CA3088279A1

CA3088279A1 - Method and system for recovery of hydrocarbons from a subterranean formation

Info

Publication number: CA3088279A1
Application number: CA3088279A
Authority: CA
Inventors: Gregory Martin Parry PERKINS
Original assignee: Martin Parry Technology Pty Ltd
Current assignee: Martin Parry Technology Pty Ltd
Priority date: 2018-01-15
Filing date: 2019-01-15
Publication date: 2019-07-18
Also published as: WO2019136533A1

Abstract

A method and system is disclosed for recovering hydrocarbons from a reservoir of a subterranean formation comprising a single horizontal well bore. The system comprises a completion assembly adapted to both inject from an injection point at a first injection location; and withdraw from a withdrawal point at a first withdrawal location. The completion assembly comprises a plurality of injection points to permit changing of the location of injection of mobilising fluid to one or more subsequent further location(s) remote from the first injection location; and a plurality of withdrawal points to permit changing of the location of withdrawal of produced fluid to one or more subsequent further location(s) remote from the first withdrawal location.

Description

METHOD AND SYSTEM FOR RECOVERY OF HYDROCARBONS FROM A
SUBTERRANEAN FORMATION
This patent document claims priority from Canadian Patent Application No.

2,991,871 Filed January 15, 2018 entitled: METHOD AND SYSTEM FOR
ENHANCED OIL RECOVERY USING MOVEABLE COMPLETIONS and Canadian Patent Application No. 2,991,889 Filed January 15, 2018 entitled: A FURTHER
METHOD AND SYSTEM FOR ENHANCED OIL RECOVERY USING MOVEABLE
COMPLETIONS, the entire contents of both of which documents are hereby incorporated by reference in their entirety.
TECHNICAL FIELD
[0001] This invention relates to recovery of hydrocarbons from a subterranean formation. The subterranean formation can including, for example, natural gas, light oil, medium oil, heavy oil, oil sands, bitumen, oil shale, shale oil and coal, mobilised via the injection of mobilising fluids. In particular, the invention relates to methods and systems for mobilising and recovering carbonaceous materials using completions which are moveable within the subterranean formation so as to be able to inject and produce hydrocarbon fluids to/from different regions of the reservoir at different times.
BACKGROUND OF THE INVENTION
[0002] Enhanced oil recovery (EOR) generally refers to methods involving the injection of mobilising fluids into a reservoir to enhance the production of hydrocarbons from the reservoir. Hydrocarbons may be present in the reservoir in the form of fluids such as oil and gas or solids such as coal and kerogen.

[0003] For light and medium oils, EOR methods generally refer to secondary or tertiary methods of recovery, which are commenced after a period of primary production. For heavy oils, oil sands and bitumen, EOR methods generally refer to thermal methods of recovery which are commenced as a primary or sometimes secondary means of producing hydrocarbons from the reservoir.

[0004] Enhanced oil recovery can refer to many types of recovery processes, including immiscible, miscible and thermal methods.

[0005] A common method for EOR involves using patterns of vertical wells and injecting a mobilising fluid into a portion of the wells (injectors) and recovering petroleum from the remaining wells (producers). Various patterns of the vertical injector and producer wells, including 5-spot, 7-spot and 9-spot, and their inverted equivalents, have been attempted.

[0006] Another common method for EOR involves using patterns of horizontal wells and a mobilising fluid into a portion of the wells (injectors) and recovering petroleum from the remaining wells (producers). Various patterns of horizontal injector and producer wells have been attempted

[0007] Various configurations which involve combinations of vertical and horizontal wells have also been disclosed.

[0008] The use of patterns of vertical wells is common for immiscible and miscible displacement of the hydrocarbons in the reservoir.

[0009] A common method of immiscible recovery is the water flood. Water floods are generally implemented using patterns of vertical wells and injecting water into a portion of the wells (injectors) and recovering petroleum from the remaining wells (producers). Water floods works best when the reservoir is relatively thick and the reservoir is on a dip, so that gravity can be used as a drive mechanism to enhance the mobilisation of the petroleum to the producer wells.

[0010] Various additives may be mixed with the water during water flood operations to improve its properties; for example, by adding polymers to increase the viscosity of the water so that the mobility ratio between the petroleum and water/polymer mixture is more favourable.

[0011] Other fluids which are used for immiscible displacement or pressure maintenance include nitrogen, methane and light hydrocarbon gases.

[0012] A common method for miscible recovery is the CO2 flood. When the pressure is sufficient and the oil properties suitable, then the injected CO2 and the oil in the reservoir become miscible, allowing more oil to be contacted. Like water floods, CO2 floods are often implemented using patterns of vertical wells, with some of the wells used as injectors and the remaining wells used as producers

[0013] Other fluids such as light hydrocarbons may also be used for miscible recovery depending upon the oil quality and the temperature and pressure of the target reservoir.

[0014] Thermal processes are generally utilised for the purpose of recovering viscous petroleum from heavy oil, oil sands, and bitumen reservoirs. The viscosities of these petroleum resources are too high to be produced without heating.
Generally heating may be undertaken by injecting hot water, steam, by performing in situ combustion by injecting an oxidant or by downhole heating using electrical heaters and other methods. Hot water injection has low efficacy and is generally not preferred. Control of the combustion front formed during in situ combustion has historically been difficult and therefore in situ combustion is currently only applied in a limited number of reservoirs to produce commercial quantities of hydrocarbons.
Electrical heating is relatively expensive and is also slow to mobilise reservoir fluids as it relies primarily on heat conduction. Thus, steam injection is generally the preferred thermal method of recovering viscous petroleum resources.

[0015] The most common methods of steam injection include the steam flood and steam assisted gravity drainage (SAGD).

[0016] Steam floods generally involve drilling a pattern of vertical wells and injecting steam into a portion of the wells (injectors) and recovering petroleum from the remaining wells (producers). Various patterns of the injector and producer wells, including 5-spot, 7-spot and 9-spot, and their inverted equivalents have been attempted. Steam flooding works best when the reservoir is relatively thick and the reservoir is on a dip, so that gravity can aid the drive mechanism to enhance the mobilisation of the petroleum to the producer wells.

[0017] The SAGD process involves positioning an injection well above a production well and injecting steam into the upper well to form a steam chamber which heats and mobilises the oil which flow to the production well below.
SAGD is the preferred method for recovering oil sands and some heavy oil reservoirs. SAGD works best in relatively thick (>15 m thick) and homogeneous reservoirs at depths less than about 800 m. SAGD is not effective in thin reservoirs due to the requirement to place the steam injector well above the petroleum producer well. SAGD is also not effective when the reservoir is fractured or highly heterogeneous, which will accelerate bypassing of the injected steam to the producer, reducing petroleum recovery and increasing the steam oil ratio (SOR) to uneconomic values. SAGD is also not practiced in deep reservoirs, due to i) heat losses during steam injection and ii) the higher steam temperatures required at higher pressures. SAGD has been applied with considerable success in recovering Athabasca bitumen in Canada.

[0018] SAGD has had limited operational success to date in heterogeneous reservoirs, such as the carbonate reservoirs in Canada.

[0019] A common issue with existing EOR methods is to ensure that the mobilising fluids contact the maximum amount of the reservoir and that breakthrough of the mobilising fluids to the producer wells is delayed for as long as possible. For once the mobilising fluids reach the producer wells, the recovery rate of hydrocarbons from the reservoir diminishes rapidly.

[0020] Solutions which are commonly applied to delay the breakthrough of the mobilising fluids are: i) inject alternating fluids and/or additives to improve the mobility ratio between the injected fluid and the reservoir hydrocarbons, ii) install injection and inflow control devices to manage the pressure distribution along the injector and/or producer wells and iii) change the configuration and spacing of the injector and producer wells.

[0021] In many cases hydrocarbon reservoirs with heterogeneous properties are avoided altogether since the existing methods are ineffective and uneconomic.

[0022] In many cases, primary production is undertaken using a single well drilled into the formation. The well may be vertical or it may be horizontal.
Common examples include wells designed for cold production in heavy oil deposits and in offshore reservoirs.

[0023] The common methods of EOR, mentioned above, which may involve adding injectors to inject mobilising fluids into the reservoir, may not be practical or may be too expensive to be economic.

[0024] An invention which would enable the use of a single well bore with EOR
methods and be suitable for use in thin, homogeneous, heterogeneous and/or fractured reservoirs would be an important improvement over the prior art. An invention which would enable the recovery of more hydrocarbons from an existing well bore, would be especially attractive.

[0025] Methods using a single wellbore to recover hydrocarbons from a reservoir include cyclic "huff and puff" approaches which can be used with immiscible, miscible and thermal recovery methods. Typically, the procedure is to inject a mobilising fluid into the formation from a wellbore, to allow the mobilising fluid to soak into the reservoir and then after a period of time soaking, produce a mixture of mobilising fluid and hydrocarbon fluids to surface. The approach has been used most frequently for the miscible recovery using CO2 and for thermal recovery using steam (generally known as cyclic steam stimulation, CSS).

[0026] Cyclic methods by their nature exacerbate heterogeneity in the near well bore region of the reservoir. The initial slugs of mobilising fluids find their way preferentially into the high permeability areas of the reservoir and drain the hydrocarbons, introducing further heterogeneity in the form of fluid saturation and permeability changes.

[0027] When considering miscible processes, pattern floods using CO2 and Water Alternating Gas (WAG) are generally preferred to single well bore cyclic processes using vertical or horizontal wells. The main reason is that cyclic injection of miscible fluids has a low recovery factor.

[0028] Thermal recovery of viscous petroleum deposits can be undertaken with CSS using vertical and horizontal wells. CSS works in relatively thin formations.
However, a major disadvantage of CSS is that it only recovers between 5 and 15%
of the Original Oil In Place (00IP). Thus, a large quantity of hydrocarbons are left behind in the reservoir. In addition, CSS is less effective in heterogeneous formations, as the injected steam will preferentially flow into the fractures, thereby bypassing a large portion of the reservoir and leading to even lower recovery factors.

[0029] A variety of methods have been described using a single well-bore to recover petroleum from subterranean reservoirs.

[0030] US Patent 5,771,973 to Jensen et al. describes a method of injecting a mobilising fluid through a tubing string at a raised end of a horizontal wellbore, and producing a mixture of mobilising fluid and hydrocarbons from the heel of the well bore through a second tubing string.

[0031] US Patent 5,131,471 to Duerksen et al. describes a method of injecting a mobilising fluid through a vertical wellbore via a tubing string and perforation into the formation and recovering mobilised fluids via a second tubing string located below a packer.

[0032] US Patent 5,215,149 to Lu describes a method of constructing a horizontal well, perforating the well at the toe and at the heel and installing a tubing string and packer on the heel side of the perforations near the toe of well.
Steam is injected into the annulus and enters the formation via the perforations at the heel of the well. Mobilised hydrocarbons are then recovered via the perforations at the toe of the well and produced to surface via the tubing string.

[0033] US Patent 4,116275 to Moore et al. describes a method of producing viscous formations by circulating steam within a wellbore and then injecting steam in a cyclic manner into the formation to mobilise and produce hydrocarbons.

[0034] US Patent 5,626,193 to Nzekwu et al. describes a method of producing viscous formations from a single horizontal wellbore via a steam flooding gravity drainage process. The process works by injecting steam and hot water condensate into the formation at the toe of the wellbore and establishing a steam chamber. The steam chamber is them propagated towards the heel of the wellbore by pressure gradients. Steam is injected into the toe of the well via a tubing string and retrieved at the heel via a thermal packer and pump arrangement.

[0035] US Patent 5,148,869 to Sanchez discloses a single well bore process for the in-situ extraction of viscous oil by gravity action using steam plus a solvent. A
horizontal well is drilled into the formation and a steam/solvent mixture is injected into the reservoir from the top of the wellbore via a conduit from surface.
Oil is recovered from the bottom of the wellbore into a second conduit and transported to surface. The process operates via heat conduction, heat convection and gravity drainage.

[0036] US Patent 5,167,280 to Sanchez et al. discloses a single well bore process for stimulating a reservoir using a solvent. Solvent permeates from the wellbore into the reservoir, reducing the viscosity of the oil in the vicinity of the well bore.

[0037] US Patent 9,328,595 B2 to Kjoorholt discloses a single well bore process for steam assisted gravity drainage. In this process, two conduits each with a plurality of permeable sections are placed within the well bore, one conduit for steam injection and one conduit for production of reservoir fluids. The invention discloses that the injection sections are staggered longitudinally with respect to the production sections within the single well bore. This configuration promotes the formation of steam chambers which mobilise the hydrocarbons in the reservoir between the various injection and production sections.

[0038] An invention which would enable the use of a pattern of well bores with EOR methods and be suitable for use in thin, homogeneous, heterogeneous and/or fractured reservoirs would be an important improvement over the prior art. An invention which would enable the recovery of more hydrocarbons from an existing pattern of well bores, would be especially attractive.

[0039] A variety of methods have been described using a pattern of well-bores to recover petroleum from subterranean reservoirs.

[0040] US Patent 4,850,429 to Mins et al. discloses use of a triangular pattern of horizontal well-bores wherein a recovery fluid is injected such as steam is injected in some of the wells in the pattern and hydrocarbons ae recovered from the remaining wells in the pattern.

[0041] US Patent 4,598,770 to Shu et al. discloses the use of a pattern of horizontal and vertical wells with steam injection for the recovery of heavy oil.

[0042] US Patent 5,201,815 to Hong et al. discloses an inverted nine-spot well pattern for use with steam enhanced oil recovery wherein the well completion in the sidewells is restricted to the lower 20% of the reservoir.

[0043] US Patent 5,915,477 to Stuebinger et al. discloses use of a pattern of injection and production well-bores for enhanced oil recovery wherein there is at least two production strata.

[0044] All of the aforementioned prior art use static completions; i.e.
completions which are fixed in time and space. None of the prior art mention the advantages of using movable completions to be able to inject and produce hydrocarbon fluids to/from different regions of the reservoir at different times.

[0045] Any discussion of prior art information in this specification is not to be taken as any form of acknowledgement that that prior art information would be considered common general knowledge by a person of skill in the art, either in Australia or in any foreign country.
SUMMARY
According to a first aspect there is provided a method to recover hydrocarbons from a reservoir of a subterranean formation comprising a single horizontal well bore, the method comprising the steps of:

a) injecting a mobilising fluid into the reservoir at a first location to create a first mobilised zone, the first mobilised zone including a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons;
b) withdrawing the mixture of mobilised fluids that flow out of the reservoir of the hydrocarbon bearing subterranean formation as a produced fluid; and c) changing the location of injection of mobilising fluid and repeating steps a) and b) one or more times so as to inject mobilising fluid into the reservoir at one or more subsequent further location(s) remote from the first location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone;
wherein the mobilising fluid is injected via a completion assembly arranged in the horizontal well bore, and the produced fluid is removed via the same completion assembly arranged in the horizontal well bore.

[0046] The mobilising fluid is injected via a completion assembly and the produced fluid is removed via the same completion assembly arranged in the horizontal reservoir. This means that the method can be applied to a single well. By "single well" it is meant that the well is disposed at a distance from any other well such that injected mobilising fluid and produced fluid enters the same completion assembly, and the fluids do not interact with any other well in terms of the produced fluid entering that other well. A single well arrangement may have the following advantages:
i. the mobilising fluid injection location(s) can be precisely controlled ii. the flux of the mobilising fluid can be precisely controlled iii. The completion assembly may be installed in existing or "old" wells to enable additional hydrocarbons to be recovered from the formation

[0047] The above advantages can in some embodiments lead to increased hydrocarbon recovery and enable maximum utilization of the mobilising fluids to be achieved. In other cases, the advantage of embodiments of the present invention is the ability to recover hydrocarbons from a reservoir using a single well bore, which in the prior art would have required at least two individual well bores to achieve the same recovery.

[0048] The method can comprise the continuous injection of mobilising fluid as the produced fluid is withdrawn.

[0049] Following the step of changing the location of injection of mobilising fluid, the subsequent further location of injection can overlap with the immediately preceding location of injection.

[0050] The completion assembly can comprise a completion tubing and a horizontal well liner comprising a plurality of perforations spaced along substantially a length of the well liner. The completion tubing can be installed within the well liner.
The tubing can be adapted to inject the mobilising fluid into the reservoir.
The tubing can be adapted to move in the reservoir.

[0051] The completion assembly can comprise a completion tubing, a horizontal well liner and one or more completion devices, whereby each completion device has apertures that can be opened and closed, thereby enabling the injected fluids to be injected at one location along the horizontal well bore at one time, and at another location at another time. Similarly, the produced fluids can be produced from one location at one time and another location at another time.

[0052] Alternatively, the completion assembly, can be as described in relation to the system described herein.

[0053] In embodiments, the present invention relates to methods of recovering hydrocarbon containing fluids by utilising a completion assembly that specifically enables the injection of mobilising fluids and the production of reservoir fluids to/from different regions of the reservoir at different times

[0054] In order to prevent, or at least reduce, the propensity for the mobilising fluids to bypass the reservoir and return to surface, one or more sealing devices can be installed to form a seal between the completion assembly and the well liner. The one or more seals can assist in preventing or at least substantially reducing a direct connection from forming between the location of injection, and the location through which the production fluid enters the completion assembly. Part of the function of sealing devices is to separate the injection and production locations in space; with this in mind, sealing them from each other but having them close together is in some embodiments ineffective. A distance between the location of injection and location of production fluid intake can be calculated to be one where there is no (or at least a reduced) tendency for a substantial amount (80, 90 or 95 or 100 /0) of the injected mobilised fluid to simply return to the completion assembly as a part of the production fluid.

[0055] Depending on the nature of the reservoir and the mobilising fluids, it may be desirable to avoid certain regions of the reservoir altogether. For example, regions with very low permeability, very high levels of fractures or regions which are highly heterogeneous.

[0056] In other cases, it may be desirable to "quickly" sweep the injection of mobilising fluids through particular regions of the reservoir, by moving parts of the completion assembly. For example, when fractures are present in the reservoir, excessive bypassing of the mobilising fluids from the injection side to the production side may occur, reducing the ratio of hydrocarbons to mobilising fluids in the produced fluids; thereby increasing the costs of production. The reservoir fluids can be referred to as produced fluid.

[0057] In other cases, it may be desirable to inject the mobilising fluids in one region at one time, and then another region at another time and alternate the injection between these regions over time in a cyclic manner.

[0058] According to a second aspect there is provided a system for recovering hydrocarbons from a reservoir of a subterranean formation comprising a single horizontal well bore, the system comprising:

a completion assembly disposed in the single horizontal well bore and adapted to both:
i. inject from an injection point at a first injection location a mobilising fluid into the reservoir to create a first mobilised zone, the first mobilised zone including a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons; and ii. withdraw from a withdrawal point at a first withdrawal location the mixture of mobilised fluids that flow out of the reservoir of the hydrocarbon bearing subterranean formation as a produced fluid;
wherein the completion assembly comprises a plurality of injection points to permit changing of the location of injection of mobilising fluid to one or more subsequent further location(s) remote from the first injection location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone; and wherein the completion assembly comprises a plurality of withdrawal points to permit changing of the location of withdrawal of produced fluid to one or more subsequent further location(s) remote from the first withdrawal location.

[0059] Unless the context makes clear otherwise, the description and elaboration of the method above also applies to the description of the system. For example, the completion assembly can comprise a completion tubing, a horizontal well liner and one or more completion devices, whereby each completion device has apertures that can be opened and closed, thereby enabling the injected fluids to be injected at one location along the horizontal well bore at one time, and at another location at another time. Similarly, the produced fluids can be produced from one location at one time and another location at another time.

[0060] The completion assembly can comprise two conduits, an inner conduit and an outer conduit, each of the two conduits can be in fluid communication with the reservoir, and the two conduits are arranged one inside the other concentrically.

[0061] Alternatively, the two conduits are arranged one inside the other eccentrically so that at least a part of the wall of the inner conduit abuts the wall of the outer conduit.

[0062] The completion assembly can comprise a plurality of completion devices, each completion device comprising a plurality of apertures that can be opened to provide the fluid communication between one or both of the conduits and the reservoir; and the apertures can be closed so as to close off the fluid communication between one or both of the conduits and the reservoir.

[0063] Each completion device (or at least some of the completion devices provided) can provided with a sliding sleeve slidable to open or close apertures in the inner and or outer conduits.

[0064] In different positions the sliding sleeve can provide:
a. the apertures of the inner conduit are closed and the apertures of the outer conduit are closed; or b. the apertures of the inner conduit are open and the apertures of the outer conduit are open; or c. the apertures of the inner conduit are open and the apertures of the outer conduit are closed; or d. the apertures of the inner conduit are closed and the apertures of the outer conduit are open.

[0065] In an embodiment, the injection of a mobilising fluid from an injection point into the reservoir comprises injection via open apertures of a first completion device;
and changing the location of injection of mobilising fluid comprises injecting via open apertures of a second completion device, wherein the sliding sleeve of the second completion device is moved to open the apertures for injection. In some embodiments, the sliding sleeve of the first completion device can be is moved to close the apertures for injection.

[0066] In an embodiment, the the withdrawal of produced fluid comprises withdrawal via open apertures of a first completion device; and the system further includes changing the location of withdrawal of produced fluid, wherein changing the location of withdrawal of produced fluid comprises withdrawal via open apertures of a second completion device, wherein the sliding sleeve of the second completion device is moved to open the apertures for withdrawal. In some embodiments, the sliding sleeve of the first completion device can be moved to close the apertures for withdrawal.

[0067] In an embodiment, a first completion device injects mobilising fluid into the reservoir at a first injection location; a second completion device withdraws produced fluid at a first withdrawal location; the first completion device ceases injecting mobilised fluid, and is changed to withdraw produced fluid at a second withdrawal location; the second completion devices ceases withdrawing produced fluid, and is changed to inject mobilising fluid at a second injection location.

[0068] An advantage of using a moveable completion assembly to inject mobilising fluids into the reservoir from the well is that greater precision can be possible in the injection of the mobilising fluid. In particular, by using the completion assembly in the methods and systems as described herein, the injection of the mobilising fluid(s) can be focused over only a portion of the well bore and hence the flux of mobilising fluids into the reservoir may be controlled to ensure optimum use of the mobilising fluids. Typically, in enhanced oil recovery operations, achieving a high ratio of hydrocarbons to the mobilising fluids is desirable. In many enhanced oil recovery methods controlling the flux of the injected mobilising fluids is critical to achieving the conditions required to mobilise the maximum amount of hydrocarbons from the reservoir.

[0069] It will be appreciated by those skilled in the art, that by moving the location of the injection zone along the horizontal well bore, operators can attempt to achieve:
i) an efficient use of the mobilising fluids, ii) sustained production of hydrocarbon fluids and iii) high hydrocarbon recovery factor. Each of these parameters directly relates to the economic performance of an enhanced oil recovery operation.

[0070] The mobilising fluids can be injected into the hydrocarbon bearing reservoir through at least one opening in the tubing of the completion assembly. If the tubing is arranged in a well liner, the mobilising fluid can then pass through an open area such as perforations in the liner. In the reservoir, a zone of mobilised hydrocarbons is therefore created, which will comprise naturally occurring hydrocarbons and the mobilising fluids; and or the products of any physical and chemical interactions which occur between them. The zone of mobilised hydrocarbons is a zone located in the vicinity of the completion assembly from which mobilising fluids and produced fluids are injected to and extracted from the reservoir, respectively.

[0071] The resulting mixture of fluids from the mobilised zone can be referred to as the produced fluids. The produced fluids from the zone of mobilised hydrocarbons may flow via gravity, pressure and or other means back through the liner and may enter the completion tubing. From there the produced fluids may travel to the heel of the well and be produced to surface via a pump and production tubing. The completion tubing can be a concentric tubing comprising an inner tube and an outer tube. The tubing can comprise at least one opening in the form of a first series of apertures. The first series or set of apertures can be in fluid communication with the inner tube. The tubing can comprise a further series of apertures spaced along the length of the tubing. The further series of apertures can be in fluid communication with the outer tube. The first series of apertures can be towards the tip of the tubing.
The further series of apertures can be remote from the tip.

[0072] In an embodiment, the apertures are arranged on a completion device.

There can be more than one completion device installed onto the completion tubing.
The advantage of the completion device is that is can integrate all of the required functions in one device and may be readily installed onto and uninstalled from the completion tubing from the rig equipment at surface. By having a standard completion device, multiple may be easily installed onto the completion tubing as it is positioned into the wellbore. The completion device may also incorporate common features of existing oil and gas completions such as monitoring instrumentation, expansion devices to manage thermal or pressure driven expansion, inflow/outflow devices to control the rate of injection/production of fluids to/from the reservoir, and sealing devices and safety devices such as quick-disconnect mechanisms.

[0073] The apertures can be any desired pattern of open area; for example slots, holes or even just an open end of the tubing. The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of first series of first apertures in the completion tubing, each set spaced apart from one another.
The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of further series of apertures in the completion tubing, each set spaced apart from another.

[0074] In an embodiment, the distance between the first series of apertures and the second series of apertures is of the order of the thickness of the formation +/- 5 or 10 %. For example, if the well is arranged within a formation which is 25 m thick, the spacing can be about 25 m.

[0075] In an embodiment, the distance between the first series of apertures and the second series of apertures is chosen to maximise hydrocarbon recovery by minimising the opportunity for the mobilizing fluids to by-pass the reservoir.

[0076] The apertures in the completion tubing can deliver the mobilising fluid into the horizontal well and then into the reservoir. If the tubing is a concentric tubing, there can be more than one mobilising fluid. The first series of apertures can deliver a first mobilising fluid, and the further series of apertures can deliver a second mobilising fluid.

[0077] Alternatively, the further series of apertures delivers a mobilising fluid and the first series of apertures receives withdrawn produced fluid. The mixture of mobilised produced fluid can flow under gravity and/or pressure through the perforations in the well liner and through the first series of apertures into the tubing.

[0078] Further alternatively, the first series of apertures delivers a mobilising fluid and the further series of apertures receives withdrawn produced fluid. The mixture of produced mobilised fluid can flow under gravity and/or pressure through the perforations in the well liner and through the further series of apertures into the tubing.

[0079] When the hydrocarbons in the zone of mobilised hydrocarbons have been produced using the completion assembly, the location of the completion tubing may be moved longitudinally along the horizontal well bore, to enable the mobilisation of hydrocarbons from a new portion of the reservoir.

[0080] The step of changing the location of the injection of mobilising fluid in the well can comprise moving the tubing. The step of moving of the tubing can comprise retracting the tubing. The step of moving of the tubing can comprise advancing the tubing. The step of retracting the tubing can be undertaken by removal of tubing sections. The step of retracting the tubing can be by winding up the tubing.
The step of advancing the tubing can be undertaken by addition of tubing sections. The step of advancing the tubing can be by winding out the tubing from a coil.

[0081] When the hydrocarbons in the zone of mobilised hydrocarbons have been produced using the completion assembly, the location of the injection point in the completion tubing may be moved longitudinally along the horizontal well bore, to enable the mobilisation of hydrocarbons from a new portion of the reservoir.

[0082] The step of changing the location of the injection of mobilising fluid in the well can comprise changing the injection point from the tubing. Old or previous injection points can be closed. New or subsequent injection points can be opened.

[0083] In an embodiment, the new location of the completion assembly, may overlap with its old position, thereby creating an overlap between the old and new location of the zone of mobilised hydrocarbons.

[0084] Generally, it is preferable, especially in thermal EOR processes, to ensure that the zone of mobilised hydrocarbons formed by operation at successive positions of the completion assembly overlap. This may ensure that there is a zone of sufficient permeability to inject the mobilising fluids. It may also help to ensure a high recovery factor for the hydrocarbons, as all of the reservoir is contacted successively with mobilising fluids.

[0085] In an embodiment the completion device can comprise of two conduits, with pathways for the flow of fluids between each of the conduits and the outside of the device. In an embodiment, the conduits can be arranged one inside the other, forming an inner conduit (annulus) and an outer conduit (annulus). In an embodiment the conduits in the completion device may be arranged concentrically or eccentrically.

[0086] In an embodiment one conduit may be used for the injected fluid and one conduit may be used for the produced fluid. In an embodiment, the two conduits may be used for the injected fluid or the two conduits may be used for the produced fluid.

[0087] In an embodiment the completion device incorporates one or more sliding sleeves that may be moved to open and close pathways within the device and the apertures on the outside of the device for the flow of the injected fluids and for the flow of the produced fluids.

[0088] In an embodiment the completion device incorporates a sliding sleeve that can be configured with one or more of the following positions:
i) enabling flow from the inner conduit to/from the outside of the device ii) enabling flow from the outer conduit to/from the outside of the device iii) disabling flow from the inner and outer conduit to/from the outside of the device iv) enabling flow from the inner conduit to/from the outer conduit inside the device

[0089] In an embodiment, the sliding sleeve(s) may be operated using any conventional means, including coiled tubing or wireline tools to latch on to the sleeve and move its position, the use of drop balls, the use of hydraulic actuators and any other method known in the art.

[0090] In an embodiment the completion assembly can comprise of a number of completion devices connected directly together. In an embodiment the completion devices can be connected together using standard tubings.

[0091] In an embodiment, the completion devices may be installed in a well bore with a well liner. In an embodiment, the completion devices may be installed in a well bore without a well liner.

[0092] In an embodiment, the step of changing the location of the injection of mobilising fluid in the well can comprise of moving a sliding sleeve in a completion device to open apertures, thereby enabling mobilizing fluid to enter the reservoir at a new location along the well bore.

[0093] In an embodiment, the step of changing the location of the injection of mobilising fluid in the well can comprise of moving a sliding sleeve in a completion device to close apertures, thereby disabling mobilizing fluid to enter the reservoir at an old location along the well bore.

[0094] In an embodiment, the step of changing the location of the production fluids in the well can comprise of moving a sliding sleeve in a completion device to open apertures, thereby enabling produced fluids to enter a conduit in the completion device from the reservoir at a new location along the well bore.

[0095] In an embodiment, the step of changing the location of the produced fluids in the well can comprise of moving a sliding sleeve in a completion device to close apertures, thereby disabling produced fluids to enter a conduit in the completion device from the reservoir at an old location along the well bore.

[0096] The mobilising fluid can be selected from one or more of steam, oxidants (oxygen containing fluids), solvents, carbon dioxide, light hydrocarbons such as methane, ethane, propane and butane, water, nitrogen and any other fluids usually used for the same purpose. Where there is a first mobilising fluid and a second mobilising fluid, the two fluids can be the same or different from one another.

[0097] An advantage of using a primary and secondary mobilising fluid is that the presence of the secondary mobilising fluid can reduce the direct contact of the primary mobilising fluid with the produced fluids in the well bore by creating a fluid blanket; thereby reducing unwanted interactions such as mixing and reaction.

[0098] Another advantage of using a primary and secondary mobilising fluid is that the temperature of the completion assembly, completion device, sealing device, liner and well bore can be better controlled. For example, when the primary mobilising fluid is an oxidant, the injection of water or steam as the secondary mobilising fluid can be used to manage the temperatures inside the well bore.
By ensuring temperatures remain within an acceptable range, the mechanical integrity of the liner, completion device and sealing device may be assured and the sealing performance of the sealing devices can be maximised. In this example, if too high temperatures are measured in the completion device then the ratio of secondary to primary mobilising fluids can be increased; while if too low temperatures are measured in the completion device then the ratio of secondary to primary mobilising fluids can be decreased.

[0099] In an embodiment, the method can be employed for the recovery of hydrocarbons from subterranean formations, including light, medium and heavy oils, tight oil, tight gas, oil shale, shale oil, oil sands and bitumen reservoirs using a moveable completion in a single well.

[0100] In an embodiment the hydrocarbon bearing subterranean formation comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is steam. In this situation the zone of mobilised hydrocarbons would be generated via the creation of a steam chamber and the condensing of steam to water to heat up and mobilise hydrocarbons in the reservoir. In the case of steam injection, the mobilised hydrocarbon zone would likely be at a temperature in the range of from about 150 to about 300 C.

[0101] In an embodiment the hydrocarbon bearing subterranean formation comprises light oil, medium oil, heavy oil, oil sands and/or bitumen and the mobilising fluid is an oxidant. The oxidant may comprise a mixture of one or more of air, oxygen, water, carbon dioxide and steam. In this situation the zone of mobilised hydrocarbons would be generated in part via the combustion of a portion of the hydrocarbons with oxygen. The mobilised hydrocarbon zone would be at various temperatures up to about 900 C. During in situ combustion a narrow high temperature combustion zone up to about 900 C is created, along with a thermal cracking zone where temperatures in the range of from about 300 to about 600 C
and a steam zone at temperatures below about 300 C.

[0102] In an embodiment the hydrocarbon bearing subterranean formation comprises coal, oil shales and/or kerogen and the mobilising fluid is an oxidant. In this situation the zone of mobilised hydrocarbons would be generated in part via the combustion and gasification of a portion of the hydrocarbons with oxygen, steam and carbon dioxide. The mobilised hydrocarbon zone would be at various temperatures up to about 1500 C and the mobilised hydrocarbons would consist of a significant quantity of synthesis gases, such as carbon monoxide and hydrogen, along with condensable hydrocarbons of varying chain lengths.

[0103] In an embodiment, steam may be generated in the completion assembly when the mobilising fluid contains a portion of liquid water at surface and sufficient heat is transferred from the produced fluids during operation to the mobilising fluid to turn the liquid water to steam. This counter-current heat transfer mechanism between the mobilising and produced fluids is of significant advantage in some applications.

[0104] For example, when an oxidant and liquid water is injected at surface, it may become a mixture of oxidant and steam when it reaches the completion device and is injected into the reservoir. Steam is an effective mobilising fluid in thermal enhanced oil recovery applications.

[0105] In addition, the evaporation of water into steam can absorb a large amount of energy at a constant temperature, due to the latent heat of evaporation.
The evaporation temperature of water in the reservoir will vary between about and 300 C, depending upon the pressure. Therefore, the co-injection of water with other mobilising fluids, such as an oxidant, together with counter-current heat transfer of the produced fluids can be used to control the temperature of the completion assembly inside the well bore during operations.

[0106] In embodiments, when an oxidant is used as a mobilising fluid, any excessively high temperature of the produced fluids is beneficially used to evaporate water co-injected with the mobilising fluid into steam such that the completion assembly is controlled to the evaporation temperature of water +/-10% at the prevailing pressure in the completion assembly, by varying the:
i) ratio of water to oxygen in the mobilising fluid.
ii) rate of injection of the mobilising fluid.

[0107] Thus, in some applications involving combustion, the single well bore configuration and completion assembly can have the advantage of being able to generate steam for injection into the reservoir as a mobilising fluid, while simultaneously controlling the temperature of the well bore and completion assembly to a temperature close to the evaporation temperature of water in the reservoir at the operating pressure.

[0108] In an embodiment the hydrocarbon bearing subterranean formation comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is a heated solvent. In this situation the zone of mobilised hydrocarbons would be generated via heating and mixing of the hydrocarbons with the injected solvent. Solvents considered to be suitable for mobilising heavy oil formations include light hydrocarbons such as ethane, propane and butane.

[0109] In an embodiment the hydrocarbon bearing subterranean formation comprises heavy oil, oil sands and/or bitumen and the mobilising fluid is a mixture of steam and/or oxidant and/or a heated solvent. In this situation the zone of mobilised hydrocarbons would be generated via heating and mixing of the hydrocarbons with the injected mobilising fluid.

[0110] In an embodiment the hydrocarbon bearing subterranean formation consists of light oil, medium oil, heavy oil or bitumen and the mobilising fluid is a fluid miscible with the hydrocarbons at the temperature and pressure conditions present in the reservoir. Fluids generally considered suitable for miscible injection into hydrocarbon formations include carbon dioxide and light hydrocarbons such as methane, ethane, propane and butane. In this situation the zone of mobilised hydrocarbons would be generated via miscible mixing of the hydrocarbons with the mobilising fluid.

[0111] In an embodiment the hydrocarbon bearing subterranean formation comprises light oil, medium oil, heavy oil or bitumen and the mobilising fluid is a fluid immiscible with the hydrocarbons at the temperature and pressure conditions present in the reservoir. Fluids generally considered suitable for immiscible injection into hydrocarbon formations include water and mixtures of water with various additives, such as polymers. Gases at low pressure may also be used for immiscible injection. In this situation the zone of mobilised hydrocarbons would be generated via immiscible displacement of the hydrocarbons with the mobilising fluid.

[0112] In an embodiment the hydrocarbon bearing subterranean formation comprises light oil, medium oil, heavy oil or bitumen and the mobilising fluid 8 is a fluid for use in microbial enhanced oil recovery (MEOR). Fluids generally considered suitable for MEOR include various combinations of oxygen, water, microbes and nutrients that enhance microbial activity in the reservoir. In this situation the zone of mobilised hydrocarbons would be generated via microbial activity that is enhanced by the mobilising fluid.

[0113] In an embodiment the mobilising fluid may be injected continuously.
In an embodiment the mobilising fluid may be injected discontinuously, for example as per cyclic processes (such as "huff and puff") and/or as per sequential processes (such as water-alternating-gas (WAG) injection).

[0114] In an embodiment the produced fluids may be produced continuously.
In an embodiment the produced fluids may be produced discontinuously, for example as per cyclic processes (such as "huff and puff") and/or as per sequential processes (such as water-alternating-gas (WAG) injection).

[0115] In an embodiment, an upgrading device is provided in the path of the produced fluid so as to upgrade the produced fluid as it is withdrawn through the completion assembly. The upgrading device can be a physical device, a material, a mixture of materials and/or a sequence of materials which improves the quality of the produced hydrocarbon fluids from the reservoir.

[0116] In an embodiment, the quality of the produced fluids is monitored.
Monitoring of the quality of the produced fluids can provide an indicator of how to move the location of the injected mobilising fluids through the reservoir. A
low ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which the injection zone is moved should be increased. A high ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which injection zone is moved should be decreased.

[0117] Therefore, in some embodiments the method can further comprise the steps of:
i) monitoring the produced fluid from each of the mobilised zones to determine the ratio of used mobilising fluid and mobilised hydrocarbons in the produced fluid;
ii) selecting or otherwise adjusting the frequency of the change in the location of injection of mobilising fluid and or the distance between the first location and the one or more further locations depending on the monitored ratio.

[0118] When a low ratio of hydrocarbons to mobilising fluids is reached the frequency and/or distance which the injection zone is moved should be increased.
When a high ratio of hydrocarbons to mobilising fluids is reached the frequency and/or distance which the injection zone is moved should be decreased. The ratio will depend on the type of mobilising fluid used; each fluid will have different properties. Also, the ratio will depend on the properties of the reservoir.

[0119] Mobilising fluids may include fluid and/or solid additives and catalysts. In an embodiment, the first and or second mobilising fluid comprises nanoparticles and or nanofluids. The nanoparticles can comprise iron, nickel, copper, vanadium, or other metals which have been shown to have a catalytic effect on upgrading crude oils. For example, Rezai etal., 2013 (Fuel 2013, v113, pp516-521) show that nanoparticles are effective in reducing the activation energy of combustion reactions.

[0120] Another advantage of using two mobilising fluids is that one of the mobilising fluids may be used to inject a catalyst material, in the form of a fluid and/or solid, into the reservoir that can catalyse the reaction between the other mobilising fluid and the naturally occurring hydrocarbons. For example, catalysts may be mixed with the secondary mobilising fluid or may be mixed with the primary mobilising fluid.

[0121] A major challenge of injecting catalysts into a reservoir using prior art is that due to natural reservoir heterogeneity there is little control over where the catalysts will end up in the reservoir and whether they will be exposed to the right conditions (temperature, pressure, fluid compositions) that will enable them to be effective in upgrading the properties of the hydrocarbons. These facts combined with the relatively expensive nature of most catalysts, mean that catalysts are rarely used in situ to improve the properties of hydrocarbons before they are produced to surface.

[0122] An advantage may be that in some embodiments it addresses all of the disadvantages of using catalyst in situ in the prior art. Firstly, by moving the injection point for the mobilising fluids through the reservoir there is much greater control over the rate and flux of the injected mobilising fluids in the first place.
Secondly, by injecting catalysts with the secondary mobilising fluid, a zone of mobilised hydrocarbons and the catalyst can be created in the reservoir; which is subsequently contacted with the primary mobilising fluid as the completion device is moved through the reservoir, thereby creating the optimal conditions for the catalyst to improve the properties of the hydrocarbons in the reservoir.

[0123] Throughout this specification, a "horizontal well or well bore" is understood to refer to a well bore which is largely aligned with the horizontal plane but which may have one or more sections which deviate by up to +/- 45 degrees and may have a vertical section which may also deviate by up to +/- 45 degrees.

[0124] Another feature of the oil formations that are the target of some methods of the present disclosure is that the reservoirs are heterogeneous; that is, that zones with different properties exist in the reservoirs. For example, zones of high or low permeability; zones which are highly fractured or not highly fractured; zones of high or low oil saturation; zones of high or low porosity; zones of high or low water saturation; and so forth. In an embodiment, the hydrocarbon bearing subterranean formation may be naturally fractured. In an embodiment the hydrocarbon bearing subterranean formation has been fractured via earlier fracturing operations.
In an embodiment, the hydrocarbon bearing subterranean formation is unfractured.

[0125] In an embodiment the produced fluids may be produced to surface via a conduit in the injection tubing. For example, the injection tubing may consist of concentric tubing enabling both the injection of mobilising fluids and the production of produced fluids.

[0126] In an embodiment the produced fluids may be produced to surface via artificial lift, i.e. due to pumping to surface or due to the injection of low density fluids (i.e. gases) into the well to lift them to surface. The artificial lift fluids may be injected via dedicated tubing placed in the well or may be formed via the injection and reaction of the mobilising fluids with the in situ hydrocarbons (for example during in situ combustion, the reaction of injected air with the hydrocarbons forms light gases).

[0127] In embodiments, the present invention relates to systems and methods of recovering hydrocarbon containing fluids by injecting mobilising fluid via an apparatus which is moved through the horizontal well bore, in time and space;
and specifically enables the injection of mobilising fluids and the production of reservoir fluids to/from different regions of the reservoir at different times.

[0128] According to a third aspect there is provided a method to recover hydrocarbons from a subterranean formation, wherein the formation is intersected by at least one well-pair comprising a first generally horizontal well and a second generally horizontal well situated near the first well, the method comprising the steps of:
injecting a mobilising fluid into the first horizontal well at a first location to create a first mobilised zone, the first mobilised zone including a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons;
withdrawing via the second horizontal well the mixture of mobilised fluids that flow out of the hydrocarbon bearing subterranean formation as a produced fluid;
and changing the location of injection of mobilising fluid and repeating steps a) and b) one or more times so as to inject mobilising fluid into the well at one or more subsequent further location(s) remote from the first location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone.

[0129] The description in relation to the single well aspects above can apply to the well pair aspect, and visa versa, unless the context makes clear otherwise.

[0130] The completion assembly in the first and or second wells may comprise of any of the aforementioned completion assemblies disclosed as part of the first and second aspects, and visa versa. Specifically, any of the completion assemblies described in Figures 1 to 16 may be used in the single well and or the well pair.

[0131] The means of injecting the mobilising fluid can be a completion assembly in the first well. The means of withdrawing the produced fluid can be a completion assembly in the second well.
First well

[0132] An advantage of using a moveable completion assembly to inject mobilising fluids into the reservoir from the well is that greater precision can be possible in the injection of the mobilising fluid. In particular, by using the completion assembly in the methods as described herein, the injection of the mobilising fluid(s) can be focused over only a portion of the well bore and hence the flux of mobilising fluids into the reservoir may be controlled to ensure optimum use of the mobilising fluids. Typically, in enhanced oil recovery operations, achieving a high ratio of hydrocarbons to the mobilising fluids is desirable. In many enhanced oil recovery methods controlling the flux of the injected mobilising fluids is critical to achieving the conditions required to mobilise the maximum amount of hydrocarbons from the reservoir.

[0133] By focusing the injection of mobilising fluids onto specific zones of the reservoir at any one time, the operation can in some embodiments use the optimum flux of mobilising fluids to maximise hydrocarbon recovery and maximise the ratio of hydrocarbons produced to mobilised fluids injected. Given that most reservoirs are heterogeneous in nature, the optimum operating conditions may then be selected for each zone of the reservoir, as the location(s) of the injected mobilising fluids are moved through the reservoir.

[0134] By moving the location of the injection of mobilising fluids along the horizontal well bore of the first well, operators can attempt to achieve: i) an efficient use of the mobilising fluids, ii) sustained production of hydrocarbon fluids and iii) high hydrocarbon recovery factor. Each of these parameters directly relates to the economic performance of an enhanced oil recovery operation

[0135] The mobilising fluids can be injected into the hydrocarbon bearing reservoir through at least one opening in the tubing. If the tubing is arranged in a well liner, the mobilising fluid can then pass through an open area such as perforations in the liner. In the reservoir, a zone of mobilised hydrocarbons is therefore created, which will comprise naturally occurring hydrocarbons and the mobilising fluids; and or the products of any physical and chemical interactions which occur between them.
The zone of mobilised hydrocarbons is a zone located in the vicinity of the completion assembly of the first well from which mobilising fluids are injected to the reservoir.

[0136] The resulting mixture of fluids from the mobilised zone can be referred to as the produced fluids. The produced fluids from the zone of mobilised hydrocarbons may flow via gravity, pressure and or other means through the liner of the completion assembly of the second well, as described below, and may enter the completion tubing. From there the produced fluids may travel to the heel of the well and be produced to surface via a pump and production tubing.

[0137] The completion tubing can be a concentric tubing comprising an inner tube and an outer tube. The tubing can comprise at least one opening in the form of a first series of apertures. The first series of apertures can be in fluid communication with the inner tube. The tubing can comprise a further series of apertures spaced along the length of the tubing. The further series of apertures can be in fluid communication with the outer tube. The first series of apertures can be towards the tip of the tubing. The further series of apertures can be remote from the tip.

[0138] In an embodiment, the apertures are arranged on a completion device.

There can be more than one completion device installed onto the completion tubing.
The advantage of the completion device is that is can integrate all of the required functions in one device and may be readily installed onto and uninstalled from the completion tubing from the rig equipment at surface. By having a standard completion device, multiple may be easily installed onto the completion tubing as it is positioned into the wellbore. The completion device may also incorporate common features of existing oil and gas completions such as monitoring instrumentation, inflow/outflow devices to control the rate of injection/production of fluids to/from the reservoir, and sealing devices and safety devices such as quick-disconnect mechanisms. An injection completion device can be installed on the completion assembly in the injection well.

[0139] The apertures can be any desired pattern of open area; for example slots, holes or even just an open end of the tubing. The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of first series of first apertures in the completion tubing, each set spaced apart from one another.
The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of further series of apertures in the completion tubing, each set spaced apart from another.

[0140] The apertures in the completion tubing can deliver the mobilising fluid into the horizontal well and then into the reservoir. If the tubing is a concentric tubing, there can be more than one mobilising fluid. The first series of apertures can deliver a first mobilising fluid, and the further series of apertures can deliver a second mobilising fluid

[0141] Where there is more than one mobilising fluid, each mobilising fluid can be injected into the reservoir at a different location. At or near each injection location one or more sealing devices can be installed to form a seal between the completion tubing and the liner. The one or more seals can assist in ensuring that the injected mobilising fluid is injected with the correct flux into the reservoir at the required location(s) and does not redistribute along the length of the horizontal injection well, thereby reducing the average flux into the reservoir.

[0142] In an embodiment, the completion assembly in the first well can comprise of completion tubing and completion devices, which are well known in the art.
For example, sliding sleeve devices are well known completion devices in the prior art which generally can only convey one fluid at a time, to or from the reservoir, which may be sufficient for the purposes of the first well. For example, out flow devices may be installed in combination with the completion tubing and sliding sleeve devices.

[0143] When the hydrocarbons in the zone of mobilised hydrocarbons have been produced, the location of the injection of the mobilising fluids may be moved longitudinally along the horizontal well bore of the first well, to enable the mobilisation of hydrocarbons from a new portion of the reservoir.

[0144] In an embodiment, the step of changing the location of the injection of mobilising fluid in the first well can comprise of moving a sliding sleeve in a completion device to open apertures, thereby enabling mobilizing fluid to enter the reservoir at a new location along the well bore.

[0145] In an embodiment, the step of changing the location of the injection of mobilising fluid in the first well can comprise of moving a sliding sleeve in a completion device to close apertures, thereby disabling mobilizing fluid to enter the reservoir at an old location along the well bore.

[0146] In an embodiment, the step of changing the location of the injection of mobilising fluid in the first well can comprise of moving the completion tubing, and if installed, the completion devices, longitudinally along the horizontal well bore, thereby enabling the mobilizing fluid to enter the reservoir at a new location along the first well bore.

[0147] In an embodiment the mobilising fluid may be injected continuously.
In an embodiment the mobilising fluid may be injected discontinuously, for example as per cyclic processes (such as "huff and puff") and/or as per sequential processes (such as water-alternating-gas (WAG) injection).
Second well

[0148] The second well will be located within the vicinity of the first well. The relative location of the first and second wells will depend on the nature of the enhanced oil recovery method and the nature of the reservoir, in particular the viscosity of the hydrocarbon fluids and the permeability of the reservoir.

[0149] The horizontal section of the second well may be located at a higher or lower elevation (depth) relative to the first well. The second well may be located deeper than the first well when it is desirable to enhance the gravity drive mechanism to increase flow of produced fluids to the second well. The second well may be located shallower than the first well, when some of the produced fluids have a lower relative density, for example to extract gaseous vapours from the reservoir or to extract oil from a layer above a water saturated zone. Most often, the first and second well will be located at approximately the same elevation (depth).

[0150] The lateral distance between the first well and second well may be between a few tens of metres and a few thousand metres. Typically, the distance between the wells will be in the range of from about 50 and about 500 metres, preferably about 50 to about 200 metres. However, in general, the lateral distance between the wells will be chosen with regards to the reservoir properties, the type of enhanced oil recovery methods being used and surface constraints. For example, offshore wells will likely be spaced further apart than onshore wells.

[0151] In an embodiment, the completion assembly in the second well can comprise of completion tubing and completion devices, which are well known in the art. For example, sliding sleeve devices are well known completion devices in the prior art which generally can only convey one fluid at a time, to or from the reservoir, which may be sufficient for the purposes of the second well. For example, in flow devices may be installed in combination with the completion tubing and sliding sleeve devices.

[0152] In an embodiment, as the location of the injection of mobilizing fluid is changed in the first well, the location of the production of produced fluids from the reservoir may be changed in the second well.

[0153] In an embodiment, the step of changing the location of the production fluids in the second well can comprise of moving a sliding sleeve in a completion device to open apertures, thereby enabling produced fluids to enter a conduit in the completion device from the reservoir at a new location along the well bore.

[0154] In an embodiment, the step of changing the location of the produced fluids in the second well can comprise of moving a sliding sleeve in a completion device to close apertures, thereby disabling produced fluids to enter a conduit in the completion device from the reservoir at an old location along the well bore.

[0155] In an embodiment, as the completion tubing in the first well is moved, the completion tubing in the second well can be moved. The tubings can be moved at substantially the same time. The tubings can be moved over substantially the same distances.

[0156] By moving the location of the injection zone along the horizontal section of the first well, operators can attempt to achieve: i) an efficient use of the mobilising fluids, ii) sustained production of hydrocarbon fluids from the second well and iii) high hydrocarbon recovery factor for the reservoir. Each of these parameters directly relates to the economic performance of an enhanced oil recovery operation.

[0157] The mobilising fluids can be withdrawn from the hydrocarbon bearing reservoir through at least one opening in the tubing. If the tubing is arranged in a well liner, the mobilising fluid can pass through an open area such as perforations in the liner. In the reservoir, a zone of mobilised hydrocarbons is created, which will comprise naturally occurring hydrocarbons and the mobilising fluids; and or the products of any physical and chemical interactions which occur between them.
The zone of mobilised hydrocarbons is a zone located in the vicinity of the completion assembly from which mobilising fluids and produced fluids are injected to and extracted from the reservoir, respectively.

[0158] The resulting mixture of fluids from the mobilised zone can be referred to as the produced fluids. The produced fluids from the zone of mobilised hydrocarbons may flow via gravity, pressure and or other means back through the liner and may enter the completion tubing. From there the produced fluids may travel via the second well to the heel of the well and be produced to surface via a pump and production tubing.

[0159] The completion tubing in the second well can be a concentric tubing comprising an inner tube and an outer tube. The tubing can comprise at least one opening in the form of a first series of apertures. The first series of apertures can be in fluid communication with the inner tube. The tubing can comprise a further series of apertures spaced along the length of the tubing. The further series of apertures can be in fluid communication with the outer tube. The first series of apertures can be towards the tip of the tubing. The further series of apertures can be remote from the tip.

[0160] In an embodiment, the apertures are arranged on a completion device.

There can be more than one completion device installed onto the completion tubing.
The completion device may also incorporate common features of existing oil and gas completions such as monitoring instrumentation, inflow/outflow devices to control the rate of injection/production of fluids to/from the reservoir, and sealing devices and safety devices such as quick-disconnect mechanisms. A production completion device can be installed on the completion assembly in the production well.

[0161] The apertures can be any desired pattern of open area; for example slots, holes or even just an open end of the tubing. The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of first series of first apertures in the completion tubing, each set spaced apart from one another.
The first series of apertures can comprise a cluster of 2, 3, 4, 5, 6, 7, 8, 9, or 10 apertures each of about 5, 10, 15, 20, 25 mm in diameter. There can be more than one set of further series of apertures in the completion tubing, each set spaced apart from another.

[0162] The apertures in the completion tubing can receive and withdraw the mobilising fluid into the horizontal well from the reservoir.

[0163] When the hydrocarbons in the zone of mobilised hydrocarbons have been produced, the location of the completion tubing may be moved longitudinally along the horizontal well bore, to enable the mobilisation of hydrocarbons from a new portion of the reservoir.

[0164] In an embodiment the second well may be fitted with inflow control devices to manage the pressure drop through the reservoir and along the length of the horizontal section of the well. The inflow devices may be installed on the completion tubing.

[0165] In an embodiment, the second well may be an open completion or a well liner without any completion tubing. In this case, the fluids enter the second well at locations along the horizontal without any physical intervention.

[0166] In an embodiment the produced fluids may be produced continuously.
In an embodiment the produced fluids may be produced discontinuously, for example as per cyclic processes (such as "huff and puff") and/or as per sequential processes (such as water-alternating-gas (WAG) injection).

[0167] In an embodiment, an upgrading device is provided in the path of the produced fluid so as to upgrade the produced fluid as it is withdrawn through the tubing. The upgrading device can be a physical device, a material, a mixture of materials and/or a sequence of materials which improves the quality of the produced hydrocarbon fluids from the reservoir.

[0168] In an embodiment, the quality of the produced fluids is monitored.
Monitoring of the quality of the produced fluids can provide an indicator of how to move the completion through the reservoir. A low ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which the completion tubing (and associated completion device) is moved should be increased. A high ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which the completion device is moved should be decreased.

[0169] Therefore, in some embodiments the method can further comprise the steps of:
monitoring the produced fluid from each of the mobilised zones to determine the ratio of used mobilising fluid and mobilised hydrocarbons in the produced fluid;
selecting or otherwise adjusting the frequency of the change in the location of injection of mobilising fluid and or the distance between the first location and the one or more further locations depending on the monitored ratio.

[0170] When a low ratio of hydrocarbons to mobilising fluids is reached the frequency and/or distance which the tubing is moved should be increased. When a high ratio of hydrocarbons to mobilising fluids is reached the frequency and/or distance which the tubing is moved should be decreased. The ratio will depend on the type of mobilising fluid used; each fluid will have different properties.
Also the ratio will depend on the reservoir.

[0171] The combination of moving the injection location in the first well and monitoring the produced fluids from the second well can alleviate the need to individually monitor and control the influx of produced fluids from discrete regions of the reservoir in the production well.

[0172] In an embodiment the produced fluids may be produced to surface via artificial lift, i.e. due to pumping of the fluids or due to the injection of low density fluids (ie. gases) into the well to lift them to surface. The artificial lift fluids may be injected via dedicated tubing placed in the well or may be formed via the injection and reaction of the mobilising fluids with the in situ hydrocarbons (for example during in situ combustion, the reaction of injected air with the hydrocarbons forms light gases).

[0173] It should also be recognised that while the discussion above refers to a well pair with a first well (the injection well) and a second well (the production well), in some embodiments more than one injection well can be used with a single production well; and in some embodiments more than one production well can be used with a single injection well. Further, in some embodiments the method may be applied to patterns of wells, wherein any suitable ratio of injection wells to production wells can be applied.

[0174] The discussion below refers to the completion assembly of the first well and the completion assembly of the second well unless the context makes clear otherwise.

[0175] The step of moving of the tubing in either the first well or the second well can comprise retracting the tubing. The step of moving of the tubing can comprise advancing the tubing. The step of retracting the tubing can be undertaken by removal of tubing sections. The step of retracting the tubing can be by winding up the tubing. The step of advancing the tubing can be undertaken by addition of tubing sections. The step of advancing the tubing can be by winding out the tubing from a coil.

[0176] The step of changing the location of injection can be changing the injection point along the length of the tubing.

[0177] In an alternative, rather than move the completion assembly, there can instead be a mechanism by which various apertures in the completion assembly are openable and closable so as to cause the change in the location of the injection of mobilising fluid. Thus, in the step c), the step is undertaken by changing the apertures in the completion assembly through which mobilising fluid is injected. The change in the apertures used can be sequential, so there is effectively a front of mobilising fluid movement injected into the formation over time. The apertures can be openable and closable by any means.

[0178] In an embodiment the apertures can be opened and closed using sliding sleeve devices which are well known in the industry. The sliding sleeve devices may be activated using pressure, dropped balls of different sizes, RFID tags, hydraulic control lines, slick lines, coiled tubing or any other suitable means. As will be appreciated by those skilled in the art, when a sliding sleeve device is used, a well liner may not be present or its functionality (eg. to prevent sand inflow) can be incorporated into the sliding sleeve device itself.

[0179] In an embodiment, the completion assembly can comprise of a number of completion devices, whereby each completion device has apertures that can be opened and closed, thereby enabling the injected fluids to be injected at one location along the horizontal well bore at one time, and at another location at another time.
Similarly, the produced fluids can be produced from one location at one time and another location at another time.

[0180] The completion devices can comprise of sliding sleeves that may be moved to open and close the apertures for the injected fluids and for the produced fluids. In an embodiment, the sliding sleeves may be operated using any conventional means, including coiled tubing or wireline tools to latch on to the sleeve and move its position, the use of drop balls, the use of hydraulic actuators and any other method known in the art.

[0181] In an embodiment the completion device can comprise of a conduit for the injected fluid and a conduit for the produced fluid.

[0182] In an embodiment the completion assembly can comprise of a number of completion devices connected directly together. In an embodiment the completion devices can be connected together using standard tubings.

[0183] In an embodiment, the new location of the injection point in the completion assembly, may overlap with its old position, thereby creating an overlap between the old and new location of the zone of mobilised hydrocarbons. Generally, it is preferable to ensure that the zone of mobilised hydrocarbons formed by operation at successive positions of the completion assembly overlap. This may ensure that there is a zone of sufficient permeability to inject the mobilising fluids. It may also help to ensure a high recovery factor for the hydrocarbons, as all of the reservoir is contacted successively with mobilising fluids.

[0184] The mobilising fluid can be selected from one or more of steam, oxidants (oxygen containing fluids), solvents, carbon dioxide, light hydrocarbons such as methane, ethane, propane and butane, water and nitrogen and any other fluids usually used for the same purpose. Where there is a first mobilising fluid and a second mobilising fluid, the two fluids can be the same or different from one another.

[0185] In some applications, for example recovery of bitumen and very heavy oils, a zone of mobilised hydrocarbons may need to be present between the first well and the second well, before the system of the second aspect can be applied.

[0186] In an embodiment the zones of mobilised hydrocarbons between the first well and second well may be generated by any method well known in the field.
For example, steam circulation is often used in bitumen recovery to mobilise bitumen between an injection well and a production well.

[0187] In an embodiment, the application of the third aspect in a first and second well, may follow an earlier operation where each well has been operated with injection and production according to the first and or second aspects.

[0188] An advantage of this sequence of operations is that zones of mobilised hydrocarbons will have already been created, by the earlier single well operations, and these zones may overlap, thereby creating a continuous or nearly continuous zone of mobilised hydrocarbons between the first well and the second well.

[0189] The presence of continuous or nearly continuous zones of mobilised hydrocarbons may be necessary to establish injection from the first well and production from the second well in some reservoirs.
BRIEF DESCRIPTION OF THE DRAWINGS

[0190] Embodiments of the invention and other embodiments will now be described with reference to the non-limiting drawings which are exemplary only. The description in relation to any one of the Figures can be applied to any of other of the Figures unless the context makes clear otherwise.

[0191] Figure 1 is a side section view of a portion of hydrocarbon-bearing subterranean formation illustrating certain aspects using a predominately horizontal well.

[0192] Figure 2 is a side section view of a portion of hydrocarbon-bearing subterranean formation illustrating certain aspects using a predominately horizontal well.

[0193] Figure 3 illustrates an embodiment wherein the moveable well completion incorporates a single tubing string and is configured for single zone injection of the mobilising fluids and the recovery of hydrocarbons in the annulus between the well liner and tubing string.

[0194] Figure 4 illustrates an embodiment wherein the moveable well completion incorporates a concentric tubing string and is configured for single zone injection of the mobilising fluids and the recovery of hydrocarbons in the inner tubing of the concentric tubing string. An upgrading material is installed to improve the properties of the produced hydrocarbon fluids as they flow back to surface.

[0195] Figure 5 illustrates an embodiment wherein the moveable well completion incorporates a concentric tubing string and is configured for injecting a primary and secondary mobilising fluid and the recovery of hydrocarbons in the annulus between the well liner and tubing string.

[0196] Figure 6 illustrates an embodiment wherein the moveable well completion incorporates a concentric tubing string and is configured for multiple zone injection of a single mobilising fluid and multiple zone recovery of the produced hydrocarbons the annulus of the concentric tubing string.

[0197] Figure 7 illustrates an embodiment showing two adjacent predominately horizontal wells each of which is configured for multiple zone injection and multiple zone recovery of the hydrocarbons from the reservoir. Although two wells are shown, each well is operating as a single injector/producer.

[0198] Figure 8 is a side section view of a portion of hydrocarbon-bearing subterranean formation illustrating certain aspects using a predominately horizontal well.

[0199] Figure 9 is a side section view of a portion of hydrocarbon-bearing subterranean formation illustrating certain aspects using a predominately horizontal well.

[0200] Figure 10 illustrates a side view of an embodiment wherein the completion device incorporates an eccentrically arranged sliding sleeve device and completion tubings that enable it to be connected to other tools.

[0201] Figure 11 illustrates cut-away views of the positions of components of an embodiment wherein the completion device incorporates an eccentrically arranged sliding sleeve device.

[0202] Figure 12 illustrates a view of an embodiment wherein the completion device incorporates a concentrically arranged sliding sleeve device and the sleeve is positioned so that no flow occurs.

[0203] Figure 13 illustrates a view of an embodiment wherein the completion device incorporates a concentrically arranged sliding sleeve device and the sleeve is positioned so that flow can occur between the inner annulus and the outside of the completion device (reservoir).

[0204] Figure 14 illustrates a view of an embodiment wherein the completion device incorporates a concentrically arranged sliding sleeve device and the sleeve is positioned so that flow can occur between the outer annulus and the outside of the completion device (reservoir).

[0205] Figure 15 is a side section view of a portion of hydrocarbon-bearing subterranean formation illustrating certain aspects using a predominately horizontal well.

[0206] Figure 16 is a conceptual drawing of the configuration and sequencing of completion devices in a well bore.

[0207] Figure 17 shows two adjacent predominately horizontal wells, one well configured for multiple zone injection of mobilising fluids and the other well configured for multiple zone recovery of the hydrocarbons from the reservoir, wherein the hydrocarbons are transported to surface in production tubing

[0208] Figure 18 shows two adjacent predominately horizontal wells, one well configured for multiple zone injection of mobilising fluids and the other well configured for recovery of hydrocarbons from the reservoir along the length of the horizontal, wherein the hydrocarbons are transported to surface using a pump and production tubing.

[0209] Figure 19 shows the moveable well completion incorporating a concentric tubing string configured for the injection of a primary and secondary mobilising fluid into the hydrocarbon bearing reservoir.

[0210] Figure 20 shows temperature profiles through the reservoir for an embodiment showing a single point injection for Moving Injection Combustion Stimulation (MICS) at three different times.

[0211] Figure 21 shows temperature profiles through reservoir for an embodiment showing a multiple-point injection for Moving Injection Combustion Stimulation (MICS) at three different times.

[0212] Figure 22 shows a schematic of the computational domain and shows contours of oil saturation in the reservoir after 10 years of waterflood enhanced oil recovery for static and moving injection configurations.

[0213] Figure 23 is a plan view of temperature contours at three different times from two adjacent predominately horizontal wells configured for single point injection for Moving Injection Combustion Stimulation (MICS).

[0214] Figure 24 is a plan view of temperature contours at three different times from two adjacent predominately horizontal wells, where the first well is configured for the moving injection of mobilised fluids and the second well is configured to produce hydrocarbons from the reservoir.
DESCRIPTION OF EMBODIMENTS

[0215] Throughout this specification, unless the context requires otherwise, the words "comprise"/"include", "comprises"/"includes" and "comprising"/"including" will be understood to mean the inclusion of a stated integer, group of integers, step, or steps, but not the exclusion of any other integer, group of integers, step, or steps.

[0216] Any promises made in the present description should be understood to relate to some embodiments of the invention, and are not intended to be promises made about the invention. Where there are promises that are deemed to apply to all embodiments of the invention, the right is reserved to later delete those promises from the description since there is no intention to rely on those promises for the acceptance or subsequent grant of a patent unless the context makes clear otherwise.
SINGLE WELL

[0217] Referring to Figure 1, there is generally depicted a hydrocarbon bearing subterranean formation 6. A generally horizontal well bore 10 is drilled through the over burden formation 18 and into the hydrocarbon bearing reservoir 6 using standard directional drilling techniques. Fractures 20 may exist in the reservoir 6 and/or overburden 18. Casing 22 extends from the surface to the horizontal section of the well. Surface casing 28, which may consist of multiple concentric tubings, is installed into the vertical section of the well. The casings and tubings are connected together at surface in a wellhead 30 as is common practice. A liner 4 with a certain amount of open area is installed into the horizontal section of the well bore 10.
Completion tubing 2 is installed into the well, with a completion device 12 at its tip.
The completion tubing may be jointed tubing or it may be coiled tubing. The completion tubing 2 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings. Production tubing 24 may be installed into the vertical section of the well along with a pump 26. Mobilising fluids 8 are injected from surface through the completion tubing 2 and enter into the completion device 12. The mobilising fluids 8 may exit into the annular space between the completion device 12 and the liner 4. The mobilising fluids are injected into the hydrocarbon bearing reservoir 6 through the open area in the liner 4. In the reservoir 6 a zone of mobilised hydrocarbons 14 is created, which consists of naturally occurring hydrocarbons and the mobilising fluids; and the products of any physical and chemical interactions which occur between them. The resulting mixture of fluids from the mobilised zone are labelled as the produced fluids 16. The produced fluids 16 from the zone of mobilised hydrocarbons 14 flow via gravity, pressure and other means back through the liner 4 and may enter the annular space between the completion tubing 2 and liner 4. From there the produced fluids may travel to the heel of the well and be produced to surface via a pump 26 and production tubing 24

[0218] The zone of mobilised hydrocarbons 14 is a zone located in the vicinity of the completion device 12, from which mobilising fluids 8 and produced fluids 16 are injected to and extracted from the reservoir, respectively.

[0219] When the hydrocarbons in the zone of mobilised hydrocarbons 14 have been produced using the completion device, in this embodiment the location of the completion device 12 may be moved longitudinally along the horizontal well bore 10, to enable the mobilisation of hydrocarbons from a new portion of the reservoir. The completion device 12 may be moved into or out of the well bore by adding or removing one or more joints of tubing, when the completion tubing is jointed;
or by winding or unwinding the coiled tubing if the completion tubing is coiled.

[0220] In an embodiment, the hydrocarbon bearing subterranean formation 6 may be naturally fractured. In an embodiment the hydrocarbon bearing subterranean formation 6 has been fractured via earlier fracturing operations. In an embodiment, the hydrocarbon bearing subterranean formation 6 is unfractured.

[0221] In an embodiment in which the tubing in moved, as seen in Figure 2, the location of the completion device 112 is moved along the well bore from its old position (in Figure 1). In an embodiment as also seen in Figure 2, the new location of the completion device 112, may overlap with its old position (in Figure 1), thereby creating an overlap between the old and new location of the zone of mobilised hydrocarbons 114.

[0222] Generally, it is preferable to ensure that the zone of mobilised hydrocarbons 114 formed by operation at successive positions of the completion device 112 overlap. This ensures that there is a zone of sufficient permeability to inject the mobilising fluids 108; it also helps to ensure a high recovery factor for the hydrocarbons, as all of the reservoir is contacted successively with mobilising fluids 108.

[0223] Monitoring of the quality of the produced fluids 116 can provide an indicator of how to move the completion device 112 through the reservoir. A
low ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which the completion device 112 is moved should be increased. A high ratio of hydrocarbons to mobilising fluids may indicate that the frequency and/or distance which the completion device is moved should be decreased.

[0224] An advantage of using a moveable completion device 112 to inject mobilising fluids 108 into the reservoir 106 is that greater precision is possible in the injection of the mobilising fluid 108. In particular, by using the completion device 112 the injection of the mobilising fluids 108 can be focused over only a portion of the well bore 110 and hence the flux of mobilising fluids 108 into the reservoir 106 can be controlled to ensure optimum use of the mobilising fluids. In all enhanced oil recovery operations achieving a high ratio of hydrocarbons to the mobilising fluids is desirable. In many enhanced oil recovery methods controlling the flux of the injected mobilising fluids is critical to achieving the conditions required to mobilise the maximum amount of hydrocarbons from the reservoir.

[0225] By moving the completion device 112 along the horizontal well bore 110, operators can achieve: i) an efficient use of the mobilising fluids, ii) sustained production of hydrocarbon fluids and iii) high hydrocarbon recovery factor.
Each of these parameters directly relates to the economic performance of an enhanced oil recovery operation

[0226] In an embodiment, multiple completion devices 112 may be installed onto the completion tubing 102.

[0227] In an embodiment the produced fluids 116 may be produced to surface via a conduit in the injection tubing 102. For example, the injection tubing may consist of concentric tubing enabling both the injection of mobilising fluids 108 and the production of produced fluids 116.

[0228] In an embodiment the produced fluids 116 may be produced to surface via artificial lift, i.e. due to a pump or due to the injection of low density fluids (ie.
gases) into the well to lift them to surface. The artificial lift fluids may be injected via dedicated tubing placed in the well or may be formed via the injection and reaction of the mobilising fluids with the in situ hydrocarbons (for example during in situ combustion, the reaction of injected air with the hydrocarbons forms light gases)

[0229] The details of the completion device 112 and examples of specific embodiments are provided in Figures 3 to 6 and Figures 10 to 14.

[0230] Referring to Figure 3, there is generally depicted a hydrocarbon bearing subterranean formation 206, a generally horizontal section of a well bore 210 and the completion device 212.

[0231] Mobilising fluids 208 are injected into the completion device 212 and exit from apertures 242 in the device. The mobilising fluids enter the space between the completion device 212 and the liner 204 and are injected into the hydrocarbon reservoir 206.

[0232] The apertures 242 in the completion device 212 may be any desired pattern of open area; for example slots, holes or even just an open end of the tubing.

[0233] The mobilising fluids 208 forms a zone of mobilised hydrocarbons within the reservoir, in the vicinity of the completion device 212.

[0234] Produced fluids 216 pass through the liner 204 at locations with open area and enter into the annulus between the completion device 212 and the liner 204; and then flow to surface.

[0235] In order to prevent, or at least reduce, the propensity for the mobilising fluids 208 to bypass the reservoir 206 and return to surface via the annulus, one or more sealing devices 240 are installed to form a seal between the completion device 212 and the liner 204; and thereby prevent a direct connection from forming between the injection apertures 242 and the production annulus.

[0236] Ideally, the sealing devices 240 would be positioned at locations such that they seal with blank sections of the liner 204, as opposed to sections of the liner 204 containing open area. This is possible, if the liner 204 and completion device 212 are designed and installed together. However, in general, when the completion device 212 is used in an old well, with a typical pattern of open area used in liners, then the sealing devices 240 will necessarily need to seal against areas of the liner, containing some open area.

[0237] The sealing devices 240 are designed to i) create a seal between the completion device 212 and the liner 204, and ii) allow the completion device 212 to be moved into and out of the well bore 210. The sealing devices should also be designed for the well bore conditions experienced during operation; for example, the relevant temperature, pressure, fluid compositions and the presence of reservoir materials such as sand and rock in addition to hydrocarbons.

[0238] In an embodiment, sealing devices 240, may also be installed at the end of the completion device 212 so that the mobilising fluids 208 can only pass through a specific zone of the liner 204 and into the reservoir 206.

[0239] If thermal enhanced oil recovery operations are used, then the sealing devices 240 must be able to withstand the high operating temperatures. When using solvents as the mobilising fluid temperatures up to 200 C may be present;
when using steam as the mobilising fluid temperatures up to 300 C may be present;
while during in situ combustion temperatures up to 600 C may be present. When such high temperatures are present a metal to metal seal may be preferred. In order, to allow movement of the seal, some degree of leakage from the seal may be acceptable and/or a necessary compromise to make.

[0240] If low temperature (less than 200 C) enhanced oil recovery operations are used then the materials used for the sealing devices 240 may be selected from a large range of generally available materials, such as elastomers. The sealing devices 240 may be inflatable devices. In general, the sealing function of the sealing devices 240 should not be triggered by a reaction with the mobilising fluids 208 or the produced fluids 216, since these methods of sealing will likely prevent the subsequent movement of the sealing devices 240.

[0241] In an embodiment, different mobilising fluids 208 may be injected in a sequence. For example, when the mobilising fluid 208 is an oxidant, water may be injected in sequence with the oxidant. During water injection into the completion device 212, the production of hot produced fluids 216 due to the combustion process, will heat the injected water turning it into steam, absorbing a large amount of energy. Hence, by injection a sequence of mobilising fluids 208 of oxidant and then water, the temperature of the completion device 212 and well liner 204 can be controlled to temperatures which ensure the mechanical integrity of the materials used and are below about 500 C, and preferably below about 300 C. At the same time, both oxygen and steam are injected into the formation 206, to mobilise the hydrocarbons.

[0242] The liner may have any arrangement of open area, including slots, holes, perforations or permeable meshes, such as wire wraps, installed in any manner.
In many applications, liners 204, have slots 244 manufactured into them.

[0243] Referring to Figure 4, which shows an embodiment for the completion device 312 using a concentric tubing string arrangement, which enables the injection of the mobilising fluids 308 and the production of produced fluids 316 (and upgraded produced fluids 317) to be controlled via a single tubing string.

[0244] A generally horizontal well bore 310 is drilled into the hydrocarbon bearing reservoir 306 using standard directional drilling techniques. A liner 304 with a certain amount of open area is installed into the well bore 310. The completion device uses a concentric tubing arrangement. Mobilising fluids 308 are injected through the annulus 348 formed between the outer and inner tubings and exit from apertures into the annulus between the completion device 312 and the liner 304. The mobilising fluids are injected into the hydrocarbon bearing reservoir 306 through the open area in the liner 304. In the reservoir 306 a zone of mobilised hydrocarbons is created, which consists of naturally occurring hydrocarbons and the mobilising fluids;
and the products of any chemical and physical interactions which occur between them. The resulting mixture of fluids from the mobilised zone are labelled as the produced fluids 316. The produced fluids 316 from the zone of mobilised hydrocarbons flow via gravity, pressure and other means back through the liner and enter the space around and ahead of the completion device 312 in the well bore 310. The produced fluids 316 re-enter the completion device 312 through apertures 346.

[0245] In order to prevent, or at least reduce, the propensity for the mobilising fluids 308 to bypass the reservoir 306 and return to surface via the annulus, one or more sealing devices 340 are installed to form a seal between the completion device 312 and the liner 304; and thereby prevent a direct connection from forming between the injection apertures 342 and the production apertures 346.

[0246] Inside the completion device 312, an upgrading device 349 may be present. The upgrading device 349 may be used to upgrade the produced fluids to higher quality; thereby becoming upgraded produced fluids 317.

[0247] When the mobilising fluid 308 is an oxidant, the produced fluids 316, are expected to be at temperatures between 250 and 600 C. These temperatures are sufficient to crack medium and heavy oils and bitumen to produce lighter oil components. Under these conditions, the use of a catalyst in the upgrading device 349 can improve the properties of the produced fluids. The use of catalyst(s) as upgrading material(s) is therefore beneficial.

[0248] Hydrotreating and hydrocracking catalysts may be used in the upgrading device 349. Common catalyst materials for hydroprocessing include CoMo/alumina, NiMo/alumina and others.

[0249] When upgrading hydrocarbon fluids at temperature and pressure and with catalysts, it is well known that the addition of hydrogen or hydrogen donor solvents can greatly improve the upgrading process. In an embodiment, hydrogen or hydrogen donor solvents may be injected upstream of the upgrading material via a hydrogen injection tubing (not shown) to improve the upgrading of the hydrocarbon fluids in the upgrading device 349.

[0250] In prior art, such as US Patent 6,412,557 B1 and US Patent 7,909,097 B2, an upgrading catalyst is installed into the well liner, which makes installation of the liner much more difficult during well construction, raising costs; and the contact of the produced fluids with the catalyst is limited; reducing the degree of upgrading. In addition, as only a small volume of the produced fluids come into contact with each volume of catalyst; large volumes of catalyst are installed into the liner with poor utilisation. The major advantages of the design shown in Figure 4 over the prior-art is that: i) catalyst in the upgrading device 349 can be installed and removed from the well bore 310, and can therefore be replaced if required, ii) as the completion device 312 is moved through the reservoir 306, the catalyst is automatically exposed to all of the produced fluids 316, making efficient use of the catalyst volume and iii) the weighted hourly space velocity (WHSV) of the fluids traversing the catalyst bed can be controlled and optimised by the design of the upgrading device 349.

[0251] In processes such as in situ combustion, residual oxygen in the produced gases can lead to the presence of flammable and/or explosive mixtures which present safety problems; especially in surface facilities. The upgrading device 349 can be designed to react with residual oxygen in the produced fluids 316 to ensure that no residual oxygen is present in the produced fluids 317. Various catalysts are available to reduce the free oxygen content in produced gases and liquids.

[0252] The produced fluids 316 or the upgraded produced fluids 317 when an upgrading device is present are produced to surface via the inner tubing string formed within the concentric tubing strings of the completion device 312.

[0253] A major advantage of the embodiment shown in Figure 4 is that the mobilising fluids 308 and the produced fluids 316 travel to/from the reservoir via dedicated conduits and do not travel in the annulus formed with the liner 304.
Fluids travelling along the annulus formed between the tubing and the liner 304 may interact with the reservoir 306 in ways which are undesirable due to the open area in the liner 304.

[0254] In an embodiment the configuration of the tubings may be reversed;
so that mobilising fluids 308 are injected into the inner tubing of the completion device 312 and exit from apertures 346 and produced fluids 316 are produced from the annulus 348 formed between the outer and inner tubing of the completion device 312. In this embodiment the upgrading device 349 would be placed in the annulus 348 between the inner and outer tubings

[0255] In an embodiment, a cross-over section of tubing may be fitted to the tubing on which the completion device 312 is installed, to enable the conduits carrying injected and produced fluids to be swapped between the vertical and horizontal sections of the well bore.

[0256] The optimal configuration of the tubings and of the primary direction of movement of the completion device 312 in the well bore 310 is dependent upon many factors including the reservoir 306 properties, the nature of the enhanced oil recovery method and the type of mobilising fluids 308 being injected into the reservoir 306.

[0257] In the case of thermal enhanced oil recovery using steam injection and/or in situ combustion, in which the mobilising fluid 308 is steam or an oxidant, the zone of mobilised hydrocarbons may reach high temperatures (200 to 600 C) and the produced fluids 316 may be hot (> 100 C), it is advisable that the produced fluids 316 are captured via apertures 346 located at one end of the completion device 312;
and that the primary direction of travel of the completion device 312 within the well bore 310 is in the same direction as the produced fluids 316 within the tubings. This configuration ensures that the production zone in the vicinity of the liner 304 is ahead of the completion device 312, and so any damage to liner 304 from overheating or excessive sand production does not interfere with the performance of the sealing devices 340. The sealing devices 340 generally operate better at ambient reservoir temperatures (between 20 and 100 C) and when the liner 304 geometry and integrity is maintained and when there is little or no sand build up. This configuration (as shown in Figure 4) also has the advantage that any hydrocarbons draining from previously swept regions of the reservoir 306 into the well bore 310 may still be collected and produced to surface.

[0258] When the hydrocarbons in the zone of mobilised hydrocarbons have been produced using the completion device 312, the location of the completion device 312 may be moved longitudinally along the horizontal well bore 310, to enable the mobilisation of hydrocarbons from a new portion of the reservoir. The completion device 312 may be moved into or out of the well bore by adding or removing one or more joints of tubing, when the completion tubing is jointed; or by winding or unwinding the coiled tubing if the completion tubing is coiled.

[0259] Generally, it is preferred that the zones of mobilised hydrocarbons formed successively by moving the completion device 312 along the well bore 310, overlap.

[0260] In an embodiment the completion device 312 is moved a distance equal to the distance between adjacent sealing devices 340.

[0261] In an embodiment, the completion device 312 is moved a distance equal to the distance between the apertures 342 and apertures 346, such that the new location of the apertures 346 is at the old location of the apertures 342 when the completion device 312 is retracted from the well bore 310; or the location of the apertures 342 is at the old location of the apertures 346 when the completion device 312 is pushed into the well bore 310.

[0262] Referring to Figure 5, which shows an embodiment for the completion device 412 using a concentric tubing string arrangement, which enables the injection of a primary mobilising fluid 408 and a secondary mobilising fluid 450 and the production of produced fluids 416 in the annulus between the completion device and the liner 404.

[0263] A generally horizontal well bore 410 is drilled into the hydrocarbon bearing reservoir 406 using standard directional drilling techniques. A liner 404 with a certain amount of open area is installed into the well bore 410. The completion device uses a concentric tubing arrangement.

[0264] Primary mobilising fluids 408 are injected through the inner tubing of the concentric tubing of the completion device 412. The primary mobilising fluids 408 exit from apertures 442 into the annulus between the completion device 412 and the liner 404. The primary mobilising fluids 408 are injected into the hydrocarbon bearing reservoir 406 through the open area in the liner 404.

[0265] Secondary mobilising fluids 450 are injected through the annulus formed between the outer and inner tubings and exit from apertures 446 into the annulus between the completion device 412 and the liner 404. The secondary mobilising fluids 450 are injected into the hydrocarbon bearing reservoir 406 through the open area in the liner 404.

[0266] In the reservoir 406 a zone of mobilised hydrocarbons is created, which consists of naturally occurring hydrocarbons and the primary and secondary mobilising fluids; and the products of any chemical and physical interactions which occur between them. An intermediate mixture of fluids 452 is formed from the interaction of the primary mobilising fluids 408 and the naturally occurring hydrocarbons. A resulting mixture of fluids, is formed from the interaction of the intermediate fluids 452 and the secondary mobilising fluids 450 forming the produced fluids 416. The produced fluids 416 from the zone of mobilised hydrocarbons flow via gravity, pressure and other means back through the liner 404 and enter the annular space between the completion device 412 and the liner 404, from which they are produced to surface.

[0267] In order to prevent, or at least reduce, the propensity for the primary mobilising fluids 408 and secondary mobilising fluid 450 to bypass the reservoir 406 and return to surface via the annulus, one or more sealing devices 440 are installed to form a seal between the completion device 412 and the liner 404; and thereby prevent a direct connection from forming between the apertures 442,446 and the annulus.

[0268] In an embodiment the configuration of the tubings may be reversed;
so that primary mobilising fluids 408 are injected into annulus 448 formed between the inner and outer tubing of the completion device 412 and the secondary mobilising fluids 450 are injected into the inner tubing of the completion device 412.

[0269] The optimal configuration of the tubings and of the primary direction of movement of the completion device 412 in the well bore 410 is dependent upon many factors including the reservoir 406 properties, the nature of the enhanced oil recovery method and the type of primary and secondary mobilising fluids being into injected into the reservoir 406.

[0270] In an embodiment the primary mobilising fluid 408 or secondary mobilising fluid 450 may contain a nanofluid, i.e. a fluid with nanoadditives which can aid in changing the properties of the hydrocarbons to improve recovery. For example, nanoadditives may be used to reduce the viscosity or modify the surface tension properties of reservoir hydrocarbons.

[0271] In an embodiment the primary mobilising fluid 408 or secondary mobilising fluid 450 may contain a fluid or solid mobilising catalyst. In an embodiment the mobilising catalyst may be a nanoparticle. Nanoparticles may be formed from any suitable catalyst.

[0272] In an embodiment the nanoparticles may be made of iron, nickel, copper, vanadium, or other metals which have been shown to have a catalytic effect on upgrading crude oils. For example, Rezai etal., 2013 (Fuel 2013, v113, pp516-521) show that nanoparticles are effective in reducing the activation energy of combustion reactions.

[0273] In an embodiment the primary mobilising fluid 408 is an oxidant and the secondary mobilising fluid 450 is water or steam.

[0274] In an embodiment, catalysts may be injected with the primary mobilising fluid 408, the secondary mobilising fluid 450 or both fluids.

[0275] One advantage of using a primary and secondary mobilising fluid is that the presence of the secondary mobilising fluid 450 can reduce the direct contact of the primary mobilising fluid 408 with the produced fluids 416 in the well bore 410 by creating a fluid blanket; thereby reducing unwanted interactions such as mixing and reaction.

[0276] Another advantage of using a primary and secondary mobilising fluid is that the temperature of the completion device 412, sealing device 440, liner 404 and well bore 410 can be better controlled. For example, when the primary mobilising fluid 408 is an oxidant, the injection of water or steam as the secondary mobilising fluid 450 can be used to manage the temperatures inside the well bore 410. By ensuring temperatures remain within an acceptable range, the mechanical integrity of the liner 404, completion device 412 and sealing device 440 may be assured and the sealing performance of the sealing devices 440 can be maximised. In this example, if too high temperatures are measured in the completion device 412 then the ratio of secondary to primary mobilising fluids can be increased; while if too low temperatures are measured in the completion device 412 then the ratio of secondary to primary mobilising fluids can be decreased.

[0277] Another advantage of using two mobilising fluids is that one of the mobilising fluids may be used to inject a catalyst material, in the form of a fluid and/or solid, into the reservoir that can catalyse the reaction between the other mobilising fluid and the naturally occurring hydrocarbons. For example, catalysts may be mixed with the secondary mobilising fluid 450 or may be mixed with the primary mobilising fluid 408.

[0278] A major challenge of injecting catalysts into a reservoir using prior art is that due to natural reservoir heterogeneity there is little control over where the catalysts will end up in the reservoir and whether they will be exposed to the right conditions (temperature, pressure, fluid compositions) that will enable them to be effective in upgrading the properties of the hydrocarbons. These facts combined with the relatively expensive nature of most catalysts, mean that catalysts are rarely used in situ to improve the properties of hydrocarbons before they are produced to surface.

[0279] An advantage of the present method/system is that it may in some embodiments address all of the disadvantages of using catalyst in situ in the prior art. Firstly, by moving the injection point for the mobilising fluids through the reservoir there is much greater control over the rate and flux of the injected mobilising fluids in the first place. Secondly, by injecting catalysts with the secondary mobilising fluid 450, a zone of mobilised hydrocarbons and the catalyst can be created in the reservoir; which is subsequently contacted with the primary mobilising fluid 408 as the completion device 412 is moved through the reservoir, thereby creating the optimal conditions for the catalyst to improve the properties of the hydrocarbons in the reservoir.

[0280] In an embodiment, any number of mobilising fluids may be injected into the reservoir 406 via the completion device 412.

[0281] Referring to Figure 6, there is generally depicted a hydrocarbon bearing subterranean formation 506, a generally horizontal section of a well bore 510 and the completion device 512 using concentric tubing to enable multi-zone injection of the mobilising fluids 508 illustrating certain aspects.

[0282] Mobilising fluids 508 are injected into inner tubing of the completion device 512 and exit from apertures 542. The mobilising fluids enter the space between the completion device 512 and the liner 504 and are injected into the hydrocarbon reservoir 506. Multiple sets of the apertures 542 may be arranged along the length of the well bore 410 so that mobilising fluids 508 may be injected into multiple zones of the reservoir 506 at the same time.

[0283] The mobilising fluids 508 form zone(s) of mobilised hydrocarbons within the reservoir, in the vicinity of the completion device 512.

[0284] Produced fluids 516 generated in the zone(s) of mobilised hydrocarbons pass through the liner 504 at locations with open area and first enter into the annulus between the completion device 512 and the liner 504; and then through apertures 546 and into annulus 548 between the inner and outer tubings of the completion device 512.

[0285] In the completion device 512, where required, a conduit (not shown in Figure 6) is formed through the device where injection of the mobilising fluids 508 exit from the device. This conduit is sealed so that mobilising fluids 508 and produced fluids 516 cannot mix. This conduit connects the annulus 548 formed between the inner and outer tubings which transports the produced fluids 516 along the length of the horizontal well bore 510.

[0286] In order to prevent, or at least reduce, the propensity for the mobilising fluids 508 to bypass the reservoir 506 and return to surface via the annulus, one or more sealing devices 540 are installed to form a seal between the completion device 512 and the liner 504; and thereby prevent a direct connection from forming between the injection apertures 542 and the production annulus. When multi-zone injection of mobilising fluids 508 is used, the sealing devices 540 can be arranged so as to form multiple zones of mobilised hydrocarbons in the reservoir 506.

[0287] Ideally, the sealing devices 540 would be positioned at locations such that they seal with blank sections of the liner 504, as opposed to sections of the liner 504 containing open area. This is possible, if the liner 504 and completion device 512 are designed and installed together. However, in general, when the completion device 512 is used in an old well, with a typical pattern of open area used in liners, then the sealing devices 540 will necessarily need to seal against areas of the liner, containing some open area.

[0288] In an embodiment the configuration of the tubings may be reversed;
so that mobilising fluids 508 are injected into the outer tubing of the completion device 512 and exit from apertures 546 and produced fluids 516 enter the inner tubing of the completion device through apertures 542 and are produced to surface.

[0289] Referring to Figure 7, there is generally depicted a hydrocarbon bearing subterranean formation 606 with two horizontally drilled well bores 610 illustrating certain aspects.

[0290] The generally horizontal well bores 610 are drilled through the over burden formation 618 and into the hydrocarbon bearing reservoir 606 using standard directional drilling techniques. Fractures 620 may exist in the reservoir 606 and/or overburden 618. Casing 622 extends from the surface to the horizontal section of the well. Surface casing 628, which may consist of multiple concentric tubings, is installed into the vertical section of the well. The casings and tubings are connected together at surface in a wellhead 30 as is common practice. A liner 604 with a certain amount of open area is installed into each horizontal section of the well bores 610.

[0291] Completion tubing 602 is installed into each well, with two completion devices 612, one installed in the middle of the completion tubing 602 and another installed at the distal tip of the completion tubing 602.

[0292] The completion tubing may be jointed tubing or it may be coiled tubing.
The completion tubing 602 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings.

[0293] The completion tubing 602 conveys the mobilising fluids 608 from the surface to the completion devices 612 and conveys the produced fluids 616 extracted from the reservoir 606 from the completion devices 612 to surface.

[0294] Packers 656 may be installed near the heel of the well bore 610 to isolate the vertical section of the well bore from the horizontal section of the well bore.

[0295] Production tubing 624 may be installed into the vertical section of the well along with a pump 626.

[0296] Mobilising fluids 608 are injected through the completion tubing 602 and enter into the completion device 612. The mobilising fluids 608 enter into the annular space between the completion device 612 and the liner 604, and are injected into the hydrocarbon bearing reservoir 606 through the open area in the liner 604. In the reservoir 606, zones of mobilised hydrocarbons 614 are created, which consists of naturally occurring hydrocarbons and the mobilising fluids; and the products of any chemical and physical interactions which occur between them. The resulting mixture of fluids from the zone of mobilised hydrocarbons 614 flow via gravity, pressure and other means back through the liner 604 and may enter the annular space between the completion tubing 602 and liner 604. From there the produced fluids 616 are conveyed from the completion devices 612 to the heel of the well bore via the completion tubing 602. The produced fluids 616 may then be produced to surface via a pump 626 and production tubing 624 or via any other artificial or natural lift mechanism.

[0297] The zones of mobilised hydrocarbons 614 are located in the vicinity of the completion devices 612, from which mobilising fluids 608 and produced fluids are injected to and extracted from the reservoir 606.

[0298] When the hydrocarbons in the zone of mobilised hydrocarbons 614 have been produced using the completion devices 612, the location of the completion devices 612 may be moved longitudinally along the horizontal well bore 610, to enable the mobilisation of hydrocarbons from new portions of the reservoir.
The completion devices 612 may be moved into or out of the well bore by adding or removing one or more joints of tubing, when the completion tubing 602 is jointed; or by winding or unwinding the coiled tubing if the completion tubing 602 is coiled.

[0299] In an embodiment, any number of completion devices 612 may be installed on each completion tubing 602.

[0300] In an embodiment, the horizontal sections of the well bores 610, may extend from a common well head 630; i.e. the well may be classed as a multi-lateral well.

[0301] In an embodiment, any number of predominately single horizontal wells 610 may be drilled into the reservoir 606 to recover the hydrocarbons present in the reservoir.

[0302] Referring to Figure 8, there is generally depicted a hydrocarbon bearing subterranean formation 706. A generally horizontal well bore is drilled into the hydrocarbon bearing reservoir 706 using standard directional drilling techniques. A
liner 704 with a certain amount of open area is installed into the horizontal section of the well bore. As shown in Figure 8, the liner 704 may be casing secured in place by cement 762 and perforated at locations 760 after installation into the well bore.
Completion tubing 702 is installed into the well, connecting completion devices 712 that are installed along the horizontal section of the well bore. Only one completion device 712 is labelled, but it should be understood that there are multiple completion devices in a row. The completion tubing 702 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings. Production tubing 724 may be installed into the vertical section of the well along with a pump 726.
Mobilising fluids 708 are injected through the completion tubing 702 and enter into the completion device 712. Apertures 764 (one aperture shown large for example) in the completion device 712 can be opened or closed to enable the mobilising fluids to enter the reservoir 706 at discrete locations via the open area in the well liner 704.
In the reservoir 706 a zone of mobilised hydrocarbons 714 is created, which consists of naturally occurring hydrocarbons and the mobilising fluids; and the products of any physical and chemical interactions which occur between them. The resulting mixture of fluids from the mobilised zone are labelled as the produced fluids 716. The produced fluids 716 from the zone of mobilised hydrocarbons 714 flow via gravity, pressure and other means back through the liner 704 and may enter the completion device 712 through apertures 766, which may also be opened and closed as desired. The produced fluids are transported to the heel of the well and are produced to surface via the pump 726 and production tubing 724.

[0303] As shown in Figure 8, the mobilising fluids 708 can be conveyed between adjacent completion devices 712 via completion tubing, and the produced fluids can be conveyed via an annulus 768 formed between the completion devices 712.

[0304] In an embodiment, the mobilising fluids 708 and the produced fluids may be conveyed from the completion devices 712 via separate conduits in the completion tubing 702.

[0305] When the hydrocarbons in the zone of mobilised hydrocarbons 714 have been produced, the apertures 764 for the mobilising fluids 708 and apertures 766 for the produced fluids 716 may be changed by opening and closing the apertures in the completion devices 712 installed along the well bore. By opening and closing of apertures 764 and 766 in the completion devices installed along the well bore, any desired pattern for the injection of mobilising fluids 708 and production of produced fluids 716 may be realised in space and time.

[0306] In an embodiment the apertures 764 and apertures 766 may consist of a series of apertures of any desired number, size and open area.

[0307] Figure 9 shows a subsequent injection location for the mobilising fluids 808 at apertures 864, while produced fluids 816 are recovered from the reservoir via apertures 866. As can be seen in Figure 9, the mobilising fluids 808 are being injected at location that is a distance of three completion devices 812 from the injection location in Figure 8. The produced fluids 816 are produced from the original location in Figure 8 as well as via completion devices 812 at the three adjacent locations. After a portion of the hydrocarbons in the reservoir has been produced to surface, a zone of desaturated hydrocarbons 858 is formed in the reservoir 806.

[0308] As is exemplified by Figure 9, the apertures 864 and apertures 866 in each completion device 812 can be opened or closed in any configuration and in any sequence that is desired. Generally, a suitable distance will be maintained between the apertures 864 and apertures 866, such that the mobilising fluids 808 do not excessively by-pass the reservoir 806.

[0309] As has been exemplified by Figures 8 and 9, the zone of injection for the mobilising fluids 808 and the zone of production for the produced fluids 816 along the wellbore may be changed over time, such that quantity of hydrocarbon fluids produced to surface is maximised and such that the hydrocarbons remaining in the reservoir 806 is minimised.

[0310] In an embodiment, the zone of injection for the mobilising fluids 808 and the zone of production for the produced fluids 816 is moved successively along the well bore from the toe to the heel. In an embodiment, the zone of injection for the mobilising fluids 808 and the zone of production for the produced fluids 816 is moved successively along the well bore from the heel to the toe

[0311] In an embodiment the zone of production for the produced fluids 816 is expanded over time, to maximise the recovery of hydrocarbons from the well bore.

[0312] Referring to Figure 10, there is generally depicted a side view of a completion device 912 that incorporates an eccentrically arranged sliding sleeve.
The completion device 912 is generally contained in a housing 972 and may have a sealing material 970 wrapped around the housing 972. An injection sleeve 978 is arranged eccentrically within the device and is threadedly connected to completion tubings 977 and 979. The completion tubings 977 and/or 979 may incorporate expansion mechanisms (not shown), so that movement of the injection sleeve 978 and thermal and pressure expansion can be accommodated during operations.

[0313] The completion tubing 979 can comprise of a female threaded coupling 981, while completion tubing 977 can comprise of a male threaded coupling 975.

The male and female couplings on either end of the device, enable multiple completion devices 912 to be connected together during rig up of the completion assembly as it is inserted into the well bore.

[0314] Apertures 964 in the housing enable fluids from the inner annulus 982 to exit the device, while apertures 966 in the housing enable fluids from outside of the device to enter into the outer annulus 976. In an embodiment, fluids may enter or exit the device via apertures 964 and may enter or exit the device via apertures 966.

[0315] The production sleeve 974 sits concentrically inside the housing 972, while an injection sleeve 978 is arranged eccentrically within the production sleeve 974. There exists a sliding sleeve 980 with a shifting profile 984 that can be engaged by any suitable shifting tool.

[0316] For example, a common profile for engaging and moving sliding sleeves is the OTIS B profile (US Patent 4,436,152 to Fisher et al., 1984). Any suitable profile may be used for the purpose of engaging the sliding sleeve. In an embodiment, the sliding sleeve may be moved by any other means known to those skilled in the art, including dropping a ball and pressuring up the inner annulus. In an embodiment the shifting tool can be deployed on tubing, which is run into the device via coiled or jointed tubing from the wellhead.

[0317] In general, it is preferred to use a shifting tool deployed by small diameter coiled tubing, where the coiled tubing diameter is between 0.5" and 2", and more preferably between 1" and 1 3/4". This method of shifting the sliding sleeve is preferred since the location of each sleeve in each completion device 912 within the well bore can be independently set with only one run in hole operation of the shifting tool. This method also avoids placing any material in the inner annulus, such as balls, which may obstruct the flow of fluids in the annulus and require other operations, such as the use of a special fluids to dissolve the ball before enabling the full flow of fluids in the annulus 982.

[0318] The sliding sleeve device can comprise of sealing materials and springs that are placed around and between parts that move relative to one another in the device to seal pathways for fluid flow and hold the position of the parts in place, respectively. In an embodiment the sealing materials can be o-rings formed of any suitable material.

[0319] In an embodiment, parts may be machined such that channels are formed within the device for the flow of fluids to/from the annuli and the outside of the device in addition to the direct alignment of the apertures in parts of the device.

[0320] In an embodiment, the sliding sleeve 980, may be positioned within a recess formed or machined in the injection sleeve 978, so as to minimise the obstruction of the cross-sectional area for the flow of fluids through the inner annulus 982.

[0321] When the production sleeve 974 is appropriately aligned in the axial direction, the produced fluids 916 pass through apertures 966 in the housing and apertures 992 in the production sleeve to enter the outer annulus 976.
Similarly, when the sliding sleeve 980, the injection sleeve 978 and the production sleeve 974 are appropriately aligned, the mobilising fluids 908 pass from the inner annulus 982, through the apertures 986 in the sliding sleeve 980, apertures 988 in the injection sleeve 978, apertures 990 in the production sleeve and apertures 964 in the housing 972, to exit the completion device 912.

[0322] Referring to Figure 11(a)-(c), there is generally depicted cut-away views of an embodiment of a completion device that incorporates an eccentrically arranged sliding sleeve device, showing the configurations of the device. Referring to Figure 11(a), the configuration of the device is such that there can be no flow of fluids to or from the device. The production sleeve 1074 is arranged such that the apertures 1092 in the production sleeve are not aligned with the apertures 1066 in the housing 1072. The sliding sleeve 1080 is arranged so that the apertures 1086 are not aligned with the apertures 1088 in the injection sleeve 1078.

[0323] Referring to Figure 11(b), the configuration of the device is such that there can be flow of fluids to or from the inner annulus of the device only. The sliding sleeve 1080 is arranged such that the apertures 1086 are aligned with the apertures 1088 in the injection sleeve 1078, the apertures 1090 in the production sleeve and the apertures 1064 in the housing 1072. The sliding sleeve 1080 is arranged so that the apertures 1092 in the production sleeve 1074 are not aligned with the apertures 1066 in the housing 1072, thereby preventing flow of fluids to or from the outer annulus of the device.

[0324] Referring to Figure 11(c), the configuration of the device is such that there can be flow of fluids to or from the outer annulus of the device only. The sliding sleeve 1080 is arranged so that the apertures 1092 in the production sleeve are aligned with the apertures 1066 in the housing 1072, thereby allowing the flow of fluids to or from the outer annulus of the device. The sliding sleeve 1080 is arranged such that the apertures 1086 are not aligned with the apertures 1088 in the injection sleeve 1078, thereby preventing the flow of fluids to or from the inner annulus of the device.

[0325] An advantage of the eccentric design of the completion device is that the injection sleeve and production sleeve can be located adjacent to each other, avoiding a more complex design that is required if the injection sleeve was located concentrically within the device. However, a disadvantage of the eccentric design is that make-up of the entire completion assembly is more difficult on the drilling rig during run in hole operations and adjacent completion devices may need to be connected together via a completion tubing.

[0326] Another potential disadvantage of the eccentric design is that during run in hole operations, the outer diameter of the assembly varies as it passes through the well head assembly, making isolation of the reservoir from the surface more difficult.
The mobilising fluids are transported from the surface to each device via completion tubing. The produced fluids will be transported along the well bore via an annulus formed by the completion tubing connecting adjacent completion devices and the well liner.

[0327] Referring to Figure 12, there is generally depicted a view of a completion device 1112 that incorporates a concentrically arranged sliding sleeve device.
The completion device is generally contained in a housing 1172 and may have a sealing material 1170 wrapped around it. The sealing material is used to aid installation and sealing of the completion device into the well bore liner. Apertures 1164 in the housing enable fluids from the inner annulus 1182 to exit the device, while apertures 1166 in the housing 1172 enable fluids from outside of the device to enter into the outer annulus 1176.

[0328] In an embodiment, fluids may enter or exit the device via apertures and may enter or exit the device via apertures 1166.

[0329] The production sleeve 1174 sits concentrically inside the housing and is rigidly connected to the injection sleeve 1178 via a solid rib 1196.
Apertures 1192 exist within the production sleeve, while apertures 1188 exist within the injection sleeve. The solid rib 1196 which connects the injection and production sleeves together moves within a slot formed in the wall of the inner tubing 1156. In an embodiment the number of solid ribs 1196 connecting the injection and production sleeves is between one and four, and preferably at least two. There exists a shifting profile 1184 on the sliding sleeve 1180 that is connected to injection sleeve 1178 and which can be engaged by any suitable shifting tool that is run inside the inner annulus 1182 of the device. Stoppers 1158 are located on the housing to limit the travel of the production sleeve 1174.

[0330] A hollow rib 1194 connects the inner tubing 1156 with the housing and has holes 1190 which can provide a pathway from the inner annulus 1182 to the outside of the device. In an embodiment the number of hollow ribs 1194 connecting the inner tubing 1156 and the housing 1172 is between one and four, and preferably at least two. The solid ribs 1196 and hollow ribs 1194 are orientated in the azimuthal direction so as to not interfere with each other whatever the position of the sliding sleeve 1180. The production sleeve 1174 has slots for the hollow ribs 1194, so that it can move relative to the housing 1172, the hollow ribs 1194 and the inner tubing 1156 which are all connected rigidly together.

[0331] When the sliding sleeve 1180 is positioned as shown in Figure 12 (to the far right), the apertures 1188 in the injection sleeve 1178 do not align with the holes 1190 in the hollow rib 1194 and no flow is possible between the inner annulus and the outside of the device. Similarly, the apertures 1192 in the production sleeve 1174 do not align with the apertures 1166 in the housing and no flow is possible between the outer annulus 1176 and the outside of the completion device. This position of the sliding sleeve is used when installing the completion device into the well bore and when it is desired that there be no flow between the outside of the device and any of the annuli inside the device.

[0332] In an embodiment, parts of the completion device 1112, which are shown as one part, may be manufactured as two or more parts and joined together during assembly of the device. For example, the housing 1172, may consist of one, two or three machined tubings which are joined together. For example, the inner tubing 1156 may consist of more than one tubing joined together.

[0333] In an embodiment, the diameter of the housing 1172 of the completion device and the thickness of the sealing material 1170 shall be chosen to enable a snug installation into the well liner and/or well bore. Generally well liners are manufactured in common sizes, with these being between about 2" and 12"
outside diameter (OD), and more commonly between about 4" and 7" OD.

[0334] In an embodiment, the inner diameter (ID) of the inner sleeve 1178 and the design of sliding sleeve 1180, will be designed such that tools having an OD of between about 0.5" and 3.5" OD can be run through the completion device 1112.
More generally, the design of the device will enable shifting tools deployed on coiled tubing to be run into and through the device to move the sliding sleeve. The most common sizes of coiled tubing are between 1" and 3.5" OD, with coiled tubing of 1", 1.5", 1 3/4" and 2" OD being preferred for use with the completion device 1112.

[0335] Referring to Figure 13, there is generally depicted a view of a completion device 1212 that incorporates a concentrically arranged sliding sleeve device.
In Figure 13, the sliding sleeve 1280 has been positioned such that the apertures in the injection sleeve 1278 are aligned with the holes 1290 of the hollow rib 1294, thereby allowing flow of the mobilising fluids 1208 from the inner annulus 1282 of the completion device 1212 to the outside through the apertures 1264. In an embodiment, the flow may occur from the outside of the device, through apertures 1264 and holes 1290 into the inner annulus 1282 of the device. When the sliding sleeve is positioned as shown in Figure 13, the apertures 1292 in the production sleeve 1274 do not align with the apertures 1266 in the housing 1272 and no flow is possible between the outer annulus 1276 and the outside of the completion device 1212.

[0336] Referring to Figure 14, there is generally depicted a view of a completion device that incorporates a concentrically arranged sliding sleeve device. In Figure 14, the sliding sleeve 1380 has been positioned such that the apertures 1392 in the production sleeve 1374 are aligned with the apertures 1366 in the housing 1372, thereby allowing flow of produced fluids 1316 from outside of the device and into the outer annulus 1376. In an embodiment, the flow may occur from outer annulus through apertures 1392 and 1366 to the outside of the device. When the sliding sleeve 1380 is positioned as shown in Figure 14, the apertures 1388 in the injection sleeve 1378 do not align with the holes 1390 in the hollow rib 1394 and apertures 1364 in the housing and no flow is possible between the inner annulus 1382 and the outside of the completion device 1312.

[0337] In an embodiment, the injection sleeve 1378 can be modified, such that the apertures 1388 align with the holes 1390 in the hollow rib 1394 when the apertures 1392 in the production sleeve 1374 align with the apertures 1366 in the housing, thereby enabling flow to or from both the inner and outer annuli and the outside of the completion device 1312.

[0338] In an embodiment, the completion device 1312 will be in the range of from about 1 to about 10 meters long. In an embodiment, the completion device will have a length equal to commonly available jointed tubulars.

[0339] The aforementioned eccentric and concentric completion devices both enable the independent flow of two fluids to or from the reservoir as however desired during operations. Since, it is envisaged that multiple completion devices will be installed into a single well bore, the completion devices enable a large number of combination and sequences of injection and production to/from the annuli. For example, during operations all completion devices may be set to be "producers", whereby fluids enter the device through the housing and are transported via the outer annulus to the heel of the wellbore. For example, all completion devices may be set to "injectors", whereby fluids are transported from the surface via the inner annulus and are injected into the reservoir. For example, some completion devices may be set to be "injectors" and some may be set to be "producers" and the set of "injectors" and "producers" may be changed over time.

[0340] Referring to Figure 15, there is generally depicted a hydrocarbon bearing subterranean formation 1406. A generally horizontal well bore is drilled into the hydrocarbon bearing reservoir 1406 using standard directional drilling techniques. A
liner 1404 with a certain amount of open area is installed into the horizontal section of the well bore. The liner may be installed into the open bore hole or it may be secured in place with a gravel pack 1462 (as shown). Completion tubing 1402 is installed into the well, connecting completion devices 1412 that are installed along the horizontal section of the well bore. The completion tubing 1402 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings. As shown in Figure 15, the completion devices 1412 are concentric completion devices like those described in Figures 12 through 14. The completion devices 1412 may be connected together directly or may be connected via concentric tubing, which may comprise of expansion joints. Production tubing 1424 may be installed into the vertical section of the well along with a pump 1426.

[0341] Mobilising fluids 1408 are injected through the completion tubing and enter into the completion device 1412. The location of the sliding sleeve in each device determines which apertures are opened and closed. Apertures 1464 in the completion device 1412 can be opened or closed to enable the mobilising fluids 1408 to enter the reservoir 1406 at discrete locations via the open area in the well liner 1404. In the reservoir 1406 a zone of mobilised hydrocarbons 1414 is created, which consists of naturally occurring hydrocarbons and the mobilising fluids;
and the products of any physical and chemical interactions which occur between them.
The resulting mixture of fluids from the mobilised zone are labelled as the produced fluids 1416. The produced fluids 1416 from the zone of mobilised hydrocarbons 1414 flow via gravity, pressure and other means back through the liner 1404 and may enter the completion device 1412 through apertures 1466, which may also be opened and closed as desired. The produced fluids are transported to the heel of the well and are produced to surface via the pump 1426 and production tubing 1424.

[0342] As shown by the arrows in Figure 15, some of the completion devices 1412 can be set to be "injectors" (arrow shown pointing out of the device) and some of the completion devices 1412 can be set to be "producers" (allow shown flowing into the device) in such an arrangement so that the zone of mobilised hydrocarbons 1414 spans the entire length of the horizontal well bore.

[0343] In an embodiment a Cyclic Injection steam assisted gravity drainage (CI-SAGD) process can be established using a single well. Steam is used as the mobilising fluid 1408 and the reservoir 1406 consists of immobile viscous "heavy" oil at reservoir conditions, such as heavy oil or oil sands bitumen. The zone of mobilised hydrocarbons forms a steam chamber, wherein the steam injected migrates to the top of the reservoir and then condenses. The condensing steam mixes with the heavy oil in the reservoir, forming the produced fluids 1416 which drain back into the completion devices 1412 with the apertures 1466 in the open position and are produced to surface via the production tubing 1424. In order to prevent direct by-passing of the injected steam 1408 to the production annulus of the completion device 1412, an appropriate distance is maintained between adjacent "injectors" and "producers". As shown in Figure 15, every second completion device 1412 can be set to be "closed" such that there is no flow to or from either annuli of the device. In an embodiment, the apertures 1464 and apertures 1466 in each device can be positioned a suitable distance from the end of the device, such that when the devices are connected together an appropriate distance is maintained between the adjacent injection and production apertures.

[0344] In an embodiment, in order to maximise the recovery of hydrocarbons from the reservoir 1406, the completion devices 1412 which are designated as "injectors" and "producers" can be changed over time and the sequence may be repeated in time, hence the designation as a cyclic injection SAGD process (CI-SAGD).

[0345] An advantage of the present method/system over previous single well SAGD concepts reported in the literature, is that a pseudo-steady steam chamber can be generated by moving the injection and production zones in a pattern along the wellbore and then cycling this pattern over time. The prior art is limited by having fixed locations for the injection of the mobilising fluids and the production of the produced fluids, and thereby the steam chamber which develops in designs of the prior art are inherently skewed, as the injection and production zones are laterally offset from one another. In the static injection concepts disclosed in the prior art, the oil mobilised in the vicinity of the "injector" needs to travel to the "producer" to be produced to surface, which may be several tens of metres away. This reduces the oil recovery factor and reduces efficiency of the process. By moving the injection and production zones, a pseudo-steady steam chamber more similar to that developed in a conventional SAGD process with the injector located above the producer can be established. In addition, oil mobilised by the injection of steam at one time (operation as "injector"), can be produced by at a later time from the same zone (operation as "producer") by only travelling a few metres.

[0346] In an embodiment, the mobilising fluid of the CI-SAGD process can be any combination of desired mobilising fluids known in the art, including steam, solvents and non-condensable gases.

[0347] In an embodiment, when the completion devices 1412 are used for a thermal oil recovery process like the CI-SAGD process shown in Figure 15, the completion devices may be modified to thermally isolate the inner annulus from the outer annulus. Thermal isolation of the inner and outer annuli improves the thermal efficiency of the process, as the injected steam will reach the reservoir at a higher temperature and/or higher quality than it would without thermal isolation. The thermal isolation may be achieved by using suitable insulation materials and/or using vacuum insulated tubing as is well known in the art.

[0348] Referring to Figure 16, there is generally depicted two combinations and sequences of "injectors" and "producers", the patterns of which may be repeated along the length of the horizontal well bore. Figure 16(a), shows a pattern with two completion devices 1512, with one designated as "injector" 1565 and the second one designated as "producer" 1567. If the apertures in the "injector" are a sufficient distance from the apertures in the "producer" the problem of by-passing of the mobilising fluids is avoided. In the stage 1 sequence, one of the completion devices is designated as the "injector" and the other completion device is designated as the "producer". After a set time, the "injector" and "producer" are swapped to form the combination shown in stage 2. After a set time, the "injector" and "producer"
may be swapped again to form the combination in stage 1. The pattern may be repeated as required to maximise the recovery of hydrocarbons from the formation. Figure 16(b) shows a pattern with four completion devices 1512, in which one is designated an "injector" 1565, one a "producer" 1567 and the remaining two are "closed". In this pattern there exists a "closed" completion device between adjacent "injectors"
and "producers". The completion device designated as the "injector" and the completion device designated as the "producer" is changed at each stage as shown in Figure 16(b). A total of four stages is required before the pattern of injectors and producers is repeated. The pattern of completion devices shown in Figure 15 is the same as stage 1 of Figure 16(b), i.e. it is the first stage of the pattern shown in Figure 16(b).

[0349] In an embodiment the set of completion devices in a well bore may be arranged to form any desired combination of "injectors" and "producers", and further the arrangement may be changed to form any other desired combination in any sequence in time. A major advantage of the present method/system is the flexibility provided by the completion devices to form arrangements of "injectors" and "producers" along the well bore.
WELL PAIR

[0350] Referring to Figure 17, there is generally depicted a hydrocarbon bearing subterranean formation 1606 with two horizontally drilled well bores 1610 illustrating certain embodiments. Casing 1622 extends from the surface to the horizontal section of the well. Surface casing 1628, which may consist of multiple concentric tubings, is installed into the vertical section of the well. A liner 1604 with a certain amount of open area is installed into each horizontal section of the well bores 1610.

[0351] The first well can be called the injection well 1668. The second well can be called the production well 1670.

[0352] Injection tubing 1658 in the form of a completion assembly is installed into the injection well 1668, with two injection devices 1660 (completion devices), one installed in the middle of the injection tubing 1658 and another installed at the distal tip of the injection tubing 1658. The injection tubing 1658 may be jointed tubing or it may be coiled tubing. The injection tubing 1658 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings. The injection tubing 1658 conveys the mobilising fluids 1608 from the surface to the injection devices 1660.

[0353] Mobilising fluid(s) 1608 are injected through the injection tubing 1658 and enter into the injection device 1660. The mobilising fluids 1608 enter into the annular space between the injection device 1660 and the liner 1604, and are injected into the hydrocarbon bearing reservoir 1606 through the open area in the liner 1604.

[0354] Packers 1656 may be used in the injection and/or production wells to isolate the horizontal section from the vertical section of the wells.

[0355] In an embodiment the mobilising fluids 1608 may include a primary mobilising fluid and a secondary mobilising fluid that are injected into different regions of the reservoir 1606 using the injection device 1660 and injection tubing 1658.

[0356] In the reservoir 1606, one or more zones of mobilised hydrocarbons are created, each of which consists of naturally occurring hydrocarbons and the mobilising fluids; and the products of any chemical and physical interactions which occur between them. The zone of mobilised hydrocarbons 1614 may form one or more relatively permeable connections between the injection well 1668 and the production well 1670.

[0357] The mixture of fluids 1662 from the zones of mobilised hydrocarbons flow via gravity, pressure and other means through the liner 1604 in the production well 1670 and may enter the annular space between the production device 1664 and liner 1604. From there the produced fluids 1616 are conveyed from the production device 1664 to the surface via the production tubing 1666.

[0358] In an embodiment the produced fluids may be produced to the heel of the well bore via the production tubing 1666. The produced fluids 1616 may then be produced to surface via a pump and production tubing or via an artificial lift mechanism.

[0359] To recover all of the hydrocarbons in the vicinity of the injection and production wells, the injection devices 1660 and production devices 1664 may be moved longitudinally along the horizontal well bores 1610 and 1670, to enable the mobilisation of hydrocarbons from new portions of the reservoir

[0360] The injection devices 1660 and production devices 1664 may be moved into or out of the well bores by adding or removing one or more joints of tubing, when the tubing is jointed; or by winding or unwinding the coiled tubing when the tubing is coiled.

[0361] Generally, the injection devices 1660 and production devices 1664 will be moved in unison into or out of the well bores; so that the zones of mobilised hydrocarbons formed between them will be "swept" in unison through the reservoir.

[0362] To recover all of the hydrocarbons in the vicinity of the injection and production wells the injection and production devices may be swept along the full length of the horizontal section of each well bore.

[0363] In an embodiment, the injection devices 1660 and production devices 1664 may be fixed in place and apertures in the devices may be opened and closed in sequence, by manipulating sliding sleeve devices within them, in order that the zones of mobilised hydrocarbons formed between the two wells will be swept through the reservoir.

[0364] In an embodiment, the injection tubing 1658 may be installed in the well bore 1610 from the beginning of the injection of mobilising fluids 1608 into the reservoir 1606.

[0365] It is generally recognized that the hydrocarbon recovery factor is maximized by using injection and production wells during enhanced oil recovery operations; however, in some cases, overlapping zones of mobilised hydrocarbons are required to be established before injection from one well and production from another can occur. For example, in heavy oil recovery using SAGD a zone of mobile hydrocarbons should be present between the upper injection and lower production well before steam injection into the reservoir is attempted

[0366] In an embodiment the horizontal wells may be arranged in any pattern.
For example, the injection well 1658 may be placed at a higher or lower elevation in the reservoir 1606 than the production well 1670.

[0367] In an embodiment, the production well 1670 may be placed down-dip of the injection well 1668 in the reservoir 1606.

[0368] Referring to Figure 18, there is generally depicted a hydrocarbon bearing subterranean formation 1706 with two horizontally drilled well bores 1710 illustrating certain embodiments.

[0369] The generally horizontal well bores 1710 are drilled through the over burden formation 1718 and into the hydrocarbon bearing reservoir 1706 using standard directional drilling techniques. Casing 1722 extends from the surface to the horizontal section of the well. Surface casing 1728, which may consist of multiple concentric tubings, is installed into the vertical section of the well. A
liner 1704 with a certain amount of open area is installed into each horizontal section of the well bores 1710.

[0370] One of the wells is called the injection well 1768. The other well is called the production well 1770.

[0371] Injection tubing 1758 is installed into the injection well 1768, with two injection devices 1760, one installed in the middle of the injection tubing 1758 and another installed at the distal tip of the injection tubing 1775.

[0372] The injection tubing 1758 may be jointed tubing or it may be coiled tubing.
The injection tubing 1758 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings.

[0373] The injection tubing 1758 conveys the mobilising fluids 1708 from the surface to the injection devices 1760.

[0374] Mobilising fluids 1708 are injected through the injection tubing 1758 and enter into the injection device 1760. The mobilising fluids 1708 enter into the annular space between the injection device 1712 and the liner 1704, and are injected into the hydrocarbon bearing reservoir 1706 through the open area in the liner 1704.

[0375] In an embodiment the mobilising fluids 1708 may include a primary mobilising fluid and a secondary mobilising fluid that are injected into different regions of the reservoir 806 using the injection device 1760 and injection tubing 1758.

[0376] In the reservoir 1706, one or more zones of mobilised hydrocarbons are created, each of which consists of naturally occurring hydrocarbons and the mobilising fluids; and the products of any chemical and physical interactions which occur between them. The zone of mobilised hydrocarbons 1714 may form one or more relatively permeable connections between the injection well 1768 and the production well 1770.

[0377] The mixture of fluids 1762 from the zones of mobilised hydrocarbons flow via gravity, pressure and other means through the liner 1704 in the production well 1770. From there the produced fluids 1716 are produced to surface via production tubing 1724 and a pump.

[0378] To recover all of the hydrocarbons in the vicinity of the injection and production wells, the injection devices 1760 may be moved longitudinally along the horizontal well bore 1710, to enable the mobilisation of hydrocarbons from new portions of the reservoir.

[0379] The injection devices 1760 may be moved into or out of the well bores by adding or removing one or more joints of tubing, when the tubing is jointed;
or by winding or unwinding the coiled tubing when the tubing is coiled.

[0380] To recover all of the hydrocarbons in the vicinity of the injection and production wells the injection devices may be swept along the full length of the horizontal section of each well bore.

[0381] In an embodiment, the injection devices 1760 may be fixed in place, and apertures in the devices may be opened and closed in sequence, by manipulating sliding sleeve devices within them, in order that the zones of mobilised hydrocarbons formed between the two wells will be swept through the reservoir.

[0382] In an embodiment, the injection tubing 1758 may be installed in the well bore 1710 from the beginning of the injection of mobilising fluids 1708 into the reservoir 1706

[0383] In an embodiment, an oblique front of mobilised fluids may be formed between the injection well and the production well, due to the movement of the injection zone in the injection well. By oblique it is meant that the gradient of the mobilised fluid is offset from a perpendicular angle with respect to the well bore. The oblique nature of the front is shown schematically in the Figures. It should be understood that if a trend line were drawn through the front, the trend line would be at an oblique angle with respect to the well bore. In embodiment, the oblique angle can be in the range of from 95 to 150 degrees, such as at least about 110, 120, 130 or 140 degrees. The obliqueness of the angle can be changed by changing the rate and the location of the injection relative to the rate and location of production.

[0384] There are several advantages of generating an oblique front between the injection and production wells. Firstly, an obliquely orientated front of mobilised hydrocarbons is larger than a front substantially perpendicular to the wells.
Thus, the injectivity of the mobilising fluids may be greater when an oblique front has developed between the wells due to the movement of the injection zone.

[0385] Secondly, the by-passing of the mobilising fluids through the reservoir is influenced by the orientation of the front of mobilised fluids in relation to fractures or permeable pathways within the reservoir.

[0386] It is often difficult to establish a front of mobilising fluids perpendicular to a fracture or other high permeability zone, because the mobilising fluids will naturally want to flow through the fracture in preference to flowing through the matrix of the reservoir.

[0387] Therefore, if there are any zones of high permeability between the injection and production wells, it can be difficult to establish a continuous front of mobilising fluids between the wells and recover a majority of the hydrocarbons in the reservoir. In severe cases, the mobilising fluid will tend to flow through the high permeability pathways and by-pass large regions of the reservoir resulting in poor recovery of the hydrocarbons and/or poor utilisation of the mobilising fluid

[0388] As is shown in several of the examples provided in this specification, by moving the injection zone along the axis of the horizontal section of the injection well, the recovery of hydrocarbons can be improved if fractures are present in the reservoir.

[0389] In an embodiment the horizontal wells may be arranged in any pattern in the formation.

[0390] Referring to Figure 19, which shows an embodiment for the injection device 1860 using a concentric tubing string arrangement, which enables the injection of a primary mobilising fluid 1808 and a secondary mobilising fluid 1850.

[0391] A generally horizontal well bore 1810 is drilled into the hydrocarbon bearing reservoir 1806 using standard directional drilling techniques. A liner with a certain amount of open area is installed into the well bore 1810. The injection device 1860 uses a concentric tubing arrangement.

[0392] Primary mobilising fluids 1808 are injected through the inner tubing of the concentric tubing of the injection device 1860. The primary mobilising fluids 1808 exit from apertures 1842 into the annulus between the injection device 1860 and the liner 1804. The primary mobilising fluids 1808 are injected into the hydrocarbon bearing reservoir 1806 through the open area in the liner 1804.

[0393] The liner may have any arrangement of open area, including slots, holes, or permeable meshes, such as wire wraps, installed in any manner. In many applications, liners 1804, have slots 1844 manufactured into them.

[0394] Secondary mobilising fluids 1850 are injected through the annulus formed between the outer and inner tubings and exit from apertures 1846 into the annulus between the injection device 1860 and the liner 1804. The secondary mobilising fluids 1850 are injected into the hydrocarbon bearing reservoir through the open area in the liner 1804.

[0395] In the reservoir 1806 a zone of mobilised hydrocarbons is created, which consists of naturally occurring hydrocarbons and the primary and secondary mobilising fluids; and the products of any chemical and physical interactions which occur between them.

[0396] In order to ensure that the primary mobilising fluids 1808 and secondary mobilising fluids 1850 are injected into the appropriate regions of the reservoir 1806, sealing devices 1840 are installed to form a seal between the injection device and the liner 1804 and to isolate the injection regions of the primary mobilising fluid 1808 and the secondary mobilising fluids 1850.

[0397] In an embodiment the configuration of the tubings may be reversed;
so that primary mobilising fluids 1808 are injected into annulus 1848 formed between the inner and outer tubing of the injection device 1860 and the secondary mobilising fluids 1850 are injected into the inner tubing of the injection device 960.

[0398] The operation of the injection device 1860, enables the formation of a zone of mobilised hydrocarbons from the injection of the secondary mobilisation fluid 1850, which is subsequently contacted with the primary mobilising fluid 1808, when the injection device 1860 is moved out of the well bore 1810; or which enables the formation of a zone of mobilised hydrocarbons from the injection of the primary mobilising fluid 1808, which is subsequently contacted with the secondary mobilising fluid 1850, when the injection device 1860 is moved into the well bore 1810.

[0399] In an embodiment the injection device 1860 is moved such that adjacent zones of mobilised hydrocarbons overlap.

[0400] In an embodiment the injection device 1860 is moved a distance equal to the distance between adjacent sealing devices 1840. In an embodiment the injection device 1860 is moved a distance equal to the distance between the apertures and the apertures 1846.

[0401] In an embodiment the primary mobilising fluid 1808 or secondary mobilising fluid 1850 may contain a fluid or solid mobilising catalyst. In an embodiment the mobilising catalyst may be a nanoparticle.

[0402] In an embodiment the primary mobilising fluid 1808 is an oxidant and the secondary mobilising fluid 1850 is water or steam.

[0403] In an embodiment, catalysts may be injected with the primary mobilising fluid 1808, the secondary mobilising fluid 1850 or both fluids.

[0404] An advantage of using two mobilising fluids is that one of the mobilising fluids may be used to inject a catalyst material, in the form of a fluid and/or solid, into the reservoir that can catalyse the reaction between the other mobilising fluid and the naturally occurring hydrocarbons. For example, catalysts may be mixed with the secondary mobilising fluid 1850 or may be mixed with the primary mobilising fluid 1808.

[0405] An advantage of some embodiments is that by moving the injection point for the mobilising fluids through the reservoir there can be much greater control over the rate and flux of the injected mobilising fluids in the first place.
Secondly, by injecting catalysts with the secondary mobilising fluid 1850, a zone of mobilised hydrocarbons and the catalyst can be created in the reservoir; which is subsequently contacted with the primary mobilising fluid 1808 as the injection device 1860 is moved through the reservoir, thereby creating the optimal conditions for the catalyst to improve the properties of the hydrocarbons in the reservoir.

[0406] In an embodiment, any number of mobilising fluids may be injected into the reservoir 1806 via the injection device 1860.

EXAMPLES

[0407] Examples of embodiments of the invention and other embodiments are now described which are exemplary only and non-limiting.
Example 1: Single point Moving Injection Combustion Stimulation (MICS)

[0408] This example was prepared using computer simulations of the recovery process using the STARSTm Thermal Simulator general issue 2018, provided by Computer Modelling Group of Calgary, Alberta, Canada.

[0409] The simulations were made with a set of simplified components, and reactions to represent the key features of the combustion of heavy oil. In the simulations the heavy oil is modelled as being composed of the pseudo-components:
maltenes and asphaltenes. The reaction scheme and stoichiometric parameters are provided in Table 1 and are derived from the work of Be!grave et al. (J. D. M.

Be!grave, R. G. Moore, M. G. Ursenbach and D. W. Bennion, "Comprehensive Approach to In-Situ Combustion Modeling", Society of Petroleum Engineers, SPE
Paper 20250, 1993). Table 2 provides the kinetic parameters for each reaction assuming a first order reaction rate, r = A exp( -E / RT ) C, where A is the pre-exponential factor (variable units), E is the activation energy (J/mol), R is the gas constant (= 8.314 x 103 J/mol-K) and T is the temperature (K) and C is the concentration of the reactant. Table 3 provides parameters for the reservoir.
Table 1 Reaction Scheme and Stoichiometry for Heavy Oil Combustion Reaction Reaction Stoichiometry Description 1 Thermal cracking Maltenes 4 0.372 Asphaltenes 2 Thermal cracking Asphaltenes 4 83.206 Coke 3 Low Temperature Maltenes + 3.431 02 4 0.4737 Asphaltenes Oxidation 4 Low Temperature Asphaltenes + 7.513 02 4 101.559 Coke Oxidation High Temperature Coke + 1.230 02 4 0.8968 CO2 + 0.1 N2 CO +
Oxidation 0.565 H20 Table 2 Reaction Kinetics for Heavy Oil Combustion Reaction Pre-Exponential Units Activation Heat of Reaction Factor A Energy E (J/mol) (J/mol) 1 4.05 x 101 day-1 1.16x 106 0 2 1.82 x 104 day-1 4.02 x 104 0 3 2.12 x 105 day-i kpa-o 4246 4.61 x 104 1.30 x 106 4 1.09 x 105 day-1kPa-4 7627 3.31 x 104 2.86 x 106 5 3.88 x 100 day-1kPa-1 8.21 x 102 4.95 x 105 Table 3 Reservoir Parameters Parameter Units Value Porosity % 32 Permeability lateral (X, Y) mD 4000 Permeability vertical (Z), assumed 75% of lateral permeability mD 3000 Reservoir Temperature C 29 Reservoir Pressure kPag 3750 Oil gravity @ 15.6 C API 10.5 Oil density kg/m3 996.5 Oil viscosity at 20 C cP
62,743 Oil saturation % 80 Water saturation % 20 Assumed auto-ignition temperature C >180

[0410] The rate of heavy oil production and cumulative oil recovery using a method for recovering petroleum from a hydrocarbon-bearing subterranean formation in accordance with an embodiment has been modelled in computer simulations. Model parameters are shown in Table 4, below.
Table 4 Computer simulation parameters Parameter Units Value Top of oil reservoir m 760 Bottom of oil reservoir m 775 Oil reservoir thickness m 15 Top of oil reservoir pressure KPag 3,750 Bottom of oil reservoir pressure KPag 4,043 Injection/production well, height above bottom of reservoir m 3.75 Pay thickness of reservoir above Injection/Production well m 11.25 Injection/Production well horizontal length m 92 Oxidant - Air Oxidant injection rate Sm3/day 6,000 Oxidant injection temperature C 25 Injection zone length m 4 Injection zone rate of movement m/day 0.0667 Initial oxidant injection pressure KPag 6,000 Production zone distance from end of injection zone m 24

[0411] The simulation is of the Moving Injection Combustion Stimulation (MICS) process which uses a single horizontal well bore and a single point injection of oxidant into the reservoir and a single production zone, in a configuration similar to Figure 9. The computational domain is 100 m (axially) x 15 m (vertically) x 25 m (laterally). The computational domain is symmetric and represents one-half of the actual domain penetrated by the well. The reported data is for the full domain, i.e. for lateral extent of 50 m, 25 m on either side of the well's centreline.

[0412] The horizontal well is located 3.75 m from the bottom of the reservoir, which is 15 m thick thereby providing 11.25 m of net pay. The reservoir is of heavy oil with an initial oil saturation of 80% and an initial water saturation of 20%. The thermophysical parameters of the heavy oil are typical of reservoirs that may are found in Alberta and Saskatchewan in Canada.

[0413] The oxidant is initially injected at a location 62 m from the heel of the well bore, from a zone of 4 m in length. The production zone is initially located at a location 88 m from the heel of the well and runs until the end of the well bore which has a total length of 92 m. The oxidant, air, is injected at an average rate of 6,000 5m3/day. After a short initial ramp up phase, the start of the injection and production zones are retracted at a rate of 4 m every 60 days, or at an average rate of 0.0667 m/day. The length of the production zone is increased as the injection zone moves closer towards the heel of the well bore, so that heated oil can drain into the production annulus and be produced to surface. A fixed distance of 24 m exists between the injection zone and the production zone throughout the simulation.

[0414] Figure 20(a) shows the injection and production configuration in the well bore 1910 and the temperature profile cross-section in the reservoir 1906 on day 396 of the simulation. At this time, the oxidant 1908 is injected into the reservoir at a position 54 m from the heel of the well bore, and the produced fluids 1916 are recovered from a zone near the toe of the well bore. The reaction of the oxidant 1908 with the hydrocarbons in the reservoir 1906, generates a combustion zone 1921 located above the well bore with a temperature of over 400 C, A zone 1922 exists around the combustion zone where the temperature is between 300 and 400 C.
Similarly a lower temperature zone 1923 exists where temperatures are between 200 and 300 C. An evaporation zone 1924 exists around the combustion process where temperatures vary between 100 and 200 C and where water originally present in the reservoir 1906 can be turned to steam. The reservoir 1906 has a temperature below 100 C and generally close to the initial temperature of 29 C..

[0415] Figure 20(b) shows the well configuration and temperature contours in the reservoir at day 762 of the simulation. At this time the oxidant 1908 is injected at a position 32 m from the heel of the well and the production zone extends for 30 m from the toe of the well bore 1910. It can be seen that the combustion zone remains located close to and above where the oxidant 1908 is injected into the reservoir, while the other zones 1922, 1923 and 1924 have expanded in size.

[0416] Figure 20(c) shows the well configuration and temperature contours in the reservoir at day 1157 of the simulation, when the injection zone is close to the heel of the well bore. The combustion zone 1921 remains close to and above the region of oxidant injection, while the temperature along the well bore where produced fluids 1916 are collected varies from about 300 to 100 C, ensuring a low viscosity of the heavy oil in the region of the production zone.

[0417] The original oil in place for the domain is 19,200 m3. The produced oil rate averages 4.22 m3/day with a maximum of 35.64 m3/day. Over the period of 1765 days, the cumulative oil production to surface is 6,262 m3 yielding an oil recovery factor of 32.6%. A further 1,180 m3 of oil is consumed in the process representing 6.1% of the original oil in place. Table 5 shows a summary of the simulation results.

[0418] The average AOR of the MICS process is estimated to be about 1400 m3/m3 which is within the economically feasible range (G. Perkins, "Mathematical modelling of in situ combustion and gasification", Proc. IMechE, Part A:
Journal of Power and Energy, v323, n1, pp56-73, 2017). Also, the simulations show no or limited breakthrough of oxygen to the production zone during the moving injection process. In the simulations the horizontal well has been placed 3.75 m from the bottom of the reservoir. If the well was instead located at 1 m from the bottom, it is estimated that the oil recovery factor would increase to over 40 %.
Table 5 Computer simulation results Parameter Units Value Original oil in place m3 19,200 Total simulation time days 1,765 Air injection rate Sm3/day 6,000 Average oil production rate m3/day 4.22 Average air oil ratio m3/m3 1,423 Oil produced to surface m3 6,262 Oil recovery factor % 32.6 Example 2: Two point Moving Injection Combustion Stimulation (MICS)

[0419] This example was prepared using computer simulations of the recovery process using the STARSTm Thermal Simulator general issue 2018, provided by Computer Modelling Group of Calgary, Alberta, Canada.

[0420] The simulations were made with the same set of components, reactions and reservoir properties as used in Example 1. The simulation is of the two point Moving Injection Combustion Stimulation (MICS) process which uses a single horizontal well bore with two injection zones for the oxidant and two production zones for the produced fluids. The computational domain is 200 m (axially) x 15 m (vertically) x 25 m (laterally). The simulation domain is symmetric and one-half of what an actual well would encounter, while the reported data is for the full well model. The horizontal well is located 3.75 m from the bottom of the reservoir, which is 15 m thick thereby providing 11.25 m of net pay.

[0421] The oxidant is initially injected at two locations, one 62 m and another at 162 m from the heel of the well, with each zone being 4 m in length. The two production zones are initially located at 88 m and 188 m from the heel of the well and are initially 4 m in length also. The oxidant, air, is injected at a maximum rate of 12,000 Sm3/day. After a short initial ramp up phase, the start of the injection and production zones are retracted at a rate of 4 m every 60 days, or at an average rate of 0.0667 m/day. The length of each production zone is increased as the injection zones moves closer towards the heel of the well bore. A fixed distance of 24 m exists between adjacent injection zone and production zones.

[0422] Figure 21 shows the configuration of the injection and production zones along the horizontal well bore 2010 and contours of temperature in the reservoir 2006 on days: (a) 396, (b) 762 and (c) 1157. The behaviour of the process is the similar to that shown for the single injection point in Example 1, albeit with two injection zones, and two corresponding zones of mobilised fluids in the reservoir and two production zones in the well bore. The combustion zones 2021 are regions of high temperature where the oxidant reacts with the hydrocarbons in the reservoir to generate heat. Lower temperature zones 2022, 2023 and 2024 exist around each combustion 2021 and reduce the viscosity of the oil enabling it to flow as produced fluids 2016 into the well bore. The individual injection and production zones can be designed to operate independently of each other, by ensuring that the oxidant is distributed equally between the two injection zones.

[0423] The original oil in place for the reservoir domain is 38,400 m3. The produced oil rate averages 8.6 m3/day. Over the period of 1765 days, the cumulative oil production to surface is 12,841 m3 yielding an oil recovery factor of 33.4 A) vs 32.6 A) for the single point simulation. Table 6 shows a summary of the simulation results. It can be seen that the production results for the two point MICS
configuration are double that of the single point simulation. Thus, the single point and two point MICS simulations can be considered representative of 100 m and 200 m long sections of the reservoir, respectively.

[0424] A typical horizontal well can be 1,000 m in length. By adding more injection and production zones the oil in place can be produced more quickly.
Table 6 also shows data scaled from the single point simulation for a 1000 m section of the reservoir with a MICS well configured hypothetically for five point and ten point injection. With five injection and production zones, the average oil production will be 20.1 m3/day over 3,530 days, while with ten injection and production zones the average oil production will be 40.2 m3/day over 1,765 days. The total oil produced from a 1000 m well is 62,620 m3 or approximately 393,000 barrels of oil.
Table 6 Computer simulation results Parameter Units Single Two Five Ten point point point point MICS MICS MICS MICS
Axial length of domain m 100 200 1000 1000 Original oil in place m3 19,200 38,400 192,000 192,000 Total simulation time days 1,765 1,765 3,530 1,765 Air injection rate Sm3/day 6,000 12,000 30,000 60,000 Average oil production rate m3/day 4.2 8.6 20.1 40.2 Average air oil ratio m3/m3 1,423 1,408 1,423 1,423 Oil produced to surface m3 6,262 12,841 62,620 62,620 Oil recovery factor % 32.6 33.4 32.6 32.6 Example 3: Single well Steam Assisted Gravity Drainage processes

[0425] This example has been prepared using computer simulations of the recovery process using the STARSTm Thermal Simulator general issue 2018, provided by Computer Modelling Group of Calgary, Alberta, Canada.

[0426] The thermo-physical properties of the heavy oil and properties of the reservoir are taken from the work of Zhao et al. (D. W. Zhao, J. Wang and I.
D.
Gates, "Thermal recovery strategies for thin heavy oil reservoirs", Fuel, v117, pp431-441, 2014). Table 7 provides a summary of the main parameters used.

Table 7 Reservoir Parameters Parameter Units Value Porosity % 0.32 Permeability lateral (X, Y) mD 3650 Permeability vertical (Z), assumed 80% of lateral permeability mD 2920 Reservoir Pressure kPag 2800 Dead oil viscosity at 20 C
20 C cP
15,212 40 C cP 1884 80 C cP
125.4 160 C cP 9.66 250 C cP 3.09 Oil saturation % 65 Water saturation % 35

[0427] The computational domain is 80 m (axially) x 10 m (vertically) x 50 m (laterally) and represents a small section of the reservoir. The lateral sides of the computational domain are modelled with symmetry boundary conditions. The 80 m axial section represents a portion of a typical horizontal well which may be over 1000 m in length. The lateral extent of 50 m assumes that the adjacent well bores are spaced 100 m apart on a repeating pattern in the reservoir. Table 8 shows the main computer simulation parameters.
Table 8 Computer simulation parameters Parameter Units Value Depth to top of oil reservoir m 334 Depth to bottom of oil reservoir m 344 Oil reservoir thickness m 10 Length of reservoir m 80 Lateral extent of reservoir m 50 Injection/production well, height above bottom of reservoir m 1.5 Pay thickness of reservoir above Injection/Production well m 8.5 Injection/Production well horizontal length m 80 Steam injection pressure kPag 4000 Steam injection rate m3/day 16.67 (max) Production pressure kPag 500 Maximum steam production m3/day 0.133 (max)

[0428] Simulations are made of a Moving Injection SAGD (MI-SAGD) process and a Cyclic Injection SAGD (CI-SAGD) process which are both embodiments of the present method and system and which both use a single horizontal well bore.
The MI-SAGD process in this example has a well configuration like that of Example with steam being used as the mobilising fluid. The steam injection zone is moved along the horizontal well bore and the production zone is expanded as the reservoir is swept of oil as in Example 1. The CI-SAGD process uses a pattern of injection and production zones in the well bore which is cycled in time to establish the development of a pseudo steady steam chamber around the well bore. The MI-SAGD and CI-SAGD simulation results are compared with a conventional SAGD
dual well configuration in which an injection well is located several metres above the production well. Table 9 provides details of the well configurations used for the simulations. For the CI-SAGD process the steam is injected as per the regular pattern given by Figure 16(b), with a 3 month duration for each stage, and 4 stages for the cycle, yielding a cycle time of 12 months.
Table 9 Well configurations Cyclic Moving Injection Injection Dual well Parameter Units SAGD SAGD SAGD
Injection zone length m 10 5 80 Production zone length m 10 varies 80 Lateral distance between injection and production zones m 20 10 n/a Stage time months 3 n/a n/a Cycle time months 12 n/a n/a Injection zone movement m/day n/a 0.033 n/a Injection well position from bottom of reservoir m 1.5 1.5 5.5 Production well position from bottom of reservoir m 1.5 1.5 1.5

[0429] Table 10 shows the results of the simulations, compared after a period of 4 years of operation. The resultant steam oil ratios at this time approximately correspond to the economic cut-off for operations of SAGD in thicker reservoirs. It can be seen that the conventional dual well SAGD process has a recovery factor of 62.2 % and a cumulative steam oil ratio (cSOR) of 5.6 m3/m3, while at the same time the MI-SAGD process has a recovery factor of 53.4 % and a cumulative steam oil ratio (cSOR) of 6.4 m3/m3. The lower performance of the MI-SAGD process is due to the fact that the steam chamber is not pseudo-steady and thus there is a relatively larger heat loss area per unit of production. The CI-SAGD process has marginally better performance than the dual well SAGD with a recovery factor of 62.3 %
and a cSOR of 5.5 m3/m3. The CI-SAGD process of the current method thus achieves equivalent performance to the dual well SAGD but has the advantage that only a single well bore is drilled into the formation. This can make it cheaper and easier to drill and complete, especially in thin seams, than the dual well design.

Table 10 Computer simulation results Cyclic Moving Injection Injection Dual well Parameter Units SAGD SAGD SAGD
Total simulation time days 1460 1460 1460 Average steam injection rate m3/day 589 584 589 Average oil production rate m3/day 106 91 106 Cumulative steam oil ratio m3/m3 5.5 6.4 5.6 Oil produced to surface m3 155,060 133,358 154,865 Oil recovery factor % 62.3 53.4 62.2 Example 4: Moving Injection Waterflood Enhanced Oil Recovery in a Fractured Reservoir (MI-E0R)

[0430] This example has been prepared using computer simulations of the recovery process using the MATLAB Reservoir Simulation Toolbox (MRST) Version 2017, developed in part by Sintef of Norway (K-A. Lie, An introduction to reservoir simulation using MATLAB/GNU Octave: User guide for the MATLAB Reservoir Simulation Toolbox (MRST). Cambridge University Press, 2019, ISBN
9781108492430).

[0431] The simulations have been made using a three phase black oil model.
The reservoir is a light oil with an initial oil saturation of 80 A) and an initial water saturation of 20 %. The reservoir rock has a porosity of 30 A) and a permeability of 1000 millidarcy. The oil density is 700 kg/m3 with a viscosity of 5 centipoise (cp), while the water density is 1000 kg/m3 with a viscosity of 1 cp at the reference conditions of 100 bara and 20 C. The gas phase is not present and models for dissolved gas and vaporised oil are turned off.

[0432] The computational domain is 500 m (axially) x 100 m (vertically) x 200 m (laterally) and represented with 50 x 10 x 20 cells (i.e. cells of 10 x 10 x 10 m3). A
horizontal injection well of 500 m length is positioned on one side and at the bottom of the reservoir. A horizontal production well of 500 m is positioned on the other side and at the top of the reservoir and operates at a production pressure of 50 bara.
Each horizontal well has a diameter of 0.2 m. Figure 22 shows the reservoir domain and horizontal wells.

[0433] The pore volume of the reservoir is 3,000,000 m3 while the original oil in place for the reservoir domain is 2,400,000 m3 (without fractures). Over a period of 3650 days (10 years) a total of 5 reservoir pore volumes of water are injected into the reservoir.

[0434] The fractures have a porosity of 80 A) and a permeability of 10,000 darcy.
The position of horizontal fractures, which bisect the entire reservoir, are generated randomly during each computer simulation. The computer simulations have been conducted with 0, 5, 10 and 20 fractures. Figure 22(a) shows a schematic of the reservoir computational domain 2106, the location of the injection well 2110 and the production well 2111 and the location of fractures 2120, for the case of 5 fractures.

[0435] The water is injected in two configuration modes. In the static configuration, the water is injected along the entire horizontal well bore throughout the entire simulation. In the moving injection configuration, the water is injected across a 50 m zone of the well bore and the position of this injection zone is moved from the toe of the well to the heel of the well over the simulation period.
The moving injection zone can be achieved using embodiments of the present disclosure. It should be noted that the total volume of water injected in all cases has been kept constant.

[0436] Table 6 shows a summary of the simulation results. It can be seen that in a homogeneous reservoir, with 0 fractures, that the static and moving injection configurations yield similar results for the total oil and water produced, the produced water/oil ratio and the oil recovery factor. In the homogenous case, the oil recovery factor is 78 ¨ 79 A) for both configurations. As the reservoir becomes more and more fractured, the performance of the static injection configuration deteriorates significantly, while the performance of the moving injection configuration deteriorates to a much lower degree. For example, in the presence of 10 fractures, the oil recovery factor for the static injection configuration is 49.7 A) versus 62.1 A) for the moving injection configuration. Similarly, with 20 fractures the oil recovery for the static configuration is only 31.7 A) compared with 61.7 A) for the moving injection configuration. Therefore, the moving injection configuration outperforms the static injection configuration in a fractured reservoir, where the fractures are predominately orientated perpendicular to the wells.

[0437] Figure 22(b)-(c) shows the oil saturation at the end of 10 years of waterflooding operations. The zone 2131 is largely swept of oil and contains mostly water, while zone 2132 has a high degree of oil remaining, notably 20-50%.
Zone 2133 has a low oil saturation <20%, while zone 2134 is essentially just water.
It can be seen, that in the case of the static configuration, shown in Figure 22(b) that large volumes of oil remain unrecovered between the fractures in zone 2132 because the water flows preferentially through the high permeability fractures forming zone 2131.
In contrast, the contours of oil saturation for the moving injection case, Figure 22(c), shows a lower average and lower variability in oil saturation, which translates into higher oil recovery. In particular, the zone 2134 of low oil saturation extends over a larger zone which penetrates more deeply into the reservoir between the wells.

Zones of high oil saturation 2132 are restricted to ends of the reservoir which are influenced by the start-up and shut-down procedure of the moving injection configuration.

[0438] It can be observed from the data that the moving injection configuration positively limits the degree of water by-passing through the fractures.
Table 11 Computer simulation results.
Number of Horizontal Fractures Parameter Units Static injection configuration Total oil produced m3 1,916,273 1,586,886 1,195,082 763,045 Total water produced m3 13,083,953 13,429,502 13,837,498 14,310,752 Produced water/oil ratio 6.8 8.5 11.6 18.7 Oil recovery factor % 79.8 66.1 49.7 31.7 Moving injection configuration Total oil produced m3 1,883,401 1,618,872 1,493,187 1,485,931 Total water produced m3 13,116,836 13,397,499 13,539,248 13,578,516 Produced water/oil ratio 7.0 8.3 9.1 9.1 Oil recovery factor % 78.5 67.4 62.1 61.7 Example 5: Moving Injection Waterflood Enhanced Oil Recovery in Multiply Fractured Reservoirs (MI-E0R)

[0439] The simulations were made using the same reservoir model as described for Example 4. In this example, fractures are orientated perpendicular and parallel to the horizontal well bores and the size and orientation of each fracture are generated randomly within pre-determined bounds during each computer simulation. The fractures may intersect with one another, and hence create complex fluid flow pathways within the reservoir and potentially between the injection and production wells. The computer simulations have been conducted with a total of 6, 12, 18 and 23 fractures.

[0440] The water is injected in two configuration modes as in Example 4. In the static configuration, the water is injected along the entire horizontal well bore throughout the entire simulation. In the moving injection configuration, the water is injected across a 50 m zone of the well bore and the position of this injection zone is moved from the toe of the well to the heel of the well over the simulation period. The moving injection zone can be achieved using embodiments of the present method/system. It should be noted that the total volume of water injected in all cases has been kept constant.

[0441] Table 12 shows a summary of the simulation results. As the reservoir becomes more and more fractured, the performance of the static injection configuration deteriorates significantly, while the performance of the moving injection configuration deteriorates to a much lower degree. For example, in the presence of fractures, the oil recovery factor for the static injection configuration is 48.7 A) versus 56.2 A) for the moving injection configuration. Similarly, with 23 fractures the oil recovery for the static configuration is 33.9 A) compared with 50.0 A) for the moving injection configuration. Therefore, the moving injection configuration outperforms the static injection configuration in a generally fractured reservoir.

[0442] Taken together, Examples 4 and 5, show that the moving injection concept increases the oil recovered compared to the static injection configuration whichever way the fractures are orientated. Thus, in fields with high levels of fracturing, which are not well known a priori, implementing a moving injection configuration should deliver equal or better oil recovery from the reservoir than is expected from a static injection configuration.
Table 12 Computer simulation results.
Total Number of Fractures Parameter Units 6 12 18 23 No. perpendicular fractures 5 10 15 20 No. parallel fractures 1 2 3 3 Static injection configuration Total oil produced m3 1,519,876 1,171,145 949,238 817,362 Total water produced m3 13,499,209 13,865,012 14,104,452 15,068,728 Produced water/oil ratio 8.9 11.8 14.9 17.4 Oil recovery factor % 63.3 48.7 39.4 33.9 Moving injection configuration Total oil produced m3 1,567,767 1,352,806 1,306,588 1,205,696 Total water produced m3 13,451,294 13,683,261 13,746,928 12,863,616 Produced water/oil ratio 8.6 10.1 10.5 11.5 Oil recovery factor 0/0 65.2 56.2 54.3 50.0 Example 6: Multi-well Moving Injection Combustion Stimulation (MICS)

[0443] This example was derived from the computer simulations of two predominately horizontal wells located in a reservoir, each as shown in Example 1.
Figure 23 shows plan views of a reservoir depicting the location of two predominately horizontal wells and contours of temperature on the plane in the middle of the reservoir, at three different times, for a Moving Injection Combustion Stimulation (MICS) process. There are two predominately horizontal wells, 2210 and 2211, respectively, drilled into the reservoir which are both configured for injection of mobilising fluids and production of reservoir fluids using a single well, like that shown in Examples 1 and 2 and using a well completion similar to that shown in Figures 1 and 2.

[0444]
Figure 23(a) shows the temperature profile in the reservoir 2206, at a time when the injection zone of the oxidant is close to the toe of the wells (i.e.
at the beginning of the wells' life). The reaction of the oxidant with the hydrocarbons in the reservoir 2206, generates combustion zones 2221 with a temperature of over 400 C, which extend laterally towards the centre-line between the wells. Zones exists around the combustion zones where the temperature is between 300 and C. Similarly, lower temperature zones 2223 exists where temperatures are between 200 and 300 C. Evaporation zones 2224 exist around the combustion process where temperatures vary between 100 and 200 C and where water originally present in the reservoir 2206 can be turned to steam. The reservoir 2206 has a natural temperature below 100 C, and typically between about 20 and 30 C. At this time, the thermally affected regions generated by the combustion zones 2221 do not substantially interact with each other, and the production from each well is equivalent to that of an isolated well bore undergoing the same process.

[0445] Figure 23(b) shows the temperature profile in the reservoir 2206, at a time when the injection zone of the oxidant is close to the middle of the wells (at the middle of well life). The reaction of the oxidant with the hydrocarbons in the reservoir 2206, generates combustion zones 2221 with a temperature of over 400 C, which extend laterally towards the centre-line between the wells. Zones 2222 exists around the combustion zone where the temperature is between 300 and 400 C.
Similarly, lower temperature zones 2223 exists where temperatures are between 200 and 300 C. The evaporation zones 2224 generated from each combustion process vary between 100 and 200 C and may merge together to form a single low temperature zone of over 100 C, where water originally present in the reservoir 2206 can be turned to steam. At this time, the thermally affected regions generated by the combustion zones start to interact with each other, and the production from both wells increases above twice that produced from an isolated well bore.

[0446] Figure 23(c) shows the temperature profile in the reservoir 2206, at a time when the injection zone of the oxidant is close to the heel of the wells (at the end of well life). At this time, the thermally affected regions generated by the combustion zones interact with each other substantially. The production from both wells is above twice that produced from an isolated well bore and the air oil ratio is below that found from a single well configuration, due to the lower heat losses experienced by the thermally affected zone.

[0447] The magnitude of the additional oil recovery from the two well MICS
process, depends on various properties of the reservoir, the well bores and the oxidant injection configuration. If the two horizontal wells are spaced very far apart, then the thermally affected zones will not interact at all, and the production will be twice that of an isolated well bore undergoing the same process. If the two horizontal wells are spaced very close together, then the thermally affected zones will largely overlap, and the production could be lower than twice that of an isolated well bore. If the wells are spaced optimally, then the thermally affected zones will have a small overlap and the production will be higher than two individual wells and the AOR will be lower, indicating a more efficient process. For the combustion of heavy oil and oil sands bitumen from reservoirs in Alberta and Saskatchewan in Canada, the lateral distance between two horizontal well bores is preferably, between about 40 and metres, and more preferably between about 50 and 75 metres.
Example 7: Multi-well Moving Injection Combustion Process

[0448] Figure 24 shows plan views of a reservoir depicting the location of two predominately horizontal wells and contours of temperature on the plane in the middle of the reservoir, at three different times, for a Moving Injection Combustion process. There are two predominately horizontal wells, with the well 2310 designated as the injection well and well 2311, designated as the production well. The well completions in 2310 and 2311 are similar to the completions shown in Figure 18, albeit with only one injection zone along the injection well 2310. The oxidant is injected into the reservoir from the injection well 23101, from an injection zone which extends about 20 m and which is moved slowly along the injection well 2310, from the toe towards the heel. The fluids mobilised by the combustion process are recovered in the production well 2311 and transported to surface.

[0449] Figure 24(a) shows the temperature profile in the reservoir 2306, at a time when the injection zone of the oxidant is close to the toe of the injection well 2310 (ie. at the beginning of the well's life). The reaction of the oxidant with the hydrocarbons in the reservoir 2306, generates a combustion zone 2321 with a temperature of over 400 C, which extend laterally towards the centre-line between the wells. Zone 2322 exists around the combustion zone where the temperature is between 300 and 400 C. Similarly, a lower temperature zone 2323 exists where temperatures are between 200 and 300 C. An evaporation zone 2324 exists around the combustion process where temperatures vary between 100 and 200 C and where water originally present in the reservoir 2306 can be turned to steam.
The reservoir 2306 has a natural temperature below 100 C, and typically between about 20 and 30 C. At this time, the thermally affected region generated by the combustion zone 2321 is skewed due to the fact that the injection zone where the oxidant is injected into the reservoir is moved slowly from the toe to the heel of well 2310. The moving injection zone therefore begins to establish an oblique combustion front between the injection well 2310 and the production well 2311.

[0450] Figure 24(b) shows the temperature profile in the reservoir 2306, at a time when the injection zone of the oxidant is close to the middle of the injection well 2310 (ie. at the middle of well life). The reaction of the oxidant with the hydrocarbons in the reservoir 2306, generates a combustion zone 2321 with a temperature of over C, which forms an oblique combustion front between the two horizontal wells.
Lower temperature zones 2322 and 2323 extend around the combustion zone. An evaporation zone 2324 exists where temperatures vary between 100 and 200 C
and where water originally present in the reservoir 2206 can be turned to steam.
At this time, a fully established oblique combustion front is present between the injection well 2310 and the production well 2311.

[0451] Figure 24(c) shows the temperature profile in the reservoir 2306, at a time when the injection zone of the oxidant is close to the heel of the injection well 2310 (ie. at the end of well life). At this time, the thermally affected region includes a skewed combustion zone 2321 where hydrocarbons are oxidised and temperatures are over 400 C, and lower temperatures zones 2322, 2323 and 2324. At this time, the majority of the hydrocarbons in the reservoir between the two wells has been produced to surface. The injection zone is moved close to the heel of the well 2310, but sufficiently far away that the maximum temperature in the vertical section of the well bore is maintained below a safe limit, typically below 300 C, and more preferably below 200 C and even more preferably below 100 C.

[0452] When the efficiency of the process drops, the injection of the oxidant can be stopped and hydrocarbons remaining in the reservoir may be produced to surface using natural and/or artificial lift as the reservoir slowly cools back down to its natural temperature.

Claims

WO 2019/136533 PCT/AU2019/050026

1. A method to recover hydrocarbons from a reservoir of a subterranean formation comprising a single horizontal well bore, the method comprising the steps of:
a) injecting a mobilising fluid into the reservoir at a first location to create a first mobilised zone, the first mobilised zone including a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons;
b) withdrawing the mixture of mobilised fluids that flow out of the reservoir of the hydrocarbon bearing subterranean formation as a produced fluid; and c) changing the location of injection of mobilising fluid and repeating steps a) and b) one or more times so as to inject mobilising fluid into the reservoir at one or more subsequent further location(s) remote from the first location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone;
wherein the mobilising fluid is injected via a completion assembly arranged in the horizontal well bore, and the produced fluid is removed via the same completion assembly arranged in the horizontal well bore.

2. The method according to claim 1, wherein the method comprises the continuous injection of mobilising fluid as the produced fluid is withdrawn.

3. The method according to claim 1 or 2, wherein following the step of changing the location of injection of mobilising fluid, the subsequent further location of injection overlaps with the immediately preceding location of injection.

4. A system for recovering hydrocarbons from a reservoir of a subterranean formation comprising a single horizontal well bore, the system comprising:
a completion assembly disposed in the single horizontal well bore and adapted to both:
(0 inject from an injection point at a first injection location a mobilising fluid into the reservoir to create a first mobilised zone, the first mobilised zone including a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons;
and (ii) withdraw from a withdrawal point at a first withdrawal location the mixture of mobilised fluids that flow out of the reservoir of the hydrocarbon bearing subterranean formation as a produced fluid;
wherein the completion assembly comprises a plurality of injection points to permit changing of the location of injection of mobilising fluid to one or more subsequent further location(s) remote from the first injection location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone; and wherein the completion assembly comprises a plurality of withdrawal points to permit changing of the location of withdrawal of produced fluid to one or more subsequent further location(s) remote from the first withdrawal location.

5. The system according to claim 4, wherein there is one or more sealing devices in the completion assembly to form a seal between the location of injection of mobilising fluid, and the location that production fluid enters the completion assembly.

6. The system according to claim 4 or 5, wherein the completion assembly comprises two conduits, an inner conduit and an outer conduit, each of the two conduits can be in fluid communication with the reservoir, and the two conduits are arranged one inside the other concentrically.

7. The system according to claim 4 or 5, wherein the completion assembly comprises two conduits, an inner conduit and an outer conduit, each of the two conduits can be in fluid communication with the reservoir, and the two conduits are arranged one inside the other eccentrically so that at least a part of the wall of the inner conduit abuts the wall of the outer conduit.

8. The system according to claim 6 or 7, wherein the completion assembly comprises a plurality of completion devices, each completion device comprising a plurality of apertures that can be opened to provide the fluid communication between one or both of the conduits and the reservoir; and the apertures can be closed so as to close off the fluid communication between one or both of the conduits and the reservoir.

9. The system according to claim 8, wherein each completion device is provided with a sliding sleeve slidable to open or close apertures in the inner and or outer conduits.

10. The system according to claim 9, wherein in a sliding sleeve position:
a. the apertures of the inner conduit are closed and the apertures of the outer conduit are closed; or b. the apertures of the inner conduit are open and the apertures of the outer conduit are open; or c. the apertures of the inner conduit are open and the apertures of the outer conduit are closed; or d. the apertures of the inner conduit are closed and the apertures of the outer conduit are open.

11. The system according to claim 10, wherein the injection of a mobilising fluid from an injection point into the reservoir comprises injection via open apertures of a first completion device;

and changing the location of injection of mobilising fluid comprises injecting via open apertures of a second completion device, wherein the sliding sleeve of the second completion device is moved to open the apertures for injection.

12. The system according to claim 11, wherein the sliding sleeve of the first completion device is moved to close the apertures for injection.

13. The system according to claim 10, wherein the withdrawal of produced fluid comprises withdrawal via open apertures of a first completion device; and the system further includes changing the location of withdrawal of produced fluid, wherein changing the location of withdrawal of produced fluid comprises withdrawal via open apertures of a second completion device, wherein the sliding sleeve of the second completion device is moved to open the apertures for withdrawal.

14. The system according to claim 13, wherein the sliding sleeve of the first completion device is moved to close the apertures for withdrawal.

15. The system according to claim 10, wherein a first completion device injects mobilising fluid into the reservoir at a first injection location;
a second completion device withdraws produced fluid at a first withdrawal location;
the first completion device ceases injecting mobilised fluid, and is changed to withdraw produced fluid at a second withdrawal location;
the second completion devices ceases withdrawing produced fluid, and is changed to inject mobilising fluid at a second injection location.

16.The system according to any one of claims 4 to 15, wherein the mobilising fluid is selected from one or more of steam, oxidants (oxygen containing fluids), solvents, carbon dioxide, light hydrocarbons such as methane, ethane, propane and butane, water and nitrogen and optionally includes additives.

17.The system according to claim 16, wherein the mobilising fluid is an oxidant and wherein the temperature of the completion assembly is controlled to the evaporation temperature of water at the prevailing pressure in the completion assembly +/- 10 %, by varying the:
i) ratio of water to oxygen in the mobilising fluid; and/or ii) rate of injection of the mobilising fluid.

18.The system according to claim 17, wherein heat from the produced fluid is used to evaporate water co-injected with the mobilising fluid into steam such that the completion assembly is controlled to the evaporation temperature of water +/-10 % at the prevailing pressure in the completion assembly.

19.The system according to any one of claims 4 to 18, wherein the hydrocarbons in the subterranean formation include one or more of natural gas, light oil, medium oil, heavy oil, oil sands, bitumen, oil shale, shale oil and coal.

20.The system according to any one of claims 4 to 19, wherein the subterranean formation is fractured.