FIELD OF THE INVENTION

The present invention relates to a method and system for recovering thermal energy from a subterranean formation depleted of hydrocarbon. The invention is also concerned with a method of recovering hydrocarbon from hydrocarbon containing subterranean formations and with an arrangement for such a recovery.

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 C0 ₂ emissions which occur. Of course it has already been recognised in the energy industry that C0 ₂ emissions must be managed better.

Attempts were made in the sixties and seventies to reduce the amount of energy that is required for thermal hydrocarbon recovery methods. US 3,258,069, for example, discloses a method of discovering and using over-pressured water-bearing reservoirs containing aqueous liquids at pressures and/or temperatures that yield useful energy. The method involves completing a well into the identified reservoir and recovering the liquid. The liquid may be used to perform different types of work including hydrocarbon recovery. In this case a tubing string is positioned in the formation to transport the superheated water from the over-pressured reservoir to the hydrocarbon-containing part of the formation. The heat of the water reduces the viscosity of the hydrocarbon and its pressure provides a drive force to displace the hydrocarbon from the formation.

In US 4,078,608 a slightly different strategy is employed whereby a formation is used to heat water that is introduced into it. US 4,078,608 discloses a method of recovering hydrocarbon wherein an aqueous fluid comprising water is injected into a second formation having a higher temperature than the first hydrocarbon-containing formation, recovering the heated aqueous fluid and then injecting the hot water into the first hydrocarbon-containing formation to displace viscous hydrocarbon toward the production well and thereby to the earth's surface. The second formation used to carry out the heating in US 4,078,608 is generally at a greater depth than the formation from which hydrocarbon is primarily extracted.

US 3,679,264 also discloses a similar approach. It describes the possibility of recovering hot liquids or gases from a deeper formation and transporting it to a less deep hydrocarbon containing formation to assist oil recovery therefrom as well as the possibility of injecting water into a deep, hot formation to generate hot water for oil recovery from another formation.

There is, however, a major drawback to all of these methods. They require at least one additional well to be drilled into the formation and this well must generally be at a significant depth, generally much deeper than wells drilled for hydrocarbon recovery operations. The drilling of such wells is extremely expensive. As a result, as far as the Applicant is aware, this approach has not been utilised in any commercial SAGD operation.

Rather oil producers, in recent times, have instead looked for alternative and cheaper sources of fuel to replace or supplement natural gas for steam generation. It has been suggested, for instance, that asphaltenes and/or coke recovered from heavy hydrocarbon may be combusted to generate steam.

A need, however, still exists for methods of generating thermal energy for hydrocarbon recovery processes such as SAGD which are less demanding in terms of fuel consumption. Methods that additionally reduce the amount of C0 ₂ emissions would naturally be particularly beneficial given the commitments already made by the energy sector to achieve this. SUMMARY OF THE INVENTION

Viewed from a first aspect, the present invention provides a method of recovering thermal energy from a subterranean formation depleted of hydrocarbon comprising:

i) selecting a formation that has been depleted of hydrocarbon by a thermal recovery method;

ii) injecting a fluid into said depleted hydrocarbon formation, wherein said fluid has a first temperature;

iii) allowing the formation to heat said fluid;

iv) recovering said fluid from said depleted hydrocarbon formation, wherein said fluid has a second temperature which is higher than said first temperature; and

v) recovering energy from said fluid having a second temperature.

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

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

(ii) recovering thermal energy from said formation by a method as hereinbefore defined,

wherein further hydrocarbon production occurs during step (ii).

Viewed from a further aspect, the present invention provides a method of recovering hydrocarbon from a hydrocarbon containing subterranean formation comprising: conducting a steam based thermal recovery method in said formation to recover hydrocarbon, wherein at least some of the steam is generated by energy recovered by the method as hereinbefore defined.

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

(i) conducting a steam based thermal recovery method in said formation to recover hydrocarbon;

(ii) recovering thermal energy from a formation by a method as hereinbefore defined;

(iii) generating steam from said recovered thermal energy; and

(iv) providing said steam to said steam based thermal recovery method. Viewed from a further aspect, the present invention provides a system for recovering thermal energy from a subterranean formation depleted of hydrocarbon comprising:

i) a means for injecting a fluid into a depleted hydrocarbon formation;

ii) a means for recovering said fluid from said formation; and

iii) a means for recovering energy from said fluid recovered from said formation, wherein said means for recovering energy is fluidly connected to said means for recovering fluid.

Viewed from a further aspect, the present invention provides an arrangement for recovering hydrocarbon from a hydrocarbon containing subterranean formation comprising;

(i) an arrangement for conducting a thermal recovery method; and

(ii) a system for recovering thermal energy as hereinbefore defined. DETAILED DESCRIPTION OF THE INVENTION

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.

The method of the present invention recovers 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 reservoir structure. The method of the present invention comprises selecting a formation that has been depleted of hydrocarbon by a thermal recovery method and injecting a fluid into the depleted hydrocarbon formation. The fluid has a first temperature at the point of injection into the formation. The method, however, further comprises allowing the formation to heat the fluid. In other words energy originally derived from, e.g. steam or in situ combustion and stored in the formation is transferred from the heated formation into the fluid. Thus when the fluid is recovered from the depleted hydrocarbon formation the fluid has a second temperature which is higher than the first temperature. This temperature increase represents the energy that is recovered. As described below, the energy may be extracted from the fluid in a number of different ways. Preferably the energy is used in steam generation.

The method of the present invention may be applied to any formation that has been depleted of hydrocarbon by a thermal recovery method. Such methods are characterised by the fact that the formation is itself heated by operation of the recovery method. In the method of the invention the formation has preferably been depleted of hydrocarbon by steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), steam flooding, hot solvent injection or in situ combustion (ISC). Particularly preferably the formation has been depleted of hydrocarbon by steam assisted gravity drainage or in situ combustion, especially steam assisted gravity drainage. These methods heat the formation to a significant extent.

The fluid used in the present invention may be any fluid that is inert to the formation. As used herein the term fluid encompasses liquids, vapours, gases and supercritical vapour. Preferably the fluid is a liquid. More preferably the fluid is an aqueous liquid, e.g. water. Particularly preferably the water comprises water recovered during a prior hydrocarbon recovery operation, e.g. water separated from hydrocarbon in a bulk separator. In a bulk separator a hydrocarbon and water mixture recovered from a formation is separated to yield separated hydrocarbon and separated water. The separated water predominantly comprises water but generally also contains impurities such as hydrocarbon and dissolved organics and inorganics. The separated water is optionally cleaned prior to use in the method of the invention. Conventional cleaning methods may be used. An advantage of the method of the invention is therefore that the water, can be recycled and hence the amount of fresh water required is minimised.

In the method of the present invention, heat is transferred from a depleted formation to the fluid, e.g. water. The temperature of the formation should therefore be higher than the temperature of the injected fluid, 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 fluid is 5 to 500 °C, more preferably 10 to 200 °C and still more preferably 15 to 150 °C. Preferably the temperature of the selected formation depleted of hydrocarbon into which the fluid 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 fluid in the method of the invention.

In preferred methods of the invention the first temperature of the fluid, at the point of injection (e.g. at atmospheric pressure) is 10 to 150 °C, more preferably 30 to 120 °C and still more preferably 50 to 100 °C. The temperature of the fluid is increased in the method of the invention by contact with the hotter formation. After injection into the formation, the fluid permeates through the formation. Since the formation has previously been depleted by a thermal recovery method, the formation is relatively permeable. Thus the fluid 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.

In preferred methods of the invention the injected fluid moves through the formation in a generally lateral or horizontal direction. Particularly preferably the fluid is injected via the injection well of a first SAGD well pair, moves through the formation in a horizontal direction to the production well of an adjacent SAGD well pair from which the heated fluid is recovered. The movement of the injected fluid from the injection well of a first SAGD well pair to the production well of an adjacent second SAGD well pair is referred to as cross flow.

In some methods of the present invention the fluid circulates through the formation continuously. In other methods, the fluid is shut into the formation for a period of time.

After circulation through the formation, the fluid has a second temperature that is higher than its first temperature at the point of injection. Preferably the difference between the first and second temperatures of the fluid is 10 to 500 °C, more preferably 20 to 300 °C and still more preferably 40 to 200 °C, e.g. at atmospheric pressure. Preferably the fluid has a second temperature of 100 to 500 °C, more preferably 105 to 300 °C and still more preferably 1 10 to 220 °C, e.g. at atmospheric pressure. The greater the temperature difference between the fluid returning from the formation and the fluid injected into the formation the greater the amount of energy that has been recovered from the formation.

In the method of the present invention, energy is recovered from the fluid that is circulated through the formation. The method of energy recovery depends on a number of factors including the temperature of the fluid recovered. When the fluid returning from the formation has a temperature exceeding 170 °C, e.g. at atmospheric pressure, the energy is preferably recovered in a heat exchanger. The heat exchanger may be, for example, an evaporator (e.g. an evaporator heating boiler feed water). Conventional commercially available evaporators may be used. In the heat exchanger, e.g. evaporator, the fluid having the second temperature heats feedwater to generate steam. Cooled fluid is simultaneously produced. Preferably the cooled fluid is recycled by injection into the hot depleted hydrocarbon formation. The fluid therefore circulates throughout the method in a loop. The fluid, at a first temperature, is injected into the formation and heated to a second temperature, then the fluid heats feedwater (e.g. in a heat exchanger) and in this process the fluid is cooled and then is reinjected into the formation.

When the fluid recovered from the formation has a temperature below boiler feed water temperature, e.g. is between 50 and 200 °C or 50 and 165 °C, the energy is preferably recovered in a heat pump. Preferably the heat pump comprises a first heat exchanger. Preferably the heat pump further comprises a second heat exchanger. Preferably one heat exchanger is an evaporator. Preferably the other heat exchanger is a condenser. Preferably the heat pump also comprises a working fluid that circulates between the two heat exchangers. Conventional heat pumps and working fluids known in the art may be used.

In a method of the invention employing a heat pump the fluid heated by the depleted formation and having a second temperature preferably heats (e.g. evaporates) a working fluid of the heat pump to generate heated working fluid and cooled fluid. Preferably the cooled fluid is recycled by injection into the depleted hydrocarbon formation. The heated working fluid is preferably compressed. In a second heat exchanger the heated working fluid, preferably compressed heated working fluid, preferably heats feedwater to generate steam and cooled working fluid (e.g. condensed working fluid). Preferably the cooled working fluid is expanded. This reduces its temperature so it can absorb further energy from further heated fluid recovered from the formation. Preferably the cooled working fluid is recycled by transportation to the first heat exchanger where it is heated (e.g. evaporated) by further fluid recovered from the depleted formation and having a second temperature.

In the methods of the present invention the steam produced in the heat exchanger, e.g. evaporator, is preferably pressurised. Conventional equipment may be used to carry out pressurisation. The pressure of the steam is preferably increased to the level required for injection into a hydrocarbon containing subterranean formation to produce hydrocarbon during a recovery operation from a depleted reservoir. Preferably the steam is injected into a hydrocarbon containing formation to recover hydrocarbon.

The method of the present invention is particularly useful when the depleted formation has been depleted of hydrocarbon by SAGD. 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. During hydrocarbon recovery steam is injected into the upper injection well, flows outward, contacts the hydrocarbon above it, condenses and transfers its latent heat to the hydrocarbon and the formation. This heating reduces the viscosity of the hydrocarbon, its mobility increases and it flows due to gravity to the lower production well from where it can be produced.

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 fluid may be injected into the formation in a number of different ways.

The fluid may, for example, be injected into the depleted formation through the injection well of a first SAGD well pair. Optionally the heated fluid 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 fluid is recovered from the formation via the production well of a second adjacent SAGD well pair. Thus the fluid is injected into the formation via the injection well of a first SAGD well pair, the fluid permeates through the formation in a generally lateral or horizontal direction and the heated fluid is recovered via the production well of an adjacent second SAGD well pair. This method and system is described as cross flow since the fluid 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 fluid and the outgoing hotter fluid is greater than in the above method and system. This is beneficial in the method of the invention

Alternatively the fluid may be injected into the depleted formation through a vertical well located at the toe of the SAGD well pair. Such a vertical well will not typically be present during a SAGD operation and is preferably drilled into the formation once SAGD is completed or at least nearly completed. Preferably the vertical well is positioned so that it overlies the toe of the SAGD well pair. Particularly preferably the vertical well is positioned so that its end is above the height of the horizontal section of the injection well of the SAGD well pair. Preferably the vertical well is located at the top of the depleted reservoir. The fluid injected into the formation through the vertical well permeates through the formation towards the vertical section of the SAGD production well. The distance between the incoming colder fluid and the outgoing hotter fluid is significant and this is beneficial in the method of the invention.

Alternatively the fluid may be injected into the depleted formation through at least one vertical well located near the top of the formation. Such vertical wells will not typically be present during a SAGD operation and are preferably drilled into the formation once SAGD is completed or at least nearly completed. Preferably a plurality of vertical injection wells is used. Preferably the vertical injection wells are relatively short and terminate in the upper part of the production zone of the depleted formation. Preferably the vertical wells are aligned with, and positioned above, the horizontal section of the injection well of the SAGD well pair. Preferably the end of each of the vertical injection wells is above the height of the injection well of the SAGD well pair. The advantage of this method is that the fluid travels through a significant portion of the depleted, hot formation. On the other hand, the drilling of a plurality of new vertical injection wells is expensive.

In a further alternative method the fluid is optionally injected into the depleted formation through a well present in a formation adjacent to, and in fluid communication with, the depleted formation. The well may be, for example, a vertical well or a well in a SAGD well pair, e.g. an injection well of a SAGD well pair.

In the methods of the present invention steam and/or light hydrocarbons are optionally recovered through vent wells, e.g. vertical vent wells. Hydrocarbon is optionally recovered via SAGD production wells. The method of the present invention is also particularly useful when the depleted formation has been depleted of hydrocarbon by ISC. In ISC at least one, e.g. a row, of vertical injection wells are drilled into the reservoir. Preferably a row of vertical vent wells, laterally spaced from the injection wells so that the rows of injection wells and rows of vent wells are parallel, is also drilled into the reservoir. A production well is also drilled in the reservoir and is preferably aligned with, and positioned below, the row of injection wells. The production well is preferably located in a lower region of the hydrocarbon-bearing formation.

Thus in a preferred method of the present invention the depleted formation comprises an injection well, preferably a row of injection wells, and a production well, preferably a horizontal well underlying the injection wells. Preferably the fluid (i.e. the fluid for extracting thermal energy) is injected into the formation through at least one injection well. Preferably the fluid is recovered through the production well.

The method of the present invention may be conducted on a formation which has been completely depleted of recoverable hydrocarbon by thermal recovery methods. In other methods of the invention the formation is only partially depleted of recoverable hydrocarbon. In the methods of the invention, further hydrocarbon recovery preferably occurs. Further hydrocarbon is preferably recovered via productions wells.

The method of the invention may, for example, be started during the wind down stage of production. Advantageously hydrocarbon production occurs during the method of the invention. 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. If hydrocarbon is recovered it is preferably separated from the fluid recovered from the formation, e.g. in a separator, prior to entry of the fluid into a heat exchanger.

The method of the present invention may also be advantageously combined with a steam-based method of recovering hydrocarbon, particularly heavy hydrocarbon mixtures, from a hydrocarbon containing subterranean formation. A heavy hydrocarbon mixture 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 hydrocarbon mixtures 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 mixture 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°, e.g. about 7.5-9°.

In such methods the energy recovered in the above-described method of the invention is used to generate steam which, in turn, is used in the method of recovering hydrocarbon. More preferably the method of recovering hydrocarbon from a hydrocarbon containing subterranean formation comprises:

(i) conducting a steam based thermal recovery method in the formation to recover hydrocarbon;

(ii) recovering thermal energy from a depleted formation by a method as hereinbefore defined;

(iii) generating steam from the recovered thermal energy; and

(iv) providing the steam to the steam based thermal recovery method.

In the above method, the steam based recovery method is preferably conducted on a different formation to the formation used in the recovery of thermal energy. The recovery of thermal energy by the method of the invention has the significant advantage that the amount of steam that needs to be generated from a fuel such as natural gas is greatly reduced. This in turn means that the cost of generating steam and the amount of C0 ₂ emissions associated with this process are reduced.

Preferably the steam based thermal recovery method is SAGD. SAGD is preferably carried out using conventional equipment and under conventional conditions. Thus preferably the steam is injected into a hydrocarbon containing formation via an injection well of a SAGD well pair. Preferably mobilised hydrocarbon mixture is recovered by pumping it from a production well of a SAGD well pair.

The present invention also relates to a system for recovering thermal energy from a subterranean formation. The system comprises:

i) a means for injecting a fluid into a depleted hydrocarbon formation;

ii) a means for recovering the fluid from the formation; and

iii) a means for recovering energy from the fluid recovered from the formation.

The fluid may be described as a heat extracting fluid since it removes heat from the formation and brings it to the surface where it may be recovered.

The means for recovering energy from the fluid is fluidly connected to the means for recovering the fluid. Since the depleted formation is permeable and permits the flow of fluid therethrough, the means for injecting a fluid is in fluid communication with the means for recovering the fluid from the formation. Preferably the depleted hydrocarbon formation comprises at least one SAGD well pair and still more preferably at least two SAGD well pairs. Preferably the means for injecting fluid is selected from a vertical well located at the toe of the SAGD well pair, the injection well of the SAGD well pair, at least one vertical well located near the top of the formation and a well present in a formation adjacent to, and in fluid communication with, said depleted hydrocarbon formation. More preferably the means for injecting fluid is selected from a vertical well located at the toe of the SAGD well pair and the injection well of the SAGD well pair. Still more preferably the means for injecting fluid is the injection well of the SAGD well pair.

Preferably the means for recovering the fluid from the formation is the producer well of the SAGD well pair. Still more preferably the means for recovering the fluid from the formation is the producer well of an adjacent second SAGD well pair.

Preferably the means for injecting fluid having a first temperature is the injection well of a first SAGD well pair and the means for recovering the fluid having a second temperature is the production well of a second adjacenet SAGD well pair.

In another preferred system the depleted hydrocarbon formation comprises a well arrangement for in situ combustion. Preferably the means for injecting fluid is the injection well, e.g. vertical injection well, of the ISC well arrangement. Preferably the means for recovering the fluid is the production well of the ISC well arrangement. Preferably the production well comprises a horizontal section that underlies the vertical injection well.

In the system of the present invention the means for recovering energy is preferably a heat exchanger and still more preferably an evaporator. Suitable evaporators are commercially available. Preferably the heat exchanger, e.g. evaporator, comprises:

(i) a first inlet for feedwater, preferably fluidly connected to a separator;

(ii) a first outlet for steam;

(iii) a second inlet fluidly connected to the means for recovering fluid from the formation; and

(iv) a second outlet for cooled fluid;

wherein the first inlet is fluidly connected to the first outlet and wherein the second inlet is fluidly connected to the second outlet.

When heated fluid is recovered from the formation it is transported into the heat exchanger via the second inlet wherein it heats the feedwater also entering the heat exchanger via the first inlet. In this process the feedwater is converted to steam and the fluid is cooled, i.e. heat transfer occurs between the two media. The second outlet for cooled fluid is preferably fluidly connected to the means for injecting a fluid into a depleted hydrocarbon subterranean formation, i.e. the cooled fluid is preferably recycled by reinjection into the depleted formation for reheating. Preferably the first outlet for steam is fluidly connected to a steam compressor. Preferably the first outlet for steam is fluidly connected to a well arrangement in a hydrocarbon containing subterranean formation.

In a further preferred system of the present invention the means for recovering energy comprises a heat pump. Preferably the heat pump comprises at least a first and second heat exchanger, e.g. an evaporator and a condenser. Further heat exchangers may optionally be present. Preferably the heat pump further comprises a working fluid. Suitable heat pumps are commercially available.

Preferably the heat pump comprises:

(A) a first heat exchanger comprising:

(i) a first inlet for cooled working fluid;

(ii) a first outlet for heated working fluid;

(iii) a second inlet fluidly connected to the means for recovering fluid from the formation; and

(iv) a second outlet for cooled fluid;

wherein said first inlet is fluidly connected to the first outlet and wherein the second inlet is fluidly connected to the second outlet; and

(B) a second heat exchanger comprising:

(v) a first inlet for feedwater;

(vi) a first outlet for steam;

(vii) a second inlet for heated working fluid fluidly connected to the first outlet of the first heat exchanger; and

(viii) a second outlet for cooled working fluid fluidly connected to the first inlet of the first heat exchanger;

wherein the first inlet is fluidly connected to the first outlet and wherein the second inlet is fluidly connected to the second outlet.

When the heated fluid is recovered from the formation, it is transported into the first heat exchanger via the second inlet wherein it heats the working fluid of the heat pump also entering the first heat exchanger via the first inlet. In this process the working fluid is heated and the fluid deriving from the formation is cooled, i.e. heat transfer occurs between the two media. The cooled fluid is preferably fluidly connected to the means for injecting a fluid into a depleted hydrocarbon subterranean formation, i.e. the cooled fluid is preferably recycled by reinjection into the depleted formation for reheating. The heated working fluid is preferably transported to a second heat exchanger wherein it heats feedwater also entering the second heat exchanger via the first inlet. Preferably the first inlet for feedwater in the second heat exchanger is fluidly connected to a separator. In the second heat exchanger the feedwater is converted to steam and the heated working fluid is cooled, i.e. heat transfer occurs between the two media. The cooled working fluid is preferably transported to the first inlet for cooled working fluid in the first heat exchanger wherein it is reheated with fluid recovered from the depleted formation. Preferably the first outlet for steam is fluidly connected to a steam compressor. Preferably the first outlet for steam is fluidly connected to a well arrangement in a hydrocarbon containing subterranean formation.

A preferred system of the present invention further comprises an expansion valve in between the second outlet for cooled working fluid of the second heat exchanger and the inlet for cooled working fluid of the first heat exchanger. A further preferred system comprises a compressor in between the first outlet for heated working fluid of the first heat exchanger and the second inlet for heated working fluid of the second heat exchanger. This enables the temperature of the working fluid to be heated by the fluid contacting the depleted formation to be controlled. Further preferred systems of the invention optionally comprise one or more further expansion valves and/or compressors that are required to regulate the temperature and pressure of the system. Optionally temperature and/or pressure monitors are included in the system.

The present invention further relates to an arrangement for recovering hydrocarbon from a hydrocarbon containing subterranean formation comprising;

(i) an arrangement for conducting a thermal recovery method; and

(ii) a system for recovering thermal energy as hereinbefore defined.

Further preferred arrangements further comprise a means for transporting the steam generated using the thermal energy recovered in the system into another well arrangement present in a hydrocarbon-containing formation. Such means typically comprises piping, optionally insulated piping.

Preferred arrangements comprise SAGD and ISC well arrangements.

Yet further preferred arrangements further comprise at least one Once Through Steam Generator (OTSG). In such arrangements the steam generated in the thermal recovery method of the present invention is combined with steam generated in the OTSG prior to injection into a hydrocarbon containing subterranean formation.

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 method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior SAGD operation;

Figure 2(b) shows a schematic of a method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior SAGD operation;

Figure 2(c) shows a schematic of a formation comprising a plurality of SAGD wells operating in a cross flow arrangment;

Figure 2(d) shows a schematic of a method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior SAGD operation and a further additional vertical well has been drilled into the formation at the toe of the SAGD well pair for injection of fluid;

Figure 2(e) shows a schematic of a method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior SAGD operation and a number of additional vertical wells have been drilled into the formation having ends located near the top of the formation;

Figure 2(f) shows a schematic of a method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior ISC operation;

Figure 3 shows a schematic of a system of the present invention for recovering thermal energy from a subterranean formation; and

Figure 4 shows a schematic of a system of the present invention for recovering thermal energy from a subterranean formation.

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.

Figure 2(a) shows a schematic of a method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior SAGD operation. Thus the method and system comprise a subterranean formation 1 that has previously been depleted of hydrocarbon by a SAGD operation. The formation 1 therefore comprises a SAGD well pair comprising an injection well 2 and a producer well 3. The formation also comprises vent wells 9 for recovery of steam and/or light hydrocarbons.

Water, which is transported from a bulk separator 4 receiving hydrocarbon and water from a hydrocarbon recovery operation, is injected into the formation through the injection well 2 where it is then heated by the depleted formation. The temperature of the formation is typically 50-600 °C whereas the temperature of the fluid is typically 5- 200 °C, thus the formation heats the water. The permeability of the formation is relatively high as hydrocarbon recovery has already occurred therefrom. The water can therefore flow through the formation to the production well 3 underlying the injection well 2. The water is recovered from the depleted hydrocarbon formation through the producer well 3 and transported to an evaporator 5. The evaporator 5 is located above the earth's surface. In the evaporator the hot water heats feedwater received from separator 4 to generate steam which exits the evaporator and passes to steam compressor 6 where it is pressurised. The steam is then combined with steam from an OSTG 8 and injected into a hydrocarbon containing formation 7 to recover hydrocarbon. The heating of the feedwater cools the water returned from the formation and the cooled water is recycled through line 10 into the injection well of the SAGD well pair and therefrom into the depleted hydrocarbon formation where it is then reheated by the formation.

Figure 2(b) shows a schematic of a preferred method and system of the present invention. Again the hydrocarbon formation has been depleted by a prior SAGD operation. Those features of Figure 2(b) that are shared with Figure 2(a) have been given the same reference numbers. The difference between Figures 2(a) and (b) is in the well arrangement used to inject and recover the water. In Figure 2(b) the water is injected into the formation through an injection well 2 of a first SAGD well pair 2, 3. The water pemeates through the formation in a generally lateral or horizontal direction (as shown by the dashed lines) and is heated by contact with the formation. The heated water is recovered from the formation via a production well 10 of an adjacent second SAGD well pair 10, 1 1 . This method and system is sometimes referred to as cross flow since the water is injected into the formation via a first SAGD well pair and recovered from the formation via a second adjacent SAGD well pair. In a particularly preferred method and system of the present invention a plurality of SAGD well pairs operate in cross flow. A preferred cross flow system is shown diagrammatically in Figure 2(c). In Figure 2(c) the dark circles represent SAGD well pair injection wells that are used for injection of fluid and the open circles with a dark perimeter represent SAGD well pair production wells that the heated fluid is recovered from.

Figure 2(d) shows a schematic of an alternative method and system of the present invention. Again the hydrocarbon formation has been depleted by a prior SAGD operation. Those features of Figure 2(d) that are shared with Figure 2(a) have been given the same reference numbers. The difference between Figures 2(a) and (d) is in the well arrangement used to inject and recover the water. In Figure 2(d) the water is injected into the formation through a new vertical well 2' located at the toe of the SAGD well pair. Again the water can flow through the permeable formation to the production well 3 from where the water is recovered. Typically the injection well of the SAGD well pair is closed. Alternatively it may additionally be used to recover heated water, e.g. by installing a pump therein.

Figure 2(e) shows a schematic of an alternative method and system of the present invention wherein again the hydrocarbon formation has been depleted by a prior SAGD operation. As above those features of Figure 2(e) that are shared with Figures 2(a) have been given the same reference numbers. The difference between Figures 2(a) and 2(e) is in the well arrangement used to inject and recover the water. In Figure 2(e) the water is injected into the formation through a plurality of vertical wells 2" located at the top of the formation. The water flows through the permeable formation, and due to the effect of gravity, will flow to producer well 3 from where the water is recovered. The water injected into the formation in this arrangement typically is in contact with the formation for a longer period of time than in the arrangements in Figures 2(a) and 2(d) due to the greater distance between the vertical injection wells at the top of the formation and the underlying producer well. A draw back of this arrangement, however, is that a number of new wells need to be drilled into the formation which is an expensive operation. Figure 2(f) shows a schematic of an alternative method and system of the present invention wherein the hydrocarbon formation has been depleted by a prior ISC operation. As above, those features of Figure 2(f) that are shared with Figure 2(a) have been given the same reference numbers. The difference between Figures 2(a)- (e) and Figure 2(f) is in the well arrangement present in the formation. In Figure 2(f) vertical well 1 1 is used to inject water and the L-shaped producer well 12 is used to recover the water. In other ISC arrangements the producer well is vertical. The temperature of the formation following an ISC operation is typically much higher than after a SAGD operation so typically more thermal energy may be recovered therefrom.

Figure 3 shows a schematic of a system of the present invention for recovering thermal energy from a subterranean formation. The energy recovered is used to generate steam. The system comprises a heat exchanger, specifically an evaporator 51 in which the heated water recovered from the formation heats feedwater to generate steam and cooled water. The cooled water is recycled by injection into the hydrocarbon depleted formation.

More specifically the system comprises a first inlet for feedwater 52, a first outlet for steam 53, a second inlet 54 fluidly connected to the means for recovering water from the formation and a second outlet for cooled water 55. The first inlet 52 is fluidly connected to the first outlet 53 and the second inlet 54 is fluidly connected to the second outlet 55. The first inlet 52 for feedwater is fluidly connected to a separator (shown in Figures 2) which receives produced water from a hydrocarbon recovery operation. The first outlet 53 for steam is fluidly connected to a steam compressor (shown in Figures 2) which increases the steam pressure to a level appropriate for injection into a hydrocarbon containing formation during a hydrocarbon recovery operation. Thus the first outlet 53 for steam is fluidly connected, either directly or indirectly, to a well arrangement in a hydrocarbon containing subterranean formation (shown in Figures 2). The second outlet 55 for cooled water is fluidly connected to the means for injecting a fluid into a depleted hydrocarbon subterranean formation.

Figure 4 shows a schematic of a further system of the present invention for recovering thermal energy from a subterranean formation. Again the energy recovered is used to generate steam. The system is a heat pump 100. The heat pump 100 comprises as a first heat exchanger an evaporator 101 in which the heated water recovered from the formation heats a working fluid of the heat pump to generate heated working fluid and cooled water. The cooled water is recycled by injection into the depleted hydrocarbon formation wherein it is heated again. The heated working fluid is compressed in compressor 102 and is transported to a second heat exchanger which is condenser 103. In condenser 103 the heated working fluid heats feedwater to generate steam and cooled working fluid. The cooled working fluid is recycled by transportation to the first heat exchanger of the heat pump where it is heated by the water recovered from the formation.

More specifically the heat pump 100 comprises a first heat exchanger 101 comprising a first inlet 104 for cooled working fluid, a first outlet 105 for heated working fluid, a second inlet 106 fluidly connected to the means for recovering water from the formation and a second outlet 107 for cooled water that is fluidly connected to the means for injecting water into the depleted formation. The first inlet 104 is fluidly connected to the first outlet 105. The second inlet 106 is fluidly connected to the second outlet 107. The heat pump also comprises a second heat exchanger 103 comprising a first inlet 108 for feedwater, a first outlet 109 for steam, a second inlet 1 10 for heated working fluid, fluidly connected to the first outlet 105 of the first heat exchanger, and a second outlet 1 1 1 for cooled working fluid, fluidly connected to the first inlet 104 of the first heat exchanger. The first inlet 108 is fluidly connected to the first outlet 109 and the second inlet 1 10 is fluidly connected to the second outlet 1 1 1 . The first inlet 108 for feedwater in the second heat exchanger 103 is fluidly connected to a separator. The first outlet 109 for steam in the second heat exchanger 103 is fluidly connected to a steam compressor. The second outlet 107 for cooled water is fluidly connected to the means for injecting the water into a depleted hydrocarbon formation

The heat pump further comprises an expansion valve 1 12 in between the second outlet 1 1 1 for cooled working fluid of the second heat exchanger 103 and the inlet 104 for cooled working fluid of the first heat exchanger. The heat pump further comprises a compressor 102 in between the first outlet 105 for heated working fluid of the first heat exchanger 101 and the second inlet 1 10 for heated working fluid of the second heat exchanger 103.