WO2002081590A1

WO2002081590A1 - Borehole fluid

Info

Publication number: WO2002081590A1
Application number: PCT/NO2002/000136
Authority: WO
Inventors: Odd Palmgren; Aslak Teigen; Torstein Obrestad
Original assignee: Norsk Hydro ASA
Current assignee: Norsk Hydro ASA
Priority date: 2001-04-09
Filing date: 2002-04-08
Publication date: 2002-10-17
Anticipated expiration: 2003-10-09
Also published as: CA2448617C; NO20011787L; NO315565B2; CA2448617A1; NO20011787D0; NO315565B1

Abstract

A water-in-oil emulsion bore hole fluid comprising oil, a brine and emulsifier wherein the oil-to-brine ratio by weight is between 10:90 and 30:70. The emulsifier has a high molecular weight in the range from 500 up to 5000 and a suitable HLB balance.

Description

"Borehole fluid"

Background of the Invention This invention concerns oil based fluids for borehole -operations and in particular drilling fluids for oil well drilling and completion etc.

A drilling fluid consists of a liquid, usually oil and/or water, with different kinds of additives. Drilling fluids are used to remove rock cuttings from the borehole and bring them to the surface. The drilling fluid also helps to control subsurface pressures and the fluid has to provide a protective and stabilising coating to permeable formations so that the productivity of the reservoir is not hindered. The productivity of an oil reservoir can be adversely affected by solids from the drilling fluid penetrating and blocking the flow channels in the formation. The productivity of a reservoir can also be reduced by drilling fluid filtrate causing hydration and swelling of the formation clays.

The drilling fluid is pumped through a hollow drill string to the drill bit cooling and lubricating the drill string and bit. The fluid is recirculated. The properties of the drill- ing fluid are monitored and adjusted during the operation. The density of the fluid must be high enough to control formation pressures, but low enough to permit the fastest possible drilling rate. At the surface the rock cuttings are removed from the drilling fluid by screening usually accompanied by the use of hydrocyclones and centrifuges. Drill cuttings are produced as a waste material.

Prior Art

At present oil-based fluids are the fluids of choice for most deep drilling operations on the basis of the following criteria : Drilling rate, lubricity, formation stability, ease of maintenance and cost. Therefore, current drilling technology is heavily dependent on the use of these fluids using diesel, mineral oils, olefins or esters as the external phase and halide brines as the internal phase. The drilling fluid is formulated as an emulsion to accommodate additional water picked up during the drilling operation and the salinity of the aqueous phase is controlled by the use of dissolved salts. Calsium chloride is the most common salt used, although sodium chloride or various other brines have been used as well. The choice is dictated by both the formation location and economics.

A typical continuous oil phase emulsion for drilling mud application formulated by conventional technology consists of 70-80 weight % of oil and 20-30 weight % of brine. In addition to oil and brine the emulsion contains an emulsifier. Such an emulsion has initially, before addition of weighting material, a density of approximately 0.9 kg 1. A typical weighting agent is barite of density 4.2. Other additives in the drilling fluid may include filtration control additives, rheology modifiers, oil wetting additives, corrosion inhibitors, etc.

For offshore drilling the legislation is driving the industry to eliminate the discharge overboard of hydrocarbons and this includes oil-contaminated cuttings from wells drilled with oil-based fluid. Disposal of the oil-contaminated drill cuttings is severely restricted in all sectors of the North Sea.

The unwanted cuttings can be re-injected back into the oil well as a ground up slurry, provided that the geological conditions down the wellbore are favourable, or shipped to shore and treated there to remove the oil contamination before disposal at land-fill sites. This can create problems in bad weather if cuttings cannot be offloaded from the rig. The concept is difficult to apply to floating exploration rigs. In addition, the extra energy required to transport and handle the cuttings produces extra pollution, as does the disposal on land which usually involves a heat extraction or incineration process.

The benefits shown by oil-based fluids in offshore drilling are equally applicable to land operations. The disposal of waste and cuttings from onshore drilling operations using oil-based muds' represents however a somewhat different problem, where the dominating factor is the presence of environmentally harmful salts in the emulsified brine. The use of calcium chloride in the brine restricts the amount of drill cuttings which can be successfully landfarmed on a given area. Canadian Patent No. 2 101 884 (Flemming) describes replacement of calsium choride in the brine phase with calsium nitrate - the objective being to minimise the environmental impact when wastes are spread to land. By replacement of the chloride with nitrate the natural process of microbial degradation of the associated oil is also enhanced.

In the past the diesel and mineral oil-based fluids have offered good technical perform- ance, reasonable cost and operational flexibility for North Sea operations and the environmental acceptability of these fluids has gradually been enhanced in terms of reduced toxicity and improved biodegradability by introduction of olefins, alkanes and esters in place of the oils. The cost of the oil-based drilling fluids has however increased dramatically as operators have moved to these more sophisticated oils.

Oil based drilling fluids designed especially for the purpose of being non-polluting are described, for instance, in European Patent 764 711 Bl and 1 029 908 A2. The patents describe the use of minimally toxic drilling fluids which are based on synthetic hydrocarbons derived from alpha-olefinic monomers. The patent claims include drilling fluid emulsions containing up to about 70 % by volume of an aqueous phase. The possibility of formulation of a drilling mud containing such a high amount of aqueous phase is not demonstrated by the examples given in the patents. The emulsions described in these patents, containing the highest amount of water, will have a density of not more than approximately 1.0, before the weighting material is being added.

Summary of the Invention

It is an object of the present invention to provide a novel borehole fluid , especially a drilling fluid, that could provide the beneficial drilling properties, of oil-based muds while generating a minimal environmental impact. Another object is to obtain a water- in-oil emulsion of high initial density. It is also an object of the present invention to provide an oil-continuous drilling fluid which offers economic benefits by reduction of the amount of ester, when ester is used as the oil phase, compared to the brine phase. The oil phase being the most expensive one in this case. These and other objects of the invention are obtained with the borehole fluid as described below. The invention is further described and characterised by the enclosed patent claims.

The invention thus concerns a water-in-oil emulsion borehole fluid, especially a drilling fluid. The fluid comprises an oil, a brine and emulsifier wherein the oil-to-brine ratio by weight is between 10:90 and 30:70. The lowest oil-to-brine ratio is preferably 15:85. The emulsifier is preferentially of high molecular weight, the molecular weight being in the range from 500 up to 5000. The preferred HLB-value is in the range from 2 up to 8. The emulsifier concentration is 0.2-5.0 % by weight active matter, preferentially 0.4-3.0 weight % of the oil and brine mixture. It is preferred that the hydrophobic part of the emulsifier molecule consists of a long branched or bulky alkyl group and the hydrophilic polar part of the molecule being polyoxyalkylene, polyol, amine or amide. Suitable emulsifiers are for example a polyisobutenyl succinic anhydride derivative or a polyal- kylene glycol where the hydrophobic part consists of an oligomer of alfa-olefmes, the hydrophilic part being a polyethylene glycol sequence.

The aqueous phase should be a concentrated solution of a nitrate, nitrite, chloride, bromide, formate, acetate, tungstate or mixtures thereof. Preferably the aqueous phase is a concentrated solution of a nitrate compound selected from the group consisting of alkali metal, alkaline-earth metal or ammonium nitrates, and hydrates and complexes thereof. The oil phase is a mineral oil-based fluid, a diesel oil, an olefin, alkane or an ester. It is preferred to use an ester of fatty acids. A preferred composition comprises an ester of a fatty acid, a concentrated solution of a nitrate compound or mixtures of nitrate, chloride and/ or bromide, 0.4-3.0 weight % of an emulsifier, and where the oil-to-brine ratio by weight is between 20:80 and 30:70. The fluids could in addition comprise suitable wetting agents, viscosifiers, weighting materials and fluid loss additives used to obtain the desired properties with respect to stability, rheology, filtration control, density etc.

By introducing an emulsifier of the specified type stable oil-continuous emulsions can be prepared with a low content of oil, the speed of mixing not being that critical , preferentially in combination with using an ester or an alpha-olefin as the external phase and a nitrate brine as the internal phase.

Conventional drilling fluids produce cuttings that are coated in oil, and disposal of these cuttings is a problem. Disposal to sea bed results in the formation of a cuttings pile coated in oil which biodegrades extremely slowly as the oil has to be broken down under anaerobic conditions. When applied on offshore drilling locations this fluid formulation should significantly reduce the amount of oil being discharged with the cuttings to sea bed or to other recipients. In the preferred formulation the presence of nitrates will introduce an alternative terminal electron acceptor for microbial respiration thereby enhancing the rate of biodegradation of the oil by encouraging anoxic microbial respiration. Under anoxic denitrifying conditions oils will degrade more rapidly than under anaerobic conditions as the process is more thermodynamically efficient and more complex molecules can serve as carbon sources.

It is also possible to provide an oil-continuous drilling fluid which offers economic benefits by reduction of the amount of oil, especially when alpha olefin or ester is used as the oil phase, compared to the brine phase. The oil phase being the most expensive one. This should apply to brines containing chlorides, bromides and nitrates and mixtures there of.

It is also important that it is possible to produce water-in-oil emulsions having a high initial density for drilling fluid application. Typically the density for such an emulsion will be 1.25-1.35 or even higher. In such a drilling fluid the requirement for addition of weighting material will be less than normal. The drilling rate, all other things being equal, is a function of the percentage of solids in the fluid and the plastic viscosity. The proposed formulation should offer improved drilling rates due to the lower solids content. Problems with barite sag will be less. This should represent a considerable improvement over the technology of today also where diesel or mineral oil are used.

Calcium nitrate based solutions have for some time been considered for use as drilling fluids. Due to the tendency of inducing stress corrosion cracking (SCC) on carbon steel (unalloyed steel), there has been hesitations in applying these solutions. By using an oil continuous emulsion the steel surface will be wetted by the oil and not by the aqueous phase. The nitrate will not be in contact with the surface and we will not have any corrosion. This has been experimentally verified by testing U-bend specimens of steel quality Q 125 for 4 weeks at 100 °C in well-formulated nitrate emulsions.

The technology of emulsification which makes it possible to prepare stable oil continuous emulsions with low content of oil, will be applicable to compositions containing diesel oils, mineral oils, olefins or esters and a long range of brine compositions. The essential point is to apply a surface active substance which has a high affinity with respect to the oil-water interface and a low mobility at the interface. A more stable emulsion will be the result. Various emulsifiers of relatively high molecular weight and of the right hydrophilic-lipophilicbalance (HLB) may be applied.

Description of the Preferred Embodiment

The preferred emulsifiers for this application are of high molecular weight - the molecular weight being in the range from 500 up to 5000 - and the preferred emulsifiers will have a HLB -value in the range from 2 up to approximately 8. The hydrophobic part of the emulsifier molecule consisting of a long branched or bulky alkyl group. The hydrophilic, polar group of the molecule having an amine, amid, polyol or polyoxyalkylene functionality. The hydrophobic part of such an emulsifier will occupy a larger volume than the hydrophilic part. The result of this will be a preferred curvature of the oil-water interface being convex towards the oil phase and the emulsifier will therefore be suitable for stabilizing water-in-oil emulsions. Mixtures of emulsifiers may also be used to obtain optimal performance.

Examples of emulsifiers suitable for this application are polyisobutenyl succinic anhydride derivatives and polyalkylene glycols of various composition. The hydropho- bic part of these emulsifiers consists of either a fairly long polyisobutylene sequence or a bulky oligomer of alfa-olefines. The hydrophilic part will either be a derivative of succinic acid or a polyethylene glycol sequence. Other types of complex, high molecular weight emulsifiers may be used for the purpose described, provided that they have a lipophilic-hydrophilic balance suitable for stabilising water-in-oil emulsions. Poly glycerol esters of different kinds i.e. esters with inter- esterified ricinoleic acid or esters of dimerised soya bean oil will give stable emulsions.

Oil-continuous emulsions of high stability and of high density can be prepared containing as little as 6 weight % of oil, i.e. an oil to brine ratio of 6:94 by weight. The aqueous phase being a concentrated solution of nitrate, choride, bromide, tungstate, acetate or formate, or mixtures thereof. To be used in a drilling fluid formulation a water-in-oil emulsion will contain an oil-to-brine ratio between 10:90 and 30:70, preferentially a ratio between 15:85 and 30:70 by weight. The emulsifier concentration in such an emulsion will be 0.2-5.0 % by weight active matter, preferentially 0.4-3.0 weight % of the oil and brine mixture.

The following examples are submitted for the purpose of illustrating the invention. The properties of the different kinds of oil being used in the examples are listed in Table 1 below:

Table 1.

EXAMPLE 1. - For comparison.

For the purpose of comparison an ordinary oil-based drilling fluid was formulated based on an emulsion containing an oil to brine ratio of approximately 70:30 by weight. The drilling fluid had the following composition : 286 g of base oil, 12 +6 g of the emulsifiers Nersavert PE and Versavert SE, 116 g of a calcium chloride brine of density 1.18, 2 g of Versavert F, 4 g of Versamod and 8 g of Bentone 128. The emulsifier mixture was dissolved in the oil by low speed stirring. The emulsion was then prepared at room temperature in a 1000 ml beaker by applying a turbo-mixer at 2000 rpm. The total mixing time was approximately 12 minutes.

The density of the emulsion was 0.89 measured at 20 °C (Sample 1A). The viscosity measured on a Bohlin CS Rheometer was shear thinning. The viscosity was decreasing from approximately 120 to 25 mPas as the shear rate was increased from 10 to 100 sec^"1 at 50 °C. After addition of 13 g lime and 438 g of barite the density of the drilling fluid was 1.50 at 20 °C (Sample IB). The viscosity at 50 °C was shear thinning from approximately 250 to 60 mPas at shear rates 10-100 sec^"1. This drilling fluid (IB) contains approximately 50 % by weight of the weighting material (barite).

The storage stability of the drilling fluids were evaluated as excess oil separating out on top of the mixtures at 20 and 80 °C and is shown in Table 2:

Table 2.

Sample IB was then treated for 10 minutes at 6000 rpm in a Silverson high speed mixer. Measured on a Fann Rheometer at 50 °C the drilling fluid had the following characteris- tics as shown in Table 3 :

Table 3.

EXAMPLE 2. - Low oil emulsion containing different kinds of emulsifier.

A series of samples were prepared with low oil content to illustrate the difference in emulsion stability using different emulsifiers. The samples were prepared with an oil to brine ratio of 40:60 and 20:80 by weight. The oil being used in these samples was an isopropyl-ester of fatty acids (Jafa-ester 2000 DF) and the aqueous phase was a mixed nitrate brine of density 1.61. The emulsions were prepared at room temperature in a 1000 ml beaker by applying a turbo-mixer at 1100 rpm for 3 minutes for dispersion of the brine in the oil phase. Emulsifiers of "low molecular weight" are Versavert PE-SE and Span 80. Span 80 has a molecular weight of approximately 410. The molecular weight of the Versavert emulsifiers is estimated to be somewhat higher than Span 80. The molecular weight of the other 3 emulsifiers used in sample no. 2.5, 2.6 and 2.7 are in the range of approximately 1000-4000 and all are illustrated in Table 4. Table 4.

Examination 1 hour after mixing :

Oil to water ratio 40:60 : Excess oil fairly quickly separated out on top of the samples no. 2.1-2.4 (40:60). The emulsions are not stable enough for measurement of viscosity. The sample no. 2.5-2.7 (40:60) were more stable. The viscosity of the emulsions measured at 50 °C using a Bohlin CS Rheometer was Newtonian and approximately 30 mPas at shear rates 10-100 sec ¹.

Oil to water ratio 20:80 : The samples no. 2.1-2.4 (20:80) were unstable, but a measure- ment of the viscosity could be done just after mixing. The viscosity of these emulsions was shear thinning. The viscosity was decreasing from approximately 3000 to approximately 500 mPas as the shear rate was increased from 10 to 100 sec^"1 at 50 °C. The samples no. 2.5-2.7 (20:80) were much more stable. The viscosity at 50 °C was found to be shear thinning from 250 to 100 mPas at shear rates 10-100 sec^"1 .

Further storage of the samples with an oil to brine ratio of 20:80 :

Samples 2.1-2.4 (20:80) : Almost all the oil separated out of the emulsions as excess oil some hours after mixing. The emulsion remaining on the bottom of these samples were jelly and were not easily remixed with the excess oil. Samples 2.5-2.6 (20:80) : The emulsions were still in good condition after 1 day of storage at room temperature. Only a very small fraction of the oil separated out on top of the emulsions. A somewhat larger part of the oil separated out (because of the lower viscosity) at 80 °C. The excess oil could easily be redispersed. More oil will separate out by further storage. The higher temperature the faster will this process proceed.

Sample 2.7 (20:80) : The emulsion was stable at room temperature, but not at 80 °C. The emulsion was after a few days at 80 °C separated into an oil and an aqueous phase. The reason for this may be a low heat tolerance of the emulsifier being used in this case (a polyglycerol ester).

The density of sample 2.5-2.7 (20:80) was approximately 1.37 at 20 °C.

EXAMPLE 3. - Low oil emulsions containing different levels of oil.

A series of samples were prepared with low oil content. The samples were prepared with an oil to brine ratio in the range from 6:94 to 22:78 by weight. The oil being used in these samples was a technical white oil (Bayol 85) and the aqueous phase was a calcium nitrate brine of density 1.52. The emulsions were prepared at 80 °C in a 1000 ml beaker by applying a turbo-mixer at 1100 rpm for 3 minutes for dispersion of the brine in the oil phase. The emulsifier used was Mobilad C 267, a poly-isobutylene-succinic amide derivative with a molecular weight estimated to be in the range of 1000-2000. The emulsifier concentration was 1% of the oil-brine mixture.

The viscosity was measured 1 hour after mixing and the storage stability of the emulsions was evaluated as excess oil separating out on top of the mixture at 20 and 80 °C . The results are shown in Table 5: Table 5.

The excess oil could easily be redispersed.

EXAMPLE 4. - Low oil emulsions containing different kinds of brine.

10 A series of samples were prepared with low oil content using different brines. The samples were prepared with an oil to brine ratio of 20:80 by weight. The oil being used in these samples was a technical white oil (Bayol 85). The aqueous phase was various brines :

15 4.1. Ca-nitrate solution of density 1.52

4.2. Ca-bromide solution of density 1.72

4.3. Ca and K-nitrate solution of density 1.61

The emulsions were prepared at 10 °C in a 1000 ml beaker by applying a turbo-mixer at 20 1100 rpm for 3 minutes for dispersion of the brine in the oil phase. The emulsifier used was Mobilad C 267. The emulsifier concentration was 1% of the oil -brine mixture. The density was measured at 20°C. The viscosity was measured 1 hour after mixing and the storage stability of the emulsions was evaluated as excess oil separating out on top of the mixture at 20 and 80 °C . The results are shown in Table 6: Table 6.

The excess oil could easily be redispersed.

EXAMPLE 5. - Low oil emulsions containing different kinds of brine.

A series of samples were prepared with low oil content using different brines. The samples were prepared with an oil to brine ratio of 20:80 by weight. The oil being used - in these samples was an alpha olefin (Novatec B). The aqueous phase was various brines :

5.1. Ca-chloride (20%), density 1.18 measured at 20 °C

5.2. Ca-chloride (40%), density 1.40

5.3. Ca-nitrate, density 1.52

5.4. Mixed Ca(NO₃)₂ (32.4%) and CaCl₂ (19.5%), density 1.53

5.5. Mixed Ca(NO₃)₂ (46.1%) and KNO₃ (15.1%), density 1.61

5.6. Mixed Ca(NO₃)₂ (40%) and CaCl₂ (18.9%), density 1.62

5.7. Mixed Ca(NO₃)₂ (31.2%), NaBr (10.6%) and CaBr₂ (15.5%), density 1.63

5.8. Ca-bromide, density 1.72

5.9. K-formate, density 1.58

The emulsions were prepared at room temperature in a 1000 ml beaker by applying a turbo-mixer at 1100 rpm for 3 minutes for dispersion of the brine in the oil phase. The emulsifier used was Anfomul 2500, a poly-isobutylene-succinic-acid derivative (amide) with a molecular weight around 1000 . The emulsifier concentration (active matter) was 0.7 % of the oil-brine mixture. Included in the recipe was also 1 % of Bentone 128. The organophilic clay was added during an additional time of mixing of 5 minutes.

The density and the viscosity was measured 1 hour after mixing and is shown in Table 7:

Table 7.

As in the other examples a small fraction of the oil separated out on top of the emulsions. A somewhat larger part of the oil separated out at 80 °C compared with 20 °C. The excess oil could easily be redispersed. More oil will separate out by further storage. The rate of separation of excess oil will depend on the viscosity of the emulsion and the difference in density between the oil and the aqueous phase.

EXAMPLE 6. - Low oil emulsion formulated at a density of 1.5.

An oil-based drilling fluid based on an emulsion containing an oil to brine ratio of approximately 18:82 by weight, was prepared with the following composition : 108 g of alpha olefin (Novatec B), 9.6 g of the emulsifier Anfomul 2500, 482.4 g of a calcium nitrate brine of density 1.52, 1 g of Versavert F, 1 g of Versamod, 2 g of Bentone 128, 0.5 g lime and 145 g of barite. The emulsifier was dissolved in the oil by low speed stirring. The emulsion was then prepared at 50 °C in a 1000 ml beaker by applying a turbo-mixer at 2000 rpm. The total mixing time was approximately 16 minutes. 5

This drilling fluid contains 19.5 % by weight of the weighting material (barite). The density was 1.49 at 20 °C.

Measured on a Fann Rheometer at 80 °C the drilling fluid had the following characteris- 10 tics as shown in Table 8 :

Table 8.

15

EXAMPLE 7. - Low oil emulsion formulated at a density of 1.5.

An oil-based drilling fluid based on an emulsion containing an oil to brine ratio of 20 19.5:80.5 by weight, was prepared with the following composition : 117 g of alpha- olefin (Novatec B), 6 g of the emulsifier Anfomul 2500, 483 g of a calcium nitrate brine of density 1.52, 1 g of Versavert F, 1 g of Versamod, 2 g of Bentone.128, 6 g lime and 180 g of barite. The emulsifier was dissolved in the oil by low speed stirring. The emulsion was then prepared at 20 °C in a 1000 ml beaker by applying a turbo-mixer at 25 2000 rpm. The total mixing time on the turbo-mixer was approximately 30 minutes, followed by 10 minutes on a Silverson high speed mixer at 6000 rpm.

This drilling fluid contains approximately 23 % by weight of the weighting material (barite). The density was 1.52 at 20 °C. 30 Measured on a Fann Rheometer at 50 and 80 °C the drilling fluid had the following characteristics as shown in Table 9 :

Table 9.

10 EXAMPLE 8. - Low oil emulsion formulated at a density of 1.5.

An oil-based drilling fluid based on an emulsion containing an oil to brine ratio of 20.5:79.5 by weight, was prepared with the following composition : 123 g of alpha- olefin (Novatec B), 6 g of the emulsifier Anfomul 2500, 77 g of a calcium nitrate brine of density 1.52, 1 g of Versavert F, 1 g of Versamod, 3 g of Bentone 128, 6 g lime and 15 180 g of barite. The emulsifier was dissolved in the oil by low speed stirring. The emulsion was then prepared at 20 °C in a 1000 ml beaker by applying a turbo-mixer at 2000 rpm. The total mixing time on the turbo-mixer was approximately 30 minutes, followed by 10 minutes on a Silverson high speed mixer at 6000 rpm.

20 This drilling fluid contains approximately 23 % by weight of the weighting material (barite). The density was 1.51 at 20 °C.

The drilling fluid sample was stored at room temperature for 2 weeks and then re-dispersed for 10 minutes on a Silverson mixer at 6000 rpm.

25

Measured on a Fann Rheometer at 50 and 80 °C the drilling fluid had the following characteristics as shown in Table 10 : Table 10.

EXAMPLE 9. - Low oil emulsions containing different kinds of emulsifier.

3 oil-based drilling fluids were prepared containing an oil to brine ratio of 24:76 by weight. The composition was as follows : 144 g of alpha olefin (Novatec B), emulsifier (specified below), 456 g of a calcium nitrate brine of density 1.52, 0.5 g of Versavert F, 1 g of Versamod, 2 g of Bentone 128, 3 g lime and 180 g of barite. The emulsifier was dissolved in the oil by low speed stirring. The emulsion was then prepared at 20 °C in a 1000 ml beaker by applying a turbo-mixer at 2000 rpm. The total mixing time on the turbo-mixer was approximately 30 minutes, followed by 10 minutes on a Silverson high speed mixer at 6000 rpm.

Emulsifier :

A 6 gram Span 80 - Molecular weight approximately 410 B 4.8 g Versavert PE + 2.4 g Versavert SE - Molecular weight 500-1000

C 6 gram Grinsted PGPR 90 - Molecular weight 2500-3500

The drilling fluids contain approximately 23 % by weight of the weighting material (barite).

The viscosity was measured 1 hour after mixing on a Bohlin CS Reometer. Table 11.

Stability at 20 and 80 °C :

A Gelled, unsatisfactory structure, especially at 80 °C

B Emulsion stable over at least 3 weeks at 80 °C C Emulsion stable over at least 3 weeks at 80 °C

Claims

Patent claims

1. A water-in-oil emulsion borehole fluid comprising oil, brine and emulsifier or a mixture of emulsifiers, wherein the oil-to-brine ratio by weight is between 10:90 and 30:70 and at least one of the emulsifiers being of high molecular weight in the range from 500 up to 5000 and having a HLB-value in the range from 2 up to 8.

2. A borehole fluid according to claim 1, wherein the emulsifier concentration being 0.2-5.0 % by weight, preferentially 0.4-3.0 weight % of the oil and brine mixture.

3. A borehole fluid according to claim 1 or 2, wherein the hydrophobic part of the emulsifier molecule consists of a long branched or bulky alkyl group and the hydrophilic polar part of the molecule being polyoxyalkylene, polyol, amine or amide.

4. A borehole fluid according to claim 3, wherein the emulsifier is a polyisobutenyl succinic anhydride derivative.

5. A borehole fluid according to claim 3, wherein the emulsifier is a polyalkylene glycol where the hydrophobic part consists of an oligomer of alfa-olefines, the hydrophilic part being a polyethylene glycol sequence.

6. A borehole fluid according to claim 1, wherein the lowest oil-to-brine ratio is 15:85.

7. A borehole fluid according to claim 1 , wherein the aqueous brine phase is a solution of a nitrate, nitrite, choride, bromide, acetate, tungstate or formate, or mixtures thereof.

8. A borehole fluid according to claim 1 or 7, wherein the aqueous phase is a concentrated solution of a nitrate compound selected from the group consisting of alkali metal, alkaline-earth metal or ammonium nitrates, and hydrates, complexes or mixtures thereof.

9. A borehole fluid according to any of the preceding claims, wherein the oil phase is a mineral oil-based fluid, a diesel oil, an olefin, alkane or ester.

10. A borehole fluid according to claim 9, wherein the oil phase is an ester of fatty acids.

11. A borehole fluid according to any of the preceding claims, wherein the fluid comprises suitable wetting agents, viscosifiers, weighting materials and fluid loss additives used to obtain the desired properties with respect to stability, rheology, filtration control, density etc.

12. A borehole fluid according to claim 1, wherein the fluid comprises an ester of a fatty acid, a concentrated solution of a nitrate compound or mixtures of nitrate, chloride and/ or bromide, 0.4-3.0 weight % of an emulsifier, and where the oil-to-brine ratio by weight is between 20:80 and 30:70 and where the fluid if necessary, comprises suitable wetting agents, viscosifiers, weighting materials and fluid loss additives.