WO2015067556A1

WO2015067556A1 - Functionalized proppants

Info

Publication number: WO2015067556A1
Application number: PCT/EP2014/073557
Authority: WO
Inventors: Erling Rytter; Arne GRISLINGÅS
Original assignee: Statoil Petroleum As
Priority date: 2013-11-06
Filing date: 2014-11-03
Publication date: 2015-05-14
Also published as: GB201319558D0; GB2520019A

Abstract

A proppant particle for use in hydrocarbon production using a tracking operation on a subterranean formation comprising kerogen and/or oil shale, the proppant particle comprising a plurality of pores. The proppant particle has a surface area of at least 5 m²/g and further comprising at least one treatment chemical sorbed to at least part of a solid surface of the pores. There is also disclosed a method of producing hydrocarbons from a subterranean formation comprising any of kerogen and oil shale using the proppant particles.

Description

Functionalized proppants

TECHNICAL FIELD The present invention relates to the field of proppants. 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 tracking 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 tracking fluid is water with added chemicals and solid particles. Typically the solids, termed proppants, make up 5-15 volume % of the tracking fluid, chemicals make up 1 -2 volume % and the remainder is water. The use of proppants is illustrated in Figure 1 , in which an injection well 1 for performing a tracking operation is provided. After the tracking operation, fractures 2 appear in the formation. Proppant particles 3 (the fractures and the proppants are not shown to scale in Figure 1 as they relatively are much smaller than the wellbore) remain in the fracture 2 and help to hold the fracture 2 open when there is no more pressure from the tracking fluid.

As already mentioned, the solid particles that are carried by the tracking fluid are often called a proppant. The cost of the proppant can be up to 10 % of the drilling costs and, as an example; 1600 tons of proppants may be used in a single well. Use of proppants is expected to double the next ten years from today's demand of around 22 million tons (201 1 ). The function of the proppant is to assist in keeping the tracks open after fracturing when the pressure is released. The proppants used today are most commonly sand particles consisting mainly of silica or quartz, ceramic particles, e.g. of titania or a-alumina made by heating loam, clay, kaolin or bauxite, the latter to temperatures above 1 100 °C, or coated particles. The coated proppants contain a thin outer layer of a polymer resin that help in reducing the drag forces during production like making the surface hydrophobic to prevent blocking by adsorbed water. A typical size of the proppant particles is in the 10-30 mesh range or 0.5 to 2 mm. The shape should be close to spherical and the size distribution reasonably uniform to provide easy flow of the particles. It is self-evident that the strength of the particles must be very high in order for the cracks to stay open. Solid catalyst particles or monopropellants are examples of other solid particles that under certain operations can be advantageous to introduce into the tracks.

Other tracking fluids besides water include freshwater, saltwater, nitrogen, C0₂ and various types of hydrocarbons, e.g. alkanes such as propane or liquid petroleum gas (LPG), natural gas and diesel. The tracking fluid may also include substances such as hydrogen peroxide, propellants (typically monopropellants), acids, bases, surfactants, alcohols and the like.

Considering the case where the tracking fluid is LPG, in order for LPG gas to be suitable for use in tracking of wells, it is necessary to form it into a gel 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 tracking fluid. After the tracking operation, the LPG reverts from a gel to a gas during decompression and escapes the borehole, 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 suitable for reuse. Compared to many other methods of hydraulic tracking, 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 tracking fluid's ability to transport proppants into the reservoir and the fractures. Some chemicals also reduce the friction between the tracking 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 tracking fluid may also be an emulsion created by mixing water with a liquid hydrocarbon. Another tracking fluid option is to form a foam, resulting from aeration of gels containing 70-80% of gas. After a tracking operation, the tracking 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 tracking fluid is water-based). After the fracturing operation, the tracking fluid normally includes bacteria and hydrogen sulphide, which need to be safely handled. Once the tracking fluids have been removed, many proppant particles remain in the fractures in the subterranean formation.

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 low viscosity or low mobility hydrocarbons such as 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 ^<€, 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.

Known 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.

In some cases it is beneficial to add treatment chemicals to the subterranean formation to treat the hydrocarbon that is to be produced, or a chemical that interacts with the rock or creates an added pressure. For example, where the hydrocarbon is viscous, it may be desired to add a diluent or emulsifier to reduce its viscosity, or a solvent to partially dissolve the hydrocarbon. Another example is a chemical that reacts with the hydrocarbon to divide large molecules into smaller molecules that more easily can be transported out of the reservoir. A further example is to use an explosive that upon detonation creates additional tracks in the formation. A further possibility is to use a liquid chemical that is prone to evaporate in the tracks and may create a local overpressure that helps produce the hydrocarbons. Adding such chemicals is a further step that requires an additional injection operation, and significant amounts of expensive chemicals may be needed.

US 7,598,209 discloses porous particles for use in well treatment, but these are typically used in proximity to the well rather than in tracks, and are not suitable for treating oil shale or kerogen formations.

SUMMARY It is an objective to provide a method for providing treatment chemicals to a reservoir formation. It has been discovered that it possible to introduce such chemicals into the tracks in the reservoir using the pores of a porous proppant without an additional injection operation, and with the potential to reduce the amount of chemicals used as the chemicals are brought directly to the tracks containing or in proximity to the hydrocarbons.

According to a first aspect, there is provided a proppant particle for use in hydrocarbon production using a tracking operation on a subterranean formation comprising kerogen and/or oil shale, the proppant particle comprising a plurality of pores. The proppant particle has a surface area of at least 5 m²/g and further comprising at least one treatment chemical sorbed to at least part of a solid surface of the pores. An advantage of this is that it allows a treatment chemical to be dispersed throughout the fractures, and to remain in the formation after the fracturing operation. As an option, the porous proppant particle is formed from any of alumina, zirconium toughened alumina, silicon (oxy) carbide, silicon nitride, stabilized zirconia, alumina spinel, and carbon nanofibres disposed on a core particle.

The proppant particle optionally has a density in the range of a group selected from below 2.0 g/cm³, below 1 .6 g/cm³, below 1 .2 g/cm³, and equal to or below 0.9 g/cm³.

As an option, the proppant particle has a porosity in the range of a group selected from at least 25 volume%, at least 50 volume %, and at least 70 volume %.

In an optional embodiment, the proppant particle has a compressive strength in the range of a group selected from at least 30 MPa, at least 80 MPa and at least 170 MPa. As an option, the porous proppant particle has a surface area greater than 30 m²/g.

The proppant particle is optionally brought to the subterranean formation using a tracking fluid with a density equal to or below 1 .1 g/cm³.

The proppant particle is optionally brought to the subterranean formation using a tracking fluid that is a condensed gas. The sorbed treatment chemical optionally comprises an oxidation agent. An example of an oxidation agent is a permanganate, which is optionally dissolved in an organic solvent selected from comprising oil produced by the process or a distillate fraction thereof. The sorbed treatment chemical optionally comprises any of a reactant, a diluent and a solvent, or a mixture thereof. Examples of these include any of: recycled oil and a distillation fraction of the recycled oil; an oxygenated hydrocarbon selected from any of a carboxylic acid, a benzoic acid, and derivatives thereof; and methanol. As an option, the sorbed treatment chemical comprises a catalyst.

As an option the treatment chemical is selected from any of:

a mineral oil, an aromatic based hydrocarbon and a silicon based hydrocarbon; a hydrogen donor;

a wholly or partially hydrogenated naphthalene, or substituted naphthalene; a wholly or partly hydrogenated benzene, toluene or xylene;

a hydrogenated oil, or a distillate fraction of the oil; and

a condensed gas, which is optionally any of a liquid petroleum gas and a component of a liquid petroleum gas.

The sorbed treatment chemical is optionally selected so as to undergo an appreciable volume expansion upon heating the reservoir and/or pressure release. The volume expansion is optionally in a range selected from any of a factor of at least 2, greater than 10, and greater than 100. The treatment chemical is optionally a monopropellant (examples of which are hydrazine and hydrogen peroxide) or an explosive (examples of which are nitrocellulose or ammonium perchlorate). According to a second aspect, there is provided a fracking fluid for use in a fracking operation, the fracking fluid comprising a dispersion of a plurality of proppant particles as described above in the first aspect.

According to a third aspect, there is provided a method of producing hydrocarbons from a subterranean formation comprising kerogen and/or oil shale, the method comprising providing an injection well in the subterranean formation, injecting a fracking fluid into the subterranean formation, the fracking fluid comprising a dispersion of proppant particles comprising a sorbed treatment chemical as described in the first aspect, the injection of the fracking fluid causing the creation or extension of fractures in the formation. The fracking fluid is removed from the subterranean formation such that proppant particles remain in the fractures. The subterranean formation is then heated and hydrocarbons are produced from the subterranean formation.

The subterranean formation optionally comprises at least 50 volume % shale.

Heating is optionally effected by injecting a heating fluid into the subterranean formation. An optional example of a heating salt is any of a molten salt and an ionic liquid. The sorbed treatment chemical is optionally any of: an oxidation agent selected to oxidise hydrocarbons in the subterranean formation; a reactant selected to be consumed in a reaction with a portion of the hydrocarbons in the subterranean formation; a diluent selected to reduce a viscosity of a portion of the hydrocarbons in the subterranean formation; a solvent selected to dissolve a portion of the hydrocarbons in the subterranean formation; a condensed gas arranged to expand on heating and increase a pressure on the hydrocarbons in the subterranean formation; and a monopropellant or an explosive to create tracks in the subterranean formation.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 illustrates a cross-section of a well after a fracking operation using proppants; Figure 2 illustrates schematically a non-porous and a porous proppant particle;

Figure 3 is a flow diagram showing exemplary steps in preparing and using a porous proppant.

DETAILED DESCRIPTION

It is foreseen that some proppants that have a porous structure can be made available. An advantage of porous proppant particles with adequate strength is that they do not settle so quickly in a tracking fluid and remain in dispersion. This means that a less dense tracking fluid can be used in order to avoid settling of proppant particles before they enter fractures where they act as spacers. A distinct advantage is that a less dense tracking fluid normally will contain less chemicals.

By way of example, quart has a density of 2.2 g/cm³, clay 1 .8-2.6 g/cm³, corundum (alumina) 3.9-4.0 g/cm³ and sandstone 2.14-2.36 g/cm³. Each of these materials is currently used as a proppant. For dilute suspensions of regular proppant particles in a viscous fluid, the settling velocity can be described by Stokes' law, which dictates that the velocity is proportional to the density difference between particle and the fluid and to the square of the particle radius. Due to the need for strong proppants that can withstand the compressive forces in the fractures of the formation, the present proppant materials have high densities. It should be understood that the definition of density or gravity of porous solid particles is not trivial, and many terms have been used. In the definitions by ASTM (American Society for Testing and Materials) there are more than 40 definitions of density. The describing terms "specific" or "apparent" are also used ambiguously. For example, in US 2006/0016598 the terms "specific gravity", "apparent specific gravity" and "apparent density" are all used for proppant particles without definition and description of measurement technique. For particles that are spherical in nature, but not necessarily ideally so, the settling velocity can be estimated using the weight of the particles to the volume of the particles including internal voids and pores, these being open or closed, but excluding any interparticle volume. For particles containing mainly pores in the micro- and meso-porous range below 100 nm, the BET method with nitrogen can be used to measure the pore volume (PV) in cm³/g. If we then know the skeletal density of the material, i.e. the density of the solid material without pores, the particle density can be calculated as: p = p° /(1 + PV ^* p°) (Eq. 1 ) or

p = P/PV (Eq. 2) where p° is the skeletal density and P the porosity, i.e. the relative portion of the total particle volume that is contained in the pores. For most particles the inaccessible internal volume by nitrogen is expected to be small and can be disregarded in the calculations, but does not limit the described principle. Another factor is the extent to which the particles, during operation, will be filled with the tracking fluid or not, which increases the density of the particles. This will depend on many factors like the hydrophilicity of the material and the viscosity of the fluid. For the sake of argument, unless otherwise stated, it is assumed that the pores do not contribute to the weight of the particles.

Table 1 contrasts the density, size and settling velocities of quartz, corundum and six theoretical particles with lower densities to illustrate how the settling velocity may be reduced by reducing the density of the proppant particles.

Table 1 . Relative settling velocities, assuming density of tracking fluid to be 1 .1 g/cm³

It can be seen that by reducing the density of the particles, the settling velocity can be reduced significantly. Alternatively, the particle size can be doubled or more for light particles without compromising the settling velocity. These data suggest that reducing the density of proppant particles can give rise to a much higher efficiency in keeping fractures open. Furthermore, such proppants would allow a higher utilization ratio of the proppants/fracking fluid, and therefore require the use of a lower volume of chemicals. This has both cost and environmental benefits. It will be appreciated that as the density of the proppant particles approaches the density of the tracking fluid, the benefits increase.

By providing proppant particles with porosities in the 50-70 volume % range, it is feasible to make proppant particles with even lower densities than in Table 1 . This allows them to be used with condensed gases as a tracking fluid. For example, the density of liquid propane at room temperature is 0.493 g/cm³, and the corresponding relative settling velocities are given in Table 2. Use of Liquid Petroleum Gas (LPG) or propane as a tracking gas with no (or a low level of) chemicals allow a tracking operation in which water consumption is substantially eliminated and surface handling of the return tracking fluid is easy. The propane can simply be flashed off from any reservoir water, if needed, and recycled to further use in the tracking operation.

Table 2. Relative settling velocities, assuming a tracking fluid density of 0.493 g/cm³

Note that hypothetical Materials 1 to 3 are the same in Tables 1 and 2.

There is a clear advantage in providing porous proppant particles. A suitable candidate class materials is porous ceramics. Examples of ceramics that can be produced in porous form are aluminium oxide, zirconium toughened alumina, silicon (oxy) carbide, silicon nitride, and stabilized zirconia with porosities of 10-55% or higher with compressive strengths up to 130 MPa.

It has been realised that the use of porous proppant particles allows treatment chemicals to be sorbed onto the surface of or into the pores (typically by adsorption or absorption). The porosity means that the effective surface area of each proppant particle is far greater than it would be if the proppant particle were not porous. This means that each porous proppant particle can act as an effective carrier of treatment chemicals. The proppant can therefore carry treatment chemicals into the subterranean formation and close to the hydrocarbons that require treatment.

Figure 2A illustrates a proppant particle 3 with a treatment chemical 4 sorbed onto its surface. Figure 2B illustrates a porous proppant particle 5 having pores 6 with a treatment chemical sorbed onto the particle surface including the surface of the pores. It is apparent from this schematic diagram that the porous proppant particle 5 can carry a far greater amount of a treatment chemical 4 than a non-porous proppant particle 3. Note that the figure is not to scale as the size of the pores will be far smaller than the proppant particle in reality, the diameter of the pore being typically 10^~2 to 10^~6 of the proppant. It is the relatively small diameter of the pores that makes up the high available internal surface area made available for sorption. In catalysis it is known that porous catalyst particles can have surface areas above 100 m²/g and in some cases even above 1000 m²/g. For a porous proppant it might be challenging to achieve these high numbers and at the same time fulfil the requirement to the strength of the particles. Still, the outer surface of a proppant particle will have a porosity below 0.1 m²/g. There is therefore a huge potential to increase the available surface area of proppant particles by making them porous.

An advantage of using proppant particles to carry the treatment chemicals rather than the tracking fluid is that the treatment chemicals remain in the subterranean formation after the tracking operation has been completed and the tracking fluid has been removed. If the treatment chemicals were carried in the tracking fluid, they would be removed along with the tracking fluid after completion of the tracking operation.

It will be appreciated that many different treatment chemicals may be used. For example, a diluent will reduce the viscosity of hydrocarbons in the subterranean formation, a solvent will dissolve hydrocarbons in the subterranean formation, and oxidation agent will oxidise and break down hydrocarbons, a reactant will have a chemical reaction (to form hydrocarbons that are easier to produce than the existing subterranean hydrocarbons). Furthermore, the treatment chemical may have other effects. For example, a condensed gas will expand and cause additional pressure in the subterranean formation, thereby extending fractures or making new fractures, and pushing hydrocarbons down the fractures towards a production well. An even more pronounced effect can be obtained by introducing a (mono)propellant like hydrazine or hydrogen peroxide. Explosives like nitrocellulose or ammonium perchlorate based explosives are other types of monopropellants. The release of the stored chemical energy in the propellant can be by increasing the temperature, optionally assisted by the presence of a catalyst. It is evident that a high energy propellant may assist in creating tracks in the formation.

The subterranean formation may be subjected to a subsequent heat treatment. This may be by providing a heating well that has electrical or other types of heaters, or by injecting a heating fluid into the subterranean formation. A heating fluid can be of several types, but can conveniently be a molten salt. Nitrate or carbonate salts are typically used, or mixtures of salts. One currently used type of molten salt is a mixture of 60% NaN0₃ and 40% KN0₃ with a melting point of 220°C. This mixture can be heated to 450-650°C, typically between 550-600°C, before being injected into the subterranean formation. The return temperature at the surface for reheating and reuse is typically in the range of 250-500°C. Other classes of salts that may be used include carbonates, halides or other well-known anions. An environmentally benign salt counterion (cation) is usually selected, typically in the form of alkali, alkaline earth elements or sink. A further option is a salt with an imidazolium based counterion if a low melting temperature is desired. Molten salts as a heat transfer fluid for heating a subsurface formation have been described in US 7,832,484, which describes several examples of such salts. 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.

Heating the subterranean reservoir can activate treatment chemicals sorbed onto the surface of proppant particles that are located in fractures. A treatment chemical may not be particularly active at the tracking operation temperature, but may become much more active during the heat treatment. In this way, treatment chemicals can be located in the subterranean formation during a tracking operation without starting to react with the hydrocarbons, and can subsequently react with hydrocarbons during a heating operation. Onset of the reaction can be facilitated by a catalyst.

Figure 3 is a flow diagram showing exemplary steps in a hydrocarbon production operation. The following numbering corresponds to that of Figure 3.

S1. Porous proppant particles are treated to sorb a treatment chemical on the surface of the particles. S2. The porous proppant particles are dispersed in a tracking fluid.

53. An injection well is provided in a subterranean formation.

54. The tracking fluid containing proppants is injected via the injection well into the formation to create fractures or extend existing fractures.

55. After the tracking operation, the tracking fluid is removed from the subterranean formation. However, proppant particles remain in the fractures to hold them open and prevent them from closing. This means that the treatment chemical also remains in the subterranean formation.

56. A heat treatment operation is performed.

57. The treatment chemicals act to improve the production of hydrocarbons from the subterranean formation, for example by reacting with the hydrocarbon, creating additional pressure in the formation, reducing the viscosity of the hydrocarbon, oxidizing the hydrocarbon or dissolving the hydrocarbon.

As discussed below, treatment chemicals may take many different forms. Furthermore, a mixture of treatment chemicals may be used, either by sorbing a plurality of different chemicals onto the surface of porous proppant particles, or by sorbing a first type of treatment onto a first batch of proppant particles and a second type of treatment chemical onto a second batch of proppant particles. Both batches can then be mixed together in the tracking fluid. Mixing with conventional proppant particles is an additional option. Use of a hydrogen donating fluid as a treatment chemical can be advantageous as a higher yield of hydrocarbons can be achieved at a given temperature, or the process temperature can be reduced, thereby saving in energy use. Typically, hydrogen donation is an acid property and the fluid can be an organic acid. Examples of these include maleic acid or any aliphatic or aromatic carboxylic acid, or a cyclic organic compound such as dialine, tetralin or decalin. These latter compounds are the partially or fully hydrogenated analogues of naphthalene, a bicyclic aromatic compound that can be found in tar. Naphthalene and its hydrogenated analogues can be substituted; that is containing sidegroups attached to one or both rings, typically alkyl groups. Single ring donors such as cyclohexane or methylcyclohexane can also be effective. Methylcyclohexane has been suggested as a hydrogen storage and transportation medium and is the hydrogenated analogue of toluene.

The donor fluid to form the treatment chemical may be derived from the produced hydrocarbon although this is not a prerequisite. The hydrogen donating fluid may also serve as a solvent for the liquid hydrocarbon products. This is particularly useful where the hydrocarbons are in solid or very viscous form.

By providing treatment chemicals sorbed to the surfaces of porous proppant particles, hydrocarbons can be produced in-situ with improved yields and, in some case, a better product quality. It should be noted that hydrogenation with a donor solvent or neat hydrogen conventionally is associated with elevated temperatures close to or above 400°C, typically 350-500°C, and high pressures, typically in the range 100-200 bar. A treatment chemical may take the form of a catalyst to speed up processes.

Note that, in addition to hydrocarbons, other substances will be produced. Examples of other substances include H₂S, H₂0 and C0₂. Conventionally it has been regarded as a necessity to remove most of the inherent oxygen atoms in the produced oil. However, novel fuel formulation may allow for, and possibly make use of, a large amount of oxygenates like phenols, aromatic acids, esters and the like. Thus, less severe hydrogenation may be required. In one embodiment, for reservoirs containing appreciable amounts of sulphur, typically aliphatic and/or thiophenic sulphur, breakdown of sulphur-carbon bonds can be sufficient for liquid production. If a less severe conversion is required, and the heating of the formation is very slow, then less severe hydrogenation conditions can be used, particularly reducing the pressure to below 100 bar, preferably below 60 bar, more preferably below 25 bar. Even pressures in the range 2-20 bar can be favourable.

Oxidation reactions can also be suitable for enhanced extraction of the hydrocarbons, both providing heat needed and breaking down the complex structure of heavy hydrocarbons. An oxidizing agent must be intimately mixed with the hydrocarbons in the reservoir and therefore conveniently can be introduced by sorbing it onto the surface of the porous proppant particles. One type of oxidizing agent is perchlorate salts, other types include ozone or hydrogen peroxide solutions. A further type is sodium or potassium permanganate, NaMn0₄ or KMn0₄, dissolved in water. A further option is to use a quaternary ammonium permanganate salt such as [Bu'₄N][Mn0₄] that is soluble in organic solvents and is known to oxidize hydrocarbons.

Under certain circumstances, a permanganate solution, and in general the oxidizing solution, can be used as a combined oxidation and tracking agent, thereby simplifying the overall operation. A tracking agent is a compound that facilitates fracturing of the formation, typically by creating an overpressure by gas release or by an explosion.

Using an oxidation agent as a treatment chemical is attractive from the point of view that no or only slight heating of the reservoir is needed. In other words, heating is not required for all types of treatment chemical. However, lower valent analogues of the oxidation agent that will be formed, such as manganese oxide and manganate will need to be separated from the produced hydrocarbon and re-oxidized before recycling. This oxidation may involve oxidation with oxygen and/or electrolytic oxidation in an alkaline solution in order to regenerate the oxidation agent.

Controlled oxidation of heavy hydrocarbons can follow complex mechanisms, but in most cases heteroatoms will be attacked, and it will be particularly useful if these atoms are situated in bridges, e.g. between aromatic structures. These atoms typically are sulphur, chlorine or nitrogen. Gaseous compounds such as C0₂ may result from the oxidation.

A solvent can also be brought into the subterranean formation with the porous proppant particles, thereby facilitating transport of hydrocarbon products to the surface. The solvent can be of any convenient form, including water, hydrocarbons, oxygenates and mixtures thereof. Similarly, diluents can be brought into the subterranean formation. Another type of treatment chemical is one that will evaporate during a subsequent heating operation. By introducing a liquid into the subterranean formation during a tracking operation that will evaporate under subsequent heating and thermal treatment of the reservoir, the liquid subsequently converts to a gas phase and consequently undergoes a large increase in volume. This increase in volume can extend existing fractures and even create new fractures. Furthermore, the pressure created in the subterranean reservoir can push produced fluid hydrocarbons towards the production well, thereby improving the production of hydrocarbons.

The techniques described above may be applied to various types of subterranean formation, including low permeability subterranean formations such as shales or formation containing more than 50% shale by volume. Furthermore, they may be applied to the production of different types of hydrocarbon, such as oil, gas, shale oil, kerogens, coal and so on. It should be understood that the term "hydrocarbon" present in the subterranean formation is now 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. Of course, different treatment chemicals will have different effects on different types of hydrocarbons, but the basic concept of introducing treatment chemicals into the subterranean formation by sorbing the chemicals into or onto the interior of porous proppant particles can be used. Using a treatment chemical will chemically modify, dilute or dissolve the hydrocarbon present in the reservoir to yield a hydrocarbon product that is brought to the surface during production. Further, in situ catalytic reactions and/or heat treatment may further 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 proppant particle for use in hydrocarbon production using a tracking operation on a subterranean formation comprising any of kerogen and oil shale, the proppant particle comprising a plurality of pores, the proppant particle having a surface area of at least 5 m²/g, the proppant particle further comprising at least one treatment chemical sorbed to at least part of a solid surface of the pores.

2. The proppant particle according to claim 1 , wherein the porous proppant particle is formed from any of alumina, zirconium toughened alumina, silicon (oxy) carbide, silicon nitride, stabilized zirconia, alumina spinel, and carbon nanofibres disposed on a core particle.

3. The proppant particle according to claim 1 or 2, wherein the proppant particle has a density in the range of a group selected from below 2.0 g/cm³, below 1 .6 g/cm³, below 1 .2 g/cm³, and equal to or below 0.9 g/cm³.

4. The proppant particle according to claim 1 , 2 or 3, the proppant particle having a porosity in the range of a group selected from at least 30 volume%, at least 50 volume %, and at least 70 volume %.

5. The proppant particle according to any of claims 1 to 4, the proppant particle having a compressive strength in the range of a group selected from at least 30 MPa, at least 80 MPa and at least 170 MPa.

6. The proppant particle according to any of claims 1 to 5, wherein the porous proppant particle has a surface area greater than 30 m²/g.

7. The proppant particle according to any of the preceding claims that is brought to the subterranean formation using a tracking fluid with a density equal to or below 1 .1 g/cm³.

8. The proppant particle according to any of the preceding claims that is brought to the subterranean formation using a tracking fluid comprising a condensed gas.

9. The proppant particle according to any of claims 1 to 8, wherein the sorbed treatment chemical comprises an oxidation agent.

10. The proppant particle according to claim 9, wherein the oxidation agent comprises a permanganate.

11 . The proppant particle according to claim 10, wherein the permanganate is dissolved in an organic solvent selected from comprising oil produced by the process or a distillate fraction thereof.

12. The proppant particle according to any of claims 1 to 8, wherein the sorbed treatment chemical comprises any of a reactant, a diluent and a solvent, or a mixture thereof.

13. The proppant particle according to claim 12, wherein the sorbed treatment chemical comprises any of recycled oil and a distillation fraction of the recycled oil.

14. The proppant particle according to claim 12, wherein the sorbed treatment chemical comprises an oxygenated hydrocarbon selected from any of a carboxylic acid, a benzoic acid, and derivatives thereof.

15. The proppant particle according to claim 12, wherein the sorbed treatment chemical comprises methanol.

16. The proppant particle according to any of claims 1 to 8, wherein the sorbed treatment chemical comprises a catalyst.

17. The proppant particle according to any of claims 1 to 8, wherein the treatment chemical is selected from any of a mineral oil, an aromatic based hydrocarbon and a silicon based hydrocarbon.

18. The proppant particle according any of claims 1 to 8, wherein the treatment chemical comprises a hydrogen donor.

19. The proppant particle according to any one of claims 1 to 16, wherein the treatment chemical comprises any of wholly or partially hydrogenated naphthalene, or substituted naphthalene.

20. The proppant particle according to any one of claims 1 to 8, wherein the treatment chemical comprises any of a wholly or partly hydrogenated benzene, toluene or xylene.

21 . The proppant particle according to any one of claims 1 to 8, wherein the treatment chemical comprises a hydrogenated oil, or a distillate fraction of the oil.

22. The proppant particle according to any one of claims 1 to 8, wherein the treatment chemical comprises a condensed gas.

23. The proppant particle according to claim 22, wherein the treatment chemical comprises any of a liquid petroleum gas and a component of a liquid petroleum gas.

24. The proppant particle according to any of claims 17 to 23 wherein the sorbed treatment chemical is selected so as to undergo an appreciable volume expansion upon heating the reservoir and/or pressure release.

25. The proppant particle according to claim 24, wherein the volume expansion is in a range selected from any of a factor of at least 2, greater than 10, and greater than 100.

26. The proppant particle according to any of claims 1 to 8, wherein the treatment chemical comprises any of a monopropellant and an explosive.

27. The proppant particle according to claim 26, wherein the treatment chemical is a monopropellant comprising any of hydrazine and hydrogen peroxide

28. The proppant particle according to claim 26, wherein the treatment chemical is an explosive comprising any of nitrocellulose or ammonium perchlorate.

29. A tracking fluid for use in a tracking operation, the tracking fluid comprising dispersion of a plurality of proppant particles according to any of claims 1 to 28.

30. A method of producing hydrocarbons from a subterranean formation comprising any of kerogen and oil shale, the method comprising:

providing an injection well in the subterranean formation;

injecting a tracking fluid into the subterranean formation, the tracking fluid comprising a dispersion of proppant particles comprising a sorbed treatment chemical according to any of claims 1 to 28, the injection of the tracking fluid causing the creation or extension of fractures in the formation;

removing the tracking fluid from the subterranean formation such that proppant particles remain in the fractures;

heating the subterranean formation to a temperature of at least 250 °C; and producing hydrocarbons from the subterranean formation.

31 . The method according to claim 30, wherein the subterranean formation comprises at least 50 volume % shale.

32. The method according to claim 30 or 31 , wherein the heating is effected by injecting a heating fluid into the subterranean formation.

33. The method according to claim 32 wherein the heating fluid comprises any of a molten salt and an ionic liquid.

34. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical is an oxidation agent selected to oxidise hydrocarbons in the subterranean formation.

35. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical is a reactant selected to be consumed in a reaction with a portion of the hydrocarbons in the subterranean formation.

36. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical is a diluent selected to reduce a viscosity of a portion of the hydrocarbons in the subterranean formation.

37. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical is a solvent selected to dissolve a portion of the hydrocarbons in the subterranean formation.

38. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical is a condensed gas arranged to expand on heating and increase a pressure on the hydrocarbons in the subterranean formation.

39. The method according to any of claims 30 to 33, wherein the sorbed treatment chemical comprises any of a monopropellant and an explosive to create tracks in the subterranean formation.