Note: Descriptions are shown in the official language in which they were submitted.
CA 0221820~ 1997-10-14
WELL DRILLING AND SERVIC~NG FLUIDS AND METHODS OF
REDUC~NG FLUID LOSS AND POLYMER CONCENTRATION THEREOF
This patent application is a continuation-in-part of application Serial Number
08/217,726 filed 03/25194.
Prior Art
The use of fluids for conducting various operations in the boreholes of
subterranean oil and gas wells which contact a producing formation are well known.
Thus drill-in fluids are utilized when initially drilling into producing formations.
Completion fluids are utilized when conducting various completion operations in
0 the producing formations. Workover fluids are utilized when conducting workover
operations of previously completed wells.
One of the most important functions of these fluids is to seal off the face of the
wellbore so that the fluid is not lost to the formation. Ideally this is accomplished
by depositing a filter cake of the solids in the fluid over the surface of the borehole
without any loss of solids to the formation. In other words, the solids in the fluid
bridge over the formation pores rather than permanently plugging the pores. This is
particularly critical in conducting horizontal drilling operations within the producing
formations.
Many clay-free fluids have been proposed for contacting the producing zone of
oil and gas wells. See for example the following U.S. Patents: Jackson et al.
3,785,438; Alexander 3,872,018; Fischer et al. 3,882,029; Walker 3,956,141;
Smithey 3,986,964; Jackson et al. 4,003,838; Mondshine 4,175,042; Mondshine
CA 0221820~ 1997-10-14
4,186,803; Mondshine 4,369,843; Mondshine 4,620,596; and Dobson, Jr. et al.
4,822,500.
These fluids generally contain polymeric viscosifiers such as certain
polysaccharides or polysaccharide derivatives, polymeric fluid loss control additives
s such as lignosulfonates, polysaccharides or polysaccharide derivatives, and bridging
solids. As disclosed in Dobson, Jr. et al. U.S. Patent No. 4,822,500, the polymeric
viscosifier and the polymeric fluid loss control additive may synergistically interact
to provide suspension and fluid loss control in such fluids.
After the wellbore fluid has completed its desired functions, it is desirable to
0 remove the filter cake before placing the well on production. The filter cake
contains the polymers and bridging solids present in the wellbore fluid as well as any
other non-soluble solids present therein. One such method of removing the filter
cake is disclosed in Mondshine et al. U.S. Patent No. 5,238,065. This method
comprises contacting the filter cake with an acidic brine fluid containing certain
1S peroxides for a period of time sufficient to decompose the polysaccharide polymers
in the filter cake, and preferably thereafter contacting the filter cake with a fluid in
which the bridging particles are soluble.
Summarv of the Invention
The present invention provides (1) a method of reducing the fluid loss of well
20 drilling and servicing fluids which contain at least one polymeric viscosifier, at least
one polymeric fluid loss control additive, and a water soluble bridging agent
suspended in an aqueous liquid in which the bridging agent is not soluble, (2) a
CA 0221820~ 1997-10-14
method of reducing the concentration of polymer required to provide a desired
degree of fluid loss control to such fluids, (3) well drilling and servicing fluids
having decreased fluid loss and/or polymer concentration therein, and (4) a water
soluble bridging agent for well drilling and servicing fluids in which the
concentration of particles less than about 10 llm is greater than about 10% by
weight. The invention comprises incorporating in the fluid the particulate, water
soluble, bridging agent in which the concentration of particles less than about 10
,um is greater than about 10% by weight of the bridging agent, most preferably at
least about 12%.
o Thus it is an object of this invention to provide a method of reducing the fluid
loss of well drilling and servicing fluids which contain at least one polymeric
viscosifier, at least one polymeric fluid loss control additive, and a water soluble
bridging agent suspended in a liquid in which the bridging agent is not soluble.It is another object of the invention to provide a method of reducing the
concentration of polymer required to provide a desired degree of fluid loss control
to such fluids.
Another object of this invention is to provide well drilling and servicing fluids
having decreased fluid loss and/or polymer concentration therein as compared to
prior art fluids.
Still another object of the invention is to provide a bridging agent for well
drilling and servicing fluids in which the concentration of particles, less than about
10 llm is greater than about 10% by weight of the bridging agent.
CA 0221820~ 1997-10-14
These and other objects of the invention will be obvious to one skilled in the art
on reading this specification and the claims appended hereto.
While the invention is susceptible to various modifications and alternative forms,
specific embodiments thereof will hereinafter be described in detail and shown by
5 way of example. It should be understood, however, that it is not intended to limit
the invention to the particular forms disclosed, but, on the contrary, the invention is
to cover all modifications and alternatives falling within the spirit and scope of the
invention as expressed in the appended claims.
The compositions can comprise, consist essentially of, or consist of the stated
o materials. The method can comprise, consist essentially of, or consist of the stated
steps with the stated materials.
CA 0221820~ 1997-10-14
Detailed Description of the Invention
We have now discovered that the fluid loss of certain polymer-cont~inin~, well
drilling and servicing fluids as set forth hereinafter can be decreased by
incorporating therein a particulate, water soluble, bridging agent in which the
s concentration of particles less than about 10 !lm is greater than about 10% by
weight of the bridging agent, most preferably at least about 12%. Alternatively, we
have discovered that for any desired degree of fluid loss control of certain polymer-
containing well drilling and servicing fluids, the polymer concentration can be
decreased by incorporating in the fluids a particulate, water soluble, bridging agent
o in which the concentration of particles less than about 10 ~m is greater than about
10% by weight of the bridging agent, most preferably at least about 12%. Well
drilling and servicing fluids having decreased fluid loss or polymer concentration
therein are provided wherein the fluids contain a bridging agent in which the
concentration of particles less than about 10 ~m is greater than about 10% by
15 weight ofthe bridging a~,ent, preferably at least about 12% by weight.
Hereinafter the term "BA10/10" may be used herein and is intended to mean the
particulate, water soluble, bridging agent in which the concentration of particles less
than about 10 lam is greater than about 10% by weight of the bridging agent.
The well drilling and servicing fluids to wllich this invention pertains contain at
20 least one polymeric viscosifier or suspending agent, at least one polymeric fluid loss
control additive, and a water soluble bridging agent suspended in an aqueous liquid
CA 0221820=7 1997-10-14
in which the bridging agent is not soluble. See for example U.S. patents 4,175,042
(Mondshine) and 4,822,500 (Dobson et al.), each incorporated herein by reference.
The colloidal properties of polymers greatly affect the role of such polymers in
well drilling and servicing fluids. They have a strong affinity for water. They
5 develop highly swollen gels in low concentrations. Most polymers do not swell as
much in salt water as they do in fresh water; however, they nevertheless provide
slimy particles of such size as to resist the flow of water through a filter cake.
These versatile polymers make practical the use of low-solids, non-dispersive well
drilling and servicing fluids. The great diversity in composition and properties of
0 the polymers used in well drilling and servicing fluids requires an examination of the
factors involved in the selection of a polymer for a specific application. Among the
factors which affect performance are the effects of temperature, shear conditions,
dissolved salts, pH, and stability to microorg~nisms. Other factors considered in
choosing a polymer include ease of degradation, ease of handling and mixing,
5 possible environmental and health effects, and the cost of the polymer.
Polymeric viscosifiers or suspending agents used in well drilling and servicing
fluids include certain natural gums, synthetic gums (called biopolymers since they
are produced by bacterial or fungal action on suitable substrates), polysaccharide
derivatives, and synthetic copolymers. Representative polymeric viscosifiers or
20 suspending agents include xanthan gum; welan gum; gellan gum; guar gum;
hydroxyalkyl guar gums such as hydroxypropyl guar, hydroxyethyl guar,
carboxymethyl hydroxypropyl guar, dihydroxypropyl guar. and the like; cellulose
CA 0221820~ 1997-10-14
ethers such as carboxymethyl cellulose, hydroxyethyl cellulose, carboxymethyl
hydroxyethyl cellulose, and the like; polyacrylates; ethylene oxide polymers; and the
like. The preferred polymeric viscosifiers or suspending agents are xanthan gum,
welan gum, gellan gum, hydroxyalkyl guar gum, high viscosity (high molecular
5 weight) carboxymethyl cellulose, and mixtures thereof, most preferably xanthan
gum.
Polymeric fluid loss control additives used in well drilling and servicing fluids
include pregelatized starch, starch derivatives, cellulose derivatives, lignocellulose
derivatives, and synthetic polymers. Representative starch derivatives include:
lo hydroxyalkyl starches such as hydroxyethyl starch, hydroxypropyl starch,
hydroxyethyl carboxymethyl starch, the slightly crosslinked derivatives thereof, and
the like; carboxymethyl starch and the slightly crosslinked derivatives thereof;
cationic starches such as the tertiary aminoalkyl ether derivatives of starch, the
slightly crosslinked derivatives thereof, and the like. Representative cellulose
5 derivatives include low molecular weight carboxymethyl cellulose, and the like.
Representative lignocellulose derivatives include the alkali metal and alkaline earth
metal salts of lignosulfonic acid and graft copolymers thereof. Representative
synthetic polymers include partially hydrolyzed polyacrylamides, polyacrylates, and
the like. The preferred polymeric fluid loss control additives are the starch ether
20 derivatives such as hydroxyethyl starch, hydroxypropyl starch, dihydroxypropyl
starch, carboxymethyl starch, and cationic starches, and carboxymethyl cellulose.
Most preferably the polymeric fluid loss control additive is a starch ether derivative
CA 0221820~ 1997-10-14
which has been slightly crosslinked, such as with epichlorohydrin, phosphorous
oxychloride, soluble trimetaphosphates, linear dicarboxylic acid anhydrides, N,N'-
methylenebisacrylamide, and other reagents containing two or more functional
groups which are able to react with at least two hydroxyl groups. The preferred
5 crosslinking reagent is epichlorohydrin. Generally the treatment level is from about
0.005% to 0.1% of the starch to give a low degree of crosslinking of about one
crosslink per 200 to 1000 anhydroglucose units. In accordance with the teachings
of co-pending U.S. patent application Serial Number 08/512676 filed 08/08/95, the
starch or starch derivative can be partially hydrolyzed to decrease the degree of
o polymerization thereof.
The bridging agents useful in this invention are bridging agents known in the art
which are modified to increase the concentration of particles therein which have a
particle size less than about 10 ~m. They are solid, particulate, water soluble salts
the particles of which have been sized to have a particle size distribution suff1cient
5 to seal offthe pores of the formations contacted by the well drilling and servicing
fluid. The bridging agent must not be soluble in the liquid used to prepare the fluid.
Representative water soluble salts include sodium chloride, potassium chloride,
calcium chloride, sodium formate, potassium formate, sodium bromide, potassium
bromide, calcium bromide, sodium acetate, potassium acetate, and the like. The
20 preferred bridging agent is sodium chloride.
It is preferred that the liquid comprises a saturated solution of one or more
water soluble salts, such as the chloride, bromide, formate or acetate salts of
CA 0221820~ 1997-10-14
sodium, potassium, or calcium, most preferably sodium chloride, sodium bromide, or
calcium chloride.
The BA10/10 of this invention may be any solid, particulate, water soluble salt
having the required particle size which is insoluble in the liquid used to prepare the
5 well drilling and servicing fluid. It may for instance be a bridging agent which has
been ground to the particle size required. Alternatively, a finely ground salt can be
added to a salt having a low concentration of particles less than about 10 llm in
order to provide the bridging agent having at least about 10% of the particles
thereof less than about 10 lam.
o The bridging agent of this invention preferably has a particle size distribution
such that: from about 5% to about 30% of the particles thereof are less than about 5
~m; from about 10% to about 50% of the particles thereof are less than about 10
~m; from about 15% to about 60% of the particles thereof are less than about 15
m; from about 25% to about 70% of the particles thereof are less than about 20
s lam; from about 45% to about 80% of the particles thereof are less than about 30
m; from about 55% to about 90% of the particles thereof are less than about 40
llm; from about 60% to about 95% of the particles thereof are less than about 44
,um; from about 65% to about 95% of the particles thereof are less than about 50
llm; and from about 80% to about 100% of the particles are less than about 80 ,um.
20 ~lost preferably, the BA10/10 of this invention has a particle size distribution
such that: from about 5% to about 25% of the particles thereof are less than about 5
llm; from about 12% to about 45% of the particles thereof are less than about 10
CA 0221820', 1997-10-14
~m; from about 20% to about 50% of the particles thereof are less than about 15
m; from about 30% to about 65% of the particles thereof are less than about 20
~m; from about 50% to about 75% of the particles thereof are less than about 30
~m; from about 60% to about 85% of the particles thereof are less than about 40
5 !lm; from about 65% to about 90% of the particles thereof are less than about 44
m; from about 70% to about 95% of the particles thereof are less than about 50
~m; and from about 85% to about 100% ofthe particles are less than about 80 ~m.
The concentration of BA10/10 must be sufficient to bridge, seal off, and reduce
the fluid loss of the well drilling and servicing fluid in wllich it is incorporated.
o Generally, a concentration of BA10/10 from about 14 kg/m3 to about 570 kglm3
will be used, preferably from about 28 kg/m3 to about 428 kg/m3.
Well drilling and servicing fluids as described herein having a desired degree of
filtration control can be formulated to contain less polymer by incorporating the
BA10/lO in the fluids. This results in a fluid having a lower viscosity at circulating
15 shear rates, and a lower cost. Polymer concentrations may be reduced by up to
about 50% in specific fluid fom1ulations. The reduction in polymer concentration
also provides for more efficient filter cake removal from the sides of the borehole in
hydrocarbon producing formations. Filter cakes containin(J less polymer are more
easily decomposed when utilizing polymer degradin(J compositions, such as those
20 disclosed in Mondshine et al. U.S. Patent No. 5,238,065. This results in: decreased
clean-up time and hence lower cost to remove the filter cake; and the use of lesser
strength polymer decomposing compositions, and hence decreased corrosion rates
CA 0221820F7 1997- 10- 14
and decreased corrosion inhibitor requirements. Higher density fluids, formulated
with inert weighting solids, can be obtained due to the reduced viscosity provided
by the decreased polymer concentrations.
These and other benefits and advantages of the hlvention will be obvious to one
s skilled in the art upon reading the foregoing description of the invention.
In order to more completely describe the invention, the following non-limiting
examples are given. In these examples and this specification, the following
abbreviations may be used: API = American Petroleum Institute; ECH~IPS =
epichlorohydrin crosslinked hydroxypropyl starch; UFS = Ultra Fine Salt (NaCl);
o S.G. = specific gravity; bbl = 42 gallon barrel; Ib/bbl = pounds per barrel; hr =
hours; g = gram; cc = cubic centimeters; ~F = degrees Fahrenheit; Ib/gal = pounds
per gallon; % = percent by weight; llm = micrometer (micron); kg/m3 = kilogram
per cubic meter; Tr = Trace; PV = API plastic viscosity in centipoise; YP = API
yield point in pounds per 100 square feet; Gel = 10 second/10 minute gel strengths
in pounds per 100 square feet; LSRV = Brookfield low shear viscosity at 0.3
revolutions per minute, in centipoise; HTHP = high temperature, high pressure; NC
= No Control.
The plastic viscosity, yield point, and gel strengths were obtained by the
procedures set forth in API's Recommended Practice 13B-l. The LSRV was
20 obtained for the fluids using a Brookfield Model LVTDV-I viscometer having a
number 2 spindle at 0.3 revolutions per minute. The LSRV is indicative of the
suspension properties of the fluid, the larger the LSRV, the better is the suspension
CA 0221820~ 1997-10-14
of solids in the fluid. All high temperature, high pressure (HT~) filtration data
were obtained by a modified API filtration test. Thus to an API high temperature
filtration cell with removable end cages is added a screen having 44 micron
openings. There is then added 67.5 grams of a sized sand to produce a 1.5 cm sand
5 bed. The sized sand has a particle such that all of the sand passes through a screen
having 177 micron openings and is retained on a screen having 125 micron
openings. The fluid to be tested is poured along the inside edge of the filtration cell
so as not to disturb the sand bed. The filtration test is then conducted for 30
minutes at the desired temperature of 250~F under a pressure differential of 17.59
o kg/cm2 (250 pounds per square inch) supplied by nitrogen.
The particle size of the sized salt bridging agents disclosed in this specification
and the claims were measured with Malvern Instruments, Inc. MASTERSIZER E
particle size analyzer. The bridging agents were suspended in a saturated sodium
chloride solution.
Example 1
A series of particulate, water soluble, sodium chloride bridging agents were
prepared by mixing together a commercial sample of Watesal A bridging agent with
an ultrafine salt (NaCI). The particle size distribution was determined, and the
pertinent data are set forth in Table A-2 through A-8, and summarized in Table A-
20 1.
Well drilling and servicing fluids were prepared by mixing together 336 cc of asaturated sodium chloride brine (S.G. = 1.2), 1.25 g of xanthan gum, 3.75 g of
CA 0221820~ 1997-10-14
ECHXHPS, and 46.0 g of the bridging agents set forth in Table A-1 to A-8. Thus
the fluids contained 1.25 lb/bbl (3.57 kg/m3) xanthan gum, 3.75 Ib/bbl (10.7 kg/m3)
ECH~IPS, and 46 Ib/bbl (131.4 kg/m3) bridging agent. These fluids were
evaluated for API rheology, low shear rate viscosity, pH, and HTHP filtration
5 characteristics. The concentration of bridging particles, less than 10 ~m in
equivalent spherical diameter, present in the fluids was calculated using the data in
table A-1. The data obtained are set forth in Table A-9.
The data indicate that fluids containing bridging agents which contain greater
than about 10% by weight of particles having a particle size of less than about 10
10 llm exhibit significantly reduced fluid loss as compared to the prior art fluids
containing the prior art bridging agent.
CA 0221820~ 1997-10-14
Table A-1
Table No. A-2 A-3 A-4 A-5 A-6 A-7 A-8
% UFS O 5 10 20 30 40 100
Avera~e Particle Size At The Indicated % Of All Particles
s 10% 11.98 8.92 5.07 3.40 3.21 1.921.44
50% 32.60 30.59 26.21 23.07 20.19 10.796.76
90% 60.98 58.67 53.40 51.80 48.49 43.4314.34
Approximate Percent Of Particles Less Than The Indicated Particle Size
2 ~m 3.2 3.6 5.0 6.1 6.5 10.514.5
0 5 !lm 4.8 6.1 9.9 14.0 15.1 26.2 35.1
10 lam 8.0 11.3 16.9 24.8 29.1 47.6 73.1
15 ~lm 14.1 18.5 25.4 34.3 39.9 59.4 91.4
20 llm 23.1 27.9 36.0 44.0 49.6 66.9 97.1
30 ~lm 44.3 48.7 57.9 62.7 67.4 78.5 99.5
40 ,um 63.9 67.4 75.4 77.8 81.4 87.3 99.8
44 ~m 83.6 73.7 81.9 82.7 85.~ 90.2 99.9
50 llm 89.9 81.2 86.8 88.2 90.7 93.5 100
80 lam 100 100 100 100 100 100 100
CA 0221820~ 1997-10-14
Table A-2
Prior Art Sized Salt (NaCI) Brid~in~ A~ent
Particle Size Ran~e um% of Particles % of Particles
Low Hi h in SizeRan~e <Hi~h Size
1 00 1.63
1.00 1.23 0.52 2.14
1.23 1.51 0.49 2.63
1.51 1.86 0.42 3.05
1.86 2.30 0.36 3.41
lo2.30 2.83 0.33 3 74
2.83 3.49 0.33 4.07
3.49 4.30 0.38 4.46
4.30 5.29 0.48 4.94
5.29 6.52 0.64 5.58
5 6.52 8.04 0.91 6.49
8.04 9.91 1.42 7.92
9.91 12.21 2.35 10.26
12.21 15.04 3.86 14.12
15.04 18.54 5.99 20.11
2018.54 22.84 8.71 28.81
22.84 28.15 11.59 40.40
28.15 34.69 13.90 54.30
34.69 42.75 14.61 68.91
42.75 52.68 13.32 82.24
~552.68 64.92 10.53 92.76
64.92 80.00 7.24 100.00
CA 0221820~ 1997-10-14
Table A-3
Sample A-3
Particle Size Ran~e. ~m % of Particles % of Particles
Low ~g~ in Size Ran~e < Hi~h Size
s 1.00 1.70
1.00 1.23 0.62 2.32
1.23 1.51 0.62 2.93
1.51 1.86 0.55 3.49
1.86 2.30 0.49 3.98
lo2.30 2.83 0.46 4.44
2.83 3.49 0 49 4.94
349 4.30 0.60 5 54
4.30 5.29 0.81 6.36
5.29 6.52 1.12 7.48
5 6.52 8.04 1.55 9.02
8.04 9.91 2.15 11.17
9.91 12.21 3.05 14.22
12.21 15.04 4.4l 18.63
15.04 18.54 6.31 24.95
2018.54 22.84 8.70 33.65
22.84 28.15 11.25 44 90
28.15 34.69 13.32 58.22
34.69 42.75 13.90 72.12
42.75 52.68 12.50 84.62
2552.68 64.92 9.48 94.11
64.92 ~0.00 ~.89 100.00
16
CA 0221820~ 1997-10-14
Table A-4
Sample A-4
Particle Size Ran~e~ llm % of Particles % of Particles
Low Hi h in SizeRan e ~Hi~h Size
1.00 2.20
1.00 1.23 0.81 3.01
1.23 1.51 0.85 3.86
1.51 1.86 0.86 4.72
1.86 2.30 0.87 5.59
lo2.30 2.83 0.93 6.52
2.83 3.49 1.06 7.58
3.49 4.30 1.25 8.83
4.30 5.29 1.49 10.32
5.29 6.52 1.76 12.07
6.52 8.04 2.09 14.17
8.04 9.91 2.64 16.80
9.91 12.21 3.59 20.39
12.21 15.04 5.13 25.51
15.04 18.54 7.21 32.73
2018.54 22.84 9.66 42.38
22.84 28.15 11.88 54.26
28.15 34.69 13.00 67.26
34.69 42.75 12.29 79.55
42.75 52.68 9.92 89.46
2~52.68 64.92 6.81 ~6.27
64.92 80.00 3.73 100.00
CA 0221820~ 1997-10-14
Table A-5
Sample A-5
Particle Size Ran~e llm % of Particles % of Particles
Low Hi~h in Size Ran~e < Hi~h Size
s 1.00 2.34
1.00 1.23 1.00 3 34
1.23 1.51 1.12 4.46
1.51 1.86 1.22 5.68
1.86 2.30 1.33 7.01
lo2.30 2.83 1.49 8.50
2.83 3.49 1.74 10.24
3.49 4.30 2.05 12.29
4.30 5.29 2.44 14.73
5.29 6.52 2.86 17.59
5 6.52 8.04 3.29 20.88
8.04 9.91 3.76 24.64
9.91 12.21 4.40 29.04
12.21 15.04 5.37 34.41
15.04 18.54 6.72 41.13
2018.54 22.84 8.42 49.55
22.84 28.15 10.06 59.61
28.15 34.69 11.08 70.69
34.69 42.75 10.83 81.53
42.75 52.68 9.12 90.65
2552.68 64.92 6.29 96.93
64.92 80.00 3.07 100.00
CA 0221820~ 1997-10-14
.
Table A-6
Sample A-6
Particle Size Ran~e ~m% of Particles % of Particles
Low Hi~h in SizeRan e <Hi~h Size
1.00 2.42
1.00 1.23 1.11 3.53
1.23 1.51 1.25 4.78
1.51 1.86 1.32 6.10
1.86 2.30 1.38 7.48
102.30 2.83 1.49 8.97
2.83 3.49 1.78 10.75
3.49 4.30 2.28 13.03
4.30 5.29 2.95 15.98
5.29 6.52 3.71 19.69
6.52 8.04 4.37 24.06
8.04 9.91 4.83 28.89
9.91 12.21 5.22 34.11
12.21 15.04 5.84 39 95
15.04 18.54 6.88 46.83
2018.54 22.84 8.18 55.01
22.84 28.15 9.50 64.51
28.15 34.69 10.27 74.79
34.69 42.75 9.98 84.77
42.75 52.68 8.19 92.95
2552.68 64.92 5.23 98.19
64.92 80.00 1.81 100.00
19
CA 0221820~ 1997-10-14
:i
Table A-7
Sample A-7
Particle Size Ran~e llm % of Particles% of Particles
Low Hi~h in SizeRan~e <Hi~h Size
1.00 3.42
1.00 1.23 1.74 5.15
1.23 1.51 2.08 7.24
1.51 1.86 2.38 9.62
1.86 2.30 2.62 12.24
102.30 2.83 2.90 15.14
2 83 3.49 3.36 18.50
3 49 4.30 4.09 22.59
4.30 5.29 5.06 27.65
5.29 6.52 6.06 33.72
6.52 8.04 6.76 40.47
8.04 9.91 6.84 47.31
9.91 12.21 6.39 53.70
12.21 15.04 5.80 59.50
15.04 18.54 5.50 65.00
2018.54 22.84 5.59 70 59
22.84 28.15 6.05 76.64
28.15 34.69 6.48 83.12
34.69 42.75 6.42 89.54
42.75 52.68 5.41 94.95
2552.68 64.92 3.60 98.55
64.92 80.00 1.45 100.00
CA 0221820~ 1997-10-14
Table A-8
Sample A-8
Particle Size Ran~e um % of Particles % of Particles
Low HiPh in Size Ran~e < HiPh Size
1.00 5.32
1.00 1.23 2.56 7.88
1.23 1.51 2.82 10.71
1.51 1.86 2.91 13.62
1.86 2.30 2.91 16.53
lo2.30 2.83 3.17 19.71
2.83 3.49 4.06 23.77
3.49 4.30 5.71 29.47
4.30 5.29 8.01 37.48
5.29 6.52 10.47 47.95
5 6.52 8.04 12.25 60.20
8.04 9.91 12.48 72.68
9.91 12.21 10.89 83.56
12.21 15.04 7.96 91.53
15.04 18.54 4.80 96.32
2018.54 22.84 2.25 98.57
22.84 28.15 0.82 99.38
28.15 34.69 0.30 99.68
34.69 42.75 0.21 99.89
42.75 52.68 0.10 100.00
2s52.68 64.92 0 100.00
64.92 80.00 0 100.00
CA 0221820~ 1997-10-14
Table A-9
Sample A-2 A-3 A-4 A-5 A-6 A-7 A-8
Approx. % of Salt
Particles<lOIaminFluid 8.0 11.3 16.9 24.8 29.1 47.6 73.1
Salt Particles <10 llm in
Fluid, Ib/bbl 3.7 5.2 7.8 11.4 13.4 21.9 33.6
Rheolo~y
PV 16 16 16 17 17 18 16
YP 24 24 27 27 26 28 28
lo Gels, lOsec/lOmin 11/15 11/14 11/15 12/16 11/15 12/16 11/15
LSRV 30,900 30,000 31,700 37,500 35,500 38,600 35,800
pH 7.9 8.1 8.0 8.0 7.9 7.9 8.0
HTHP Filtrate
Spurt Loss, cc 2.0 1.25 0 0 0 0 NC
lOmin., cc 3.5 2.5 2.0 2.0 2.0 1.75 --
20min., cc 5.0 3.5 3.5 3.0 3.0 2.5 --
30 min., cc 7.25 5.5 4.25 3.5 3.25 3.25 --
CA 0221820F7 1997- 10- 14
Example 2
Well drilling and servicing fluids were prepared as in Example 1 except that theamount of the ECH~lPS fluid loss control agent was reduced to 2.0 g (i.e., 2
Ib/bbl, 5.7 kg/m3). The fluids were evaluated as in Example 1. The data obtained5 are set forth in Table B.
Comparison of the data with the data for Sample/Fluid A-2 of Table A-9
indicates that the concentration of the polymer fluid loss Gontrol additive can be
decreased significantly by increasing the concentration of the bridging agent
particles ~Yhich are less than 10 ~m in size.
0 Example 3
Evaporated salt (NaCl) was ground to give the particle size distribution set forth
in Table C. This bridging agent contained 12.8% ofthe particles less than about 10
m. A well drilling and servicing fluid was prepared and evaluated as in Example 1.
The data obtained are set forth in Table C.
CA 0221820~ 1997-10-14
Table B
Sample/Fluid A-2 A-3 A-4 A-5 A-6 A-7 A-8
Approx. % of Salt 8.0 11.3 16.9 24.8 29.1 47.6 73.1
Particles <lO lam in Fluid
s Salt Particles <10 ~m in
Fluid, Ib/bbl 3.7 5.2 7.8 11.4 13.4 21.9 33.6
Rheology
PV 13 13 12 14 14 15 13
YP 20 19 22 22 18 21 21
o Gels, lOsec/lOmin 10/13 9/12 10/13 10/13 9/13 10/13 10/14
LSRV 23,900 23,500 33,900 31,300 25,900 29,600 25,400
pH 8.1 8.0 8.0 7.9 8.0 7.9 8.1
HTHP Filtrate
Spurt Loss, cc 4.0 3.5 1.5 0.5 Tr O NC
1S 10 min., cc 9.0 6.0 2.5 2.0 2.0 2.0 --
20min., cc 12.0 7.75 3.5 3.0 2.5 2.5 --
30min., cc 15.0 10.0 4.0 3.5 3.0 2.75 --
24
CA 02218205 1997-10-14
-
Table C
Bridging Agent Fluid
Average Particle Size Approx. % of Salt
At The Indicated Particles <10 !lm
s % Of All Particles In Fluid 12.8
10% = 8 14 ~lm Salt Particles <10 ,um
50% = 33 06 !lm In Fluid~ Ib/bbl 5 9
90% = 87 95 llm Rheolo~y
Approximate Percent PV 15
o Of Particles Less YP 23
Than The Indicated Gels, 10 sec/10 min 10/13
Particle Size LSRV 30,000
2 lam= 2 3~/0 pH 8 0
5 llm = 6 3% HTHP Filtrate
10 llm= 12 8% SpurtLoss, cc 1 75
15 lam = 21.1% 10 min, cc 4 0
20 lam= 29 5% 20 min, cc 5.0
30 lam = 45 4% 30 min, cc 6 75
40 lam= 59 2%
44 Ilm= 64 0%
5011m=70 1%
80 llm= 87 1%
