

21. The system according to any one of claims 17 to 20, wherein the second pipe section is not perforated.

22. The system according to any one of claims 17 to 21, comprising a recovery facility in communication with the production tubing for recovery of solvent injected into the hydrocarbon-bearing formation.

23. The system according to claim 22, wherein the recovery facility is in fluid communication with the pipe sections for re-injection of recovered solvent into the hydrocarbon-bearing formation.

24. The system according to any one of claims 17 to 23, wherein the hydrocarbon-bearing formation is a thin-pay hydrocarbon-bearing formation having a pay thickness of less than about 20 meters.

25. The system according to any one of claims 17 to 24, wherein the second pipe section is less than 100 meters in length.

26. The system according to any one of claims 17 to 24, wherein the second pipe section is from 10 meters to 50 meters in length.