GB1591313A - Wellbore fluids and dry mix additive packages for use in such fluids - Google Patents

Description

(54) WELLBORE FLUIDS AND DRY MIX ADDITIVE PACKAGES FOR USE IN SUCH FLUIDS (71) We, BRINADD COMPANY, formally known as CHEMICAL ADDITIVES COMPANY, a corporation organised and existing under the laws of the State of Texas, United States of America, of 6003 Murphy Street, Houston State of Texas 77033, United States of America, (assignee of ARLYNN HENRY HARTFIEL), do hereby declare the invention, for which we pray that a patent may be granted to us, and the method by which it is to be performed, to be particularly described in and by the following statement: The present invention relates to dry mix additive packages and their use in wellbore fluids, including drilling fluids, completion fluids, workover fluids, and packer fluids, that is, all of those fluids which are employed over the course of the life of a well.

Generally wellbore fluids will be either clay-based or brines which are clay-free. These two classes are exclusive, that is, clay-based drilling fluids are not brines. A wellbore fluid can perform any one or more of a number of functions. For example, the drilling fluid will generally provide a cooling medium for the rotary bit and a means to carry off the drilled particles. Since great volumes of drilling fluid are required for these two purposes, the fluids have been based on water. Water alone, however, does not have the capacity to carry the drilled particles from the borehole to the surface.

In the drilling fluid class, clay-based fluids have for years preempted the field, because of the traditional and widely held view in the field that the viscosity suitable for creating a particle carrying capacity in the drilling fluid could be achieved only with a drilling fluid having thixotropic properties, that is, the viscosity must be supplied by a material that will have sufficient gel strength to prevent the drilled particles from separating from the drilling fluid when agitation of the drilling fluid has ceased, for example, in a holding tank at the surface.

In order to obtain the requisite thixotropy or gel strength, hydratable clay or colloidal clay bodies such as bentonite or fuller's earth have been employed. As a result the drilling fluids are usually referred to as "muds". The use of clay based drilling muds has provided the means of meeting the two basic requirements of drilling fluids, i.e., cooling and particle removal. However, the clay-based drilling muds have created problems for which solutions are needed. For example, since the clays must be hydrated in order to function, it is not possible to employ hydration inhibitors, such as calcium chloride, or if employed, their presence must be at a level which will not interfere with the clay hydration.In certain types of shales generally found in the Gulf Coast area of Texas and Louisiana, there is a tendency for the shale to disintegrate by swelling or cracking upon contact with the water if hydration is not limited. Thus the uninhibited clay-based drilling fluids will be prone to shale disintegration.

The drilled particles and any heaving shale material will be hydrated and taken up by the conventional clay-based drilling fluids. The continued addition of extraneous hydrated solid particles to the drilling fluid will increase the viscosity and necessitate costly and constant thinning and reformulation of the drilling mud to maintain its original properties.

Another serious disadvantage of the clay-based fluids is their susceptibility to the detrimental effect of brines which are often found in drilled formations, particularly Gulf Coast formations. Such brines can have a hydration inhibiting effect, detrimental to the hydration requirement for the clays.

Other disadvantages of clay-based drilling fluids are (1) their tendency to prevent the escape of gas bubbles, when the viscosity of the mud rises too high by the incidental addition of hydratable material, which can result in blow-outs; (2) the need for constant human control and supervision of the clay-based fluids because of the expectable, yet unpredictable, variations in properties; and (3) the formation of a thick cake on the internal surfaces of the wellbore.

The brines have the advantage of containing hydration inhibiting materials such as potassium chloride, calcium chloride or the like. Quite apparently any solid particulate material would be easily separated from the brine solution since it is not hydrated. Thus, the properties of the brine are not changed by solid particulate matter from the wellbore.

Similarly, there is no opportunity for gas bubbles to become entrapped, blowouts are less likely in a clay-free brine-type wellbore fluid.

Non-argillaceous (clay-free wellbore fluids based on non-thixotropic viscosifiers have been developed, which overcome the problems noted above with the clay-based fluids, such as a brine containing a viscosifying amount of magnesia stabilized hydroxyethyl cellulose described in detail in United States Patent Specification No. 3,852,201.

Thus, although these two principal water-based, competing and incompatible systems are commercially available and used, there is yet a hiatus, in a manner of speaking, between the capacities and desirable properties of these two systems. Thus, even though the clay-free systems described avoid the problems of the clay-based systems, they are not suitable for systems where weighting materials such as calcium carbonate are necessary or desired, especially if the weighting material is used in substantial quantities.

A material which has come into expanding use in wellbore fluids is heteropolysaccharide produced by the action of bacteria of the genus Xanthomonas on carbohydrates, such as described in United States Patent Specifications Nos. 3,198,268; 3,208,526; 3,251,417; 3,243,000; 3,305,016; 3,319,715; and 3,953,336. This material has been employed for a number of functions in the wellbore fluids, e.g., fluid loss additive, foaming agent, and viscosifier. Generally these heteropolysaccharides are employed with clays; however, they need not be, and in United States Patent Specification No. 3,319,715 they are disclosed to be useful in brine completion fluids.

It has been found that an improved clay-free wellbore fluid having thixotropic gel properties and containing a weighting agent for use in subterranean formations in the earth is comprised of water, a viscosifying amount of heteropolysaccharide produced by the action of bacteria of the genus Xanthomonas on carbohydrates, a weighting amount of a weighting material, a stabilizing amount of lignosulfonate salt and a brine forming soluble salt.

According to the present invention there is provided an aqueous clay-free thixotropic wellbore fluid for use in subterranean formations in the earth which comprises water, at least 1% by weight of a brine forming soluble salt or mixture of salts, a viscosifying amount of a non-cross-linked heteropolysaccharide prepared by the action of bacteria of the genus Xanthomonas on carbohydrates, a weighting amount of a powdered weighting material and a stabilizing amount of lignosulfonate salt, the fluid optionally containing in addition either at least 0.50 gram of MgO per liter of wellbore fluid or a starch or modified starch but not both. Preferably MgO is present as a stabilizer.

According to the present invention there is also provided a dry mix additive package for use in aqueous clay-free brine well fluids comprising an intimate mixture of non-crosslinked heteropolysaccharide, prepared by the action of bacteria of the genus Xanthomonas on carbohydrates and lignosulfonate salt in a weight ratio of 0.08 : 1 to 14.28 : 1.

Suitable weighting agents or materials are those generally known to the prior art of well working fluids such as powdered weighting materials comprising substantially waterinsoluble solid materials having a specific gravity greater than 2.6 grams per cc, for example, barium sulfate (barite or barytes) BaSO4, the various lead oxides, chiefly litharge (PbO) and red lead (Pb3O4), the iron ores or iron oxides, chiefly magnetite (Fe304) and hermatite (Fe2O3); powdered iron, zinc, and lead or other powdered heavy metals and their solid or other water-insoluble stable compounds, such as metal carbonates, for example calcium carbonate, iron carbonate (ferrous carbonate), barium carbonate, and the like.

The materials are employed to provide 0.72 to 7.14 grams of heteropolysaccharide prepared by the action of bacteria of the genus Xanthomonas on carbohydrates; 100 to 500 grams of powdered weighting material such as CaCO3, and 0.5 to 9.0 grams of the lignosulfonate salt per liter of wellbore fluid or more preferably 0.72 to 3.57 grams, 200 to 400 grams, and 0.7 to 7.0 grams per liter, respectively. The three component system of heteropolysaccharide, lignosulfonate salt and weighting material such as CaCO3 is more stable in brines regarding the settling of the weighting material such as CaCO3 than a fluid without the lignosulfonate salt.

According to a further embodiment of the present invention there is provided a method of treating a subterranean formation by injecting thereinto the wellbore fluid of the present invention.

In dry mix compositions the CaCO3 or other weighting materials would comprise from about 86.10 to 99.76 weight percent, the heteropolysaccharide about 0.15 to 6.63 weight percent and the lignosulfonate salt about 0.09 to 8.2 weight percent, or a dry mix of heteropolysaccharide and lignosulfonate salt in the weight ratio in the range of 0.08 1 to 14.28 : 1.

The heteropolysaccharides are those produced as generally described in United States Patent Specifications referred to hereinabove. The heteropolysaccharides are commercially available. Methods for the preparation are also described in the following literature articles: an article by J.G. Leach, V.G. Lilly, H.A. Wilson and M.R. Purvis, Jr., entitled "The Nature and Function of the Exudate Produced by Xanthomonas phaseoli," which appeared in Phytopathology, volume 47, pages 113 to to 120 (1957); an article by V.G. Lilly, H.A.

Wilson and J.G. Leach entitled "Bacterial Polysaccharides II: Laboratory-Scale Production of Polysaccharides by Species of Xanthomonas," which was published in Applied Microbiology, volume 6, pages 105 to 108 (1958); a paper by R.F. Anderson, S.P. Rogovin, M.C. Cadmus and R.W. Jackson, "Polysaccharide Production by Xanthomonas campestris," presented at the 136th National Meeting of the American Chemical Society in Atlantic City, New Jersey, on September 14-18, 1959; and a paper by A.R. Jeanes, J.E.

Pittsley, J.H. Sloneker and F.R. Senti, "Composition and Properties of a Heteropolysaccharide Produced From Glucose by Xanthomonas campestris NRRL B-1459," which was delivered at the 136th National Meeting of the American Chemical Society in Atlantic City, New Jersey, on September 14-18, 1959.

A typical heteropolysaccharide material is produced by the action of Xanthomonas campestris NRRL B-1459 upon carbohydrates. The purified product can be characterized as a soft, bulky powder having a slight tint, which swells rapidly in the presence of small quantities of water and dissolves in larger quantities. Generally from 0.72 to 7.14 grams of the heteropolysaccharide are dissolved per liter of wellbore fluid and more preferably 0.72 to 3.57 grams per liter. Amounts less than 0.72 grams per liter (0.25 pounds per barrel) are ineffective to provide the necessary thixotropic properties in the fluid. Amounts above 7.14 grams per liter (2.5 pounds/barrel) render the wellbore fluid too viscous for handling at the surface.

A very important adjunct for use in wellbore fluids containing the heteropolysaccharides is MgO (magnesia) which serves as a further stabilizing effect regarding fluid loss.

Generally only a stabilizing amount of MgO will be employed, e.g., about 0.05 percent by weight based on drilling fluids, which is about 0.50 grams per liter of wellbore fluid (0.188 pounds/barrel). The MgO is only very slightly soluble in the brine under the conditions presented here, about 10 ppm of magnesium ion concentration. Hence, the MgO is employed in quantities substantially greater than its solubility. The use of larger amounts of MgO is not harmful, but generally no more than about 15 grams per liter of wellbore fluid is employed. MgO could of course be employed in larger quantities as indicated below as a weighting material should the cost be justifiable. Preferably for stabilization the MgO will be employed in the range of 1.0 to 7.0 grams per liter of wellbore fluid.

The wellbore fluids concerned in the present invention are those typically known as "brines". As the term brine is employed here it means at least 1% by weight of soluble salt of potassium, sodium or calcium in water. In addition, the brine may contain other soluble salts of, for example, zinc, chromium, ion, copper and the like. Generally, the chlorides are employed because of availability, but other salts such as the bromides, sulfates and the like can be used. The soluble salts of the brine not only furnish weighting material by adjusting the density of the solution, but also typically furnish the cations for inhibiting the fluid against hydration of solid materials.

The lignosulfonate salts are known in the wellbore art and have been used as water loss reduction agents. Suitable lignosulfonate salts are the alkali, alkaline earth and metal salts thereof which are soluble in the brine wellbore fluid, e.g., calcium, chromium, sodium and the like. It has been found surprisingly that the lignosulfonate salts substantially prevent settling of the weighting material such as calcium carbonate in combination with heteropolysaccharides, whereas with other viscosifiers such as hydroxyethyl cellulose or bentonite clay it does not. The lignosulfonate salt is employed in a settling stabilizing amount.

In addition ta soluble brine salts and heteropolysaccharides, lignosulfonate salts and powdered weighting materials such as CaCO3, the present wellbore fluids can contain other conventional wellbore additives, such as oil for producing water-in-oil or oil-in-water emulsions, viscosifiers such as hydroxyethyl cellulose, gums, or the starch or modified starches referred to above.

Numerous derivatives of starch, i.e., modified starches, have been described in the art.

Their synthesis and properties are outlined in detail in hundreds of papers and patents. An excellent and relatively recent compilation of much of this information is presented in "Starch and Its Derivatives", 4th Ed., J.A. Radley, Chapman and Hall Lts.; London 1968.

Included among the suitable modified starches are etherified starch, esterified starch and partially oxidized starch.

Some particular etherified starches would include alkylated ethers, prepared for example by treating the starch with an alkyl sulfate and alkali to convert the free hydroxy groups to alkoxyl producing, e.g., a methyl or ethyl ether derivative. Other types of ethers such as hydroxyethylated starch, prepared by mixing starch with dry powdered sodium hydroxide, aging, followed by treatment with ethylene oxide are included. Similarly carboxyalkyl ethers such as carboxymethyl ether of starch prepared by the action of chloroacetic acid on starch in the presence of alkali; sulfur containing ethers such as those described in British Patent Specification No. 895,406 and the phosphorus analogues are suitable.The so-called "cationic" nitrogenous starch ethers such as the derivative from the reaction of starch with the reaction product of epihalohydrin and a tertiary amine or the amine salts in the presence of strongly alkaline catalysts are also suitable for the present invention. Other nitrogenous starch ethers include the cyanoalkyl ethers produced by the reaction of starch and acrylonitrile. A further listing of suitable nitrogenous starch ethers is described, for example in United States Patent Specifications Nos. 2,813,093; 2,842,541; 2,894,944; 2,917,506 and 2,970,140.

A broadly applicable method of ether preparation for a large number of suitable ethers was described in United States Patent Specifications Nos. 2,671,779; 2,671,780; and 2,671,781 which briefly involved the reaction of an alkalinated starchate with an organic halogen compound.

A particularly preferred class of starch derivatives are starch ethers of the general formula

where Rl is OH, CH2OH, or H; R2 is a hydrocarbyl group or H; R3 is a hydrocarbyl group, H, COOH, CHR40H or NRsR; R4 is a hydrocarbyl group and R5 and R6 are each H or a hydrocarbyl group. Generally each hydrocarbyl group has from 1 to 8 carbon atoms and is an alkyl, cycloalkyl, aryl, alkaryl, or aralkyl group. Most preferably, the hydrocarbyl groups are alkyl of 1 to 6 carbon atoms. Each hydrocarbyl group is independently selected.

The starch esters may be generally prepared by treating the starch with an organic acid, acid anhydride or acid chloride in presence of an alkaline catalyst such as a tertiary amine or an alkali hydroxide. Specifically water soluble starch formate, starch acetate, starch benzoate and the like have been prepared as well as mixed starch esters such as acetate-butyrate and acetate-formate.

The partial oxidation of starches, for example, with citric acid introduces carboxyl and carbonyl groups into the starch to produce suitable organic starch derivatives for use in the conjunction with the present invention.

It is understood that not all of these possible constituents will be present in any one wellbore fluid but their selection and use will be governed by other constituents and the use for which the wellbore fluid is intended.

The various components may be added to a wellbore fluid as individual components or may be preblended as a dry ready mix additive package or packages in such proportions that the relative amounts of each component will be within the ranges recited above in the fluid.

The present invention may be further illustrated by, but is in no manner limited to the following Examples.

Examples 1 to 14 In these Examples the same brine was employed, which was a saturated solution of NaCI.

The fluids were prepared as shown in the Tables then aged for 16 hours at 175 F in a roller oven. The samples turn at approximately 30 rpm (revolutions per minute). After aging, the samples were removed from the roller-oven and cooled to about 80" F before the testing described and reported in the tables. The amounts are given in pounds per barrel (US-42 gal/barrel).

Examples 1 to 4 In these Examples the surprising effect of the lignosulfonate salt on the settling of CaCO3 is demonstrated, the results being set forth in Table 1.

TABLE I Example 1 2 3 4 Components CaCO3, ppb 300 300 300 300 X-C, "' ppb .75 1. 1. .75 Toranil-B ,(2)ppb 0 0 5 5 Properties Apparent Viscosity, cp 35 40 46 42 Plastic Viscosity, cp. 28 30 34 32 Yield Point, lg/100sq.ft. 14 20 24 20 Gel Strength (0/10 min.) 3/5 3/5 5/6 3/5 pH 6.8 6.8 6.4 6.3 API filtrate, ml 130 100 67.0 54 Settling, inch 1/8 1/8 0 0 (1) heteropolysaccharide, commercial product of Kelco co, Cal, produced by fermination of carbohydrate with genus Xanthomonas bacteria (2) calcium lignosulfonate salt, St. Regis Paper Co.

Examples 5 to 8 In these Examples the combination of lignosulfonate salt with an unstructured viscosifier, hydroxyethyl cellulose (HEC) and a structured viscosifier, bentonite clay, is shown to be ineffective in reducing the settling rate of the CaCO3, the results being set forth in TABLE II.

TABLE II Example 5 6 7 8 Component CaCO3, ppb 300 300 300 300 Toranil-B, ppb - 5 - 5 HEC, ppb 1 1 - Bentonite, ppb - - 50 50 Properties Apparent Viscosity, cp 125 58 17.5 22 Plastic Viscosity, cp 110 46 13 19 Yield Point lb/100 sq.ft. 30 24 9 6 Gel Strength (0/10 min.) 0/0 0/0 5/7 3/4 pH 6.4 6.4 7.7 7.1 API filtrate, ml 90.0 125.0 175.0 150.0 Settling, inch 1/2 1/2 1/8 1/8 Examples 9 to 14 Examples 11 and 12 show the improvement in API filtrate derived from the presence of MgO in the compositions of the present invention, but demonstrate the stabilizing effect of MgO does not improve the settling stability. Examples 13 and 14 show that MgO also does not effect the settling stability of HEC viscosified fluids. The results are set forth in TABLE III.

TABLE III Example 9 10 11 12 13 14 Component MgO, ppb .5 .5 .5 .5 .5 .5 CaCO3, ppb 300 300 300 300 300 300 X-C, ppb .5 .75 .5 .75 - Toranil-B, ppb - - 5 5 5 HEC, ppb - - - - 1 1 Properties Apparent Viscosity, cp 30 30 39 41 30 87 Plastic Viscosity, cp 22 22 31 30 28 76 Yield Point, lb/100 sq.ft. 16 16 16 11 4 22 Gel Strength (1/10 min,) 3/7 3/7 4/5 5/7 0/0 0/0 pH 8.4 8.1 8.5 8.2 8.8 8.4 API filtrate, ml 175.0 175.0 22.0 29.0 180.0 75.0 Settling, inch 1/8 1/8 0 0 1/2 1/2 WHAT WE CLAIM IS: 1.An aqueous clay-free thixotropic wellbore fluid for use in subterranean formations in the earth which comprises water, at least 1% by weight of a brine forming soluble salt or a mixture of salts, a viscosifying amount of a non-cross-linked heteropolysaccharide prepared by the action of bacteria of the genus Xanthomonas on carbohydrates, a weighting amount of a powdered weighting material and a stabilizing amount of lignosulfonate salt, the fluid optionally containing in addition either at least 0.50 grams of MgO per liter of wellbore fluid or a starch or modified starch but not both.

2. A wellbore fluid as claimed in claim 1 which contains 0.72 to 7.14 grams of heteropolysaccharide, 100 to 500 grams of weighting material, and 0.5 to 9.0 grams of a lignosulfonate salt per liter of wellbore fluid.

3. A wellbore fluid as claimed in claim 2 which contains 0.72 to 3.57 grams of heteropolysaccharide, 200 to 400 grams of weighting material, and 0.7 to 7.0 grams of a lignosulfonate salt per liter of wellbore fluid.

4. A wellbore fluid as claimed in any of claims 1 to 3 in which the lignosulfonate is the calcium salt.

5. A wellbore fluid as claimed in any of claims 1 to 4 which contains 1.0 to 7.0 grams of MgO per liter of wellbore fluid.

6. A wellbore fluid as claimed in any of claims 1 to 5 in which the weighting material is CaCO3.

7. A wellbore fluid according to claim 1, substantially as hereinbefore described with particular reference to any of Examples 3, 4, 11, or 12.

8. A dry mix additive package for use in aqueous clay-free brine well fluids comprising an intimate mixture of a non-cross-linked heteropolysaccharide, prepared by the action of bacteria of the genus Xanthomonas on carbohydrates and a lignosulfonate salt in a weight ratio of 0.08 : 1 to 14.28 : 1.

9. A package as claimed in claim 8 containing a weighting material.

10. A package as claimed in claim 9 in which the weighting material is CaCO3.

11. A package as claimed in any of claims 8 to 10 which contains 86.10 to 99.76 weight percent weighting material, 0.15 to 6.63 weight percent heteropolysaccharide, and 0.09 to 8.2 weight percent lignosulfonate salt.

12. A package as claimed in any of claims 8 to 11 in which the salt is calcium lignosulfonate.

13. A package according to claim 8 substantially as hereinbefore particularly described.

14. A method of treating a subterranean formation comprising injecting into the formation clay-free wellbore fluid as claimed in any of claims 1 to 7.

15. A method as claimed in claim 14 in which the formation is contacted with the fluid

**WARNING** end of DESC field may overlap start of CLMS **.

Claims (16)

1. **WARNING** start of CLMS field may overlap end of DESC **.

   Examples 9 to 14 Examples 11 and 12 show the improvement in API filtrate derived from the presence of MgO in the compositions of the present invention, but demonstrate the stabilizing effect of MgO does not improve the settling stability. Examples 13 and 14 show that MgO also does not effect the settling stability of HEC viscosified fluids. The results are set forth in TABLE III.

   TABLE III Example 9 10 11 12 13 14 Component MgO, ppb .5 .5 .5 .5 .5 .5 CaCO3, ppb 300 300 300 300 300 300 X-C, ppb .5 .75 .5 .75 - Toranil-B, ppb - - 5 5 5 HEC, ppb - - - - 1 1 Properties Apparent Viscosity, cp 30 30 39 41 30 87 Plastic Viscosity, cp 22 22 31 30 28 76 Yield Point, lb/100 sq.ft. 16 16 16 11 4 22 Gel Strength (1/10 min,) 3/7 3/7 4/5 5/7 0/0 0/0 pH 8.4 8.1 8.5 8.2 8.8 8.4 API filtrate, ml 175.0 175.0 22.0 29.0 180.0 75.0 Settling, inch 1/8 1/8 0 0 1/2 1/2 WHAT WE CLAIM IS: 1.An aqueous clay-free thixotropic wellbore fluid for use in subterranean formations in the earth which comprises water, at least 1% by weight of a brine forming soluble salt or a mixture of salts, a viscosifying amount of a non-cross-linked heteropolysaccharide prepared by the action of bacteria of the genus Xanthomonas on carbohydrates, a weighting amount of a powdered weighting material and a stabilizing amount of lignosulfonate salt, the fluid optionally containing in addition either at least 0.50 grams of MgO per liter of wellbore fluid or a starch or modified starch but not both.
2. 2. A wellbore fluid as claimed in claim 1 which contains 0.72 to 7.14 grams of heteropolysaccharide, 100 to 500 grams of weighting material, and 0.5 to 9.0 grams of a lignosulfonate salt per liter of wellbore fluid.
3. 3. A wellbore fluid as claimed in claim 2 which contains 0.72 to 3.57 grams of heteropolysaccharide, 200 to 400 grams of weighting material, and 0.7 to 7.0 grams of a lignosulfonate salt per liter of wellbore fluid.
4. 4. A wellbore fluid as claimed in any of claims 1 to 3 in which the lignosulfonate is the calcium salt.
5. 5. A wellbore fluid as claimed in any of claims 1 to 4 which contains 1.0 to 7.0 grams of MgO per liter of wellbore fluid.
6. 6. A wellbore fluid as claimed in any of claims 1 to 5 in which the weighting material is CaCO3.
7. 7. A wellbore fluid according to claim 1, substantially as hereinbefore described with particular reference to any of Examples 3, 4, 11, or 12.
8. 8. A dry mix additive package for use in aqueous clay-free brine well fluids comprising an intimate mixture of a non-cross-linked heteropolysaccharide, prepared by the action of bacteria of the genus Xanthomonas on carbohydrates and a lignosulfonate salt in a weight ratio of 0.08 : 1 to 14.28 : 1.
9. 9. A package as claimed in claim 8 containing a weighting material.
10. 10. A package as claimed in claim 9 in which the weighting material is CaCO3.
11. 11. A package as claimed in any of claims 8 to 10 which contains 86.10 to 99.76 weight percent weighting material, 0.15 to 6.63 weight percent heteropolysaccharide, and 0.09 to 8.2 weight percent lignosulfonate salt.
12. 12. A package as claimed in any of claims 8 to 11 in which the salt is calcium lignosulfonate.
13. 13. A package according to claim 8 substantially as hereinbefore particularly described.
14. 14. A method of treating a subterranean formation comprising injecting into the formation clay-free wellbore fluid as claimed in any of claims 1 to 7.
15. 15. A method as claimed in claim 14 in which the formation is contacted with the fluid

    and the fluid returned to the surface for regeneration and reinjection into the formation.
16. 16. A method according to claim 14 substantially as hereinbefore particularly described.