DK201570068A1

DK201570068A1 - Enhanced Oil Recovery Method

Info

Publication number: DK201570068A1
Application number: DK201570068A
Authority: DK
Inventors: Kristian Mogensen; Jens Henrik Hansen
Original assignee: Mærsk Olie Og Gas As
Priority date: 2013-06-07
Filing date: 2015-02-04
Publication date: 2015-02-23
Also published as: DK179456B1; WO2014195443A2; GB201310186D0; WO2014195443A3

Abstract

A method for recovering hydrocarbons from a formation 112, comprises: (a) injecting steam 122 in a formation 112 to form a steam chamber 118; (b) injecting at least one non-condensable gas (NCG) 124 in the formation 112; and (c) injecting steam 122 in the formation 112. the present method improves efficiency, performance, and/or oil recovery, without reduction in heat transfer from steam to hydrocarbons associated with co-injection of steam and non-condensable gases.

Description

Enhanced Oil Recovery MethodEnhanced Oil Recovery Method

FIELD OF THE INVENTIONFIELD OF THE INVENTION

The present invention relates to methods and systems for recovering hydrocarbons, and in particular, though not exclusively, heavy hydrocarbons, from an oil reservoir.The present invention relates to methods and systems for recovering hydrocarbons, and in particular, though not exclusively, heavy hydrocarbons, from an oil reservoir.

BACKGROUND TO THE INVENTIONBACKGROUND TO THE INVENTION

Many techniques exist for recovering hydrocarbons from a subterranean reservoir, in order to enhance and optimize oil and gas production. A particular challenge relates to the recovery of heavy or viscous hydrocarbons which typically exhibit high viscosity. A number of so-called "enhanced oil recovery" techniques are known in the art to improve recovery of heavy or viscous hydrocarbon fractions, including bitumen, which would otherwise not be recoverable using conventional production techniques. Viscous oils or heavy oils typically have a viscosity between 10 and 1,000,000 cP (between 10 and 1,000,000 mPa.s) at reservoir conditions, and do not flow at commercial rates unless diluted with a solvent or heated.Many techniques exist for recovering hydrocarbons from a subterranean reservoir, in order to enhance and optimize oil and gas production. A particular challenge relates to the recovery of heavy or viscous hydrocarbons which typically exhibit high viscosity. A number of so-called "enhanced oil recovery" techniques are known in the art to improve recovery of heavy or viscous hydrocarbon fractions, including bitumen, which would otherwise not be recoverable using conventional production techniques. Viscous oils or heavy oils typically have a viscosity of between 10 and 1,000,000 cP (between 10 and 1,000,000 mPa.s) at reservoir conditions, and do not flow at commercial rates unless diluted with a solvent or heated.

Steam injection is a common thermal recovery technique for heavy oils, which has been used in countries such as United States, Canada, Venezuela, and Oman. One such technique is the so-called "steam-assisted gravity drainage" (commonly known as SAGD). A conventional SAGD system comprises two horizontal wellbores, one located a few metres above the other, which are created through a subterranean formation containing heavy or viscous hydrocarbons. Steam is injected through the upper (injection) wellbore into the surrounding formation to create a steam chamber. Steam injected into the wellbore condenses in the reservoir and transfers its heat of vaporization to the reservoir fluids, e.g. heavy hydrocarbons, thereby reducing their viscosity sufficiently to allow the hydrocarbons to drain into the lower (production) wellbore and be pumped to the surface.Steam injection is a common thermal recovery technique for heavy oils, which has been used in countries such as the United States, Canada, Venezuela, and Oman. One such technique is the so-called "steam-assisted gravity drainage" (commonly known as SAGD). A conventional SAGD system comprises two horizontal wellbores, one located a few meters above the other, which are created through a subterranean formation containing heavy or viscous hydrocarbons. Steam is injected through the upper (injection) wellbore into the surrounding formation to create a steam chamber. Steam is injected into the wellbore condenses in the reservoir and transfers its heat of vaporization to the reservoir fluids, e.g. heavy hydrocarbons, thereby sufficiently reducing their viscosity to allow the hydrocarbons to drain into the lower (production) wellbore and be pumped to the surface.

Attempts have been made to further improve efficiency and performance of conventional SAGD techniques. US Patent Application Publication No. US 2003/0000711 (Gutek et al.) discloses injecting a viscosity reducing solvent into the reservoir in order to mobilise hydrocarbons and displace hydrocarbons. US Patent Application Publication No. US 2005/0082067 (Good et al) discloses a pair of injection and production wells. Good discloses injecting a non-condensable gas (NCG) in a first section to pressurize the first section, and injecting steam in a second section while producing the first section.Attempts have been made to further improve efficiency and performance of conventional SAGD techniques. US Patent Application Publication No. US 2003/0000711 (Gutek et al.) Discloses injecting a viscosity reducing solvent into the reservoir in order to mobilize hydrocarbons and displace hydrocarbons. US Patent Application Publication No. US 2005/0082067 (Good et al) discloses a pair of injection and production wells. Good discloses injecting a non-condensable gas (NCG) into a first section to pressurize the first section, and injecting steam into a second section while producing the first section.

Various attempts have been made to co-inject one or more non-condensable gases (NCGs) with the steam during formation of the steam chamber. Such attempts have been disclosed for example in US 2007/0199696 (Walford), US 2008/0017372 (Gates et al.), US 2010/0065268 (Gates et al), US 2010/0096126 (Sullivan et al.), US 2011/0120709 (Nasr et al.), US 2012/0043081 (Kjørholt), US 2012/0247760 (Wheeler et al.), US 2012/0273195 (Wheeler et al.), US 6,257,334 (Cyr et al.), WO 2010/084369 (Rochon), and WO 2012/119076 (Sultenfuss et al.). These documents disclose coinjection of a NCG with steam, in order to help mobilise hydrocarbons in the formation, and/or improve solubility of hydrocarbons in a solvent co-injected in the steam and NCG mixture.Various attempts have been made to co-inject one or more non-condensable gases (NCGs) with the steam during the formation of the steam chamber. Such attempts have been disclosed for example in US 2007/0199696 (Walford), US 2008/0017372 (Gates et al.), US 2010/0065268 (Gates et al), US 2010/0096126 (Sullivan et al.), US 2011 / 0120709 (Nasr et al.), US 2012/0043081 (Kjørholt), US 2012/0247760 (Wheeler et al.), US 2012/0273195 (Wheeler et al.), US 6,257,334 (Cyr et al.), WO 2010 / 084369 (Rochon), and WO 2012/119076 (Sultenfuss et al.). These documents disclose coinjection of an NCG with steam, in order to help mobilize hydrocarbons in the formation, and / or improve solubility of hydrocarbons in a solvent co-injected into the steam and NCG mixture.

However, a problem with the prior art is that the presence of NCGs in the steam may, by absorbing some of the heat of the steam, hinder heat transfer from steam to hydrocarbons, and slow down the steam-oil displacement front.However, a problem with the prior art is that the presence of NCGs in the steam may, by absorbing some of the heat of the steam, hinder heat transfer from steam to hydrocarbons, and slow down the steam-oil displacement front.

SUMMARY OF THE INVENTIONSUMMARY OF THE INVENTION

According to a first aspect of the present invention there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam in a formation to form a steam chamber; and (b) injecting at least one non-condensable gas (NCG) in the formation.According to a first aspect of the present invention, there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam into a formation to form a steam chamber; and (b) injecting at least one non-condensable gas (NCG) into the formation.

The method may further comprise: (c) injecting steam in the formation to maintain heat transfer to hydrocarbons in the formation.The method may further comprise: (c) injecting steam into the formation to maintain heat transfer to hydrocarbons in the formation.

Step (a) may comprise injecting steam in a first region of the formation.Step (a) may comprise injecting steam into a first region of the formation.

Step (b) may comprise injecting at least one non-condensable gas (NCG) in a second region of the formation.Step (b) may comprise injecting at least one non-condensable gas (NCG) into a second region of the formation.

Step (c) may comprise injecting steam in a third region of the formation.Step (c) may comprise injecting steam into a third region of the formation.

The first region, second region, and/or third region may be the same of different.The first region, second region, and / or third region may be the same of different.

In one embodiment, the first region and the second region may be the same.In one embodiment, the first region and the second region may be the same.

In one embodiment, the first region, the second region, and the third region may be the same.In one embodiment, the first region, the second region, and the third region may be the same.

The method may comprise: (a) injecting steam in a region of the formation to form a steam chamber; and (b) injecting at least one non-condensable gas (NCG) in said region of the formation.The method may comprise: (a) injecting steam into a region of the formation to form a steam chamber; and (b) injecting at least one non-condensable gas (NCG) into said region of the formation.

The method may further comprise: (c) injecting steam in said region of the formation to maintain heat transfer to hydrocarbons in the formation.The method may further comprise: (c) injecting steam into said region of the formation to maintain heat transfer to hydrocarbons in the formation.

The method may comprise producing the formation, e.g. by means of a production wellbore. The method may comprise producing said region of the formation.The method may comprise producing the formation, e.g. by means of a production wellbore. The method may comprise producing said region of the formation.

The method may comprise injecting steam and/or at least one non-condensable gas by means of an injection wellbore. The injection well bore may be located above the production wellbore. The injection wellbore and/or the production wellbore may extend substantially horizontally through the formation. The injection wellbore may be substantially parallel to the production wellbore. The injection wellbore may be substantially vertically aligned relative to the production wellbore.The method may comprise injecting steam and / or at least one non-condensable gas by means of an injection wellbore. The injection well bore may be located above the production wellbore. The injection wellbore and / or the production wellbore may extend substantially horizontally through the formation. The injection wellbore may be substantially parallel to the production wellbore. The injection wellbore may be substantially vertically aligned relative to the production wellbore.

The step (a) of injecting steam in the formation to form a steam chamber may be performed until the steam chamber if fully developed. By fully developed it is meant that the steam chamber has grown vertically and horizontally to reach a substantially stable profile, e.g. the size and shape of the steam chamber may be substantially stable overtime under controlled, e.g. constant, injection conditions.The step (a) of injecting steam into the formation to form a steam chamber may be performed until the steam chamber if fully developed. By fully developed it is meant that the steam chamber has grown vertically and horizontally to reach a substantially stable profile, e.g. the size and shape of the steam chamber may be substantially stable overtime under controlled e.g. constant, injection conditions.

The step (a) of injecting steam in the formation may comprise a start-up phase during which steam may be injected into the formation via the injection wellbore and the production wellbore.The step (a) of injecting steam into the formation may comprise a start-up phase during which steam may be injected into the formation via the injection wellbore and the production wellbore.

The step (a) of injecting steam in the formation to form a steam chamber may last for at least one day, e.g. at least one week, e.g. at least one month, typically at least three months.The step (a) of injecting steam into the formation to form a steam chamber may last for at least one day, e.g. at least one week, e.g. at least one month, typically at least three months.

Steam may have a pressure in the range of approximately 100 - 3,000 psia, typically 100 - 1,500 psia.Steam may have a pressure in the range of approximately 100 - 3,000 psia, typically 100 - 1,500 psia.

Steam may have a temperature in the range of approximately 150°C - 350°C, typically 200°C - 300°C. It will be understood that the steam temperature may be dependent on the pressure of the steam and/or pressure in the formation.Steam may have a temperature in the range of approximately 150 ° C - 350 ° C, typically 200 ° C - 300 ° C. It will be understood that the steam temperature may be dependent on the pressure of the steam and / or pressure in the formation.

The method may comprise performing steps (a) and (b) sequentially. The method may comprise interrupting injection of steam (step (a)) before injecting at least one NCG (step (b)) in the formation. The method may comprise injecting at least one NCG without injection of steam.The method may comprise performing steps (a) and (b) sequentially. The method may comprise interrupting injection of steam (step (a)) before injecting at least one NCG (step (b)) into the formation. The method may comprise injecting at least one NCG without injection of steam.

By injecting at least one NCG in the formation, the at least one NCG may rise to an upper portion of the formation and/or reservoir, e.g. to a portion of the formation below the overburden. The at least one NCG may act as a layer providing thermal insulation between the steam chamber and the overburden. This may reduce heat loss from steam to the overburden, thus improving thermal transfer from steam to hydrocarbons in the formation, which may improve efficiency, performance, and/or oil recovery.By injecting at least one NCG into the formation, the at least one NCG may rise to an upper portion of the formation and / or reservoir, e.g. to a portion of the formation below the overburden. The at least one NCG may act as a layer providing thermal insulation between the steam chamber and the overburden. This may reduce heat loss from steam to the overburden, thus improving thermal transfer from steam to hydrocarbons in the formation, which may improve efficiency, performance, and / or oil recovery.

The injection of at least one NCG in the formation may also increase pressure in the formation, which may act to displace and/or mobilise hydrocarbons in the formation. This may further improve efficiency, performance, and/or oil recovery.The injection of at least one NCG in the formation may also increase pressure in the formation, which may act to displace and / or mobilize hydrocarbons in the formation. This may further improve efficiency, performance, and / or oil recovery.

The at least one non-condensable gas may exhibit a density no greater than, preferably lower than, the density of steam, e.g. at reservoir conditions. By such provision, the at least one non-condensable may rise to an upper portion of the formation, e.g. above or near the top of the steam chamber.The at least one non-condensable gas may exhibit a density no greater than, preferably lower than, the density of steam, e.g. to reservoir conditions. By such provision, the at least one non-condensable may rise to an upper portion of the formation, e.g. above or near the top of the steam chamber.

The at least one non-condensable gas may comprise one non-condensable gas, such as nitrogen (N2), carbon dioxide (C02), methane (CH4), or the like. The at least one non-condensable gas may comprise a mixture of non-condensable gases, including two or more non-condensable gases such as nitrogen (N2), carbon dioxide (C02), methane (CH4), or the like.The at least one non-condensable gas may comprise one non-condensable gas, such as nitrogen (N2), carbon dioxide (CO2), methane (CH4), or the like. The at least one non-condensable gas may comprise a mixture of non-condensable gases, including two or more non-condensable gases such as nitrogen (N2), carbon dioxide (CO2), methane (CH4), or the like.

In one embodiment, the at least one non-condensable gas may comprise a mixture of carbon dioxide (C02) and nitrogen (N2). Ratios of N2to C02 may be dictated by pressure and temperature at reservoir conditions. Typically, the maximum amount of C02 in the mixture may be such that the density of the NCG mixture is less than or equal to, typically less than, the density of steam, under reservoir conditions.In one embodiment, the at least one non-condensable gas may comprise a mixture of carbon dioxide (CO 2) and nitrogen (N 2). Ratios of N2to C02 may be dictated by pressure and temperature at reservoir conditions. Typically, the maximum amount of C02 in the mixture may be such that the density of the NCG mixture is less than or equal to, typically less than, the density of steam, under reservoir conditions.

The at least one non-condensable gas, e.g. mixture of non-condensible gases, may be injected at a pressure in the range of range of approximately 100 - 3,000 psia, typically 100 - 1,500 psia.The at least one non-condensable gas, e.g. mixture of non-condensable gases may be injected at a pressure in the range of about 100 - 3,000 psia, typically 100 - 1,500 psia.

The at least one non-condensable gas, e.g. mixture of non-condensible gases, may be injected at a temperature in the range of range of approximately 150°C -350°C, typically 200°C - 300°C.The at least one non-condensable gas, e.g. mixture of non-condensable gases may be injected at a temperature in the range of about 150 ° C to 350 ° C, typically 200 ° C - 300 ° C.

The method may comprise performing steps (a), (b) and (c) sequentially.The method may comprise performing steps (a), (b) and (c) sequentially.

The method may comprise interrupting and/or ending injection of at least one non-condensable gas (step (b)) before injecting steam (step (c)) in the formation.The method may comprise interrupting and / or ending injection of at least one non-condensable gas (step (b)) before injecting steam (step (c)) into the formation.

The method may comprise injecting steam without simultaneous injection of NCGs, e.g. the method may comprise injecting steam only during step (a) and/or step (c). By injecting only steam in the formation, heat loss through heat transfer from steam to NCGs may be minimised and/or avoided, thus optimising heat transfer to the hydrocarbons in the reservoir. The presence of a layer of at least one NCG in an upper portion of the formation, e.g. between the steam chamber and the overburden, may reduce heat loss from steam to the overburden. This may improve thermal transfer from steam to hydrocarbons in the formation and thus improve oil recovery. This may also reduce the amount of steam necessary to reduce viscosity of the hydrocarbons in the reservoir. This may help reduce cost and/or environmental impact, for example by reducing the amount of contaminated water produced.The method may comprise injecting steam without simultaneous injection of NCGs, e.g. the method may comprise injecting steam only during step (a) and / or step (c). By injecting only steam into the formation, heat loss through heat transfer from steam to NCGs may be minimized and / or avoided, thus optimizing heat transfer to the hydrocarbons in the reservoir. The presence of a layer of at least one NCG in an upper portion of the formation, e.g. between the steam chamber and the overburden, may reduce heat loss from steam to the overburden. This may improve thermal transfer from steam to hydrocarbons in the formation and thus improve oil recovery. This may also reduce the amount of steam necessary to reduce the viscosity of the hydrocarbons in the reservoir. This may help reduce costs and / or environmental impact, for example by reducing the amount of contaminated water produced.

The method may comprise injecting at least one non-condensable gas without injection of steam, e.g. during step (b).The method may comprise injecting at least one non-condensable gas without injection of steam, e.g. during step (b).

The method may be devoid of any co-injection of steam and non-condensable gas(es).The method may be devoid of any co-injection of steam and non-condensable gas (es).

The inventors have surprisingly discovered that it may be possible to inject a NCG in the formation without co-injection of steam, without significantly affecting or disrupting the steam chamber. This may help reduce the amount of steam required during the oil recovery process. This may also allow subsequent injection of steam (step (c)) under improved efficiency due to the presence of a layer of NCG below the overburden, above or near the top of the steam chamber.The inventors have surprisingly discovered that it may be possible to inject an NCG into the formation without co-injection of steam, without significantly affecting or disrupting the steam chamber. This may help reduce the amount of steam required during the oil recovery process. This may also allow subsequent injection of steam (step (c)) under improved efficiency due to the presence of a layer of NCG below the overburden, above or near the top of the steam chamber.

Advantageously, step (b) of injecting at least one NCG in the formation may last for a period of time sufficient to create a layer of NCG below the overburden, but without significantly disrupting the steam chamber. Typically, step (b) of injecting at least one non-condensable gas (NCG) in the formation may last approximately 1-6 months, typically approximately 3 months. The step (b) of injecting at least one noncondensable gas (NCG) in the formation may be ended upon detection of an increase in gas content, e.g. gas/oil ratio, in a/the production mixture and/or in the production wellbore.Advantageously, step (b) of injecting at least one NCG into the formation may last for a period of time sufficient to create a layer of NCG below the overburden, but without significantly disrupting the steam chamber. Typically, step (b) of injecting at least one non-condensable gas (NCG) into the formation may last approximately 1-6 months, typically approximately 3 months. The step (b) of injecting at least one non-condensable gas (NCG) into the formation may be ended upon detection of an increase in gas content, e.g. gas / oil ratio, in a / the production mixture and / or in the production wellbore.

Typically, step (c) of injecting steam in the formation may last approximately 1-6 months, typically approximately 3 months.Typically, step (c) of injecting steam into the formation may last approximately 1-6 months, typically approximately 3 months.

The method may further comprise: (d) repeating step (b).The method may further comprise: (d) repeating step (b).

The at least one NCG may maintain or further increase pressure in the reservoir, which may act to further displace and/or mobilise hydrocarbons in the formation. This may further improve efficiency, performance, and/or oil recovery.The at least one NCG may maintain or further increase pressure in the reservoir, which may act to further displace and / or mobilize hydrocarbons in the formation. This may further improve efficiency, performance, and / or oil recovery.

The method may further comprise: (e) repeating step (c).The method may further comprise: (e) repeating step (c).

Typically, the amount of NCG and steam and/or the duration of each of steps (b) and (c), when repeated a number of times, may be such that the ratio of NGC/steam ratio in the reservoir may decrease from an early stage of the method to an advanced or final stage of the method. For example, the amount of NCG and steam and/or the duration of each of steps (b) and (c), when repeated a number of times, may be such that the ratio of NGC/steam ratio in the reservoir may be in the range of about 1:1, for example near an early stage of the method, to about 1:10, for example near an advanced or final stage of the method. As such, the amount of NCG and steam and/or the duration of each of steps (b) and (c), when repeated a number of times, may be analogous to or similar to a "tapered injection strategy" or "tapered WAG" as used in water-alternating-gas injection cycles.Typically, the amount of NCG and steam and / or the duration of each of steps (b) and (c), when repeated a number of times, may be such that the NGC / steam ratio in the reservoir may decrease from an early stage of the method to an advanced or final stage of the method. For example, the amount of NCG and steam and / or the duration of each of steps (b) and (c), when repeated a number of times, may be such that the NGC / steam ratio in the reservoir may be in the range from about 1: 1, for example near an early stage of the method, to about 1:10, for example near an advanced or final stage of the method. As such, the amount of NCG and steam and / or the duration of each of steps (b) and (c), when repeated a number of times, may be analogous to or similar to a "tapered injection strategy" or "tapered WAG" "as used in water-alternating-gas injection cycles.

The method may comprise performing steps (a), (b), (c), (d), and (e) sequentially.The method may comprise performing steps (a), (b), (c), (d), and (e) sequentially.

The method may comprise repeating step (b) and (c), e.g. alternately. Steps (b) and (c) may be repeated as often as desired to recover a predetermined, or an optimum amount of hydrocarbons from the reservoir, and/or until the rate of production has reached a predetermined level, e.g. has fallen below a predetermined production rate. It will be understood that the method may not necessarily end during a step of injecting steam, but may end during a step of injecting at least one non-condensable gas (NCG) in the formation, or during a step of injecting steam in the formation.The method may comprise repeating steps (b) and (c), e.g. Alternately. Steps (b) and (c) may be repeated as often as desired to recover a predetermined, or an optimum amount of hydrocarbons from the reservoir, and / or until the rate of production has reached a predetermined level, e.g. has fallen below a predetermined production rate. It will be understood that the method may not necessarily end during a step of injecting steam, but may end during a step of injecting at least one non-condensable gas (NCG) into the formation, or during a step of injecting steam into the formation. .

The method may comprise providing a liner in/on the injection well bore.The method may comprise providing a liner in / on the injection well bore.

The liner may extend from a heel or first portion of the injection wellbore nearest an entry point thereof, to a toe or second portion of the injection wellbore farthest from an entry point thereof.The liner may extend from an entire or first portion of the injection wellbore nearest an entry point thereof, to a toe or second portion of the injection wellbore farthest from an entry point thereof.

The method may comprise feeding steam and/or at least one non-condensable gas (NCG) from the heel or first portion of the injection wellbore.The method may comprise feeding steam and / or at least one non-condensable gas (NCG) from the very or first portion of the injection wellbore.

The injection wellbore may comprise openings to allow passage of steam and/or NCGs through the wellbore. Typically, the injection wellbore may comprise openings configured to allow substantially unrestricted passage of steam and/or NCGs through the wellbore.The injection wellbore may comprise openings to allow passage of steam and / or NCGs through the wellbore. Typically, the injection wellbore may configure openings to allow substantially unrestricted passage of steam and / or NCGs through the wellbore.

The liner may comprise a non-cemented liner.The liner may comprise a non-cemented liner.

The liner may comprise a plurality of holes formed in a wall of the liner.The liner may comprise a plurality of holes formed in a wall of the liner.

The liner may define an annular space between the liner and the injection wellbore, e.g. between an outer surface of the liner and an inner surface of the injection wellbore.The liner may define an annular space between the liner and the injection wellbore, e.g. between an outer surface of the liner and an inner surface of the injection wellbore.

The method may comprise injecting steam and/or at least one non-condensable gas (NCG) into the annular space through one or more of the plurality of holes in the liner, preferably through a plurality of holes.The method may comprise injecting steam and / or at least one non-condensable gas (NCG) into the annular space through one or more of the plurality of holes in the liner, preferably through a plurality of holes.

The annular space may be provided substantially along an entire length of the injection wellbore and/or liner.The annular space may be provided substantially along an entire length of the injection wellbore and / or liner.

The holes in the liner may be distributed such so that the total hole area per length unit of the liner may be greater at the toe or second portion of the injection wellbore and/or liner than at the heel or first portion of the injection wellbore and/or liner.The holes in the liner may be distributed such that the total hole area per unit length of the liner may be greater at the toe or second portion of the injection wellbore and / or liner than at the very or first portion of the injection wellbore and / or liner.

In use, upon injection of steam and/or at least one NCG in the liner, the steam and/or at least one NCG may enter the annular space through holes near the heel or first portion of the injection wellbore. In use, upon further injection of steam and/or at least one NCG in the liner, the steam and/or at least one NCG may travel inside the liner towards the toe or second portion of the injection well bore and/or liner. Thus, in use, steam and/or at least one NCG may progressively enter the annular space through a plurality of holes in the liner as the steam and/or at least one NCG travels towards the toe or second portion of the injection well bore. This may result in displacing liquid away from the annular space, e.g. away from an upper portion of the annular space.In use, upon injection of steam and / or at least one NCG into the liner, the steam and / or at least one NCG may enter the annular space through holes near the very or first portion of the injection wellbore. In use, upon further injection of steam and / or at least one NCG into the liner, the steam and / or at least one NCG may travel inside the liner towards the toe or second portion of the injection well bore and / or liner. Thus, in use, steam and / or at least one NCG may progressively enter the annular space through a plurality of holes in the liner as the steam and / or at least one NCG travels toward the toe or second portion of the injection well bore. This may result in displacement of liquid away from the annular space, e.g. away from an upper portion of the annular space.

The liner may be substantially closed at one end thereof, e.g. at a toe or second end thereof. The liner may comprise a closure, e.g. an end cap, at a toe or second end thereof. By such provision, steam and/or at least one NCG injected into the liner may exit the liner and/or enter the annular space through one or more of the plurality of holes in the liner.The liner may be substantially closed at one end thereof, e.g. at a toe or second end thereof. The liner may comprise a closure, e.g. an end cap, at a toe or second end thereof. By such provision, steam and / or at least one NCG injected into the liner may exit the liner and / or enter the annular space through one or more of the plurality of holes in the liner.

The liner may comprise at least two holes arranged substantially diametrically opposite one another. Typically, the liner may comprise a plurality of sets of holes provided along a length of the liner. Each set of holes may comprise at least one pair of holes which may typically be arranged substantially diametrically opposite one another. Each set of holes may comprise a plurality of pairs of holes, e.g. arranged substantially circumferentially around the liner. Each pair of holes may typically be arranged substantially diametrically opposite one another.The liner may comprise at least two holes arranged substantially diametrically opposite one another. Typically, the liner may comprise a plurality of sets of holes provided along a length of the liner. Each set of holes may comprise at least one pair of holes which may typically be arranged substantially diametrically opposite one another. Each set of holes may comprise a plurality of pairs of holes, e.g. arranged substantially circumferentially around the liner. Each pair of holes may typically be arranged substantially diametrically opposite one another.

The holes in the liner may distributed such so that the total hole area per length unit of the liner may be greater at the toe or second portion of the injection wellbore than at the heel or first portion of the injection wellbore.The holes in the liner may be distributed such that the total hole area per unit length of the liner may be greater at the toe or second portion of the injection wellbore than at the very or first portion of the injection wellbore.

The distance between successive sets of holes in a longitudinal direction may decrease from a heel or first portion to a toe or second portion of the injection wellbore. Additionally, or alternatively, the size, e.g. diameter, of the holes may increase from a heel or first portion to a toe or second portion of the injection wellbore. This may improve steam and/or NCG distribution along the length of the injection well by ensuring a more evenly distributed flow of steam and/or NCG from the liner into the annular space along a length of the liner. Without wishing to be bound by theory, it is believed that flow of steam and/or NCG through holes at or near a heel or first portion of the injection well bore may decrease the pressure of steam and/or NCG along the length of the liner, thus reducing the flow of steam and/or NCG into the annular space at or near a toe or second portion of the liner. By increasing the hole area distribution towards a toe or second portion of the liner, a more even and/or better distributed flow of steam and/or NCG from the liner into the annular space may be obtained along the length of the liner.The distance between successive sets of holes in a longitudinal direction may decrease from an entire or first portion to a toe or second portion of the injection wellbore. Additionally, or alternatively, the size, e.g. diameter, of the holes may increase from a very or first portion to a toe or second portion of the injection wellbore. This may improve steam and / or NCG distribution along the length of the injection because by ensuring a more evenly distributed flow of steam and / or NCG from the liner into the annular space along a length of the liner. Without wishing to be bound by theory, it is believed that flow of steam and / or NCG through holes at or near a whole or first portion of the injection well bore may decrease the pressure of steam and / or NCG along the length of the liner. , thus reducing the flow of steam and / or NCG into the annular space at or near a toe or second portion of the liner. By increasing the hole area distribution towards a toe or second portion of the liner, a more even and / or better distributed flow of steam and / or NCG from the liner into the annular space may be obtained along the length of the liner.

In an embodiment, the total hole area per length unit of the liner at or near a toe or second portion of the injection well bore may be at least 2 times, preferably at least 3 times, more preferably at least or about 4 times the total hole area per length unit of the liner at or near a heel or first portion of the injection well bore.In one embodiment, the total hole area per unit length of the liner at or near a toe or second portion of the injection well bore may be at least 2 times, preferably at least 3 times, more preferably at least or about 4 times the total. hole area per unit length of the liner at or near a very or first portion of the injection well bore.

In an embodiment, the holes in the liner may have a diameter in the range of about 4 mm to about 8 mm, e.g. about 5 mm to about 7 mm, typically about 6 mm.In one embodiment, the holes in the liner may have a diameter in the range of about 4 mm to about 8 mm, e.g. about 5 mm to about 7 mm, typically about 6 mm.

The distance between consecutive holes in the liner at or near a second portion of the injection well bore may be less than about 12 metres, preferably less than about 9 metres, typically about 7.5 metres. The distance between consecutive holes in the liner at or near a first portion of the injection well bore may be greater than about 24 metres, preferably greater than 27 metres, typically about 30 metres.The distance between consecutive holes in the liner at or near a second portion of the injection well bore may be less than about 12 meters, preferably less than about 9 meters, typically about 7.5 meters. The distance between consecutive holes in the liner at or near a first portion of the injection well bore may be greater than about 24 meters, preferably greater than 27 meters, typically about 30 meters.

In an embodiment, the liner may have a diameter, e.g. an inner diameter, of between about 11 cm to about 18 cm.In one embodiment, the liner may have a diameter, e.g. an inner diameter, between about 11 cm to about 18 cm.

Water used to create steam injected in the method of the present invention may be obtainable as a combustion product from hydrocarbons. In one embodiment, the method may comprise combusting low value hydrocarbons, e.g. low value hydrocarbon by-products, in a reactor, for example in a turbine engine such as a rocket turbine engine. The low value hydrocarbons may be combusted with oxygen, e.g. substantially pure oxygen. In one embodiment, the combustion process may generate electricity, energy, water and/or carbon dioxide, preferably at least water and carbon dioxide. As such, the energy and materials efficiency of the method may be improved, and the method may decrease the dependence on the external supply of water. This may be particularly advantageous in locations where water, e.g. fresh water, has a limited availability.Water used to create steam injected in the method of the present invention may be obtainable as a combustion product from hydrocarbons. In one embodiment, the method may comprise combining low value hydrocarbons, e.g. low value hydrocarbon by-products, in a reactor, for example in a turbine engine such as a rocket turbine engine. The low value hydrocarbons may be combusted with oxygen, e.g. substantially pure oxygen. In one embodiment, the combustion process may generate electricity, energy, water and / or carbon dioxide, preferably at least water and carbon dioxide. As such, the energy and materials efficiency of the method may be improved, and the method may reduce the dependence on the external supply of water. This may be particularly advantageous in locations where water, e.g. fresh water, has a limited availability.

In one embodiment, the energy generated during combustion of low value hydrocarbons may be used to heat water, e.g. water generated during combustion of low value hydrocarbons, into steam.In one embodiment, the energy generated during combustion of low value hydrocarbons may be used to heat water, e.g. water generated during combustion of low value hydrocarbons, into steam.

At least one NCG injected in the method of the present invention may be obtainable as a combustion product from hydrocarbons. In one embodiment, the method may comprise combusting low value hydrocarbons, e.g. low value hydrocarbon by-products, in a reactor, for example in a turbine engine such as a rocket turbine engine. The low value hydrocarbons may be combusted with oxygen, e.g. substantially pure oxygen. In one embodiment, the combustion process may generate electricity, water and carbon dioxide. The carbon dioxide produced by this process may be used as a NCG in the method of the present invention.At least one NCG injected in the method of the present invention may be obtainable as a combustion product from hydrocarbons. In one embodiment, the method may comprise combining low value hydrocarbons, e.g. low value hydrocarbon by-products, in a reactor, for example in a turbine engine such as a rocket turbine engine. The low value hydrocarbons may be combusted with oxygen, e.g. substantially pure oxygen. In one embodiment, the combustion process may generate electricity, water and carbon dioxide. The carbon dioxide produced by this process may be used as an NCG in the method of the present invention.

The method may comprise performing air separation. Air separation may generate nitrogen and/or oxygen, preferably nitrogen and oxygen.The method may comprise performing air separation. Air separation may generate nitrogen and / or oxygen, preferably nitrogen and oxygen.

In one embodiment, the oxygen prepared by air separation may be used in the combustion of low value hydrocarbons, e.g. for the production of water and carbon dioxide.In one embodiment, the oxygen prepared by air separation may be used in the combustion of low value hydrocarbons, e.g. for the production of water and carbon dioxide.

In one embodiment, the nitrogen prepared by air separation may be used as NCG in the method of the present invention.In one embodiment, the nitrogen prepared by air separation may be used as NCG in the method of the present invention.

In one embodiment, the method may comprise: performing air separation to generate nitrogen and oxygen; feeding the oxygen in a combustion reactor, for example in a turbine engine such as a rocket turbine engine, with low value hydrocarbons, to produce water and carbon dioxide; heating water into steam, using energy generated from the combustion reactor; feeding the steam to a subterranean formation, for example according to the method of the present invention; feeding nitrogen produced from air separation, and carbon dioxide produced from the combustion of low value hydrocarbons, as NCGs in a subterranean formation, for example according to the method of the present invention.In one embodiment, the method may comprise: performing air separation to generate nitrogen and oxygen; feeding the oxygen in a combustion reactor, for example in a turbine engine such as a rocket turbine engine, with low value hydrocarbons, to produce water and carbon dioxide; heating water into steam, using energy generated from the combustion reactor; feeding the steam to a subterranean formation, for example according to the method of the present invention; feeding nitrogen produced from air separation, and carbon dioxide produced from the combustion of low value hydrocarbons, as NCGs in a subterranean formation, for example according to the method of the present invention.

Such a method may decrease the dependence on external sources of materials required for the present method, and may thus improve the self-sustainability of the method, while also reducing the impact on the environment.Such a method may reduce the dependence on external sources of materials required for the present method, and thus improve the self-sustainability of the method, while also reducing the impact on the environment.

According to a second aspect of the present invention there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam in a region of the formation to form a steam chamber; (b) injecting at least one non-condensable gas in said region of the formation; (c) injecting steam in said region of the formation to maintain heat transfer to hydrocarbons in the formation; (d) optionally repeating step (b); and (e) optionally repeating step (c).According to a second aspect of the present invention, there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam into a region of the formation to form a steam chamber; (b) injecting at least one non-condensable gas into said region of the formation; (c) injecting steam into said region of the formation to maintain heat transfer to hydrocarbons in the formation; (d) optionally repeating step (b); and (e) optionally repeating step (c).

The method may comprise repeating step (b) and (c), e.g. alternately. Steps (b) and (c) may be repeated as often as desired to recover a predetermined, or an optimum amount of hydrocarbons from the reservoir and/or formation, and/or until the rate of production has reached a predetermined level, e.g. has fallen below a predetermined production rate.The method may comprise repeating steps (b) and (c), e.g. Alternately. Steps (b) and (c) may be repeated as often as desired to recover a predetermined, or an optimum amount of hydrocarbons from the reservoir and / or formation, and / or until the rate of production has reached a predetermined level, e.g. has fallen below a predetermined production rate.

The features described herein in relation to any other aspect of the invention, can apply in respect of the method according to a second aspect of the present invention, and are therefore not repeated here for brevity.The features described herein in relation to any other aspect of the invention may apply in respect of the method according to a second aspect of the present invention, and are therefore not repeated here for brevity.

According to a third aspect of the present invention there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam in a region of the formation to form a steam chamber; and subsequently (b) alternately injecting at least one non-condensable gas, and steam, in said region of the formation.According to a third aspect of the present invention, there is provided a method for recovering hydrocarbons from a formation, comprising: (a) injecting steam into a region of the formation to form a steam chamber; and (b) alternatively injecting at least one non-condensable gas, and steam, into said region of the formation.

The features described above in relation to any other aspect of the invention, can apply in respect of the method according to a third aspect of the present invention, and are therefore not repeated here for brevity.The features described above in relation to any other aspect of the invention may apply in respect of the method according to a third aspect of the present invention, and are therefore not repeated here for brevity.

BRIEF DESCRIPTION OF THE DRAWINGSLETTER DESCRIPTION OF THE DRAWINGS

These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:These and other aspects of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 is a schematic side view of a conventional SAGD recovery system;Figure 1 is a schematic side view of a conventional SAGD recovery system;

Figure 2 is a schematic end view of the system of Figure 1;Figure 2 is a schematic end view of the system of Figure 1;

Figure 3A is a schematic representation of a first step of an enhanced oil recovery method according to an embodiment of the present invention;Figure 3A is a schematic representation of a first step of an enhanced oil recovery method according to an embodiment of the present invention;

Figure 3B is a schematic representation of a second step of an enhanced oil recovery method according to an embodiment of the present invention;Figure 3B is a schematic representation of a second step of an enhanced oil recovery method according to an embodiment of the present invention;

Figure 3C is a schematic representation of a third step of an enhanced oil recovery method according to an embodiment of the present invention;Figure 3C is a schematic representation of a third step of an enhanced oil recovery method according to an embodiment of the present invention;

Figure 4 is a schematic representation of an enhanced oil recovery method according to an embodiment of the present invention;Figure 4 is a schematic representation of an enhanced oil recovery method according to an embodiment of the present invention;

Figure 5 is a schematic side view of an injection wellbore including a liner according to an embodiment of the present invention;Figure 5 is a schematic side view of an injection wellbore including a liner according to an embodiment of the present invention;

Figure 6 is a schematic representation of an enhanced oil recovery system according to an embodiment of the present invention.Figure 6 is a schematic representation of an enhanced oil recovery system according to an embodiment of the present invention.

DETAILED DESCRIPTION OF THE DRAWINGSDETAILED DESCRIPTION OF THE DRAWINGS

Figures 1 is a schematic side view of a conventional SAGD recovery system, generally designated 10.Figures 1 is a schematic side view of a conventional SAGD recovery system, generally designated 10.

The system 10 comprises an injection wellbore 20 which extends substantially horizontally in an oil reservoir 12. The system 10 comprises a production wellbore 30 which extends substantially horizontally in the oil reservoir 12. The injection wellbore 20 is substantially parallel to, and substantially vertically aligned with, the production wellbore 30. The injection wellbore 20 is typically located approximately 4 to 6 metres above the production wellbore 30.The system 10 comprises an injection wellbore 20 which extends substantially horizontally in an oil reservoir 12. The system 10 comprises a production wellbore 30 which extends substantially horizontally in the oil reservoir 12. The injection wellbore 20 is substantially parallel to, and substantially vertically aligned with , the production wellbore 30. The injection wellbore 20 is typically located approximately 4 to 6 meters above the production wellbore 30.

The injection wellbore 20 and production wellbore 30 are located near a lower section of the oil reservoir 12, above an interface 13 between the oil reservoir 12 and an underlying structure, in this embodiment an aquifer 14. As shown in Figures 3A to 3C, the oil reservoir 12 is located below an overlying overburden 16.The injection wellbore 20 and production wellbore 30 are located near a lower section of the oil reservoir 12, above an interface 13 between the oil reservoir 12 and an underlying structure, in this embodiment an aquifer 14. As shown in Figures 3A to 3C, the oil reservoir 12 is located below an overlying overburden 16.

As shown in Figure 2, in a typically SAGD system, steam 22 is injected into the reservoir 12 via the injection wellbore 20. Steam 22 travels upwards, expanding vertically and laterally in the reservoir 12 until a steam chamber 18 is formed. As steam exchanges heat with the heavy hydrocarbons of the reservoir 12, the viscosity of heavy hydrocarbons is reduced sufficiently to allow the hydrocarbons to drain into the production wellbore 30 and be pumped to the surface, along with any water condensed in the steam chamber 18.As shown in Figure 2, in a typically SAGD system, steam 22 is injected into reservoir 12 via injection wellbore 20. Steam 22 travels upwards, expanding vertically and laterally in reservoir 12 until a steam chamber 18 is formed. As steam exchanges heat with the heavy hydrocarbons of reservoir 12, the viscosity of heavy hydrocarbons is reduced sufficiently to allow the hydrocarbons to drain into production wellbore 30 and be pumped to the surface, along with any water condensed into the steam chamber 18.

Figures 3Ato 3C show schematic representations of an enhanced oil recovery method 100 according to an embodiment of the present invention. A schematic flowchart of the method 100 is also shown in Figure 4. The method 100 as shown in Figures 3A to 3C and 4 comprises a system generally similar to the system of Figures 1 and 2, like parts being denoted by like numerals, incremented by "100".Figures 3Ato 3C show schematic representations of an enhanced oil recovery method 100 according to an embodiment of the present invention. A schematic flowchart of the method 100 is also shown in Figure 4. The method 100 shown in Figures 3A to 3C and 4 comprises a system generally similar to the system of Figures 1 and 2, like parts being denoted by similar numerals, incremented by "100".

In a first step 101 of the method 100, as shown in Figure 3A, steam 122 is injected into a region 113 of the oil reservoir 112 via injection wellbore 120 to form a steam chamber 118. In this embodiment, steam 122 only is injected during the first step 101, that is, without simultaneous injection of additional injectants such as NCGs.In a first step 101 of method 100, as shown in Figure 3A, steam 122 is injected into a region 113 of the oil reservoir 112 via injection wellbore 120 to form a steam chamber 118. In this embodiment, steam 122 is only injected during the first step 101, that is, without simultaneous injection of additional injectors such as NCGs.

In a second step 102 of the method 100, as shown in Figure 3B, once the steam chamber 118 is established, injection of steam 122 via the injection wellbore 120 is stopped. At least one non-condensable gas (NCG) 124 is injected into said region 113 of the reservoir 112 via the injection wellbore 120. In this embodiment, an NCG mixture 124 of nitrogen and carbon dioxide is injected in the reservoir 112. The NCG mixture 124 being less dense than steam 122, the NCG mixture 124 rises to an upper portion of the reservoir 112 below the overburden 116, forming a layer 125 providing thermal insulation between the steam chamber 118 and the overburden 116. This helps reduce heat loss from steam 122 to the overburden 116, thus improving thermal transfer from steam 122 to hydrocarbons in the reservoir 112, which may improve efficiency, performance, and/or oil recovery. The injection of NCG mixture 124 also increases pressure in the reservoir 112, which acts to displace and/or mobilise hydrocarbons in the reservoir 112. This may further improve efficiency, performance, and/or oil recovery.In a second step 102 of the method 100, as shown in Figure 3B, once the steam chamber 118 is established, injection of steam 122 via the injection wellbore 120 is stopped. At least one non-condensable gas (NCG) 124 is injected into said region 113 of the reservoir 112 via the injection wellbore 120. In this embodiment, an NCG mixture 124 of nitrogen and carbon dioxide is injected into the reservoir 112. The NCG mixture 124 being less dense than steam 122, the NCG mixture 124 rises to an upper portion of the reservoir 112 below the overburden 116, forming a layer 125 providing thermal insulation between the steam chamber 118 and the overburden 116. This helps reduce heat loss from steam 122 to the overburden 116, thus improving thermal transfer from steam 122 to hydrocarbons in reservoir 112, which may improve efficiency, performance, and / or oil recovery. The injection of NCG mixture 124 also increases pressure in reservoir 112, which acts to displace and / or mobilize hydrocarbons in reservoir 112. This may further improve efficiency, performance, and / or oil recovery.

In a third step 103 of the method 100, as shown in Figure 3C, once a desired amount of NCG mixture 124 has been injected, injection of NCG mixture 124 is stopped. Steam 122 is then injected into said region 113 of the reservoir 112 via the injection wellbore 120, to maintain heat transfer from steam 122 to hydrocarbons in the reservoir. In this step 103, steam 122 is injected without co-injection of NCGs. In this embodiment, only steam 122 is injected during step 103.In a third step 103 of method 100, as shown in Figure 3C, once a desired amount of NCG mixture 124 has been injected, injection of NCG mixture 124 is stopped. Steam 122 is then injected into said region 113 of reservoir 112 via injection wellbore 120, to maintain heat transfer from steam 122 to hydrocarbons in the reservoir. In this step 103, steam 122 is injected without co-injection of NCGs. In this embodiment, only steam 122 is injected during step 103.

The presence of a layer 125 of NCGs between the steam chamber 118 and the overburden 116, helps reduce heat loss from steam 122 to the overburden 116 during injection of steam 122. This may improve thermal transfer from steam 122 to hydrocarbons in the reservoir 112 and also reduce the amount of steam 122 necessary to reduce viscosity of the hydrocarbons in the reservoir 112.The presence of a layer 125 of NCGs between the steam chamber 118 and the overburden 116 helps reduce heat loss from steam 122 to the overburden 116 during injection of steam 122. This may improve thermal transfer from steam 122 to hydrocarbons in the reservoir 112 and also reduce the amount of steam 122 necessary to reduce viscosity of the hydrocarbons in the reservoir 112.

As shown in Figure 4, the method 100 may comprise repeating step 102, as shown by the dotted arrows. The method may further comprise repeating step 103. The second step 102 and the third step 103 may be repeated alternately as often as desired to recover a desired amount of hydrocarbons from the reservoir 112, and/or until the rate of production has fallen below a predetermined production rate. The second step 102 and third step 103 may be repeated a number of times which may be based on a number of parameters, such as the viscosity of the hydrocarbons, the size of the reservoir, the porosity of the formation and/or overburden, the internal pressure in the reservoir, the depth of the reservoir, the type of NCG injected in the reservoir, availability of injectants, overall project economics, and the like.As shown in Figure 4, the method 100 may comprise repeating step 102, as shown by the dotted arrows. The method may further comprise repeating step 103. The second step 102 and the third step 103 may be repeated alternately as often as desired to recover a desired amount of hydrocarbons from the reservoir 112, and / or until the rate of production has fallen below predetermined production rate. The second step 102 and third step 103 may be repeated a number of times which may be based on a number of parameters such as the viscosity of the hydrocarbons, the size of the reservoir, the porosity of the formation and / or overburden, the internal pressure in the reservoir, the depth of the reservoir, the type of NCG injected into the reservoir, availability of injectors, overall project economics, and the like.

Although Figure 4 depicts a method 100 which, in this embodiment, ends with step 103, it will be understood that, provided steps 102 and 103 have been performed at least once, the method 100 may equally end with step 102.Although Figure 4 depicts a method 100 which, in this embodiment, ends with step 103, it will be understood that, provided steps 102 and 103 have been performed at least once, method 100 may equally end with step 102.

Figure 5 is a schematic side view of an injection wellbore 220 including a liner 240 according to an embodiment of the present invention. The injection wellbore 220 of Figure 5 is generally similar to the injection wellbore 20 of the system of Figures 1 and 2, like parts being denoted by like numerals, incremented by "200".Figure 5 is a schematic side view of an injection wellbore 220 including a liner 240 according to an embodiment of the present invention. The injection wellbore 220 of Figure 5 is generally similar to the injection wellbore 20 of the system of Figures 1 and 2, like parts being denoted by like numerals, incremented by "200".

The injection wellbore 220 comprises openings 226 to allow substantially unrestricted passage of steam and/or NCGs through the injection wellbore 220.The injection wellbore 220 comprises openings 226 to allow substantially unrestricted passage of steam and / or NCGs through the injection wellbore 220.

The liner 240 extends from a heel or first portion 227 of the injection wellbore 220 nearest an entry point thereof, to a toe or second portion 228 of the injection wellbore farthest from an entry point thereof. In this embodiment, the liner 240 is a non-cemented liner 240.The liner 240 extends from a very or first portion 227 of the injection wellbore 220 nearest an entry point thereof, to a toe or second portion 228 of the injection wellbore farthest from an entry point thereof. In this embodiment, the liner 240 is a non-cemented liner 240.

The liner 240 is provided on an inner side of the injection wellbore 220, and defines an annular space 241 between the liner 240 and the injection wellbore 220.The liner 240 is provided on an inner side of the injection wellbore 220, and defines an annular space 241 between the liner 240 and the injection wellbore 220.

The liner 240 comprises a plurality of holes 242,243 formed in a wall of the liner 240.The liner 240 comprises a plurality of holes 242,243 formed in a wall of the liner 240.

The liner 240 comprises a plurality of sets of holes 242,243. For ease of representation, the liner of Figure 5 has been depicted with four sets of holes. However, it will be understood that in a downhole environment the liner may comprise many sets of holes, typically 10 to 300 sets of holes, e.g. 50 to 200 sets of holes.The liner 240 comprises a plurality of sets of holes 242,243. For ease of representation, the liner of Figure 5 has been depicted with four sets of holes. However, it will be understood that in a downhole environment the liner may comprise many sets of holes, typically 10 to 300 sets of holes, e.g. 50 to 200 sets of holes.

Each set of holes comprises one or more pair of holes 242,243 which are typically arranged substantially diametrically opposite one another. The cross-sectional view of Figure 5 depicts one pair of holes 242,243 for each set of holes for ease of representation. Each pair of holes comprises an upper hole 242 facing substantially upwards, and a lower hole 243 facing substantially downwards. The upper holes 242 serve to divert the steam and/or NCGs upwards into the annular space 241. The lower holes 243 serve to enable condensed water and initial well bore fluids to escape from the liner 240 into the reservoir 212.Each set of holes comprises one or more pairs of holes 242,243 which are typically arranged substantially diametrically opposite one another. The cross-sectional view of Figure 5 depicts one pair of holes 242,243 for each set of holes for ease of representation. Each pair of holes comprises an upper hole 242 facing substantially upwards, and a lower hole 243 facing substantial downwards. The upper holes 242 serve to divert the steam and / or NCGs upwards into the annular space 241. The lower holes 243 serve to enable condensed water and initial well bore fluids to escape from the liner 240 into the reservoir 212.

The liner 240 is substantially closed at a toe or second end 228 thereof. The liner may comprise a closure 245, e.g. an end cap, at a toe or second end thereof. By such provision, steam and/or NCGs injected into the liner 240 exit the liner 240 and/or enter the annular space 241 through one or more of the holes 242 in the liner 240.The liner 240 is substantially closed at a close or second end of 228. The liner may comprise a closure 245, e.g. an end cap, at a toe or second end thereof. By such provision, steam and / or NCGs injected into liner 240 exit liner 240 and / or enter annular space 241 through one or more of holes 242 in liner 240.

The holes 242,243 are distributed such so that the total hole area per length unit of the liner 240 is greater at the toe or second portion 228 of the injection wellbore and/or liner than at the heel or first portion 227 of the injection wellbore 220. By increasing the hole area distribution towards a toe or second portion 228 of the liner 240, a more even and/or better distributed flow of steam and/or NCG from the liner 240 into the annular space 241 may be obtained along the length of the liner 240.The holes 242,243 are distributed such that the total hole area per unit length of the liner 240 is greater at the toe or second portion 228 of the injection wellbore and / or liner than at the very or first portion 227 of the injection wellbore 220. By increasing the hole area distribution towards a toe or second portion 228 of the liner 240, a more even and / or better distributed flow of steam and / or NCG from the liner 240 into the annular space 241 may be obtained along the length of the liner 240.

In this embodiment, the distance between successive sets of holes in a longitudinal direction decreases from a heel or first portion 227 to a toe or second portion 228 of the injection wellbore 220.In this embodiment, the distance between successive sets of holes in a longitudinal direction decreases from a very or first portion 227 to a toe or second portion 228 of the injection wellbore 220.

In alternative embodiment, the distance between successive sets of holes in a longitudinal direction may remain constant, but the size, e.g. diameter of the holes 242,243 may increases from a heel or first portion 227 to a toe or second portion 228 of the injection wellbore 220.In an alternative embodiment, the distance between successive sets of holes in a longitudinal direction may remain constant, but the size, e.g. diameter of the holes 242,243 may increase from a very or first portion 227 to a toe or second portion 228 of the injection wellbore 220.

Figure 6 is a schematic representation of an enhanced oil recovery system 300 according to an embodiment of the present invention.Figure 6 is a schematic representation of an enhanced oil recovery system 300 according to an embodiment of the present invention.

The system 300 comprises an air separator unit 350 which separates air 352 into nitrogen 354 and oxygen 356.The system 300 comprises an air separator unit 350 which separates air 352 into nitrogen 354 and oxygen 356.

The oxygen 356 is used in a combustion reactor 360 combust hydrocarbons 362, yielding energy 364, water 366 and carbon dioxide 368 as main reaction products.The oxygen 356 is used in a combustion reactor 360 combustion hydrocarbons 362, yielding energy 364, water 366 and carbon dioxide 368 as main reaction products.

Water 366 from the combustion reactor 360 is fed to a steam generator 370. The steam generator 370 may use water from an external water source in addition, or instead of, water 366 obtained from the combustion reactor 360.Water 366 from the combustion reactor 360 is fed to a steam generator 370. The steam generator 370 may use water from an external water source in addition, or instead, water 366 obtained from the combustion reactor 360.

The steam generator 370 may use heat 364 from the combustion reactor 360 to generate steam 324. The steam 324 is supplied to a steam injector 380 that injects steam 324 through an injection channel 382 into the oil reservoir 312, for example during step 101 or 103 of the process 100 of Figure 4. The steam injector 380 brings the steam 324 to desired and/or predetermined conditions such as temperature and pressure. Optionally, the steam injector may be capable of co-injecting a NCG such as nitrogen 354 and/or carbon dioxide 368. A NCG injector 390 injects nitrogen 354 generated by the air separation unit 350, and/or carbon dioxide 368 generated by the combustion reactor 360, through an injection channel 392 into the oil reservoir 312, for example during step 102 of the process 100 of Figure 4. In this embodiment the NCG injection channel 392 is shown separately from the steam injection channel 382. Flowever, in another embodiment, the NCG injection channel 392 and the steam injection channel 382 may form a single injection channel to the reservoir 312.The steam generator 370 may use heat 364 from the combustion reactor 360 to generate steam 324. The steam 324 is supplied to a steam injector 380 which injects steam 324 through an injection channel 382 into the oil reservoir 312, for example during step 101 or 103. of the process 100 of Figure 4. The steam injector 380 brings the steam 324 to desired and / or predetermined conditions such as temperature and pressure. Optionally, the steam injector may be capable of co-injecting an NCG such as nitrogen 354 and / or carbon dioxide 368. An NCG injector 390 injects nitrogen 354 generated by the air separation unit 350, and / or carbon dioxide 368 generated by the combustion reactor 360, through an injection channel 392 into the oil reservoir 312, for example during step 102 of process 100 of Figure 4. In this embodiment, the NCG injection channel 392 is shown separately from the steam injection channel 382. Flowever, in another embodiment , the NCG injection channel 392 and the steam injection channel 382 may form a single injection channel to the reservoir 312.

The hydrocarbons 362 recovered from the reservoir 312 may be produced and/or collected through a collector channel 395, into a collector unit 396. The collector unit 396 may feed part of the hydrocarbons 362 to the combustion reactor 360, for example low value hydrocarbons 362, whereas another fraction 398 of the hydrocarbons, e.g. a higher value fraction, is transported through line 399 for storage and/or processing.The hydrocarbons 362 recovered from the reservoir 312 may be produced and / or collected through a collector channel 395, into a collector unit 396. The collector unit 396 may feed part of the hydrocarbons 362 to the combustion reactor 360, for example low value hydrocarbons 362 , whereas another fraction 398 of the hydrocarbons, e.g. a higher value fraction, is transported through line 399 for storage and / or processing.

Various modifications may be made to the embodiment described without departing from the scope of the invention.Various modifications may be made to the embodiment described without departing from the scope of the invention.

Claims

1. A method for recovering hydrocarbons from a formation, comprising: (a) injecting steam in a region of the formation to form a steam chamber; (b) injecting at least one non-condensable gas (NCG) in said region of the formation; and (c) injecting steam in said region of the formation.

2. A method according to claim 1, wherein steps (a), (b) and (c) are performed sequentially.

3. A method according to any preceding claim, wherein injection of steam and/or at least one non-condensable gas is performed by means of an injection wellbore.

4. A method according to any preceding claim, comprising producing the formation by means of a production wellbore.

5. A method according to claim 3 or claim 4, wherein the injection wellbore and/or the production wellbore extends substantially horizontally through the formation.

6. A method according to claim 4 or claim 5, wherein the injection wellbore is located above the production wellbore and is substantially vertically aligned relative to the production wellbore.

7. A method according to any preceding claim, wherein step (a) of injecting steam in a region of the formation to form a steam chamber is performed until the steam chamber if fully developed.

8. A method according to any preceding claim, wherein, during step (a), steam is injected into said region of the formation via the injection wellbore and the production wellbore.

9. A method according to any preceding claim, wherein step (b) comprises injecting at least one NCG without injection of steam.

10. A method according to any preceding claim, wherein the density of the at least one non-condensable gas is less than or equal to the density of steam.

11. A method according to any preceding claim, wherein the at least one noncondensable gas comprises one or more gases selected from the list consisting of nitrogen (N2), carbon dioxide (C02), and methane (CH4).

12. A method according to claim 11, wherein the at least one non-condensable gas comprises a mixture of carbon dioxide (C02) and nitrogen (N2).

13. A method according to any preceding claim, comprising alternately repeating step (b) and step (c).

14. A method according to any of claims 3 to 13, comprising providing a non-cemented liner in the injection wellbore.

15. A method according to claim 14, wherein the liner extends from a heel or first portion of the injection wellbore nearest an entry point thereof, to a toe or second portion of the injection wellbore farthest from an entry point thereof.

16. A method according to any of claims 14 to 15, wherein the injection wellbore comprises openings configured to allow substantially unrestricted passage of steam and/or NCGs through the wellbore.

17. A method according to any of claims 14 to 16, wherein the liner defines an annular space between an outer surface of the liner and an inner surface of the injection wellbore.

18. A method according to any of claims 14 to 17, wherein the liner comprises a plurality of holes formed in a wall thereof, wherein the holes in the liner are distributed such so that the total hole area per length unit of the liner is greater at the toe or second portion of the injection wellbore and/or liner than at the heel or first portion of the injection wellbore and/or liner.

19. A method according to any of claims 14 to 18, wherein the liner comprises a plurality of sets of holes provided along a length of the liner, each set of holes comprising at least one pair of holes arranged substantially diametrically opposite one another.

20. A method according to any preceding claim, wherein water used to create the injected steam is obtainable by combustion of hydrocarbons in a turbine engine.

21. A method according to claim 20, wherein the combustion generates water and carbon dioxide.

22. A method according to claim 21, wherein the carbon dioxide generated during combustion of hydrocarbons is used as one of the at least one non-condensable gas.

23. A method according to any of claims 20 to 22, wherein combustion further generates electricity and/or energy.

24. A method according to claim 23, wherein the energy generated during combustion of hydrocarbons is used to heat water into steam.

25. A method according to any of claims 20 to 24, further comprising performing air separation to generate nitrogen and oxygen.

26. A method according to claim 25, wherein the oxygen prepared by air separation is used in the combustion of hydrocarbons.

27. A method according to claim 25 or claim 26, wherein the nitrogen prepared by air separation is used as one of the at least one non-condensable gas.

28. A method for recovering hydrocarbons from a formation, comprising: (a) injecting steam in a region of the formation to form a steam chamber; and subsequently (b) alternately injecting at least one non-condensable gas, and steam, in said region of the formation.