GB2520719A

GB2520719A - Producing hydrocarbons by circulating fluid

Info

Publication number: GB2520719A
Application number: GB1321043.0A
Authority: GB
Inventors: Erling Rytter; Arne Grislingas
Original assignee: Statoil ASA
Current assignee: Equinor ASA
Priority date: 2013-11-29
Filing date: 2013-11-29
Publication date: 2015-06-03
Also published as: GB201321043D0

Abstract

A system and method for producing hydrocarbons from a subsurface formation includes an injection well 4 disposed in the formation 2, the injection well 4 arranged to inject acirculation fluid. A production well 3 is also disposed in the formation for producing hydrocarbons. A fracture 6 is provided in the formation to provide a communication channel between the injection well 4 and the production well 3, thereby allowing injected circulation fluid to pass from the injection well 4 to the production well 3. The reservoir is heated and the heat may be provided by the circulation fluid or by heaters. Circulation fluid may be separated from production fluid following production

Description

Producing hydrocarbons by circulating fluid

TECHNICAL FIELD

The present invention relates to the field of producing hydrocarbons.

BACKGROUND

In order to improve the efficiency of extracting hydrocarbons from subterranean formations, it is known to inducing and/or extend existing fractures and cracks in the subterranean formation. Fractures may extend many meters and tens or even hundreds of meters from a main wellbore from which they originate.

As hydrocarbon-bearing formations are often disposed substantially horizontally, in many cases it is preferred to use horizontal drilling and f racking operations (inducing fractures in the formation) may be carried out on a single well. This may be accomplished by, for example, retracting open slots in a liner along the borehole. A common method to induce fractures is by hydraulic fracturing. In this case, a fluid is pumped into the formation via the wellbore at high pressures. The pressure can be up to around 600 bar, or in some cases even higher. The first fractures may be created by the use of explosive materials, and these are extended by the high pressure fluid. The most commonly used fracking fluid is water with added chemicals and solid particles.

Typically the solids, termed proppants, make up 5-15 volume % of the fracking fluid, chemicals make up 1-2 volume % and the remainder is water.

Other fracking fluids include freshwater, saltwater, nitrogen, CO2 and various types of hydrocarbons, e.g. alkanes such as propane or liquid petroleum gas (LPG), natural gas and diesel. The fracking fluid may also include substances such as hydrogen peroxide, propellants (typically monopropellants), acids, bases, surfactants, alcohols and the like.

Considering the case where the fracking fluid is LPG, in order for LPG gas to be suitable for use in fracking of wells, it is necessary to form it into a gel it so that, among other properties, it may transport proppants. A gel consistency is required to maintain a suitable proppant dispersion. An advantage of this technology is the simplicity in disposal of the fracking fluid. After the fracking operation, the LPG reverts from a gel to a gas and escapes the borehole during decompression, leaving proppants in the fractures in order to hold the fractures open and prevent them from closing.

Furthermore, during the change from (gel-like) liquid to gas form, the LPG volume increases greatly, thereby increasing the pressure in the formation and further extending fractures. It is thought that recovered LPG gas is suitabe for reuse.

Compared to many other methods of hydraulic fracking, the method based on LPG does not leave chemical substances in the soil, and also reduces the effect of reflux.

The chemicals added may comprise viscosifier agents and/or cross-linked polymers, often from natural vegetation like cellulose, that enhance the fracking fluid's ability to transport proppants into the reservoir and the fractures. Some chemicals also reduce the friction between the fracking fluid being pumped and the well conduits. Examples of suitable gelling agents are hydroxypropyl guars (of ionic or non-ionic type) and polyacryl imides. The fracking fluid may also be an emulsion created by mixing water with a liquid hydrocarbon. Another fracking fluid option is to form a foam, resulting from aeration of gels containing 70-80% of gas. After a fracking operation, the fracking fluid is returned, at least in part, back to the surface for reuse or disposal. This operation creates issues with handling the added chemicals and also with handling large amounts of water (where the fracking fluid is water-based). After the fracturing operation the tracking fluid normally includes bacteria and hydrogen sulphide, which need to be safely handled.

The cost of the proppant may be up to 10 % of the drilling costs. A single well may require 1,600 tons ot proppant. As described above, the function of the proppant is to assist in keeping the fractures open after fracturing when the pressure from the fracking fluid is removed. Commonly used proppants are sand particles consisting mainly of silica or quartz, or ceramic particles, e.g. of titania or a-alumina made by heating loam, clay, kaolin or bauxite, the latter to temperatures above 1100CC.

Proppants may be coated particles, in which case the particles contain a thin outer layer of a polymer resin that help in reducing the drag forces during production and to make the surface hydrophobic to prevent blocking by adsorbed water. This prevents agglomeration of the proppant particles and improves dispersion in the fracking fluid.

A typical size of the proppants particles is a diameter of around 0.5 to 2 mm. It is preferred that each particle is approximately spherical and that the size distribution of the particles is reasonably uniform to enable easy flow of the particles. The compressive strength of the particles must be very high in order for them to keep fractures open without being crushed.

Note that hydraulic fracturing is not the only means to stimulate hydrocarbon production in a subterranean reservoir. Other techniques include acid stimulation to dissolve part of the formation rock (typically carbonates like nahcolite), and steam injection in the steam assisted gravity drainage (SAGD) technique.

Hydrocarbons that can benefit from heat treatment are typically bitumen, e.g. in oil sands, heavy oil, extra heavy oil, tight oil: kerogen and coal. Oils are often classified by their API gravity, and a gravity below 22.3 degrees is regarded as heavy, and below 10.0°API as extra heavy. Bitumen is typically around 8°API.

Shale reservoirs are hydrocarbon reservoirs formed in a shale formation, often denoted as shale oil, shale gas or oil shale. It can be difficult to extract the hydrocarbons from shale reservoirs because the shale formation is of low porosity and low permeability, and so fluid hydrocarbons may not be able to find a path through the formation towards a production well. This means that when a well is drilled into the formation, only those fluid hydrocarbons in proximity to the well are produced, as the other hydrocarbons further away from the well have no easy path to the well through the relatively impermeable rock formation. In order to improve hydrocarbon recovery from shale formations, the shale around the well is often hydraulically fractured. This involves propagating fractures through the shale formation using a pressurized fluid to create conduits in the impermeable shale formation. Hydrocarbon fluids can then migrate through the conduits toward the production well. In this way, recovery of hydrocarbons from the reservoir is improved because hydrocarbons that would not previously be able to reach the well now have a path to the well and can be produced.

The term oil shale" refers to a sedimentary rock interspersed with an organic mixture of complex chemical compounds collectively referred to as "kerogen". The oil shale consists of laminated sedimentary rock containing mainly clay minerals, quartz, calcite, dolomite, and iron compounds. Oil shale can vary in its mineral and chemical composition. When the oil shale is heated to above 260-370 CC, destructive distillation of the kerogen (a process known as pyrolysis), occurs to produce products in the form of oil, gas, and residual carbon. The hydrocarbon products resulting from the destructive distillation of the kerogen have uses that are similar to other petroleum products. Oil shale is considered to have potential to become one of the primary sources for producing liquid fuels and natural gas, to supplement and augment those fuels currently produced from other petroleum sources.

Prior art in situ processes for recovering hydrocarbon products from oil shale resources describe treating the oil shale in the ground in order to recover the hydrocarbon products. These processes involve the circulation or injection of heat and/or solvents within a subsurface oil shale. Heating methods include hot gas injection, e.g. flue gas or methane or superheated steam, hot liquid injection, electric resistive heating, dielectric heating, microwave heating, or oxidant injection to support in situ combustion.

Permeability enhancing methods are sometimes utilized including; rubblization, hydraulic fracturing, explosive fracturing, heat fracturing, steam fracturing, and/or the provision of multiple wellbores.

Heating fluids can be one of several types. Often a molten salt is used, such as a nitrate or carbonate salt, or a mixture of such salts. An example of a heating fluid is a mixture of 60% NaNO3 and 40% KNO3 with a melting point of 220CC. This mixture can be heated to 450-650CC, preferably between 550-600°C, before being piped into to the reservoir. The return temperature at the surface for reheating is typically around 250- 500CC, preferably 300-450°C. Other classes of suitable salts include carbonates, halides or other well-known anions.. The counterion (cation) should be environmentally benign, essentially in the form of alkali, alkaline earth elements or sink. A further option is imidazolium based counterion if a low melting temperature is required. In general, a large size counterion gives a low melting point due to reduced coulomb interactions. A low melting point of the molten or ionic salt will ease operation as provisions to avoid solidification and blocking of pipes, flanges and the like will be simplified or not necessary at all. Further, intermittent operations will be possible by letting the liquid salt to be at a standstill in the reservoir. A low melting point will be required if the hydrocarbon can be extracted at a moderate temperature, say below 300, 250 or even 200 CC. The use of molten salts as a heat transfer fluid for heating a subsurface formation has been described in US 7,832,484, which also includes several examples of such salts. Note that it is also possible, with due consideration of cracking effects, to use a hydrocarbon as heating medium. The hydrocarbon can be in a gaseous or liquid form.

The heating fluid is returned to the surface. In the surface facilities, the heating fluid is reheated after having been cooled down in the reservoir formation. Furthermore, it may be necessary to remove unwanted impurities in the heating fluid that have been picked up in the reservoir. Certain aspects of U-shaped wellbores containing heating fluid in a closed loop heating system have been described in WO 2006/116096.

A problem with heating formations is that it can take a great deal of time to heat a formation to a suitable temperature (for example, to initiate pyrolysis of kerogen, or to sufficiently reduce the viscosity of viscous hydrocarbons). Heating operation can take many months or years. One reason for this is that the rocks and hydrocarbons in the formation act as effective insulators, and so heat distribution in the formation is not even. Long heating operations require a large energy consumption.

SUMMARY

It is an object to provide systems, methods and apparatus for improving the efficiency of hydrocarbon production operations in subterranean reservoirs.

According to a first aspect, there is provided a system for producing hydrocarbons from a subsurface formation. An injection well is disposed in the formation, the injection well arranged to inject a circulation fluid. A production well is also disposed in the formation for producing hydrocarbons. A fracture is provided in the formation to provide a communication channel between the injection well and the production well, thereby allowing injected circulation fluid to pass from the injection well to the production well.

The reservoir is heated.

Optionally, a separator is connected to the production well for separating produced hydrocarbon from circulation fluid. The separator optionally separates any of at least 10%, at least 30%, at tleast 60% and at least 80% of the produced hydrocarbon from the circulation fluid.

Heating is optionally provided using heaters that do not contain circulation fluid.

As an option, heating is provided by any of electrical heaters, microwave heaters or heaters containing a heating fluid.

The circulation fluid may itself be a heating fluid for heating the reservoir.

As an option, the system further comprises apparatus for heating the circulation fluid obtained from the separator and returning the heated circulation fluid to the injection well.

Examples of hydrocarbons in the subsurface formation include any of kerogen, coal, bitumen and oil.

As an option, the subsurface formation has a low permeability.

As an option, the subsurface formation comprises more than 50% shale by volume.

The injection well and the production well are optionally substantially horizontal in the subsurface formation, although it will be appreciated that they may be at any optimal angle depending on the location of the hydrocarbons to be produced and constraints of the formation.

An optional example of a circulation fluid is a molten salt. For example, the circulation fluid may be selected from any of a nitrate, a carbonate, an environmentally benign counterion and an imidazolium based counterion.

As an alternative option, the circulation fluid comprises any of a hydrocarbon based fluid, a mineral oil, an aromatic based fluid, a silicon based fluid, a hydrogen donor fluid and a wholly or partially hydrogenated naphthalene or substituted naphthalene.

As an option, the circulation fluid is selected so as to perform any of at east partially oxidizing the hydrocarbon, at least partially dissolving the hydrocarbon and at least partially expanding the hydrocarbon.

As a further option, the circulation fluid may comprise a gas. Examples of such fluids include any of a natural gas, a liquid petroleum gas, propane, flue gas, exhaust gas, nitrogen, carbon dioxide and steam.

The circulation fluid is optionally also used as a fracking fluid.

The system optionally further comprises a plurality of production wells connected by at least one fracture to at least one injection well.

Optional ratios of injection wells to production wells are in a range selected from any of three or lower, two or lower, and between 0.5 and 1.5.

The system may comprise a plurality of production wells and a plurality of injection wells, the production wells and injection wells being arranged in a pattern throughout the subsurface formation to optimize production of hydrocarbons.

The system optionally further comprising a computer device arranged to control conditions of injection, production and heating, conditions selected from at least a temperature of circulation fluid and/or temperature of optional heating wells, a pressure of circulation fluid in the injection well, a flow rate of circulation fluid in the injection well, a pressure of produced hydrocarbon in the production well, and an amount of circulaton fluid recovered from the separator for returning to the injection well.

Proppants are optionally disposed in the fracture to maintain the fracture dimensions.

As a further option, the proppants are chemically inert with respect to hydrocarbons and the circulation fluid.

As an option, the circulation fluid comprises a conductivity agent comprising a chemical compound or particles arranged to form a conductive layer on an inner surface of the fracture.

As an option, at least a portion of the wellbore lining comprises a material having any of a high corrosion rate, a low melting temperature and a susceptibility to oxidation in the presence of the circulation fluid. This is because during the circulation operation, a direct contact is required between the wellbore and the fractures, and so a portion of the lining that oxidizes, melts or corrodes can allow this.

According to a second aspect, there is provided a method of producing hydrocarbons from a subsurface formation. The method includes the following steps: disposing an injection well disposed in the formation; disposing a production well in the formation; forming a fracture in the formation to provide a communication channel between the injection well and the production well; injecting a circulation fluid from the injection well into the formation such that at least a portion of the circulation fluid passes through the fracture; producing a mixture of hydrocarbons and circulation fluid into the production well; separating the produced hydrocarbons from the produced circulation fluid.

At least part of the produced circulation fluid is optionally returned to the injection well.

The method optionally includes any of at least partially oxidizing the hydrocarbon using the circulation fluid, at least partially dissolving the hydrocarbon in the circulation fluid, and at least partially expanding the hydrocarbon using the circulation fluid.

As an option, the method includes providing a plurality of production wells and a plurality of injection wells, and arranging the production wells and injection wells in a pattern throughout the subsurface formation to optimize production of hydrocarbons.

The method optionally comprises controlling conditions of injection and production, conditions being selected from at least a temperature of circulation and/or heating fluid, a pressure of circulation fluid in the injection well, a flow rate of circulation fluid in the injection well, a pressure of produced hydrocarbon in the production well, and an amount of circulation fluid recovered from the separator for returning to the injection well.

The method optionally comprises injecting a plurality of proppants into the fracture to maintain the fracture dimensions.

According to a third aspect, there is provided a computer device comprising a processor for controlling the system as described in the first aspect, a memory and an interface connecting the computer with the system.

According to a fourth aspect, there is provided a computer program comprising computer readable code which, when run on a computer device causes the computer device to control a system as described above in the first aspect.

According to a fifth aspect, there is provided a computer program product comprising a non-transitory computer readable medium and a computer program as described above in the fourth aspect, wherein the computer program is stored on the non-transitory computer readable medium.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 illustrates schematically a cross section view of a subterranean formation and a production facility; Figure 2 illustrates a cross section view of a subterranean formation comprising an injection well and a production well; FigureS is a flow diagram showing exemplary steps; Figure 4 illustrates schematically in a block diagram an exemplary computer device.

DETAILED DESCRIPTION

As described above, providing heat to a formation containing hydrocarbons reduces the viscosity of the hydrocarbons and allows it to flow through the formation and into a production tubular more easily. Furthermore, sufficient heat for a sufficient length of time can give rise to the pyrolysis of the hydrocarbon, e.g. of kerogen. As the heat capacity is high and the thermal conductivity is low, it can take up to three years to heat a hydrocarbon containing formation to a temperature of around 350 Cc, and the substantially heated zone at that temperature will only extend for 2 to 3 metres around the heat source in the heating well. Further limitations to heating of a formation include the maximum temperature of the heating fluid, and the diameter of the heating well.

In order to maximize the volume of the formation that is heated, it is possible to drill multiple heating wells in proximity to each other. However, horizontal drilling, completion, and additional handling of hot fluid are costly operations that should be kept to a minimum. The inefficiency of the heat transfer and heat losses to the surrounding formation leads to high energy consumption. As the energy for heating commonly comes from fossil fuel sources, the amount of CO2 generated in extracting hydrocarbons in this way is much greater than that required for production of conventional oil.

It is proposed to provide fractures in a reservoir extending between an injection well and a production well and to allow a fluid to pass from the injection well through the fractures and into the production well by a forced convection mechanism. It has been found that significant improvements to the efficiency of production of hydrocarbons from the formation can be made in this way.

Figure 1 illustrates the principles. In the following example, the circulation fluid is itself a heating fluid. It will be appreciated that the circulation fluid may not provide heating, in which case heating is provided by an alternative method such as electrical heating, microwave heating, or use of a separate heating fluid.

A production facility 1 is located at a surface above a hydrocarbon-bearing formation 2.

A production well 3 and an injection well 4 are drilled through the formation 2. In this example, the wells are horizontal but it will be appreciated that the wells may be of any angle suitable for the shape of the formation 2. A source of circulation fluid 5 is provided at the production facility 5. A series of fractures 6 is provided extending between the injection well 4 and the production well 3. Circulation fluid flows from the circulaton fluid source 5 into the injection well 4, passes through the fractures 6 and into the production well 3. Optionally, not shown in the figure, part of the circulation fluid can be returned to the surface by extension of the injection well, that is a portion of the circulaton fluid is not going through the formation. A combination of produced hydrocarbons and circulation fluid flows through the production well 3 back to the production facility 1. A separator 7 may be provided to separate the circulation fluid from the hydrocarbons. Separated circulation fluid may be passed back to the source of heating fluid 5 for reheating and reinjection into the injection well 4. A controller B is also provided for controlling the process, as described in more detail below.

Figure 2 shows a more detailed view of an area of the formation around the injection well 4 and the production well 3. A number of fractures 6 containing proppants 9 extend between the wells 3, 4 and also out into the formation. These fractures 6 effectively increase the surface area of the formation that is exposed to the circulation fluid, thereby making the process of heating the formation much more efficient. The basic concept of improving heating of the formation in this way applies irrespective of the number, shape or types of fractures and proppants used, or the direction or distance between the different fractures and wells.

In the example of Figure 2, circulation fluid has a clear path between the injection well 4 and the production well 3 through the larger shaded fractures 6 shown. A much larger surface area of the formation is therefore in proximity to the circulation fluid, and so heating becomes much more efficient.

In the system described herein, the circulation fluid will push or carry hydrocarbons from the formation and into the production well 3 where a combination of produced hydrocarbons and heating fluid is returned to the surface. This gives the option of using a circulation fluid that also helps dissolve or react with the hydrocarbon in the reservoir. Optionally, reaction with the hydrocarbons can be the main objective of the fluid that is circulating through the fracks. It is an advantage to use a circulation fluid that easily can be separated into the desired produced hydrocarbon and the circulation fluid.

The technique is summarized in Figure 3. The following numbering corresponds to that of Figure 3: Si. An injection well 4 is drilled into the formation.

S2. A production well 3 is drilled into the formation.

S3. If no or few natural fractures exist, a fracking operation may be performed to induce or extend fractures 6 and ensure that some fractures 6 extend substantially between the injection well 4 and the production well 3.

S4. Circulation fluid is injected into the fractures 6 from the injection well 4.

S5. The circulation fluid passes through the fractures 6 in the formation, heating the formation around the fractures.

S6. Circulation fluid enters the production well 3 from the fractures 6, carrying with it any produced hydrocarbons.

S7. A mixture of hydrocarbons and circulation fluid is returned to the production facility 1. Produced hydrocarbons are separated from the circulation fluid.

SB. Recovered circulation fluid is returned to the injection well.

The following examples are provided in order to demonstrate the improvements in heating efficiency that passing heating fluid through a fracture in a formation can give.

The example above assumes that the circulation fluid provides the heat. It will be appreciated that heat may be provided by different means, in which case circulation fluid is used primarily to carry produced hydrocarbons towards the production well and to provide any required treatment to the reservoir.

Table 1 below shows a computation of the theoretical heating time shown with the addition of one or more fractures between an injection well and production well, where the circulation fluid is used as a heating fluid. It can be seen that the time used to heat the same formation volume diminishes significantly as a function of heating surface by adding fractures. It is assumed that the fractures essentially are parallel to the well directions, connecting the wells, allowing a system with convection between wells and that the heating surface limits the possible heat input. It can be expected that the fracking pattern and the connection between the injection wells and the production well are not ideal and so Table 1 includes columns with only 15 % efficiency. Reduced efficiency can come from non-ideal connection between the heater and producer along the total length of the wells and from transport restrictions of heating fluid in the narrow fracks. However, it is apparent that the time needed to heat the reservoir can be reduced from around three years to around four months just by providing two fractures between the production well and injection well and allowing convection of heating fluid from injection to to production wells.

The data of Table 1 only considers the time needed to heat the formation based on the available heating surface and is independent of the detailed distribution of injection and production wells.

Table 1. Heating efficiency for conventional heaters compared to added fracture heating surface.

Heater Heater Theoretical Heater Effective surface/rn heating tirne surface:15 % heating tirne (m2) (weeks) efficiency of (weeks) the fracture surface Wells with hot fluid 0.5 150 0.5 + 1 diagonal frack 12.5 6 2.3 33 + 2 diagonal fracks 24.5 3 4.1 18 + 3 diagonal fracks 36.5 2 5.9 13 + 4 diagonal fracks 48.5 1.5 7.7 10 It can be seen frorn Table 1 that injecting a heating fluid through fractures between an injection well and a production well greatly improves the efficiency of heating for the sarne volume of forrnation. Interestingly there is also an incentive to reduce the nurnber of heating wells per producer as long as one can assure convective heating between injector and producer. It should be understood that the present estimates can be improved by performing a proper reservoir simulation.

The system described above is suitable for the production of most types of hydrocarbon, such as kerogen, coal, and oil. it is particularly suitable for use in a forrnation that has a low permeability, such as a shale formation, or a forrnation that contains a significant arnount of shale (for example, more than 50% by volume).

Any suitable circulation/heating fluid may be used. Molten salts are particularly suitable, such as carbonate, nitrates or mixtures of carbonates and nitrates.

Furthermore, salts that contain a benign counterion or an imidazolium based counterion are suitable. Alternative circulation/heating fluids include a hydrocarbon based fluids, mineral oils, aromatic based fluids, silicon based fluids, hydrogen donor fluids and wholly or partially hydrogenated naphthalene or substituted naphthalenes.

To further improve the efficiency of production, a circulation fluid may be chosen that can partially oxidize the hydrocarbon in the formation. A circulation fluid may also be selected in which the hydrocarbon is at least partially soluble in order to improve the mobility of the hydrocarbon. In this way hydrocarbons may dissolve in the circulation fluid and be carried to the production facility via the production well in solution. This may be particularly suitable for hydrocarbons which would otherwise be too viscous to produce. Furthermore, a circulation flud may be selected that can at least partially expand the hydrocarbon by dissolving part of the circulation fluid.

Another type of suitable circulation fluid s a gas, such as natural gas, liquid petroleum gas, propane, flue gas, exhaust gas, nitrogen, carbon dioxide and steam. A gas has the added advantage that convection in very small f racks is facilitated. Furthermore, certain gases like LPG, CO2 and N2 car be used as fracking fluid, thereby simplifying operation.

Figure 4 illustrates schematically in a bock diagram an exemplary controller 8 in the form of a computer device. The controller is provided with a processor 10 for executing instructions and sending them via an interface 11 to components of the system. For example, the processor might receive measurements from the system such as readings of the temperature of the circulation or heating fluid or formation, the pressure of heating fluid or circulation fluid, the amount of recovered circulation flud mixed with hydrocarbon, and on the basis of user input 12 or rules stored in a database 13, take corrective action. A non-transitory computer readable medium in the form of a memory 14 may also be provided that can be used to store the database 13. It may also be used to store a computer program 15 which, when executed by the processor, causes the controller 8 to control the system. Note that the computer program 15 may be provided from an external non-transitory computer readable medium in the form of a memory 16, such as a DVD disk, a flash drive and so on.

The techniques described above may be applied to the production of different types of hydrocarbon, such as oil, gas, shale oil, bitumen, kerogens, coal and so on. It should be understood that the term "hydrocarbon" present in the subterranean formation is used in a broad meaning of the term, i.e. not only covering material and compounds that strictly is composed of hydrogen and carbon atoms, but also to a larger or smaller extent contains heteroatoms that typically are oxygen, sulphur or nitrogen, but also minor amounts of phosphorous, mercury, vanadium, nickel, iron or other elements can be present. In situ catalytic reactions and/or heat treatment may modify the composition of the hydrocarbon product. The term hydrocarbon product" is also used in a broad sense to cover products that contain heteroatoms, in particular oxygen. This hydrocarbon product will often be further treated in one or more processing steps to give a secondary or final product, e.g. to be shipped to a refinery or sold to a consumer. The hydrocarbon product may contain alcohols, in particular phenols or other aromatic compounds with attached alcohol groups.

It will be appreciated by the person of skill in the art that various modifications may be made to the above-described embodiments without departing from the scope of the present invention.

Claims

CLAIMS: 1. A system for producing hydrocarbons from a subsurface formation, the system comprising: an injection well disposed in the formation, the injection well arranged to inject a circulaton fluid; a production well disposed in the formation for producing hydrocarbons; a fracture in the formation providing a communication channel between the injection well and the production well, thereby allowing injected circulation fluid to pass from the injection well to the production well; and heating the reservoir.
2 The system according to claim 1, further comprising a separator connected to the production well for separating produced hydrocarbon from circulation fluid.
3. The system according to claim 2, wherein the separator separates any of at least 10%, at least 30%, at least 60% and at least 80% of the produced hydrocarbon from the circulation fluid and substantially returns the rest to the injection well.
4. The system according to any one of claims 1 to 3, wherein the reservoir is heated at least in part by heaters that do not contain circulation fluid.
5. The system according to any one of claims 1 to 4, wherein heating the reservoir is at least in part by heaters selected from electrical heaters, microwave heaters and heaters containing a heating fluid.
6. The system according to any one of claims ito 5, wherein the circulation fluid is a heating fluid for heating the subsurface formation.
7. The system according to claim 2, further comprising apparatus for heating the circulaton fluid obtained from the separator and returning the heated circulation fluid to the injection well.
8. The system according to claim 1 to 7, wherein the hydrocarbon in the subsurface formation is selected from any a! kerogen, coal, and oil.
9. The system according to any of claims 1 to 8, wherein the subsurface formation has a low permeability.
10. The system according to any of claims 1 toY, wherein the subsurface formation comprises more than 50% shale by volume.
11. The system according to any of claims 1 to 10, wherein the injection well and the production well are substantially horizontal in the subsurface formation.
12. The system according to any of claims 1 to 11, wherein the circulation fluid comprise a molten salt.
13. The system according to claim 12, wherein the circulation fluid is selected from any of a nitrate, a carbonate, an environmentally benign counterion and an imidazolium based counterion.
14. The system according to any of claims 1 to 11, wherein the circulation fluid comprises any of a hydrocarbon based fluid, a mineral oil, an aromatic based fluid, a silicon based fluid, a hydrogen donor fluid and a wholly or partially hydrogenated naphthalene or substituted naphthalene.
15. The system according to any of claims 1 to 11, wherein the circulation fluid is selected so as to perform any of at least partially oxidizing the hydrocarbon, at least partially dissolving the hydrocarbon and at least partially expanding the hydrocarbon.
16. The system according to any of claims 1 to 11, wherein the circulation fluid comprises a gas.
17. The system according to claim 16, wherein the circulation fluid is selected from any of a natural gas, a liquid petroleum gas, propane, flue gas, exhaust gas, nitrogen, carbon dioxide and steam.
18. The system according to any of claims 1 to 17, wherein the circulation fluid is used as a fracking fluid.
19. The system according to any of claims ito 18, further comprising a plurality of production wells connected by at least one fracture to at least one injection well.
20. The system according to claim 19, wherein a ratio of injection wells to production wells is in a range selected from any of three or lower, two or lower, and between 0.5 and 1.5.
21. The system according to any of claims ito 20, further comprising a plurality of production wells and a plurality of injection wells, the production wells and injection wells being arranged in a pattern throughout the subsurface formation to optimize production of hydrocarbons.
22. The system according to any of claims 1 to 21, further comprising a computer device arranged to control conditions of injection and production, conditions selected from at least a temperature of circulation and/or a heating fluid, a pressure of circulaton and/or heating fluid in the injection well, a flow rate of circulation and/or heating fluid in the injection well, a pressure of produced hydrocarbon in the production well, and an amount of circulation and/or heating fluid recovered from the separator for returning to the injection well.
23. The system according to any of claims 1 to 22, further comprising proppants disposed in the fracture to maintain the fracture dimensions.
24. The system according to claim 23, wherein the proppants are chemically inert with respect to hydrocarbons and the circulation fluid.
25. The system according to any of claims 1 to 24, wherein the circulation fluid comprises a conductivity agent comprising a chemical compound or particles arranged to form a conductive layer on an inner surface of the fracture.
26. The system according to any of claims 1 to 25, wherein at least a portion of the wellbore lining comprises a material having any of a high corrosion rate, a low melting temperature and a susceptibility to oxidation in the presence of the circulation fluid.
27. A method a! producing hydrocarbons from a subsurface formation, the method comprising: disposing an injection well disposed in the formation; disposing a production well in the formation; forming a fracture in the formation to provide a communication channel between the injection well and the production well; injecting a circulation fluid from the injection well into the formation such that at least a portion of the circulation fluid passes through the fracture; producing a mixture of hydrocarbons and circulation fluid into the production well; separating a substantial part of the produced hydrocarbons from the produced circulaton fluid.
28. The method according to claim 27, further comprising returning the produced circulaton fluid to the injection well.
29. The method according to claim 27 or 28, further comprising any of: at least partially oxidizing the hydrocarbon using the circulation fluid; at least partially dissolving the hydrocarbon in the circulation fluid; and at least partially expanding the hydrocarbon using the circulation fluid.
30. The method according to any of claims 27 to 29, further comprising providing a plurality of production wells and a plurality of injection wells, and arranging the production wells and injection wells in a pattern throughout the subsurface formation to optimize production of hydrocarbons.
31. The method according to any of claims 27 to 30, further comprising controlling conditions of injection, production and heating, conditions being selected from at least a temperature of circulation fluid and/or temperature of optional heaters, a pressure of circulaton fluid in the injection well, a flow rate of circulation fluid in the injection well, a pressure of produced hydrocarbon in the production well, and an amount of circulation fluid recovered from the separator for returning to the injection well.
32. The method according to any of claims 27 to 31, further comprising injecting a plurality of proppants into the fracture to maintain the fracture dimensions.
33. A computer device comprising: a processor for controlling the system according to any of claims ito 26; a memory; an interface connecting the computer with the system.
34. A computer program, comprising computer readable code which, when run on a computer device causes the computer device to control a system according to any of claims ito 26.
35. A computer program product comprising a non-transitory computer readable medium and a computer program according to claim 34, wherein the computer program is stored on the non-transitory computer readable medium.