WO2016037291A1

WO2016037291A1 - Method of capturing and venting non-condensable reservoir gases in enhanced oil recovery applications

Info

Publication number: WO2016037291A1
Application number: PCT/CA2015/050885
Authority: WO
Inventors: Fred Schneider
Original assignee: Resource Innovations Inc.
Priority date: 2014-09-11
Filing date: 2015-09-11
Publication date: 2016-03-17

Abstract

In new or depleted steam-assisted gravity drainage (SAGD) operations, non-condensable gases gathering in the steam chamber can be collected and vented to surface for maintaining mobilization efficiency with the reservoir. An existing upper injection well, or a new upper well can be repurposed or converted to both inject and vent, or an independent well can be completed into the steam chamber for venting of the non-condensable gases.

Description

METHOD OF CAPTURING AND VENTING NON-CONDENSABLE RESERVOIR GASES IN ENHANCED OIL RECOVERY

APPLICATIONS" FIELD

Embodiments herein relate methods for recovering heavy oil from a subterranean hydrocarbon reservoir utilizing a modified, steam-assisted gravity drainage (SAGD) process that applies also to solvent-assisted processes. More specifically, non-condensable gases that collect along a long horizontally-extending formation are removed to aid in the production of mobilized oils from the reservoir to a horizontally extending well along a lower portion of the formation.

BACKGROUND

One conventional methodology for enhanced recovery of heavy oils is to apply a steam-assisted gravity drainage (SAGD) process. SAGD utilizes a pair of substantially parallel wells, each well having a horizontal portion extending through a hydrocarbon reservoir in a subterranean formation. An upper horizontal injection well introduces steam into the reservoir to heat and mobilize the oil in a growing steam chamber forming about the upper well. The mobilized oil then flows downward through the formation towards a lower horizontal well for production to surface.

The introduction of heat into the oil reservoir also results in the release of non-condensable gases, such as carbon dioxide and light hydrocarbon gases that rise within the steam chamber. Injection or co-injection of solvent along with steam is also practiced in the industry. Solvent, often a mixture of light hydrocarbons, is injected to aid in the reduction of the viscosity of the heavy oil, increasing the mobility of the oil towards the production wells. Such solvent "floods" also can result in co-production of vapour solvent streams along with the oil through the lower producing horizontal well, often resulting in production inefficiencies as the highly-mobile gaseous solvent preferentially flows into the production well, bypassing the oil and creating a "channeling" affect that reduces the efficiency at which in-situ oil enters the production well.

In conventional steam-injection or solvent-injection gravity-assisted processes, non-condensable gases, such as carbon dioxide and light hydrocarbon gases, such as ChM, resulting from either as a part of the injection stream or from mobilization of gases present in the hydrocarbon reservoir, rise upwardly in the steam chamber. The non-condensable gases create a gaseous insulating barrier between the injected steam and the remaining reservoir above to be treated, resulting in inefficient heating of the formation thereabove, lessening the efficiency of mobilizing in-situ heavy oil. Furthermore, due to the forming of a low-pressure void surrounding the production well, solvent injected into the formation preferentially flows downwards towards the production well and can supplant the desired production of heavy oil. SUMMARY

Embodiments herein improve the effectiveness of horizontal well pair arrangements for heavy oil recovery using steam-assisted gravity drainage (SAGD) processes, including solvent-to-steam aided processes, wherein the non- condensable gases collecting within the steam chamber are vented, minimizing impediments to heat transfer to the reservoir and aiding in solvent delivery while minimizing solvent channeling in co-injection and solvent injection operations.

Generally non-condensable gases are released from the reservoir or formation, or delivered as part of the thermal process, and migrate upwardly. The gases collect in the upper portion of the steam chamber of the reservoir, and can act detrimentally to impede heat and solvent transfer to the heavy hydrocarbons of the reservoir. The gases are removed from the chamber by collection and transport to surface, improving the efficiency of the mobilization of the heavy oil and its ultimate recovery.

In existing or new SAGD operations, an upper horizontal well is located in the reservoir over a lower horizontal well. In one embodiment, the upper horizontal well forms both a source of recovery enhancing fluids and as an exit or vent for non-condensable gases. In another embodiment, a third well is provided as a vent for non-condensable gases. In another embodiment, when the upper well also forms a vent, the arrangement can further provide for the heel to be located higher in the formation than that of the toe of the well. Use of the upper well to collect non-condensable gases can also be also aided by configuring the upper well the slanted-form of well wherein injected steam, or steam and solvent, is further urged to circulate upwards through the reservoir towards the heel of the slanted well and away from the mobilized oil that flows downward towards the lower horizontal production well. Upward circulation of steam and/or solvents away from the oil flow reduces impetus for the "channelling" effect that would otherwise bypass oil that should flow to the production well.

In an embodiment, an upper horizontal well is provided to the subterranean formation and a horizontal production well is provided below the upper well, each well co-extending and generally parallel to each other through the formation. The upper well can form a source of enhanced mobilization fluid such as steam and solvent. As a result of mobilized oil production, released or generated non-condensable gases can be vented at either the same upper well in a multi- passage well or in a third specific vent well completed above the production well.

In another embodiment, an upper horizontal well is provided to the subterranean formation in a "slanted" orientation, such that the heel of the injection well is located uphole or at a higher elevation than the toe of the injection well. The upper well is configured with dual passages for downhole injection of mobilizing fluid and uphole venting of non-condensable gases. Injected vapour solvents can rise in the reservoir along the length of the vent well for collecting and venting, circulating away from the lower production well, thereby reducing the "channelling" effect. Non-condensable gases similarly rise along the length of the injection well, venting the gases from the formation and further to control reservoir pressure.

In another embodiment, an upper horizontal well is provided to the subterranean formation for downhole injection of mobilizing fluid. A third well is completed into an upper portion of the reservoir for uphole venting of non- condensable gases. Injected vapour solvents can rise within the reservoir for collecting and venting from the third well.

In another thermal embodiment, a third well can be provided as a source of mobilizing fluid including the heat and by-products from an in-situ burner. The third well can be fit with a downhole burner for production of hot non- condensable vapor, steam or both. In such instances, the upper and generally horizontal well forms the vent for removal of in-situ non-condensable gases and for non-condensable gaseous products of combustion. The third well could also form a conduit for the delivery of energy generated energy, such as steam.

Generally, a method of producing hydrocarbons from a subterranean reservoir is provided. A generally co-extensive upper and lower well pair is provided in a hydrocarbon formation providing a vent well to surface from the formation; operating the upper well to conduct a mobilizing fluid into the formation thereby mobilizing hydrocarbons downwards to the lower well and collecting non- condensing gases above the lower well in a gravity-controlled process; establishing a mobilized hydrocarbon communication between the upper and lower wells; operating the lower well to produce the hydrocarbons mobilized downward towards the lower well in a gravity-controlled process; and venting gases collected about the upper well. The vent well can be a vent passage co-extensive along the upper well, such as that provided by a second string extending therealong and forming an annular the vent passage. The vent well can be the upper well and mobilizing fluid is introduced in a third well completed in the formation. In another aspect, apparatus is provided for producing hydrocarbons by steam -assisted gravity drainage from a heavy oil reservoir in a subterranean formation, non-condensable gases being created by such production, comprising a first and upper injection well for the injection of a mobilization fluid, comprising at least steam, to the formation and a second lower production well completed in the formation for mobilization of the heavy oil in the reservoir for gravity-drainage to the lower well; and a vent passage extending between a location in an upper portion of the formation to the surface. The vent passage can comprise a third well extending between surface and an upper portion of the formation for venting of the non- condensable gases to surface, The third well can be formed by the upper injection well, the upper injection well comprising two passages, one for injection of the mobilization fluids, and second path forming the vent passage for the collection and venting of non-condensable gases from the reservoir, or alternatively the third well is an independent well completed to about the toe of the upper injection well. The independent well can further comprise a downhole burner for producing at least steam.

BRIEF DESCRIPTION OF DRAWINGS

Fig. 1 illustrates a conventional, steam-assisted gravity drainage (SAGD), having a horizontal well pair provided to a subterranean formation 10

Fig. 2 is an illustration of an embodiment of the invention, wherein a third vertical well 6 can be positioned near the toe 3 of the upper horizontal well 7. Fig. 3A is an illustration of an alternate embodiment of venting of the increase in concentration of non-condensable gases therein;

Fig. 3B illustrates a similar process as shown in Fig. 3A, except that steam is not created downhole through the use of a downhole steam generator, but rather injected downhole from the surface;

Figs. 4A and 4B illustrate another embodiment using a third vertical well 6 to inject or otherwise introduce steam into the formation and providing the upper horizontal well 7 on a slant or incline;

Fig. 5A illustrates another embodiment wherein the upper well is operated to inject a mobilizing fluid, such as a mixture of any of steam, heated water, light hydrocarbons or carbon oxides, into a hydrocarbon formation 10.

Fig. 5B illustrates another embodiment wherein the upper well is slanted and operated to inject a mobilizing fluid into a hydrocarbon formation 10.

Fig. 6 illustrates the various formation conditions surrounding the upper horizontal injection well 7 for the embodiment set forth in Fig. 5B;

Figures 7A and 7B illustrate modelling results for a well arrangement according to Fig. 5B, Fig. 7A showing concentration or distribution maps of each of oil So, gas Sg and temperature T at about 1 year from steam initiation for a layer at the well (layer 1 ) and a layer (layer 3) spaced laterally from the well;

Figures 8A and 8B also show the oil, gas and temperature distribution maps at 510 days from initiation;

Figures 9A and 9B also show the oil, gas and temperature distribution maps at 1020 days from initiation; and Figure 10 is a graph generated from the model applied to Fig. 5B, illustrating the instantaneous steam (injected) to oil (produced) ratio (SOR) for conventional SAGD and for vent well scenarios. DESCRIPTION OF THE PREFERRED EMBODIMENTS

As shown in the prior art arrangement of Fig. 1 , a conventional steam- assisted gravity drainage (SAGD) is shown having a horizontal well pair provided to a subterranean formation 10 supporting a hydrocarbon reservoir. A generally coextensive upper and lower well pair is completed in a formation, the lower well extending generally horizontally in the formation. As shown, an upper horizontal well 7 is employed to inject a mobilizing fluid such as steam 20 and optionally solvent into the formation 10 while a lower horizontal well 5 is employed for producing oil. Fluid communication is established between the upper and lower wells. The lower well is operated to produce the hydrocarbons mobilized downward towards the lower well in a gravity-controlled process.

Typical solvents include a light hydrocarbon or a combination of light hydrocarbons. Further, the mobilizing fluid can include a carbon oxide or a combination of carbon oxides. The introducing of mobilization fluids, including at least steam 20, can comprise introducing steam, a light hydrocarbon, carbon oxides or mixtures thereof. Further, the instruction of each mobilizing fluid can be in mixtures or applied in an alternative fashion. For simplicity, the embodiment herein is described in the context of the introduction of steam. As the steam 20 is injected into the formation 10, the oil therein is heated by the latent heat present in the steam and results in the reduction of its viscosity, allowing the heated oil to flow down or drain in a gravity-controlled process into the lower producing well 5. Further, as the steam is injected, a steam chamber 1 1 is created about the upper injection well 7, which eventually extend downwardly to about the lower producing well 5.

Over time, non-condensable gases collect adjacent in an upper portion of the steam chamber 1 1 . Non-condensable gases can be released from the in-situ reservoir and include CO2 and Chk At about a threshold condition or concentration, the build-up or increased concentration of non-condensable gases can form a layer or barrier at the top of the steam chamber and reduced mobilization efficiency, acting to isolate the injected steam from the yet-to-be- treated heavy oil in the formation. The barrier results in inefficient transfer of heat from the injected steam to the yet-to-be-treated formation, as the steam must first travel through the layer of non-condensable gases before it can transfer any heat to the formation and can interfere with any solvent-aided effectiveness.

In other prior art operations, light hydrocarbons, actin as solvents can be introduced to the reservoir as a solvent flood. Fig. 1 further illustrates a channelling effect that can sometimes occur when performing such solvent floods. Concentration of solvent vapour can also build up within the steam chamber, however in another phenomenon, the highly mobile solvent vapours 25 can preferentially flow towards a low pressure void formed about the lower producing well 5, creating wormholes which can bypass untreated heavy oil and thereby inhibit mobilization and production of the in situ oil.

With an objective to reduce the inhibitory effect of non-condensable gases and bypassing light solvents, if introduced and to mitigate against poor solvent management, means are provided herein to vent such non-condensable gases.

INDEPENDENT VENT WELL

With reference to Fig. 2, in a first embodiment, a third well 6 is provided in addition to the conventional well pair. The third well is located at about the toe 3 of the upper well 7 and completed to be in fluid communication with an upper portion of the steam chamber 1 1 for relieving the reservoir of non- condensable gases 30 collected therein. As shown, mobilizing fluid such as steam, solvent and mixtures thereof can be injected into the formation 10 through the upper horizontal injection well 7. As the steam 20 travels along the horizontal portion thereof, ports formed therealong permit steam 20 to enter into and permeate through the formation 10. Injected steam 20 can exit the upper well 7 and enter into the formation using well known technologies, such as screened or otherwise ported sections of the well.

As the steam 20 travels or permeates through the formation, the latent heat in the steam heats the formation 10 to reduce the viscosity of the oil therein, and also releases or creates non-condensable gases 30 which collect within the steam chamber 1 1 . As the non-condensable gases 30 are less dense than the chamber environment, the non-condensable gases rise or otherwise migrate towards the upper portion of the steam chamber 1 1 , collecting and building up in concentration to a threshold concentration. At about this threshold concentration, the accumulation of non-condensable gases 30 can be sufficient to negatively impact the heat transfer from the injected steam to the yet-to-be-treated formation.

The third vertical well 6 taps into the upper portion of the steam chamber 1 1 and fluidly connects thereto for providing a vent that permits the removal of non-condensable gases 30 collected therein.

The venting, removal, or transport of any collected gases 30, including in-situ generated non-condensable gases and introduced solvent vapour, mitigates the build up and increasing of concentration of the non-condensable gases and/or solvent vapour. Removal of such non-condensable gases reduces the formation of a thermal barrier between the injected steam 8 and the yet-to-be-treated formation.

The embodiment illustrated in Fig. 2 can be adapted to be used with existing horizontal well pairs where primary production has been completed, such as SAGD, CHOPS-depleted formations or other well pair completions.

INDEPENDENT STIMULATION WELL

Fig. 3A is an illustration of an alternate embodiment of thermal mobilization and venting of the non-condensable gases resulting therefrom.

As shown, in an embodiment, a third vertical well 6 can be drilled to fluidly connect with the steam chamber 1 1 of a depleted reservoir near the toe 3 of the original and upper horizontal well 7. The third vertical well can be equipped with a source of stimulation of mobilization fluids, provided in a well that is physically independent of the well pair. This is ideal for depleted reservoirs, previously completed and operations in a conventional manner, the upper well of the well pair being conventional in its construction, providing a single flow path, formerly for steam injection. Herein, one source of stimulation or mobilization fluids is a downhole steam generator 60 for generating in-situ steam within the formation and/or steam chamber. One such steam generator 60 can be downhole burner.

As the steam generator 60 produces steam 20 that permeates through the formation 10, mobilized heavy oil 25 and condensed water continue to be produced by the lower producing well 5, while non-condensable gases 30 are collected within the steam chamber 1 1 . The non-condensable gases 30 increase in concentration at the upper portion of the steam chamber 1 1 and form a non- condensable gas barrier of gases.

In processes using solvent flood, the highly mobile solvent vapours can also preferentially flow or channel 40 into the lower pressure areas surrounding the lower producing well 5, causing a channelling effect and creating wormholes that can bypass untreated heavy oil in the formation.

As steam is created and injected into the formation by the third vertical well 6, the past and conventional direction of flow of the upper horizontal well 7 is reversed, such that the upper horizontal well 7 serves as a vent, venting or removing the build up of non-condensable gases near the top portion of the steam chamber 1 1 . Fig. 3B illustrates a similar process as shown in Fig. 3A, except that steam is not created downhole through the use of the downhole steam generator 60, but rather injected downhole from the surface.

As introduced above, the embodiments illustrated in Figs. 3A and 3B can be adapted to be used with existing horizontal well pairs where primary production has been previously completed, such as SAGD, CHOPS depleted formations, or other well pair completion operations.

In embodiments in which the upper well is substantially horizontal, the effectiveness of the upper well to operate as the vent, or as both a vent and the source of stimulation/mobilizing fluids is dependent on various factors including the location of upper well with respect to the overburden and the extent of collection of non-condensable vapours. An optional location of the third well 6, as a supplementary vent, can be completed as necessary to maximize removal.

In other embodiments, the upper well 7 itself can be modified or completed with the expectation that it will participate in the venting aspects described herein.

Thus, mobilizing fluids 20 can be introduced to the formation 10 by way of an independent third well 6, the mobilizing fluid either injected from the surface or generated from the downhole well apparatus 60, the mobilizing fluid being thus injected or generated in the vicinity of the upper well 7 at any location within fluid communication of the upper well, the mobilizing fluid preferentially travelling along the extent of the upper well 7 towards the heel 2 of the upper well 7 and contacting the surrounding formation 10 as the mobilizing fluid is conducted through the slanted section of the upper well 7. The mobilizing fluid can alternatively be introduced from the surface, the mobilizing fluid travelling along the extent of the upper well towards the toe 3 and contacting the surrounding formation. SLANTED UPPER WELL

Figs. 4A and 4B illustrate other embodiments of the arrangement of Figs. 3 and 3B, the well pair arrangement using a third vertical well 6 to inject or otherwise introduce steam 20 into the formation 10 and providing the upper well 7 as a vent. In these embodiments, the upper well 7 is slanted upwardly from toe 3 to heel 2. The upper well extends generally horizontally with the heel of the upper well located higher relative to the toe 3 of the upper well, the differences in elevation between toe 3 and heel 2 being greater than industry tolerances for conventional horizontal wells.

Non-condensable gases 30 that rise in the steam chamber 1 1 are taken into the upper well for transport out of the formation 10 for venting to surface. In the slanted configuration, the collected gases 30 can rise along the slanted upper horizontal well 7 towards the heel section thereof. At the heel 3, the non- condensable gases can be vented such as at an intake 31 .

Further, as the non-condensable gases are vented from the upper portion of the steam chamber 1 1 , a pressure gradient is formed with lower pressures within the upper portion enabling any solvent vapour to also rise away from the lower horizontal producing well 5, per the intended action in solvent flood, minimizing the debilitating effect of channelling 40. As shown in Figs. 3A and 3B, the non-condensable gases can enter into the upper well 7 along all or a portion of its length. As shown in Figs. 4A and 4B, the non-condensable gases can be urged to enter into the upper well 7 at the heel 2 such being limited to intake 31 .

COMBINATION INJECTION AND VENT

Having reference to the embodiments set forth in Figs. 5A, 5B and 6, an upper well 7 is provided in a subterranean formation 10 above a co-extensive, generally horizontal production well 5. The upper well 7 is operated to inject a mobilizing fluid 20, such as a mixture of any of steam, heated water, light hydrocarbons or carbon oxides, into the hydrocarbon formation 10. The injected steam heats the oil in the formation for mobilizing the oil 25 towards the lower horizontal producer well 5. The upper well 7 also collects the gases 30 that are circulated or conducted upwardly and along the void space around the upper well towards the elevated heel 2.

For each embodiment, the upper well 7 can include a venting mechanism which may be controlled by a control valve 15, either installed at the surface or below the surface. The venting mechanism allows the slanted upper well to control certain characteristics of the reservoir. Further, the venting mechanism can provide additional control of pressure to the cap rock above the formation. The mobilizing fluid being thus injected or generated in the vicinity of the upper well at any location within fluid communication of the upper well for control by the control valve or valves. Non-condensable gases 30 that, in a conventional horizontal implementation, collect at the top of the steam or solvent chamber 1 1 are instead conducted upwards along the length of the upper well towards the vent intake 31. As shown, non-condensable gases 30 can enter the upper well at a vent intake 31 adjacent the upper end of the slanted upper well. The operator can control the flow through the control valve 15 and vent the non-condensable gases from the reservoir. Venting the gases allows for greater control of the injection and production process, including the control of the reservoir pressure, the reservoir temperature and the behaviour of the insulating layer of non-condensable gases. The control valve 15 is installed in the vent passage above the horizontal portion of the upper well, such as adjacent the heel or at or substantially near the surface. The control valve operates via remote control. The pressure of the upper well can be maintained, increased or decreased to change or maintain the delivery of the mobilizing fluid, including the flow rate of the mobilizing fluid through the upper well, the flow rate of the mobilizing fluid into the surrounding formation, and the temperature of the mobilizing fluid at various locations within the formation 10 and upper well 7.

In Fig. 5A, gases are collected along the upper well and vented. In Figs. 5B and 6, the upper well 7 is slanted, inclined or oriented such that the heel 2 of the well is located at a higher elevation than the toe 3 of the well, the difference in elevation between toe and heel being beyond the normal tolerances expected during the drilling of a conventional, generally horizontal well. The slanted upper well also further aids in enhancing the circulation of mobilizing fluid upward through the reservoir towards the elevated heel from where it can then be vented. This directs the mobilizing fluid away from the lower production well, thereby avoiding the effect of channelling 40 common with conventional horizontal well arrangements, wherein the mobilizing fluid preferentially flows towards the lower production well, bypassing the oil and inhibiting production. Further control of the behaviour of the mobilizing fluid is enabled through the operation of the venting mechanism.

Mobilizing fluid 20 in injected through the upper well 7, such as any one of steam, heated water, light hydrocarbons and carbon oxides or mixtures thereof, into the hydrocarbon reservoir. The upper horizontal injection well 7 is preexisting or completed above lower producing well 5, and an inner conveyance string 8, such as a coiled tubing string, can be positioned within the upper horizontal injection well 7 for providing a fluid passageway for injecting or delivering the mobilized oil 25 downhole. The inner conveyance string 8 forms an annular space 8a with the upper horizontal well 7, which can be employed to serve as a second fluid passageway, allowing non-condensable gases to be vented therethrough.

The steam is injected through the inner conveyance string 8 and conducted through crossovers across the annulus 8a to the subterranean formation 10. The non-condensable gases 30 collect in the upper portion of the steam chamber 1 1 and be taken in along the upper well into the annulus for transport to the heel and vented through a venting mechanism at about the heel 2 of the upper horizontal injection well 7. Similarly to the earlier embodiments shown in Figs. 4A and 4B, the venting may be controlled by a control valve 15, either installed at the surface or below the surface. The venting mechanism allows the slanted upper well 7 to control certain characteristics of the reservoir.

Turning to Fig. 6, repeating the arrangement as set forth in Fig 5B, as the steam is injected into the formation 10, the steam 20 transfers heat to the surrounding formation, causing the viscosity of the heavy oil to decrease and the oil to gravity-drain down towards the lower producing well 5. At the same time, non- condensable gases 30 collect in the upper portion of the steam chamber 1 1 . The collected gases are taken into the upper well annular space 8a formed between the upper horizontal injection well 7 and the inner conveyance string. The annular space 8a is fluid connected with surface for venting.

As shown in the inset graph, Applicant notes that once the steam chamber 1 1 is formed and during the continued injection of steam, the temperature of the steam chamber remains relatively constant, while the temperature in the venting annular space steadily increases as increasing amounts of non-condensable gases are vented from the steam chamber. Further, Applicant notes that the ratio of the concentration of non-condensable gases to the concentration of steam will decrease as venting continues.

Example

The venting of gas collection in the formation and its effect on solvent to oil recovery ratio, rate of increase of oil recovery and cumulative oil production has been modeled. Applicant simulated the embodiment of Fig. 5B, using a slanted upper well configuration using a computer modelling program built to predict the behaviour of water and heavy oil in a reservoir subject to the introduction of energy. The model was developed using Flashpoint, LLC's GFLASH solver, a general purpose, equation of state-based, multi-component, multiphase flash code, coupled with Stanford University's Automatic Differentiation General Purpose Research Simulator (AGPRS) for thermal reservoir flow simulations. The model had previously been shown to capture all of the well-known multi-phase (vapor-liquid, liquid-liquid, and vapor-liquid-liquid) behavior of heavy oil/bitumen reservoir fluids in enhanced oil recovery (EOR) applications, and has been validated by matching both dead oil and live oil API gravity and density.

The program was set up to model a configuration similar to that shown in Fig. 5B, and compared that configuration against the conventional arrangement of a parallel SAGD well pair.

The model was set with the following parameters:

For the model, the slant of the upper well descended heat-to-toe 14 m over a 1000m horizontal extent, for an angle of 0.8°.

Having reference to Figure 10 the results show that the slanted upper well as a steam and a vent well configuration results in improved enhanced oil recovery than in conventional SAGD. As shown in Fig. 10, the recovery occurs at a lower steam-to-oil ratio as compared to a configuration utilizing a conventional a horizontal non-venting upper well.

For interpretation of the distribution map pairs one can compare the oil distribution So over 360, 510 am 1020 days for Figs. 7A, 8A and 9A respectively. On the distribution, opposite to the arrangement of Fig. 5B, the toes of the wells 5, 7 are at the left and the heels are to the right. Thus, steam is flowing from right to left, and oil is produced left to right. Gas is vented left to right.

As shown in Fig. 7A, the oil is being depleted at the left, low relative concentration, with higher relative concentrations shown to the right approaching the heel between the upper and lower wells. As time progresses, as shown in Fig. 8A, the oil is further depleted, the low concentration depleted areas extend further right towards the heel with some oil still at higher concentrations at the right, but less than before, illustrating that much of the mobilized oil has already been produced. As the operation progresses to near end of life, as shown in Fig. 9A, the oil is further depleted, the low concentration depleted areas extending almost entirely to the right to the heel with a very small amount of oil remaining at higher concentrations just at the heel as most of the mobilized oil has already been produced. Note that the temperature of the steam chamber T is steady saturating across the entirety of the horizontal extent of the well pair over time, with the temperature fairly uniform and maximized across the entire chamber by 1020 days.

Similarly, looking at gas distribution Sg, over time the non- condensable gas concentration long the upper well is moderate at 360 days (at a relative concentration of about 0.7 in Fig. 7A), and increasing steadily with an increasingly larger areas in an upper portion of the reservoir along the upper well increase to some approaching concentrations of 0.8 at 510 days (Fig. 8A) and a large volume of gas at 0.8 or higher by 1020 days (Fig. 9A). In all cases illustrated in Figs. 7B, 8B and 9B, layers three being laterally offset from the wells shows the diminishing effect for the thermal recovery as one moves further from the well pair.

Claims

CLAIMS:

1 . A method of producing hydrocarbons from a heavy oil reservoir in a subterranean formation having a generally parallel upper and lower well pair completed therein for steam-assisted gravity drainage operations, comprising:

injecting at least steam into the formation;

forming a steam chamber along the upper well for mobilizing heavy oil and collecting non-condensable gases in an upper portion thereof;

establishing a flow of mobilized heavy oil from about the steam chamber in a gravity-controlled process for production from the lower well; and

venting the collected gases through a vent to surface.

2. The method of claim 1 wherein the venting of the gases further comprises providing a third well completed in the upper portion of the formation for venting non-condensable gases to surface.

3. The method of claim 1 wherein the venting of the gases further comprises providing a third well completed in the steam chamber for venting non- condensable gases to surface.

4. The method of claim 1 wherein the upper well forms two passages, one passage for injection of mobilization fluids including steam, and another passage for the collecting of collected non-condensable gases and venting to surface.

5. The method of claim 1 wherein venting of the gases further comprises installing a conduit within the upper well for forming two flow passages to surface, comprising introducing the mobilization fluids through the conduit, and venting the non-condensable gases through an annular path about the conduit to surface.

6. A method of producing hydrocarbons from a heavy oil reservoir in a subterranean formation, comprising:

providing at least two wells extending to the subterranean formation containing the reservoir for production by steam-assisted gravity drainage from a heavy oil reservoir in the subterranean reservoir;

introducing mobilization fluids, including at least steam, through a first well to the formation for forming a steam chamber and mobilizing heavy oil to flow downward in gravity-controlled process to a horizontally extending production well therebelow, non-condensable gases rising upwardly in the formation;

producing mobilized oil from the lower well; and

collecting the non-condensable gases and venting the gases to surface.

7. The method of claim 6 wherein the first well is a horizontally extending upper injection well for introduction of the mobilization fluids, the method further comprising venting the non-condensable gases through a third well extending between an upper portion of the formation and the surface.

8. The method of claim 6 wherein the first well is a horizontally extending upper well, the method further comprising:

injecting the mobilization fluids through a first passage in the upper well; and

venting the non-condensable gases through a second passage in the upper well.

9. The method of claim 6 further comprising:

introducing the mobilization fluids through a third well completed in an upper portion of the formation; and

collecting and venting non-condensable gases through the first well to surface.

10. The method of claim 9 wherein introducing the mobilization of fluids at the third well further comprises:

operating a downhole burner in the reservoir for production of the mobilizing fluids including products of combustion; collecting and venting at least the products of combustion through the first well for venting to surface; and

collecting and venting non-condensable gases through the first well to surface.

1 1 . The method of claim 9 wherein the first well is a generally horizontally extending upper well extending along the formation from a toe to a heel, the third well being completed at about the toe.

12. The method of claim 1 1 wherein the first well is slanted uphole from the toe to the heel.

13. The method of claim 12 wherein the non-condensable gases are collected at about the heel.

14. The method of claim 6 wherein the introducing mobilization fluids, including at least steam, comprises introducing steam and light hydrocarbons.

15. The method of claim 6 wherein the introducing mobilization fluids, including at least steam, comprises introducing steam and carbon oxide or a combination of carbon oxides.

16. The method of claim 6 wherein the introducing mobilization fluids, including at least steam, comprises introducing steam, a light hydrocarbon, carbon oxides or mixtures thereof.

17. The method of claim 6 further comprising controlling the venting of non-condensable gases to surface for controlling pressure of the reservoir.

18. Apparatus for producing hydrocarbons by steam-assisted gravity drainage from a heavy oil reservoir in a subterranean formation, non- condensable gases being created by such production, comprising:

a first and upper injection well for the injection of a mobilization fluid, comprising at least steam, to the formation and a second lower production well completed in the formation for mobilization of the heavy oil in the reservoir for gravity-drainage to the lower well; and

a vent passage extending between a location in an upper portion of the formation to the surface.

19. The apparatus of claim 18 wherein the vent passage comprises a third well extending between surface and an upper portion of the formation for venting of the non-condensable gases to surface.

20. The apparatus of claim 18 wherein the third well is formed by the upper injection well, the upper injection well comprising two passages, one for injection of the mobilization fluids, and second path forming the vent passage for the collection and venting of non-condensable gases from the reservoir.

21 . The apparatus of claim 18 wherein the third well is an independent well completed to about the toe of the upper injection well.