CA2991889A1 - A further method and system for enhanced oil recovery using moveable completions - Google Patents

Abstract

A method to recover hydrocarbons from a subterranean formation is described. 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 comprises 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 includes a mixture of mobilised fluids including injected mobilising fluid and mobilised hydrocarbons. The method includes withdrawing via the second horizontal well the mixture of mobilised fluids that flow out of the hydrocarbon bearing subterranean formation as a produced fluid. The method includes changing the location of injection of mobilising fluid and the injection and withdrawal steps one or more times so as to inject mobilising fluid into the well at one or more subsequent further location(s). The one or more subsequent further location(s) are remote from the first location to create one or more subsequent further mobilised zone(s) remote from the first mobilised zone.

Description

A FURTHER METHOD AND SYSTEM FOR ENHANCED OIL RECOVERY USING
MOVEABLE COMPLETIONS
TECHNICAL FIELD
This invention relates to recovery of hydrocarbons from a subterranean formation. The subterranean formation can include, 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 for mobilising and recovering carbonaceous materials by injecting mobilising fluids and recovering hydrocarbon containing fluids using completions which are moved within the well(s) and swept through the reservoir.
BACKGROUND OF THE INVENTION
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.
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.
Enhanced oil recovery can refer to many types of recovery processes, including immiscible, miscible and thermal methods.
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.

i 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 Various configurations which involve combinations of vertical and horizontal wells have also been disclosed.
The use of patterns of vertical wells is common for immiscible and miscible displacement of the hydrocarbons in the reservoir.
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.
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.
Other fluids which are used for immiscible displacement or pressure maintenance include nitrogen, methane and light hydrocarbon gases.
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.

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.
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.
The most common methods of steam injection include the steam flood and steam assisted gravity drainage (SAGD).
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.
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.
SAGD has had limited operational success to date in heterogeneous reservoirs, such as the carbonate reservoirs in Canada.
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.
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.
In many cases hydrocarbon reservoirs with heterogeneous properties are avoided altogether since the existing methods are ineffective and uneconomic.
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.

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.
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.
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).
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.
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.
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.
A variety of methods have been described using a single well-bore to recover petroleum from subterranean reservoirs.
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.
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.
US Patent 5,215,149 to Lu describes a method of constructing a horizontal well, perforating the well at the toe and at the heal 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.
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.
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.

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

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.
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.
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.
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.
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 OF THE INVENTION
According to a first aspect of the invention 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:
a) 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;
b) 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 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 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.
The present invention relates to 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.
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.
The completion assembly in either well 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 withdraw produced fluid. The tubing can be adapted to move in the reservoir.
The perforations in the well liner may encompass any type of open area present in the well liner, including holes, slots, screens and perforations made using conventional perforation guns.
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.
In these regions, the injection of mobilising fluids may be halted as the completion assembly is moved along the length of the horizontal well.

In other cases, it may be desirable to "quickly" sweep at least a part of the completion assembly through particular regions of the reservoir. 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.
First well An advantage of using a moveable completion tubing 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.
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.
It will be appreciated by those skilled in the art, that by moving the completion tubing 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 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.
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.
.. 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.
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.
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.
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 15. fluid.
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.
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.
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 1i processes (such as "huff and puff') and/or as per sequential processes (such as water-alternating-gas (WAG) injection).
Second well 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.
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. Most often, the first and second well will be located at approximately the same elevation (depth).
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 will be inthe 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.
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.
It will be appreciated by those skilled in the art, that by moving the completion tubing 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.
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.
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.
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.
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.

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.
The apertures in the completion tubing can receive and withdraw the mobilising fluid into the horizontal well from the reservoir.
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.
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.
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.
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).
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.
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.
Therefore, in some embodiments the method can further comprise the steps of:
d) 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;
e) 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.
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.
In an embodiment the produced fluids may be produced to surface via artificial lift, i.e.
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).

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 invention may be applied to patterns of wells, wherein any suitable ratio of injection wells to production wells can be applied.
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.
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.
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.
In an embodiment the apertures can be opened and closed using a sliding sleeve device, which are well known in the industry. The sliding sleeve device 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 (e.g. to prevent sand inflow) can be incorporated into the sliding sleeve device itself.

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.
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. Where there is a first mobilising fluid and a second mobilising fluid, the two fluids can be the same or different from one another.
One 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.
Another advantage of using a primary and secondary mobilising fluid is that the temperature of the 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.
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.
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.
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 and steam. In this situation the zone of mobilised hydrocarbons would be generated 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.
In an embodiment, steam may be generated in the completion tubing 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. 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. It is well known that steam is a much better mobilising fluid than water in thermal enhanced oil recovery applications.
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.
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.
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.
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.
In an embodiment the hydrocarbon bearing subterranean formation comprises light = oil, medium oil, heavy oil or bitumen and the mobilising fluid 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.

The 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.
Another advantage of using two mobilising fluids is that one of the mobilising fluid 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.
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.
An advantage of the present invention is 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.
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 present invention can be applied.

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.
In an embodiment, the application of the present invention in a first and second well, may follow an earlier operation where each well has been operated with injection and production according to the invention described by applicant's co-pending application entitled A METHOD AND SYSTEM FOR ENHANCED OIL RECOVERY USING
MOVEABLE COMPLETIONS lodged on the same date. 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. 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 with the present invention in some reservoirs.
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.
Another feature of the oil formations that are the target of some methods of the present invention 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.

BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments will now be described with reference to the non-limiting drawings which are exemplary only. The description in relation to any one the Figures can be applied to any of other of the Figures unless the context makes clear otherwise.
Figure 1 illustrates an embodiment of the invention showing 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 Figure 2 illustrates an embodiment of the invention showing 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.
Figure 3 illustrates an embodiment of the invention wherein the moveable well completion incorporates a concentric tubing string and is configured for the injection of a primary and secondary mobilising fluid into the hydrocarbon bearing reservoir.
DESCRIPTION OF EMBODIMENTS
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.
Referring to Figure 1, there is generally depicted a hydrocarbon bearing subterranean formation 706 with two horizontally drilled well bores 710 illustrating certain aspects of the invention.

Casing 722 extends from the surface to the horizontal section of the well.
Surface casing 728, which may consist of multiple concentric tubings, is installed into the vertical section of the well. A liner 704 with a certain amount of open area is installed into each horizontal section of the well bores 710.
The first well can be called the injection well 768. The second well can be called the production well 770.
Injection tubing 758 in the form of a completion assembly is installed into the injection well 768, with two injection devices 760 (completion devices), one installed in the middle of the injection tubing 758 and another installed at the distal tip of the injection tubing 775.
The injection tubing 758 may be jointed tubing or it may be coiled tubing. The injection tubing 758 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings.
The injection tubing 758 conveys the mobilising fluids 708 from the surface to the injection devices 760.
Mobilising fluid(s) 708 are injected through the injection tubing 758 and enter into the injection device 760. The mobilising fluids 708 enter into the annular space between the injection device 760 and the liner 704, and are injected into the hydrocarbon bearing reservoir 706 through the open area in the liner 704.
In an embodiment the mobilising fluids 708 may include a primary mobilising fluid and a secondary mobilising fluid that are injected into different regions of the reservoir 706 using the injection device 760 and injection tubing 758.
In the reservoir 706, one or more zones of mobilised hydrocarbons 714 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 714 may form one or more relatively permeable connections between the injection well 768 and the production well 770.

The mixture of fluids 762 from the zones of mobilised hydrocarbons 714 flow via gravity, pressure and other means through the liner 704 in the production well 770 and may enter the annular space between the production device 764 and liner 704.
From there the produced fluids 716 are conveyed from the production device 764 to the surface via the production tubing 766.
In an embodiment the produced fluids may be produced to the heel of the well bore via the production tubing 766. The produced fluids 716 may then be produced to surface via a pump and production tubing or via an artificial lift mechanism.
To recover all of the hydrocarbons in the vicinity of the injection and production wells, the injection devices 760 and production devices 764 may be moved longitudinally along the horizontal well bores 710 and 770, to enable the mobilisation of hydrocarbons from new portions of the reservoir The injection devices 760 and production devices 764 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.
Generally, the injection devices 760 and production devices 764 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.
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.
In an embodiment, the injection tubing 758 may be installed in the well bore 710 from the beginning of the injection of mobilising fluids 708 into the reservoir 706.
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 In an embodiment the horizontal wells may be arranged in any pattern. For example, the injection well 758 may be placed at a higher or lower elevation in the reservoir 706 than the production well 770.
In an embodiment, the production well 770 may be placed down-dip of the injection well 768 in the reservoir 706.
Referring to Figure 2, there is generally depicted a hydrocarbon bearing subterranean formation 806 with two horizontally drilled well bores 810 illustrating certain aspects of the invention.
The generally horizontal well bores 810 are drilled through the over burden formation 818 and into the hydrocarbon bearing reservoir 806 using standard directional drilling techniques. Casing 822 extends from the surface to the horizontal section of the well.
Surface casing 828, which may consist of multiple concentric tubings, is installed into the vertical section of the well. A liner 804 with a certain amount of open area is installed into each horizontal section of the well bores 810.
One of the wells is called the injection well 868. The other well is called the production well 870.
Injection tubing 858 is installed into the injection well 868, with two injection devices 860, one installed in the middle of the injection tubing 858 and another installed at the distal tip of the injection tubing 875.
The injection tubing 858 may be jointed tubing or it may be coiled tubing. The injection tubing 858 may consist of a single tubing or it may consist of multiple tubings, including concentric tubings.
The injection tubing 858 conveys the mobilising fluids 808 from the surface to the injection devices 860.

Mobilising fluids 808 are injected through the injection tubing 858 and enter into the injection device 860. The mobilising fluids 808 enter into the annular space between the injection device 812 and the liner 804, and are injected into the hydrocarbon bearing reservoir 806 through the open area in the liner 804.
In an embodiment the mobilising fluids 808 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 860 and injection tubing 858.
In the reservoir 806, one or more zones of mobilised hydrocarbons 814 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 814 may form one or more relatively permeable connections between the injection well 868 and the production well 870.
The mixture of fluids 862 from the zones of mobilised hydrocarbons 814 flow via gravity, pressure and other means through the liner 804 in the production well 870.
From there the produced fluids 816 are produced to surface via production tubing 824 and a pump.
To recover all of the hydrocarbons in the vicinity of the injection and production wells, the injection devices 860 may be moved longitudinally along the horizontal well bore 810, to enable the mobilisation of hydrocarbons from new portions of the reservoir.
The injection devices 860 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.
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.
In an embodiment, the injection tubing 858 may be installed in the well bore 810 from the beginning of the injection of mobilising fluids 808 into the reservoir 806.

In an embodiment the horizontal wells may be arranged in any pattern.
Referring to Figure 3, which shows an embodiment for the injection device 960 using a concentric tubing string arrangement, which enables the injection of a primary mobilising fluid 908 and a secondary mobilising fluid 950.
A generally horizontal well bore 910 is drilled into the hydrocarbon bearing reservoir 906 using standard directional drilling techniques. A liner 904 with a certain amount of open area is installed into the well bore 910. The injection device 960 uses a concentric tubing arrangement.
Primary mobilising fluids 908 are injected through the inner tubing of the concentric tubing of the injection device 960. The primary mobilising fluids 908 exit from apertures 942 into the annulus between the injection device 960 and the liner 904. The primary mobilising fluids 908 are injected into the hydrocarbon bearing reservoir 906 through the open area in the liner 904.
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 904, have slots 944 manufactured into them.
Secondary mobilising fluids 950 are injected through the annulus 948 formed between the outer and inner tubings and exit from apertures 946 into the annulus between the injection device 960 and the liner 904. The secondary mobilising fluids 950 are injected into the hydrocarbon bearing reservoir 906 through the open area in the liner 904.
In the reservoir 906 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.
In order to ensure that the primary mobilising fluids 908 and secondary mobilising fluids 950 are injected into the appropriate regions of the reservoir 906, sealing devices 940 are installed to form a seal between the injection device 960 and the liner 904 and to isolate the injection regions of the primary mobilising fluid 908 and the secondary mobilising fluids 950.
In an embodiment the configuration of the tubings may be reversed; so that primary mobilising fluids 908 are injected into annulus 948 formed between the inner and outer tubing of the injection device 960 and the secondary mobilising fluids 950 are injected into the inner tubing of the injection device 960.
It should be clear to those skilled in the art, that operation of the injection device 960, enables the formation of a zone of mobilised hydrocarbons from the injection of the secondary mobilisation fluid 950, which is subsequently contacted with the primary .. mobilising fluid 908, when the injection device 960 is moved out of the well bore 910;
or which enables the formation of a zone of mobilised hydrocarbons from the injection of the primary mobilising fluid 908, which is subsequently contacted with the secondary mobilising fluid 950, when the injection device 960 is moved into the well bore 910.
In an embodiment the injection device 960 is moved such that adjacent zones of .. mobilised hydrocarbons overlap.
In an embodiment the injection device 960 is moved a distance equal to the distance between adjacent sealing devices 940. In an embodiment the injection device 960 is moved a distance equal to the distance between the apertures 942 and the apertures 946.
In an embodiment the primary mobilising fluid 908 or secondary mobilising fluid 950 may contain a fluid or solid mobilising catalyst. In an embodiment the mobilising catalyst may be a nanoparticle.
In an embodiment the primary mobilising fluid 908 is an oxidant and the secondary mobilising fluid 950 is water or steam.
.. In an embodiment, catalysts may be injected with the primary mobilising fluid 908, the secondary mobilising fluid 950 or both fluids.

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 950 or may be mixed with the primary mobilising fluid 908.
An advantage of some embodiments of the present invention 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 950, a zone of mobilised hydrocarbons and the catalyst can be created in the reservoir; which is subsequently contacted with the primary mobilising fluid 908 as the injection device 960 is moved through the reservoir, thereby creating the optimal conditions for the catalyst to improve the properties of the hydrocarbons in the reservoir.
In an embodiment, any number of mobilising fluids may be injected into the reservoir 906 via the injection device 960.

Claims (28)

31

1. 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:
a) 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;
b) 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 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 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.

2. The method according to claim 1, wherein the method comprises the continuous injection of mobilising fluid into the first horizontal well as the produced fluid is withdrawn from the second horizontal well.

3. The method according to claim 1 or 2, wherein there is one or more sealing devices is provided to form a seal between each location of injection of mobilising fluid.

4. The method according to any one of the preceding claims, 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

5. The method according to any one of the preceding claims, wherein the first horizontal well comprise a first horizontal well liner comprising a plurality of perforations spaced along substantially a length of the well liner, and a first tubing is installed within the well liner, the first tubing adapted to inject the mobilising fluid into the first horizontal well.

6. The method according to claim 5, wherein the step of changing the location of the injection of mobilising fluid in the well comprises moving the first tubing.

7. The method according to claim 6, wherein the step of moving of the first tubing comprises retracting the first tubing.

8. The method according to claim 7, wherein the step of retracting the first tubing is undertaken by one of removal of tubing sections and winding up the tubing

9. The method according to any one of claims 5 to 8, wherein the first tubing is adapted to inject the mobilising fluid into the well through at least one opening in the tubing.

10. The method according to any one of the preceding claims, wherein the second horizontal well comprise a second horizontal well liner comprising a plurality of perforations spaced along substantially a length of the well liner.

11. The method according to claim 10, wherein a second tubing is installed within the well liner.

12. The method according to any one of the preceding claims, wherein the step of withdrawing the mixture of mobilised fluid comprises allowing the mixture to flow under gravity through the perforations in the second well liner.

13. The method according to any one of the preceding claims, wherein the first and or second tubing is a concentric tubing comprising an inner tube and an outer tube.

14. The method according to claim 13, wherein the first tubing and or second tubing comprises at least one opening in the form of a first series of apertures, the first series of apertures in fluid communication with the inner tube, and a further series of apertures spaced along the length of the first tubing, the further series of apertures in fluid communication with the outer tube.

15. The method of claim 14, wherein the first series of apertures are towards the tip of the tubing, and the further series of apertures are remote from the tip.

16. The method according to claim 14 or 15, wherein there is at least one seal between the tubing and the well liner adjacent each first and further series of apertures.

17. The method according to any one of claims 14 to 16, wherein the further series of apertures delivers the mobilising fluid.

18. The method according to any one of claims 14 to 17, wherein the first series of apertures delivers the mobilising fluid.

19. The method according to claim 17 or 18, wherein the first series of apertures delivers a first mobilising fluid, and the further series of apertures delivers a second mobilising fluid.

20. The method according to any one of the preceding claims, wherein 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.

21. The method according to any one of the preceding claims, wherein the first 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.

22. The method according to claim 21, wherein the second mobilising fluid is different from the first mobilising fluid and 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

23. The method according to claim 21 or 22, wherein the first and or second mobilising fluid comprises nanoparticles and or nanofluids.

24 The method according to any one of the preceding claims, wherein there is more than one set of first series of first apertures, each set spaced apart from one another; and there is more than one set of further series of apertures, each set spaced apart from another

25. The method according to any one of the preceding claims, wherein the method further comprises the step of d) 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;
e) 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.

26. The method according to any one of the preceding claims, 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

27 The method according to any one of the preceding claims, wherein the first horizontal well and or second horizontal well is a fractured

28. Hydrocarbons when produced by a method according to any one of the preceding claims.