Compositions comprising an acrylamide-containing polymer and process therewith

A composition is provided which comprises an acrylamide-containing polymer comprising repeat units derived from at least two monomers, a polypropylene glycol, and optionally, a polysaccharide. Also provided is a water-based composition which can be used as drilling fluid wherein the composition comprises calcium chloride, an acrylamide-containing polymer which has repeat units derived from at least two monomers, a polypropylene glycol, and optionally, a polysaccharide. Additionally, a process for using a water-based fluid which has the characteristics of an oil-based fluid as to use in drilling a gumbo shale or highly hydratable formation is provided wherein the process comprises contacting the shale or formation with a composition comprising calcium chloride, an acrylamide-containing polymer, a polypropylene glycol, and optionally, a polysaccharide wherein the acrylamide-containing polymer, polypropylene glycol, and polysaccharide are each present in a sufficient amount to effect the control of fluid loss of a water-based composition.

The present invention relates to a composition comprising an 
acrylamide-containing polymer and a process for using the composition. 
BACKGROUND OF THE INVENTION 
Water-based fluids such as, for example, drilling fluids, milling fluids, 
mining fluids, water-based metal working fluids, food additives and 
water-based paints, are useful in a variety of industrial applications. It 
is well known to those skilled in the art of drilling wells to tap 
subterranean deposits of natural resources, such as gas, geothermal steam 
or oil, especially when drilling by the rotary method or the percussion 
method wherein cuttings must be removed from the bore hole, it is 
necessary to use a drilling fluid. 
The use of water-based fluids in, for example, workover and completion 
fluids in oil field operations is also well known to those skilled in the 
art. Workover fluids are those fluids used during remedial work in a 
drilled well. Such remedial work includes removing tubing, replacing a 
pump, cleaning out sand or other deposits, logging, etc. Workover also 
broadly includes steps used in preparing an existing well for secondary or 
tertiary recovery such as polymer addition, micellar flooding, steam 
injection, etc. 
Completion fluids are those fluids used during drilling and during the 
steps of completion, or recompletion, of the well. Completion operation 
can include perforating the casing, setting the tubing and pump, etc. Both 
workover and completion fluids are used in part to control well pressure, 
to stop the well from blowing out while it is being completed or worked 
over, or to prevent the collapse of casing from over pressure. 
Oil-based, or hydrocarbon-based, drilling fluids have been generally used 
for drilling highly hydratable formations, or gumbo shales. However, these 
oil- or hydrocarbon-based drilling fluids which contain at least a 
hydrocarbon as liquid carrier cannot be used in some areas where 
environmental regulations are of concern. Water-based drilling fluids 
would therefore be the fluids of choice. 
Although many water-based drilling fluids have been used to drill through 
gumbo shales or highly hydratable formations, none has performed as well 
as oil- or hydrocarbon-based fluids. Even though recently some synthetic 
liquid-based fluids containing esters, polyolefins, or glycols have been 
used in drilling the gumbo shales or highly hydratable formations with 
limited success, these liquid-based fluids are generally not cost 
effective because they are too expensive. 
Additionally, many additives for water-based fluids were found to 
effectively provide fluid loss control, increase viscosity, inhibit drill 
solids, or combinations of two or more thereof, of the water-based fluids 
when the fluids are used in drilling a subterranean formation and contain 
less than about 2000 mg/l of calcium chloride. However, as the calcium 
chloride concentration increases, the effectiveness of these additives, 
especially for maintaining rheology and water loss control, decreases 
significantly. It is, therefore, highly desirable to develop an improved 
water-based fluid, or an additive thereof, and a process for using these 
fluids or additives. 
SUMMARY OF THE INVENTION 
An object of the present invention is to provide an additive useful in a 
water-based fluid. A further object of the invention is to provide a 
water-based fluid having the characteristics of an oil-based fluid useful 
in drilling a gumbo shale or highly hydratable formation. Another object 
of the invention is to provide a water-based fluid for use as drilling 
fluid. Still another object of the invention is to provide a composition 
which can be used as drilling fluid wherein the drilling fluid contains at 
least 1,000, preferably 5,000, more preferably 10,000, even more 
preferably, 25,000, and most preferably 50,000 mg/l of calcium chloride. 
Other objects, advantages, and features will become more apparent as the 
invention is more fully disclosed hereinbelow. 
According to a first embodiment of the present invention, a composition is 
provided which comprises an acrylamide-containing polymer which contains 
repeat units derived from at least two monomers, a polypropylene glycol, 
and, optionally, a polysaccharide wherein the acrylamide-containing 
polymer, polyproylene glycol, and polysaccharide are each present in a 
sufficient amount to effect the control of fluid loss of a water-based 
composition. 
According to a second embodiment of the present invention, a water-based 
composition which can be used as drilling fluid is provided wherein the 
composition comprises calcium chloride, an acrylamide-containing polymer 
which has repeat units derived from at least two monomers, a polypropylene 
glycol, and, optionally, a polysaccharide wherein the 
acrylamide-containing polymer, polyproylene glycol, and polysaccharide are 
each present in a sufficient amount to effect the control of fluid loss of 
a water-based composition. 
According to a third embodiment of the present invention, a process for 
using a water-based fluid which has the characteristics of an oil-based 
fluid as to use in drilling a gumbo shale or highly hydratable formation 
is provided. The process comprises contacting the shale or formation with 
a composition comprising calcium chloride, an acrylamide-containing 
polymer, a polypropylene glycol, and optionally, a polysaccharide wherein 
the acrylamide-containing polymer, polyproylene glycol, and polysaccharide 
are each present in a sufficient amount to effect the control of fluid 
loss of a water-based composition. 
DETAILED DESCRIPTION OF THE INVENTION 
According to the first embodiment of the invention, a fluid additive is 
provided. The additive comprises an acrylamide-containing polymer having 
repeat units derived from at least two monomers, a polypropylene glycol, 
and a polysaccharide. The term "hydratable formation" is used herein as, 
unless otherwise indicated, gumbo shales. The term "gumbo shale" as used 
in the present invention, unless otherwise indicated, refers to soft and 
easily dispersible formation which forms highly plastic and sticky masses 
when wet. 
According to the first embodiment of the invention, the 
acrylamide-containing polymer can be any acrylamide-containing polymer 
that inhibits shale dispersion, or increases the viscosity of the water 
under ambient conditions, or both. The term "polymer" used herein denotes, 
unless otherwise indicated, a copolymer, a terpolymer, a tetrapolymer, or 
combinations of any two or more thereof. 
Suitable acrylamide-containing polymers are thermally stable polymers of 
acrylamide and at least one olefinic comonomer. Generally, any olefinic 
comonomer which can be co-polymerized with acrylamide can be used in the 
present invention. Examples of suitable olefinic comonomers include, but 
are not limited to, R--C(R).dbd.C(R)--C(O)--C(R)(R), 
R--C(R).dbd.C(R)--C(O)--N(R)--Y--R, R--C(R).dbd.C(R)--C(O)--G--Y--Z, 
R--C(R).dbd.C(R)--C(O)--G--Y--W, CH.sub.2 
.dbd.CH--C(O)--N(R)--(CH.sub.2).sub.n --CH.sub.3, and combinations of any 
two or more thereof where each R can be the same or different and is each 
selected from the group consisting of hydrogen, alkyl radicals, aryl 
radicals, aralkyl radicals, alkalkyl radicals, cycloalkyl radicals, and 
combinations of any two or more thereof wherein each radical can contain 1 
to about 12 carbon atoms; G is O or NH; Y is an alkylene radical having 1 
to about 10, preferably 1 to about 7, and most preferably 1 to 4 carbon 
atoms and can contain substituents selected from the group consisting of 
hydroxy group, halides, amino groups, alkyl radicals, aryl radicals, 
alkaryl radicals, aralkyl radicals, cycloalkyl radicals, and combinations 
of any two or more thereof wherein each carbon-containing radical has 1 to 
about 12 carbon atoms; W is an acid moiety selected from the group 
consisting of phosphonic acids, phosphoric acids, phosphinic acids, 
sulfuric acids, sulfonic acids, sulfurous acids, sulfinic acids, 
carboxylic acids, alkali metal salts of the acids, ammonium salts of the 
acids, and combinations of any two or more thereof; Z has a formula 
selected from the group consisting of N(R)(R), N.sup.+ (R)(R)(R)X.sup.-, 
and combinations of any two or more thereof wherein R is the same as above 
and X can be any inorganic anion selected from the group consisting of 
sulfonates, sulfinates, sulfates, phosphonates, phosphinates, phosphates, 
halides, nitrates, and combinations of any two or more thereof; and n is a 
number of from 0 to about 10. More specific examples of suitable olefinic 
comonomers include, but are not limited to, vinyl acetate, vinylpyridine, 
styrene, methyl methacrylate, acryloylpiperazine, methacryloylpiperazine, 
methacryloylmorpholine, methacrylamide, acrylonitrile, methacrylic acid, 
ammonium salt of methacrylic acid, alkali metal salts of methacrylic acid, 
2-methacryloyloxyethyltrimethylamine, 2-acrylamido-2-methylpropane 
sulfonic acid, alkali metal salts of 2-acrylamido-2-methylpropane sulfonic 
acid, 2-methacryloyloxyethane sulfonic acid, alkali metal salts 
of2-methacryloyloxyethane sulfonic acid, acryloylmorpholine, 
N-4-butylphenylacrylamide, 2-acrylamido-2-methylpropane dimethylammonium 
chloride, 2-methacryloyloxyethyldiethylamine, 
3-methacrylamidopropyldimethylamine, vinylsulfonic acids, alkali metal 
salts of vinylsulfonic acid, styrene sulfonic acid, alkali metal salts of 
styrene sulfonic acid, N-vinyl-2-pyrrolidone, and combinations of any two 
or more thereof. The presently preferred comonomers are 
2-acrylamido-2-methylpropane sulfonic acid, alkali metal salts of 
2-acrylamido-2-methylpropane sulfonic acid, N-vinyl-2-pyrrolidone, or 
combinations of any two or more thereof. The presently preferred 
acrylamide-containing polymers are copolymers of N-vinyl-2-pyrrolidone and 
acrylamide, terpolymers of sodium 2-acrylamide-2-methylpropanesulfonate, 
acrylamide and N-vinyl-2-pyrrolidone, copolymers of sodium 
2-acrylamido-2-methyl-2-propanesulfonate and acrylamide, and combinations 
of any two or more thereof for applications in high salinity environments 
at elevated temperatures. Selected terpolymers also are useful in the 
present process, such as terpolymers derived from acrylamide and 
N-vinyl-2-pyrrolidone comonomers with lesser amounts of termonomers such 
as vinyl acetate, vinylpyridine, styrene, methyl methacrylate, and other 
polymers containing acrylate groups. Generally, the mole percent of 
acrylamide is in the range of from about 15 to about 90%, preferably about 
20 to about 85%, and most preferably 20 to 80%. Olefinic comonomer makes 
up the rest of the mole percent. 
Suitable polysaccharides for use in the composition are those capable of 
increasing the viscosity, or controlling the water loss, or both, of the 
composition in aqueous form and include, but are not limited to, starches, 
gums, other biopolysaccharides, celluloses, and combinations of any two or 
more thereof. 
Examples of suitable celluloses are those selected from the group 
consisting of carboxymethylcellulose, methylcellulose, carboxymethyl 
hydroxyethyl cellulose, hydroxypropyl methylcellulose, hydroxypropyl 
cellulose, hydroxyethyl cellulose, ethylhydroxy cellulose, and 
combinations of any two or more thereof. 
Examples of suitable starches include those selected from the group 
consisting of carboxymethyl starch, hydroxyethyl starch, and hydroxypropyl 
starch, and combinations of any two or more thereof. 
Examples of suitable gums are those selected from the group consisting of 
arabic, trajacanth, karaya, shatti, locust bean, guar, psyllium seed, 
quince seed, agar, algin, carrageenin, furcellaran, pectin, gelatin, and 
combinations of any two or more thereof. 
The biopolysaccharides useful in this invention are biopolymers produced by 
a process comprising the microbial transformation of a carbohydrate with a 
microorganism to obtain a polymeric material which differs from the parent 
polymeric material in respect of composition, properties and structure. 
These are thoroughly discussed in U.S. Pat. No. 5,091,448, which is 
incorporated herein by reference. 
The presently preferred polysaccharides are high viscosity hydroxyethyl 
cellulose polymer and carboxymethyl hydroxyethyl cellulose polymer for 
their ready availability. 
Polypropylene glycols are commercially available glycol-based polymers. A 
polypropylene glycol is the product of a propylene oxide polymerization. 
Generally, a suitable polypropylene glycol can have a molecular weight in 
the range of from about 400 to about 7,500, preferably about 1,000 to 
about 6,000, more preferably about 1,200 to about 5,000, and most 
preferably 1,500 to 4,500. Furthermore, the polypropylene glycol polymer 
useful in the invention can also be a polypropylene glycol having one or 
more methyl groups attached to the propylene units of the polymer. 
The weight percent of the individual components of the composition can be 
any weight percent so long as the additive can increase the viscosity, or 
control the water loss, or inhibit the drill solids, or combinations of 
any two or more thereof, of a water-based fluid and can vary widely 
depending on the desired applications. Generally the composition of the 
present invention can contain the acrylamide-containing polymer in the 
range of from about 10 to about 55, preferably from about 12.5 to about 
50, and most preferably from 15 to 45 weight %; the polypropylene glycol 
polymer in the range of from about 20 to about 90, preferably about 30 to 
about 80, and most preferably 40 to 70 weight %; and the polysaccharide in 
the range of from about 1 to about 20, preferably about 1 to about 17.5, 
and most preferably 1 to 15 weight %. When the composition is used in a 
water-based fluid, the water-based fluid composition can contain the 
acrylamide-containing polymer in the range of from about 0.01 to about 10, 
preferably from about 0.05 to about 5, and most preferably from 0.1 to 3 
weight %; the polypropylene glycol polymer in the range of from about 0.01 
to about 20, preferably from about 0.05 to about 15, and most preferably 
from 0.1 to 10 weight %; the polysaccharide in the range of from about 
0.01 to about 10, preferably from about 0.05 to about 5, and most 
preferably from 0.1 to 3 weight %; and water, as defined below, making up 
the rest of the composition. 
The additive or composition can be made by a variety of mixing means known 
to one skilled in the art such as, for example, blending. The individual 
components can be mixed in any order. Because such mixing means are well 
known to one skilled in the art, the description is omitted herein for the 
interest of brevity. 
The term "water" can be a pure water, a regular tap water, a solution, a 
suspension, or combinations of any two or more thereof wherein the 
solution or suspension contains dissolved, partially dissolved, or 
undissolved substances. The substances can be salts, clays, or 
combinations of any two or more thereof. 
Examples of salts that can be present in a water-based fluid using the 
composition of the invention include, but are not limited to, alkali metal 
halides, alkaline earth metal halides, and combinations of any two or more 
thereof. Generally the total salts content in the water-based composition 
can vary widely from, for example, 5 to as high as 50 weight %. The 
typical total salts content can be in the range of from, for example, 
about 5 weight % to about 40 weight %. 
Examples of suitable clays include but are not limited to kaolinite, 
halloysite, vermiculite, chlorite, attapulgite, smectite, montmorillonite, 
illite, saconite, sepiolite, palygorskite, Fuller's earth, and 
combinations of any two or more thereof. The presently preferred clay is 
palygorskite which is also known as attapulgite because it works well in 
drilling fluids. The clay can be present in the water in the range of from 
about 0.25 weight % to about 15 weight %, preferably about 0.5 weight % to 
about 10 weight %, and most preferably 1 weight % to 5 weight %. 
According to the second embodiment of the present invention, a composition 
is provided which comprises, or consists essentially of, calcium chloride, 
an acrylamide-containing polymer, a polypropylene glycol, water, and 
optionally a polysaccharide. The scope of the acrylamide-containing 
polymer, polypropylene glycol, and polysaccharide is the same as that 
disclosed in the first embodiment of the invention. 
The weight percent of the individual components of the composition, 
according to the second embodiment of the present invention, can be any 
weight percent so long as the additive composition can increase the 
viscosity, or control the water loss, or inhibit the drill solids, or 
combinations of any two or more thereof, of a water-based fluid and can 
vary widely depending on the desired applications. Generally the additive 
of the present invention can contain calcium chloride in the range of from 
about 2,000 to about 250,000, preferably from about 5,000 to about 
250,000, more preferably from about 10,000 to about 250,000, even more 
preferably from about 25,000 to about 200,000, and most preferably from 
50,000 to 200,000 mg/l; the acrylamide-containing polymer in the range of 
from about 0.01 to about 10, preferably from about 0.05 to about 5, and 
most preferably from 0.1 to 3 weight %; the polypropylene glycol polymer 
is present in the range of from about 0.01 to about 20, preferably from 
about 0.05 to about 15, and most preferably from 0.1 to 10 weight %; and 
the polysaccharide is present in the range of from about 0.01 to about 10, 
preferably from about 0.05 to about 5, and most preferably from 0.1 to 3 
weight %. Water makes up the rest of the additive composition. 
The composition of the second embodiment of the present invention can also 
be made by a variety of mixing means known to one skilled in the art such 
as, for example, blending. The individual components can be mixed in any 
order. 
According to the third embodiment of the present invention, a process for 
treating subterranean formations comprises contacting the formation with a 
composition which comprises, or consists essentially of, calcium chloride, 
an acrylamide-containing polymer, a polypropylene glycol, water, and 
optionally a polysaccharide. The scope of the acrylamide-containing 
polymer, polypropylene glycol, and polysaccharide is the same as that 
disclosed in the first embodiment of the invention. 
The weight percent of the individual components of the composition used in 
the third embodiment of the present invention can be any weight percent so 
long as the additive can increase the viscosity, or control the water 
loss, or inhibit the drill solids, or combinations of any two or more 
thereof, of a water-based fluid and can vary widely depending on the 
desired applications. Generally the additive of the present invention can 
contain calcium chloride in the range of from about 2,000 to about 
250,000, preferably from about 5,000 to about 250,000, more preferably 
from about 10,000 to about 250,000, even more preferably from about 25,000 
to about 200,000, and most preferably from 50,000 to 200,000 rag/l; the 
acrylamide-containing polymer in the range of from about 0.01 to about 10, 
preferably from about 0.05 to about 5, and most preferably from 0.1 to 3 
weight %; the polypropylene glycol polymer is in the range of from about 
0.01 to about 20, preferably from about 0.05 to about 15, and most 
preferably from 0.1 to 10 weight %; and the polysaccharide in the range of 
from about 0.01 to about 10, preferably from about 0.05 to about 5, and 
most preferably from 0.1 to 3 weight %. Water makes up the rest of the 
additive composition. 
The composition used in the third embodiment of the present invention can 
also be made by a variety of mixing means known to one skilled in the art 
such as, for example, blending. The individual components can be mixed in 
any order. 
The additive and/or water-based composition can be used in well treating, 
drilling, workover, or completion fluids in oil field operations by those 
skilled in the art. Generally, the liquid additive composition can be used 
in any drilled wells having a temperature in the range of from about 
50.degree. F. to about 500.degree. F., preferably 75.degree. F. to 
400.degree. F.

The following specific examples are intended to illustrate the advantages 
of the present invention and are not intended to unduly limit the scope of 
the invention. 
Example I 
This example illustrates that an acrylamide-containing polymer having 
repeat units derived from at least two monomers has the properties of 
inhibiting drill solids and increasing viscosity at high temperature. 
The runs were conducted by adding 93 grams of calcium chloride to 327 ml of 
tap water in glass quart jars then followed by mixing for 2 minutes. 
Unless otherwise indicated, a Multimixer was used for mixing and calcium 
chloride having activity of approximately 75% was used in all runs. While 
mixing the CaCl.sub.2 fluid samples, polymer shown in Table I was added 
and then all samples were mixed for about 1.5 hours. To each sample, 3 
balls (each ball prepared from 5 grams of wet drilled solids from a North 
Sea well) were added to the jars, the jars were capped, and then all 
samples were rolled at 150.degree. F. for about 16 hours. After cooling to 
about 80.degree. F., the balls were separated by screening the samples 
through a standard 4 mesh screen. The balls were reweighed after they were 
wiped with paper towels. The fluid samples were tested for viscosity at 
about 80.degree. F. according to the API RP 13B-1 procedure. Drill solid 
inhibition was calculated as follows: 
EQU Inhibition (%)=(Weight of 3 balls after rolling.div.15).times.100 
The results are shown in Table I. The abbreviations used in Table I are: 
AMPS, sodium 2-acrylamide-2-methylpropanesulfonate; NVP, 
N-vinyl-2-pyrrolidone; and Na-acrylate, sodium acrylate. 
TABLE I 
______________________________________ 
Run Polymer (gram).sup.a 
AV.sup.b 
Inhibition 
______________________________________ 
1 None 2.0 00% 
2 Kelco's XC .RTM. Polymer (2.0) 
19.5 30% 
3 Kem-Seal from INTEQ (5.0) 
6.0 00% 
4 #0 (5.0) 16.5 31% 
5 #1 (5.0) 30.5 108% 
6 #2 (5.0) 34.5 106% 
7 #3 (5.0) 32.5 109% 
8 #4 (5.0) 36.5 100% 
9 #5 (5.0) 37.0 107% 
10 #6 (5.0) 13.0 00% 
11 #7 (5.0) 18.0 68% 
12 #8 (5.0) 36.0 107% 
______________________________________ 
.sup.a The polymer composition of each polymer was: 
XC polymer is a xanthan gum obtained from Kelco Oil Field Group, Inc., 
Houston, Texas. 
KemSeal is reported as a copolymer of AMPS and acrylic acid obtained from 
Baker Houghes INTEQ, Houston, Texas. 
#0 = copolymer of 90% AMPS and 10% NVP. 
#1 = copolymer of 50% Acrylamide and 50% AMPS. 
#2 = terpolymer of 50% Acrylamide, 40% AMPS and 10% NaAcrylate. 
#3 = terpolymer of 50% Acrylamide, 40% AMPS, 8% NaAcrylate and 2% NVP. 
#4 = terpolymer of 60% Acrylamide, 38% AMPS, and 2% NVP. 
#5 = terpolymer of 40% Acrylamide, 50% AMPS, 5% NaAcrylate, and 5% NVP. 
#6 = terpolymer of 10% Acrylamide, 70% AMPS, 5% NaAcrylate, and 15% NVP. 
#7 = terpolymer of 15% Acrylamide, 55% AMPS, and 30% NVP. 
#8 = copolymer of 60% Acrylamide and 40% AMPS. 
.sup.b AV, apparent viscosity, cps. 
The above test results show that those polymers containing 15% or more 
acrylamide (runs 5-9, 11 and 12) as one of the monomers, provided 
excellent inhibition properties in CaCl.sub.2 fluids. 
Example II 
This example illustrates shale inhibition of the invention composition. 
The runs were carried out as follows. Five compositions shown in Table II 
were prepared by mixing the components shown in the Table II in quart 
jars. After addition of each component, the mixing was continued for about 
10 minutes. After all components were mixed, the compositions were mixed 
using a Multimixer for about 1 hour before they were used in Test 1 and 
Test 2 described below. 
In Test 1, about 20 ml of sample were transferred into plastic weighing 
dishes and 3 bentonite tablets (Volclay/Pure Gold Tablets 1/4" obtained 
from Colloid Environmental Technologies Company, Arlington Heights, Ill.) 
were added to the 20 ml sample in each dish. Pictures of these dishes with 
tablets were taken at 30 seconds, 1 minute, 5 minutes, 6 hours, and 72 
hours. These pictures showed that the bentonite tablets disintegrated in 
runs 21, 22, and 25 (Table II) in 5 minutes, whereas runs 23 and 24 (see 
Table II) showed excellent inhibiting properties by protecting the tablets 
for at least 72 hours. 
In Test 2, about 300 ml of sample were placed in pint jars. Three (3) 
pieces of drilled cuttings from Ecofisk Bravo well B-103 of North Sea, 
after the pieces were weighed and photographed, were added to each jar. 
The jars were capped and then rolled 16 hours at about 176.degree. F. in 
an oven. After cooling to about 80.degree. F. the samples were screened 
through a 70 mesh screen. The residues recovered on the screen were kept 
for 30 minutes in an already heated oven and maintained at 250.degree. F. 
and thereafter, weighed and photographed again. 
The results of Test 2 are shown in Table II. 
TABLE II 
______________________________________ 
Initial Weight 
Weight of 
Cutting 
Run.sup.a 
of 3 Pieces, g 
Residue, g 
Recovered, %.sup.b 
______________________________________ 
21 19.60 2.55 13.0 
22 22.37 2.93 13.1 
23 22.38 17.37 77.6 
24 27.31 11.56 42.3 
25 31.45 5.01 15.9 
______________________________________ 
.sup.a The compositions used are as follows: 
21: 350 ml of 10.5 pounds per gallon (ppg) CaCl.sub.2 brine + 50% W/V NaO 
solution adjusted to pH of 8.5 
22: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5). 
23: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 10 g PPG 4000 + 3 g 
Polymer #1 (see Table I) where PPG 4000 is a polypropylene glycol having 
molecular weight of about 4000. 
24: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 3 g Polymer #1. 
25: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 10 g PPG 4000. 
.sup.b Cutting recovered, % = (weight of residue .div. initial weight of 
pieces) .times. 100. 
The results show that the maximum cutting recovery of 77.6% was obtained 
with the fluid in 23. These results indicate that a drilling fluid similar 
to that in 23 can be used for drilling water-sensitive formations because 
it prevents disintegration of "gumbo" cuttings. 
Example III 
This example illustrates the rheology and fluid loss of drilling fluids 
using the inventive composition. 
The runs were carried out as follows. Five compositions shown in Table III 
were prepared by mixing the component shown in the Table in quart jars. 
After addition of each component, the contents of the jar were mixed for 
about 10 minutes. Before the addition of OCMA clay to represent drill 
solids, all mixed fluids were mixed for about one hour to simulate field 
condition. After addition of OCMA clay and mixing for 10 minutes, the 
compositions were tested initially at about 83.degree. F. according to the 
API RP 13B-1 procedure. These test results are presented in Table III 
under "Initial Results". The compositions were then rolled for 16 hours in 
capped jars at 176.degree. F., cooled to about 80.degree. F., and retested 
after the compositions were mixed for 5 minutes. These test results are 
represented in Table III under "Results After Rolling at 176.degree. F.". 
TABLE III 
______________________________________ 
Initial Results Results After Rolling at 176.degree. F. 
PV.sup.d / PV.sup.d / 
Run.sup.a 
600/300.sup.b 
AV.sup.c 
YP.sup.e 
600/300.sup.b 
AV.sup.c 
YP.sup.e 
FL.sup.f 
______________________________________ 
31 11/6 5.5 5/1 12/6 6 6/0 340 
32 24/12 12.0 12/0 24/12 12 12/0 56.4 
33 28/14 14.0 14/0 28/14 14 14/0 20.4 
34 30/15 15.0 15/0 40/20 20 20/0 142 
35 37/19 18.5 18/1 48/24 24 24/0 44 
______________________________________ 
.sup.a The composition of each run is as follows: 
31: 340 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 10 g PPG 4000 + 15 g 
OCMA clay which is primarily a montmorillonite clay. 
32: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 3 g Polymer #1 (run 5) 
in Table I OCMA clay. 
33: 340 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 10 g PPG 4000 + 3 g 
Polymer #1 in Table I + 15 g OCMA clay. 
34: 350 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 5 g Polymer #1 in Tabl 
I + 15 g OCMA clay. 
35: 340 ml of 10.5 ppg CaCl.sub.2 brine (pH 5.5) + 10 g PPG 4000 + 5 g 
Polymer #1 in Table I + 15 g OCMA clay. 
.sup.b Readings in this column refer to the readings of a directindicatin 
115volt motordriven viscometer (API RP 13B1, June 1, 1990, Section 24a) a 
600/300 rpm, respectively. 
.sup.c AV -- apparent viscosity, cps. 
.sup.d PV -- plastic viscosity, cps. 
.sup.e YP -- yield point, lbs/100 sq. ft. 
.sup.f FL -- fluid loss at room temperature, ml/30 minutes. 
These results show that drilling fluids containing PPG 4000 and Polymer #1 
(runs 33 and 35) had higher viscosities and lower fluid loss than the 
fluids containing either PPG 4000 (run 31) or Polymer #1 (runs 32 and 34). 
Example IV 
This example illustrates that drilling fluids containing the inventive 
compositions which contain blends of an acrylamide-containing copolymer 
and hydroxyethyl cellulose have lower fluid loss than the drilling fluids 
that contain only either the copolymer or hydroxyethyl cellulose. 
The runs were carried out by mixing the components shown in Table IV to 
prepare approximately 350 ml of each of nine drilling fluid compositions 
in quart jars. The mixing time after the addition of each component is 
shown in Table IV. Bentonite clay represented drill solids. Polymers were 
added before adding bentonite to simulate the field use. After the mixing 
was completed, the fluids were kept at about 75.degree. F. They were then 
mixed for 5 minutes, transferred into pint jars, and tested at about 
85.degree. F. These test results are reported under "Initial Results" in 
Table V. The fluids were then rolled for about 16 hours in sealed pint 
jars in an oven at 160.degree. F., cooled to about 85.degree. F., and 
retested after mixing for 5 minutes. These test results are reported in 
Table V under "After Rolling at 160.degree. F.". 
TABLE IV 
______________________________________ 
Run Materials Used 
______________________________________ 
41 307 ml tap water + 113 g CaCl.sub.2 (5 minutes) + 2 g PPG 4000 
(5 minutes) + 5 g attapulgite clay (90 minutes) + 10 g bentonite 
clay (30 minutes) 
42 307 ml tap water + 113 g CaCl.sub.2 (5 minutes) + 2 g PPG 4000 
(5 minutes) + 5 g attapulgite clay (30 minutes) + 0.5 g Polymer 
#1.sup.a 
(60 minutes) + 10 g bentonite clay (30 min) 
43 Same as #42 except 1.0 g Polymer #1 
44 Same as #42 except 2.0 g Polymer #1 
45 Same as #42 except 0.5 g HEC 25.sup.b in place of Polymer #1 
was used 
46 Same as #43 except 1.0 g HEC 25 in place of Polymer #1 was used 
47 Same as #44 except 2.0 g HEC 25 in place of Polymer #1 
was used 
48 Same as 444 except 2.0 g Blend-A.sup.c in place of Polymer #1 
was used 
49 Same as 444 except 2.0 g Blend-B.sup.d in place of Polymer #1 
was used. 
______________________________________ 
.sup.a See Table I for Polymer #1 composition. 
.sup.b HEC 25 is hydroxyethyl cellulose obtained from Union Carbide 
Corporation. 
.sup.c BlendA is a blend of 0.5 g Polymer #1 and 0.5 g HEC 25. 
.sup.d BlendB is a blend of 1.5 g Polymer #1 and 0.5 g HEC 25. 
TABLE V 
______________________________________ 
Initial Results After Rolling at 160.degree. F. 
Run AV.sup.a 
PV/YP.sup.a 
FL.sup.a 
AV.sup.a 
PV/YP.sup.a 
FL.sup.a 
______________________________________ 
41 4.5 4/1 &gt;200 4.5 4/1 207 
42 5.5 5/1 &gt;100 6.0 6/0 142 
43 8.0 7/2 &gt;100 7.5 7/1 98.6 
44 11.5 10/3 &gt;50 10.5 9/3 73.4 
45 10.0 9/2 12.6 9.5 9/1 14.3 
46 20.5 14/13 7.2 19.0 14/10 8.6 
47 55.5 26/59 5.4 55.5 26/59 4.8 
48 11.0 10/2 7.2 9.5 9/1 8.9 
49 15.5 14/3 3.8 14.5 13/3 3.8 
______________________________________ 
.sup.a See TABLE III. 
Fluid loss results of runs 48 and 49 were unexpected. From test results 
shown in runs 42, 43, 45, and 46, 1.0 gram of Blend-A (run 48) was 
expected to give higher fluid loss than the results shown. Similarly, 
Blend-B (run 49) provided lower fluid loss than the fluid loss expected 
from test results shown in runs 44, 45, and 47. 
Example V 
This example illustrates that the inventive composition containing an 
acrylamide-containing copolymer, HEC Polymer, and PPG 4000 has higher 
shale inhibition than the composition without PPG 4000 when used in 
drilling fluids. 
The runs were carried out as follows. Approximately 350 ml of each of four 
drilling fluid compositions shown in Table VI were prepared by mixing the 
materials in quart jars. The mixing time after the addition of each 
material is shown in Table VI. After mixing all materials, the jars were 
capped and kept at about 75.degree. F. for 16 hours. The fluids were then 
stirred for 10 minutes, transferred into pint jars, and tested for 
viscosity. Bentonite tablets described in Example II were then weighed and 
placed in each fluid. After the jars were capped, the fluids were rolled 
for 2 hours in a roller oven at 150.degree. F. Residues of the bentonite 
tablets were then separated by screening the fluids through a 20 mesh 
screen. The residues were washed gently with tap water, dried at 
250.degree. F., and weighed. These test results are provided in Table VII. 
The test results in Table VII show that the drilling fluids containing the 
inventive composition (run 52) provides the maximum shale inhibition. The 
fluid composition (run 53) that contained all components of run 52 except 
the acrylamide-containing polymer provided the least inhibition. Run 54, 
which contained NaCl brine instead of CaCl.sub.2 brine in the fluid 
composition, is more inhibitive than the composition that did not contain 
PPG 4000 (run 51). These test results demonstrate that the drilling fluid 
similar to run 52 containing the invention composition can be used for 
drilling water-sensitive formations where many water-based drilling fluids 
cause problems. 
TABLE VI 
______________________________________ 
Run Materials Used 
______________________________________ 
51 307 ml tap water + 113 g CaCl.sub.2 (10 minutes) + 5 g attapulgite 
clay 
(10 minutes) + 3 g Blend-C (30 minutes) 
52 299 ml tap water + 110 g CaCl.sub.2 (10 minutes) + 10 g PPG 4000 
(10 
minutes) + 5 g attapulgite clay (10 minutes) + 3 g Blend-C.sup.a 
(30 minutes) 
53 299 ml tap water + 110 g CaCl.sub.2 (10 minutes) + 10 g PPG 4000 
(10 
minutes) + 5 g attapulgite clay (10 minutes) + 1 g HEC 25 
(30 minutes) 
54 299 ml tap water + 110 g NaCl (10 minutes) + 10 g PPG 4000 (10 
minutes) + 5 g attapulgite clay (10 minutes) + 3 g Blend-C 
(30 minutes) 
______________________________________ 
.sup.a Blend-C = Blend of 75 weight % Polymer #1 (see Table I) and 25 
weight % HEC 25. 
TABLE VII 
______________________________________ 
Weight of 
Bentonite Tablets, g 
Weight of Residue 
Run AV W1 W2 W3 Inhibition, % 
______________________________________ 
51 31.5 10.28 9.59 8.45 88.1 
52 39.5 10.25 9.56 9.33 97.6 
53 27.0 10.18 9.50 7.59 79.9 
54 39.0 10.21 9.53 8.74 91.7 
______________________________________ 
Moisture content of Bentonite Tablets was 93.3 weight % 
W2 = 0.933 .times. W1 
Inhibition, % = (W3/W2) .times. 100 
Example VI 
This example illustrates that the drilling fluid containing the invention 
composition which contains an acrylamide-containing copolymer, HEC 
Polymer, and PPG 4000 is less corrosive toward metals than the composition 
which does not contain PPG 4000. 
To conduct the runs, approximately 350 ml of each of six drilling fluid 
compositions shown in Table VIII were prepared by mixing the materials in 
quart jars. After each material was added, the mixing was continued for 10 
minutes. After all materials were mixed, the jars were capped and kept at 
room temperature (about 25.degree. C.) for about 18 hours. The fluid 
compositions were then stirred 10 minutes and, immediately after the 
stirring, approximately 210 ml of each sample was transferred into 215 ml 
glass bottles for measuring corrosion rate according to the Wheel test 
which is well known to one skilled in the art. The conditions used for the 
corrosion rate test were: Test vapor-ambient, time(T)--28 hours, and 
temperature--120.degree. F. Corrosion coupons:Material--carbon steel; 
density(D)--7.88 g/cc; area (A)--calculated; length--3.0 inches; 
thickness--0.005 inch; and total used--2. Initial and final weights of the 
two corrosion coupons in each run were measured to determined weight loss 
(.DELTA.W). 
TABLE VIII 
______________________________________ 
Run Materials Used MPY.sup.a 
pH 
______________________________________ 
61 245 ml tap water + 90 g CaCl.sub.2 + 4 g Blend-C.sup.b 
11.3 8.2 
62 245 ml tap water + 90 g CaCl.sub.2 + 4 g Blend-C + 
5.9 8.0 
2 g PPG 4000 
63 245 ml tap water + 90 g CaCl.sub.2 + 4 g Blend-C + 
5.6 7.9 
2 g PEG 8000.sup.b 
64 245 ml tap water + 90 g CaCl.sub.2 + 4 g attapulgite 
16.9 7.6 
clay + 4 g Blend-C + 8 g bentonite clay 
65 245 ml tap water + 90 g CaCl.sub.2 + 4 g attapulgite 
13.5 7.0 
clay + 0.4 g PPG 4000 + 4 g Blend-C + 
8 g bentonite clay 
66 245 ml tap water + 90 g CaCl.sub.2 + 4 g attapulgite 
17.9 6.9 
clay + 0.4 g PEG 8000.sup.c + 4 g Blend-C + 
8 g bentonite clay 
______________________________________ 
.sup.a MPY = Corrosion rate in mills per year calculated as: 
##STR1## 
.sup.b See Table VI. 
.sup.c PEG 8000 = Polyglycol E8000, a polyethylene glycol having molecula 
weight of about 8000, obtained from Dow Chemicals. 
As shown in Table VIII, the corrosion rate was lower in fluids containing 
PPG 4000 (runs 62 and 65) than the fluids which did not contain PPG 4000 
(runs 61 and 64). The drilling fluid composition containing PEG 8000 (run 
66) as described in U.S. Pat. No. 4,425,241 was very corrosive as compared 
to the PPG 4000 containing drilling fluid (run 65). 
Example VII 
This example illustrates that drilling fluid composition containing an 
acrylamide-containing copolymer, HEC Polymer, and PPG 4000 has lower fluid 
loss and higher viscosity than the fluid composition without PPG 4000. 
The runs were carried out as follows. Five drilling fluid compositions 
shown in Table IX were prepared by mixing the materials in quart jars. 
After addition of each material, the mixing was continued for 10 minutes. 
After all materials were mixed, the jars were capped and rolled for 2 
hours in a roller oven at 100.degree. F. After cooling to about 80.degree. 
F., the fluids were mixed for 5 minutes, transferred into pint jars, and 
tested at about 90.degree. F. These test results are provided under 
"Initial Results" in table X. The jars were then capped and static aged 
for 16 hours at 176.degree. F. After cooling to about 80.degree. F. and 
mixing 5 minutes, the fluids were retested at 90.degree. F. These test 
results are provided under "After Aging at 176.degree. F." in Table X. 
The results in Table X show that the drilling fluid composition containing 
the inventive composition (run 72), provided lower fluid loss and higher 
rheology than the fluid without PPG 4000 (run 73). The composition of run 
74, which contained PPG 4000 but did not contain either HEC or Polymer #1, 
produced unacceptably high fluid loss. Similar to test results in Example 
III, the fluid composition of run 75, which contained Polymer #1 and PPG 
4000, gave better fluid loss than run 74. The test results of runs 71 and 
72 further indicate that the addition of attapulgite clay significantly 
lowered fluid loss. 
TABLE IX 
______________________________________ 
Run Materials Used 
______________________________________ 
71 299 ml tap water + 110 g CaCl.sub.2 + 10 g PPG 4000 + 4 g 
Blend-C.sup.a + 10 g bentonite clay 
72 299 ml tap water + 110 g CaCl.sub.2 + 5 g attapulgite clay + 10 g 
PPG 4000 + 4 g Blend-C + 10 g bentonite clay 
73 307 ml tap water + 113 g CaCl.sub.2 + 5 g attapulgite clay + 4 g 
Blend-C + 10 g bentonite clay 
74 299 ml tap water + 110 g CaCl.sub.2 + 5 g attapulgite clay + 10 g 
PPG 4000 + 10 g bentonite clay 
75 299 ml tap water + 110 g CaCl.sub.2 + 5 g attapulgite clay + 10 g 
PPG 4000 + 4 g Polymer #1.sup.b + 10 g bentonite clay 
______________________________________ 
.sup.a See Table VI 
.sup.b see Table I. 
TABLE X 
______________________________________ 
Initial Results After Aging at 176.degree. F. 
Run AV.sup.a 
PV/YP.sup.a 
FL.sup.a 
AV PV/YP FL HTHPFL.sup.b 
______________________________________ 
71 54.5 28/53 49.6 52.5 29/47 43.3 -- 
72 53.5 31/45 4.2 48.5 30/37 3.5 12.8 
73 49.0 30/38 6.3 41.0 26/30 6.6 18.4 
74 12.0 12/0 &gt;100 -- -- -- -- 
75 27.0 23/8 45.4 25.0 22/6 46.2 -- 
______________________________________ 
.sup.a See Table III. 
.sup.b HTHPFL (high temperature high pressure fluid loss) -- fluid loss 
measured at 200.degree. F. and 500 psi differential pressure. 
Example VIII 
This example illustrates that drilling fluid composition containing 
attapulgite clay provides lower fluid loss than the composition containing 
bentonite clay. Furthermore, if attapulgite was added to the composition 
before the acrylamide-containing and HEC polymers were added, the fluid 
loss was much lower. 
The runs were carried out as follows. Six drilling fluid compositions shown 
in Table XI were prepared and tested according to the test procedures 
described in Example VII. These test results are shown in Table XII. 
Test results in table XII show that the drilling composition containing 
attapulgite clay (run 81) had lower fluid loss than the composition that 
contained bentonite clay (run 82). Both clays were helpful for reducing 
fluid loss, which is evident from the test results of runs 81, 82, and 83. 
The fluid test results of runs 81, 84, 85, and 86 indicate that the 
compositions had the lowest fluid loss when attapulgite was mixed in the 
compositions before the addition of polymers as in runs 81 and 85. 
TABLE XI 
______________________________________ 
Run Materials Used 
______________________________________ 
81 299 ml tap water + 90 g CaCl.sub.2 + 2 g PPG 4000 + 5 g attapulgite 
clay + 4 g Blend-C + 10 g OCMA clay 
82 299 ml tap water + 90 g CaCl.sub.2 + 2 g PPG 4000 + 5 g bentonite 
clay + 4 g Blend-C + 10 g OCMA clay 
83 299 ml tap water + 90 g CaCl.sub.2 + 2 g PPG 4000 + 4 g 
Blend-C.sup.a + 
10 g OCMA clay 
84 299 ml tap water + 90 g CaCl.sub.2 + 2 g PPG 4000 + 4 g Blend-C + 
5 g attapulgite clay + 10 g OCMA clay 
85 307 ml tap water + 113 g CaCl.sub.2 + 2 g PPG 4000 + 5 g 
attapulgite 
clay + 3 g Blend-C + 10 g bentonite clay 
86 307 tap water + 113 g CaCl.sub.2 + 2 g PPG 4000 + 3 g Blend-C + 
5 g attapulgite clay + 10 g bentonite clay 
______________________________________ 
.sup.a See Table VI. 
TABLE XII 
______________________________________ 
Initial Results After Aging at 176.degree. F. 
Run AV.sup.a 
PV/YP.sup.a 
FL.sup.a 
AV PV/YP FL 
______________________________________ 
81 45.5 26/39 4.6 41.5 25/33 3.5 
82 44.5 25/39 6.1 46.5 27/39 6.0 
83 46.5 25/43 7.9 47.0 27/40 9.2 
84 50.5 27/47 5.7 46.5 27/39 5.3 
85 30.5 22/17 3.9 26.5 21/11 3.3 
86 32.0 21/22 7.2 29.5 21/17 6.2 
______________________________________ 
.sup.a See Table III. 
Example IX 
This example illustrates that calcium tolerant polymers such as 
carboxymethyl hydroxyethyl cellulose (CMHEC) can also be used for fluid 
loss control in drilling fluids. 
The runs were conducted as follows. Two drilling fluid compositions in 
Table XIII were prepared and tested according to the procedure described 
in Example IV. Run 91 was the same as rum 47. As shown in Table XIII, the 
fluid containing CMHEC (run 92) had lower viscosity than the 
HEC-containing fluid (run 91), even though both fluids gave very low fluid 
loss. These results indicate that any calcium tolerant polymer can be used 
in the inventive drilling fluid. 
TABLE XIII 
______________________________________ 
Initial Results After Rolling at 160.degree. F. 
Run.sup.a 
AV.sup.b 
PV.sup.b /YP.sup.b 
FL AV PV/YP FL 
______________________________________ 
91 55.5 26/59 5.4 55.5 26/59 4.8 
92 8.0 8/0 5.4 8.0 8/0 5.2 
______________________________________ 
.sup.a Run 91 was the same as run 47 and run 92 was the same as run 91 
except 2.0 g CMHEC (Tylodrill .TM. obtained from Hoechst 
Aktiengesellschaft, Frankfurt, Germany) was used in place of HEC 25. 
.sup.b See Table III. 
The results shown in the above examples clearly demonstrate that the 
present invention is well adapted to carry out the objects and attain the 
ends and advantages mentioned as well as those inherent therein. While 
modifications may be made by those skilled in the art, such modifications 
are encompassed within the spirit of the present invention as defined by 
the disclosure and the claims.