Patent application title: DELIVERY OF PARTICULATE MATERIAL BELOW GROUND
Trevor Hughes (Cambridge, GB)
Evgeny Barmatov (Cambridge, GB)
Jill Geddes (Cambridge, GB)
Michael Fuller (Cypress, TX, US)
Bruno Drochon (Houston, TX, US)
Sergey Makarychev-Mikhailov (Richmond, TX, US)
IPC8 Class: AC09K880FI
Class name: Earth boring, well treating, and oil field chemistry well treating contains intended gaseous phase at entry into wellbore
Publication date: 2016-04-21
Patent application number: 20160108308
A wellbore fluid comprises an aqueous carrier liquid, hydrophobic
particulate material suspended therein and a gas to wet the surface of
the particles and bind them together as agglomerates. The hydrophobic
particulate material has a specified maximum particle size and/or minimum
surface area: namely a volume median particle size d50 of not more
than 200 micron, determined as median diameter of spheres of equivalent
volume and/or a surface area of at least 30 m2 per litre (0.03
m2 per milliliter), determined as surface area of smooth spheres of
The agglomeration of the particles by gas leads to the formation of
agglomerates which contain gas and so have a bulk density lower than the
density of the particles. This reduces the rate of settling. The fluid is
particularly envisaged as a slickwater fracturing fluid in which the
suspended particles are proppant. We have found that the small particle
size and/or substantial surface area increases the amount of gas which
can be retained within agglomerates and so enhances the buoyancy of the
agglomerates. The end result is that a greater proportion of a hydraulic
fracture is propped open.
1. A wellbore fluid comprising an aqueous carrier liquid and hydrophobic
particulate material suspended therein, wherein the hydrophobic
particulate material has a volume median particle size d50 of not more
than 200 micron, determined as median diameter of spheres of equivalent
volume, the fluid also comprising a gas to wet the surface of the
particles and bind them together as agglomerates.
2. A fluid according to claim 1 wherein the hydrophobic particulate material has a specific gravity of at least 1.8.
3. A fluid according to claim 1 wherein agglomerates of the hydrophobic particles in the fluid, containing the gas in the maximum amount which the agglomerates can retain, have a density of not more than 1.4 gm/ml.
4. A fluid according to claim 1 wherein the hydrophobic particulate material comprises solid particles with a hydrophobic surface coating.
5. A fluid according to claim 1 wherein the aqueous carrier liquid is substantially free of viscosity-enhancing polymeric thickener and has a viscosity which is less than 15 centipoise when viscosities are measured at 20.degree. C. and a shear rate of 100 sec-1.
6. A fluid according to claim 1 wherein the aqueous carrier liquid contains one or more friction reducing additives in a total amount which is not greater than 1% by weight.
7. A wellbore fluid comprising an aqueous carrier liquid and hydrophobic particulate material suspended therein, wherein the hydrophobic particulate material has a surface area of at least 30 m2 per litre (30,000 m2 per m3 or 0.03 m2 per milliliter), determined as surface area of smooth spheres of equivalent volume, the fluid also comprising a gas to wet the surface of the particles and bind them together as agglomerates.
8. A fluid according to claim 7 wherein the hydrophobic particulate material has a specific gravity of at least 1.8.
9. A fluid according to claim 7 wherein agglomerates of the hydrophobic particles in the fluid, containing the gas in the maximum amount which the agglomerates can retain, have a density of not more than 1.4 gm/ml.
10. A fluid according to claim 7 wherein the hydrophobic particulate material comprises solid particles with a hydrophobic surface coating.
11. A fluid according to claim 7 wherein the aqueous carrier liquid is substantially free of viscosity-enhancing polymeric thickener and has a viscosity which is less than ten times the viscosity of water when viscosities are measured at 20 QC and a shear rate of 10 sec-1.
12. A fluid according to claim 7 wherein the aqueous carrier liquid contains one or more friction reducing additives in a total amount which is not greater than 1% by weight.
13. A fluid according to claim 1 wherein the gas is air or nitrogen.
FIELD OF THE INVENTION
 The invention relates to delivery of particulate material to a location below ground. A significant application is as part of a method of hydraulic fracturing of a subterranean reservoir formation, placing proppant in the fracture so as to keep the fracture open as a flow path. However, the invention also extends to other applications where placing of particulate material underground, notably within subterranean reservoirs, is required. It is envisaged that the invention will be used in connection with exploration for, and production of, oil and gas.
BACKGROUND OF THE INVENTION
 Placing particulate material at a location below ground is a very significant part of a hydraulic fracturing operation. Hydraulic fracturing is a well established technique for reservoir stimulation. Fluid is pumped under pressure into a subterranean formation, forcing portions of the formation apart and creating a thin cavity between them. When pumping is discontinued the natural pressure in the subterranean formation tends to force the fracture to close. To prevent the fracture from closing completely it is normal to mix a solid particulate material (termed a proppant) with the fracturing fluid at the surface and use the fluid to carry the proppant into the fracture. When the fracture is allowed to close, it closes onto the proppant and a flow path to the wellbore between the proppant particles remains open. The proppant is then under considerable pressure from the formation rock pressing on it.
 It is normal practice to employ solid proppant of controlled particle size distribution in order that the proppant pack has adequate fluid conductivity, i.e. is adequately porous, and to mitigate the flowback of fine particles. Post-fracture proppant flowback to the wellbore is generally regarded as a problem and an occurrence to be avoided. Although many materials have been used as proppants, for the fracturing of oil reservoirs it is commonplace to use so-called 20/40 sand which has a particle size distribution such that 90% by weight passes a 20 US mesh (840 micron) sieve but is retained by a 40 mesh (400 micron) sieve. Finer materials have been used and American Petroleum Institute Recommended Practices (API RP) standards 56 and/or 60 recognize proppant sizes down to a size range of 70/140 US mesh (sieve openings of 210 and 105 micron). Materials which are smaller than 70/140 US mesh have been regarded as too small to use as proppants.
 When the proppant is mixed with the fracturing fluid at the surface and pumped into the wellbore it is subjected to very high shear. The proppant-laden fluid then flows down the wellbore under conditions of lower shear. Subsequently it turns and flows out of the wellbore and into the fracture in the formation. Entry to the fracture may be associated with an increase in shear, in particular if the wellbore is cased and the fluid passes through perforations in the wellbore casing to enter the fracture. Once the fluid enters the fracture, and as the fracture propagates and extends into the reservoir, the fluid is subjected to much less shear. Suspended solid begins to settle out. Subsequently pumping is discontinued, allowing the fracture to close onto the proppant packed in the fracture.
 In order that the fluid can convey particulate material in suspension, and place it across the fracture face, it is conventional to include a viscosity-enhancing thickening agent in the fluid. Typically the fluid is then formulated so as to achieve a viscosity of at least 100 centipoise at 100 sec-1 at the temperature of the reservoir. Guar is widely used for this purpose. Guar derivatives and viscoelastic surfactants may also be used. However, for some fracturing operations, especially where the rock has low permeability so that leak off into the rock is not a significant issue, it is preferred to pump a fluid, often called "slickwater", which is water or salt solution containing a small percentage of friction reducing polymer. The fluid then has low viscosity. This considerably reduces the energy required in pumping but keeping particulate material in suspension becomes much more difficult and a higher pump flow rate is commonly used.
 As recognized in Society of Petroleum Engineers Papers SPE98005, SPE102956 and SPE1125068 conventional proppant particles suspended in slickwater pumped into a large fracture will settle out more quickly than is desired and form a so-called "bank" or "dune" close to the wellbore. Because of this premature settling, proppant may not be carried along the fracture to prop the full length of the fracture and proppant may not be placed over the full vertical height of the fracture. When pumping is stopped and the fracture is allowed to close, parts of the fracture further from the wellbore may not contain enough proppant to keep them sufficiently open to achieve the flow which would be desirable. As a result the propped and effective fracture size may be less than the size created during fracturing.
 One approach to improving the transport of particulate proppant has been to use a material of lower specific gravity in place of the conventional material which is sand or other relatively heavy mineral (sand has a specific gravity of approximately 2.65). SPE84308 describes a lightweight proppant having a specific gravity of only 1.75 which is a porous ceramic material coated with resin so that pores of the ceramic material remain air-filled. This paper also describes an even lighter proppant of specific gravity 1.25 which is based on ground walnut hulls. This is stated to be a "resin impregnated and coated chemically modified walnut hull".
 These lightweight proppants are more easily suspended and transported by slickwater and their use is further discussed in SPE90838 and SPE98005, the latter paper demonstrating that settling out is reduced compared to sand, although not entirely avoided. There have been a number of other disclosures of proppants lighter than sand. Examples are found in U.S. Pat. Nos. 4,493,875 and 7,491,444 and in US patent applications 2005/096,207, 2006/016,598 and 2008/277,115.
 A recognized issue with lightweight proppants is that they may not be as strong as sand and are at risk of becoming partially crushed when a hydraulic fracture is allowed to close on the proppant placed within it. An approach to the suspension of particulate proppant which seeks to avoid this issue is disclosed in US2007/015,669, also in WO2009/009,886 and in "Lightening the Load" New Technology Magazine, January/February 2010 pages 43 and 44. According to the teachings of these documents, a conventional proppant such as sand is treated to render its surface hydrophobic and is added to the slurry of proppant and water. Bubbles adsorb to the hydrophobic solid particles so that the adsorbed gas gives the particles a lower effective density. The literature describing this approach advocates it on grounds that the conventional sand is both cheaper and stronger than lightweight proppant.
SUMMARY OF THE INVENTION
 Broadly, the present invention provides a wellbore fluid comprising an aqueous carrier liquid with hydrophobic particulate material suspended therein where the fluid also contains a gas which serves to wet the surface of the particles and bind them together as agglomerates.
 By agglomerating with gas it is possible to form agglomerates with a bulk density which is lower than the density of the particulate material in them. Because they are of lower density they will settle out of the carrier liquid more slowly. As a result they can be transported more effectively to their intended destination. In the context of hydraulic fracturing the particulate materials can be transported further into the fracture than would be possible if the particulate material was suspended without agglomeration by gas and in consequence a greater length and/or vertical height of fracture (i.e. the fracture area) remains propped open after pumping has ceased. We have found that the amount of gas which can be held in agglomerates has an upper limit. The amount of gas cannot be increased indefinitely. However, we have also found that the amount of gas which can be retained and the concomitant lowering of bulk density are linked to the surface area of the hydrophobic particulate material. The surface area of a particulate material increases as its particle size becomes smaller and in consequence this invention calls for the agglomeration of materials of specified surface area or small particle size.
 According to one aspect of the present invention there is provided a wellbore fluid comprising an aqueous carrier liquid and hydrophobic particulate material suspended therein, wherein the hydrophobic particulate material has a volume median particle size d50 of not more than 200 micron, determined as median diameter of spheres of equivalent volume, the fluid also comprising a gas to wet the surface of the particles and bind them together as agglomerates.
 In a second aspect the invention provides a method of delivering particulate material below ground, comprising supplying, underground, a fluid composition comprising an aqueous carrier liquid with a hydrophobic particulate material suspended therein, the hydrophobic particulate material having a volume median particle size d50 of not more than 200 micron, determined as median diameter of spheres of equivalent volume, the fluid also comprising a gas wetting the surface of the particles and binding the particles together such that agglomerates of the particulate material held together by the gas are present below ground.
 Particulate material having a median particle size of not more than 200 micron is smaller than the size range most commonly used as proppant but is satisfactory in a number of circumstances. The particle size of the material may be a value as determined by the commonly used technique of low angle laser light scattering, more commonly known as laser diffraction. Instruments for carrying out this technique and calculating particle size data from the observations are available from a number of suppliers including Malvern Instruments Ltd., Malvern, UK. When determining particle sizes using such an instrument, the size of an individual particle is reported as the diameter of a spherical particle of the same volume, the so-called "equivalent sphere". Volume median diameter denoted as D[v,05] or d50 is a value of particle size such that 50% (by volume) of the particles have a volume larger than the volume of a sphere of diameter d50 and the remaining particles have a volume smaller than the volume of a sphere of diameter d50.
 Particle size distribution is conveniently indicated by the values of d10 and d90 measured in the same way. 10% by volume of the particles in a sample have an equivalent diameter smaller than d10. 90% by volume are smaller than d90 and so 10% by volume are larger than d90. The closer together are the values of d10 and d90, the narrower is the particle size distribution.
 Particle sizes determined by low angle laser light scattering are similar to particle sizes determined by sieving if the particles are approximately spherical. However, if the particles have a shape which is not spherical, for instance a plate-like form so that a dimension in one direction is much greater than in an orthogonal direction, the diameter of the equivalent sphere provides a useful value.
 If the particulate material has a bimodal or asymmetric particle size distribution, we have observed that the presence of smaller size particles can enable the formation of agglomerates which are lighter and more buoyant than agglomerates formed using particles with a symmetrical size distribution around the same d50 value. Consequently in a further aspect this invention provides a wellbore fluid comprising an aqueous carrier liquid and hydrophobic particulate material suspended therein, wherein the hydrophobic particulate material has a surface area of at least 30 m2 per litre (30,000 m2 per m3 or 0.03 m2 per milliliter), determined as surface area of smooth spheres of equivalent volume, the fluid also comprising a gas to wet the surface of the particles and bind them together as agglomerates. (Simple calculation of geometry indicates that the surface area of uniform spheres of diameter 200 micron would be 30 m2 per litre).
 In a fourth aspect the invention provides a method of delivering particulate material below ground, comprising supplying, underground, a fluid composition comprising an aqueous carrier liquid with a hydrophobic particulate material suspended therein, the hydrophobic particulate material having surface area of at least 30 m2 per litre (0.03 m2 per milliliter), determined as surface area of smooth spheres of equivalent volume, the fluid also comprising a gas wetting the surface of the particles and binding the particles together such that agglomerates of the particulate material held together by the gas are present below ground.
 The surface area, determined as surface area of smooth spheres of equivalent volume is a value which can be calculated by the software of a Malvern Mastersizer or similar instrument along with the mean and distribution of particle sizes. It will be appreciated that it is not a direct measurement of specific surface area but it has the advantage that it can be determined easily.
 Where the invention is characterized by the surface area of the hydrophobic particulate material, that surface area may be at least 50 and possibly at least 70 or 100 m2 per liter (0.05, 0.07 or 0.10 m2 per milliliter).
 Agglomeration by gas may be prevented or reversed when-the composition is subjected to shear. As already mentioned a composition which is pumped downhole is subjected to varying amounts of shear in the course of travel downhole. Consequently agglomeration may take place at the subterranean location to which the particulate material is delivered. However, it is possible that agglomeration may take place or may at least begin in the course of flow towards the subterranean location where the material will serve its purpose.
 As already mentioned, it is possible to form agglomerates with a bulk density which is lower than the density of the particulate material in them. Because they are of lower density they will settle out of the carrier liquid more slowly. As a result they can be transported more effectively to their intended destination. The compositions used in this invention may be such that the agglomerates formed in accordance with this invention have a density not exceeding 1.4 g/ml and possibly not exceeding 1.1 g/ml. In some embodiments of the invention agglomerates may have a density close to 1.0 gm/ml, giving them a neutral buoyancy in water, or may have an even lower density so that they float in water.
 It should of course be appreciated that when agglomerates are formed in accordance with this invention, the amount of gas contained in them may not be as much as the maximum amount which is possible, which is governed by the properties of the materials present.
 Hydrophobic particulate material used in this invention may be a single material with a size distribution such that it has a d50 not over 200 micron and/or has surface area of at least 30 m2 per litre. Another possibility within the scope of the invention would be a mixture of two materials, a first one of which is of larger size such that it has d50 larger than 200 micron while a second material in the mixture is of smaller size such that the overall size distribution of the mixture has d50 smaller than 200 micron and/or has surface area of at least 30 m2 per litre. Particulate mixtures of three or more hydrophobic materials are also possible within this invention so long as the overall mixture meets the requirements for d50 or surface area.
 Whether the particulate material is a single material or a mixture of materials it is possible that its d50 particle size will be smaller than 200 micron. For instance more than 70% by volume may be smaller than 200 micron and indeed more than 90% may be smaller than 200 micron. It may be that d50 for the particulate material is no larger than 175 micron. Using a Malvern Mastersizer, we have measured the d50 particle size of a sample of 20/40 sand as 616 micron, and the d50 particle size of a sample of 70/140 sand as 169 micron. One possibility is that the particulate material complies with an approximation to the API definition of the 70/140 US mesh size range, such that not more than 0.1% by volume is larger than 300 micron, d90 is not larger than 210 micron, d10 is larger than 100 micron, and not more than 1% by volume is smaller than 75 micron.
 It is also possible that this invention may use particulate material which is even smaller than conventional proppant. The material may be such that d50 is no more than 150 micron and possibly no more than 125 micron or 105 micron. The material may be such that d90 is no more than 175 micron, or perhaps no more than 150 micron. Any of these criteria would define a particle size distribution smaller than 70/140 US mesh which is the smallest proppant size range recognized by API RP 56.
 In some embodiments of this invention, d50 for all suspended solid particles (whether hydrophobic or not) is not larger than 200 micron, and indeed d90 for all suspended solids may be no larger than 200 micron. For any particulate material it is preferred that d10 is larger than 10 micron, that is at least 90% of the material by volume is larger than 10 micron.
 The invention may be used in a variety of oilfield applications but it is particularly applicable to fracturing a formation which is a gas reservoir. Using a fine mesh proppant, that is to say a proppant of small particle size, may be expected to lead to fractures with lower permeability and conductivity than would be achieved with a proppant of larger size. Nevertheless, such fractures can carry gas with acceptable flow rates. The benefit of conveying proppant further into a fracture, so that the fracture has a greater effective size after it closes onto the proppant outweighs the lower conductivity. Overall, the stimulation of the formation is greater.
 Within embodiments of this invention used for fracturing a formation, the fracturing step may be followed by producing gas, gas condensate or a combination of them from the formation through the fracture and into a production conduit in fluid communication therewith.
 This invention may be used when fracturing a reservoir formation which has low permeability, so that slickwater is the fracturing fluid of choice. As mentioned above, this has considerable advantage when pumping into the formation but makes suspension of proppant much more difficult.
 A reservoir formation of low permeability may well be a gas reservoir, although this is not inevitably so. A formation of low permeability may have a permeability of no more than 10 millidarcies (10 mD), possibly no more than 1 millidarcy. Its permeability may be even lower, such as less than 100 microdarcy, or even less than 1 microdarcy. The agglomeration of proppant particles will lead to some small-scale non-uniformity of the distribution of proppant within a fracture when the fracture is allowed to close onto the proppant. Distributing proppant throughout a fracture, but with some non-uniformity in the distribution of proppant (sometimes referred to as heterogeneous proppant placement) may be helpful in enhancing fracture conductivity. In some embodiments of this invention, localized non-unity may be deliberately enhanced.
 One known method for heterogenous proppant placement which may be used in this invention is to pump a fluid containing suspended proppant alternately with a fluid containing less of the suspended proppant or none at all. This approach is the subject of U.S. Pat. No. 6,776,235. Another known method which may be employed is to pump the proppant together with a removable material, referred to as a `channelant`. After pumping has ceased and the fracture has closed onto proppant in the fracture, removal of the channelant leaves open pathways between islands or pillars of the proppant. This approach is the subject of WO2008/068645, the disclosure of which is incorporated herein by reference.
 A degradable channelant material may be selected from substituted and unsubstituted lactide, glycolide, polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of such materials. Representative examples are polyglycolic acid or PGA, and polylactic acid or PLA. These materials function as solid-acid precursors, and undergo hydrolytic degradation in the fracture.
 The particulate material used in this invention must have a hydrophobic surface in order that it can be agglomerated by gas while suspended in an aqueous wellbore fluid. The particles may be formed of materials which are inherently hydrophobic or may be particles which are hydrophilic but have a hydrophobic coating on their surface. For instance, ordinary silica sand which is commonly used as a proppant is hydrophilic and is not agglomerated by oil in the presence of water. By contrast, we have found that sand which has been surface treated to make it more hydrophobic will spontaneously agglomerate in the presence of oil, air or nitrogen gas. The particulate material used for this invention may be sand or another mineral material having a specific gravity of 1.8 or more, possibly 2.0 or more, having a particle size as discussed above and having a hydrophobically modified surface, although it is also possible that the invention could be used with a lightweight particulate material such as material with specific gravity in a range from 1.2 or 1.5 up to 1.8. As an alternative to sand or other mineral, the particulate material could be a manufactured ceramic proppant, treated to give it a hydrophobically modified surface, provided this material meets the particle size requirements of this invention. A further possible source of material to be hydrophobically modified and used in this invention is flyash recovered from the flue gas of coal fired power plants. This is a small particle size material with a high silica content. It typically has d90 below 100 micron and specific gravity in the range 1.9 to 2.4.
 A quantitative indication of the surface polarity of a solid (prepared with a smooth, flat surface) is the concept of critical surface tension pioneered by Zisman (see Fox and Zisman J. Colloid Science Vol 5 (1950) pp 514-531 at page 529). It is a value of surface tension such that liquids having a surface tension against air which is lower than or equal to this value will spread on the surface of the solid whereas those of higher surface tension will remain as droplets on the surface, having a contact angle which is greater than zero. A strongly hydrophobic solid has a low critical surface tension. For instance the literature quotes a critical surface tension for polytetrafluoroethylene (PTFE) of 18.5 mN/m and for a solid coated with heptadecafluoro-1,1,2,2-tetra-hydro-decyl-trichlorosilane the literature value of critical surface tension is 12 mN/m. By contrast the literature values of critical surface tension for soda-lime glass and for silica are 47 and 78 mN/m respectively.
 We have found that an analogous measurement of the hydrophobicity of the surface of a particulate solid can be made by shaking the solid with a very hydrophobic oil (preferably a silicone oil) having a low surface tension and mixtures of ethanol and water with a progressively increasing proportion of ethanol. This may be done at a room temperature of 20° C. The surface tensions of a number of ethanol and water mixtures are tabulated in CRC Handbook of Chemistry and Physics, 86th edition, section 6 page 131.
 Increasing the proportion of ethanol in the aqueous phase (i.e. the ethanol and water mixture) reduces its surface tension. Eventually a point is reached when the surface tension of the aqueous phase is so low that the solid can no longer be agglomerated by the oil. The boundary value at which agglomeration by the oil ceases to occur is a measure of the hydrophobicity of the solid and will be referred to as its "agglomeration limit surface tension" or ALST.
 We have observed that particulate solids which can undergo spontaneous aggregation from suspension in deionised water on contact with oil always display an ALST value of approximately 40 mN/m or less. This ALST test covers a range of values of practical interest, but it should be appreciated that if no agglomeration takes place, this test does not give a numerical ALST value, but demonstrates that the surface does not have an ALST value of 40 mN/m or less. Moreover, if the surface has an ALST value below the surface tension of pure ethanol (22.4 mN/m at 20° C.), this test will not give a numerical ALST value but will show that the ALST value is not above 22.4 mN/m.
 When particulate materials to be agglomerated are not inherently hydrophobic, a range of different methods can be used to modify the surface of solid particles to become more hydrophobic--these include the following, in which the first three methods provide covalent bonding of the coating to the substrate.
 Organo-silanes can be used to attach hydrophobic organo-groups to hydroxyl-functionalized mineral substrates such as proppants composed of silica, silicates and alumino-silicates. The use of organosilanes with one or more functional groups (for example amino, epoxy, acyloxy, methoxy, ethoxy or chloro) to apply a hydrophobic organic layer to silica is well known. The reaction may be carried out in an organic solvent or in the vapour phase (see for example Duchet et al, Langmuir (1997) Vol 13 pp 2271-78).
 Organo-titanates and organo-zirconates such as disclosed in U.S. Pat. No. 4,623,783 can also be used. The literature indicates that organo-titanates can be used to modify minerals without surface hydroxyl groups, which could extend the range of materials to undergo surface modification, for instance to include carbonates and sulphates.
 A polycondensation process can be used to apply a polysiloxane coating containing organo-functionalised ligand groups of general formula P--(CH2)3--X where P is a three-dimensional silica-like network and X is an organo-functional group. The process involves hydrolytic polycondensation of a tetraalkoxysilane Si(OR)4 and a trialkoxysilane (RO)3Si(CH2)3X. Such coatings have the advantage that they can be prepared with different molar ratios of Si(OR)4 and (RO)3Si(CH2)3X providing "tunable" control of the hydrophobicity of the treated surface.
 A fluidized bed coating process can be used to apply a hydrophobic coating to a particulate solid substrate. The coating material would typically be applied as a solution in an organic solvent and the solvent then evaporated within the fluidized bed.
 Adsorption methods can be used to attach a hydrophobic coating on a mineral substrate. A surfactant monolayer can be used to change the wettability of a mineral surface from water-wet to oil-wet. Hydrophobically modified polymers can also be attached by adsorption.
 The surface modification processes above may be carried out as a separate chemical process before the wellbore fluid is formulated. Such pretreatment of solid material to make it hydrophobic would not necessarily be carried out at the well site; indeed it may be done at an industrial facility elsewhere and the pretreated material shipped to the well site. However, it is also possible that some of the above processes, especially an adsorption process, could be carried out at the well site as part of the mixing procedure in which the wellbore fluid is made.
 The particulate material must of course form a separate solid phase when the agglomeration takes place. At this time it must therefore be insoluble in the carrier liquid, or at least be of low solubility. For many applications of this invention it will be desirable that the particulate solid remains insoluble after agglomeration has taken place. However, it is within the scope of some forms of this invention that the agglomerates might not have a permanent existence and might in time dissolve in surrounding liquid. For instance, hydrophobically modified calcium carbonate would lead to agglomerates which could be dissolved by subsequent flow of an acidic solution able, eventually, to penetrate the hydrophobic coating.
 The solid particles used in this invention may vary considerably in shape and size. They may have irregular shapes typical of sand grains which can be loosely described as "more spherical than elongate" where the aspect ratio between the longest dimension and the shortest dimension orthogonal to it might be 2 or less. Other shapes such as cylinders or cubes are possible, notably if the particles are a manufactured ceramic product meeting the particle size requirement of this invention.
 Another possibility is that the particulate material has the form of plates. Mica is a material with this characteristic and the particulate material used in this invention may comprise hydrophobically modified mica having a size distribution such that its d50 value is not more than 200 micron.
 The agglomerating agent which binds the particles together as agglomerates is a gas. This gas must be sufficiently hydrophobic to form a phase which does not dissolve in the aqueous carrier liquid, although it is possible for it to have some limited water solubility, as is the case with air and with nitrogen. As mentioned above the amount of gas which can be retained in agglomerates has an upper limit. We have found that agglomeration by gas may be assisted and improved if a small amount of hydrophobic oil is present. However, the amount should be small, such as not more than 10% or not more than 5% or even 2% by volume of the amount of gas downhole. If the amount of oil is larger, agglomeration occurs but the oil displaces gas from the agglomerates and so the amount of gas which can be held by agglomerates is reduced.
 The aqueous carrier liquid which is used to transport the particles may be a non-viscous or slickwater formulation. Such a formulation is typically water or a salt solution containing at least one polymer which acts as a friction reducer. A combination of polymers may be used for this purpose. Polymers which are frequently used and referred to as "polyacrylamide" are homopolymers or copolymers of acrylamide. Incorporation of a copolymer can serve to give the "modified" polyacrylamide some ionic character. A polyacrylamide may considered a copolymer if it contains more than 0.1% by weight of other comonomers. Mixtures of homopolymers and copolymers may be used. Copolymers may include two or more different comonomers and may be random or block copolymers. The comonomers may include, for example, sodium acrylate. The polyacrylamide polymers and copolymers useful as friction reducers may include those having an average molecular weight of from about 1000 up to about 20 million, or possibly above, with from about 1 million to about 5 million being typical. Other suitable friction reducers may be used as well; for example vinyl sulfonates included in poly(2-acrylamido-2-methyl-1-propanesulfonic acid) also referred to as polyAMPS.
 The polyacrylamide may be used in the treatment fluid an amount of from about 0.001% to about 5% by weight of the treatment fluid but the amount is frequently not over 1% or even 0.5% by weight by weight. In many applications, the polyacrylamide is used in an amount of from about 0.01% to about 0.3% by weight of the fluid. The polyacrylamide may be initially dissolved or dispersed as a concentrate in mineral oil or other liquid carrier to enhance the delivery or mixability prior to its addition to water or a salt solution to make the carrier liquid.
 A slickwater formulation may be substantially free of viscosity-enhancing polymeric thickener and have a viscosity which is not much greater than water, for instance not more than 15 centipoise which is about 15 times the viscosity of water, when viscosity is measured at 20° C. and a shear rate of 100 sec-1.
 This invention may also be used where the carrier liquid is a more traditional fracturing fluid incorporating a thickening agent to increase the viscosity of the fluid. Such a thickening agent may be a polymer. It may be a polysaccharide such as guar, xanthan or diutan or a chemically modified polysaccharide derivative such as hydroxyalkylcellulose or a hydroxyalkyl guar. These polysaccharide thickeners may be used without cross linking or may be cross-linked to raise viscosity further. Viscoelastic surfactants are another possible thickening agent which may be used to increase viscosity. We have observed that some thickening of the carrier liquid does not prevent agglomeration, although it may be preferred that the viscosity is not allowed to become too high before agglomeration takes place.
 Agglomerates of hydrophobic particles and a gas as agglomerating agent will form spontaneously in an aqueous carrier liquid when the materials are mixed together. One possibility is that the particulate materials, carrier liquid and agglomerating gas are all mixed together at the surface and then pumped down a wellbore. In this case the particles may agglomerate before passing through the pumps. If so, they may be sheared apart by the pumps, but spontaneously reform downstream of the pumps as they pass down the wellbore.
 A possibility to avoid passing the agglomerates through the pumps is that the gas is compressed at the surface and then admitted to the high pressure flowline downstream of the surface pumps which are driving the carrier liquid and the particulate materials into the wellbore. As a variant of this, the gas could be transported down the wellbore in a separate pipe so as to travel to a considerable depth underground before mixing with the particulate materials.
 Another approach is to allow the materials to mix, but inhibit agglomeration for at least part of the journey of the carrier liquid and entrained materials to the subterranean location where the agglomerates are required. Some possibilities for this are as follows:
 Encapsulation or coating. The particulate materials are coated with a hydrophilic material which dissolves slowly or undergoes chemical degradation under conditions encountered at the subterranean location, thereby exposing the hydrophobic surface within. Degradation may in particular be hydrolysis which de-polymerises an encapsulating polymer. While such hydrolytic degradation may commence before the overall composition has travelled down the wellbore to the reservoir, it will provide a delay before contact between agglomerating gas and exposed hydrophobic surface becomes significant.
 A number of technologies are known for the encapsulation of one material within another material. Polymeric materials have frequently been used as the encapsulating material. Some examples of documents which describe encapsulation procedures are U.S. Pat. No. 4,986,354, WO93/22537, and WO03/106809. Encapsulation can lead to particles in which the encapsulated substance is distributed as a plurality of small islands surrounded by a continuous matrix of the encapsulating material. Alternatively encapsulation can lead to core-shell type particles in which a core of the encapsulated substance is enclosed within a shell of the encapsulating material. Both core-shell and islands-in-matrix type encapsulation may be used.
 An encapsulating organic polymer which undergoes chemical degradation may have a polymer chain which incorporates chemical bonds which are labile to reaction, especially hydrolysis, leading to cleavage of the polymer chain. A number of chemical groups have been proposed as providing bonds which can be broken, including ester, acetal and amide groups. Cleavable groups which are particularly envisaged are ester and amide groups both of which provide bonds which can be broken by a hydrolysis reaction.
 Generally, their rate of cleavage in aqueous solution is dependent upon the pH of the solution and its temperature. The hydrolysis rate of an ester group is faster under acid or alkaline conditions than neutral conditions. For an amide group, the decomposition rate is at a maximum under low pH (acidic) conditions. Low pH, that is to say acidic, conditions can also be used to cleave acetal groups.
 Thus, choice of encapsulating polymer in relation to the pH which will be encountered after the particles have been placed at intended subterranean location may provide a control over the delay before the encapsulated material is released. Polymers which are envisaged for use in encapsulation include polymers of hydroxyacids, such as polylactic acid and polyglycolic acid. Hydrolysis liberates carboxylic acid groups, making the composition more acidic. This lowers the pH which in turn accelerates the rate of hydrolysis. Thus the hydrolytic degradation of these polymers begins somewhat slowly but then accelerates towards completion and release of the encapsulated material. Another possibility is that a polymer containing hydrolytically cleavable bonds may be a block copolymer with the blocks joined through ester or amide bonds.
 Sensitivity to temperature. A development of the use of a hydrophilic coating makes use of the difference between surface temperatures and temperatures below ground, which are almost always higher than at the surface. During transit to the subterranean location, the carrier liquid and everything suspended in it will pass through a wellbore exposed to subterranean temperatures and will begin to heat up, but if the flow rate is substantial, the flowing composition will reach the subterranean location at a temperature well below the natural temperature at that location. In particular, in the case of hydraulic fracturing the fracturing fluid will leave the wellbore and enter the fracture at a temperature significantly below the reservoir temperature. A possibility, therefore, would be to coat the hydrophobic particles with a coating of a hydrophilic material which remains intact at surface temperatures, but melts or dissolves in the carrier liquid at the temperature encountered below ground.
 Generating gas below ground. Another possible approach for delaying agglomeration during at least part of the journey of the materials to the subterranean location where the agglomerates are required is to generate the agglomerating gas chemically, for example by including aluminium powder in the composition and formulating the carrier liquid to be alkaline so that hydrogen is generated by reaction of aluminium and the aqueous alkaline carrier liquid. Conversely, iron or zinc particles could be incorporated in a fluid with pH below 7 to generate hydrogen. A further possibility for generating gas below ground would be to pump a neutral slickwater fluid containing suspended calcium carbonate particles, followed by an acidic slickwater fluid containing hydrophobic fibres and hydrophobic particulate proppant. Carbon dioxide would then be liberated below ground on contact between the acidic slickwater and the carbonate previously placed below ground. In the methods above for generating gas below ground, the solid material could be encapsulated in or coated with a material which dissolves or melts at the reservoir temperature, thus delaying the start of the chemical generation of gas. Another way to generate carbon dioxide would be to incorporate nanoparticulate polycarbonates which decompose, liberating carbon dioxide, at a temperature of around 150° C.
 Discussion above has focused on placing particulate material below ground. However, the invention also has application to the removal of particulate material in wellbore clean-out. After hydrophobic particulate materials have been placed in a fracture (or other location underground) the removal of hydrophobic particulate material remaining in the wellbore can be carried out by using coiled tubing to pump gas, or a mixture of gas and aqueous liquid, into the bottom of the wellbore while the wellbore contains aqueous liquid. This gas will rise towards the surface. If it encounters hydrophobic particulate material it will agglomerate that material into lightweight particles which will rise or be carried upward to the surface.
BRIEF DESCRIPTION OF THE DRAWINGS
 FIG. 1 diagrammatically illustrates features of a close-packed agglomerate;
 FIG. 2 similarly illustrates features of an agglomerate which is not close packed;
 FIG. 3 is a graph of density against composition for mixtures of nitrogen and hydrophobically modified sand;
 FIG. 4 schematically illustrates the use of the invention in fracturing, and
 FIG. 5 illustrates fracturing from a horizontal wellbore.
Hydrophobic Modification of Materials.
 There are several procedures for hydrophobic modification of materials such as sand which have hydroxyl groups at their surface before modification.
Toluene Reflux Method
 Sand of the required particle size was washed by mixing with ethanol at ambient temperature, then filtering, washing with deionised water and drying overnight at 80° C.
 Quantities of this pre-washed sand were hydrophobically modified. 75 gm pre-washed sand was added to a mixture of 200 ml toluene, 4 ml organo-silane and 2 ml triethylamine in a 500 ml round bottomed flask. The mixture was refluxed under a nitrogen atmosphere for 4 to 6 hours. After cooling, the hydrophobically modified sand (hm-sand) was filtered off (on a Whatman glass microfiber GF-A filter) and then washed, first with 200 ml toluene, then 200 ml ethanol and then 800 ml deionised water. The hm-sand was then dried overnight at 80° C.
 The above procedure was carried out using both 20/40 and 70/140 sand and using each of the following four reactive organo-silanes:
 5.64 gm Heptadecafluoro-1,1,2,2-tetrahydro-decyl-triethoxysilane (>95% purity, specific gravity=1.41 gm/ml).
 5.40 gm Tridecafluoro-1,1,2,2-tetrahydro-octyl-triethoxysilane (>95% purity, specific gravity=1.35 gm/ml).
 3.53 gm Octadecyl-trimethoxysilane (90% purity, specific gravity=0.883 gm/ml).
 5.93 gm Octadecyldimethyl 3-trimethoxysilylpropyl ammonium chloride (60% active solution in methanol, specific gravity=0.89 gm/ml).
 These quantities of organo-silane were far in excess of the stoichiometric amount required to react with all the hydroxyl groups on the surface of the sand particles. A direct determination of the specific surface area of the 70/140 sand by an analytical laboratory using a B.E.T. method gave a value of 0.15 m2/gm (because this measurement takes account of surface texture, the value is above the value for the surface area of equivalent spheres determined by a Malvern Mastersizer). The theoretical maximum concentration of hydroxyl (--OH) groups per unit area of silica surface, is 4.5 hydroxyl groups per square nanometre. From these values it can be calculated that 75 gm 70/140 sand has approximately 5.2×1019 hydroxyl groups exposed on its surface. Using Avogadro's number, 5.64 gm (0.00924 mol) heptadecafluoro-1,1,2,2-tetra-hydro-decyl-triethoxysilane contains 5.56×1021 molecules which is an approximately 100-fold excess. (It should be noted that at least some excess organosilane is removed from the treated sand during the filtration and washing stages). In previous work we had found that use of a significant excess of reactive silane was useful to obtain effective hydrophobic modification of the particles' surfaces.
 The procedure of Example 1 above was also used to bring about hydrophobic modification of two further materials having particle size as given in the following table which also includes size data for the 70/140 sand of the previous example.
TABLE-US-00001 70/140 sand Muscovite mica Fine silica d10 121 micron 50 micron 6 micron d50 169 micron 111 micron 34 micron d90 235 micron 200 micron 84 micron
 The reactive organosilane used with both of these particulate materials was heptadecafluoro-1,1,2,2-tetrahydro-decyl-triethoxysilane. 75 gm of the particulate solid was treated with 5.89 gm of the reactive silane.
 70/140 sand, prewashed as in Example 1 above, was given a hydrophobic surface coating by the simultaneous condensation polymerization of tetraethylorthosilicate (TEOS) and heptadecafluoro-1,1,2,2-tetrahydro-decyl-triethoxysilane in 3:1 molar ratio under basic conditions.
 200 gm pre-washed sand, 12 ml of aqueous ammonia (NH4OH, 28%), 57 ml of absolute ethanol and 3 ml deionized water were mixed and stirred vigorously (Heidolph mechanical stirrer at 300-400 RPM) for 30 min. Then 0.73 gm (3.53 mmol) of TEOS and 0.63 gm (1.17 mmol) heptadecafluoro fluoro-1,1,2,2-tetrahydro-decyl-triethoxysilane were added and stirred for 3.5 hrs at room temperature. The resulting hm-sand was then filtered off, washed with ethanol and then with deionized water and dried at 120° C. overnight.
 This procedure was also carried out using pre-washed 70/140 sand with a mixture of tetraethylorthosilicate (TEOS) and octadecyl-trimethoxysilane.
Agglomeration with Gas
 FIG. 1 diagrammatically illustrates a portion of an agglomerate formed from particles in a close packed arrangement. In this illustration the particles are spheres 10 of uniform size. The interstitial volume, that is the spaces 12 between particles, is determined by the geometry of the arrangement. For an agglomerate of a large number of close packed spheres of uniform size, it can be calculated that the interstitial volume amounts to a volume fraction of 0.36. The spheres of course then occupy a volume fraction of 0.64. If the particles are not spherical or are not uniformly sized the interstitial volume of a close packed arrangement will still be dictated by geometry but be a different fraction of the overall volume. Notably, a mixture of particle sizes can give a closely packed arrangement in which the interstitial volume fraction is smaller than 0.36.
 It can be envisaged that if the amount of agglomerating agent is larger than the interstitial volume of a close packed arrangement, the particles will still be agglomerated but will not be in a completely close packed state. They would instead be slightly spaced as shown in FIG. 2 and the interstitial volume would then be larger, thus taking up the available amount of agglomerating agent.
 We have previously found that when hydrophobic particles are agglomerated with oil this does indeed happen. A quantity of oil in excess of the minimum amount required to bring about agglomeration can be included in the agglomerates. However, we have now found that this does not happen, or does not happen to the same extent, when the agglomerating agent is gas.
 FIG. 3 is a graph of density against volume fraction of nitrogen in hypothetical mixtures of hydrophobically modified sand (specific gravity 2.65) and nitrogen gas as an agglomerating agent. The specific gravity of the nitrogen gas is taken to be 0.081 at a pressure of 10 MPa and a temperature of 400 Kelvin (127° C.) representative of a downhole pressure and temperature. If the agglomerates were to have a nitrogen volume fraction of 0.64 (that is 64 parts by volume nitrogen and 36 parts by volume sand) they would have a density of 1 gm per ml, which is neutral buoyancy in water. However, we have found by experiment that stable agglomerates of the commonly used 20/40 sand with air or nitrogen as agglomerating agent do not contain such a high volume of fraction of the gas and remain denser than water even after attempting to incorporate as much air or nitrogen as possible. This is also the case with 70/140 sand but with this smaller particle size proppant the maximum amount of gas which can be incorporated is larger and a lower bulk density can be achieved.
Agglomeration of hm-Particulates
 2 gm 70/140 sand, hydrophobically modified with tridecafluoro-1,1,2,2-tetrahydro-octyl-triethoxysilane as in Example 3 and having a specific gravity of 2.65 was mixed with 20 ml of deionised water in a bottle of about 40 ml capacity, thus leaving an air-filled headspace of about 15 ml in the bottle. The bottle was closed and shaken vigorously so that the solids could be agglomerated with air from the headspace.
 A single agglomerate with a smoothly curved surface was formed. This demonstrated that the hydrophobically modified sand could be agglomerated with air. However, the agglomerate sank to the bottom of the bottle, indicating that the amount of air which could be retained in the agglomerate was not a sufficiently large volume fraction to give an agglomerate of neutral buoyancy. The bottle was stored at 80° C. for 3 months, during which time the agglomerate remained stable.
 In a similar experiment nitrogen gas was bubbled into the bottle near the bottom instead of shaking the bottle. Again an agglomerate formed, but it remained at the bottom of the bottle.
 Examination of the particle size of this hm sand using a Malvern Mastersizer 2000 showed a symmetrical particle size distribution with d10=121 micron, d50=169 micron and d90=235 micron. Surface area determined by the same instrument was 0.014 m2 per gram. Taking into account the specific gravity (2.65) of the sand, this was 37 m2 per liter (0.037 m2 per milliliter) of solid.
 The procedure of Example 4 above was also carried out using the hydrophobically modified fine silica of Example 2 which had an asymmetric particle size distribution with a distinct tail of fine particles determined by Malvern Mastersizer as d10=6 micron, d50=34 micron and d90=84 micron; surface area 0.16 m2 per gram. Taking into account the specific gravity (2.65) of the silica, this corresponded to 424 m2 per liter (0.42 m2 per milliliter) of solid. After shaking the closed bottle, the proppant agglomerates which formed floated to the top of the liquid in the bottle, indicating that their bulk density was less than 1 gm/ml.
 1 gm hydrophobically modified 20/40 sand, prepared as in Example 3 and 1 gm hydrophobically modified silica prepared as in Example 2 were mixed together. Details of the silica are stated in Example 5. Examination of the 20/40 sand using a Malvern Mastersizer 2000 showed a symmetrical particle size distribution with d10=442 micron, d50=616 micron and d90=874 micron. Surface area calculated by the same instrument was 0.0038 m2 per gram. Taking into account the specific gravity of the sand, this is 10 m2 per liter (0.010 m2 per milliliter) of solid. Consequently the calculated surface area of the 1:1 mixture was 217 m2 per liter (0.22 m2 per milliliter) of solid.
 The particulate mixture was mixed with 20 ml of deionised water in a bottle of about 40 ml capacity, thus leaving an air-filled headspace of about 15 ml in the bottle. The bottle was closed and shaken vigorously so that the solids could be agglomerated with air from the headspace.
 It was observed that a substantial part of the resulting agglomerates floated to the top of the water in the bottle, indicating that these agglomerates had a bulk density below 1 gm/ml. Part of the agglomerates sank, but the agglomerated material had an uneven surface and appeared to be more buoyant than the agglomerate of 70/140 sand described in Example 4, indicating that these agglomerates included some fine silica.
 The experiment was repeated using the fine silica and 20/40 sand in a weight ratio of 30:70. The surface area of this mixture was calculated to be 134 m2 per liter (0.13 m2 per milliliter) of solid. Similar results were observed.
 0.5 gm of the muscovite mica hydrophobically modified as in Example 2 was mixed with 20 ml of deionised water in a bottle of about 40 ml capacity, thus leaving an air-filled headspace of about 15 ml in the bottle. The bottle was closed and shaken vigorously so that the solids could be agglomerated with air from the headspace. A comparison experiment was carried out using unmodified mica.
 In the comparison experiment all the mica settled at the base of the bottle. With hydrophobically modified mica, some of the material formed agglomerates which floated, some of the material sank. The material which sank was visibly more buoyant and less firmly settled on the bottom of the bottle than was the case in the comparison experiment using unmodified mica.
 The procedure of Example 4 was repeated using polytetrafluoroethylene (ptfe) particles with a d50 particle size of 100 micron and a specific gravity of 2.1. This material is of course inherently hydrophobic. After shaking the closed bottle, the proppant agglomerates which formed floated to the top of the liquid in the bottle, indicating that their bulk density was less than 1 gm/ml.
APPLICATION OF THE INVENTION
 To illustrate and exemplify use of some embodiments of the method of this invention, FIG. 4 shows diagrammatically the arrangement when a fracturing job is carried out. A mixer 14 is supplied with a small amount of viscosity reducing polymer, particulate material and water as indicated by arrows V, P and W. The mixer delivers a mixture of these materials to pumps 16 which pump the mixture under pressure down the production tubing 18 of a wellbore 20. Nitrogen from a supply 22 pressurized by compressor 24 is driven down a tube 26 within the production tubing 18 and forms agglomerates of the particulate materials when it exits into the flow within tubing 18. The aqueous carrier liquid and suspended agglomerates 28 then pass through perforations 30 into the reservoir formation 32 as indicated by the arrows 34 at the foot of the well.
 In the early stages of the fracturing job, the fluid does not contain particulate solid nor added nitrogen but its pressure is sufficiently great to initiate a fracture 36 in the formation 32. Subsequently the particulate materials and nitrogen are mixed, as described above, with the fluid which is being pumped in. Its pressure is sufficient to propagate the fracture 36 and as it does so it carries the suspended agglomerates 28 into the fracture 36. Because the agglomerates have a low density they do not settle out at the entrance to the fracture, but are carried deep into the fracture.
 FIG. 5 illustrates the use of tubing 40, which may be coiled tubing, to form fractures within a horizontal wellbore. As illustrated here, fracture 42 has already been formed and has been closed off by a temporary plug 44. Fracture 46 is being formed. In a manner generally similar to the arrangement of FIG. 4, water, friction reducing polymer, a small quantity of oil and the particulate materials are supplied under pressure through tubing 40. Pressurized nitrogen is supplied along smaller tubing 48. Agglomerates form as nitrogen gas exits from the tubing 48, and the flow of carrier liquid delivers these into the fracture 46 which extends both upwards and downwards from the wellbore.
Patent applications by Bruno Drochon, Houston, TX US
Patent applications by Evgeny Barmatov, Cambridge GB
Patent applications by Jill Geddes, Cambridge GB
Patent applications by Sergey Makarychev-Mikhailov, Richmond, TX US
Patent applications by Trevor Hughes, Cambridge GB
Patent applications in class Contains intended gaseous phase at entry into wellbore
Patent applications in all subclasses Contains intended gaseous phase at entry into wellbore