US3831678A

US3831678A - Method of producing and using a gelled oil base packer fluid

Info

Publication number: US3831678A
Application number: US00356347A
Authority: US
Inventors: T Mondshine
Original assignee: NL Industries Inc
Current assignee: Baroid Technology Inc
Priority date: 1973-05-02
Filing date: 1973-05-02
Publication date: 1974-08-27
Anticipated expiration: 1991-08-27

Abstract

An oil base packer fluid is provided for use in permafrost formations which is pumpable at temperatures less than 50*F and which will gel after placement at its desired location in an annular space in a wellbore when a hot oil or gas is produced through the wellbore. The packer fluid comprises an oil, an organic modified clay gellant, a dispersant for the clay, and, optionally, asbestos, wherein the clay is added to the oil at a temperature less than about 50*F and the temperature of the packer fluid is maintained less than about 50*F before and during placement within the wellbore.

Description

United States Patent [191 Mondshine Aug. 27, 1974 METHOD OF PRODUCING AND USING A GELLED OIL BASE PACKER FLUID [75] Inventor: Thomas C. Mondshine, Houston,

21 Appl. No.: 356,347

[52] 11.8. C1 166/288, 166/294, l66/D1G. 1 [51] Int. Cl E2lb 33/14, E2lb 43/00 [58] Field of Search 166/288, 293, 285, 294, 166/D1G. 1, 302, 303; 175/72, 70, 65, 17

[56] References Cited UNITED STATES PATENTS 3,467,208 9/1969 Kelly, Jr 175/72 3,618,680 11/1971 Ellard et a1... 175/17 3,650,327 3/1972 Burnside 166/D1G. 1 X 3,662,832 5/1972 Keeler et a1. l66/D1G. 1 X 3,695,351 10/1972 Lubinski 175/171 3,700,050 10/1972 Miles 175/65 3,719,601 3/1973 Jacocks 3,724,565 4/1973 Kelly, Jr 166/294 X Primary Examiner-Stephen J. Novosad Attorney, Agent, or Firm-Roy F. House; Delmar H. Larsen; Fred Floersheimer [5 7] ABSTRACT An oil base packer fluid is provided for use in permafrost formations which is pumpable at temperatures less than 50F and which will gel after placement at its desired location in an annular space in a Wellbore when a hot oil or gas is produced through the wellbore. The packer fluid comprises an oil, an organic modified clay gellant, a dispersant for the clay, and, optionally, asbestos, wherein the clay is added to the oil at a temperature less than about 50F and the temperature of the packer fluid is maintained less than about 50F before and during placement within the wellbore.

16 Claims, No Drawings METHOD OF PRODUCING AND USING A GELLED OIL BASE PACKER FLUID BACKGROUND OF THE INVENTION 1. Field of the Invention This invention relates to methods of completing oil and gas wells drilled through permafrost zones of the earth. In particular, this invention relates to thermal insulating fluids and methods for preventing the thawing of the permafrost after production has begun from an q t t d g wsl 2. Description of the Prior Art In many frigid areas of the world such as Northern Alaska and Canada oil and/or gas wells are being drilled through permafrost. Permafrost is a thick layer of frozen surface ground which may be several hundred feet thick. The permafrost presents a great obstacle to the production of relatively warm fluids through the wellbore since thawing of the permafrost in the vicinity of the well causes disintegration of the well wall and subsidence of the surface. Cooling of the gas coming to the surface will cause hydrate crystals to form which may freeze together blocking the tubing.

Various methods of alleviating these and other problems associated with the production of oil and gas in wells drilled through permafrost have been proposed. These are adequately described in the following refer ences: Alaskan Completions Will Be Complicated, World Oil, January, 1970, page 85; B'Ps Unique Completion Of High-Rate Arctic Wells, Petroleum Engineer, February 1972, pp. 39-41; Permafrost Completions Use Gelatinous-Oil Fluid, The Oil and Gas Journal, Jan. 24, 1972, page 56; and the following US. Pat. Nos: 3,642,065; 3,662,832; 3,677,340; 3,685,583; 3,695,351; 3,700,050.

One method which has been proposed is to place a gelatinousoil base packer fluid as a thermal insulator in an annular space within the wellbore. This fluid is prepared by adding gel-building concentrates and a catalyst to the oil to be gelled. As this mixture is pumped down the hole gelation is initiated by the catalyst. This catalytic action is both time and shear dependent. One problem associated with this method of preparing the packer fluid is that of gelation of the fluid before it is placed at the desired location in thewell due to mechanical problems, particularly pump failure. Also as the viscosity of the packer fluid increases with time the efficiency of the pump decreases which increases the placement time and power requirement for placement. Another problem associated with this method is the high cost of the gelatinous oil packer fluid since these fluids must be prepared from relatively pure oils such as diesel oil because of the particular materials used to gel the oils.

Another packer fluid which has been proposed, in US. Pat. No. 3,700,050, comprises a hydrocarbonaceous oil base fluid which has a freezing point below 14F having incorporated therein an effective thermal insulating and/or weighting amount of at least one of hollow shapes of glass and/or plastic and, optionally, halogenated ethane and/or halogenated ethylene. This packer fluid is also very expensive due to the high cost of the components and the high transportation costs associated with the low bulk density hollow shapes.

An excellent article concerning oil base packer fluids for general use has been published in Journal of Canadian Petroleum Technology, Vol. 8 (1), pp. 24-8 (1969) by Jay P. Simpson, entitled Stability and Cor rosivity of Packer Fluids."

It has recently been proposed by Jacocks in US. Pat. No. 3,719,601 to use a liquid insulating medium comprising a mineral oil plus from 1 to 10 percent by weight of a fibrous finely divided magnesium silicate or asbestos for insulating thermal injection wells, wells drilled through permafrost, and pipelines traversing a permafrost region. This insulating medium is very expensive due to the cost of the highly refined mineral oil used and, depending on the concentration of magnesium silicate or asbestos, has a high viscosity which makes placement of the medium with an annular space difficult.

SUMMARY OF THE INVENTION 1 have now found a method and composition for preparing a gelled oil base packer fluid and a method of preventing thawing of permafrost in the vicinity of a wellbore drilled through the permafrost which is free of the limitations of the oil base packer fluids proposed in the prior art. In a particular embodiment I have found a method for preparing a gelled oil base packer fluid from used drilling fluids which have an oil continuous phase. The use of such used drilling fluids in the method also eliminates the burden of otherwise disposing or storing of such fluids.

This invention comprises the discovery that organic modified clays, which-are known gellants for oleaginous mediums, particularly when used with a polar dispersant, do not function efficiently as gellants at a temperature less than about 50F. Upon raising the temperature of a mixture of an oleaginous medium, organic modified clay and polar dispersant above about 50F gelation takes place the extent of which depends on the composition of the mixture and. the temperature to which the mixture is raised.

This discovery has enabled me to formulate a fluid, pumpable oil base packer fluid containing sufficient organic modified clay to thicken the packer fluid upon placement of the packer fluid in an annular space within a wellbore and raising the temperature within the wellbore such as by producing oil and/or gas through tubing within the wellbore. The thus gelled oil base packer fluid is an excellent insulator preventing the high temperatures within the wellbore from melting the permafrost surrounding the wellbore. The packer fluid has a low thermal conductivity and because it is gelled the transfer of heat from the interior of the wellbore to the permafrost formation by convection currents is effectively eliminated.

The packer fluid consists of an oleaginous medium, from 20 to about pounds per barrel of an organic modified clay, from O to about 30 pounds per barrel of asbestos, and a polar dispersant for the organic modifled clay in an effective dispersing amount, the organic modified clay being added to the oleaginous medium at a temperature less than about 50F such that the packer fluid is pumpable while being placed in its desired location in a wellbore and it is gelled upon raising the temperature within the wellbore.

Accordingly, it is an object of this invention to provide a method for preparing a gelled oil base packer fluid. It is another object to provide an oil base packer fluid for preventing the thawing of permafrost in the vicinity of a wellbore upon producing gas and/or oil through the wellbore. It is another object of this invention to provide a method for producing a well through a permafrost zone. It is still another object of this invention to provide a pumpable oleaginous composition having a temperature less than 50F which comprises DESCRIPTION OF THE INVENTION Organic modified clays are well known gellants or thickeners for oleaginous mediums. They have been used in many systems including oil base paints, oil base drilling fluids, greases, printing inks and the like for controlling the flow properties, suspension characteristics, and other properties of the oleaginous medium. Usually a polar dispersant is added to the organic moditied clay-oleaginous medium system to aid in dispersing the clay and thus in increasing the viscosity of the system.

The organic modified clays are prepared from clays which are initially hydrophilic in character, but which have been converted into a hydrophobic condition by the introduction of long chain hydrocarbon radicals onto the surface of the clay particles; as for example, by being subjected to a treatment with an organic cationic surface active agent such as an onium compound. Typical onium compounds are acidic salts of primary, secondary and tertiary amines, and, preferably, quaternary ammonium compounds. The onium compound should have at least one alkyl, alkylene, or alkylidene radical having at least carbon atoms, preferably from 16 to 22 carbon atoms. Typical onium compounds are dimethyldihydrogenated tallow ammonium chloride, trimethylhydrogenated tallow ammonium chloride, dimethylbenzyloctadecyl ammonium chloride, and mixtures thereof. Hydrogenated tallow is a term used for a mixture of alkyl radicals derived from tallow fatty acids which have been hydrogenated, primarily containing l6 and 18 carbon atoms. The clays which are useful as starting materials in forming the organic modified clays can comprise the naturally occurring or synthetically prepared clays. These clays are crystalline complex silicates the exact composition of which cannot be precisely described since they vary widely from one natural source to another. These clays can be described as complex inorganic silicates such as aluminosilicates, magnesium silicates, and the like, containing, in addition to the complex silicate lattice, varying amounts of cation-exchangeable ions such as calcium, magnesium and, preferably, sodium. Hydrophilic clays which are preferred are the water swelling smectite clays such as montmorillonite, hectorite, saponite, and the like. One typical organic modified clay is dimethyldihydrogenated tallow ammonium bentonite prepared by treating a bentonite clay from Wyoming, in which the majority of the exchangeable cations are sodium ions, with dimethyldihydrogenated tallow ammonium chloride. The clay may be in the impure form as mined or may have been purified by centrifuging an aqueous slurry of the clay.

The organic modified clays and their preparation are adequately described in the following listed U.S. Pats. each of which are incorporated herein by reference: Hauser U.S. Pat. No. 2,531,427; Hauser U.S. Pat. No.

5 2,531,812; Jordan U.S. Pat. No. 2,966,506.

In the practice of the present invention there must be present in the mixture of organic modified clay and oleaginous medium an effective dispersing amount of a dispersant or solvating agent for the organic modified clay. The dispersant is used in the sense of the solvation agent referred to in the article, Organophilic Bentonites. Swelling in Organic Liquids, by John W. Jordan, The Journal of Physical and Colloid Chemistry, Vol. 53, No. 2, 1949, and in the article, Organophilic Bentonites. II Organic Liquid Gels," by John W. Jordan, B. J. Hook, and C. M. Finlayson, The Journal of Physical and Colloid Chemistry, Vol. 54, No. 8, 1950. Two U.S. Pats. which indicate the effect of dispersants in the preparation of greases are U.S. Pat. Nos. 2,833,720 and 2,879,229.

Materials which function as dispersants for organic modified clays in an oleaginous medium are well known to those skilled in the art. Such dispersants are generally water and/or low molecular weight, polar organic compounds such as, for example, alcohols, ketones, diketones, nitroalkanes, alkene carbonates, ether alcohols, ether esters, and the like. Representative dispersants are methanol, ethanol, acetone, methylethyl ketone, acetonylacetone, acetophenone, diethylketone, methyln-propyl ketone, 2, 3-butanedione, nitromethane, nitroethane, l-nitropropane, propylene carbonate, ethylene carbonate, ethyleneglycol monomethyl ether, ethyleneglycol monoethyl ether, diethyleneglycol monomethyl ether, ethyleneglycol monoacetate, diethyleneglycol monoacetate, and the like low molecular weight polar organic compounds.

The preferred dispersant for the practice of the present invention is water including aqueous solutions of inorganic salts such as sodium chloride, calcium chloride, and the like. The presence of soluble inorganic salts in the water lowers the freezing point of the water.

Generally from 0.5 to 10 percent by weight, based on the total composition, of dispersant is sufficient to effectively disperse the organoclay. It is preferred to use from 0.5 to 5 percent when the dispersant is a polar organic compound.

Oleaginous mediums useful in preparing the packer fluids of this invention may suitably be crude petroleum and fractions thereof, as, for example, diesel oil, kerosene, fuel oil, light lubricating oil fractions, heavy naphtha having a boiling range between about 300 to 600F, and the like. Because of the very high costs associated with transporting goods into remote frigid areas of the world such as the North Slope of Alaska, preferred for the practice of this invention are crude petroleum oil from which the light ends have been removed, diesel oil resulting from a crude distillation of the crude petroleum oil produced in the region of use, still bottoms which are obtained from the crude distillation of the crude petroleum oil, and mixtures of these oleaginous mediums. It is important that the oleaginous medium have a freezing point below the temperatures normally prevailing in a permafrost zone which is normally within the range from about 14 to about 32F.

Especially preferred for the practice of this invention is the use of an oil base mud as the oleaginous medium.

As is well known to those skilled in the art, oil base muds have many advantages in the drilling of oil and gas wells and are especially effective in frigid areas since they remain fluid at low temperatures such as are especially encountered in the surface pits and adjacent permafrost formations. See for example, US. Pat. No. 3,618,680. Such muds normally contain an oleaginous medium, such as those discussed hereinbefore, weighting agents such as barite, fluid loss control agents such as those disclosed in Jordan et al., US. Pat. No. 3,168,475 and Andrews et al., U.S. Pat. No. 3,494,865, emulsifiers, suspension agents such as the organic modified clays discussed and referenced herein. and emulsified water or aqueous solutions. The exact composition of such oil base muds is not critical. It is to be understood that the term oil base mud is used for those drilling fluids which have an oleaginous continuous phase. Such drilling fluids may contain emulsified water as a discontinuous phase. it is preferred for the practice of this invention that the oil base mud contain less than about percent emulsified water.

The emulsified water in the oil base drilling fluid will function as a dispersant for the organoclay in the process of the present invention such that additional dispersant may not be needed.

The concentration of organic modified clay is not critical in the process of the present invention provided that the concentration is sufficient to gel the composition upon raising the temperature of the composition to the maximum temperature expected to be encountered after placement of the composition at its desired location. Thus the concentration of organoclay need only be an effective gelling amount. For the purposes of this invention a composition is considered gelled when the gel strength of the composition is greater than 100 pounds per 100 square feet. The minimum concentra tion of organoclay needed to gel any particular composition is dependent upon several factors such as the type of organoclay used, the type of dispersant, the characteristics of the oleaginous medium to be gelled, the maximum temperature to which the composition is to be raised, and the concentration of any auxiliary thickener, such as asbestos, in the composition. The maximum concentration of organoclay which can be used in the process of this invention is limited only in that the composition must be sufficiently fluid at a temperature less than about 50F to be pumpable. This maximum concentration is dependent upon the type of organoclay used, the type of dispersant, the characteristics of the oleaginous medium to be gelled, the temperature of preparation of the composition, and the degree of shear imparted to the composition. In general the maximum concentration of organoclay which can be used in the composition increases as the preparation temperature decreases and as the degree of shear imparted to the composition decreases.

A concentration of organic modified clay within the range from pounds to 70 pounds per barrel (42 gal ions) of oleaginous medium, preferably 20 to 50 pounds per barrel, will generally provide a fluid, pumpable composition at an initial temperature less than about 50F which will become gelled at a temperature greater than 50F, preferably at a temperature within the range from 50F to 180F.

The concentration of organoclay required to gel the oleaginous medium can be decreased provided an aux iliary inorganic thickener such as asbestos, preferably chrysotile asbestos, is present in the composition. The asbestos may be pre-treated with a surfactant suchas those disclosed in Jordan et al., US. Pat. No.

5 2,995,514, fatty acids and the like.

The concentration of asbestos useful in the compositions of this invention is generally within the range from 0 to pounds per barrel of oleaginous medium to be gelled.

It is preferred that the total concentration of organoclay plus asbestos not be greater than 70 pounds per barrel of oleaginous medium. Still more preferably the total concentration of organoclay plus asbestos need not be greater than 50 pounds per barrel of oleaginous medium and the asbestos to organoclay clay ratio should be within the range from 0:1 to 111.

In accordance with this invention a packer fluid for permafrost zones is prepared by adding to an oleaginous medium an organoclay, a dispersant for the or-' ganoclay, and optionally, asbestos, in any order, provided that the organoclay is added only when the temperature of the oleaginous medium is less than about 50F. The composition of this packer fluid is regulated as discussed herein to provide a fluid, pumpable composition which gels at a temperature within the range from about 50F to about 180F. This packer fluid is then transferred, such as by pumping, into a wellbore at least one portion of which is to be insulated from the permafrost, at the desired location and gelled by raising the temperature within the wellbore above about 50F, preferably above about 100F. The gelation of the packer fluid need not take place immediately after placement of the fluid packer at its desired location. This fluid oil base packer fluid will efficiently insulate the interior of the wellbore from the freezing temperatures of the permafrost formation, and vice versa, at the relatively low temperatures which exist in the wellbore prior to producing oil and gas through the wellbore. Thus this fluid packer fluid can be used to insulate the wellbore during drilling of an oil and/or gas well and gelled after completion of the well by producing hot oil and/or gas through the wellbore. The preparation and placement of this packer fluid within the wellbore as described effectively prevents the thawing and attendant subsidence of the permafrost zone surrounding the wellbore upon producing hot fluid through the wellbore.

The temperature of the oleaginous medium may be lowered to 50F or less simply by exposure of the oleaginous medium to the low temperatures normally encountered in the frigid areas of the world. A temperature of 50F or less can also be obtained by any of the known means of refrigerating fluids. If necessary the pumpable oleaginous composition can be maintained at a temperature less than 50F before use by storage in refrigerated and/or insulated containers.

The following examples will further illustrate the invention and are not intended to limit the invention. Obvious changes may be made by those skilled in the art without changing the essential characteristics and the basic concept of the invention.

In these examples the following abbreviations, units of measure, and notations are used: ppb pounds per 42 gallon barrel of oleaginous medium; F degrees Fahrenheit; hr. hours; min. minutes; sec. seconds; cp centipoise; percent by weight of the total composition; ppm parts per million by weight;

all gel strengths and yield points are measured in pounds per 100 square feet; (1 sample temperature in F; (2) I gel strength at the indicated temperature obtained by observing the maximum reading of a Fann Meter at p Without y Prior Stirring Ofthc 5 were then stirred with a Hamilton Beach mixer for an p All tcst results were Obtained in accordance additional 2 minutes. The rheological properties of the with Standard AP] Procedures RP Fourth samples were obtained at the temperature indicated in Edition, November, 1972) unless otherwise indicated. T bl 2 hi h rose to 34-40F d i i i S b quent gel strengths were measured as the casing pack EXAMPLE 1 samples were statically aged and warmed to approximately 170 F over a time period of about 2 hours. Mea- An oil base mud was P p y adding 2 PP Of a surements were made at irregular time intervals de- Watet'ih-bh emulsifier MUL, Product Of Baroid pending upon the temperature change. These measure- Dtvtsibh, N L Industries and PP 0f ments were obtained by observing the maximum readdimethyldihydrogenatedtallow ammonium bentonite l5 ing at 3-rpm without any prior tirring of the sample, (GELTONE, product of Baroid Division, N L Indus- Th d t bt i d are given i T bl 2 tries, to a mixture of 95 Percent y Volume Arctic The data indicate that both samples would be effecdteset and 5 Percent y Volume Water and mixing for tive as packer fluids in this invention as both were ini- 5 minutes at room temperature with a Hamilton Beach tially of sufficient low viscosity for easy transfer into a mixer at high speed. Sufficient calcium chloride was 20 llb d d I d a l Strength f at least 100 then added to provide a concentration of 250,000 ppm upon b i h d to 17()F in the aqueous phase and the mixture stirred for an additional 10 minutes. The mud was then cooled to 0F. Table 2 Various concentrations of GELTONE as indicated in Table l were added to aliquots of the cold mud which sample D Sample E were then stirred with a Hamilton Beach mixer for 10 GELTONEv ppb minutes. Rheology and electrical stability of the sam- P- "F 34 40 ples were then checked at the temperature indicated in ffihmf 2 Table l which rose to 34-36F during mixing. The IO-ScC-GcI Strength 5 5 samples were static aged at room temperature (76F) 30 l for 5 hours, their rheology checked, then static aged at 46 22 62 85 120F for 16 hours, cooled to 76F and re-evaluated. g? 3: g; a The data obtained are given in Table 1. 65 4g 92 |36 The data indicate that the organoclay did not appre- 68 50 132 176 73 54 148 225 clably affect the rheology or electrical stability of the 35 61 162 240 oil base mud at the low initial temperatures encoun- 88 6 1 (off tered. However, upon heating these systems to 76F 9,2 Scale) and 120F the viscosity, thixotropy, and gel strengths of I30 88 the systems containing the organoclay added at the low {2% temperature increased whereas the rheology of the oil 40 16(1) Hg base mud did not chan e a reciably. The system coni I taining 25 ppb of addid o r ganoclay developed a lO- H) sample Temperature (2) Gel Strength sec. el stren th reater than u on heatin at e 12OP and wOl lld 5e suitable for use asa packer fiuid EXAMPLE 3 in permafrost formations. 45 An oil base mud was prepared as in Example 2 except Table 1 Sample A Sample B Sample C GELTONE.ppb 0 15 25 Test Temp. F 34 76 76 36 76 76 36 76 76 Max. Temp. F 34 76 36 76 120 36 76 120 Aged at 76F, hr. 5 5 5 5 5 5 Aged at 120F. hi. 16 l6 16 Plastic Viscosity, cp 17 13 l2 15 34 45 I7 90 85 Yield Point 8 7 I 1 15 34 65 14 100 255 lO-secGel Strength 7 5 5 8 I5 40 8 65 10-min.Gel Strength 8 5 l0 8 15 60 8 65 Electrical Stability. volts 1800+ 1800+ 1800+ EXAMPLE 2 that the oil phase consisted of Arctic dieseloiI only 7 I An oil b d was prepared b ddi 4 b f a 60 Various concentrations of GELTONE were added and water-in-oil emulsifier (EZ MUL) at a temperature less evaluated in the satne h as in Example The h 20 to a mixture f 475 percent by volume data obtained are given in Table 3. The data indicate tic diesel oil, 47.5 percent by volume still bottoms" that SamPleS G and H could effectively be used as (which remain after distilling off diesel oil and light hy- P e flulds the Present invention and that Sample drocarbons from crude petroleum oil), and 5 percent 65 F thd not get Suffietehtty on heating to 17001: to tune" by volume of 25 percent aqueous calcium chloride solution and mixing for 2 minutes with a Hamilton Beach Mixer.

Various concentrations of GELTONE as indicated in Table 2 were added to aliquots of this cold mud which tion as a packer fluid in the present invention.

Table 3 Sample F Sample G Sample H GELTONE. ppb 30 45 60 Test Temp. "F 39 36 46 Plastic Viscosity, cp. I] l3 12 Yield Point 2 0 lO-sec. Gel Strength l 3 0 (l) (2) (l) (2) (l) (2) 52 l 48 14 50 l 86 8 60 I5 54 2 92 ll 72 35 61 8 96 13 8O 56 67 II 112 27 95 66 69 I9 I18 34 105 8! 72 38 I37 37 I30 90 86 63 l55 52 l39 [I2 I08 144 168 56 l55 I15 I33 235 I65 I16 180 118 (l) Sample Temperature (2) Gel Strength EXAMPLE 4 To Arctic diesel oil cooled to 20F were added the concentrations of dimethyldihydrogenatedtallow ammonium bentonite (GELTONE) and either methanol or water as indicated in Table 4. These mixtures were stirred with a Hamilton Beach mixer for the length of time indicated in Table 4. During mixing the temperature of the samples increased to the indicated temperature. The rheological properties of the samples were obtained. The samples were then slowly heated to 170F and gel strength measurements obtained periodically as in Example 2. The date obtained are also given in Table 4.

Comparison of the data obtained for Sample I (not an illustration of the invention) and Sample J indicate that a polar dispersant is necessary in the process and composition of the present invention for adequate gel development above about 50F. Comparison of the data obtained for Sample K, Sample L (not an illustration of the invention) and Sample M indicate that 70 ppb of organoclay can be used in the process and composition of the present invention provided that the dispersant used and/or the mixing temperature are chosen to effectively retard gel development until the packer fluid can be placed in its desired location, Sample L gelled on heating only to 45F. A packer fluid having this composition would have to be maintained less than about F during placement in order to prevent gelation of the fluid as is the case for Sample K.

EXAMPLE 5 w Arctic diesel oil cooled to 20F containing 40 ppb dimethyldihydrogenatedtallow ammonium bentonite (GELTONE), 17.5 ppb water and the concentration of asbestos indicated in Table 5 was stirred with a Hamilton Beach mixer for 2-3 minutes. The temperature increased during mixing as indicated in Table 5 at which temperature the rheological properties of the samples were obtained. The samples were then slowly heated to l70F and gel strength measurements obtained periodically as in Example 2. The data obtained are given in Table 5.

The asbestos used in this example was short fibered chrysotile asbestos of the Coalinga, California variety sold commercially for use in drilling fluids under the trademark FLOSAL.

Comparison of the data indicate that the asbestos did not seriously effect the rheological properties at low temperature and considerably enhanced the gel strength at elevated temperatures. Comparison of Sample O with Sample M of Example 4 indicat that the as bestos can replace more than an equal weight of the organoclay for equal gel strength development.

Table 4 Sample 1 Sample J Sample K Sample L Sample M GELTONE, ppb 50 50 70 70 70 Methanol. ppb 0 5.6 5T6 5.6 0 Water, ppb 0 t) 0 17.5 Mixing Time. min. 5 4 2 3 4 Test Temp, "F 33 33 45 40 Plastic Viscosity cp. 3 l0 5 40 3 Yield Point 1 l2 4 I00 3 lO-sec. Gel Strength 0 36 l l 200 l (l) (2) (l) (2) (l) (2) (l) (2) (l) (2) 53 0 75 205 47 101 50 250 205 R0 (1 I05 220 56 l40 340 82 300 ti l 0 l 34 240 150 86 420 98 430 I46 I55 230 I65 I05 370 440 158 U 170 205 116 I75 120 360 118 465 I70 0 I36 [80 335 500 145 l4O 151 330 l60 5l5 ISO lSO l70 325 I70 525 I60 I85 230 (l) Sample Temperature (2) Gel Strength Table 5 Sample N Sample Sample P Asbestos. ppb 0 I0 20 Test Temp. F 42 36 40 Plastic Viscosity. cp 3 7 8 Yield Point 3 I5 IO-sec. Gel Strength I 5 I l (I) (2) (I) (2) (I) (2) 72 5 66 25 74 65 I I0 I0 97 I I00 I I55 I5 I20 200 I40 235 I70 20 I 275 I48 340 I45 340 I62 395 I62 4I5 I70 425 I70 455 I I) Sample Temperature (2) Gel Strength EXAMPLE 6 To Arctic diesel oil cooled to 20F were added the concentrations of dimethylhydrogenatedtallowbenzyl ammonium bentonite (BARAGEL 24) and either methanol or water as indicatedin Table 6. These mixtures were stirred for 2 minutes with a Hamilton Beach mixer. During mixing the temperature of each sample increased to 36-40F as indicated in Table 6. The rheological properties of the samples were obtained and then the gel strength at various temperatures as in Example 2. The data obtained are given in Table 6.

The data indicate that water did not function as a dispersant for this organoclay in diesel oil. Use of methanol as a dispersant produced packer fluids for use in the present invention which are characterized by low initial viscosity and gel strength and a very rapid gel development at temperatures above about 75F to produce highly gelled packer fluids.

A packer fluid was prepared by mixing into an oil A I base mud having the properties given in Table 7, pounds of dimethyldihydrogenatedtallow ammonium bentonite (GELTONE) per barrel of the mud at a temperature of 40F. The oil base mud contained 81 percent oil, primarily Arctic diesel oil, 7 percent water, and 12 percent solids as determined by API Standard Procedure RB 138, the aqueous phase of which contained soluble salts equivalent to 280,000 ppm of calcium chloride. This packer fluid possessed the properties given in Table 7. The packer fluid was then pumped into a wellbore between the 13 3/8 inch casing and the 20 inch casing using a pump truck normally used for placing cement within wellbores. The temperature of the excess returns from this annulus was 40F. This packer fluid was sufficiently viscous to insulate the wellbore from the permafrost zone. All the water within the packer fluid was very tightly emulsified and Table 6 Sample 0 Sample R Sample S BARAGEL 24. ppb 30 3O 5O Methanol. ppb 0 5.6 5.6 Water, ppb I7.5 0 0 Test Temp, "F 40 38 36 Plastic Viscosity, cp. 2 5 8 Yield Point 3 3 5 IO-sec. Gel Strength I 3 5 (I) (2) (I) (2) (I) (2) 90 0 58 20 64 60 I 0 76 25 I00 205 I70 0 I00 I65 I15 705 I30 320 I47 I255 I45 615 I64 I500 I53 690 I 770 I70 820 (I) Sample Temperature (2) Gel Strength EXAMPLE 7 contained sufficient water soluble salts to prevent its Non-producing wells in the Prudhoe Bay Field of 60 freezing- Additionally the packer fluid contained sufficient or ganic modified clay and dispersant (emulsified aqueous phase) to efficiently gel the packer fluid upon raising the temperature within the wellbore when the well is placed into production as the data in Table 7 indicate. No casing failures have occurred in this well since this packer fluid was placed therein.

Table 7 Oil Bust. Packer Fluid Mud Initially Mud Temp.. F 45 40 Mud Densityv ppg 9.9 l0.0 Electrical Stability, volts 2000+ 2000+ Funnel Viscosity. sec. 45 94 Test Temp., F 62 I 40 Plastic Viscosity. cp. 24 I6 68 Yield Point. lb./l00 sq. ft. 6 8 6l l0sec. Gel Strength. lb./l00 sq. ft. 8 6 44 -min. Gel Strength, lb./l00 sq. ft. 10 8 81 Gel Strength at 100F, lb./l00 sq. ft. 8 (ND) 130 Gel Strength at 170F, lb./l00 sq. ft. 6 (ND) 150 (N. D. Not Determined) The gelled oil base fluids provided by the invention disclosed herein have uses other than their use as packer fluids. Thus such gels can replace the rigid oil base gel disclosed and claimed in l-loeppel US. Pat. No. 3,705,107, incorporated herein by reference, for the uses disclosed therein.

These gelled oleaginous fluids can also be used in insulating wellbores in thermal injection wells and in insulating pipelines traversing a permafrost region.

I claim:

1. In a method of producing a gelled oil base packer fluid and transferring said fluid to a desired location within a wellbore, wherein said fluid comprises an oleaginous medium, an effective gelling amount of an organic modified clay and a dispersant for said clay in an effective dispersing amount, the method of preventing gelation of said fluid before placement of said fluid at said desired location and gelling said fluid after said placement, which comprises mixing said clay in said medium at a temperature less than about 50F, maintaining the temperature of said fluid less than about 50F before and during said placement, and thereafter raising the temperature within said wellbore to gel said fluid.

2. The method of claim 1 wherein the concentration of said clay is from ppb to 70 ppb.

3. The method of claim 2 wherein the concentration of said clay is from 20 ppb to 50 ppb.

4. The method of claim 3 wherein the fluid contains up to 30 ppb of asbestos.

5. The method of claim 4 wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.

6. The method of claim 5 wherein said dispersant is selected from the group consisting of water and low molecular weight polar organic compounds, and wherein the concentration of said dispersant is from 0.5 to 10 percent by weight.

7. The method of claim 6 wherein said clay is dimethyldihydrogenatedtallow ammonium bentonite, wherein said medium is an oil base drilling fluid, and wherein said dispersant is an aqueous phase emulsified in said drilling fluid.

8. A method of producing a gelled oil base packer fluid and transferring said fluid to a desired location within a wellbore in a permafrost formation before gelation of said fluid comprising the steps of adding to an oleaginous medium from 20 ppb to 70 ppb of organic modified clay and from 0.5 percent to 10 percent by weight of a dispersant for said clay selected from the group consisting of water and low molecular weight polar organic compounds, said clay being added to said oleaginous medium at a temperature less than about 50F; mixing the resulting fluid to distribute said clay and said dispersant throughout said medium; transferring said fluid to said desired location; and thereafter flowing a hot fluid selected from the group consisting of oil and gas through said wellbore to the surface of the earth to raise the temperature within the wellbore whereupon said fluid is gelled; wherein the temperature of said fluid is maintained less than about 50F during said mixing and transferring steps.

9. The method of claim 8 wherein the concentration of said clay is from 20 ppb to 50 ppb, wherein said fluid contains up to 30 ppb of asbestos, and wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.

10. The method of claim 9 wherein said clay is the re action produce of a water swelling smectite clay and an onium compound which contains at least one radical having at least 10 carbon atoms selected from the group consisting of alkyl, alkylene, and alkylidene radicals.

11. The method of claim 10 wherein said clay is dimethyldihydrogenatedtallow ammonium bentonite.

12. The method of claim 1 wherein said medium is an oil base drilling fluid and wherein said dispersant is an aqueous phase emulsified in said drilling fluid.

13. In a method of insulating casing in a wellbore in permafrost from the low temperatures in said permafrost and of insulating said permafrost from high temperatures within said wellbore upon producing hot oil or gas through said wellbore which comprises pumping an oil base packer fluid in an annular space within said wellbore and thereafter gelling said packer fluid, the improvement which comprises said packer fluid which comprises an oleaginous medium, from 20 ppb to ppb of organic modified clay, and. from 0.5 to 10 percent by weight of a dispersant for said clay selected from the group consisting of water and low molecular weight polar organic compounds, said clay being mixed into said medium at a temperature less than about 50F, wherein the temperature of said fluid is maintained less than about 50F before and during placement of said fluid within said wellbore, and wherein said packer fluid is gelled upon raising the temperature within said wellbore.

14. The method of claim 13 wherein the concentration of said clay is from 20 ppb to 50 ppb, wherein said fluid contains up to 30 ppb of asbestos, and wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.

15. The method of claim 14 wherein said clay is selected from the group consisting of dimethyldihydrogenatedtallow ammonium bentonite, trimethylhydrogenatedtallow ammonium bentonite, and dimethylwherein said medium is an oil base drilling fluid, and hydrogenatedtallowbenzyl ammonium bentonite. wherein said dispersant is an aqueous phase emulsified 16. The method of claim 14 wherein said clay is in said drilling fluid.

dimethyldihydrogenatedta]low ammonium bentonite,

Claims

2. The method of claim 1 wherein the concentration of said clay is from 20 ppb to 70 ppb.
3. The method of claim 2 wherein the concentration of said clay is from 20 ppb to 50 ppb.
4. The method of claim 3 wherein the fluid contains up to 30 ppb of asbestos.
5. The method of claim 4 wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.
6. The method of claim 5 wherein said dispersant is selected from the group consisting of water and low molecular weight polar organic compounds, and wherein the concentration of said dispersant is from 0.5 to 10 percent by weight.
7. The method of claim 6 wherein said clay is dimethyldihydrogenatedtallow ammonium bentonite, wherein said medium is an oil base drilling fluid, and wherein said dispersant is an aqueous phase emulsified in said drilling fluid.
8. A method of producing a gelled oil base packer fluid and transferring said fluid to a desired location within a wellbore in a permafrost formation before gelation of said fluid comprising the steps of adding to an oleaginous medium from 20 ppb to 70 ppb of organic modified clay and from 0.5 percent to 10 percent by weight of a dispersant for said clay selected from the group consisting of water and low molecular weight polar organic compounds, said clay being added to said oleaginous medium at a temperature less than about 50*F; mixing the resulting fluid to distribute said clay and said dispersant throughout said medium; transferring said fluid to said desired location; and thereafter flowing a hot fluid selected from the group consisting of oil and gas through said wellbore to the surface of the earth to raise the temperature within the wellbore whereupon said fluid is gelled; wherein the temperature of said fluid is maintained less than about 50*F during said mixing and transferring steps.
9. The method of claim 8 wherein the concentration of said clay is from 20 ppb to 50 ppb, wherein said fluid contains up to 30 ppb of asbestos, and wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.
10. The method of claim 9 wherein said clay is the reaction produce of a water swelling smectite clay and an onium compound which contains at least one radical having at least 10 carbon atoms selected from the group consisting of alkyl, alkylene, and alkylidene radicals.
11. The method of claim 10 wherein said clay is dimethyldihydrogenatedtallow ammonium bentonite.
12. The method of claim 1 wherein said medium is an oil base drilling fluid and wherein said dispersant is an aqueous phase emulsified in said drilling fluid.
13. In a method of insulating casing in a wellbore in permafrost from the low temperatures in said permafrost and of insulating said permafrost from high temperatures within said wellbore upon producing hot oil or gas through said wellbore which comprises pumping an oil base packer fluid in an annular space within said wellbore and thereafter gelling said packer fluid, the improvement which comprises said packer fluid which comprises an oleaginous medium, from 20 ppb to 70 ppb of organic modified clay, and from 0.5 to 10 percent by weight of a dispersant for said clay selected from the group consisting of water and low molecular weight polar organic compounds, said clay being mixed into said medium at a temperature less than about 50*F, wherein the temperature of said fluid is maintained less than about 50*F before and during placement of said fluid within said wellbore, and wherein said packer fluid is gelled upon raising the temperature within said wellbore.
14. The method of claim 13 wherein the concentration of said clay is from 20 ppb to 50 ppb, wherein said fluid contains up to 30 ppb of asbestos, and wherein the total concentration of said clay and said asbestos is from 20 ppb to 50 ppb.
15. The method of claim 14 wherein said clay is selected from the group consisting of dimethyldihydrogenatedtallow ammonium bentonite, trimethylhydrogenatedtallOw ammonium bentonite, and dimethylhydrogenatedtallowbenzyl ammonium bentonite.
16. The method of claim 14 wherein said clay is dimethyldihydrogenatedtallow ammonium bentonite, wherein said medium is an oil base drilling fluid, and wherein said dispersant is an aqueous phase emulsified in said drilling fluid.