WO1998040606A1

WO1998040606A1 - Well treatment with particles

Info

Publication number: WO1998040606A1
Application number: PCT/GB1998/000552
Authority: WO
Inventors: Philip John Charles Webb
Original assignee: Aea Technology Plc
Priority date: 1997-03-13
Filing date: 1998-02-20
Publication date: 1998-09-17
Also published as: AU6300898A; GB9705200D0

Abstract

Well treatment chemicals are deposited as a hard adherent coating onto insoluble inorganic particles such as ceramic beads. The solution from which deposition occurs includes a deposition-enhancing agent, for example an antifoam agent, and has a pH and a polyvalent cation concentration which ensure the coating is of low solubility. The coated particles are used as proppants or in filter beds within a well, gradually releasing the chemicals into the well fluids.

Description

Well Treatment with Particles

This invention relates to particles which incorporate chemicals for treating wells, such as oil wells, to a method of treating a well using such particles, and to a method of making such particles.

For many oil wells the composition of the fluid or fluids in or adjacent to the well is such that it is beneficial to add to the fluid a material to inhibit deleterious processes (such as corrosion, or scale deposition) wnich woulα otnerwise occur. The provisior or sucn inhibitor material in an oil well is theretore well known, It may be injected as a liquid, or incorporated into a bead or particle, for example (EP 0 193 369 (Exxon)) in a polymer bead from which it leaches out into the well fluid, or (US 3 782 469 (Fulford) ) adsorbed onto proppant particles such as sand grains, or (GB 2 284 223 B (AEA Technology) ) precipitated in a porous ceramic bead. In the case of water wells and water injection wells too there may be a need to supply water treatment chemicals to the well. Such beads or particles may be introduced into the well m a variety of ways, for example m a prepacked screen, or in a gravel pack, or as a fracture proppant.

According to the present invention there is provided a method of treating a well, the method comprising of depositing a well treatment agent onto insoluble, inorganic particles, by wetting the particles with a solution in a solvent, the solution comprising the well treatment agent, polyvalent cations if the solvent is aqueous, and a deposition-enhancing agent, and drying the wetted particles gradually so as to deposit a hard, adherent coating comprising the well treatment agent on the external surface of the particles, and introducing the coated particles into the well.

The solution used to wet the particles desirably has a viscosity higher than that of water, for example up to 20 times that of water, as this ensures that a thicker coating of the solution remains on the particles. Good results have been obtained with a solution of viscosity 5 times that of water, i.e. of viscosity 5 x 10 Pa s. The well treatment agent might be a scale inhibitor, corrosion inhibitor, αsphaltene deposition inhibitor, wax deposition mhiDitor, σemuisifier, gel breaker, biocide, or a hydrogen sulphide scavenger, for example. The deposition-enhancing agent may be a polymeric and/or an organic material. It may aid the formation of a liquid coating, for example being a surface wetting agent, and/or a viscosifier, or it may influence the form of the deposited solid, for example being an anti-foam agent. For example it might comprise a silicone oil acting as an antifoam agent; this is preferably provided m sufficient quantity to give a concentration of between 100 and 1000 ppm m the solution, for example 200 ppm.

In this specification the term 'solution' is to be taken as encompassing both solutions and dispersions. The particles may be porous or non-porous, but are preferably not more than 30% porosity, as particles of higher porosity tend to be insufficiently strong. The particles may be of any shape, but the preferred particles are generally spheroidal beads, or spherical beads, preferably of an inorganic oxide or a ceramic material for example alumina, silica, silicon carbide or aluminium silicate based material. The coating on the surface is typically of thickness in the range 1 urn up to 20 μm, for example 2 μm or 5 μm. The drying step desirably takes place at a temperature above the boiling point of the solvent at the applied pressure, but is desirably sufficiently gradual that the drying takes more than 1 hour, preferably more than VA hours to complete. If the pressure is atmospheric, for an aqueous solvent the temperature is desirably m the range 100°C to 120°C; for example the particles might be exposed to a gas stream at 120°C. If the particles are dried at a temperature below the solvent's boiling point, the drying process will be slower.

The invention also provides particles coated with well treatment agent by the said deposition method, tor use m the treatment method. The particles may oe introduced into the well m a prepacked screen, or in a gravel pack, or as proppant particles injected into the formation around the well, or m other ways, and may be used on their own or m conjunction with other types of particle. For any of these uses the particles are preferably of size m the range 0.3 mm to 5 mm, more preferably between 0.5 mm and 2.0 mm, for example about 0.5 mm or about 1.0 mm. It is often desirable to have all the particles of the same size.

Once introduced into the well, the coated particles act as a reservoir of the well treatment agent, which gradually leaches out into the well fluids over a period which is preferably several months and for some well treatment agents is preferably more than a year, for example between 3 and 5 years. Typically the resulting concentration of the chemical in the well bore is m the range 0.1 to 100 ppm, preferably 1 to 50 ppm, for example 10 ppm. The term "insoluble" means that the particles are not soluble in the well fluids (e.g. water, brine, or oil) under the conditions found m the well, which typically means at temperatures no higher than 250°C and pressures no higher than about 120 MPa . Because they are insoluble they continue to act as proppant, gravel-pack or filter-pack particles even after all the well treatment agent has leached away.

It is desirable for the coated particles to comply with the API specification for the use to which they are to be put. This recommends testing criteria for particle shape, for acid resistance (in 12% HC1 and 3% HF solution), and for crush resistance. The particles are therefore desirably strong enough to withstand crushing at pressures above 1000 psi (6.9 MPa), for example above 3000 psi (21 MPa) , for example up to 6000 psi (41 MPa) or higher. The API criterion for crushing strength depends on the particle size, and on use; for example sand particles of size 20 - 40 mesh (0.42 - 0.84 mm) for use in gravel packs must not lose more than 2% by mass at a closure pressure of 2000 psi, sand particles of that size for use as fracture proppants must not lose more than 14% at 4000 psi, while particles of that size for use as high strength fracture proppants must not lose more than 10% at a closure pressure in the range 7500 to 15000 psi.

The chemical composition of the solution from which the coating is derived has a significant effect on the nature of the coating, and on the subsequent rate of dissolution when the coated particles are exposed to well fluids. For example polyvalent cations promote the formation of a solid coating of scale inhibitor on particles, the coating dissolving at a rate which results in scale inhibitor concentrations in the range 0.1 to 100 ppm (as discussed earlier) . The preferred cations are calcium and magnesium. The cation concentration is preferably in the range 5000 to 150 000 ppm. As the mole ratio of polyvalent cation to scale inhibitor is increased in the solution from which the coating is deposited, the concentration of scale inhibitor in water subsequently flowing past the coated particles decreases. Also the pH of the solution affects the composition of the deposited coating, and so affects the subsequent rate of dissolution of the inhibitor (e.g. scale inhibitor) into water flowing past the coated particles. Increasing the pH of the solution reduces the rate of release of the inhibitor The pH is generally adjusted to be m the range 6 to 11, for example pHlO.

The drying step is also important in determining whether or not a hard, adherent coating is produced. If the drymσ takes olace too

tne deposition will tend to De powdery or flaky ano non-adherent On tne other hand slow drying reduces the throughput and so may not be economic. Drying m a fluidised bed using an air stream supplied at between 110°C and 140°C, more preferably about 120°C, has been found to be satisfactory. Other types of drier, such as rotary driers, cone driers or paddle driers may be used, as long as rapid drying is avoided. The drying may be performed at ambient pressure, or at reduced pressure.

It will be appreciated that the concentration of the well treatment agent which is required in the well fluids will differ from well to well. The present invention allows a coating of well treatment agent to be deposited on the particles with the requisite solubility and dissolution rate for use m a particular well.

The invention will now be further and more particularly described by way of example only, and with reference to the accompanying drawing which shows graphically the variation of inhibitor concentration with volume of water flowing through a packed bed. To increase the permeability of oil-bearing strata m the vicinity of an oil well, it is known to inject a fluid into the well such that the pressure at the depth of those strata is sufficient to cause cracking or fracturing of the rocks of the strata. The fluid may contain a dissolved polymer cross-linked to form a gel (so it is of high viscosity), and may include particles of solid material which are carried into the fractures as the fluid is injected. The gel subsequently breaks down, and the particles prevent the fractures closing when the pressure is reduced. Such particles may be referred to as proppant particle-:.

Example 1

One type of proppant particle comprises 0.5 mm diameter spheres of an alumino silicate ceramic. Such particles may be coated with a layer of scale inhibitor as follows. A 25 wt% solution of commercially available part neutralised diethylene-triamme penta (methylene- phosphonic acid) has its solution pH set to 8.0 by the addition of concentrated sodium hydroxide. A silicone oil type anti-foam is added to give a solution concentration of 200 ppm. Calcium and magnesium chlorides are added to the scale inhibitor solution to give calcium and magnesium solution concentrations of 500 ppm and 15 000 ppm respectively.

The resulting mixture is more viscous than water. It is used to wet the spherical proppant particles, and the excess liquid drained off. The particles are then dried m a fluidised bed with an air stream at 120°C over a period of between IV-. and 2 hours, so forming a hard, adherent coating of solid scale inhibitor on their surfaces of thickness about 5 urn. Experimental measurements were then taken, using a column packed with the coated particles, and causing sea water (obtained from near Chesil Beach) to flow through the column. Referring to the drawing, this shows how the concentration of inhibitor m the sea water emerging from the column varied with the number of column pore volumes which have flowed through the column. The inhibitor dissolves m the water, at first rapidly, and then at a steady rate.

The following two examples are of different solutions, each containing a different scale inhibitor, which are suitaole for use m torming a coating on proppant particles.

Example 2

A 40 wt% solution of commercially available phosphmo-carboxylic acid has its solution pH set to 10.0 by the addition of concentrated sodium hydroxide. A silicone oil type anti-foam is added to give a solution concentration of 200 ppm. Calcium and magnesium chlorides are added to the scale inhibitor solution to give calcium and magnesium solution concentrations of 20 000 ppm and 10 000 ppm, respectively. This solution has a viscosity about five times that of water (at room temperature) .

Example 3

A 40 wt% solution of commercially available a polyvmylsulphonate has its solution pH set to 10.0 by the addition of concentrated sodium hydroxide. A silicone oil type anti-foam is added to give a solution concentration of 200 ppm. Calcium chloride is added to the scale inhibitor solution to give a calcium solution concentration of 40 000 ppm. This solution has a viscosity about three times that of water.

It will be appreciated that the invention is applicable with a wide range of different oilfield chemicals. Other suitable scale inhibitors are: polyacrylate, a copolymer of vmylsulphonate and acrylic acid, a copolymer of maleic acid and acrylic acid, or other phosphonate-type inhibitors such as aminotrimethylene phosphonic acid. A solution of such a chemical at a concentration m tne range 25 to 50 wt% would have its pH set m the range 6-11 by adding for example sodium hydroxide or hydrochloric acid, and polyvalent cations such as calcium or magnesium added as chlorides or carbonates. After addition of a deposition enhancing agent the mixture would be used to coat particles, and the particles then gradually dried. The particles might be dried in a rotary drier with an air stream at 120°C, or in a cone drier under reduced pressure, for example 0.75 atmosphere, and at a temperature corresponding to a vapour pressure of for example 0.75 to 0.9 atm. The deposition enhancing agent might be silicone oil (as m the examples given earlier) , or might be a surfactant such as sodium dodecylbenzene sulphonic acid or nonylethoxylated phenols, which are typically provided at a concentration (by weight) m the range 10 ppm up to 1000 ppm.

Claims

C laims

1. A method of treating a well, the method comprising depositing a well treatment agent onto insoluble, inorganic particles by wetting the particles w th a solution in a solvent, the solution comprising the well treatment agent, and polyvalent cations if the solvent is aqueous, drying the wetted particles, and introducing the coated particles into the well, and characterised in that the solution also contains a deposition-enhancing agent, that the drying is performed gradually, and the deposition method is such that a hard, adherent coating comprising the well treatment agent is deposited on the external surface of the particles.

2. A method as claimed in Claim 1 wherein the deposition enhancing agent comprises a surface-wetting agent and/or a viscosifier and/or an antifoam agent.

3. A method as claimed m Claim 1 or Claim 2 wherein the solvent is aqueous, and the solution contains polyvalent cations in the range 5000 to 150 000 ppm and has a pH m the range 6 to 11, selected to acnieve a coating of desired solubility.

4. Particles coated with a hard, adherent coating on their external surface for use in the treatment method as claimed m any one of the preceding Claims.

5. Particles as claimed in Claim 4 wherein the coating is of thickness m the range 2 ╬╝m to 10 ╬╝m.