WO2015158371A1

WO2015158371A1 - Method for recovering heavy hydrocarbon from a depleted formation

Info

Publication number: WO2015158371A1
Application number: PCT/EP2014/057650
Authority: WO
Inventors: Harald Vindspoll; Sturla SÆTHER
Original assignee: Statoil Canada Limited; Lind, Robert
Priority date: 2014-04-15
Filing date: 2014-04-15
Publication date: 2015-10-22

Abstract

The present invention relates to a method of recovering heavy hydrocarbon from a partially depleted heavy hydrocarbon containing formation (2) comprising: • i) selecting a formation (2) that has been partially depleted of hydrocarbon by a thermal recovery method for at least 1 year; • ii) injecting (well 5) solvent into said partially depleted heavy hydrocarbon formation, wherein said solvent has a first temperature; • iii) allowing said formation to heat said solvent to a second temperature; and • iv) recovering heavy hydrocarbon which is diluted and mobilised by the heated solvent.

Description

METHOD FOR RECOVERING HEAVY HYDROCARBON FROM A DEPLETED FORMATION

FIELD OF THE INVENTION

The present invention relates to a method for recovering heavy hydrocarbon from a partially depleted heavy hydrocarbon containing formation which utilises the thermal energy stored in the formation to facilitate the mobilisation of further heavy hydrocarbon.

BACKGROUND

Heavy hydrocarbons, e.g. bitumen, represent a huge natural source of the world's total potential reserves of oil. Present estimates place the quantity of heavy hydrocarbon reserves at several trillion barrels, more than 5 times the known amount of the conventional, i.e. non-heavy, hydrocarbon reserves. This is partly because heavy hydrocarbons are generally difficult to recover by conventional recovery processes and thus have not been exploited to the same extent as non-heavy hydrocarbons. Heavy hydrocarbons possess very high viscosities and low API (American Petroleum Institute) gravities which makes them difficult, if not impossible, to pump in their native state.

A number of methods have been developed to extract and process heavy hydrocarbon mixtures. The recovery of heavy hydrocarbons from subterranean reservoirs is most commonly carried out by steam assisted gravity drainage (SAGD) or in situ combustion (ISC). In these methods the heavy hydrocarbon is heated and thereby mobilised, by steam in the case of SAGD and by a combustion front in the case of ISC, to flow to a production well from where it can be pumped to the surface facilities. The transportability of the viscous heavy hydrocarbon mixture recovered is conventionally improved by dilution with a lighter hydrocarbon.

The thermal recovery processes currently used suffer from inherent drawbacks. These include the consumption of vast amounts of energy, usually in the form of increasingly expensive natural gas, in the production of steam and the concomitant high C0₂ emissions which occur. Of course it has already been recognised in the energy industry that C0₂ emissions must be managed better.

To reduce consumption of natural gas and decrease C0₂ emissions, methods wherein SAGD is combined with another recovery technique have been previously disclosed. In these processes, SAGD is carried out for a relatively short period of time before switching to another recovery technique so that natural gas consumption is minimized. In these processes the energy in the steam present in the SAGD chamber deriving from the SAGD operation is scavenged.

US2003/000071 1 , for example, discloses a combined SAGD and VAPEX process (called SAPEX) for recovery of heavy oil from an underground reservoir. Steam is injected through an injection well and a fraction of hydrocarbons are recovered from a production well. Steam injection is continued until a steam chamber is formed that has progressed vertically to a position that is 25-75 % of the distance from the bottom of the injection well to the top of the reservoir. Alternatively steam injection is continued until the recovery rate of the hydrocarbons is 25-75% of the peak rate using SAGD. A liquid solvent is then injected into the reservoir that exists in vapour form in the chamber to mobilise and recover an additional fraction of hydrocarbons from the reservoir. US2003/000071 1 teaches that the cross over from steam injection to vaporized solvent injection typically occurs about 4-6 months after initiation of SAGD operations and confirms that as a result heat loss to the formation is avoided. This is achieved by injecting the solvent into the formation before heat loss to the formation has occurred and instead the heat in the SAGD steam chamber is transferred directly from the steam to the solvent.

In a paper by Zhao, L. (SPE, Alberta Research Council April 2007 "Steam Alternating Solvent Process" Copyright Society of Petroleum Engineers) a method for the recovery of heavy oil, entitled SAS (Steam Alternating Solvent Process) is proposed. The process requires a horizontal injection well and a parallel production well directly beneath the injection well, i.e. a SAGD well pair. Pure steam is injected into the injection well. When the steam chamber is established steam injection is then stopped and solvent injection is started as the heat loss to the formation is becoming significant. When the chamber temperature has been reduced, the solvent injection is stopped and the steam injection started again. The cycle is repeated until it is no longer economical to do so.

The aim of the method proposed by Zhao, which is supported by numerical simulation data, is to replace a large amount of the steam injection in the SAGD process with solvent, while maintaining similar overall oil production rates. Thus as in US2003/000071 1 above, the switch from steam injection to solvent injection occurs early in the operation and it is the energy in the steam that is not transferred to the oil that is captured by the solvent, rather than the energy that is lost to the formation i.e. energy loss to the formation is avoided. US 4,519,454 discloses the general idea of injecting solvent into a formation that has been pre-treated with steam. The method comprises:

1 ) Heating the reservoir surrounding the wellbore with steam. The steam should be injected at a temperature of between about 149 °C (300 °F) and 315 °C (600 °F), so as to raise the temperature of the formation to a selected temperature 4 to 93 °C (40-200 °F) above the initial reservoir temperature.

2) Producing the formation until some of the water injected as steam has been recovered.

3) Injecting a liquid solvent, having a ratio of crude viscosity to solvent viscosity of at least about 10, into the reservoir. Exemplified suitable solvents are light crude oil, syncrude, diesel fuel, condensate, cutter stock or other light hydrocarbons. The liquid solvent is injected in sufficient amounts to provide adequate solvent fingering around the wellbore, resulting in a high mobility path for subsequent produced oil flowing backwards into the well.

4) Producing the formation until the amount of solvent in the solvent-crude mixture drops below 12%.

The solvent injection/production cycles are then repeated. When the temperature of the produced oil drops to 20 °F above the untreated produced oil, the steam injection process is repeated to reheat the reservoir. Alternatively, the liquid solvent can be heated to the desired temperature prior to injection to maintain the temperature inside the formation.

As in the prior art documents discussed above, the formation is only heated by a steam treatment to establish a modest temperature increase over a short period of time. Thus once again the prior art advocates transferring heat directly from steam to a solvent.

A need still exists for methods of heavy hydrocarbon recovery, such as SAGD, which are more efficient in terms of hydrocarbon production for fuel consumed during steam generation. SUMMARY OF THE INVENTION

Thus viewed from a first aspect the present invention provides a method of recovering heavy hydrocarbon from a partially depleted heavy hydrocarbon containing formation comprising:

i) selecting a formation that has been partially depleted of hydrocarbon by a thermal recovery method for at least 1 year; ii) injecting solvent into said partially depleted heavy hydrocarbon formation, wherein said solvent has a first temperature;

iii) allowing said formation to heat said solvent to a second temperature; and iv) recovering heavy hydrocarbon which is diluted and mobilised by the heated solvent.

Viewed from a further aspect the present invention provides a method of recovering heavy hydrocarbon from a heavy hydrocarbon containing subterranean formation comprising:

(i) conducting a thermal recovery method in said formation to recover heavy hydrocarbon; and

(ii) recovering further heavy hydrocarbon by a method as hereinbefore defined.

DETAILED DESCRIPTION OF THE INVENTION The methods of the present invention are for the recovery of heavy hydrocarbon from heavy hydrocarbon containing formations. As used herein heavy hydrocarbon refers to a mixture of hydrocarbon that comprises a greater proportion of hydrocarbons having a higher molecular weight than a relatively lighter hydrocarbon mixture. Terms such as "light", "lighter", "heavier" etc. are to be interpreted herein relative to "heavy". Typical heavy hydrocarbons have an API gravity of less than about 20°, preferably less than about 15°, more preferably less than 12°, still more preferably less than 10°, e.g. less than 8°. It is particularly preferred if the API gravity of the heavy hydrocarbon recovered by the method of the present invention is from about 5° to about 15°, more preferably from about 6° to about 12°, still more preferably about 7° to about 12°.

To recover hydrocarbon, and particularly heavy hydrocarbon, from subterranean formations, it is often necessary to employ thermal recovery methods such as Steam Assisted Gravity Drainage (SAGD) and In Situ Combustion (ISC). Thermal recovery methods generally facilitate recovery of heavy hydrocarbon by mobilising it by heating and in some cases by additionally reducing its viscosity by dilution. These methods successfully facilitate the recovery of hydrocarbon which otherwise would remain in the formation.

There is, however, a significant energy cost associated with thermal recovery methods. In SAGD the steam needed for injection into the formation is usually generated using natural gas as the fuel. Since vast volumes of steam are required in an effective recovery operation that might last for 10-20 years this is a huge cost. Although an advantage of ISC is that the fuel for combustion is the in situ hydrocarbon, a steam treatment is usually required initially to heat the formation to a temperature that will sustain combustion.

Another disadvantage of conventional SAGD is that significant amounts of heavy hydrocarbon remain in the formation after SAGD ceases to be economically viable. When two adjacent SAGD well pairs are operated as a unit, which is conventionally the case, they initially each facilitate enhanced heavy hydrocarbon recovery in their immediate vicinities. Over time, however, the adjacent SAGD well pairs form a continuous zone above the injector wells in which steam is present and mobilised hydrocarbon is produced. An area of reservoir in between the producer wells that comprises heavy hydrocarbon is, however, always bypassed by the steam which tends to rise. As a result heavy hydrocarbon present in this area is not mobilised and never recovered.

The method of the present invention recovers and utilises thermal energy generated for carrying out thermal recovery methods that is not recovered in the extracted hydrocarbon. Typically this is the thermal energy that heats the formation, i.e. the energy that accumulates in the formation or reservoir structure. The method of the present invention comprises selecting a formation that has been partially depleted of hydrocarbon by a thermal recovery method for at least 1 year since the initial supply of thermal energy (e.g. steam), and which therefore has a temperature that is significantly (e.g. at least 100 °C) higher than the original temperature of the formation, i.e. prior to starting the thermal recovery method, and injecting a solvent into the depleted heavy hydrocarbon formation. The solvent has a first temperature at the point of injection into the formation. The method, however, further comprises allowing the formation to heat the solvent. In other words energy originally derived from, e.g. steam or in situ combustion and stored in the formation is transferred from the formation into the solvent so that the solvent has a second temperature which is higher than the first temperature. The heated solvent permeates through the formation thereby facilitating recovery of further heavy hydrocarbon. This is achieved by the solvent heating heavy hydrocarbon and mobilising it and by the solvent mixing with the heavy hydrocarbon and reducing its viscosity by dilution. Advantageously the solvent mixing with the heavy hydrocarbon may also reduce the asphaltene content of the in situ heavy hydrocarbon. The further heavy hydrocarbon can then be recovered.

The method of the present invention may be applied to any formation that has previously been partially depleted of hydrocarbon by a thermal recovery method for at least 1 year (i.e. at least 12 months). The prior occurrence, preferably continuous prior occurrence, of a thermal recovery method for at least 1 year ensures that the temperature of the formation is significantly higher than the original temperature of the formation, i.e. prior to starting the thermal recovery method. The initiation of a thermal recovery method is generally characterised by the first input of thermal energy to recover heavy hydrocarbon, e.g. the first steam injection. Preferably the thermal recovery method has been carried out, preferably continuously, on the selected formation for at least 1 .5 years (i.e. at least 18 months) and more preferably for at least 2 years (i.e. at least 24 months) prior to injection of a solvent in the method of the present invention. Still more preferably the thermal recovery method has been carried out (e.g. continuously) for 1 to 15 years, still more preferably 1 .5 to 10 years and yet more preferably 2 to 5 years prior to injection of a solvent in the method of the present invention. In particularly preferred methods of the invention, the selected formation has a production rate by the thermal recovery method which is in decline. Optionally the selected formation has a production rate by the thermal recovery method which is in the wind down period.

In preferred methods of the invention the prior thermal recovery method has heated the formation to a temperature that is at least 100 °C higher than the original temperature of the formation, i.e. prior to starting the thermal recovery method. More preferably the thermal recovery method has heated the formation to a temperature that is 120 to 400 °C, still more preferably 150 to 350 °C and yet more preferably 200 to 340 °C higher than the original temperature of the formation, i.e. prior to starting the thermal recovery method. The temperature of the formation may be determined, for example, by installation of observation wells equipped with temperature recording equipment.

In the method of the present invention the formation has preferably been partially depleted of hydrocarbon by steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), steam flooding or in situ combustion (ISC). Preferably the thermal recovery method comprises injection of steam into the formation. Particularly preferably the formation has been partially depleted of hydrocarbon by steam assisted gravity drainage (SAGD).

In the methods of the present invention steam injection may or may not be ceased prior to injection of the solvent. When steam injection is not ceased prior to injection of solvent, there exists a transitional period of time when both steam and solvent are injected in the formation. In this case the ratio of steam to solvent is gradually decreased until solely solvent is injected into the formation. More preferably, however, steam injection is ceased prior to injection of the solvent.

The solvent used in the present invention may be any fluid that is miscible with heavy hydrocarbon and which reduces the viscosity of heavy hydrocarbon. Preferably the solvent is non-aqueous. Preferably the solvent is a hydrocarbon, more preferably a d-8 hydrocarbon and still more preferably a C₃-₅ hydrocarbon. Representative examples of suitable Ci_-8 hydrocarbons include methane, ethane, propane, butane, pentane, hexane, pentane, octane and mixtures thereof. Propane, butane, pentane and mixtures thereof are particularly preferred.

As used herein the term solvent encompasses liquids, gases and supercritical liquids. Preferably the solvent is in the form of a liquid or a saturated vapour, particularly a saturated vapour, when it is injected into the formation. Preferably the solvent is in the form of a vapour or superheated vapour once it is heated by the formation. As used herein the term saturated vapour is used to refer to a vapour whose temperature and pressure are such that any compression of its volume at constant temperature causes it to condense to liquid. As used herein the term superheated vapour refers to a vapour at a temperature that is higher than its boiling point for the pressure at which the vapour is present. This means that the temperature of the vapour may be lowered without the vapour converting to liquid.

In the methods of the present invention, heat is transferred from the partially depleted and heated formation to the solvent. Preferably this heating converts the saturated solvent, e.g. saturated vapour, into a superheated solvent, e.g. superheated vapour. The temperature of the formation should therefore be higher than the temperature of the injected solvent, e.g. under equivalent pressure conditions. Preferably the difference in temperature (e.g. at the same pressure) between the formation and the first temperature of the solvent is 5 to 500 °C, more preferably 10 to 200 °C and still more preferably 15 to 150 °C. In some preferred methods of the invention the solvent is not heated prior to injection into the formation. In other preferred methods the solvent may be heated prior to injection, e.g. to 30 to 130 °C.

Preferably the temperature of the selected formation partially depleted of hydrocarbon into which the solvent is injected is 50 to 600 °C, more preferably 60 to 300 °C and still more preferably 70 to 200 °C, e.g. at formation pressure which typically is in the range 500 to 7000 kPa. The formation obviously comprises a range of temperatures, e.g. at the cap rock, in the zone previously comprising hydrocarbon and in the underburden. The temperature of the formation referred to herein is the average temperature in the area of formation that previously comprised hydrocarbon and which is contacted by the solvent in the method of the invention.

In preferred methods of the invention the first temperature of the solvent, at the point of injection, is 10 to 200 °C, more preferably 20 to 150 °C and still more preferably 30 to 130 °C. The temperature of the solvent is increased in the method of the invention by contact with the hotter formation. After injection into the formation, the solvent permeates through the formation. Since the formation has previously been depleted by a thermal recovery method, the formation is relatively permeable. Thus the solvent travels through the pores and channels present in the formation and in so doing is in contact with the hot surface of the formation where it extracts heat therefrom.

After heating in the formation, the solvent has a second temperature that is higher than its first temperature at the point of injection. Preferably the solvent is superheated by the formation. Preferably the difference between the first temperature of the solvent and the highest superheated temperature of the solvent is 10 to 500 °C, more preferably 20 to 300 °C and still more preferably 40 to 200 °C, e.g. at formation pressure. The greater the temperature difference between the solvent permeating through the formation and the solvent injected into the formation, the greater the amount of energy that has been recovered from the formation into the solvent.

In preferred methods of the present invention the solvent vapour is superheated by the formation. The superheating increases the mixing rate of the solvent with the heavy hydrocarbon compared to non-superheated solvent. The generation of superheated solvent can therefore lead to better heavy hydrocarbon production rates and/or better sweep efficiency in the formation.

When the heated solvent permeates through the partially depleted hydrocarbon formation it encounters heavy hydrocarbon. Typically a significant amount of heavy hydrocarbon is present in the region in between the SAGD well pairs since the injected steam typically rises upwards. The method of the present invention advantageously targets this region of heavy hydrocarbon.

In preferred methods of the invention the injected solvent moves through the formation in a generally lateral or horizontal direction. Preferably the injected solvent moves through the formation in a more lateral or horizontal direction compared to the injection of steam, e.g. which may occur during the thermal recovery method. This is partly achieved because of the higher density of solvent compared to steam. A level of control over the direction of movement of the injected solvent may also be achieved by the utilisation of particular well arrangements. Particularly preferably the solvent is injected via the injection well or production well, preferably the injection well, of a first SAGD well pair and moves through the formation in a horizontal direction to the injection well or production well of an adjacent SAGD well pair. During at least a part of this movement the solvent may be in liquid or vapour form, but is preferably in vapour form. Preferably the solvent condenses upon contact with the heavy hydrocarbon. Generally the solvent contacts heavy hydrocarbon remaining in the formation, particularly in the area in between SAGD well pairs. The solvent mixes with the heavy hydrocarbon and, if in vapour form condenses, thereby increasing the temperature of the heavy hydrocarbon and reducing its viscosity. The movement of the solvent also causes the heavy hydrocarbon to flow. The overall movement of the injected solvent from a well of a first SAGD well pair to a well, e.g. the production well, of an adjacent second SAGD well pair is referred to as cross flow. Cross flow drives the flow of heavy hydrocarbon to the well of the second SAGD well pair from where heavy hydrocarbon is recovered.

In some methods of the present invention the solvent circulates through the formation continuously. In other preferred methods, the solvent is shut into the formation for a period of time to allow more thermal energy stored in the formation to be transferred to the solvent.

In further preferred methods of the present invention a displacement gas is injected into the formation. When utilised, the displacement gas may be injected simultaneously or separately to the solvent. Preferably the displacement gas is injected after the solvent. When a shut in period is used, the displacement gas is preferably injected into the formation after the shut in period. Any inert gas that is non- condensable under formation conditions may be used as displacement gas, e.g. nitrogen, C0₂ or natural gas. The purpose of the displacement gas is to displace solvent and any remaining mobilised heavy hydrocarbon towards a well from where it can be produced. Preferably the displacement gas is injected into the formation via a production or injection well of a first SAGD well pair. Preferably the displacement gas is injected into the formation via the same well as the solvent.

Further preferred methods of the present invention comprise a step (v) of steam injection. Thus a further steam injection step may be employed after solvent injection. Optionally solvent and steam injection are repeatedly alternated. A further steam injection may be used, for example, to displace solvent and any remaining mobilised hydrocarbon towards the producer well. Preferably, however, no further steam injection is carried out after solvent injection. Indeed the objective of the method of the invention is to capture and utilise the thermal energy stored in the formation as a result of prior steam injection, hence further heating by steam injection is contrary to this aim.

The method of the present invention is preferably carried out for the period of time wherein the value of the heavy hydrocarbon recovered is greater than the cost of extracting it. This will depend on, for example, the location and nature of the heavy hydrocarbon and the prevailing cost of solvent for injection.

The method of the present invention is particularly useful when the depleted formation has been depleted of hydrocarbon by SAGD. As described above, in SAGD two horizontal wells, typically referred to as an injection well and a production well, are drilled into the reservoir, vertically separated by, e.g. 5-10 meters. This group of two wells is typically referred to as a well pair or a SAGD well pair. The method of the present invention is therefore especially useful when the depleted formation comprises at least one SAGD well pair and more preferably at least two SAGD well pairs, e.g. a plurality of SAGD well pairs. The solvent may be injected into the formation in a number of different ways.

The solvent may, for example, be injected into the depleted formation through the injection well of a first SAGD well pair. Optionally the solvent and mobilised hydrocarbon is recovered from the production well of the SAGD well pair. This method and arrangement is described as cyclical since the fluid cycles through the injection and production wells of a single SAGD well pair. This method has the significant advantage that no new wells need to be drilled into the formation which is economically highly beneficial.

More preferably, however, the heated solvent and mobilised heavy hydrocarbon is recovered from the formation via the production well of a second adjacent SAGD well pair. Thus the solvent is injected into the formation via the injection or production well of a first SAGD well pair, the solvent permeates through the formation in a generally lateral or horizontal direction and the heated solvent and mobilised hydrocarbon is recovered via the production well of an adjacent second SAGD well pair. This method is described as cross flow since the solvent enters and leaves the formation via different SAGD well pairs. This method also has the significant advantage that no new wells need to be drilled into the formation which is economically highly beneficial. It also has the further advantage that the distance between the incoming colder solvent and the outgoing hotter solvent is greater than in the above method. This is beneficial in the method of the invention

In the methods of the present invention heated solvent and mobilised hydrocarbon is preferably recovered via SAGD production wells. In further preferred methods steam and/or light hydrocarbons are optionally recovered through vent wells, e.g. vertical vent wells

The method of the present invention is conducted on selected formations that are partially depleted of recoverable hydrocarbon. In preferred methods of the invention the selected formation is depleted of hydrocarbon that is recoverable economically by a thermal recovery method. In the methods of the invention, further hydrocarbon recovery occurs. Further hydrocarbon is recovered via productions wells.

The method of the invention may, for example, be started during the wind down stage of production. The wind down period for a formation is the later period of economic production. This is particularly beneficial since it is during this stage that hydrocarbon recovery is least economical. The method of the invention, however, can make it worthwhile continuing the recovery operation for a much longer period of time.

The method of the present invention may be advantageously combined with a steam-based method of recovering hydrocarbon, particularly heavy hydrocarbon, from a hydrocarbon containing subterranean formation. In such methods the thermal recovery method is conducted and then further heavy hydrocarbon is recovered by the methods of the present invention. Advantageously this means that a higher proportion of heavy hydrocarbon present in the formation is recovered and energy demand is decreased. DESCRIPTION OF THE DRAWINGS

Figure 1 shows a schematic of a typical SAGD recovery operation and the heat losses that occur therein;

Figure 2(a) shows a schematic of a cross-section of a formation comprising a SAGD well arrangement prior to SAGD;

Figure 2(b) shows a schematic of a cross-section of a formation comprising a

SAGD well arrangement after SAGD has been carried out; and

Figure 3 shows a schematic of a cross-section of a formation after the method of the invention is carried out and illustrating a well arrangement suitable for carrying out the method of the invention. DETAILED DESCRIPTION OF THE DRAWINGS

Figure 1 shows a schematic of a typical SAGD recovery operation. Thus steam is generated in a Once Through Steam Generator (OTSG) using natural gas as the fuel. The steam is injected into a formation through an injection well and hydrocarbon is recovered, along with water, through a production well. The most significant energy consumption occurs during the generation of steam. Some of the energy in the steam is returned in the sense that the steam transfers its heat to heavy hydrocarbon that is then produced at the surface. A larger proportion of the energy in the steam is, however, lost. Heat losses occur at the surface in the OTSGs and in the processing facilities (e.g. separator) and flow lines. The vast majority of heat losses, however, occur subsurface. The most significant subsurface heat losses are heat that is stored in the reservoir (sometimes referred to as accumulated heat) and heat lost to the cap rock, overburden and area of formation below the hydrocarbon containing formation. In some cases heat is also lost to thief zones.

Referring to Figures 2a and 2b, they show a cross section of a reservoir comprising SAGD well pairs. Figure 2a shows the reservoir shortly after SAGD is started whereas Figure 2b shows the reservoir towards the end of the SAGD process.

A covering of overburden 1 lies above the hydrocarbon-containing portion of the reservoir 2. The well arrangement comprises pairs of two horizontal wells. Each group of two wells is typically referred to as a well pair or a SAGD well pair. Each SAGD well pair 3, 4 comprises an injector well 5, 6 and a producer well 7, 8. The vertical separation (arrow a) between each well pair is about 5 m. The horizontal separation (arrow b) between each well pair is about 100 m. The injector wells 5, 6 are at the same depth in the reservoir and are parallel to each other. Similarly the producer wells 7, 8 are at the same depth in the reservoir and are parallel to each other. The producer wells are preferably provided with a liner (not shown) as is conventional in the art.

In Figure 2a steam has been injected into injector wells 5, 6 thus heated areas 9, 10 around each of the injector wells have been formed. In these areas the latent heat from the steam is transferred to the hydrocarbon and, under gravity, it drains downwards to producer wells 7, 8.

Referring to Figure 2b, it shows a cross section of the same reservoir, but much later on in the SAGD process, typically 2-5 years after the initial steam injection. In Figure 2b, the mobilised zones of each SAGD well pair have merged to form a mobilised zone 1 1 that connects the SAGD well pairs. Any hydrocarbon that was present in this mobilised zone will have been heated and its viscosity reduced. It will drain downwards, under gravity, to the producer wells 7, 8. Because steam naturally rises, however, it does not contact an area that exists between the injection wells 5, 6 and producer wells 7, 8. Thus a wedge of hydrocarbon-containing reservoir 12 is bypassed by the steam. This means that hydrocarbon present in this area is not recovered. Figure 2b represents a suitable formation for carrying out the method of the invention.

Figure 3 shows a schematic cross-section of a formation 2 illustrating a well arrangement suitable for carrying out the method of the invention. Figure 3 also shows the formation 2 after the method of the invention has been carried out.

In the method of the present invention a solvent, e.g. a d-₈ hydrocarbon, is injected into an injection well 5 of a first SAGD well pair. At the surface the solvent is in the form of a saturated vapour. As the solvent enters the formation, however, it is superheated by the steam chamber 1 1 that surrounds the production well. Once the solvent enters the formation 2 it is further heated by the steam chamber and more significantly by the heat accumulated in the formation 2. Once solvent injection is carried out, the formation is optionally shut in for a suitable time to allow the formation to heat the solvent.

The solvent in vapour form tends to permeate through the formation (dotted arrows) towards the wells 6, 8 of an adjacent SAGD well pair. Lateral movement through the formation may be optimised by injection of a displacement gas (e.g. C0₂, N₂) through the same well 5 as the solvent. During permeation through the formation, the solvent contacts the heavy hydrocarbon in the region 12 in between the SAGD well pairs. The solvent heats the heavy hydrocarbon and mixes with it thereby mobilising the heavy hydrocarbon. The mobilised heavy hydrocarbon and solvent permeate to the production well of an adjacent SAGD well pair from where it is pumped to the surface.

The hybrid method of the present invention, e.g. hybrid SAGD-solvent injection method, includes the following advantages:

i) Using the formation to superheat the solvent is energy efficient since it uses energy that would otherwise be lost to the formation.

ii) It means the overall amount of hydrocarbon recovered from a formation is increased and total energy demand is reduced.

iii) The ability to produce superheated solvent. There is so much heat remaining in a formation post-SAGD that solvents will be superheated. This is highly advantageous because it improves and accelerates the miscibility of the solvent with the heavy hydrocarbon and the solvents ability to drive hydrocarbon towards producer wells.

iv) The depleted reservoir is left at a much lower temperature compared to a traditional SAGD method. Thus the energy losses to the formation are much lower.

v) Solvent injection can be targeted towards the heavy oil located in between SAGD well pairs

vi) The solvent type and/or injection rate can be varied to control the production rate and reservoir temperature.

vii) The solvent may be injected into the pre-existing injection wells of the SAGD well pairs (i.e. no new drilling is required). Mobilised hydrocarbon is recovered from the pre-existing production wells of the SAGD well pairs viii) Solvent injection and steam injection can be alternated to optimise sweep and hydrocarbon recovery with the use of significantly less steam.

Claims

CLAIMS:

1. A method of recovering heavy hydrocarbon from a partially depleted heavy hydrocarbon containing formation comprising:

i) selecting a formation that has been partially depleted of hydrocarbon by a thermal recovery method for at least 1 year;

ii) injecting solvent into said partially depleted heavy hydrocarbon formation, wherein said solvent has a first temperature;

2. A method as claimed in claim 1 , wherein said thermal recovery method has been carried out on said selected formation for 2 to 5 years.

3. A method as claimed in claim 1 or 2, wherein said selected formation has a production rate by the thermal recovery method which is in decline.

4. A method as claimed in any one of claims 1 to 3, wherein said selected formation has a temperature that is at least 100 °C higher than the temperature of the formation prior to starting the thermal recovery method.

5. A method as claimed in any one of claims 1 to 4, wherein said selected formation has a temperature that is 150-500 °C higher than the temperature of the formation prior to starting the thermal recovery method.

6. A method as claimed in any one of claims 1 to 5, wherein said formation has been depleted of heavy hydrocarbon by a thermal recovery method selected from steam assisted gravity drainage, cyclic steam stimulation, steam flooding and in situ combustion.

7. A method as claimed in any one of claims 1 to 6, wherein said thermal recovery method comprises injection of steam into said formation.

8. A method as claimed in claim 7, wherein steam injection is ceased prior to injection of said solvent.

9. A method as claimed in any one of claims 1 to 8, wherein said solvent is a hydrocarbon.

10. A method as claimed in claim 9, wherein said solvent is a C₃-₅ hydrocarbon.

11 . A method as claimed in any one of claims 1 to 10, wherein the said solvent is in the form of a saturated vapour at the point of injection into said formation.

12. A method as claimed in any one of claims 1 to 1 1 , wherein said solvent is superheated by said formation.

13. A method as claimed in claim 12, wherein the difference in temperature between the first temperature and the superheated temperature of said solvent is 10 to 500 °C.

14. A method as claimed in any one of claims 1 to 13, further comprising a step of injecting a displacement gas into said formation.

15. A method as claimed in any one of claims 1 to 14, further comprising a step (v) of steam injection.

16. A method as claimed in claim 15, wherein said solvent and steam injection are repeatedly alternated.

17. A method as claimed in any one of claims 1 to 16, wherein said formation has been depleted of hydrocarbon by steam assisted gravity drainage.

18. A method as claimed in claim 17, wherein said formation comprises at least one SAGD well pair.

19. A method as claimed in claim 18, wherein said solvent is injected into said depleted formation through the injection well or production well of said SAGD well pair.

20. A method as claimed in claim 18 or 19, wherein said mobilised and diluted hydrocarbon is recovered through the production well of a SAGD well pair.

21 . A method as claimed in claim 20, wherein said production well is in a second adjacent SAGD well pair.

22. A method of recovering heavy hydrocarbon from a heavy hydrocarbon containing subterranean formation comprising:

(ii) recovering further heavy hydrocarbon by a method as defined in any one of claims 1 to 21 .