NO137180B - WATER GEL FOR USE AS A DRILL IN OIL PRODUCING FORMATIONS - Google Patents

Abstract

Aqueous gel for use as an aid when drilling in oil-producing formations.

Description

Secondary extraction of oil from oil-bearing or oil-containing underground formations by fluid extrusion methods, where a fluid is injected into the formation through one or more injection wells to push the oil through the formation to one or more production wells, is a well-known process. The fluids used in such processes include liquids such as water and . various hydrocarbons and gases such as e.g. hydrocarbon gases, carbon dioxide etc. Many oil traps comprise layers or zones of porous rocks, whose mechanical permeability can vary from more than 1,000 mD to less than 10 mD.

In all fluid extrusion methods, the tendency of the press fluid to

to channel along or through the more permeable zones of . the formation a problem that has been aware of. This is commonly referred to as

show as "finger formation". After the oil has mostly been pushed out from the more permeable zones, these act as "thief zones" which allow the pressure fluid to flow directly from the injection wells to the production wells. In many cases, such channeling or finger formation means that significant amounts of oil remain in the less permeable zones of the formation that are bypassed. Such channeling or finger formation can take place when the mobility, i.e. the permeability of the reservoir or oil trap to the pressure fluid divided by the viscosity of this, becomes relatively large in relation to the mobility of the reservoir oil.

Drilling fluids used when drilling oil wells, gas wells

and similar boreholes, are usually aqueous fluids containing clays or other colloidal materials. Drilling fluids serve as a lubricant for the drill bit and drill stem and as a carrier medium for the chips formed by the drill bit, as well as helping to form a filter cake on the wall of the borehole to reduce fluid loss to the surrounding layers below

the surface. It is known that too high a viscosity of the drilling fluid has an adverse effect on the penetration rate that can be achieved with the drill bit. In many cases, significantly better speeds can be achieved by looping colloidal materials and reducing the viscosity of the drilling fluid. In certain cases, air, clean water or other similar low-viscosity fluids can be used instead of the usual drilling fluid or drilling mud.

The present invention provides a solution to the above problems. Namely, a class of new, aqueous gels has been discovered which can constitute at least part of the aqueous medium used in the aforementioned secondary extraction operations, as well as the aqueous medium used in the well drilling operations. It has been discovered that when water-soluble cellulose ethers are used in conjunction with a water-soluble compound of a polyvalent metal which can be reduced to a lower valency which is, however, higher than 1, and a suitable reducing agent capable of effecting said reduction, this material will could be used as a gelling agent for gelling aqueous media, including water. It has been established that by varying the composition and/or the amount of the gelling agents mentioned and/or the conditions under which they are used in the formation of the gels, a large spectrum of aqueous gels can be produced from liquid, highly mobile gels to rigid gels.

The aqueous gels according to the invention are particularly useful in operations where a fluid is introduced into a borehole in the earth, e.g. in the above-described secondary extraction, in the above-described drilling operations, in completion operations for wells, as packing fluids etc.

The invention thus concerns an aqueous gel for use as an aid when drilling in oil-producing formations, more specifically for use as at least part of a fluid that is introduced into a borehole in the earth to contact an underground formation that is penetrated by the borehole, as the gel is produced by thickening water by adding 0.0025 - 20% by weight, calculated on the weight of the water, of a water-soluble cellulose ether and gelling the thickened aqueous solution by adding 0.05 - 60% by weight, calculated on the weight of the cellulose ether, of a water-soluble compound of a polyvalent metal with more than one polyvalent state, characterized in that the metal compound is a compound of chromium or manganese and is present in an amount of at least 3·10 gram atoms of metal per grams of cellulose ether, and that at least part of the metal is reduced to a lower polyvalent state by the addition of a water-soluble reducing compound.

In general, any of the water-soluble cellu-ethers can be used in carrying out the invention. The cellulose ethers that can be used include the various carboxyalkyl cellulose ethers, e.g. carboxyethyl cellulose and carboxymethyl cellulose~(GMC), mixed ethers such as e.g. carboxyalkyl/hydroxyalkyl ethers, e.g. carboxymethyl/hydroxyethyl cellulose (CMHEC), hydroxyalkyl celluloses such as hydroxyethyl cellulose and hydroxypropyl cellulose, alkyl-hydroxyalkyl celluloses such as e.g. methylhydroxypropyl cellulose, alkyl celluloses such as methyl cellulose, ethyl cellulose and propyl cellulose, alkylcarboxyalkyl celluloses such as e.g. ethyl carboxymethyl cellulose, alkyl alkyl celluloses such as e.g. methylethylcellulose and hydroxyalkyl-alkylcelluloses such as e.g. hydroxypropylmethylcellulose and similar cellulose ethers. Many of these cellulose ethers are commercially available in various grades. The carboxy-substituted cellulose ethers are available as the alkali metal salt, usually the sodium salt. However, reference is rarely made to the metal, and the ethers are usually referred to as e.g. CMC, CMHEC etc. Water-soluble CMC is e.g. available in various degrees of carboxylate substitution in the range from ca.

0.3 up to the maximum degree of substitution of 3.0. CMC with a degree of substitution in the range of 0.65 to 0.95 is generally preferred.

CMC with a degree of substitution in the range from 0.85 to 0.95 is often one

even more preferably cellulose ether. CMC with a degree of substitution below the above-mentioned ranges usually have less uniform properties and are thus less desirable for use in carrying out the invention. CMC with a degree of substitution above the above preferred ranges generally has a lower viscosity, and larger amounts are required in the practice of the invention. The degree of substitution of CMC is usually expressed in the designations, which are e.g. CMC-7, CMC-9, CMC-12 etc, where the numbers 7, 9 and 12 refer to a degree of substitution of 0.7, 0>9 and 1.2 respectively.

In the above-described mixed ethers, it is preferred that the

the proportion of these that contain the carboxylate groups is significant rather than just a trace. When it e.g. for CMHEC, it is preferred that the degree of carboxymethyl substitution is at least 0.4. The degree of hydroxy-ethyl substitution is less important and can vary within wide limits, e.g. from approx. 0.1 or lower to approx. 4 or higher.

The amount of cellulose ether used in carrying out the invention can vary within wide limits depending on the degree of viscosity and the purity of the ether and the properties desired in the aqueous gels to which the invention relates. The amount of cellulose ether used will usually be a water-thickening amount, i.e. at least an amount that noticeably thickens the water to which it is added. Quantities in the order of magnitude from 25 to 100 parts by weight per million (0.0025 - 0.01 weight percent) is e.g. found to thicken water noticeably. Water containing 25 ppm CMC has a viscosity increase of approx. 215?. At 50 ppm, the increase in viscosity is approx. 45$. At 100 ppm, the increase in viscosity is approx. 195% - In general terms, amounts in the range from 0.0025 to 20 percent by weight, preferably 0.01-5 and most preferably 0.025-1 percent by weight, calculated on the weight of water, can be used. However, quantities outside these ranges can also be used. When the correct amounts of polyvalent metal and reducing agent are used, the amount of cellulose ether used will usually determine the consistency of the resulting gel. Small amounts of cellulose ether will usually give liquid mobile gels that can be easily pumped, while large amounts of cellulose ether will usually give stiff, solid gels. If desired, these stiff gels can be "thinned" by dilution to any desired cellulose ether concentration. This can be done mechanically, e.g. by stirring, pumping or using a suitable device for turbulent supply that produces a shearing effect, e.g. a jet nozzle. There is thus in reality no fixed upper limit for the amount of cellulose ether that can be used. When a liquid mobile gel is desired, however, it is preferred to dilute the more concentrated gels before they solidify.

Examples of the polyvalent metal compounds include potassium permanganate, sodium permanganate, ammonium chromate, ammonium dichromate, alkali metal chromates, alkali metal dichromates and chromium trioxide.

The amount of the aforementioned metal-containing compounds used in carrying out the invention is a noticeable amount, i.e. a small but limited amount greater than incidental contaminants that serves or is sufficient to provide substantial gelation when the metal in the compound is reduced to a lower valence greater than 1. The lower limit of the concentration of the starting metal-containing compound will depend on the particular type of cellulose ether used, the concentration of cellulose ether in the water to be gelled, the water used, and the desired type of gel product. Too large amounts of the starting metal compound, e.g. hexavalent chromium, which can give excessive amounts of trivalent chromium when sufficient reducing agent is present, can adversely affect the stability of the produced gels. As a general rule, the amount of the starting compound containing polyvalent metal used for the production of aqueous gels will lie in the range from 0.05 to 60, preferably 0.5 to 30 percent by weight of the amount of cellulose ether used. Expressed differently, the amount will usually be sufficient to provide at least 3"10 ^ and

-5

preferably at least 3*10 gram atoms of the reducible metal per grams of cellulose ether. The amount of the metal will preferably not exceed 4"10 - 3 J and most preferably not 2*10 - 3 J gram atoms of the metal per gram of cellulose ether. Those skilled in the art can determine the optimum amounts of the metal compound to be used by routine tests which can be carried out in light of the present preparation When salt water of the kind usually available in producing oil fields is used as water in the preparation of gels according to the present invention, less of the starting compound is required, for example, than when distilled water is used.

Stable gels have been prepared using salt water with a content of dissolved solids within a wide range, e.g. from water with respectively 850, 1200, 6000 and 90,000.ppm dissolved solids. The gelation rates are often greater when such salt solutions are used. Such oilfield brine usually contains varying amounts - sodium chloride, calcium chloride, magnesium chloride, etc. Sodium chloride is usually present in the greatest concentration. The word "water" is used in the present description as a generic term which, unless otherwise stated, shall include salt water and salt solutions as mentioned, fresh water and other aqueous media which can be gelled in accordance with the invention.

Suitable reducing agents which can be used in the gels according to the invention include sulfur-containing compounds such as sodium sulphite, sodium hydrosulphite, sodium metabisulphite, potassium sulphite, sodium bisulphite, potassium metabisulphite, sodium sulphide, sodium thiosulphate, iron sulphate and thioacetamide, in addition to compounds which do not contain sulphur, e.g. hydroquinone, ferric chloride, p-hydrazinebenzoic acid, hydrazine phosphite and hydrazine dichloride. Some of the above reducing agents work faster than others. E.g. sodium thiosulphate reacts slowly in the absence of heat and thus requires e.g. heating to approx. 52-54°C. Preferred reducing agents are sodium hydrosulfite or potassium hydrosulfite.

The amount of reducing agent used is an appreciable amount, i.e. a small but finite amount that is greater than incidental impurities but is effective to reduce at least a portion of the polyvalent metal in the starting compound to a lower valence state. As a general rule, the amount of reducing agent used will usually lie in the range from 0.1 to at least 150 and preferably at least approx. 200 percent by weight of the stoichiometrically necessary amount for reduction of the metal from the original polyvalent state to the mentioned lower valence state, e.g. from +6 Cr to + 3 Cr. Those skilled in the art can determine the amount of reducing agent to be used by simple experiments carried out in light of the present preparation.

For the production of the aqueous gels according to the invention can

the metal-containing compound or the reducing agent is added to an aqueous solution of cellulose ether, or the metal-containing compound and the reducing agent can be simultaneously added to the aqueous medium containing the cellulose ether. The preferred method generally involves first dispersing the cellulose ether in the aqueous medium. The reducing agent is then added with stirring. Then the metal compound is added. Gelation starts as soon as some of the polyvalent metal is reduced to a state of lower valence. The newly formed metal ions with lower valence, e.g. +3 chromium produced from +6 chromium causes rapid cross-linking of the cellulose ethers and gelation of the solution or the aqueous medium containing these.

Aqueous gels can be produced according to the invention

with a large spectrum of viscosities or firmnesses in the range from low-viscous or highly mobile gels with a relatively low viscosity up to solid or rigid gels that do not move. The choice of viscosity or concentration of the gel will depend on its application. The actual viscosity and/or gel strength will depend on the nature and concentration of the cellulose ether, the nature and amount of the starting metal compound used and the nature and amount of the reducing agent used.

A currently preferred method is to prepare a relatively concentrated or highly viscous gel and dilute this to a viscosity or concentration suitable for practical use of the gel. In many cases, this method provides a more stable gel.

When using this dilution technique, an initial solution of cellulose ether containing e.g. 1,000 - 10,000 ppm (0.1-1% by weight) cellulose ether. This solution is then gelled by adding suitable amounts of metal compound and reducing agent. After the gelation has been carried out to the desired degree, the resulting gel can be diluted to the concentration or viscosity most suitable for the intended application. If the gel is to be used for a water filling operation, it will e.g. could be diluted to a gel with a nominal content of 1,000, 500, 250 ppm or less by adding a suitable amount of water. The more concentrated cellulose ether solutions usually have a faster gelation rate. In most cases, it will thus be preferred to carry out the dilution immediately after the gel's components have been added to water or another aqueous medium, e.g. within approx. 5 ~ 30 minutes. The concentration of cellulose ether in the "concentrated gel" will preferably be at least twice as high as in the finished gel. Diluting the gel slows the gelation rate. This dilution technique can therefore be used to control or control the gelation rate if desired. In many cases, gels prepared using the aforementioned dilution technique are more stable. Another advantage of the dilution technique is that it is usually more convenient to weigh out and handle larger amounts of reaction components.

Chromium ions with a value of +3 have been used for reaction with water-dispersible polymers such as e.g. polyacrylamides and polysaccharides. See e.g. U.S. patent documents no. 3-114,651 and 3-383,307-

In these processes, the chromium compound is added in a form where the chromium has an original valence of +3, e.g. + . CrCl,■ > , Cr(N0,), etc. It has been found that the Cr ions obtained in this way do not form stable gels with the cellulose ether. The gels that may be produced in this way will undergo either syneresis or precipitation within a few minutes. When carrying out the present invention, the Cr<+>^ ions must be newly formed, e.g. nascent ions formed in situ in the solution to be gelled.

Gel instability is shown by precipitation and/or syneresis (separation or water separation). A rigorous test of gel stability consists of preparing the gel and simply setting it aside. It has been found that gels which are stable for as long as 48 hours are usually stable for a month or longer. Formation materials such as sandstone and limestone have also been found to promote gel stability.

The pH value of the final solution of the gelation reaction components is preferably lower than 7 and preferably in the vicinity of 6. Generally, the pH value is not critical, but higher pH values slow

the gelation rate. Generally, the pH value of the gelling solution will depend on the reducing agent used. If desired,

the pH value can be adjusted by adding a suitable acid, depending on the reducing agent used.

In the present preparation, the aqueous gels according to the invention, unless otherwise stated, for the sake of simplicity and not with a view to limitation, will be designated according to the amount of the cellulose ether content, regardless of whether all the cellulose ether is cross-linked. A 1% by weight or 10,000 ppm gel is e.g. a gel prepared

from an original cellulose ether solution containing 1% by weight or 10,000 ppm cellulose ether. The same system is used for the gels produced by the above dilution techniques.

As indicated above, the aqueous gels according to the invention are particularly applicable in fluid extrusion methods for the secondary extraction of oil. The gels according to the invention are useful for reducing the mobility of an extortion fluid such as e.g. water, or reduction of the permeability of formations before or during secondary extraction operations such as e.g. fluid squeezing methods, as well as for water sealing treatments in production wells. An un-

equal water filling or gas extrusion is carried out in the usual way until the extrusion fluid breaks through to the production well in excessive quantities. A gel according to the invention is then pumped down the well and into the formation in any suitable manner and in any suitable quantity and for any suitable period of time sufficient to provide the desired in-depth penetration penetration) and reduce the mobility of the driving fluid or the permeability of the zones in the formation that have high permeability. A penetration to a depth of 3 - 300 and preferably 23 - 274 meters from the injection well will be sufficient. However, this can vary from formation to formation, and penetration rates outside these areas can be used. There can e.g. a gel according to the invention is injected into the formation via the injection well in an amount of approx. 0.001 to approx. 0.5 times the pore volume during a suitable period of time which can be between one day and 6 months. Optionally, the injection of the gel can be carried out by injecting a rate of approx. 32,000 - 800,000 liters of gel in the well and then in the formation. Injection in one of the above ways will provide a fill front close to the oil to be recovered. If desired, a normal saline solution or water can then be used to press

this rate or front or this band of gel further through the formation to the production well. In order to avoid any sharp dividing lines in the viscosity or mobility of the gel, which could have an adverse effect on the relative mobility of the filling medium and the oil and cause channeling, the viscosity or concentration of the gel can possibly be reduced gradually by a series of stepwise reductions instead of the injection of the gel stops abruptly.

The formation can be treated before carrying out the secondary extraction by fluid extrusion. This is a particularly applicable method when there is a good knowledge of the nature of the formation. In a formation where the oil-bearing layers alternate with more permeable porous layers that contain no oil or insufficient oil to make secondary recovery economical, but which would nevertheless serve as thief zones, the formation can be treated with a gel according to the invention before fluid extrusion begins.

The gel according to the invention can also be used on production wells or gas wells where the hydrocarbon-bearing layers border more porous layers that do not contain hydrocarbons. Such a condition can e.g. occur when a water-containing sand adjoins a hydrocarbon-containing sand and the water penetrates into the borehole and disrupts the extraction of hydrocarbon. In such cases, the formation can be treated with a gel according to the invention to shut off the water flow. The procedure for carrying out such a water shut-off treatment is essentially the same as described above in connection with fluid extrusion.

The gel injections can also be carried out periodically or intermittently as needed during a secondary extraction with fluid extrusion or during the extraction of oil from a production well.

In all of the above-mentioned operations, the injection of the gel according to the invention can be carried out in the usual way. If desired, a gel of suitable viscosity or concentration can be injected as the actual extrusion fluid. Gels to be injected can be prepared in advance, stored in suitable tanks and then pumped into the well. Optionally, the gels can be formed in a line leading to the injection well, or in the casing pipes in the well itself and then injected into the formation. The necessary quantities of cellulose ether, metal compounds and reducing agent can be supplied to the pipes in the well in measured quantities, mixed in the pipes and then injected into the formation. If desired, selected parts of the formation can be isolated mechanically, e.g. by using packings, (packers) and in other ways known in the art.

The aqueous gels according to the invention can constitute or be used as drilling fluids when drilling wells in any manner known in the art, and where drilling fluids are used. Such gels can be used without the addition of other materials. If desired, however, drilling fluids containing the aforementioned aqueous gels can be made heavier by incorporating agents such as barium carbonate, barium sulfate, amorphous silicon oxide, etc. If desired, other additives compatible with the aqueous gels can also be incorporated into the drilling fluid. The drilling fluids can thus contain clays such as bentonite, attapulgus clay, fluid loss agents etc.

Example 1

A number of experiments have been carried out to shed light on the production of aqueous gels according to the invention. For these experiments, a stock solution containing 4.3 g/l of highly viscous CMC-9 was prepared. To separate 233 ml portions of this stock solution were added varying amounts of Ha^ S^ O^ dissolved in 27 ml of distilled water while stirring for 10 seconds and then different amounts of Na2^ 2^" j' 2H,.,0 dissolved in 20 ml of distilled water with stirring for 10 minutes. Thus, each test solution had a total volume of 280 ml, and the concentration of CMC in the solution was 3>6 g/l or 0.357% by weight (3570 ppm). Stable gels were formed in each case. The results of these experiments are given in Table I. The figures in the table show that the rate of gelation increases with increasing amounts of ^2^20^' 2E^ 0 when sufficient reducing agent is present to reduce Cr<+>^ to Cr<+ The figures also show that the degree of gelation increases with an increasing amount of reducing agent for a given amount of Na2Cr20^•2H20.

Example II

A series of experiments were carried out to investigate the order of addition of the metal compound and the reducing agent to the cellulose solution. A solution containing 0.357% by weight of highly viscous CMC-9 in distilled water was prepared. The order of addition

of the metal compound (M) and the reducing agent (RA) was varied on

three ways: (1) First M, then RA (M-RA), (2) first RA, then metal (RA-M) and (3) RA and M simultaneously (RA & M). The metal compound and/or reducing agent were added in dissolved form in sufficient

amounts to obtain 0.16 g of each substance per 280 ml total finished solution volume. Gel formation was measured by determining the apparent viscosity and gel strengths of the resulting gels. The results of these tests are given in Table II together with comparable samples of ungelled CMC solution.

The figures in Table II show that good gels were obtained in all cases, and that the order of addition of the reducing agent and the metal compound to the CMC solution can be varied as desired. The figures also show that a better control of the gelation rate is achieved when the reducing agent is added first.

Example III

A number of experiments were carried out to check the gelation properties of water-soluble cellulose ethers other than CMC. In each experiment, a 1.0 percent by weight solution (10,000 ppm) of the cellulose ether to be controlled was prepared. in water. To 250 ml of each solution were then added 0.375 g m& 2S 2 °H and 0.375 g Na 2 Cr 2 O 7 • 2H 2 O (both in solutions containing 1.5 g/l) in the aforementioned order with stirring after each addition. The solutions were then examined visually for gel formation. The results of the experiments were as follows

The results of other gelation tests have shown that CMC-7 and CMC-12 as well as CMC-9 form good stable gels according to the invention.

Example IV

A number of experiments were carried out to check the effectiveness of different reducing agents in the reduction of hexavalent chromium to trivalent chromium. In each experiment, a test tube was filled halfway with a 1.0% by weight solution (10,000 ppm) of ^2(^20,., • 2K^ 0. A small amount of reducing agent was added to this solution. If the solution changed color from orange (Cr<+>^1) to green (Cr<+>^) within 30 minutes, the material was considered an effective reducing agent. Effective sulfur-containing reducing agents included sodium sulfide, sodium hydrosulfite, sodium metabisulfite, potassium sulfite, sodium bisulfite, potassium metabisulfite, sodium sulfite, sodium thiosulfate ( with small amounts of heat), ferrous sulfate and thioacetamide plus sulfuric acid. Effective non-sulfur reducing agents included: Hydroquinone, ferric chloride, sodium nitrite, p-hydrazinebenzoic acid, hydrazine phosphite, and hydrazine dihydrochloride.

Example V

A selected few of the effective reducing agents determined in Example IV were used together with Na2Cr20^• 2H20 for gelation of

CMC solutions in a series of experiments. In each experiment, 1.6 g of high-viscosity CMC-9 was added to 280 ml of distilled water to give a solution containing 0.57 weight percent or 5700 ppm CMC. To each solution was then added 0.5 g of the reducing agent and 0.5 g of Na 2 Cr 2 O 2 H 2 O in 10% by weight solutions in the order mentioned and with stirring. The solutions were then examined visually for gel formation. The results of the trials were as follows:

The result of other similar trials gave positive results, i.e. gel formation, when hydroquinone was used as a reducing agent for Na2Cr20?-2H20.

Example VI

Two sample solutions containing 0.357 weight percent (3570 ppm) high viscosity CMC-9 in distilled water were prepared. Sample No. 1 was prepared using 0.32 g of Na2S2Oi( and 0.32 g of Na2Cr2O^ • 2H2O, both dissolved in distilled water. The total volume of the sample solution thus prepared was 280 ml. Sample No. 2 was prepared under use of 0.68 g CrCl^ dissolved in distilled water The total

volume of the thus prepared sample solution was 280 ml. The gel obtained in sample No. 1 using Cr<+>^ was still a stable gel after 7 days. The gel formed from sample #2 using Cr was unstable and underwent syneresis within 10 minutes of mixing.

Example VII

Potassium permanganate and calcium permanganate were each used together with sodium hydrosulfite to gel a solution containing 0.357 weight percent (3570 ppm) high viscosity CMC-9 in saline containing 1200 ppm dissolved solids. To a 250 ml sample of the aforementioned CMC solution was added 0.357 g of KMnO^ (3.75 ml of a 10% by weight solution in distilled water) and 0.375 g of Na^,^

(3.75 ml of a 10% by weight solution) with stirring after each addition. The resulting gel had properties similar to those gels prepared from similar CMC solutions using substantially equivalent amounts of Na^rgO^• 2H 2 O and Na^gO^ . Another

gel was prepared in the same way using NaMnO 2 . The resulting gel had similar properties to the gel prepared using KMnO 4 .

Example VIII

A dry mixture of 1 part by weight of high viscosity CMC-9, 0.28 parts by weight of Na 2 Cr 2 O 7 -2 H 2 O and 0.28 parts by weight of Na 2 Cl 2 was prepared. To this dry mixture was added a sufficient amount of an oil field brine containing approx. 850 ppm dissolved solids, to form a solution containing 1000 ppm CMC (0.1% by weight], and stirred for 10 minutes with a high-speed mixer. The resulting aqueous gel had an apparent viscosity of 4.5 cP about 15 minutes after mixing. About 6 hours later, the apparent viscosity was 7.5 cP. About 24 hours after mixing, the apparent viscosity of a stored sample was 9.0 cP. These apparent viscosities were measured on a Fann VG apparatus (300 rpm ./min.

A solution of said high viscosity CMC-9 which contained

1000 ppm ungelled CMC (0.1% by weight) was also prepared using the same oil field brine. Another substantially equal solution of the same CMC had an apparent viscosity of 4.0 cP (Fann VG apparatus 300 rpm).

A linear displacement (sand fill) model was constructed as follows: A 1.8 m long steel pipe with an internal diameter of 19 mm was filled with Mill Creek sand. The filled tube was then evacuated to remove air. The evacuated tube was then flushed with CO 2 gas to remove any remaining air. The pipe was then evacuated again. The tube was then filled with water from the bottom to remove all traces of gas from it. The column was then filled from the top with an oil having a viscosity of 210 cP at 24°C to obtain a condition of saturation of oil and residual, associated (connate) water. The column was then backfilled with the above described oil field brine from the top for a sufficient time to give a water/oil ratio at the outlet in excess of 100:1 so as to ensure that all mobile oil had been removed. The column was then considered saturated with residual oil (residual 011 saturated).

The linear displacement model produced in this way had

a pore volume of 195 ml, a porosity of 42.8$ and a residual oil saturation (Sor) of 0.298. The column was mounted in a vertical position and supplied

with pressure outlet at the following distances from the top: 0 cm, 30 cm, 91 cm,

1.5 m and 1.8 m. The water drainage test was then carried out as described

below, with all liquids being pumped into the top of the column. As the column was flooded in this way in a downward direction, no separation or fluidization effect of the sand layer took place as a result of the lifting effect from the introduced liquids.

When carrying out water discharge tests with the column described above, different liquids were pumped into the column at constant rates and pressure measurements taken at the selected pressure outlets along the column.

The values obtained in this way were used to calculate mobility values using Darcy's linear flow equation. This equation can be written as follows:

where the factor represents the mobility in mD divided by the viscosity of the liquid v , Q is the flow rate in cm 3/s, L is the length of the column in cm, A is the cross-sectional area of the column in cm 2 and AP is the pressure difference in atmospheres. Since L and A are constant for a particular model,

the mobility can be easily calculated from —When using the numbers, mobility values can optionally be plotted as ordinate as a function of cumulative injected volume as abscissa.

In this example, mobility tests were performed by first

a total of 600 ml of the aforementioned oil field brine was introduced at a uniform speed, so that the speed through the column was 30 m per day. Then a total of 250 ml of the above-described ungelled CMC solution containing 1,000 ppm (0.1 weight percent) CMC was introduced at the same rate. This was followed by injection of a further 1,600 ml of the saline at the same rate. Next, 200 ml of the above-described gelled CMC solution containing 1000 ppm (0.1% by weight) CMC was introduced at the same rate. This was followed by 2,350 ml of the brine at the same rate. During the introduction of all these liquids, pressure measurements were taken at the inlet to the column, at a location 30 cm below the inlet, at a location 91 cm below the inlet, and at the outlet from the column. The mobility values — for each fluid were calculated from the injection rate and pressure measurements as described above. The results for the entire column length are given in Table III,

and the results for the other part of the column, i.e. the section between the points which were respectively 30 cm and 91 cm below the inlet to the column is indicated in table IV.

As shown in Table III, the mobility of the brine, in the column was initially 4200 mD/cP. The mobility of the ungelled CMC solution at the end of its injection was 1250 mD/cP. The mobility of the second saline injection increased from 2300 initially to 3500 at the end, indicating that the saline washed out the previously injected ungelled CMC and that this was largely ineffective in reducing the permeability of the column and/or reduce the mobility of the salt water. The mobility of the gelled CMC solution decreased from 7^0 mD/cP at the beginning to 35 mD/cP at the end, showing that the gelled CMC solution could be used to mainly block or plug the column if it were to be desirable. The mobility of the last batch of injected saline increased from 130 mD/cP initially (the first 100 ml), to a stabilized value of the order of 425 mD/cP, showing that the gelled CMC solution had effectively reduced the permeability of the column and/or the mobility of the salt water. From this example, it is clear that the gelled CMC solution can be used to selectively reduce the permeability of the more porous sections of a formation and thus lead filling or displacement water (flood water) to the less porous parts of a formation. This is possible because the gelled CMC solution will preferentially penetrate into the more porous parts of the formation.

Similar conclusions can be drawn from Table IV. The special feature of the figures in Table IV is that they show that the second batch of saline injected after the ungelled CMC solution completely removed this solution, the mobility of the second batch of saline being somewhat greater than the original mobility of the first salt water rate. The figures show that there was no residual action in the column of the ungelled CMC solution.

Example IX

An aqueous gel according to the invention was prepared from a solution originally containing 100 ppm CMC (0.01 weight percent). The gel was prepared by adding 10 g of CMC to 1 liter of tap water in Bartlesville, USA. Sufficient sodium hydrosulphite was then added to this solution with stirring to give 0.2 g/l.

To the resulting mixture was then added, with stirring, sufficient sodium dichloronate to give 0.15 g/l. Thus, the resulting gel should be a 10,000 ppm CMC gel (0.1% by weight CMC). This gel was then diluted with sufficient water to give a 100 ppm CMC gel (0.01 wt% CMC).

This 100 ppm CMC gel was then used to perform water drainage tests in a linear displacement model (sandfilling) prepared essentially as described above in Example VIII. The linear displacement model used had a pore volume of

194 ml, a porosity of 42.6$ and a residual oil saturation (Sor) of 0.088.

Mobility tests were then carried out by first leading

put in a total of 2,600 ml of the aforementioned oil field brine in such a quantity that the speed through the column was approx. 38 m per day. Subsequently, a total of 4,800 ml of the aforementioned 100 ppm CMC gel was introduced at the same addition rate. This was followed by 1,500 ml of the aforementioned oil field brine at the same rate. During the introduction of all these liquids, pressure readings were taken at the inlet to the column and at a point 30 cm from the inlet to measure the pressure difference across this 30 cm section of the column. The mobility of each liquid was calculated from the aforementioned injection rate and pressure readings as described above in Example VIII. The results are shown in Table V.

The figures in Table V show that the original mobility of the salt water in the column was 5,800 mD/cP. During the injection of the gelled CMC solution, its mobility decreased from 5,800 to 50 mD/cP, and at this time the mobility had stabilized, indicating that the permeability of the column had stabilized or become substantially constant. After approx. 4800 ml of the gelled CMC solution had been injected, the injection of the solution was stopped and the injection of the saline resumed. The figures show that the mobility of the salt water in the treated and filled column was stabilized at 40 mD/cP. The residual resistance factor was 145. This residual resistance factor shows that the sandfill treated with the 100 ppm gel of CMC offered a 145 times greater resistance to the flow of the salt water through the pores of the fill after treatment with the gelled CMC solution. Previous experiments had shown that a 100 ppm solution of ungelled CMC had a viscosity which was about the same as the viscosity of the said 100 ppm CMC gel, and that the ungelled CMC solution gave a residual resistance factor which was usually lower than about 5- This example shows that very diluted aqueous gels of CMC produced according to the invention can be effectively used to reduce the permeability of porous formations

Example X

Another mobility test was conducted using a core of Burbank sandstone from the Burbank Field, Oklahoma, containing residual oil, and an aqueous gel in accordance with the invention containing 500 ppm high viscosity CMC-9• This mobility test was conducted in a similar manner to that used in examples VIII and IX, in that first a batch of the oil field brine was injected, then a batch of the aqueous gel containing 500 ppm CMC and finally a new batch of the brine. The result of the experiment showed that the aqueous gel reduced the mobility of the salt water from 720 mD/cP to 1.7 mD/cP. The resulting residual resistance factor was approx. 430.

Example XI

This example illustrates the applicability of aqueous gels as drilling fluids according to the invention. Three bore fluids were prepared and the viscosities set to essentially the same value at a shear rate of 511 s 1 (300 rpm on a Fann VG apparatus, model 35) - The viscosity behavior of all three fluids could thus be compared at shear rates above and under 511 s<-1>. Each of the liquids was prepared by sprinkling their dry ingredients into 280 ml of distilled water while stirring at low speed on a Hamilton Beach blender. All liquids were then stirred for 10 minutes with a Multimiter. The viscosities were then adjusted by dilution with water to substantially the same viscosity as the lowest viscosity liquid. The finished compositions of the liquids were as follows: A. Dispersed bentonite liquid: 86.6 g/l bentonite, 8.66 g/l ferro-chromium-lignosulphate and 2.2 g/l NaOH in distilled water.

B. High viscosity CMC-g liquid: 3.45 g/l of the mentioned CMC in distilled water. C. Gelled high-viscosity CMC-9 liquid: 2.5 g/l of the said CMC,

0.68 g/l Na2Cr207 • 2H20 and 0.68 g/l Na^C^ in distilled water.

This gel thus contained 0.28% by weight or 2,800 ppm

CMC.

Viscosity values at different shear rates, the pH value and the water loss were then determined for each of the three fluids. The results of these three experiments are given in Table VI.

A graphical plotting of shear stress against shear rate or reading on the Fann device against the device's rpm shows that the drilling fluids A and B are pseudoplastic, i.e. that the curve passes through the origin at a shear rate or rpm of 0, while the gelled CMC liquid behaves like a Bingham's plastic fluid at low shear rates and has a true yield strength of approx. 9 (intersection with the Y-axis when the shear stress or reading on the Fann apparatus is deposited along the Y-axis).

The gelled CMC drilling fluid (C) had a lower viscosity at the higher shear rate (600 rpm) than the bentonite drilling fluid and a higher viscosity than both the other two fluids A and B at lower shear rates (100, 6 and 3 rpm my). This property will facilitate the penetration of the drill cutting and still allow excellent suspension of solids in the ring for cleaning the borehole. The penetration rate is usually considered to be an inverse function of the apparent viscosity at high shear conditions. The gelled CMC drilling fluids according to the invention will therefore allow higher drilling speeds than those in normal bentonite drilling fluids. The gelled CMC drilling fluid provides a controlled water loss (35 ml in 30 minutes) while the ungelled CMC drilling fluid had a water loss of 165 ml in 30 minutes. This last value is classified as "no control" in the drilling fluid field. The results obtained with the gelled CMC drilling fluid were surprising, as the fluid (1) behaves as a pseudoplastic fluid at moderate to high shear rates, (2) behaves like a Bingham's plastic fluid at low shear rates and (3) provides water loss control.

The gels according to the invention are also applicable for hydraulic fracturing.

Hydraulic fracturing of underground formations penetrated by a borehole has been used to a large extent to increase the recovery of hydrocarbon fluids, e.g. crude oil and natural gas, from the formations. Hydraulic fracturing involves injecting a fracturing fluid into a well that penetrates the formation, and into it under sufficient pressure to overcome the pressure exerted by the overlying soil layers. This means that a fracture is formed in the formation, which facilitates the flow of hydrocarbons through the formation to the well.

Desirable properties of a hydraulic fracturing fluid are

high viscosity, low fluid losses, low friction losses during pumping into the well, stability under the conditions of use such as e.g. in deep wells with high temperature, and easy removal from the fracture and the well after the operation has been carried out. It would be desirable to have a fracturing fluid that has all these properties.

Higher viscosities of the fracturing fluid help to provide wider fractures. This is particularly advantageous when a viscous solution is used as a "cushion" that precedes the acid in combined digestion

and pickling operations. More viscous solutions also contribute to

introduce propping agents into the formation when such agents are used. The usual thickeners that have been used in the past, e.g. natural gums (guar gum etc.) and starches, require exceptionally large quantities to achieve significant increases in viscosity. Furthermore, solutions of such gums and starches are not viscosity stable at the higher temperatures encountered in

deep wells, e.g. temperatures above 93°C.

The fluid loss properties of the fracturing fluid must be sufficiently low to allow the build-up and maintenance of the pressure necessary to fracture the formation. Otherwise, low penetration and/or ineffective breakdown will be achieved. Different means of controlling the fluid loss have been proposed in the past for use together with different fracturing fluids. However, the use of such agents is at best an undesirable complicating factor in the production and use of fracturing fluids. It would be better to have a breakup fluid that does not require the use of a fluid loss control agent.

Low friction loss is desirable to avoid unreasonably high wellhead pressures when pumping the fracturing fluid through the casings and pipes and into the formation. Otherwise, the friction losses can become insurmountable.

Stability under the conditions of use, i.e. maintaining sufficient viscosity at temperatures of the order of 93°C and higher for a period of time sufficient to carry out the fracturing operation is particularly important when breaking up formations penetrated by deep, high-temperature wells. Fracturing fluids produced from many of the previously known thickening materials have at temperatures of 93°C and higher not much higher viscosity than water.

A disadvantage of using many highly viscous solutions is that they are difficult to remove from the pores or fracture cracks after the operation has been performed. Other highly viscous solutions sometimes leave clogging residues in the pores of the formation. This prevents recovery and often requires expensive cleaning operations after the breaking up operation has been carried out. It would be desirable to have a thickened solution which will break down to a lower viscosity in a short time after the break-up operation has been carried out.

The present invention provides aqueous gels having all of the desirable properties described above. These aqueous gels can thus be injected into the well and then into the porous formation using common pumping equipment and common methods.

The amount of fracturing fluid injected into the formation is usually the same as that used by other fracturing fluids known in the art. The amount of fracturing fluid can thus be from 12 liters to 24,000 liters per vertical meters of the formation.

Another application involves a combined decomposition and acidification treatment. Such a treatment is particularly useful when the formation is prone to attack by the acid. In this combined method, the aqueous gels of cellulose ether solutions are used as fracture "pads" and injected prior to the injection of the acid with sufficient pressure to create a fracture. The acid is then injected to react with and etch the fracture surfaces and roughen them to provide good conductivity when the operation is complete.

The aqueous gels are particularly suitable as a break-up cushion in combined break-up and acidification treatments. They reduce the apparent acid reaction rate by reducing the contact speed. These aqueous gels made from cellulose ethers are superior to other aqueous gels for wetting and bonding to oil-covered sand. Thus, when the aqueous gel pad is displaced by the acid, a thin film will remain long enough to slow down the acid reaction rate sufficiently for greater penetration to be achieved. The acid will quickly destroy the gel film and perform its intended effect of etching and roughening the fracture surfaces, but not before its action has been sufficiently delayed that a larger quantity of unused acid is allowed to penetrate further into the fracture.

Another valuable property of the viscous aqueous gels

according to the invention is that they increase the width and length of the fracture.

This gives a larger fracture surface on which the acid can work, which means that the fracture will have greater conductivity. The width of the fracture is i

large extent depending on the viscosity of the fracturing fluid.

The aqueous gels used according to the invention have superior viscosity properties at high temperature compared to commercially available gels. These superior viscosity properties result in better breaking. Yet another advantage of the better viscosity properties is that the gels will carry with them more and larger repellants in the applications where such agents are used.

Yet another advantage of the aforementioned aqueous gels is that they serve to cool the well pipes during the injection, whereby the limitation of corrosion inhibitors used in the acid is overcome.

Repelling agents (propping agents) which can be used in carrying out the invention include all those known in the art, e.g. grains of sand, pieces of walnut shell, tempered glass beads, aluminum pellets and similar materials. Repellents are not usually used in the combined breaking-up and • acidification treatments. However, repellents can also be used in such combined treatments. When repellents are used in this way, they should be made from materials that are not seriously attacked by the acid used.

Usable acids include all which have the effect of increasing the flow of hydrocarbons through the formation to the well. Examples of acids that can be used include inorganic acids

such as hydrochloric, nitric and sulfuric acids, organic acids such as acetic and formic acids and combinations of inorganic and organic acids. The concentration or strength of the acid may vary depending on the nature of the acid, the nature of the formation being treated, and the results desired in the particular treatment operation. When e.g. hydrochloric acid solution is used in a formation that mainly consists of limestone, the concentration can vary from approx. 5 to approx. 38 weight percent HC1, and concentrations in the range of 10 to 30 weight percent are usually preferred. Organic acids are usually used in lower concentrations, e.g. about. 10 percent by weight. A preferred mixture of inorganic and organic acid includes mixtures of hydrochloric acid and acetic acid. An example of such a mixture is a 15% hydrochloric acid solution which contains sufficient acetic acid to bring the total acidity up to a value corresponding to 20 - 22% HCl. The acids used may contain which

preferably of the known corrosion-inhibiting agents, re-emulsifying agents, exfoliating agents, surface-active agents, friction-reducing agents, etc. which are known in the art. The amount of acid used in a particular case will depend on a number of factors, including the size and quantity of the formation to be treated, the nature of the formation, the nature and concentration of acid and the formation temperature. Any suitable amount from approx. 12 liters to 9,300 liters per vertical meters of the formation can be used.

The breaking operation can be carried out in one or more stages. One stage may include the following steps: If desired, and depending on the well conditions, before the aqueous gel, a small amount of a cleaning acid may be injected to remove flakes, wax deposits, etc. and clean the perforations. This injection of a cleaning acid can be followed by a pre-rinse with water to cool the liners and the formation. The aqueous gel is then injected. Usually the acid injection follows the injection of the aqueous gel. The acid addition is then followed by a water flush to displace the acid. The second stage and possibly further stages may comprise the same steps carried out in the same order.

However, it will be understood that other combinations can be used. The only crucial step is the injection of the aqueous gel under sufficient pressure to form the fracture. Before the injection of the aqueous gel, any suitable pre-rinse-injection steps etc. can be carried out, and after the injection of the aqueous gel any suitable subsequent rinsing or other purification steps can be carried out. In the same way, with the combined breaking-up and acidification process, it is only essential that an injection of the aqueous gel and a subsequent injection of the acid take place. In general, in the aforementioned combined treatment, it is preferred to inject the acid immediately after the injection of. that of an aqueous gel consisting of breaking fluid. However, it is also possible to inject a batch of water or other spacer liquid between the batch of aqueous gel and the batch of acid.

Example XII

The purpose of this example is to show that gels of CMC solutions have high viscosities at relatively high temperatures. A solution was prepared by mixing 2.4 g of CMC-9 in 500 cm"5 of tap water in Bartlesville, Oklahoma, USA, to form a solution of 4,800 ppm (parts by weight). To this solution was added 7 .5 cm-5 of a 10% by weight solution of sodium dichromate (Na2Cr207•2H20) followed by gentle stirring (the solutions were at room temperature, 24°C). After the addition of the sodium dichromate, the solution was placed in a water bath and the temperature raised to 54°C in over a period of 5-10 minutes. When the temperature had reached 54°C, 23.5 cm^ of a 20% by weight solution of sodium thiosulfate (Na2S20^•5H20), which is a reducing agent, was added to initiate gelation, followed by of stirring by hand for 60 seconds. A portion was then poured into a stainless steel cup in a high-pressure, high-temperature Fann Model 50 Viscometer apparatus so that the rate of gelation with temperature and time could be monitored. The concentration of the final ingredients under consideration of dilution ng as a result of the addition of the last two chemicals was as follows:

The degree of gelation as expressed by increased viscosity was measured as the finished mixture was heated by the oil bath surrounding the bowl of a standard Fann Viscometer apparatus of model 50. The figures in Table VII show that the viscosity increased from 18.5 cP at a shear rate of 500 s""1" after the addition of the last component to a peak viscosity of 115 cP at a temperature of 114°C and then slowly decreased as the temperature was raised to 151°C. The degree of heating was an approximate simulation of the heating that occurs in a hydraulically generated fracture during fracturing and acidizing treatments of deep Ellenburger gas wells in the Gomez field in Pecos County, Texas.The example illustrates a method of producing

of viscous gels which are useful as fracturing fluids.

Example XIII

The purpose of this example is to show that gels of CMC solutions will form while the mixture is pumped or circulated in a turbulent flow, and will have friction loss properties that are useful when calculating the pressure drops that will be achieved in tubular equipment during refractive treatments where the gels are used.

A quantity of CMC-9 was added via an eductor to tap water

in Duncan, Oklahoma, USA, in a 950 liter Halliburton ribbon mixer.

The final CMC concentration was 4.8 g/l or 4800 ppm. The solution was kept at a constant temperature of 54°C throughout the preparation. When the CMC solution was fully hydrated, as indicated by a reading of 300 rpm on a Model 35 Fann VG apparatus, sodium dichromate (NagC^O^ • 2H 2 O) was added to the CMC solution in an amount sufficient to to achieve a concentration of 1.44 g/l or 1,440 ppm CMC. The sodium dichromate was easily soluble and dissolved in less than 5 minutes in the ribbon mixer tank. This solution was used as a base solution in the experiments described below.

(a) Friction loss tests were carried out on a portion of the aforementioned base solution by circulating it in a turbulent flow under controlled conditions with regard to temperature and speed through

a pipe loop with a diameter of 2.5 cm and a sample section with a length of 12 m. Pressure drop readings were taken during circulation. The data obtained was used to calculate the friction loss that can be expected when pumping the base solution down a well under the following conditions: Well depth 6,880 m, casing 5,200 m of a 14 cm steel casing at 34 kg/m and 1,680 m of a 13 cm steel casing of 34.7 kg/m, surface injection temperature 54°C, formation temperature 177°C on

6,880 m and pump speeds of 4,000 - 4,800 l/min. The calculated data are shown in table VIII. (b) Friction loss tests and measurements of the degree of gelation were carried out on another part of the base solution where the gelation was carried out while the base solution was circulated as indicated above under (a). Gelation was accomplished by adding sufficient sodium thiosulfate, Na2S2°3' 5H2O> ^ o<pp>using) to provide 1440 ppm (parts by weight) of the thiosulfate in the circulating solution. Pressure drop readings were taken during circulation. The figures showed that gelation was delayed for approx. 370 seconds before the gelled solution exhibited some gelling properties which could increase the frictional losses above those in an ungelled system. It was determined that this system could rightly be called a delayed gelling system, as no significant gelation took place for approx. 6 minutes. The friction losses for the well conditions stated under (a) above were calculated from the data obtained. The calculated data are shown in table VIII. (c) Friction loss tests and measurements of the degree of gelation were carried out on yet another portion of the base solution, as described under (b) above, except that the gelation was carried out by the addition of sufficient sodium hydrosulphite, NagSgO 2 , (in solution) to provide 1 440 ppm in the circulating solution. Pressure drop readings were taken during circulation. The figures showed that gelation began within 60 seconds of the addition of the sodium hydrosulphite. This system cannot be called a delayed system at the temperature (approx. 54°C) at which the experiment was carried out. The friction loss for the well conditions described above was calculated from the data obtained. (d) Friction loss tests were also performed on tap water in Duncan, Oklahoma, USA, circulating as described under (a) above. The friction losses for the well conditions specified under (a) above

for, was calculated from the obtained data. These calculated data are also given in Table VIII.

The figures in Table VIII show that solutions of CMC are friction-reducing agents compared to pure water. Gelled solutions of CMC that gel during pumping are also friction-reducing agents compared to water, as they can be pumped at high speeds down through the well in a well with less power consumption than is required for pumping water. Gelation of the CMC solution during pumping is currently preferred as it provides another means of controlling the degree of gelation.

Calculated values for comparable solutions of CMC which

is "fully gelled" before pumping, 207 and 250 atmospheres are total pressure drops at pumping rates of 4,000 and 4,800 l/min respectively in the 6,880 m pipe string described above. This shows the advantages of gelation during pumping.

The above-mentioned example also illustrates a currently preferred method for performing a breaking operation. This method comprises preparing a base-breaking liquid comprising a solution of a cellulose ether, adding to this base solution (a) a metal compound of a polyvalent metal, e.g. sodium dichromate, or (b) a reducing agent such as sodium thiosulphate or sodium hydrosulfite, pumping a batch of this base fracturing fluid down the well and into the formation under sufficient pressure to obtain the fracture and, during pumping, adding to the base fracturing fluid that of the constituents (a) and (b) which have not been added in advance. It is also possible to incorporate all these components of an aqueous gel into a stream of water while this is being pumped, e.g. down a well. CMC can e.g. first the running water is added, after which the other ingredients may be added in..any suitable order. The turbulent flow conditions in the pipe will provide proper mixing.

Example XIV

This example illustrates the degradation of gelled solutions of CMC when exposed to elevated temperatures. Gelled solutions

of sodium carboxymethyl cellulose (CMC-7 and CMC-9) were prepared so that they contained approx. 5,000 ppm CMC, approx. 1,500 ppm Na^O^ and approx.

1,500 ppm Na2Cr2O7•2H2O. The. gelled solutions were prepared by first dispersing CMC in water, after which solutions of Na2S20^ and ^a2^r2°7 t)"Le were added with stirring. Samples of the gelled solutions were then subjected to elevated temperatures of the order of 150 and 175°C for varying periods of time in an Amoco cement consistency meter at pressures of approximately 1,000 - 1,300 atmospheres. The viscosity was then determined on a Model 35 Fann VG apparatus after the samples had cooled. From these viscosity measurements, it was determined that the gelled solutions were self-degrading at elevated temperatures, and that the degradation time decreased with increasing temperature. The viscosity determinations showed, for example, that the degradation time of the gelled solutions of CMC

investigated in this example ranged from 8 to 12 hours at 150°C and 2 to 3 hours at 175°C. These data show that the gelled solutions of CMC can be used as fracturing fluids in high temperature formations, and that the gels will break down after a relatively short time to allow easy cleaning of the well.

Example XV

There are a number of methods by which gelled solutions of CMC can degrade over time so that their final viscosity will be approximately the same as that of ungelled CMC solutions or water. One method consists in using excessive amounts of gelling agents which will provide sufficient viscosity and the required gel strength during the break-up treatment, but which will then cause breakdown into a thin solution that allows rapid cleaning of a well after a break-up treatment. Table IX sets forth the results for three gelled solutions of CMC-9 prepared in substantially the same manner but gelled with different amounts of gelling agents. Solution #3 gelled the fastest and also degraded the fastest due to an excessive amount of gelling agent. Solution No. 1, which was gelled with about 1/6 of the amount of gelling agent used in Solution 3, required about 18 minutes to reach the maximum viscosity before it started to break down. Considerably less gelling agent is required for gelling solutions of CMC prepared with strong salt solutions than is required for gelling solutions prepared with fresh water. As the salt content of the water increases, the gelation rate of the CMC solutions also increases. The "lifetime" of gelled solutions of CMC can be regulated by adjusting the amount of gelling agent in accordance with the existing water and temperature conditions.

The gelled solutions used to obtain the data in Table IX were prepared as follows: To 1 liter of actual prepared salt solution from the North Burbank Unit in Burbank, Oklahoma, (total dissolved solids about 90,000 ppm) was added 5 g CMC-9 to form a 5,000 ppm solution. The solution was stirred for 5 minutes on a malt mixer and allowed to stand for 30 minutes to achieve a maximum viscosity of 21.6 cP at a shear rate of 170 s ^ measured on a Fann VG apparatus of model 35 at a temperature of 21 °C. The one liter solution was then divided into three equal portions, designated as solution 1, solution 2 and solution 33 and placed in bowls on Fann Viscometer apparatus. The solutions were stirred continuously at 100 rpm, which corresponds to a shear rate of 170 s 1. Each of

the solutions were gelled by adding first sodium dichromate and then sodium hydrosulphite, so that the final solutions had the following compositions:

Example XVI

Various and excessive amounts of gelling agents were used to prepare gelled solutions of CMC-9 using relatively fresh water (total dissolved solids 1100 ppm). A base CMC solution was prepared by mixing 3>57 g of CMC i

1 liter of this water at room temperature in a multimixer. The concentration of CMC was approximately 3,570 ppm. The resulting solution

was divided into three equal volume parts. Two portions were gelled using two different reducing agents and sodium dichromate, and the other portion was used for base viscosity comparison. Table X shows that high viscosities were developed in less than 5 hours for the two gelled solutions and that the gels eventually degraded to lower viscosities within 7 days.

The figures in the above-mentioned examples XII-XVI show that the gelation speed of solutions of CMC and/or the lifetime of the resulting gel can be "tailored" in accordance with the conditions existing in the field. This can be done by taking into account the temperature of the formation where the gel is to be used, the quantity of the gelling agents used to produce the gels, and the water used in the production. A gel can thus be adapted so that it will have a lifetime of 12, 8, 4 or even 2 hours or less, so that the gel will break down to a viscosity that approaches the viscosity of water within the selected time period. This allows easy cleaning of the well after the break-up treatment and easy removal of the gel residues, e.g. when extracting formation fluids. Gels can be produced that will break down to viscosities of less than approx. 20 cP or even to the viscosity of water if proper consideration is given to the above factors.

Example XVII

Four fracturing fluids were tested for their viscosity characteristics at high temperature. These liquids were: (1) A gelled solution of CMC-9 with a concentration of 4,800 ppm, (2) a gelled solution of CMC-9 with a concentration of 3,600 ppm, (3) a gelled solution of guar gum (commercially available) at a concentration of 9,600 ppm and (4) an ungelled solution of a commercially available modified guar gum. Liquid No. 1 was prepared by dry mixing predetermined portions of CMC-9 and Na2Cr207•2H20. The resulting mixture was then added to 5 liters of Duncan, Oklahoma, USA tap water with stirring on a Waring mixer at low speed for 20 minutes. The resulting solution contained 4,800 ppm (parts by weight) of CMC and

1,440 ppm Na2Cr2O7•2H2O. The solution was then transferred to an apparatus for measuring the friction loss. This apparatus comprised a pipe loop with a diameter of 6 mm and provided with heating means and

circulators for measuring the friction losses during simulated pump operations. The solution was heated from room temperature to 54°C during circulation. A sufficient amount of Na^^O^ to

giving 1440 ppm (calculated on the above 5 liter solution of CMC and Na2Cr207•2H20) was dissolved in 150 ml of water and added to the circulating solution. Gelation started in less than 1 minute. Circulation continued for approx. 30 minutes and then finished. The gelled solution was allowed to solidify overnight and cool to room temperature. The following day, the viscosity of the gel was determined in the range from 21 to 150°C using a writing high temperature high pressure Fann Viscometer apparatus model 50 at a pressure of 38 atmospheres. During these viscosity measurements, the temperature was increased from 21°C to 150°C within 20 minutes.

Liquid No. 2 was prepared and tested in substantially the same manner as described above for Liquid No. 1, except that Liquid No. 2 contained 3,600 ppm CMC-9, 1,080 ppm Na 2 Cr 2 O 7•2H 2 O, and 1,080 ppm Na 2 S 2 O^. During the viscosity measurements, the temperature was increased from 21°C to 143°C in 17 minutes.

Liquid No. 3, which was the commercially available gelled solution of guar gum (the exact composition is unknown), was prepared at a concentration of 9,600 ppm in tap water in Duncan, Oklahoma, USA, under -division of the usual gelling agent (also unknown). The solution was stirred for 1 minute in a mixer. The solution gelled immediately at room temperature upon addition of the gelling agent. This gel is commercially available as a break-up liquid. Viscosity measurements were performed on the gel in the same manner as described above. During the viscosity measurements, the temperature was increased from 21°C to 150°C in 16 minutes.

Liquid No. 4 was prepared by mixing a portion of the modified guar gum with a sufficient amount of tap water in Duncan, Oklahoma, USA, to give a guar gum concentration of

3,600 ppm. The mixture was stirred for 1 minute on a malt mixer. This fluid is commercially available as a break-up fluid. Viscosity measurements were performed on this liquid in the same manner as described above. During the viscosity measurements, the temperature was increased from 24°C to 100°C in 17.5 minutes. To facilitate comparison, the viscosity in cP at a shear rate of 511 s"<1> was plotted as a function of temperature in °C for each of the four fluids. A smooth curve was obtained for each fluid.

Table XI contains a direct comparison between the viscosities of the aforementioned four liquids at temperatures in steps of approx. 14°C.

The figures in Table XI clearly show the superior viscosity characteristics of liquids (1) and (2) at high temperatures.

Example XVIII

Fluid loss values at high temperatures were determined on a gelled solution of CMC-9 containing 5,000 ppm CMC and gelled by the addition of 1,500 ppm NaCrgO 2 H 2 O and 1,500 ppm Na 2 S 2 O 2 . These fluid loss values were obtained using a No. 387 Baroid filter press using three No. 988 Baroid paper filters and according to the procedure described in API RP 13B, Third Edition, February 1971. Burst loss values were obtained by plotting the fluid loss as function of the square root of time. The burst loss is the value of the intersection of this plot and the line at time 0. The results of the test are given in Table XII. The m-values given in the table are the slope of the plotted line.

The figures in Table XII show that gelled solutions of CMC have good fluid loss properties at high temperatures.

Another problem that often occurs with fluid extrusion methods is the more or less direct channeling of relatively large amounts of the extrusion fluid from the injection well to the production well or wells as a result of the presence of natural or artificially created fractures in the formation.

The problem of channeling fluids through fractures in the formations is not limited to secondary extraction operations. In certain cases, fractures that are connected to water-bearing layers that border a hydrocarbon-bearing formation, and are also connected to this formation, will result in unreasonably large amounts of water or salt water being extracted together with the hydrocarbon. Various modifications of this problem are sometimes referred to as "coning".

The use of the gel according to the present invention provides a solution to these and other related problems. Thus, the gels can be used for plugging fractures in formations, where aqueous gels produced by gelling solutions of cellulose ethers as described above are placed in the fractures.

When carrying out this plugging operation, the aqueous gels can be injected into the formation using conventional pumping equipment.

When the aqueous gels used in this method are injected into a well in an underground formation, it is desirable that a batch of gel is followed by a batch of flushing liquid such as e.g. water or oil, e.g. crude oil, to flush the well firing. This rate of water or oil should at least be sufficient to clean the perforations. Otherwise, the liner and perforations will be blocked when the gel hardens into a solid gel. Water can be used for the flushing operation if the injection well is an injection well for a secondary extraction process. Oil will be used as flushing fluid if the well is a production well.

After the gel is placed in the formation and the liner and perforations cleaned, it is preferred to close the well and keep the gel still for a time sufficient to allow the gel to develop sufficient gel strength to remain in place. The well will thus e.g. preferably shut down for a period of 8-48 hours before the injection of the usual extraction fluid resumes or the extraction of hydrocarbons resumes if the well is a production well. Confinement periods outside this range can be used if desired, depending on the particular gel used, the nature of the formation and the extent of the fracture system in the formation.

In some cases and depending on the nature of the formation and the fracture system in it, a deeply placed plug can be used, i.e. a plug of gel that is placed approximately 8-30 meters out into the formation from the injection well. In certain cases, the subsequent flushing with water or other liquid will thus be sufficient not only to clean the perforations, but also to displace the amount of gel the previously determined, desired part out into the formation. This is particularly useful when there is a more or less well-defined fracture system that exists in a relatively small part of the formation.

The amount of the aqueous gel used will depend on the type of formation being treated, the degree or volume of the fracture system in this and the part of the fracture system that it is desired to block. The grade or volume of a fracture system in a particular formation can be determined by methods known in the art. E.g. a batch of water of known size, if containing a fluidizing dye, can be injected, followed by continuous injection of water until the color appears at the affected production well. The quantity of the subsequent water that is injected in this way constitutes an estimate for the volume of the fracture system that connects the injection well with the production well. Radioactive tracers can be used in a similar way.

The aqueous gels may be injected at any suitable rate and pressure. Usually, the injection rate will lie in the range from 16 to 8,000 l/min, preferably 160 to 1,600 l/min. If desired, the injection pressure may be sufficient to overcome the weight of the overlying soil layers, open the fracture and keep the fracture open and thus facilitate placement of the gel plug. Application of such increased injection pressures will depend on the nature of the formation being treated, and the fracture system therein. If such increased pressures are used, later reduction of the pressure will allow the fracture to close and expose the gel to the pressure from the overlying soil layers in this way helping to keep the gel in place.

Another application of the gels according to the invention comprises a combined acidification and sealing treatment. This application is particularly useful when the formation is susceptible to attack by an acid. In this combined method, before injecting a batch of a sealing gel, a batch of an acid is injected in sufficient quantity to penetrate any desired length into the fracture system depending on the nature of the formation and the volume of the fracture system therein. The acid will react with and etch the fracture surfaces and make these rough. This will provide a clean, rough surface for the gel to adhere to. The batch of acid can be allowed to remain in the fracture system and leach out naturally. If desired, the injected acid batch can possibly be immediately followed by a water rinse to displace the acid. If the acid is allowed to leach out naturally, it is desirable to inject sufficient water to flush the spent or partially spent acid out of the fracturing system before injecting the gelled cellulose ether solution.

The acids and the quantities thereof which are applicable in combined acidizing and sealing operations according to the invention are the same as those previously described.

When no combined acidification and sealing treatment is used as stated above, it will sometimes be desirable that before injecting the gel, a small batch of cleaning acid is injected with the aim of removing flakes, wax deposits etc and cleaning the perforations. This cleaning acid can be any of the acids described above. The cleaning acid will be followed by a water rinse.

Aqueous gels are particularly well suited for sealing fractures in formations. These gels have the unusual property or ability to "wet" and adhere to oil-covered sands or other formation materials.

In this respect, they are much better than other gels, e.g. gelled solutions of polyacrylamides. Gels formed by gelation of water-

solid solutions of cellulose ethers, e.g. CMC, will adhere to the fracture surfaces and remain in place. The aforementioned other gels will slowly be displaced through the fracture, as a film of formation salt solution or oil on the fracture surfaces serves as a lubricant. It is possible to produce stiffer gels from cellulose ethers, e.g. CMC, than from other materials, e.g. linear polyacrylamides. This is another, highly desirable property for materials that are supposed to plug or seal fractures.

If desired, filler materials such as silica flour, diatomaceous earth, ground nut shells, finely divided natural sand, etc. can be incorporated into the aqueous gels used in sealing operations as indicated above.

Example XIX

1 liter of CMC-9 solution was prepared by mixing 3 g of CMC-9 i

1 liter of artificial oil field brine (total dissolved solids 1,491 ppm) on a magnetic stir bar to form a 3,000 ppm solution of CMC-9. The CMC-9 solution was gelled by the addition of 1.5 g/l Na2S20i| with stirring by hand and 1.5 g/l NagCr^• 2H 2 O followed by stirring at room temperature. The solution was allowed to stand overnight and gel to a semi-solid state. The gel was then placed in a glass container inside a pressure-tight steel bomb, and the bomb was placed in an oven set at a constant temperature of 88°C. No attempt was made to remove or exclude atmospheric oxygen in the processing and preparation of the gelled solution of CMC-9•

First 7 days and then 19 days after the sample had been placed in the oven, the bomb was opened and the gel examined visually. On both occasions the gelled solution was still in a soft, semi-rigid state.

60 days after the gel sample had been placed in the oven, it was visually examined again. There were traces of free water, but most of the solution was still in a semi-solid state, which showed that the gelled solution of CMC-9 was thermally very stable. The gelled sample was again visually inspected after heating for 91 days at 88°C. More than 90$

of the water was still in a semi-rigid gelled state. Part of the free water observed in the last two inspections was due to condensation, as each time the bomb was examined it was quickly cooled to room temperature with tap water and then opened. Each opening or inspection period exposed the sample to severe thermal changes and to atmospheric conditions.

These results definitely show that gelled solutions of cellulose ether can be produced, e.g. CMC, which has sufficient stability (gel life) to be used as sealing material for fractures in formations where the formation temperature is not higher than approx. 95 C.

Example XX

Aqueous gels were prepared from CMC-9 and a linear polyacrylamide (PF-1160) to determine the effectiveness of the gels in holding oil and wet sand in suspension. Each of the gels was prepared by adding the below mentioned amounts of polymer to 1 liter of simulated Dakota brine (about 14,000 ppm total dissolved solids). The addition was carried out with stirring, after which the indicated amounts of gelling agents were added to the resulting solutions with stirring.

Both gels were thick and viscous. Due to the higher molecular weight of polyacrylamide, only 2 g of polyacrylamide was required

the amide to give a gel with about the same viscosity as the gel prepared from CMC. To a 200 ml portion of each gel was added 50 g of Dakota sand taken from a well in Converse County, Wyoming, USA. This

sand had been crushed to grain size and covered with a thick coating of storage crude oil. After the sand had been stirred into each of the gels,

these were placed in a sealed bomb and stored in an oven at 88°C.

After 7 days, the bombs were removed from the oven and cooled

room temperature before opening. Visual examination showed that the sand had remained suspended in the gel prepared from the CMC, but had settled to the bottom of the glass container containing the polyacrylamide gel. These results show that the gel prepared from CMC had superior

appropriate wetting and adhesion properties of the oil-covered sand. These results also show that the gel prepared from CMC will be better than the polyacrylamide gel in adhering to oil-moistened surfaces of a fracture and remaining in place in the fracture.

Claims (2)

1. Aqueous gel for use as an aid when drilling in oil-producing formations, the gel being produced by thickening water by adding 0.0025 - 20 percent by weight, calculated on the weight of the water, of a water-soluble cellulose ether and gelling the thickened aqueous solution by addition of 0.05 - 60% by weight, calculated on the weight of the cellulose ether, of a water-soluble compound of a polyvalent metal with more than one polyvalent state, characterized in that the metal compound is a compound of chromium or manganese and is present in an amount of at least 3-10 ^ gram atoms of metal per grams of cellulose ether, and that at least part of the metal is reduced to a lower polyvalent state by the addition of a water-soluble reducing compound. 2. Gel as specified in claim 1, characterized in that it contains 0.01 - 5% by weight of cellulose ether, based on the amount of water, 0.5 - 30% by weight of chromium or manganese compound, based on the amount of cellulose ether, and reducing agent in an amount of .0.1 - 200 percent of the stoichiometric amount necessary for the reduction of manganese or chromium.