CA2968392A1 - Variable pressure sagd (vp-sagd) for heavy oil recovery - Google Patents

Abstract

A thermal process to recover heavy and extra heavy oil from subterranean reservoirs is described. This process requires a pair of horizontal wells directly above each other. Steam-assisted gravity drainage (SAGD) involves a pure steam or steam-gas mixture being injected from the upper horizontal well, and then the heated and diluted crude oil drains by gravity and is produced from the lower production well. During this process a steam chamber develops around the injector and above the producer.
After producing for a period of time, a pressure-drop scheme is executed: The injector is shut in while the producer is kept open with modified production conditions.
When the pressure at the injector drops to a pre-determined level, the injector is reopened, the injection of steam and gas is resumed and the production constraints return to those before the pressure drop.

Description

VARIABLE PRESSURE SAGD (VP-SAGD) FOR HEAVY OIL RECOVERY
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering, particularly thermal recovery processes such as steam-assisted gravity drainage (SAGD) systems in heavy oil reservoirs.
BACKGROUND OF THE INVENTION

[0002] Crude heavy oil and bitumen are characterized with high viscosities (i.e., higher than 100 mPa.s for heavy oil and 10,000 mPa.s for bitumen) and low API
(American Petroleum Institute) gravities (i.e., lower than 20.0 API for heavy oil and 10.0 API for bitumen) [Speight, 1991]. These conditions make them immobile under reservoir conditions. Open-pit mining and in situ methods are the two main techniques used for recovering heavy oil and bitumen. Open-pit is feasible for bitumen deposits less than 100 m deep and has a limited future capacity since 80 percent of the oil sand resources lie too deep underground to mine. In situ production primarily relies on two commercial thermal recovery methods: cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD). Both of these processes employ steam to heat and dilute bitumen to make it mobile enough to recover.
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[0003] Cyclic steam stimulation (CSS) is commonly known as "huff and puff' and was the first commercially applied process to recover heavy oil/bitumen. In this process, a vertical/horizontal well is used cyclically as a steam injector and an oil producer. In a typical cycle of conventional CSS, steam is first injected into a formation at a temperature of 300-400 C and a pressure up to 2,000 psi for a period of time ("injection"). Then the well is shut in for several days to weeks to let steam condense and release the latent heat into a formation ("soaking"). Finally, the well is re-opened to produce heated oil and steam condensate that are pumped to the surface until the production rate declines to an economic limit ("production"). Throughout this process an expanding "steam chamber" is gradually developed due to the depletion of heavy oil/bitumen.

[0004] In conventional SAGD, parallel horizontal wells are applied with one right above the other by about 5 meters. Initially, steam is circulated through both wells to warm up the areas around the wells, and the heated oil nearby is produced until the two wells are communicated. The production of heavy oil/bitumen leads to the development of a steam chamber around the steam injector. The saturated steam is injected into the steam chamber at a constant temperature of 150-300 C and below a fracture pressure.
Steam condenses at the steam chamber boundary and releases its latent heat to crude oil. The heavy oil/bitumen is diluted, becomes mobile, and drains along the steam chamber boundary to the production well at the bottom of a reservoir, where it is pumped out to the surface by a natural lift, a gas lift, or a submersible pump.

[0005] Atypical SAGD process is disclosed in Canadian Patent No.
1,130,201 issued on 24 August 1982, in which two wells are drilled into a deposit, one for injection of steam and the other for production of oil and water. Steam is injected via the injection well to heat the formation. It condenses and gives its latent heat to reservoir rock and the inside fluids. The viscous hydrocarbons are thereby mobilized, and drained with an aqueous condensate by gravity toward the production well. In this way, the injected steam initially mobilizes 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 generally saturated with injected steam in the presence of residual oil and water, and from which mobilized 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 steam chamber remains above the production well, with the production well in an appropriate position to collect mobilized hydrocarbons.

[0006] Variants of the SAGD and CSS processes have been described. For example, US. Pat. No. 4,344,485, 1982 discloses steam-assisted gravity drainage (SAGD) processes wherein steam is injected via an upper horizontal well section to transfer heat to the normally immobile heavy oil so that it will melt and will drain by gravity to a lower horizontal well section where the oil is recovered. Butler (1999) describes a steam and gas push (SAGP) process in which steam is co-injected with a non-condensable gas such as natural gas. Gas accumulates in the chamber above an injector and lowers the average temperature in the reservoir by reducing heat loss to the overburden. Rising gas fingers increase the pressure towards the top of the reservoir and displace oil downwards even though the temperature is below that of saturated steam, and they also penetrate into the cooler oil because of their higher mobility. The gas in the chamber comes from the combination of added gas, solution gas, and gas generated by chemical reactions, minus gas produced with the oil and the net gas driven to or coming from outside the depleted region by pressure difference.
Ba ci, S., & GOrnrah, F. (1992) Journal of Petroleum Science and Engineering, 8(1), 59-72, described cyclic and continuous steam-injection processes using horizontal wells to produce heavy oils ¨ specifically a horizontal injector and a horizontal producer. For each cycle, first the steam is injected (injection period), and then the injection well and production well are closed for some time. After the soaking period, the well was opened for production. International Patent Publication WO 2013181750 Al ¨2013 describes a method for a production well in a SAGD process to increase hydrocarbon recovery from a hydrocarbon reservoir, wherein the SAGD process occurs at a site including an injection well, a production well and a steam chamber. The method includes shutting the production well and maintaining or increasing steam injection through the injection well until pressure in the steam chamber increases. Then, while continuing steam injection, production is resumed at rates for normal SAGD or greater until reservoir pressure reaches normal operating pressure.

[0007] 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. The abbreviation POIP stands for "producible oil in place" and in the context of the methods disclosed herein is generally defined as the exploitable or producible oil structurally located above the production well elevation.

[0008] It is a 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 1,000 kg/m3 and a viscosity greater than 10,000 centipoise or 10 Pa.s 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.

[0009] A reservoir is a subsurface (or subterranean) formation containing one or more natural accumulations (or deposits) of moveable petroleum, which are generally confined by relatively impermeable rock. An "oil sand" (or formerly "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.

[0010] 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

[0011] Variable Pressure-SAGD (VP-SAGD) is a process that mingles the operation scheme of SAGD and CSS. Over a life of a conventional SAGD process, the SAGD
operating scheme is first practiced. After a steam chamber is initially developed, at a certain stage (better at an early or an intermediate stage) the steam injector is shut in while the producer is kept open and the production constraints are adjusted to let the pressure in the steam chamber drop quickly. Once the pressure in the steam chamber (monitored at the injector) declines to a specific level the steam injection is resumed at a higher rate than that before the injector was shut in in order to restore the production constraints to their previous levels. If required this pressure drawdown process may be repeated at a later stage of a SAGD process.
BRIEF DESCRIPTION OF THE DRAWINGS

[0012] Figure 1 is a perspective illustration in a cross section of a modeled reservoir, showing the reservoir model for a simulation base case.

[0013] Figure 2 is a line graph illustrating crude heavy oil viscosity vs. temperature at 101.325 kPa.

[0014] Figure 3 includes three plots, showing (a) oil and water relative permeability, (b) gas and oil relative permeability, and (c) three-phase relative permeability.

[0015] Figure 4 illustrates the simulation results of enhanced SAGD: (a) a recovery factor and an oil production rate and (b) cumulative and instantaneous steam¨oil ratios (Note: "VP-SAGD" denotes "enhanced SAGD").

[0016] Figure 5 illustrates the steam chamber development of SAGD and VP-SAGD.

[0017] Figure 6 includes two plots that illustrate (a) temperature and pressure profiles and (b) a pressure versus temperature profile during the pressure drawdown and buildup of VP-SAGD.

[0018] Figure 7 includes two plots that illustrate the effect of a steam release rate during pressure drawdown on VP-SAGD: (a) pressure and (b) recovery factor (RF).

[0019] Figure 8 includes two plots that illustrate the effect of turning pressure or Pmin on the (a) pressure and (b) RF of VP-SAGD.

[0020] Figure 9 includes two plots that illustrate the effect of a steam injection rate on the (a) pressure and (b) RF of VP-SAGD.

[0021] Figure 10 includes two plots that illustrate the effect of starting time on VP-SAGD performance: (a) RF and (b) cSOR.

[0022] Figure 11 includes two plots that illustrate the effect of starting time and turning pressure on final (a) RF and (b) SOR of VP-SAGD (t = 1/1/2029).

[0023] Figure 12 includes three plots that illustrate the effects of different SAGD
stabilized pressures on the VP-SAGD performance: (a) p = 2550 kPa and T = 225 C, (b) p = 4000 kPa and T= 250 C, and (c) p = 5080 kPa and T = 265 C.

[0024] Figure 13 includes two plots that illustrate the effects of absolute permeability on (a) RF and (b) RF ratio of VP-SAGD and SAGD.

[0025] Figure 14 includes three plots that illustrate the effect of heterogeneity of (a) permeability and (b) porosity on (c) RF and cSOR of VP-SAGD.

[0026] Figure 15 includes three plots illustrating (a) the effect of starting time on final cRF (t = 1/1/2029) for Swc = 13%, (b) optimum turning pressure at different starting time for Swc = 13%, and (c) optimum turning pressure at different starting time for Swc = 13%.

[0027] Figure 16 includes three plots illustrating (a) the effect of starting time on final RF (t = 1/1/2029) for Swc = 23%, (b) optimum turning pressure at different starting time for Swc = 23%, and (c) optimum turning pressure at different starting time for Swc = 23%.

[0028] Figure 17. The effect of payzone thickness (H = 20 or 30 m) on the (a) RF
and (b) cSOR of VP-SAGD.

[0029] Figure 18. (a) Impermeable interlayer distribution and (b) RF of SAGD and VP-SAGD with the impermeable interlayers.

[0030] Figure 19 is a graph illustrating RF and cSOR of multiple cycle VP-SAGD vs.
SAGD.

[0031] Figure 20 is a graph illustrating SAGD and VP-SAGD performance in a real field case.

[0032] Figure 21 includes two plots illustrating the effect of gas injection pressure on the (a) RF profiles and (b) final RF of VP-SAGD.

[0033] Figure 22 includes two plots illustrating the effect of gas injection duration on the RF profiles and final RFs of VP-SAGD.
DETAILED DESCRIPTION OF THE INVENTION

[0034] In accordance with various aspects of the invention, detailed computational simulations of reservoir behaviour have been carried out to describe and analyze the new process, named VP-SAGD. The fluid and reservoir properties and the basic operating conditions are listed in Tables 1 and 2. The simulation model, crude heavy oil viscosity vs. temperature and multi-phase permeability profiles used in this study are shown in Figs. 1-3, respectively.
Table 1. Properties and parameters of a simulation base case.
Reservoir Dimension (m x m x m) 50 x 100 x 30 Number of grid blocks 50 x 1 x Permeability (Darcy) 1 Porosity (vol.%) 30 Fluid Crude heavy oil content 8.23 mol.% oil, 91.77 mol. /0 Heavy oil gravity 0.975 Heavy oil viscosity Fig. 2 Relative permeability Figs. 3 Initial conditions Pressure (kPa) 3000 Temperature ( C) 16 Operation Injector depth (m) 525 Producer depth (m) 530 Steam injection temperature 250 Steam injection pressure 4000 Steam quality (unity) 0.8 Table 2. Operation constraints for each cycle of VP-SAGD.
SAGD process Inector BHP bottom hole pressure MAX, kPa 4000 j STW surface water rate MAX, m3/day 40 BHP bottom hole pressure MIN, kPa 3000 Producer STL surface liquid rate MAX, m3/day 30 STEAM steam rate MAX, m3/day 0.1 Pressure drawdown process Injector Shut in Shut in for 0-7 days and then Producer STL surface liquid rate MAX, m3/day 30 STEAM steam rate MAX, m3/day 5.0

[0035] Fig. 4 provides the simulation results of a conventional SAGD and a typical VP-SAGD. Compared to SAGD, the final RF of VP-SAGD is higher by 8.1% and its cSOR is lower by 0.4 clearly demonstrating the greater potential of VP-SAGD.

[0036] Without being limited to the theory, in some embodiments, the process may be adapted to implement specific mechanisms, particularly specific mechanisms of heat transfer. Heat transfer from the steam to the bitumen and the gravity drainage of diluted bitumen are two of the most important recovery mechanisms of SAGD. During the heat transfer from the steam to the bitumen the steam chamber pressure is maintained constant throughout the SAGD process. The convection velocity or pressure gradient across a heat transition zone is very limited so the heat transfer is dominated by conduction rather than by convection. In VP--SAGD, the steam chamber pressure is first drawn down and then built up, which may be implemented so as to cause a significant pressure difference across the heat transition zone and thus enlarge the convection effect. This is evident by the thinner transition-zone thickness of VP-SAGD
(Figs. 5c-d).

[0037] In addition, during the pressure drawdown period, pressure may be adjusted so as to drop sharply while temperature declines slowly, as shown in Fig. 6a.
More specifically, it can be seen that the pressure versus temperature profile falls along the vapour line above 2,800 kPa. Afterwards, the profile drops almost vertically.
This may, for example, be carried out so that the decreased pressure makes the steam over-saturated and easy to condense accelerating the pressure drop. During the pressure restoration process, in some embodiments, the pressure versus temperature profile first rises quickly and then follows the vapour line since the injected fluid is pure steam (Fig.
6b).

[0038] The gravity drainage of heated bitumen is generally largely determined by a slip angle. In most bitumen reservoirs, permeability in the horizontal direction is greater than in the vertical direction due to the geological deposition. In SAGD, the contrast between horizontal and vertical permeability may result in a slimmer and slimmer slip angle over time. This may be especially true near the reservoir bottom where it can seriously reduce the oil drainage rate. In the present process, the pressure drawdown and buildup process may accordingly be adapted to provide time for the heated bitumen to slip down from a chamber side and accumulate at the chamber bottom, augmenting the interface slope (Figs. 5c-d) and benefiting the oil drainage rate during the subsequent gravity drainage process.

[0039] A variety of operating conditions may be imposed at various stages of the process of the invention, and these may vary from one embodiment to another.
Selected embodiments of particular operating conditions are described below.
Pressure drawdown rate

[0040] During the pressure drawdown process the producer may, for example, be shut in, for example, for a few days, to allow the heat to soak into the heavy oil. Then the same producer may be opened and the steam rate at the surface increased.
The production of steam, water and oil may be adjusted to quickly bring down the steam chamber pressure. In Fig. 7 a comparison between the effect of a steam rate and the decline rate of the injector BHP (bottom-hole pressure) is outlined. For subsequent oil production the steam chamber pressure may, for example, be brought down as quickly as possible. In other words, the steam rate may be set as high as possible during the pressure drawdown process.

Turning pressure

[0041] A turning pressure (Pmin) is defined as the terminal and minimum pressure of the pressure drawdown period. It is also the starting pressure for the following gravity drainage process. Fig. 8 shows the effect of the turning pressure on the oil recovery factor profiles. It is found that for the base case (the starting point is RF
= 25%), higher Pmin leads to a quicker production response but with a lower final recovery.
In some embodiments, Pmin = 250-500 kPa may be the optimum turning pressure range.
Pressure buildup rate

[0042] Once the BHP reaches Pmin, steam injection may be resumed.
Consequently, the steam chamber pressure is gradually restored, for example, to the previous SAGD
operation pressure, and then it may be maintained at that level. Fig. 9 analyzes the steam injection rate or pressure buildup rate on the VP-SAGD performance. It is found that the pressure buildup rate is significantly related to the oil production response but only slightly impacts the eventual oil recovery. Accordingly, in some embodiments, the steam injection rate for the second or subsequent SAGD processes may be set as high as possible in the short run, and may, for example, be varied in the long run.
Timing

[0043] Fig. 10 analyzes the effect of the starting time of the pressure drawdown on the VP-SAGD performance. It is found with the given reservoir properties (porosity, permeability, and initial water saturation), a starting point of approximately RF = 20%
may give the highest recovery factor and lowest cSOR at a later particular time point.
Fig. 11 shows the effect of the starting time and turning pressure on the final (a) RF and (b) SOR of VP-SAGD. In the selected embodiments, the starting time at RF = 15-30%
may, for example, achieve an optimal recovery enhancement and SOR reduction.
SAGD pressure/temperature

[0044] Fig. 12 shows the effects of three different SAGD pressures on the VP-SAGD
performance: p = 2550 kPa and T= 225 C, p = 4000 kPa and T= 250 C, and p =

kPa and T= 265 C. The relative RF enhancement at the same time for the three cases are 20.3%, 14.3%, and -0.1%, respectively. This illustrates that applying the VP-SAGD

scheme to lower-pressure SAGD operations can in some implementations achieve a significant production improvement.
Reservoir Properties Permeability

[0045] Fig. 13 shows the RF and SOR of SAGD and VP-SAGD for three cases with different permeabilities (K = 1, 3, and 5 Darcy). It has been determined that in the illustrated embodiment VP-SAGD has a higher RF and lower SOR than SAGD in all cases. The greater the permeability the quicker the production response while smaller permeability saves more time. For instance, for a final RF of 60%, the VP-SAGD
of K =
5 Darcy saves 2.67 yrs from SAGD, the K = 3 Darcy case saves 2.88 yrs, and the K = 1 Darcy case saves 6.68 yrs. For heterogeneous permeability and porosity, the advantages of VP-SAGD over SAGD are more or less the same as shown in Fig. 14.
Initial water saturation

[0046] Initial water saturation may have a great effect on the VP-SAGD
performance.
For Swc = 13%, Fig. 15 shows the final recovery factor (t =1/1/2029) for different turning pressures (Pmin = 1500, 1000, 500, 250, and 150 kPa) along a SAGD life (starting RF =
5, 10, 15, 20, 25, 30, 35, 40, 45, and 50%). It is found that in the selected embodiments optimum pressures for different starting times are distinct. In some cases, in the early and middle stages, a lower turning pressure may lead to more oil production, whereas at the late stages, the best turning pressure may gradually increase from 150 kPa to 950 kPa. Fig. 15c illustrates the general trend of the optimum turning pressure.

[0047] For Sc = 23%, in the exemplified embodiment, the situation is different although the general trend remains the same. Lower turning pressures work well only in the early stages. Higher turning pressures perform better than lower ones at a late stage. As shown in Fig. 16, in the selected cases, a turning pressure of approximately 1100 kPa may provide the best performance after RF = 25%.
Payzone thickness

[0048] Fig. 17 shows the effect of payzone thickness (H = 20 and 30 m) on the RF
and cSOR of VP-SAGD. In the exemplified embodiment, the RF enhancement and cSOR reduction of VP-SAGD in a thinner reservoir are more or less the same as those in a thicker one.
-- Impermeable interlayer

[0049] An impermeable interlayer may greatly affect the VP-SAGD
performance depending on the distribution and location of the impermeable interlayer, as shown in Fig. 18.
-- Multiple cycles

[0050] Fig. 19 shows a multi-cycle VP-SAGD. The first cycle starts at RF
= 15%, while the second cycle starts randomly at RF = 42%. The final RF at t =
1/1/2029 of VP-SAGD with two cycles is 66.2%, which is slightly higher than the final RFs of VP-SAGD
with one cycle (65.8%) and significantly higher than that of conventional SAGD
(RF =
-- 58.5%). Therefore, in alternative embodiments, multiple cycles can be applied to VP-SAGD, dependent on the reservoir properties and operation parameters.
Real field case

[0051] Fig. 20 shows VP-SAGD performance with real reservoir and fluid properties -- and operating conditions. For a real field case, the RF at t = 1/1/2019, which is 15 years after the pressure fluctuation, is improved by 8.2% and cSOR increased by 0.45.
Further Improvement by Adding Non-Condensable Gas

[0052] In some embodiments, injection of a slug of non-condensable gas (such as -- 002, N2, CH4, 002, etc.), for example, at a pressure higher than the SAGD
operation pressure, before pressure drawdown, can be adapted to result in a larger final RF. The high-pressure non-condensable gas may, for example, be injected so as to induce a greater pressure difference later on to provide stronger stimulation of the heated heavy oil at a steam chamber boundary. This may be adapted to result in a larger slip angle -- and higher VP-SAGD performance. In some embodiments, the non-condensable gas may, for example, accumulate at the top part of a steam chamber, for example, so as to help reduce the heat losses to the overburden formation in the subsequent VP-SAGD
process. The following section analyzes the injection of a slug of non-condensable gas on the RF and SOR of VP-SAGD.

[0053] Fig. 21 shows that the gas injection pressure exerts a big difference on the recovery profiles. In the selected embodiments, the optimum gas injection pressure in terms of the highest RF may, for example, be around p = 4,300-4,500 kPa, which is 300-500 kPa higher than the normal SAGD operating pressure (p = 4,000 kPa).

[0054] A gas injection pressure of p = 4,500 kPa is selected to investigate the effect of gas injection duration on the final RF at t = 1/1/2029. Fig. 22 shows that the gas injection duration has an invisible effect on the RF profiles. Nevertheless, it is found that one week's injection is the best injection length as long as the steam chamber pressure reaches the pre-specified value, i.e., p = 4,500 kPa.

[0055] As discussed above, various aspects of the invention involve the drilling of one or more wells that are situated and operated so as to form a hydrocarbon extraction chamber within a reservoir. This may, for example, include SAGD well pairs within a reservoir, with each injection well paired with a corresponding production well. Each well may have a completion on the surface, for example, with a generally vertical segment leading to the heel of the well, which then extends along a generally horizontal segment to the toe of the well. In very general terms, to provide a general illustration of the scale in the 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 pair may, for example, average approximately 800 m in length, although a wide range of alternatives are possible, for example, from about 200 m to about 1,600 m. The lower production well profile may generally be targeted so that it is approximately 1 to 2 m above the reservoir base.

[0056] It will be appreciated that the VP-SAGD recovery techniques can be practiced in combination with other hydrocarbon recovery processes. A very wide variety of alternative techniques may be combined with VP-SAGD, including conventional SAGD, for example, consecutively or in alteration.

[0057] In alternative embodiments, using steam additives such as solvents or other chemical additives may enhance VP-SAGD. Solvents or other chemical additives may, for example, include xylene, toluene, diesel, propane, butane, pentane, hexane, diluent, condensate, C7-C10 hydrocarbons, surfactants, other polar compounds, or combinations thereof.
Conclusion

[0058] 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. For example, any one or more of the injection or production wells may be adapted from well segments that have served or serve a different purpose so that the well segment may be re-purposed to carry out aspects of the invention, including, for example, the use of multilateral wells as injection or production wells. 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. Any priority document(s) and all publications, including but not limited to patents and patent applications, cited in this specification are incorporated herein by reference as if each individual publication were specifically and individually indicated to be incorporated by reference herein and as though fully set forth herein. The invention includes all embodiments and variations substantially as hereinbefore described and with reference to the examples and drawings.

Claims (11)

1. A process for removing fluids from a subterranean formation, the process comprising:
a) selecting a hydrocarbon reservoir in the formation bearing a heavy oil, the reservoir comprising a steam chamber having a peripheral heat transition zone comprising condensing steam, non-condensing gas and mobile hydrocarbons, wherein the steam chamber has a longitudinal axial dimension formed by:
i) a generally horizontal segment of a production well that is in fluid communication with the zone of mobile hydrocarbons;
ii) a generally horizontal segment of an injection well that is in fluid communication with the steam chamber, generally parallel to and vertically spaced apart above the horizontal segment of the production well; and;
b) injecting an injection fluid comprising steam through the horizontal segment of the injection well at a range of selected bottom hole injection pressures that vary over time, so as to form a temporary radial pressure gradient within the steam chamber at a selected starting time (t s) by successively:
i) establishing an initial steam chamber operating pressure (P o) and temperature (T o), so as to mobilize the heavy oil in the peripheral heat transition zone to form the mobile hydrocarbons, so that the mobile hydrocarbons flow downwardly and towards the production well in a gravity dominated process to radially expand the steam chamber; then, ii) reducing the bottom hole injection pressure to a reduced injection pressure (P r) that is less than P o, in conjunction with producing fluids through the production well, so that the bottom hole pressure at the production well drops over a pressure drawdown time (t d) to a turning pressure (P min); then, iii) increasing the bottom hole injection pressure above P min so as to form a pressure gradient across the peripheral heat transition zone, returning to a secondary steam chamber operating pressure (P o 2) and temperature (7 o 2) so as to continue to mobilize the heavy oil in the peripheral heat transition zone to form the mobile hydrocarbons, so that the mobile hydrocarbons continue to flow downwardly and towards the production well in the gravity dominated process to radially expand the steam chamber; and, c) recovering the mobilized hydrocarbons from the reservoir through one or more wells in the formation, thereby removing heavy oil from the reservoir, wherein Pr, td, Pmin, Po2 and To2 are selected so that the cumulative steam-oil ratio (cSOR) for the subsequent recovery of a given recovery factor (RF) of the mobilized hydrocarbons is less than the cSOR of a process continuously carried out at Po and To.

2. The process of claim 1, wherein Pr is at least 90% less than Po.

3. The process of claim 1 or 2, wherein Pmin = 250-500 kPa.

4. The process of any one of claims 1 to 3, wherein Po is less than 5500 kPa and To is less than 300°C.

5. The process of any one of claims 1 to 4, wherein ts is within 15% to 30%
of total RF.

6. The process of any one of claims 1 to 5, wherein the production well is temporarily shut in when reducing the bottom-hole injection pressure to Pr.

7. The process of any one of claims 1 to 6, further comprising injecting a non-condensing gas (NCG) into the steam chamber prior to step (b)(ii).

8. The process of claim 7, wherein the NCG is CO2, N2, CH4, or CO2.

9. The process of any one of claims 1 to 8, further comprising a plurality of cycles of step (b).

10. The process of any one of claims 1 to 9, wherein the injection well comprises an injection well surface completion in fluid communication with the hydrocarbon reservoir through an injection wellbore that comprises an initial segment having a vertical component extending downwardly from the injection well surface completion, the injection wellbore extending therefrom through an injection well heel section that transitions the injection wellbore from the initial segment thereof to a longitudinal extension segment comprising the generally horizontal segment of the injection well, the longitudinal extension segment terminating in an injection well toe.

11. The process of any one of claims 1 to 10, wherein the production well comprises a production well surface completion in fluid communication with the hydrocarbon reservoir through a production wellbore that comprises an initial segment having a vertical component extending downwardly from the production well surface completion, the production wellbore extending therefrom through a production well heel section that transitions the production wellbore from the initial segment thereof to a longitudinal extension segment comprising the generally horizontal segment of the production well, the longitudinal extension segment terminating in a production well toe.