DRILLING FLUID FOR HYDROCARBON WELLS AND MANUFACTURING PROCESS THEREOF

Abstract

The invention relates to a drilling fluid resulting from a combination of calcium carbonate, starch, calcium oxide, xanthan gum, and essentially a cationic surfactant, where the cationic surfactant is constituted by the following components: calcium nitrate, diethanolamine (DEA), and glacial acetic acid. Also disclosed is a method for producing the cationic surfactant, a process for obtaining the drilling fluid, as well as a method for measuring the free calcium of the reaction when the fluid is in wellbore operation.

Claims

1. A cationic surfactant composition comprising calcium nitrate, diethanolamine and glacial acetic acid, wherein the cationic surfactant composition is capable of inhibiting precipitation of asphaltenes during a hydrocarbon drilling operation.

2. The surfactant of claim 1, comprising 2 to 5 vol. % of diethanolamine, 0.5 to 2 vol. % acetic acid, and 92 to 97 vol. % of a calcium nitrate solution including 54 to 57 vol. % calcium nitrate.

3. The surfactant of claim 1, consisting essentially of: 1 to 5 vol. % of diethanolamine, 0.5 to 2 vol. % acetic acid, and 92 to 97 vol. % of a calcium nitrate solution including 54 to 57 vol. % calcium nitrate.

4. A method of making a cationic surfactant, the method comprising: (a) preparing calcium nitrate from a reaction between nitric acid in a concentration between 56 wt. % and 66 wt. % and calcium carbonate in a concentration between 96 wt. % and 99 wt. %; (b) adding an alkalizing agent to step (a) to neutralize or adjust the pH; (c) obtaining a calcium nitrate solution in a concentration between 54 vol % and 57 vol %; (d) adding diethanolamine to the calcium nitrate solution; and (e) adding glacial acetic acid to form the cationic surfactant.

5. A drilling fluid comprising the cationic surfactant according to claim 1.

6. The drilling fluid of claim 5, further comprising a viscosifier.

7. The drilling fluid of claim 6, wherein the viscosifier is xanthan gum.

8. The drilling fluid of claim 7, comprising 1.2-1.6 lbm/bbl. (3.42 to 4.56 kg/m) of viscosifier.

9. The drilling fluid of claim 5, further comprising starch as a filtration control agent.

10. The drilling fluid of claim 9, comprising 6 lbm/bbl. (17.1 kg/m) of starch.

11. The drilling fluid of claim 5, comprising an alkalizing agent selected from the group consisting of calcium oxide, lime, magnesium oxide, magnesium peroxide, or mixtures thereof.

12. The drilling fluid of claim 11, wherein the alkalizing agent is calcium oxide.

13. The drilling fluid of claim 12, comprising 0.4 to 1.4 lbm/bbl. (1.14 to 3.99 kg/m.sup.3 of calcium oxide.

14. The drilling fluid of claim 5, further comprising a densifier.

15. The drilling fluid of claim 14, wherein the densifier comprises calcium carbonate, barite, galena, and/or hematite.

16. The drilling fluid of claim 14, comprising 95 to 105 lbm/bbl. (270-299.24 kg/m.sup.3) of calcium carbonate and drilling fluid of 10.0 pounds per gallon, wherein the amount of such densifier is a function of the density required up to 11.2 pounds per gallon.

17. The drilling fluid of claim 5, consisting essentially of: 1 to 5 vol. % of the cationic surfactant of any one of claims 1 to 3; an alkalizing agent; starch; a viscosifier; and an optional densifier.

18. A method to prepare a drilling fluid, comprising the steps of: (a) adding to the preparation tank a volume of water needed to prepare the required volume of the drilling fluid; (b) adding sufficient viscosifier to achieve a viscosifier concentration of 1.2-1.6 lbm/bbl. (3.42 to 4.56 kg/m.sup.3) at a rate sufficient to disperse the viscosifier in the water without gelation; (c) adding 1 to 5 vol. %, preferably 2 vol. % of the cationic surfactant of any one of claims 1 to 3; (d) adding a sufficient amount of calcium oxide to obtain an calcium oxide equivalence of 38-49 lbm (17.2 to 22.2 kg) of calcium oxide per each barrel of fluid of 10 lbs/gal; and (e) adding a sufficient amount of densifier to obtain a densifier concentration of 95 to 105 lbm/bbl. (270.8 to 299.3 kg/m3.

19. A method for controlling the free calcium in a drilling fluid of claim 5 in a wellbore drilling operation comprising the following steps: (a) obtaining an basic solution comprising water, a calcium indicator, and analyte comprising calcium ions; and (b) adding a volume of 0.5 molar (M) ethylenediaminetetraacetic acid (EDTA) to the solution until a visual endpoint is obtained; and (c) determining the parts per million of free calcium in the analyte by multiplying the EDTA volume from step (c) by 2000.

20. The method of claim 19, wherein the analyte is comprised in a drilling fluid obtained from a wellbore.

Description

BRIEF DESCRIPTION OF THE FIGURES

[0036] Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description and upon reference to the accompanying drawings.

[0037] FIG. 1 is a chart showing bentonite swelling (%) vs Time (min) in contact with the drilling fluid of the present invention.

[0038] FIG. 2 is a chart showing dynamic swelling of a sediment sample (%) vs. time (hrs.) in contact with the drilling fluid of the present invention.

[0039] FIG. 3 is a chart showing the results of % v/v and pounds per barrel (lbs./bbl.) vs. Ca.sup.+2 Concentration, corresponding to field tests of the invention.

[0040] While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings. The drawings may not be to scale.

DESCRIPTION OF THE INVENTION

[0041] The present invention provides a solution the problems associated with many drilling fluids (e.g., precipitation of asphaltenes during use and/or destabilized clay and/or shale). The solution is premised on a cationic surfactant that includes calcium nitrate, diethanolamine (DEA), and glacial acetic acid. The cationic surfactant can be comprised in a drilling fluid. The drilling fluid of the present invention can be added to a wellbore during a drilling process to I) allow precipitation of asphaltenes reaction products and/or 2) inhibit swelling of clays or shale. Without wishing to be bound by theory, it is believed that the mechanism that allows precipitation of the asphaltenes present in crude oil is established between diethanolamine and glacial acetic acid, when the crude oil is incorporated from the deposit to the drilling fluid in contact with the formation, the gases associated to the crude oil, i.e. CO.sub.2 expansion and chemical reaction with the asphaltenes, precipitating the reaction products.

A. Cationic Surfactant

[0042] The cationic surfactant alone can inhibit precipitation of asphaltenes, inhibit swelling of clay and/or shale, provide anti-bacterial action, emulsify any type of crude that is incorporated into the fluid during the drilling of a reservoir, and the ability to be stored for reuse are properties provided by the environmentally-friendly surfactant.

[0043] The cationic surfactant composition of the present invention can include calcium nitrate, DEA and glacial acetic acid. The amount of DEA can be 2 to 5 vol. %, 3 to 4 vol. %, or 2, 3, 4, 5 vol. % or any value or range there between of diethanolamine. Glacial acetic acid can be present in about 0.5 to 2 vol. %, 1 to 1.5 vol. %, or 0.5, 1, 1.5, 2 vol. %, or any range or value there between. A 53-57 vol. % calcium nitrate solution can be present in 92 to 97 vol. %, 93 to 96 vol. %, 94 to 95 vol. %, or 92, 93, 94, 95, 96, 97 vol. %, or any range or value there between. The calcium nitrate, DEA and glacial acetic acid can be obtained from various commercial sources. A non-limiting example of a commercial source is Sigma-Aldrich (USA). In some embodiments, the calcium nitrate is prepared by reacting aqueous nitric acid and calcium carbonate. The nitric acid can include 56 wt. % and 66 wt. % of nitric acid, preferably between 62 wt. % and 65 wt. %, and calcium carbonate can have a purity of 89% to 99%, preferably 97 to 99% (i.e., 96 to 99 wt. % calcium carbonate).

[0044] In some embodiments, the cationic surfactant composition can be prepared by combining the calcium nitrate, diethanolamine and then acidify the solution with glacial acetic acid to form the cationic surfactant. In some embodiments, the cationic surfactant is prepared in the following manner. In a first step, calcium nitrate can be prepared by combining a desired amount of aqueous nitric acid with a stoichiometric amount of calcium carbonate at a temperature of 50 to 70 C., preferably 60 C. with agitation to form calcium nitrate in a concentration of 53 to 57 vol. %, preferably 54 to 56 vol. %, or 53, 54, 55, 56, 57 vol. %, or any range or value there between. The pH of the solution can be neutralized or adjusted to a neutral pH (e.g., pH of 6.5 to 7.5, or about 7) with the addition of calcium oxide. To this solution 2 to 5 vol. % of diethanolamine can be added at 22 to 25 C. with agitation to form the calcium salt of diethanolamine. The nitrogen of the diethanolamine can be protonated by addition of glacial acetic acid to form the cationic surfactant. The amount of glacial acetic acid can be 0.5 to 2 vol. %, 1 to 1.5 vol. %, or 0.5, 1, 1.5, 2 vol. % or any range or value there between. In some embodiments, the cationic surfactant can have a general structure of:

##STR00001##

In other structure embodiments, the surfactant is a linear molecule.

B. Drilling Fluids

[0045] The cationic surfactant of the present invention can be combined with other components to produce a drilling fluid suitable for use in subterranean hydrocarbon formations. The drilling fluid can include viscosifiers, alkalinizing agents, densifiers, control agents or other components.

[0046] 1. Viscosifiers

[0047] Viscosifiers are materials that provide a suitable viscosity for carrying the drilled cuttings in tangential vertical or horizontal wells, as well as capacity to keep the cutting in suspension, maintain optimal fluid thixotropic properties, and optional lubricity and emulsification. Non-limiting examples of viscosifiers include clays, mixed metal hydroxides, carboxylic acid polymers, crosslinked polyacrylate polymers, polyacrylamide polymers, polysaccharides, biopolymers and gums. In a preferred embodiment, the viscosifier is xanthan gum. The xanthan gum can be added in amounts suitable to obtain a concentration of 1.2-1.6 lbm/bbl. (3.42 to 4.56 kg/m.sup.3). In a preferred embodiment, the viscosifier is xanthan gum. The xanthan gum can be added in amounts suitable to obtain a concentration of 1.2-1.6 lbm/bbl. (3.42 to 4.56 kg/m.sup.3).

[0048] 2. Filtration Loss Control Agents

[0049] The drilling fluid can include one or more control agents. The control agent can manage filtration rate, filtration volume, and filter cake thickness and permeability, thus reducing the amount of filtrate lost from the filling fluid into a subsurface formation. Lowering the filtration rate can effectively reduce the reaction of the drilling fluid with the surrounding formation, thus contributing to borehole stability and controlling the borehole geometry. Non-limiting examples of control agents include clays (e.g., bentonite), polymers cellulosic polymers, modified natural cellulosic polymers, starch or combinations thereof. In a preferred embodiment, the drilling fluid can include starch in a concentration of 4 to 6 lbm/bbl. (11.4 to 17.1 kg/m.sup.3), or 4, 5, 6 lbm/bbl. (11.4, 14.2, 17.1 kg/m.sup.3), or any value or range there between.

[0050] 3. Alkalinity Agents

[0051] The drilling fluid can include one or more alkalinity agents. The alkalinizing agent can be used to control the pH of the drilling fluid. By way of example, the drilling fluid can have a pH of 10.5 to 11. Non-limiting examples of alkalinity agents include soda ash (sodium carbonate), lime, calcium oxide, potassium hydroxide, caustic soda (sodium hydroxide), magnesium oxide, or magnesium peroxide, or mixtures thereof. In a preferred embodiment, the drilling fluid can include calcium oxide in a concentration of 0.4 to 1.4 lbm/bbl. (1.14 to 3.99 kg/m.sup.3), or 0.4, 0.5, 0.6, 0.7, 0.8, 0.9, 1.0, 1.2, 1.3, 1.4 lbm/bbl. (1.14, 1.43, 1.71, 2.0, 2.28, 2.57, 2.85, 3.42, 3.71, or 3.99 kg/m3), or any value or range there between. In some embodiments, calcium oxide can provide an additional source of calcium ion (e.g., free calcium). In water, the alkalinity agent can form metal hydroxides, which can activate, maintain or promote cation exchange with of ions in clay or shale at pH values above 10. In the most preferred embodiment, the alkalizing agent has a cation that is equal or similar to the cation of the active agent (e.g., Ca.sup.+2), in order to decrease the probability of competition for occupying the active center of the clay particle.

[0052] 4. Densifiers

[0053] The drilling fluid can include one or more densifiers. Densifiers can be compounds that increase the density of the drilling fluid and can be dispersed or solubilized in the drilling fluid. Densifiers are useful to help control formation pressure, and/or combat effects of sloughing or heaving shales that can be encountered in stressed areas. Densifiers can also thicken or viscosify the drilling fluid. The use of densifiers in the formulation is optional, and in that sense any thickener existing in the art may be used, the concentration thereof will depend on the density value required (e.g., density greater than density of water), being a non-restrictive element over the whole of the present invention. In a preferred embodiment, the drilling fluid can include calcium carbonate in a concentration 95-105 lbm/bbl. (270-299.24 kg/m.sup.3) as a densifier. Preferably, a densifier is calcium carbonate, optionally could be barite, galena, hematite, ilmenite or combinations thereof. Hematite can be obtained under the trade name ORIMATITA by Petroleos de Venezuela, S.A. (PDVSA) with a specific gravity between 4.8 g/cc to 5.1 g/cc. Barite can be obtained from BAROID Industrial Drilling Products under the tradename BAROID.

[0054] The above described components can be combined to form a drilling fluid of the present invention. In a first step, a volume of water needed to prepare the required volume of drilling fluid can be added to a preparation tank. The volume of water can be determined by subtracting the volume displacement of the viscosifier, optional densifier, and considering the increase of density of water caused by the other components of the formulation of 0.5-0.8 LPG. By way of example, considering the density of water with the rest of the components of the formulation of 8.4-8.5 LPG, the volume of water can be 86-91% bbl. (about 13.7% to 14.5%) m.sup.3 and 104 lbm (47.17 kg) of calcium carbonate, considering as a basis of calculation one barrel of fluid densified with calcium carbonate at 10 LPG. LPG means Lbs./Gal.

[0055] In step 2, the viscosifier described below (e.g., xanthan gum) can be added to the water under agitation. The viscosifier can be added at a rate sufficient to inhibit the formation of aggregates or hydrated globules (fish eyes). In step 3, 1 to 3 vol. % or 1, 1.5, 2, 2.5, or 3 vol. % or any value or range there between of the cationic surfactant of the present invention can be added to the viscosified water. In step 4, the alkalinity agent can be added to adjust the pH to greater than 10 (e.g., 10 to 11 or 10.5 to 11, or 10, 10.1, 10.2, 10.3, 10.4, 10.5, 10.6, 10.7, 10.8, 10.9, or 11, or any range or value there between). In step 5, an optional densifier can be added. After all the ingredients have been added to the water, the solution can be agitated for 55 to 105 minutes, 60 to 100 min., 70 to 90 min, or any range or value there between.

C. Determination of Free Calcium in the Fluid

[0056] In some embodiments, it is desirable to know amount of active agent in the fluid in the formation during the drilling operation so that the drilling fluid formulation can be adjusted to provide more or less active agent (e.g., Ca.sup.+2). A method of determining the free calcium can include obtaining a solution that include calcium free water and a calcium ion indicator. In a preferred embodiment, the calcium indicator is ammonium-2,6-dioxo-5-[(2,4,6-trioxotetrahydro-5(2H)-pyrimidinyliden)amino]-1,2,3,6-tetrahydro-4-pyrimidinolat, commonly known as Murexide or ammonium purpurate. Such an indicator is available from various commercial sources (e.g., Sigma-Aldric). In a calcium-free water solution, the solution can have a violet color. An analyte can be obtained from the drilling fluid in the wellbore and then be added to the water solution containing the calcium ion indicator. If the solution remains violet in color, no calcium is present. If the solution turns red, free calcium is present. To determine the amount of free calcium, the solution can be titrated with a known molarity of ethylenediaminetetraacetic acid (EDTA) that is equivalent to a known amount of CaC0.sub.3 (equivalence number) until the solution returns to the violet color and recording the volume of EDTA solution used. In a non-limiting example, a 0.5 M solution of EDTA can be used, which is equivalent to 2000 ppm CaC0.sub.3). The concentration of free calcium can then be calculated by multiplying the EDTA volume used by the equivalence number (e.g., 2000). In embodiments, where the water used to make the indicator solution turn red when the indicator is added, the residual calcium can be complexed with a 0.01 M solution of EDTA (e.g., 40 ppm). In a specific embodiment, the titration procedure is as follows: [0057] (a) In a 50 ml graduated cylinder, measuring 50 milliliters of distilled water and add it to a 250-milliliter flask. [0058] (b) Adding dropwise IN sodium hydroxide solution to pH value between 12-13, add between 0.3 and 0.5 grams of Murexide indicator. If the water turns light red, it indicates the presence of calcium; if on the contrary, it turns violet, it is a sign that there is no free calcium in the distilled water nor in any of the reagents used. In case of turning red, titrate with 40 ppm (0.01 M) EDTA using a graduated pipette of I milliliter until it changes from red to violet, indicating that all the calcium present in the mixture has been complexed. [0059] (c) Adding I milliliter of the fluid filtrate sample to be analyzed; if there is free calcium present when adding the sample, the solution will turn intense red. [0060] (d) Titrating with 0.5 M EDTA (equivalent to 2000 ppm CaC03), until the solution turns violet, taking note of the volume of EDTA used for titration. [0061] (e) For purposes of calculation of the concentration, multiplying the EDTA volume by 2000, obtaining the result in parts per million of free calcium (ppm of calcium). [0062] (f) If the solution does not turn red, indicating the absence of free calcium in the distilled water or in the reagents used, then proceeding with step (c).

[0063] This method using 2000 ppm EDTA can be used a guide for control of free calcium concentration of the drilling fluid according to the present invention.

EXAMPLES

[0064] The present invention will be described in greater detail by way of specific examples. The following examples are offered for illustrative purposes only, and are not intended to limit the invention in any manner. Those of skill in the art will readily recognize a variety of noncritical parameters which can be changed or modified to yield essentially the same results.

Example 1

Drilling Fluid Containing the Cationic Surfactant of the Present Invention

[0065] A drilling fluid containing the cationic surfactant of the present invention was made by adding xanthan gum to water, starch, cationic surfactant, calcium oxide, and calcium carbonate to water under agitation in the amounts in pounds per barrel (lbs./bbl.) listed in Table 1. The drilling fluid was tested at different rates of agitation to determine the rheology properties of the fluid with and without contamination using a methylene blue tester. The methylene blue capacity test of a drilling fluid provides an indication of the amount of reactive clay-like material in a water-base drilling fluid based on the amount of methylene blue dye absorbed by the sample. Methylene Blue Test kits are commercially available. Table 2 lists the testing results.

TABLE-US-00001 TABLE 1 CONCENTRATION (POUNDS PER PRODUCTS BARREL (LBS/BBL)) XANTHAN GUM 1.5 LBS/BBL STARCH 6 LBS/BBL CATIONIC SURFACTANT 2 VOL % CALCIUM OXIDE 0.4-1.3 LBS/BBL.sub.[Ir1] CALCIUM CARBONATE 104 LBS/BBL

TABLE-US-00002 TABLE 2 RHEOLOGY CONTAM. Gels (LBS/ MBT(LBS ARC./ (lbm/bbl.) READINGS YP 100 FT.sup.2) BBL OF FLUID) BENT L600 L300 P V (LBS/ 10 SEC/10 MBT(LBS ARC./ (lbm/BBL) (RPM) (RPM) (CENTIPOIS) 100 FT.sup.2) MIN/30 MIN BBL OF FLUID) Without 62 45 17 28 9/9/12 0 contaminant C.20 77 59 18 41 13/19/21 12.5 C.30 82 62 20 42 16/23/26 20 C.40 116 90 26 64 23/33/36 25 *Methylene blue testing agent

Example 2

Comparative Drilling Fluid Absent the Cationic Surfactant of the Present Invention

[0066] A drilling fluid absent the cationic surfactant of the present invention was made by adding xanthan gum to water, starch, calcium oxide, and calcium carbonate to water under agitation in the amounts listed in Table 3 lists. The drilling fluid was tested at different rates of agitation to determine the rheology properties of the fluid with and without contamination. Table 4 lists the testing results.

TABLE-US-00003 TABLE 3 CONCENTRATION (POUNDS PER PRODUCTS BARREL (LBS/BBL) XANTHAN GUM 1.5 LBS/BBL STARCH 6 LBS/BBL CATIONIC SURFACTANT 0 CALCIUM OXIDE 0 4-1.3 LBS/BBL.sub.[Ir2] CALCIUM CARBONATE 104 LBS/BBL

TABLE-US-00004 TABLE 4 RHEOLOGY CONTAM. Gels (LBS/ MBT(LBS ARC./ (lbm/bbl.) READINGS YP 100 FT.sup.2) BBL OF FLUID) BENT L600 L300 PV (LBS/ 10 SEC/10 MBT(LBS ARC./ (lbm/BBL) (RPM) (RPM) (CENTIPOIS) 100 FT.sup.2) MIN/30 MIN. BBL OF FLUID) Without 62 45 17 28 9/9/12 0 contaminant C.20 77 59 18 41 13/19/21 20 C.30 300 242 ? ? 70/105/? 30 C.40 UNREADABLE, COMPLETELY GELIFIED 40 *Methylene blue testing agent

Comparison of Testing Results

[0067] When comparing the results in Table 2, Example 1, with the cationic surfactant of the present invention with those obtained in Table 4, Example 2, absent said cationic surfactant, the effect caused by the presence of the cationic surfactant was determined. In the formulation of the fluid rheology, especially the effects of the contaminant, which simulated the incorporation of forming clay into the fluid when drilling; in addition to the effect on the rheological properties, the effect on the MBT (methylene blue tester) test where both fluid samples were contaminated with: 20, 30 and 40 lbs./bbl. of commercial bentonite (bentonite or montmorillonite sodium is the most important active component of lithology of different layers that are crossed during the drilling of a well and the main responsible for the swelling by water absorption of the clays and shales that cause so many difficulties in the drilling of an oil or gas well) was apparent. The results of the MBT test in Table 2 show the following: C20: 12.5 MBT; C30: 20 MBT; C40: 25 MBT; in (t2) C20: 20 MBT; C30: 30 MBT; C40: 40 MBT, the difference of (7.5; 10 and 15) lbs. of arc./bbl. of fluid) between the bentonite added as contaminant and what was detected in Table 2 through the MBT indicated the capacity of the surfactant in the formulation of fluid Table 2 to modify the active center of the clay particle through the cationic exchange by substitution of Ca++ with Na+, this difference of values in the Tables 2 and 4 between the MBT and the contaminant represented the amount of sodium montmorillonite transformed into calcium montmorillonite with lower water absorption capacity, because when Na+ is displaced from the active center of the clay particle, it drags water and Ca++, having less chemical activity and less hydrodynamic potential, it fixed less water than Na+, reducing the swelling of the clay, the well diameter and incorporation of sodium clay into the drilling fluid prepared in accordance with this formulation.

Example 3

Linear Swelling Data for the Drilling Fluid of the Present Invention

[0068] The wellbore instability problems generated as a result of the contact between drilling fluid and clay formations have been studied for several years; however, the complexity of the behavior of argillaceous rocks makes their analysis difficult. For this reason, it is important and necessary to propose a possible solution by means of experimental testing using as an instrument of measurement strain gages in order to determine the linear swelling of clays in contact with different drilling fluids. The main objective of this procedure is to propose a methodology based on laboratory tests to determine the linear swelling of the clays in drill cuttings using displacement sensors as the strain gages.

[0069] The drilling fluid of the present invention was tested to determine the linear swelling percentage using the Linear Swell Meter (LSM) test. This test is used to determine the linear volume of water absorption of a sample of commercial bentonite, clay, cuttings or samples of formation that has not been exposed to drilling fluid. Such Figures are constructed from the experimental data listed in Table 5. FIGS. 1 and 2 are graphs of the data listed in Table 5.

TABLE-US-00005 TABLE 5 DRILLING FLUID LINEAR SWELLING % DATA Time Water Fluid with DRILLING FLUID 0.0 0 0 1.0 0.8 0.66 2.0 1.4 1 3.0 1.8 1.3 4.0 2.3 1.7 5.0 2.7 1.9 6.0 3 2.1 7.0 3.4 2.4 8.0 3.7 2.5 9.0 4 2.7 10.0 4.3 2.8 11.0 4.6 3.2 12.0 4.9 3.3 13.0 5.1 3.4 14.0 5.3 3.6 15.0 5.5 3.8 16.0 5.8 4

[0070] The results obtained from this test to evaluate the efficiency of the drilling fluid according to the present invention are related to reducing the swelling capacity of the clays and shales, and hence are considered excellent.

Field Test

(% V/V and Pounds Per Barrel (lbs./bbl.) Vs. Ca.SUP.+2 .Concentration in ppm)

[0071] In field tests, the product performed satisfactorily. The results obtained during the drilling of the intermediate section of several wells (12.25 inches) allowed to confirm the effects of the present formulation; in which between 600-980 feet of the producing or reservoir section were drilled, where up to between 2-3% of crude equivalent to between 44-66 barrels of crude oil were incorporated, this volume of crude oil incorporated into the fluid was efficiently emulsified without affect the rheological properties of the fluid as well as not significantly affect the physical properties, nor presented accretion, or plugging of flow lines or the meshes of the solids control equipment. Accretion implies the growth of a body by aggregation of minor bodies

[0072] When establishing comparisons, it was determined that a reduction in the volume of incorporation of plastic or bentonite clays between 50-60% of the total average of the incorporated when other clay inhibitors are used. This was confirmed by the MBT analysis (Methylene Blue Test).

[0073] Likewise, it showed capacity of cationic exchange of the active center of the clay particle, quality that the sodium montmorillonites possess, this allows them to modify their chemical structure converting them in this case into calcium montmorillonites; which have lower water absorption capacity, which affects less swelling capacity.

[0074] The following table that can be interpreted with FIG. 3, reflects the results of the field tests:

TABLE-US-00006 TABLE 6 (% V/V & LBS/BBL VS. CA.sup.+2 CONCENTRATION) % v/v & Lbs/Bbl. Vs. Ca.sup.+2 Concentration in ppm Ca.sup.++ (ppm) Lbs/Bbl. % v/v 500 0.84 0.15 1000 1.94 0.35 1500 3.04 0.55 2500 5.25 1 5100 10.5 2 7320 15.75 3 9760 21 4 12000 26.25 5 ppm = parts per million