METHOD AND SYSTEM OF PRODUCING HYDROCARBON

Heated production well for enhancing production of hydrocarbons from a hydrocarbon reservoir are described. By heating the production well, heat is imparted to the reservoir and helps to mobilize the hydrocarbons and improve hydrocarbon production. A method of producing hydrocarbons from a hydrocarbon reservoir, includes using a heated production well positioned in the hydrocarbon reservoir, the heated production well having a higher temperature than the ambient temperature of the hydrocarbon reservoir.

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Description
INCORPORATION BY REFERENCE OF PRIORITY APPLICATIONS

This application claims the benefit of priority of U.S. Provisional Patent Application No. 61/910,107 filed Nov. 28, 2013, which is hereby incorporated by reference in its entirety.

FIELD

The present disclosure relates to methods and systems for producing hydrocarbons from a hydrocarbon reservoir and more specifically to methods and systems for producing hydrocarbons that utilize a heated production well for imparting heat into the hydrocarbon reservoir to increase mobility of the hydrocarbons therein.

BACKGROUND

Production of hydrocarbons from subsurface reservoirs is a difficult endeavor that generally necessitates the use of wellbores positioned in the hydrocarbon reservoirs and techniques for producing the hydrocarbons to the surface for subsequent processing and use. In a basic hydrocarbon production operation, a production well may be drilled to provide access to a subsurface reservoir. Natural mechanisms may then provide lift for producing hydrocarbons to the surface. A primary production phase of hydrocarbon production may involve a producer well using natural lift to produce hydrocarbons to the surface. Following the primary phase of production, a secondary phase of hydrocarbon production may occur. Here, artificial lift techniques may be used, which may include the injection of liquid or gas into the reservoir to assist in production of hydrocarbons from the production well. In some cases, pumps may be used to provide lift, such as electronic submersible pumps (ESPs) or progressive cavity pumps (PCPs). Injection of other substances, for example, water or solvent may occur through additional wells drilled in the vicinity of the production well, and these additional wells are typically known as injection wells. Further or enhanced oil recovery may occur, using any of a variety of methods for mobilizing reservoir hydrocarbons to the surface through a production well.

Some examples of further oil production methods include steam-assisted gravity drainage (SAGD). In SAGD, steam may be injected underground through an injection well, the upper well of a horizontal well pair, softening oil in a reservoir. The softened mobilized oil generally flows to a lower production well of the horizontal well pair, facilitating the production of the mobilized oil to the surface. Water flooding is another approach for improving oil production, in which water is injected into a reservoir through one or more injection wells, which assists in sweeping oil towards and displacing oil to the surface through a production well. Polymer flooding approaches, which are related to water flooding methods, are also possible. In polymer flooding, a polymer is injected into a reservoir through an injection well. Polymer flooding may act similarly to water flooding, but increases the viscosity of the water flood and the added polymer may further improve the ability to produce hydrocarbons from the reservoir.

The characteristics of hydrocarbon reservoirs can vary significantly. The ambient temperature of the reservoir, the viscosity of the hydrocarbons, the thickness of the reservoir, the porosity of the reservoir, and geological considerations are all important factors affecting oil production operations. Steep viscosity gradients within a reservoir can also make efficient hydrocarbon production challenging.

There is a need for providing hydrocarbon production solutions for subsurface reservoirs for enhancing hydrocarbon production, for example, in reservoirs with geological limitations that impart pressure issues associated with various known production techniques, reservoirs that are too thin for certain hydrocarbon recovery methods, or reservoirs with low hydrocarbon mobility.

SUMMARY

In one embodiment, the present invention provides for a method of producing hydrocarbons from a hydrocarbon reservoir, the method comprising injecting fluid via an injection well into the reservoir; circulating a non-hydrocarbon based heated fluid through a production well to impart heat into the hydrocarbon reservoir; producing hydrocarbons from the hydrocarbon reservoir to a production site, wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

In a further embodiment of the method or methods outlined above, circulating a non-hydrocarbon based fluid is initiated after a start-up phase of the hydrocarbon production has been completed.

In a further embodiment of the method or methods outlined above, the non-hydrocarbon based heated fluid comprises water.

In a further embodiment of the method or methods outlined above, the production well comprises an insulated coil tube for transferring the heated fluid to various portions of the production well.

In a further embodiment of the method or methods outlined above, the production well comprises an insulated coil tube for transferring the heated fluid to the toe of the production well.

In a further embodiment of the method or methods outlined above, the step of circulating the non-hydrocarbon based heated fluid through the production well and producing hydrocarbons from the hydrocarbon reservoir are carried out simultaneously.

In a further embodiment of the method or methods outlined above, the steps of injecting fluid via the injection well and circulating the non-hydrocarbon based heated fluid through the production well are carried out simultaneously.

In a further embodiment of the method or methods outlined above, fluid is injected into the reservoir via injection wells positioned substantially horizontally on both sides of the production well.

In a further embodiment of the method or methods outlined above, the non-hydrocarbon based heated fluid comprises steam.

In a further embodiment of the method or methods outlined above, the non-hydrocarbon based heated fluid circulating through the production well is between about 30° C. and about 180° C.

In a further embodiment of the method or methods outlined above, the injection well and the production well are horizontal wells spaced apart from between about 25 m and about 200 m.

In a further embodiment of the method or methods outlined above, between about 50 m3/day and about 120 m3/day of the non-hydrocarbon based heated fluid is circulated through the production well.

In a further embodiment of the method or methods outlined above, the production well is insulated to reduce heat loss of the non-hydrocarbon based heated fluid.

In a further embodiment of the method or methods outlined above, the heated fluid temperature is 80° C. or below and a heat exchanger is used to heat the non-hydrocarbon based heated fluid.

In a further embodiment of the method or methods outlined above, the hydrocarbon reservoir has a viscosity of below 100,000 cP before injection of the non-hydrocarbon based heated fluid.

In a further embodiment of the method or methods outlined above, the hydrocarbon reservoir has a viscosity of between about 500 and 20,000 cP before injection of the non-hydrocarbon based heated fluid.

In a further embodiment of the method or methods outlined above, the hydrocarbon reservoir has a viscosity of between about 1,000 and 10,000 cP before injection of the non-hydrocarbon based heated fluid.

In a further embodiment of the method or methods outlined above, the hydrocarbon reservoir has a thickness of 10 m or less.

In a further embodiment of the method or methods outlined above, the hydrocarbon reservoir has a thickness of between about 3 m and 6 m.

In another embodiment, a system for producing hydrocarbons from a hydrocarbon reservoir, comprises a first injection well positioned in the hydrocarbon reservoir for injecting fluid into the reservoir; and a production well positioned in the hydrocarbon reservoir, the production well comprising a wellbore for circulating a non-hydrocarbon based heated fluid therein for imparting heat to the hydrocarbon reservoir and producing hydrocarbon from the reservoir, wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

In another embodiment, a method of producing hydrocarbons from a hydrocarbon reservoir, the method comprises circulating a non-hydrocarbon based heated fluid through a production well to impart heat into the hydrocarbon reservoir; producing hydrocarbon from the hydrocarbon reservoir to a production site, wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the present disclosure will now be described, by way of example only, with reference to the attached Figures. The patent or application file contains at least one drawing executed in color. Copies of this patent or patent application publication with color drawing(s) will be provided by the Office upon request and payment of the necessary fee.

FIG. 1 is a schematic of one embodiment of a heated production well for producing hydrocarbons from a hydrocarbon deposit;

FIG. 2 is a schematic of a top view of another embodiment comprising a heated production well for producing hydrocarbons from a hydrocarbon deposit;

FIG. 3 is a graph showing hot water pilot performance of a pilot project utilizing one embodiment of a system for producing hydrocarbons from a hydrocarbon deposit using a heated production well;

FIG. 4 is a graph of a projection of hydrocarbon production using a system for producing hydrocarbons from a hydrocarbon deposit using a heated production well; and

FIG. 5 is a graph showing hot water pilot performance results as compared to simulation prediction results of one embodiment of a system for producing hydrocarbons from a hydrocarbon deposit using a heated production well.

 DETAILED DESCRIPTION

Described herein are methods, systems, apparatuses, techniques and embodiments suitable for producing hydrocarbons from a subterranean hydrocarbon reservoir. It will be appreciated that the methods, systems, apparatuses, techniques and embodiments described herein are for illustrative purposes intended for those skilled in the art and are not meant to be limiting in any way. All reference to dimensions, capacities, embodiments or examples throughout this disclosure, including the Figures, should be considered a reference to an illustrative and non-limiting embodiment or an illustrative and non-limiting example.

Generally, hydrocarbons are produced from a hydrocarbon reservoir using a production well positioned in the hydrocarbon reservoir. As referred to herein, the term “positioned” refers to a production well drilled into, penetrating, accessing or otherwise located in, or at least partially located in, the hydrocarbon reservoir such that hydrocarbons may be produced from the reservoir and brought to surface or other production site. The production well may be used in combination with other types of wells in an effort to mobilize the hydrocarbons in the reservoir to increase production as viscosity of the hydrocarbons is generally very high. Examples of these recovery schemes include SAGD, cyclic steam stimulation (CSS), a solvent aided process (SAP), water flood or polymer flood techniques.

In SAGD, for example, before hydrocarbon production may begin, a start-up phase is initiated wherein the hydrocarbons of the reservoir are sufficiently mobilized such that they may be produced. Start-up may employ various known means and methods including, for example, thermal means and methods. One such start-up method involves the injection of steam into the reservoir, sometimes for weeks, until the hydrocarbons are sufficiently mobilized such that they may be produced via a production well.

The methods, techniques, systems and apparatuses of the present invention, in various embodiments, are generally directed, but not limited, to enhancing hydrocarbon recovery post start-up once the hydrocarbons in the reservoir have at least some mobility or in reservoirs with low enough viscosities that a start-up phase is not required. Therefore, the length of time that the methods, techniques, systems and apparatuses of the present invention are applied can be for a portion of or the full life cycle of a well. Various optional parameters related to the viscosity of the hydrocarbons in the reservoir are discussed below in more detail. It will be appreciated that the present invention is not limited to these viscosities nor are the application of the methods, techniques, systems and apparatuses of the present invention limited to use or implementation post start-up.

In one embodiment, the present invention provides for a heated production well such as that shown with reference to FIG. 1. The heated production well 20 penetrates a hydrocarbon reservoir 80 and imparts heat to the reservoir 80 for example by conduction. In turn, the heated hydrocarbons of the reservoir 80 mobilize or become more mobile and hydrocarbon production is generally increased. It will be appreciated that any method of heating the production well may be used. The production well 20 should be heated to above the ambient temperature of the reservoir 80 and may be heated significantly above the ambient temperature of the reservoir to thereby further mobilize the hydrocarbons therein via, for example, conduction.

Examples of various methods of heating the production well 20 include but are not limited to an electric heating coil in the production well or heated fluid.

The example shown in FIG. 1 uses a non-hydrocarbon based heated fluid, such as water, to heat the production well 20. It will be appreciated that the water may be produced water and may include trace or residual amounts of hydrocarbon or contaminants or impurities. Typically, the fluid may be heated at the surface using conventional heating methods such as a boiler, a heat exchanger including a line heater, or other suitable means. An insulated coil tubing 40 within the production well 20 delivers heated fluid into the production well 20. The insulated coil tubing 40 may deliver the heated fluid to various or multiple locations within the production well 20. In one embodiment the heated fluid is delivered to the toe of the production well 20 and circulates back to the surface together with produced hydrocarbons. A surface heater associated with the production facilities 70 may be used to heat the fluid and may include for example a boiler or a heat exchanger to heat fresh or produced water or combinations thereof. For higher temperatures a boiler may be more effective. As outlined above, the heated fluid should be at a temperature higher than the ambient temperature of the reservoir. For example, reservoir temperatures typically range between 15° C. and 30° C. but may range from about 8° C. to about 100° C. As such, it may be advantageous to heat the heated fluid to above 100° C. to temperatures as high as 180° C. In some embodiments, the fluid may be heated to 30° C. depending on the temperature of the reservoir. In some embodiments, a temperature of between 55° C. and 80° C. for the heated fluid may be sufficient. In another embodiment, a temperature of about 80° C. may be used or a temperature of less than 100° C.

At temperatures between about 30° C. and 180° C., a minimum pressure may be maintained such that steam will not be formed, for example, ˜1000 kPa. The system may be operated at higher fluid (water) temperatures, which can involve higher pressures, which may not be desirable due to cost and safety issues.

In situations where the temperature of the heated fluid is below about 80° C., a heat exchanger may be sufficient to heat the heated fluid at the surface. In addition, the production well 20 may be insulated to further prevent heat loss during travel of the heated fluid within the well.

The well may include additional components as would be appreciated by those of skill in the art such as an intermediate casing 30, a surface casing 50 and a conductor pipe 60.

A production pump 90 may be used to facilitate production of the hydrocarbons to the surface and the production facility as needed. It will be appreciated that any suitable means of pumping the hydrocarbons to the surface may be used. For example an electronic submersible pump (ESP) or a progressive cavity pump (PCP) may be used. It should be taken into consideration that temperatures may be higher than normal and volumes may be higher than normal, thereby requiring a pump that can accommodate such conditions.

An alternative hydrocarbon production system 100 is shown in FIG. 2 wherein injection wells 110 and 120, sometimes referred to as edge wells, may be spaced parallel to the production well 130 or may be spaced to substantially match the contour of the reservoir. The production well 130 includes an insulated coil tubing 40 for injecting heated fluid, such as water, into the production well 130 for circulation through the well and back to the surface and the production facilities 70 together with produced hydrocarbons from the reservoir. The injection wells 110 and 120 inject fluid, optionally heated fluid, into the reservoir to sweep hydrocarbons towards and into the production well 130. It will be appreciated that the production well may follow the contour of the reservoir. It will also be appreciated that additional injection wells may be included in the well system architecture as can additional production wells placed in association or reservoir communication with the edge wells.

Various amounts of heated fluid may be circulated through the production well 130 depending on the viscosity, temperature, and nature of the reservoir, the length of the well, and the temperature of the heated fluid. As outlined above, the temperature of the heated fluid circulating through the production well should be above the ambient temperature of the reservoir. Typical ranges of fluid flow are from 50 to 120 m3/day or about 80 m3/day. It will be appreciated that at initial stages the fluid flow may begin at 0 m3/day and ramp up to 120 m3/day or more as desired. The temperature of the heated fluid, for example, water, circulating through the production well 130 may be between 30° C. and 180° C. Typically, reservoir temperatures are between 15° C. and 30° C. but may range from about 8° C. to about 100° C. As such, it may be advantageous to heat the heated fluid to above 100° C. to temperatures as high as 180° C. In some embodiments, it the fluid may be heated to 30° C. depending on the temperature of the reservoir. In some embodiments, a temperature of between 55° C. and 80° C. for the heated fluid is sufficient. In situations where the temperature of the heated fluid is below about 80° C., a heat exchanger may be sufficient to heat the heated fluid at the surface. In addition, the production well 130 may be insulated to further prevent heat loss during travel of the heated fluid within the well.

A production pump 90 (as shown in FIG. 1) may be used to facilitate production of the hydrocarbons to the surface and the production facility as needed. It will be appreciated that any suitable means of pumping the hydrocarbons to the surface may be used. For example an electronic submersible pump (ESP) or a progressive cavity pump (PCP) may be used. It should be taken into consideration that temperatures may be higher than normal and volumes may be higher than normal and a suitable pump can advantageously be used.

The injection wells 110 and 120 may be spaced apart from the production well 130 any suitable distance as would be appreciated in the art. For example, between about 25 m and about 200 m. Alternatively, from 50m to 100m. A system may be implemented that includes a plurality of production wells and injection wells situated relative one another to allow for influence of the injection wells on multiple production wells. For example, a system may be implemented that includes 3 production wells and 5 injection wells.

Heated fluid circulated in or injected into the production well is generally recovered with negligible, little or no injection, input or leaking of the heated fluid into the reservoir.

Without being limited to theory, the heated fluid may uniformly heat the horizontal portion of the production well, thereby homogenizing oil viscosity around the production well and improving overall conformance of the fluid flood from the injection wells towards the production well. In contrast, without this homogenization of viscosity at the production well, and particularly in reservoirs with a steep viscosity gradient, the fluid flood from the injection wells may be less effective in uniformly sweeping hydrocarbons towards the production well due to fluid from the injection wells taking a more circuitous route through the reservoir.

An example of a method for producing hydrocarbons from a reservoir is described in further detail below, with reference to FIG. 3.

A pilot test of oil production from oil sands using hot water circulation was performed. In this non-limiting example, heating of a production well was achieved via hot water injection and circulation using insulated coiled tubing (ICT) to heat the production well in at least a part of the wellbore in communication with the hydrocarbon reservoir. The oil production from the well during the primary phase, edge hot water injection only phase, and edge hot water with hot water circulation in the producer phases are shown in FIG. 3 and FIG. 5. In the primary phase, oil production per day was below 50 bbls/d as indicated. Following a switch to an edge hot water injection phase, in which hot water was injected into the reservoir through edge wells, oil production did not change significantly, although production began to improve near the end of the phase. Upon entering the edge hot water and hot water circulation phase, however, oil production per day greatly improved up to about 200 bbls/d, as shown in FIG. 3 and FIG. 5. In this example, hot water circulation provided improvements in oil production rates from the reservoir, even in comparison to the hot water edge well injection phase of the pilot.

FIG. 5 shows the continued results of the pilot test of oil production during operation following the collection of results shown in FIG. 3. As can be seen as represented by the actual production results between August 2013 to August 2014, actual pilot performance has been at the high end of (or exceeding) simulation predication. This indicates that the simulated predictions should be suitable to justify forward development and implementation. It should also be noted that non-hydrocarbon based fluid has been injected/circulated as hot as 180° C. in pilot history. Further, an initial oil rate peak of >30 m3/d (between August and November 2012) represents the start of hot water circulation (at 80-100° C.), while a secondary peak in oil production (about 30 m3/d between May and July 2013) represents an increase in the circulation temperature from 100° C. to 180° C.

Injection of the non-hydrocarbon based heated fluid may begin following start-up of a production well, meaning that hydrocarbon production has commenced and initial mobilization of hydrocarbons in the reservoir has taken place via suitable means and methods.

FIG. 4 is a graph of a projection of hydrocarbon production using a system for producing hydrocarbons from a hydrocarbon deposit using a heated production well.

It will be appreciated that reference herein to increases in hydrocarbon production may refer to initial or short term hydrocarbon production and may also refer to overall and/or long term hydrocarbon production. It will be understood that hydrocarbon production may not begin until after a well start-up phase has taken place. Depending on the hydrocarbon reservoir, either short or long term hydrocarbon production increases or both may be observed. Any increase in hydrocarbon production at any stage throughout operation of the heated production well is meant to be encompassed by reference to an increase in hydrocarbon production as referred to herein. It will be appreciated that reference herein to a hydrocarbon reservoir encompasses hydrocarbon deposits and hydrocarbon formations and generally refers to any subterranean or subsurface hydrocarbons producible via a production well. In various embodiments, the reservoir may be a thinner reservoir where some methods of hydrocarbon production, for example SAGD, cannot be easily implemented, for example, in reservoirs that are 10 m or less in thickness. The reservoir may be between 3 m and 6 m in thickness. The hydrocarbon reservoir may be a reservoir that necessitates a low pressure approach, such as reservoirs without cap rock, and/or those reservoirs where the use of high pressure steam is not as appropriate due to, for example, geological considerations such as the lack of cap rock or circumstances including the presence of a gas cap or bottom water zone.

The viscosity of the hydrocarbons may allow for some hydrocarbon production before circulation of the heated non-hydrocarbon based fluid through the production well, for example where the viscosity is below 100,000 cP. In addition, for better results the hydrocarbons should have a viscosity high enough that heating results in an uptake in mobilization or reduced viscosity. In various embodiments, the reservoir may have a viscosity of between 500 cP and 20,000 cP or in other embodiments between 1,000 cP and 10,000 cP.

As referred to herein, the term “hydrocarbon” or “hydrocarbons” includes but is not limited to bitumen, oil, heavy oil, oil sands and any other hydrocarbon that may be produced via a production well.

It will be appreciated that a plurality of injection or edge wells may be used together with one or more production wells either alternating or adjacent thereto as desired within a hydrocarbon reservoir.

It will be appreciated that reference to the “production well” herein encompasses embodiments wherein the production well may be used to inject and/or circulate fluid therethrough in addition to being used to produce hydrocarbon either sequentially or concurrently from the reservoir.

It will also be appreciated that heat energy for heating the heated fluid, or the heated fluid itself, for circulation through the production well may at least partially be obtained or recycled from an alternative well site such as a primary pay zone operation. Alternatively, heated fluid or blowdown water from an alternative site such as for example a primary pay zone may be used as at least some of the heated fluid for circulation in the production well. It will be appreciated that hydrocarbons are recoverable through existing steam-assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), solvent aided process (SAP), or other operations from a primary pay zone with a typical thickness of about 25-30 m. A thinner (typically 5-10 m), pay zone above or beneath the primary pay zone may be referred to as a secondary pay zone. Often, these two zones are separated by an impermeable barrier. As such, it will be understood that heat reused or recycled from the primary pay zone, such as a thermal recovery operation including SAGD, may be used to provide heat to the operation in the secondary pay zone or operations as described herein. This may occur by transfer of the heat to the secondary pay zone through the geological formation, by using heated produced fluids, for example, produced water, from the primary pay zone recovery operation to heat the production well in the secondary pay zone, or by other suitable methods.

In an alternative embodiment, the secondary pay zone is at least partially heated by convective heating imparted by a thermal recovery scheme from the primary pay zone and the fluid circulated through the production well is at or near the at least partially heated temperature of the secondary pay zone. The heat imparted from the primary pay zone may also augment fluid injected from the edge or injection wells.

Further, the systems and methods described herein may be combined with other types of drilling techniques or well architectures to produce hydrocarbons, such as SAGD, cyclic steam stimulation (CSS), etc.

It will be appreciated that modifications, amendments and/or alterations to the systems, methods and concepts described herein may be carried out and are intended to be within the scope and spirit of the invention.

Claims

1. A method of producing hydrocarbons from a hydrocarbon reservoir, the method comprising:

injecting fluid via an injection well into the reservoir;
circulating a non-hydrocarbon based heated fluid through a production well to impart heat into the hydrocarbon reservoir; and
producing hydrocarbons from the hydrocarbon reservoir to a production site,
wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

2. The method of claim 1, wherein circulating a non-hydrocarbon based heated fluid is initiated after a start-up phase of the hydrocarbon production has been completed.

3. The method of claim 1, wherein the non-hydrocarbon based heated fluid comprises water.

4. The method of claim 1, wherein the production well comprises an insulated coil tube for transferring the heated fluid to various portions of the production well.

5. The method of claim 1, wherein the production well comprises an insulated coil tube for transferring the heated fluid to the toe of the production well.

6. The method of claim 1, wherein the step of circulating the non-hydrocarbon based heated fluid through the production well and producing hydrocarbons from the hydrocarbon reservoir are carried out simultaneously.

7. The method of claim 1, wherein the steps of injecting fluid via the injection well and circulating the non-hydrocarbon based heated fluid through the production well are carried out simultaneously.

8. The method of claim 1, wherein fluid is injected into the reservoir via injection wells positioned substantially horizontally on both sides of the production well.

9. The method of claim 1, wherein the non-hydrocarbon based heated fluid comprises steam.

10. The method of claim 1, wherein the non-hydrocarbon based heated fluid circulating through the production well is between about 30° C. and about 180° C.

11. The method of claim 1, wherein the injection well and the production well are horizontal wells spaced apart from between about 25 m and about 200 m.

12. The method of claim 1, wherein between about 50 m3/day and about 120 m3/day of the non-hydrocarbon based heated fluid is circulated through the production well.

13. The method of claim 1, wherein the production well is insulated to reduce heat loss of the non-hydrocarbon based heated fluid.

14. The method of claim 1, wherein the heated fluid temperature is 80° C. or below and a heat exchanger is used to heat the non-hydrocarbon based heated fluid.

15. The method of claim 1, wherein the hydrocarbon reservoir has a viscosity of below 100,000 cP before injection of the non-hydrocarbon based heated fluid.

16. The method of claim 1, wherein the hydrocarbon reservoir has a viscosity of between about 500 and 20,000 cP before injection of the non-hydrocarbon based heated fluid.

17. The method of claim 1, wherein the hydrocarbon reservoir has a viscosity of between about 1,000 and 10,000 cP before injection of the non-hydrocarbon based heated fluid.

18. The method of claim 1, wherein the hydrocarbon reservoir has a thickness of 10 m or less.

19. The method of claim 1, wherein the hydrocarbon reservoir has a thickness of between about 3 m and 6 m.

20. A system for producing hydrocarbons from a hydrocarbon reservoir, the system comprising:

a first injection well positioned in the hydrocarbon reservoir for injecting fluid into the reservoir; and
a production well positioned in the hydrocarbon reservoir, the production well comprising a wellbore for circulating a non-hydrocarbon based heated fluid therein for imparting heat to the hydrocarbon reservoir and producing hydrocarbon from the reservoir,
wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

21. A method of producing hydrocarbons from a hydrocarbon reservoir, the method comprising: wherein the non-hydrocarbon based heated fluid has a higher temperature than the ambient temperature of the hydrocarbon reservoir.

circulating a non-hydrocarbon based heated fluid through a production well to impart heat into the hydrocarbon reservoir; and
producing hydrocarbon from the hydrocarbon reservoir to a production site,
Patent History
Publication number: 20150144338
Type: Application
Filed: Nov 26, 2014
Publication Date: May 28, 2015
Inventors: Chong Sin CHAN (Calgary), Kirk Anthony Duval (Calgary)
Application Number: 14/555,513
Classifications
Current U.S. Class: Steam As Drive Fluid (166/272.3); Liquid Material Injected (166/272.6); Attacking Formation (166/307); With Heating, Refrigerating Or Heat Insulating Means (166/57)
International Classification: E21B 43/24 (20060101); E21B 36/00 (20060101); E21B 17/20 (20060101);