GB2216573A

GB2216573A - Water base drilling fluid

Info

Publication number: GB2216573A
Application number: GB8905501A
Authority: GB
Inventors: Arthur Herman Hale
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 1988-03-14
Filing date: 1989-03-10
Publication date: 1989-10-11
Anticipated expiration: 2009-03-10
Also published as: GB8905501D0; NO177012B; NO891023D0; NO177012C; NO891023L; GB2216573B

Abstract

Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and oil-in-alcohol emulsion. The alcohol is preferably glycerol.

Description

WATER BASE DRILLING FLUID This invention relates to water base drilling fluids. More particularly, the invention relates to water base drilling fluids having improved characteristics which allow low temperature drilling operations, inhibit formation of gas hydrates which form at low temperatures and high pressures, reduce shale dispersion which results in improved borehole stability, reduce fluid loss, and are environmentally safe.

Oil-in-water emulsion drilling fluids (or muds) generally comprise water, oil, emulsifier, clays or polymers, and various treating agents which control the physical, chemical and/or rheological properties of drilling fluids in boreholes. Any type of aqueous drilling fluid can be converted to an emulsion drilling fluid through the simple expedient of adding the desired amount of oil and emulsifier. The drilling fluid serves to remove chips, cuttings and the like produced by a rotating drill bit from a borehole by circulating the drilling fluid down from the surface of the well, through the drill string, and out through openings in the drill bit such that the drilling fluid is then circulated upwardly in the annulus between the side of the borehole and the rotating drill string.

The selection of a drilling fluid is primarily dependent upon the geological formation being drilled and the problems associated with such formation. Principal concerns in selection of a drilling fluid are temperature drilling conditions, formation of gas hydrates, shale dispersion, and drilling fluid loss and environmental requirements. Classically, temperature concerns associated with drilling oil/gas wells have been associated with deep hot wells ( > 150 OC); however, for deep water and/or Arctic drilling low temperatures are a concern for two principal reasons: (1) freezing of the mud due to low temperature, especially if the well must be shut in for long durations, and (2) the formation of gas hydrates under low temperature and high pressure conditions after the influx of gas.The present invention provides a drilling fluid additive which overcomes these and other problems as more particularly disclosed hereinafter.

The primary purpose of the present invention is to provide a drilling fluid, and process for the use thereof, which drilling fluid contains additives which depress the freezing point of the drilling fluid to allow low temperature drilling operations, inhibit formation of gas hydrates which form at low temperatures and high pressures, prevent shale dispersion which results in improved borehole stability, reduce drilling fluid loss thereby reducing amounts of other fluid loss additives if any (e.g. gelbentonite, carboxymethylcellulose, starch), and are environmentally more safe than oil base systems.

Accordingly, the present invention is directed to a water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and an oil-in-alcohol emulsion. The amount of an alcohol such as glycerol and, optionally, a salt should be sufficient to reduce the freezing point of the drilling fluid to a predetermined value, inhibit the formation of gas hydrates in the drilling fluid, prevent shale dispersion from the borehole into the drilling fluid, and reduce drilling fluid loss through the wall of the borehole thereby reducing amounts of other fluid loss additives if any (e.g. gel-bentonite, carboxymethylcellulose (CMC), starch).

In addition, the present invention is directed to a method for drilling a well comprising rotating a drill string to cut a borehole into the earth; circulating water base drilling fluid through the drill string and through the annulus between the drill string and the wall of the borehole; checking the drilling fluid for evidence of any of the following problems: freezing, gas hydrate formation, shale dispersion and fluid loss; and adding an oil-in-alcohol emulsion, optionally including salt, to the drilling fluid in an amount sufficient to overcome the above identified problems.Further, the present invention provides a method for drilling a well comprising determining whether the formation to be drilled will subject the drilling fluid to any of the following problems: freezing, gas hydrate formation, shale dispersion, and fluid loss; adding an oil-in-alcohol emulsion to the water base drilling fluid, optionally including salt, in an amount sufficient to overcome the above identified problems; rotating a drill bit to cut a borehole into the earth; and circulating the drilling fluid through a drill string and through an annulus between the drill string and the wall of the borehole.

It was found that the use of an alcohol such as glycerol and, optionally, a salt in an appropriate amount, as an oil-in-alcohol emulsion water base drilling fluid substantially depresses the freezing point of the drilling fluid to eliminate problems with low temperature drilling operations, inhibits formation of gas hydrates which form at low temperatures and high pressures, prevents shale dispersion which results in improved borehole stability, reduces drilling fluid loss thereby reducing amounts of other fluid loss additives if any (e.g. gel-bentonite, carboxymethylcellulose, starch), and is environmentally safe.Thus, according to the Applicant's method, the drill string is rotated to cut a borehole into the earth while circulating an oil-in-alcohol emulsion water base drilling fluid down through the drill string and thence up the annulus between the drill string and the wall of the borehole.

While this is occurring, a driller preferably is checking or observing the drilling fluid for evidence of the above noted problems. Alternatively, the formation may be known in advance to present certain problems, and the oil-in-alcohol emulsion water based drilling fluid may be utilised to overcome these problems.

In most instances, the applicable amount of oil-in-alcohol emulsion, optionally including salt, in the water base drilling fluid will be determined on a well-to-well basis. A concentration of alcohol in the oil-in-alcohol emulsion water base drilling fluid of from about 1 to 60, or preferably about 5 to 40 %w (percent by weight based on the total weight of the drilling fluid) and, optionally, of salt of from about 1 to 26, or preferably about 5 to 20 tw will reduce the freezing point of the drilling fluid by about 1 to 40 "C. A concentration of from about 1 to 60, or preferably about 10 to 40 Ew alcohol and, optionally, of from about 1 to 26, or preferably about 5 to 26 %w salt will inhibit formation of gas hydrates.A concentration of from about 1 to 60, or preferably about 5 to 30 %w alcohol and, optionally, of from about 1 to 26, or preferably about 5 to 20 %w salt in the drilling fluid will prevent shale dispersion. A concentration of from about 1 to 60, or preferably about 5 to 40 %w alcohol in the drilling fluid and, optionally, of salt of from about 1 to 26, or preferably about 5 to 15 Gw will reduce fluid loss from the drilling fluid through the wall of the borehole.

Various inorganic salts are suitable for use with the invention, including but not limited to Nail, NaBr, KC1, Caul2 and NaN03, among which NaCl is preferred. A synergistic effect is experienced when such a salt is used with alcohol as a mud additive package, i.e., an effect greater than the sum of the effects from salt and alcohol individually.

The alcohol of the present invention may be any alcohol of less than 8 hydroxy groups and less than 16 carbon atoms. Glycerol is most preferred. Other exemplary suitable alcohols include isopropanol, ethylene glycol, and 1,2-propanediol.

In accordance with the present invention, any type of water base drilling fluid can be converted to an emulsion drilling fluid through the expedient of adding the desired amount of oil, emulsifier (surfactants) and alcohol (e.g., glycerol).

Emulsion drilling fluids possess many advantages over regular drilling fluids, including but not limited to, increased drilling rate, longer bit life, fewer round trips, less torque on pipe, less drag on pipe, and improved hole conditions.

Emulsifiers (surfactants) preferred for use with the present invention are diquarternary amines, alkylphenyl ethoxylates, alcohol ethoxylates, and amine ethoxylates. In accordance with the present invention it is highly preferred to first make an emulsion of the oil, surfactant and alcohol (e.g. glycerol). This emulsion is then emulsified or mixed with water. Emulsification preferably is accomplished through mechanical agitation.

Drilling fluid properties should be such as to promote safe and speedy drilling and completion of the well with the maximum productive capacity. Use of emulsion drilling fluids of controlled properties requires expenditure of large sums of money, and to carry out its role properly, the drilling fluid must be protected against the effects of freezing conditions, gas hydrate formation, shale dispersion and fluid loss. The use of alcohol/oil emulsion in a water base drilling fluid, optionally including salt, readily protects the drilling fluid against freezing conditions and gas hydrate formation by lowering the freezing point of the drilling fluid.

With respect to shale dispersion and fluid loss, the use of alcohol/oil emulsion in a water base drilling fluid, optionally including salt, aids in deposition of an impermeable filter cake, and the filter cake in turn prevents fluid loss and shale dispersion. The filter cake performs its job primarily on the basis of its impermeability to water. If the formation permeability and the fluid-loss properties of the mud are both high, large quantities of fluid will flow through the wall cake and into the permeable formation, leaving a thick wall cake behind. This cake may become so thick as to seriously interfere with movement of the drill pipe when it is withdrawn and may even result in sticking the pipe.If a thick cake is formed over the face of the producing formation, it may not become properly cleaned off during the well completion process and will interfere with the production rate of the well. The fluid which passes into the formation may also exercise an influence. When the drilling fluid is water based and shales and clays which are susceptible to hydration are drilled, the use of high fluid loss drilling fluid may result in swelling and heaving of the shale, slow drilling rates, stuck pipe, fishing jobs and even loss of the hole. If the producing formation contains hydratable clays, the intrusion of water may result in swelling of the clay particles within the sandy formation and permanent loss of permeability with resulting impaired production rates.The additive package of the present invention readily solves such problems by increasing the impermeability of the filter cake to water, thus decreasing the fluid-loss properties of the drilling fluid.

The following examples are illustrative of the application of the process of the present invention and of the drilling fluid composition, and are not to be construed as limiting the scope thereof.

Cutting dispersion tests of which the results are shown in Table 1 and Table 2 were carried out as follows. Test fluids and sized shale cuttings (6-10 mesh) were hot rolled for 45 seconds at 65 "C. After the shale test solution mixture was hot rolled the shale was sized over 10, 30 and 80 mesh screen and dried. The data is expressed as percent retained of the original weight (2.5 gram), and are shown in the column "Exper.".

The fresh water (FW) and the 0.150 M NaCl solution (NaCl) contained 0.2 lb/bbl XC polymer, which is a water soluble polysaccharide sold under the trade name "Kelzan XC" by Kelco Corp. for viscosity control. As a result, all of the test solutions had an apparent viscosity of approximately 2.0 centipoise as measured on a Fann 35A viscometer.

The percentages are always percent by volume (%v). "0" refers to mineral oil used in the experiments, "S" refers to a ethoxylated tallow amine surfactant used in the experiments and "G" refers to glycerol.

In Table 1 data are shown that indicate that the addition of glycerol, oil and surfactant enhances performance in terms of inhibiting cuttings dispersion. Each of the components oil, surfactant and glycerol were added separately to fresh water or fresh water with Nazi. To evaluate the synergistic effects, the percent shale retained in fresh water was subtracted from all of the other test solutions (the results are shown in the column "Corr."). To determine synergy between oil, surfactant and glycerol the percent retained (minus percent retained in fresh water) of the glycerol/fresh water, oil/fresh water and surfactant /fresh water were added together.This result is a predicted value of 4.9 percent retained, see column "Pred.". This is significantly less than what was obtained when all three components were added into the same test solution.

When salt was present it was found that the percent retained of the individual components (glycerol, oil and surfactant) in fresh water (minus the percent retained in fresh water) plus NaCl in fresh water (minus the percent retained in fresh water) was 37.6 percent retained. This was significantly less than what was observed when all four reagents were in the same test solution.

These results suggest a synergistic action between the different additives being tested.

Table 1. Cuttings dispersion test results with Green Canyon shale.

Results

Test fluid i Exper. Corr. Pred.

fresh water ( FW) 1 2.5 0.150 M NaCl (- NaCl) 1 35.2 32.7 FW (10 %v 0/1 %v S) 1 3.6 1.1 FW (1 %v S) 1 4.2 1.7 NaCl (10 %v 0/1 Zv S) ≈ 65.6 63.1 NaCl (1 %v S) 1 63.2 60.7 FW (10 %v 0/1 %v S/10 %v G) 1 20 17.5 4.9 NaCl (10 %v 0/1 %v S/10 %v G)l 72.8 70.3 37.6 NaCl (10 %v G) ss 50.7 48.2 FW (10 %v G) 1 4 1.5 FW (10 %v O) 1 4.2 1.7 NaCl (10 %v O) 1 36.2 33.7 The results of the tests of Table 1 suggested that the combination of these additives was not only an improvement, but was synergistic in terms of inhibiting shale dispersion.

As a means of improving the emulsification of the additives, an emulsion of mineral oil, glycerol and a tallow ethoxylated amine surfactant was made prior to adding thereto fresh or salt water, wherein the oil/surfactant/glycerol emulsion, referred to as O/G/S, was made at a ratio of 24/75/1 percent by volume. This emulsion was stable at room temperature for weeks. The effectiveness of this emulsion to inhibit cuttings dispersion is shown in Table 2.

The emulsion was tested for inhibition of cuttings dispersion (Table 2) of two shales. The results indicate that the emulsion is an effective inhibitor of cuttings dispersion and that a synergistic relationship exists between the presence of glycerol and oil/surfactant.

To evaluate the synergistic effects, the percent shale retained in fresh water was subtracted from all of the other test solutions. To determine synergy between oil, surfactant and glycerol the percent retained (minus percent retained in fresh water, see column "Corr.") of the glycerol/fresh water, oil/fresh water and surfactant/fresh water were added together. This result is the predicted value, see column "Pred.". This value is significantly less than what was obtained when all three components were in the same test solution.

When salt was present it was found that the percent retained of the individual components (glycerol, oil and surfactant) in fresh water (minus the percent retained in fresh water) plus NaCl in fresh water (minus the percent retained in fresh water) represented the predicted percent retained. This was significantly less than what was observed when all four reagents were in the same test solution. These results suggest a synergistic action between the different additives being tested.

Table 2. Cuttings dispersion test results.

Green Canyon I South Timbalier Results I Results Test fluid I Ex. Corr. Pred.l Ex. Corr. Pred.

I I fresh water (= FW) 2.4 16 0.150 M NaCl (= NaCl) 34.6 32.2 38.6 22.6 FW (2.4 %v 0/0.1 %v S) 1 2.7 0.3 1 21.2 5.2 FW (0.1 %v S) 1 2.6 0.2 1 17.5 1.5 NaCl (2.4 %v 0/0.1 %v S) 1 36 33.6 1 45.1 29.1 NaCl (0.1 %v S) 33.8 31.4 39 23 FW 10 %v O/S/G (24/1/75) 1 16.5 14.1 1.8 I 32.2 16.2 7.1 NaCl 10 %v O/S/G (24/1/75) 55.2 52.8 34 57.9 41.9 28.5 NaCl (7.5 %v G) 1 41.2 38.8 1 51.2 35.2 FW (7.5 %v G) 3.7 1.3 20.4 4.4 FW (2.4 %v 0) 1 2.7 0.3 1 17.2 1.2 Table 3 shows the results of cutting dispersion tests for Pierre shale. Sized shale cuttings (6-10 mesh) were rolled in the test fluid for 15 seconds at 65 C. The shale test solution mixture is then sized over 10, 30 and 80 mesh screens. The amount retained on the screens is added and the percent retained is calculated relative to the original starting material (2.5 gm). All samples were hot rolled at 65 C for the indicated amount of time.

O/S is used to refer to 10 volume parts of mineral oil and 1 volume part of a tallow ethoxylated amine surfactant. O/S/G is used to refer to 6 volume parts mineral oil, 93 volume parts glycerol and 1 volume part of a tallow ethoxylated amine surfactant. XC is a water soluble polymer including polysaccharides, as sold under the trade name "Kelzan XC" by Kelco Corp. 20% NaCl is a 20 %w NaCl solution.

In Table 3 a comparison of the abilities of the different systems to inhibit cuttings dispersion of Pierre shale is shown.

The results indicate that glycerol/oil/surfactant is superior to all of the other systems for inhibiting cuttings dispersion of this shale.

Table 3. Effectiveness of different formulations in the presence of NaCl.

Formulation Apparent * retained viscosity 18 45 145 200 300 (cP) (hour) (hour) (hour) (hour) (hour) FW and 0.2 lb/bbl XC 2 8 0.2 NaCl and 0.2 lb/bbl XC 2 92.5 85.3 57.5 45.2 22.3 20 %v Nail/10 %v G 2 97.8 93.5 85.3 79.8 68.6 20 %v NaCl/10 %v (O/S) 2 95.6 92.3 68.3 55.3 35.6 20 %v NaCl/10 %v (O/S/G) 2 98.6 97.3 92.3 88.6 82.3 Table 4 provides freezing point depression data which indicates that the oil/glycerol/surfactant mixture lowers the freezing point of fresh water and salt water. This result suggests that this emulsion can be used to prevent freezing of mud in cold environments. In addition, it indicates that this emulsion will reduce the probability of forming gas hydrates in the drilling fluid. 20% NaCl is a 20 %w NaCl solution.This solution was mixed with the oil/glycerol/surfactant emulsion by volume. The oil/glycerol/surfactant emulsion comprises 94 %v glycerol, 5 %v oil and 1 %v surfactant. The freezing point was the determined using the ASTM D-1177 method.

Table 4. Freezing point depressions ("C) for glycerol/oil/ surfactant emulsions (E).

Composition Freezing point 20 %v NaCl -17 20 %v Nail/10 %v E -20 20 %v NaCl/20 %v E -23 20 %v Nail/30 %v E -28 20 Zv Nail/40 %v E -32 20 %v NaCl/50 %v E -34 FW O FW/10 %v E -2 FW/20 %v E -7 FW/30 %v E -11 FW/40 %v E -18 FW/50 %v E -29 In Table 5 data is presented showing that the glycerol/oil/ surfactant emulsion can be used in a mud formulation without severely altering the primary rheological or fluid loss properties.

The oil/glycerol/surfactant (O/G/S) was emulsified at a ratio of 5/94/1 percent by volume. Resinex is a water-soluble, heat stable synthetic resin used for high temperature fluid loss sold by MI Drilling Fluid Company. CLS is used to refer to chrome lignosulphonate.

The test for fluid loss and the test for the High Pressure High Temperature (HPHT) are described in the API Standard Procedures of Field Testing Drilling Fluid (RP 13B). This document further describes the way in which the shear stress at 600 RPM and at 300 RPM (in lb/100 ft2), the plastic viscosity (PV), yield point (YP) and gel strength at 10 seconds and at 10 minutes (in lb/100 ft2) were determined using a Fann 35A viscometer.

Table 5. Laboratory mud formulations.

Formulation

l 2 3 4 5 6 7 8 9 Seawater (ml) 1 245 221 196 172 147 221 196 172 147 Glycerol (%v) 0 10 20 30 40 - - - O/G/S (%v) I - - - - - 10 20 30 40 Bentonite (gm) 10 10 10 10 10 10 10 10 10 Drill solids (gm) 1 35 35 35 35 35 35 35 35 35 Barite (gm) 1 367 360 354 347 340 368 369 369 370 CLS (gm) 6 6 6 6 6 6 6 6 6 CMC (gm) l 1 1 1 1 1 1 1 1 1 Resinex (gm) 2 2 2 2 2 2 2 2 2 Density (lb/gal) 16 16 16 16 16 16 16 16 16 600 RPM 1 70 72 70 67 72 73 75 77 82 300 RPM 1 41 41 41 37 41 43 43 45 47 PV (cps) 1 29 31 29 30 31 30 32 32 35 YP (lb/100 ft) 12 10 12 7 10 13 11 13 12 10 s gel 1 3 3 2 3 2 3 2 3 3 10 min gel 1 14 15 9 5 6 12 10 12 13 API fluid loss (ml)l 9 6 4.5 4 5 3.5 4 3.5 3.5 Cake thickness I (32nd in) 4 2 2 2 2 2 2 2 2 The foregoing description of the invention is merely intended to be explanatory thereof, and various changes in the details of the described method and apparatus may be made within the scope of the appended claims without departing from the spirit of the invention

Claims

CLAIMS 1. Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and an oil-in-alcohol emulsion.
2. Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier and an oil-in-alcohol emulsion sufficient to reduce the freezing point of the drilling fluid.
3. Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and an oil-in-alcohol emulsion sufficient to inhibit formation of gas hydrates in the drilling fluid.
4. Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and an oil-in-alcohol emulsion sufficient to prevent shale dispersion in a borehole in which the drilling fluid is employed.
5. Water base drilling fluid comprising water, at least one of a clay and a polymer, emulsifier, and an oil-in-alcohol emulsion sufficient to reduce drilling fluid loss in a borehole in which the drilling fluid is employed.
6. Water base drilling fluid as claimed in any one of the claims 1-5 wherein the alcohol is glycerol.
7. Water base drilling fluid as claimed in any one of the claims 1-6 including a salt.
8. Method for drilling a well comprising determining whether the formation to be drilled will subject a drilling fluid to at least one problem of (a) freezing, (b) gas hydrate formation, (c) shale dispersion, and (d) fluid loss; and adding an oil-in-alcohol emulsion to the drilling fluid in an amount sufficient to overcome the problem; rotating a drill bit to cut a borehole into the earth; and circulating the drilling fluid through a drill string and through an annulus between the drill string and the wall of the borehole.
9. Method as claimed in claim 8, wherein the drilling fluid is further provided with a salt.
10. Water base drilling fluid as claimed in claim 1 substantially as described in the specification with reference to the examples.