U.S. patent application number 13/971697 was filed with the patent office on 2014-02-20 for solubilized polymer concentrates, methods of preparation thereof, and well drilling and servicing fluids containing the same.
This patent application is currently assigned to TUCC Technology, LLC. The applicant listed for this patent is TUCC Technology, LLC. Invention is credited to James W. Dobson, JR., Kim O. Tresco.
Application Number | 20140051606 13/971697 |
Document ID | / |
Family ID | 49118779 |
Filed Date | 2014-02-20 |
United States Patent
Application |
20140051606 |
Kind Code |
A1 |
Dobson, JR.; James W. ; et
al. |
February 20, 2014 |
Solubilized Polymer Concentrates, Methods of Preparation Thereof,
and Well Drilling and Servicing Fluids Containing the Same
Abstract
The invention provides concentrates for reducing the fluid loss
on an oil base well drilling or servicing fluid, the concentrates
comprising an oleagineous liquid and (1) a polymer which is
solublized in the oleagineous liquid, or (2) a polymer which is
solublized in the oleaginous liquid together with an organophilic
polyphenolic material which is solublized and/or dispersed in the
oleagineous liquid. The method of preparing the concentrate and the
method of reducing the fluid loss of an oil base well drilling or
servicing fluid utilizing the concentrates is also disclosed. The
preferred oil soluble polymer is a styrene-butadiene rubber crumb.
The preferred oleagineous liquid is an aromatic-free hydrogenated
oil essentially containing only saturated hydrocarbons. The
preferred polyphenolic material is a source of humic acid, such as
mined lignite.
Inventors: |
Dobson, JR.; James W.;
(Houston, TX) ; Tresco; Kim O.; (Houston,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
TUCC Technology, LLC |
Houston |
TX |
US |
|
|
Assignee: |
TUCC Technology, LLC
Houston
TX
|
Family ID: |
49118779 |
Appl. No.: |
13/971697 |
Filed: |
August 20, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61691039 |
Aug 20, 2012 |
|
|
|
Current U.S.
Class: |
507/107 ;
166/294; 507/106; 507/117; 523/130 |
Current CPC
Class: |
Y02W 30/91 20150501;
C09K 8/64 20130101; C09K 8/34 20130101; C09K 8/02 20130101; Y02W
30/96 20150501; C09K 8/487 20130101; C09K 8/035 20130101; E21B
33/138 20130101; C09D 183/04 20130101; C04B 24/2676 20130101; C08K
5/01 20130101; E21B 21/003 20130101; C04B 18/22 20130101; C09K 8/52
20130101; C08K 5/01 20130101; C08L 19/003 20130101 |
Class at
Publication: |
507/107 ;
507/117; 507/106; 523/130; 166/294 |
International
Class: |
C09K 8/34 20060101
C09K008/34; E21B 33/138 20060101 E21B033/138; C09K 8/487 20060101
C09K008/487 |
Claims
1. A solubilized polymer concentrate for use in reducing the fluid
loss of an oil base well drilling or servicing fluid, the
concentrate comprising: an oleaginous liquid; an organophilic
polyphenolic material; and a polymer soluble in the oleaginous
liquid, wherein the concentration of the polymer is from about
0.0168 grams per milliliter (g/mL) of the oleaginous liquid to
about 0.0348 g/mL of the oleaginous liquid, and wherein the
particle size of the pre-solubilized polymer is less than about
2000 microns, and wherein the concentration of the organophilic
polyphenolic material is from about 0.1677 g/mL of the oleaginous
liquid to about 0.3482 g/mL of the oleaginous liquid.
2. The concentrate of claim 1, wherein the polymer is a
styrene-butadiene rubber (SBR) crumb or a styrene-butadiene-styrene
block copolymer crumb.
3. The concentrate of claim 2, wherein the polymer is a cold-type
SBR crumb.
4. The concentrate of claim 1, wherein the oleaginous liquid is an
aromatic-free, hydrogenated oil comprising only saturated
hydrocarbons of medium- to high-molecular weight.
5. The concentrate of claim 1, wherein the polyphenolic material is
selected from the group consisting of lignite, tannin, and mixtures
thereof.
6. The concentrate of claim 5, wherein the polyphenolic material is
an amine-treated lignite dispersed in an oleaginous liquid in a
concentration ranging from 0.17 g/mL of the oleaginous liquid to
about 0.35 g/mL of the oleaginous liquid.
7. A method of manufacturing a solubilized polymer concentrate of
claim 4, the method comprising: admixing the polymer, the
organophilic polyphenolic material, and the oleaginous liquid
together at a temperature in the range from about 150.degree. F. to
about 200.degree. F. for a period of time ranging from about 30
minutes to about 3 hours, at a mixing shear rate of at least 5,000
rpm.
8. The method of claim 7, wherein the oleaginous liquid is an
aromatic-free oil containing substantially only saturated
hydrocarbons of medium- or high-molecular weight and wherein the
polyphenolic material is selected from the group consisting of
lignite, tannin, and mixtures thereof.
9. A method of reducing the fluid loss of an oil base well drilling
or servicing fluid, the method of which comprises: adding to the
fluid the concentrate of claim 1, 2, or 3, in an amount sufficient
to provide the fluid with from about 0.5 ppb to about 2.5 ppb of
the polymer and from about 5 ppb to about 25 ppb of the
organophilic polyphenolic material.
10. A method of reducing the fluid loss of an oil base well
drilling or servicing fluid which comprises adding to the fluid the
concentrate of claim 4 in an amount sufficient to provide the fluid
with from about 0.5 ppb to about 2.5 ppb of the polymer and from
about 5 ppb to about 25 ppb of the organophilic polyphenolic
material.
11. A method of reducing the fluid loss of an oil base well
drilling or servicing fluid which comprises adding to the fluid the
concentrate of claim 6 in an amount sufficient to provide the fluid
with from about 0.5 ppb to about 2.5 ppb of the polymer and from
about 5 ppb to about 25 ppb of the organophilic polyphenolic
material.
12. A method of reducing the fluid loss of an oil base well
drilling or servicing fluid which comprises adding to the fluid a
concentrate of an oil soluble polymer solublized in an oil wherein
the concentration of the polymer is from about 0.03 grams per
milliliter of the oil to about 0.143 grams per milliliter of the
oil.
13. The method of claim 12 wherein the amount of the concentrate is
sufficient to provide the fluid with from about 0.5 ppb to about
5.0 ppb of the polymer.
14. A method of preparing a well treatment fluid, the method
comprising: providing an oleaginous base fluid; providing one or
more polymer materials having a solubility in the oleaginous base
fluid; providing one or more organophilic polyphenolic materials;
and combining the polymer material and the organophilic
polyphenolic material with the base fluid such that the
concentration of the oil soluble polymer ranges from about 0.03
g/mL of the base fluid to about 0.143 g/mL of the base fluid.
15. A method of reducing lost circulation in a subterranean well,
the method comprising: preparing a treating composition comprising
an oleaginous base fluid, a polymer material having a solubility in
the oleaginous base fluid, and one or more organophilic
polyphenolic materials, the polymer being present in a
concentration ranging from about 0.03 g/mL of the base fluid to
about 0.143 g/mL of the base fluid; injecting the treating
composition into the well; and forcing the treating composition
into a lost circulation zone within the well.
16. The method of claim 15, wherein the oleaginous base fluid is a
hydrocarbon fluid selected from the group consisting of crude oil,
diesel oil, kerosene, mineral oil, gasoline, naphtha, toluene, and
mixtures thereof.
17. An oil-field cement composition comprising a cement and the
composition of claim 1.
18. A drilling fluid composition comprising a composition according
to claim 1.
19. A method of controlling fluid loss properties in oil-field
oil-based or invert-based systems, the method comprising adding to
the system an effective amount of a composition as defined in claim
1.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional Patent
Application Ser. No. 61/691,039, filed Aug. 20, 2012, the contents
of which are incorporated herein by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO APPENDIX
[0003] Not applicable.
BACKGROUND OF THE INVENTION
[0004] 1. Field of the Invention
[0005] The inventions disclosed and taught herein relate generally
to oil-based well drilling and servicing fluids. More particularly,
the inventions relate to all-oil and invert oil emulsion well
drilling, servicing and treating fluids containing an oil-soluble
polymeric fluid loss control additive solubilized therein.
[0006] 2. Description of the Related Art
[0007] This invention relates to oil base well drilling and
servicing fluids. In particular, the invention relates to "all-oil"
and "invert oil" emulsion well drilling and servicing fluids
containing an oil-soluble polymeric fluid loss control additive
solubilized therein.
[0008] As is well known in the art, invert emulsion oil based well
drilling and servicing fluids, generally called "muds", are
water-in-oil emulsions that typically contain an organophilic clay
viscosifier/suspension additive, and a weighting agent. The water
phase is usually a solution of a salt, such as calcium chloride or
sodium chloride, whose concentration is normally adjusted such that
the aqueous activity of the fluid is equal to or less than the
aqueous activity of the subterranean formations contacted by the
fluids. This minimizes transfer of water-to-water-sensitive
formations and maintains a stable wellbore.
[0009] The invert emulsion is usually stabilized with a "primary
emulsifier", often a fatty acid or salt thereof, while the
weighting material and the solids the fluid acquires during use are
made oil-wet and dispersed in the fluid with a "secondary
emulsifier", typically a strong wetting agent such as a polyamide,
amido-amine (partial amide of a polyamine), and the like.
[0010] Regardless of whether it is an all-oil, or an invert fluid,
drilling fluids, or `drilling muds` as they are sometimes called,
are slurries used in the drilling of wells into the earth for the
purpose of recovering hydrocarbons and other fluid materials.
Drilling fluids have a number of functions, the most important of
which include lubricating the drilling tool and drill pipe which
carries the drilling tool, removing formation cuttings from the
well, counterbalancing formation pressures to prevent the inflow of
gas, oil or water from permeable rocks which may be encountered at
various levels as drilling continues, and holding the cuttings in
suspension in the event of a shutdown in the drilling and pumping
of the drilling fluid.
[0011] For a drilling fluid to perform these functions and allow
drilling to progress, the drilling fluid must stay in the borehole
during the drilling operation. Frequently, undesirable formation
conditions are encountered in which substantial amounts, or in some
cases, practically all of the drilling fluid may be lost to the
formation. Drilling fluid can leave the borehole through large or
small fissures or fractures in the formation or through a highly
porous rock matrix surrounding the borehole.
[0012] Most subterranean wells are drilled with the intent of
forming a filter cake of varying thickness on the sides of the
borehole. The primary purpose of the filter cake is to reduce the
large losses of drilling fluid to the surrounding formation.
Unfortunately, formation conditions are frequently encountered
which may result in unacceptable losses of drilling fluid to the
surrounding formation despite the type of drilling fluid employed
and filter cake created.
[0013] Well drilling and servicing fluids typically contain an
additive to control the loss of fluid to the formation being
drilled or serviced. A variety of different substances have been
used and are pumped down well bores in an attempt to reduce the
large losses of drilling fluid to fractures and the like in the
surrounding formations. Typical fluid loss control additives for
use with oil base fluids are gilsonite, asphalt, oxidized asphalt,
cellulose-based materials and various polymers, as well as almond,
walnut, and other nut hulls. These fluid-loss control agents are
added to the drilling or servicing fluid in an attempt to reduce
the unacceptable high losses of drilling or servicing fluid to
fractures and/or porous structures in the surround formation.
[0014] A number of issued patents over the years have described
various polymeric compositions as fluid loss control additives in
oil base muds. For example, U.S. Pat. No. 2,697,071 to Kennedy, et
al. describes the use of rubber latex to regulate the viscosity and
fluid loss of oil base muds.
[0015] U.S. Pat. No. 2,743,233 to Fisher describes drilling muds,
and improved methods of drilling wells in the earth. Preferred
embodiments of the invention reportedly relate to oil-base drilling
muds having low fluid loss and increased viscosities. Another
aspect of the disclosed invention pertains to oil-water emulsions
used as drilling muds.
[0016] U.S. Pat. No. 4,740,319 (Patel, et al.) discloses oil base
muds containing a "gelling composition" comprising a copolymer
which includes 2 primary components: (1) latex type material
preferably a styrene-butadiene copolymer and (2) one or more
functional monomers selected from the group consisting of amides,
amines, sulfonates, monocarboxylic acids, dicarboxylic acids and
combinations thereof.
[0017] In U.S. Pat. No. 5,333,698, a wellbore fluid (e.g., a
drilling, completion, packer, or fracturing fluid) is described
that includes (a) at least one additive selected from the group
consisting of emulsifiers, wetting agents, viscosifiers, weighting
agents, fluid loss control agents, including polymeric fluid loss
control agents, proppants for use in hydraulically fracturing
subterranean formations, and particulate agents for use in forming
a gravel pack; and, (b) a non-toxic white mineral oil having (i) an
API gravity at 15.6.degree. C. (60.degree. F.) greater than 35,
(ii) a content of compounds containing 14 or more carbon atoms of
at least about 95 weight percent, and (iii) a pour point of at
least about -30.degree. C. (-22.degree. F.).
[0018] U.S. Pat. No. 5,883,054 to Hernandez, et al., describes
thermally stable, oil base drilling fluid systems including
drilling fluid and an additive, wherein the additive includes
styrene-butadiene copolymers having an average molecular weight
greater than about 500,000 g/mol, and wherein the drilling fluid
system exhibits fluid loss control under high temperature and high
pressure conditions. According to the disclosure, the copolymers
were dissolved in the base oil for 16 hours before the remainder of
the additives were added.
[0019] U.S. Pat. No. 6,730,637 to Stewart, et al. describes a low
toxicity drilling mud oil. In some of the described embodiments,
the fluid loss characteristic of the drilling mud oil as used in a
borehole can be reduced to less than 0.2 ml/30 minutes by adding
about 0.05% to about 2.0% by weight of a
butadiene-styrene-butadiene (BSB) block copolymer having about 20%
by weight or more styrene.
[0020] The inventions disclosed and taught herein are directed to
polymeric compositions and methods for the use of such compositions
for reducing the fluid loss of invert oil emulsion and all oil well
drilling and servicing fluids in which oil is the continuous
phase.
BRIEF SUMMARY OF THE INVENTION
[0021] The objects described above and other advantages and
features of the invention are incorporated in the application as
set forth herein, and the associated examples and drawings, related
to systems for utilizing an oil-soluble polymer in decreasing the
fluid loss of oil base muds, particularly such muds that contain
little or no aromatic compounds.
[0022] The primary purpose of the present invention is to provide a
polymeric composition and methods for use of such compositions for
reducing the fluid loss of invert oil emulsion and all oil well
drilling and servicing fluids in which oil is the continuous phase,
hereinafter sometimes called "oil-base muds" or "oil-base
fluids".
[0023] In accordance with a first embodiment of the present
disclosure, an oil soluble polymer is dissolved in an oil to
provide a concentrate which is added to an oil base mud to decrease
the fluid loss thereof.
[0024] Still another embodiment of the invention provides an
additive to reduce the fluid loss of an oil base mud which
comprises an oil soluble polymer and an organophilic polyphenolic
fluid loss control agent solublized in an oil to form a
concentrate.
[0025] Another embodiment of the invention provides a method of
decreasing the fluid loss of an oil base well drilling or servicing
fluid which comprises adding to the fluid a first concentrate
comprising an oil soluble polymer dissolved in an oil and a second
concentrate comprising an organophilic polyphenolic material
dispersed or solublized in an oil.
[0026] In another embodiment of the invention, a method of reducing
the loss of fluid from an oil base mud is provided which comprises
adding a solublized (dissolved) polymer concentrate to an oil base
mud.
[0027] Yet another embodiment of the invention is to provide a
method of preparing a concentrate for reducing the fluid loss of an
oil base well drilling or servicing fluid which comprises mixing an
oil soluble polymer and an organophilic polyphenolic material in an
oil at a temperature in the range from about 150.degree. F. to
about 200.degree. F. for 30 minutes to about 3 hours at a mixing
shear rate of at least about 5,000 rpm.
[0028] In yet another embodiment of the invention, a method of
decreasing the fluid loss of an oil base well drilling or servicing
fluid is provided which comprises adding to the fluid a first
concentrate of an oil soluble polymer dissolved in an oil as
provided hereinbefore and a second concentrate or an organophilic
polyphenolic material, dissolved or dispersed in an oil. The
concentration of the organophilic polyphenolic material in the
second concentrate is from about 0.167 grams per milliliter to
about 0.348 grams per milliliter of the oil. This second
concentrate is prepared by mixing the organophilic polyphenolic
material and the oil together at a temperature in the range from
about 150.degree. F. to about 200.degree. F. for 30 minutes to
about 3 hours.
[0029] In a specific aspect of embodiments of the invention, a
butadiene-styrene copolymer is dissolved in a paraffinic
hydrocarbon oil to form a concentrate which is added to an oil base
mud to decrease the fluid loss thereof.
[0030] In another embodiment of the invention, a butadiene-styrene
copolymer is dissolved in an oil and an organophilic polyphenolic
material, such as lignite, is dissolved or dispersed in the oil to
form a concentrate which can be added to an oil base mud to
decrease the fluid loss therefrom.
[0031] In yet another embodiment of the present invention, methods
of reducing lost circulation in a subterranean well are described,
the method comprising the steps of preparing a treating composition
comprising an oleaginous base fluid, a polymer material having a
solubility in the oleaginous base fluid, and one or more
organophilic polyphenolic materials, the polymer being present in a
concentration ranging from about 0.03 g/mL of the base fluid to
about 0.143 g/mL of the base fluid; injecting the treating
composition into the well; and forcing the treating composition
into a lost circulation zone within the well. In accordance with
aspects of this embodiment, the oleaginous base fluid is a
hydrocarbon fluid with a low- or no aromatic content selected from
the group consisting of crude oil, diesel oil, kerosene, mineral
oil, parrafinic hydrocarbon fluid, gasoline, naphtha, and mixtures
thereof.
DETAILED DESCRIPTION
[0032] The written description of specific structures and functions
below are not presented to limit the scope of what Applicants have
invented or the scope of the appended claims. Rather, the written
description is provided to teach any person skilled in the art to
make and use the inventions for which patent protection is sought.
Those skilled in the art will appreciate that not all features of a
commercial embodiment of the inventions are described or shown for
the sake of clarity and understanding. Persons of skill in this art
will also appreciate that the development of an actual commercial
embodiment incorporating aspects of the present inventions will
require numerous implementation-specific decisions to achieve the
developer's ultimate goal for the commercial embodiment. Such
implementation-specific decisions may include, and likely are not
limited to, compliance with system-related, business-related,
government-related and other constraints, which may vary by
specific implementation, location and from time to time. While a
developer's efforts might be complex and time-consuming in an
absolute sense, such efforts would be, nevertheless, a routine
undertaking for those of skill in this art having benefit of this
disclosure. It must be understood that the inventions disclosed and
taught herein are susceptible to numerous and various modifications
and alternative forms. Further, it will be understood that the
compositions described herein can comprise, consist essentially of,
or consist of the stated materials. Lastly, the use of a singular
term, such as, but not limited to, "a," is not intended as limiting
of the number of items. Also, the use of relational terms, such as,
but not limited to, "top," "bottom," "left," "right," "upper,"
"lower," "down," "up," "side," and the like are used in the written
description for clarity in specific reference to the Figures and
are not intended to limit the scope of the invention or the
appended claims.
[0033] As used herein, the term "well" includes at least one
wellbore. A "well" can include a near-wellbore region of a
subterranean formation surrounding a portion of a wellbore that is
in fluid communication with the wellbore. As used herein, the term
"into a well" means at least through the wellhead; it can include
into any downhole portion of the wellbore or through the wellbore
and into a near-wellbore region.
[0034] As used herein, the term "polymer block" means and includes
a grouping of multiple monomer units of a single type (i.e., a
homopolymer block) or multiple types (i.e., a copolymer block) of
constitutional units into a continuous polymer chain of some length
that forms part of a larger polymer of an even greater length and
exhibits a .sub.XN value with other polymer blocks of unlike
monomer types that is sufficient for phase separation to occur. For
example, the .sub.XN value of one polymer block with at least one
other polymer blocks in the larger polymer may be greater than
about 10.
[0035] As used herein, the term "block copolymer" means and
includes a polymer composed of chains where each chain contains two
or more polymer blocks as defined above and at least two of the
blocks are of sufficient segregation strength (e.g., .sub.XN>10)
for those blocks to phase separate. A wide variety of block
polymers are contemplated herein, including but not limited to
diblock copolymers (i.e., polymers including two polymer blocks),
triblock copolymers (i.e., polymers including three polymer
blocks), multiblock copolymers (i.e., polymers including more than
three polymer blocks), and combinations thereof.
[0036] The term "saturated hydrocarbon", as used herein, refers to
paraffinic and naphthenic compounds, but not to aromatics.
Paraffinic compounds may be either linear (n-paraffins) or branched
(i-paraffins). Naphthenic compounds are cyclic saturated
hydrocarbons, i.e. cycloparaffins. Such hydrocarbons with cyclic
structure are typically derived from cyclopentane or cyclohexane. A
naphthenic compound may comprise a single ring structure.
[0037] The phrase "high molecular weight hydrocarbons," in
accordance with the present invention, refers to those hydrocarbons
having an API value (API gravity) of from 8 to 12.degree. API (and
generally a viscosity higher than 350 cSt at about 7.degree. C.),
while medium molecular weight hydrocarbons have an API value of
greater than 20.degree. API (for example, from 22 to 30). The terms
"high molecular weight hydrocarbon" and "medium molecular weight
hydrocarbon," as used herein, are terms relative to one another.
The former term signifies a mixture of hydrocarbons, with or
without their entrained impurities, with an average molecular
weight of the hydrocarbons significantly higher than the average
molecular weight of the hydrocarbons in a medium molecular weight
hydrocarbon. Thus, the use of the terms "high molecular weight
hydrocarbon" and "medium molecular weight hydrocarbon" does not
signify any particular molecular weight ranges.
[0038] High molecular weight hydrocarbons are typically materials,
such as crude oils, asphaltenes, tars, and heavy oils, which have
limited or no practical use, but which can be converted to more
valuable and useful lower molecular weight hydrocarbons via
chemical means. Medium oils generally have resins or polar
fractions less than about 25% of the weight of the total oil and
have an API gravity of 22.3 to 32 with viscosities in the range of
about 100 to 1000 centipoise; heavy oils generally have resins or
polar fractions between about 25 and 40% of the total weight of the
oil and have an API gravity of generally above 10 but less than
22.3 with viscosities greater than about 1000 centipoise; tars
generally have resins or polar fractions greater than about 40% of
the total weight of the oil and have an API gravity less than about
8 to 10 and a viscosity greater than about 8000 centipoise.
[0039] The lowest molecular weight hydrocarbons can include C.sub.1
to C.sub.4 gases, e.g., methane, propane, and natural gas. When
these gases are present as part of the lower molecular weight
hydrocarbon product, they impart an even higher API value.
[0040] Applicants have created compositions and associated methods
for utilizing an oil soluble polymer in decreasing the fluid loss
of oil base muds, particularly such muds containing oils containing
low (or no) aromatic compounds. As used herein, the term "fluid
loss" refers to the undesirable migration or loss of fluids (such
as the fluid portion of a drilling mud or cement slurry) into a
subterranean formation or proppant pack. The term "proppant pack",
as used herein, refers to a collection of a mass of proppant
particulates within a fracture or open space in a subterranean
formation. Fluid loss may be problematic in any number of
subterranean operations, including drilling operations, fracturing
operations, well bore clean-out operations, and similar treatment
operations. In fracturing treatments, for example, fluid loss into
the formation may result in a reduction in fluid efficiency, such
that the fracturing fluid cannot propagate the fracture as
desired.
[0041] Oil soluble, polymeric, fluid loss control additives are
extremely difficult to dissolve in a low aromatic content
hydrocarbon oil. This results in: (1) poor efficiency as a
filtration control additive without extensive mixing at elevated
temperatures (such as "hot rolling" in a laboratory "roller oven");
(2) extreme viscosity increase of the mud after the polymer is
solublized during circulation of the mud; (3) loss of a
considerable quantity of the polymer over solids control screening
equipment due to the particle size of the undissolved polymer; (4)
high concentrations of polymer are required to compensate for the
inefficiency and losses of the polymer; and (5) potential formation
damage due to the stickiness and adhesive characteristics of
partially dissolved polymer lodging in producing formation pore
openings as a result of inadequate filtration control.
[0042] The concentrate composition of the present invention for
reducing the loss of fluid from an oil base mud comprises an oil
soluble polymer dissolved in a paraffinic oil. The concentration of
polymer in the concentrate is such that the concentrate is flowable
and pumpable at ambient temperature, preferably from about 0.03
grams per milliliter of the oil to about 0.143 grams per milliliter
of the oil. It is preferred that the Brookfield 8.48 sec.sup.-1
shear rate viscosity of a 6.15% wt./vol. concentrate at 40 rpm
using a number 2 spindle is from about 300 to about 500
centipoise.
[0043] The preferred oil soluble polymeric fluid loss control
additive for use in the invention comprise styrene-butadiene
copolymers known in the art as SBR (styrene-butadiene rubber). The
styrene content of the SBR is preferably from about 15% by weight
to about 45% by weight of the SBR, more preferably from about 20%
to 35% by weight, and most preferably from about 20% to about 25%
by weight of the SBR.
[0044] It is known to prepare SBR by emulsion polymerization using
either a "hot process" or a "cold process." The hot process is
conducted at a temperature of about 50.degree. C. whereas the
polymerization in a cold process is about 15.degree. C. to about
20.degree. C. The cold process results in a SBR which contains less
branching than in the hot process, i.e., the SBR molecules from 10
the cold process contain more linear molecules than the SBR from
the hot process. It is preferred that the SBR be prepared using a
cold process. It is also preferred that the SBR not be
crosslinked.
[0045] The SBR for use in the compositions of this invention must
be of the crumb type (as it is coagulated from the master batch)
rather than a ground, fine particle size material, in order to
obtain the desired effect. The particle size of the crumb SBR is
less than about 2000 micrometers (microns), U.S. Standard Sieve
Series (10 mesh screen), preferably from about 2000 micrometers to
about 500 micrometers (35 mesh screen), and more preferably from
about 2000 micrometers to about 300 micrometers (50 mesh
screen).
[0046] Representative crumb type SBR copolymers can be obtained
from ISP ELASTOMERS, 1615 Main Street, Port Neches, Tex. 77651 such
as the following: Hot Process SBR Elastomers--1006, 1012, and 1013;
Cold Process SBR Elastomers--8113 and 4503. It is preferred that
the Massed Mooney Viscosity (MML 1+4 (100.degree. C.)) ("Mooney
viscosity") of the SBR (as determined by the American Society of
Testing Materials standard procedure ASTM D1646-96a) be in the
range from about 40 to about 140, most preferably from about 105 to
about 135. Some other properties of the crumb SBR include the
following: a free flowing crumb form which eliminates the need for
milling, cutting or grinding; and the crumb particles retain the
porous nature of the coagulated rubber and can be dissolved in a
solvent faster than milled or pelletized bale rubber.
[0047] Other oil soluble polymers for use in this invention
include, but are not limited to, polystyrene, polybutadiene,
polyethylene, polypropylene, and copolymers consisting of at least
two monomers selected from the group consisting of styrene,
butadiene, isoprene, ethene and derivatives thereof, and
propylene.
[0048] The oil used in the solublized polymer concentrate is
preferably an aromatic-free, preferably hydrogenated paraffinic
hydrocarbon oil, or synthetic oil that is aromatic-free.
Hydrogenation converts the unsaturated, olefinic carbon-to-carbon
bonds to saturated, paraffinic bonds. This results in an oil which
is more environmentally acceptable. By aromatic-free is meant
herein that the oil contains less than 1 volume % aromatic
compounds, preferably less than about 0.1 volume %, most preferably
no aromatic compounds.
[0049] Representative hydrogenated paraffinic oils can be obtained
from VASSA, Acientes y Solventes, Venezolanos, S. A., Av. Francisco
de Miranda, con calle San Ignacio, Tone 15 Metalica, Piso 3,
Chacas, Caracas, Venezuela, such as VASSA.TM. LP-70, VASSA.TM.
LP-70P, VASSA.TM. LP-90, VASSA.TM. LP-100, and VASSA.TM.
LP-120.
[0050] The solublized polymer concentrate is prepared by mixing the
crumb polymer and oil together at a temperature in the range from
about 65.degree. C. to about 93.3.degree. C. for 30 minutes to
about 3 hours at a mixing shear rate of at least about 5,000 rpm. A
longer mixing time and a higher temperature can be utilized but are
generally unnecessary to thoroughly solubilize the polymer. The
shear rate during mixing must be sufficient to minimize the
adherence of the particulate polymer crumbs to one another and to
the sides of the mixing container as the SBR is very adhesive.
[0051] The solublized polymer concentrate may be used to decrease
the fluid loss of oil base well drilling and servicing fluids.
Thus, a method of reducing the fluid loss of an oil base mud
comprises adding to the mud the solublized polymer concentrate in
an amount sufficient to provide the fluid with from about 0.5 ppb
to about 5 ppb of the polymer.
[0052] The oil base mud generally comprises the oil, a suspending
agent, and a weighting agent, and optionally a dispersed
(emulsified) aqueous phase, emulsifiers, wetting agents,
dispersants, and the like as is well known in the art.
[0053] Oils suitable for use in the oil base muds of this invention
may be selected from any known oleaginous liquids having a high
flash point such as mineral oil, diesel oil, other petroleum
fractions, synthetic esters, synthetic ethers, synthetic
hydrocarbons such as internal olefins, polyalphaolefins, and the
like. Preferred are environmentally acceptable oils with low
toxicity, preferably aromatic-free oils. Particularly preferred are
the hydrogenated paraffinic hydrocarbons as set forth
hereinbefore.
[0054] The emulsifiers used in this invention may be the same
emulsifiers generally used in water-in-oil invert drilling fluids.
These include the various fatty acid soaps, including oxidized tall
oil soaps, preferably the calcium soaps whether pre-formed or
prepared in-situ in the fluid, polyamides, alkylamidoamines,
imidazolines, alkyl sulfonates, fatty acyl esters, lecithin, and
the like. These include so-called primary emulsifiers, and
secondary emulsifiers.
[0055] See, for example the following U.S. Pat. Nos. 2,876,197;
2,994,660; 2,962,881; 2,816,973; 2,793,996; 2,588,808; 3,244,638;
4,504,276; 4,509,950; 4,776,966; and 4,374,737. Weighting agents as
is known in the art can be incorporated in the fluids of this
invention. Exemplary weighting agents or weight materials include
barite, galena, ilmenite, iron oxide, siderite, calcite, and the
like.
[0056] Any of the typically used suspending agents known in the
industry can be used. The preferred suspending agent is an
organophilic clay (organoclay). Exemplary organoclays are set forth
in the following U.S. patents, all incorporated herein by
reference: U.S. Pat. Nos. 2,531,427; 2,966,506; 4,105,578;
4,208,218. U.S. Pat. No. 5,021,170 discloses mixtures of an
organoclay and a sulfonated ethylene/propylene/5-phenyl-2-norborene
terpolymer. Preferred organoclays are dimethyldi(alkyl)-ammonium
bentonite, dimethyldi(alkyl)-ammonium hectorite,
methyl-benzyldi(alkyl)ammonium hectorite, and mixtures thereof.
[0057] Any of the typically used fluid loss control additives known
in the industry can be present in the oil base mud, such as
gilsonite, asphalt, oxidized asphalt, lignites, and the like.
Exemplary organophilic polyphenolic materials suitable for use as
fluid loss control additives are lignites, as described herein.
Particularly preferred are polyphenolic compounds such as humic
acid and the alkali metal salts thereof (such as found in
lignites). Humic acid (HA) is a material of wide distribution and
is present in soils, peat, and coals, particularly lignite or brown
coal, and most particularly in the soft brown coal known as a
leonardite. Humic acids are complex organic molecules that are
formed by the breakdown of organic matter. Their exact structures
are generally unknown, and they are extremely variable, often being
a mixture of different acids containing carboxyl and phenolate
groups (such as quinones, phenols, catechols, and the like) so that
the mixture behaves functionally as a dibasic or tribasic add. The
principal organic groups present are phenolic and carboxylic OH,
aliphatic CH, carbonyl, conjugated carbonyl or aromatic CH.sub.2 or
CH.sub.3 or ionic carboxyl, and possibly others. The average
molecular weight of the humic acids is between 5,000 and
50,000.
[0058] In accordance with one exemplary embodiment of the present
disclosure, the organophilic polyphenolic material is a lignite
(amine-treated or otherwise) that exhibits a humic acid (HA)
content (as determined by gravimetric analysis or the equivalent),
% HA, ranging from about 20% to about 50%.+-.2% HA; greater than
50% d.b. volatile matter as determined by ASTM D3176-09 and D3180;
and an average ash content of 15% to 20% d.b. ash (avg.), as
determined by ASTM D-3174-12. These requirements have been found to
contribute to both the solubility of the polyphenolic material, and
the fluid loss control properties.
[0059] Various other known additives may also be employed in the
fluids of this invention, if necessary or desired. For example,
other wetting agents, corrosion inhibitors, scale inhibitors, and
other common additives.
[0060] The invention further provides a second polymer concentrate
to reduce the fluid loss of oil base muds. This second concentrate
comprises an oil, an oil soluble polymer, and an organophilic
polyphenolic material in which the oil soluble polymer is
solublized (dissolved) and in which the organophilic polyphenolic
material is dispersed and/or solubilized.
[0061] The concentration of the polymer and the organophilic
polyphenolic material in this concentrate are such that the
concentrate is flowable and pumpable at ambient temperatures.
Preferably the concentration of the oil soluble polymer is from
about 0.0168 grams per milliliter of the oil to about 0.0348 grams
per milliliter of the oil, and the concentration of the
organophilic polyphenolic material is from about 0.1677 grams per
milliliter of the oil to about 0.3482 grams per milliliter of the
oil.
[0062] The second polymer concentrate is prepared by mixing the oil
soluble polymer, organophilic polyphenolic material, and oil
together under the same temperature and time conditions as set
forth hereinbefore for the first polymer concentrate. The oil and
oil soluble polymer are the same as set forth hereinbefore for use
in the first polymer concentrate. The organophilic polyphenolic
materials for use in the second polymer concentrate any number of
polyphenolic materials, including those known in the art as set
forth in the following U.S. patents, each incorporated herein by
reference as appropriate: U.S. Pat. Nos. 3,168,475 (Jordan, et
al.); 3,379,650 (Beasley, et al.); 3,494,865 (Andrews, et al.);
4,421,655 (Cowan); 4,597,878 (House, et al.,); and 4,853,465
(Cowan, et al.). In accordance with one aspect of the present
disclosure, the preferred organophilic polyphenolic materials are
organophilic lignitic and amine treated organophilic lignitic
(lignite) materials, and amine treated organophilic tannins, the
polyphenolic materials being treated with amines, particularly
quaternary amines, to make the material oil dispersible in oil- and
synthetic-base muds and fluids.
[0063] The second polymer concentrate may also be used to decrease
the fluid loss of oil base well drilling and servicing fluids. This
method of reducing the fluid loss of oil base well drilling and
servicing fluids comprises adding to the fluid, or to the oil used
in preparing the fluid, the second polymer concentrate in an amount
sufficient to provide the fluid with from about 0.5 ppb to about
2.5 ppb of the polymer, and from about 5 ppb to about 25 ppb of the
organophilic polyphenolic material.
[0064] The invention further provides a concentrate of an
organophilic polyphenolic material dissolved and/or dispersed in an
oil for the addition to oil base fluids containing the solublized
polymer concentrate of this invention. When added to oil base
fluids containing the pre-solublized polymer concentrate, the
concentrate of the organophilic polyphenolic material reduces the
large viscosity increase (>25%) upon aging the fluids at
elevated temperatures as compared when adding the organophilic
polyphenolic material as manufactured, i.e., as a dry powder. The
concentration of the organophilic polyphenolic material in this
concentrate is from about 0.1677 grams per milliliter to about
0.3482 grams per milliliter of the oil. This concentrate is
prepared by mixing the oil and the organophilic polyphenolic
material together at a temperature in the range from about
150.degree. F. to about 200.degree. F. for 30 minutes to about 3
hours.
[0065] The invert fluids of the invention generally will have an
oil to water (0/W or oil:water) volume ratio of from about 40:60 to
about 95:5. The "all oil" fluids of the invention will contain less
than about 5 volume % aqueous phase, preferably less than about 2
volume %.
[0066] The compositions of the present disclosure are useful in
preventing fluid loss in certain subterranean formations, during a
number of different subterranean operations, including drilling,
completion, and workover. "Drilling" refers to the events and
equipment necessary for drilling a wellbore. "Completion" refers to
the events and equipment necessary to bring a wellbore into
production once drilling operations have been concluded, including
but not limited to the assembly of downhole tubulars and equipment
required to enable safe and efficient production from an oil or gas
well. "Workover" refers to the performance of major maintenance or
remedial treatments on an oil or gas well.
[0067] Completion and workover operations may include, but are not
limited to, cementing, gravel packing, stimulation, and conformance
operations. Many of these well services are designed to facilitate
or enhance the production of desirable fluids from or through a
subterranean formation.
[0068] As used herein, the word "treatment" refers to a treatment
for a well or subterranean formation penetrated by a wellbore that
is adapted to achieve a specific purpose in completion or workover,
such as stimulation, isolation, or conformance control; however,
the word "treatment" does not necessarily imply any particular
purpose.
[0069] Drilling typically requires the use of a drilling fluid. As
used herein, a "drilling fluid" is any of a number of fluids,
including fluid mixtures of a liquid with particulate solids or gas
(such as suspensions, emulsions, foams) used in operations to drill
boreholes into the earth. The term is synonymous with "drilling
mud" in general usage, although sometimes the term is used to refer
to more sophisticated and well-defined "muds." One classification
scheme for drilling fluids is based on singling out the component
that clearly defines the function and performance of the fluid: (1)
water-based, (2) non-water-based, and (3) gaseous (pneumatic). Each
category has a variety of subcategories that overlap each other
considerably.
[0070] A treatment typically involves introducing a treatment fluid
into a well. As used herein, a "treatment fluid" is a fluid used to
resolve a specific condition of a wellbore or subterranean
formation. As used herein, a "treatment fluid" also means the
specific composition of a fluid at the time the fluid is being
introduced into a wellbore. A treatment fluid is typically adapted
to be used to achieve a specific purpose, such as stimulation,
isolation, or control of reservoir gas or water. The word
"treatment" in the term "treatment fluid" does not necessarily
imply any particular action by the fluid.
[0071] A "spacer fluid" is a fluid used to physically separate one
special-purpose fluid from another. A special-purpose fluid can be
a drilling fluid, a cementing fluid, or a treatment fluid.
Special-purpose fluids are typically prone to contamination, so a
spacer fluid compatible with each is used between the two. For
example, a spacer fluid is used when changing fluid types used in a
well. For example, a spacer fluid is used to change from a drilling
fluid during drilling a well to a cement slurry during cementing
operations in the well. In case of an oil-based drilling fluid, it
should be kept separate from a water-based cementing fluid. In
changing to the latter operation, a chemically treated water-based
spacer fluid is usually used to separate the drilling fluid from
the cement slurry. By way of another example, a spacer fluid can be
used to separate two different types of treatment fluids.
[0072] As used herein, a "well fluid" refers to any fluid adapted
to be used in a well for a particular purpose, without necessarily
implying any particular purpose. A "well fluid" can be, for
example, a drilling fluid, a cementing fluid, a treatment fluid, or
a spacer fluid. As used herein, a "well fluid" means the specific
composition of a fluid at the time the fluid is being introduced
into a wellbore.
[0073] The following examples are included to demonstrate preferred
embodiments of the invention. It should be appreciated by those of
skill in the art that the techniques disclosed in the examples
which follow represent techniques discovered by the inventor(s) to
function well in the practice of the invention, and thus can be
considered to constitute preferred modes for its practice. However,
those of skill in the art should, in light of the present
disclosure, appreciate that many changes can be made in the
specific embodiments which are disclosed and still obtain a like or
similar result without departing from the scope of the
invention.
[0074] In these examples and this specification, the following
abbreviations may be used: API=American Petroleum Institute; bbl=42
gallon barrel; ppg=pounds per gallon; gal=gallon; m.sup.3=cubic
meters; .degree. F.=degrees Fahrenheit; %=percent;
kg/m.sup.3=kilograms per cubic meter; PV=API plastic viscosity in
centipoise (cp); YP=API yield point, measured in pounds per 100
square feet (lb/100 ft.sup.2); 10''/10' Gels=10 second/10 minute
gel strengths in pounds per 100 square feet; LSRV=Brookfield low
shear rate viscosity at 0.3 revolutions per minute, 0.063
sec.sup.-1 in centipoise; vol.=volume; 0/W=oil/water ratio,
vol/vol; mL=milliliters; g=grams; lb=pounds; cp=centipoise;
ft=feet; rpm=revolutions per minute; ES=emulsion stability, in
volts; psi=pounds per square inch; mm=millimeter; HTHP=high
temperature, high pressure fluid loss, measured at 200-350.degree.
F./500 psi differential and reported as milliliters (mL)/30 min,
evaluated in accordance with API Bulletin RP 13B-2 1990 or the
equivalent (e.g., API Recommended Practice (RP)
131/26.4--"Procedure for High Temperature, High Pressure (HTHP)
Filtration").
[0075] The plastic viscosity, yield point, and gel strengths were
obtained by the procedures set forth in API's Recommended Practice
13B-1. Using the viscometer as described in API Bulletin RP 13B-1,
the viscosity of the fluids was determined by taking readings at
600 rpm, 300 rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The following
calculations were made to determine the Plastic Viscosity (PV) and
Yield Point (YP): Plastic Viscosity=600 rpm reading minus 300 rpm
reading=PV value (in cP); Yield Point=300 rpm reading minus PV=YP
value (in lb/100 ft.sup.2). Gel strength readings were taken at 10
second, 10 minute, and 30 minute intervals in the following manner:
the viscometer was run at high speed for 10 seconds and then the
fluid remains static (undisturbed) for 10 seconds. At the end of 10
seconds, the maximum reading running the viscometer at 3 rpm was
recorded. This procedure was repeated for 10 minute and 30 minute
gels, the values being given in units of lb/100 ft.sup.2. The LSRV
(low shear rate viscosity) was obtained for the fluids using a
Brookfield Model LVTDV-I viscometer having a number 2 or 3 spindle
at 0.3 revolutions per minute (shear rate of 0.063 sec.sup.-1). The
LSRV is indicative of the suspension properties of the fluid, the
larger the LSRV, the better is the suspension of solids in the
fluid. The fluid loss was determined at 300.degree. F. in a
modified API HTHP cell at 500 psi differential pressure utilizing a
3 micron disk (Aloxite.TM.)
[0076] In the examples, the oil designated "LP-90E" is the
hydrogenated paraffinic hydrocarbon VASSA.TM. LP-90 containing 1.56
mL per bbl of the organoclay activator set forth in U.S. Pat. No.
7,897,544 (Dobson, et al.), incorporated herein by reference,
wherein the volume ratio of propylene carbonate to tall oil fatty
acid is 1:4. The oil designated "SAFRASOL D 80.TM." is a
dearomatized kerosene available from Safra Co. Ltd., P.O. Box 2824,
Jeddah 21461, Saudi Arabia. The hydrocarbon polymers utilized in
the examples designated "SBR 1012", "SBR 8113", "SBR 1013", "SBR
1006", and "SBR 4503" are crumb-type styrene-butadiene rubber
copolymers available from ISP Elastomers, 1615 Main Street, Port
Neches, Tex. 77651. The organophilic polyphenolic material is the
organophilic lignite "Petrolig.TM." available from Grinding and
Sizing Co., Inc., 7707 Wallisville Road, Houston, Tex. 77020, which
is lignite from Texas. The lignite preferably exhibits a humic acid
(HA) content (as determined by gravimetric analysis or the
equivalent), % HA, ranging from about 20% to about 50%.+-.2% HA;
greater than 50% d.b. volatile matter as determined by ASTM
D3176-09 and D3180; and an average ash content of 15% to 20% d.b.
ash (avg.), as determined by ASTM D-3174-12.
EXAMPLES
Example 1
Sample Preparation
[0077] To 0.6354 bbl equivalents (222.4 milliliters or 189.2 grams)
of VASSA.TM. LP-90 were added 1.0 mL of propylene carbonate, 5.75
grams of the organoclay CLAYTONE.RTM. IMG 400 (a product of
Southern Clay Products, Gonzales, Tex.), 0.1 mL of a secondary
emulsifier, 30 mL of a polymer concentrate containing 0.035 grams
per milliliter of <8 mesh SBR 8113 crumb and 0.4 grams per
milliliter of PETROLIG.TM. solublized and dispersed in VASSA.TM.
LP-90 oil (mixed 2 hr. at 175.degree. F.), 40 grams of ULTRA CARB
12 calcium carbonate bridging agent available from TBC-Brinadd,
Houston, Tex., and 352 grams of barite. The oil base mud was mixed
with a Brookfield overhead mixer at 5200 rpm for 40 total minutes.
The oil base mud was then evaluated for rheological properties and
fluid loss properties as set forth in Table 1.
[0078] The polymer concentrate (350 mL) was prepared as follows:
(1) Heat 210.3 mL of VASSA.TM. LP-90 oil to 175.degree. F.
(79.4.degree. C.) while mixing slowly on a Fann.TM. overhead mixer;
(2) Add 140 grams of PETROLIG.TM. and allow to disperse completely
(about 30 seconds at 5200 rpm); (3) With the Fann.TM. overhead
mixer at medium/low speed add 12.25 grams of SBR 8113 crumb (<8
mesh); (4) Continue mixing for 2 hours at 175.degree. F.,
increasing the speed of the mixer as the SBR dissolves and the
concentrate thickens.
Example 2
[0079] An oil base mud such as described in Example 1 was prepared,
except that the fluid contained 187.4 mL of VASSA.TM. LP-90, and
the 30 mL of the polymer concentrate used in Example 1 was replaced
by 33.6 mL of a concentrate containing 125 grams of PETROLIG.TM.
(114 mL) dissolved/dispersed in 236 mL VASSA.TM. LP-90, and 20 mL
of a concentrate containing 5% wt./vol. (0.05 grams/mL) SBR 8113 in
VASSA.TM. LP-90 oil. The data obtained is given in Table 2.
Comparative Example A
[0080] An oil base mud such as described in Example 1 was prepared,
except that the fluid contained 213.5 mL of VASSA.TM. LP-90, and
the 30 mL of the polymer concentrate used in Example 1 was replaced
by 21.0 mL of the 5% wt./vol. SBR 8113 crumb concentrate in Example
2 and 12.0 grams of PETROLIG.TM. powder. The data obtained is given
in Table A.
[0081] The data in Table I and Table 2 as compared to the data in
Table A indicates that the polymer concentrate containing both the
solublized SBR 8113 crumb copolymer and the solublized/dispersed
organolignite (Table 1) or the two concentrates containing the
solublized polymer and the solublized/dispersed organolignite
(Table 2) produced oil base muds exhibiting better fluid loss
control and better rheological stability after heating at
300.degree. F. as compared to adding the dry, powdered
organolignite, as exhibited by the HTHP/API fluid loss values of 20
and 22 respectively for the two solubilized compositions, compared
with the HTHP/API fluid loss value of nearly 32 when the
organophilic polyphenolic material was added in dry, powdered form
(i.e., dry blended). This data also shows that the solubilized
polymer and solubilized or dispersed organophilic polyphenolic
material in combination perform efficiently as fluid loss control
additives for well treatment or drilling fluids.
Example 3
[0082] To 213.5 mL of SAFRASOL D80.TM. were added 1.0 mL of the
organoclay activator set forth in U.S. Pat. No. 7,897,544 (Dobson
et al.), 5.75 grams of the organoclay CLAYTONE.RTM. IMG 400, 33.0
mL of the polymer concentrate containing 5.0% wt./vol. SBR 8113
crumb and 36.0% wt./vol. PETROLIG.TM. solubilized and dispersed in
SAFRASOL D80.TM. (mixed at 175.degree. F. for 2 hrs.), 40.0 grams
of ULTRA CARB 12, 353 grams of barite, and 0.1 mL of a secondary
emulsifier. The oil base mud was mixed as in Example 1 and
evaluated. The data obtained is set forth in Table 3.
Comparative Example B
[0083] To 0.61 bbl equivalents (213.5 mL) of VASSA.TM. LP-90 oil
are added 1.0 mL of propylene carbonate, 5.75 grams of the
organoclay CLAYTONE.RTM. IMG 400, 0.1 mL of a secondary emulsifier,
12.0 grams of PETROLIG.TM., 21 mL of a polymer concentrate
containing 5% wt/vol SBR 1012 crumb (1.05 grams SBR 1012), 40 grams
of ULTRA CARB 12, and 352 grams of barite to prepare one bbl
equivalent (350 mL) of an oil base fluid of this invention. The
fluid was admixed for 30 minutes with an overhead mixer. The oil
base fluid was then evaluated for rheological properties and fluid
loss properties as set forth in Table B.
Comparative Examples C, D
[0084] Comparative Example B was repeated except that the SBR 1012
was replaced by SBR 1013, and SBR 1006, respectively. The data
obtained is set forth in Tables C, and D, respectively. The data in
Tables B, C, and D, indicate the large viscosity increase of the
oil base fluids containing the dry organophilic polyphenolic
material (lignite powder) upon aging at high temperatures, and in
comparison with the data in Comparative Example A, that the cold
processed SBR crumb (SBR 8113) is preferred over the hot processed
SBR crumb (SBR 1012, 1013, 1006).
TABLE-US-00001 TABLE 1 After Hot Rolling Initial Initial 16 hr. @
300.degree. F. Temperature, .degree. F. 79 150 150 API Rheology 600
185 98 84 300 108 58 52 200 80 45 40 100 49 30 27 6 14 12 11 3 12
11 9 PV 77 40 32 YP 31 18 20 10''/10' Gels 20/37 18/36 14/26 LSRV
Peak 65,300 53,200 54,600 2 Minute 65,300 53,200 53,300 HTHP Fluid
Loss @ 300.degree. F. Spurt, mL 1.0 Trace 30 Minute, mL 9.0
22.0
TABLE-US-00002 TABLE 2 After Hot Rolling Initial Initial 16 hr. @
300.degree. F. Temperature, .degree. F. 83 150 150 API Rheology 600
210 104 90 300 124 64 53 200 93 49 40 100 58 33 26 6 15 13 10 3 11
11 9 PV 86 40 37 YP 38 24 16 10''/10' Gels 17/40 18/45 14/26 LSRV
Peak 97,000 60,000 55,700 2 Minute 97,000 60,000 55,700 HTHP Fluid
Loss @ 300.degree. F. Spurt, mL Trace 30 Minute, mL 20.0
TABLE-US-00003 TABLE A After Hot Rolling Initial Initial 16 hr. @
300.degree. F. Temperature, .degree. F. 82 150 150 API Rheology 600
128 74 132 300 72 42 96 200 51 32 85 100 31 21 70 6 7 7 56 3 5 5 55
PV 56 32 36 YP 16 10 60 10''/10' Gels 8/16 9/20 72/85 LSRV Peak
36,200 27,800 89,000 2 Minute 36,200 27,800 66,700 HTHP Fluid Loss
@ 300.degree. F. Spurt, mL 1.5 4.0 30 Minute, mL 13.0 31.5
TABLE-US-00004 TABLE 3 After Hot Rolling Initial 16 hr. @
300.degree. F. Temperature, .degree. F. 85 150 API Rheology 600 120
98 300 70 68 200 52 59 100 32 48 6 8 35 3 6 35 PV 50 30 YP 20 38
10''/10' Gels 10/26 45/65 LSRV 2 Minute 51,100 62,900 HTHP Fluid
Loss @ 300.degree. F. Spurt, mL 0 Trace 30 Minute, mL 5.0 8.0
TABLE-US-00005 TABLE B SBR 1012 After Hot Rolling Initial Initial
16 hr. @ 300.degree. F. Temperature, .degree. F. 82 150 150 API
Rheology 600 138 78 171 300 78 47 130 200 58 35 120 100 35 23 94 6
8 8 74 3 6 7 73 PV 50 47 41 YP 28 31 87 10''/10' Gels 10/20 10/22
88/110 LSRV Peak 51,800 45,200 108,000 2 Minute 51,800 45,200
91,200 HTHP Fluid Loss @ 300.degree. F. Spurt, mL Trace Trace 30
Minute, mL 13.5 16.5
TABLE-US-00006 TABLE C SBR 1013 After Hot Rolling Initial Initial
16 hr. @ 300.degree. F. Temperature, .degree. F. 82 150 150 API
Rheology 600 130 70 153 300 72 40 113 200 52 30 103 100 30 18 86 6
7 5 70 3 5 4 70 PV 58 30 40 YP 14 10 73 10''/10' Gels 8/20 7/16
91/95 LSRV Peak 47,300 38,400 259,000 2 Minute 47,300 38,400 74,000
HTHP Fluid Loss @ 300.degree. F. Spurt, mL Trace 1.0 30 Minute, mL
11.5 26.0
TABLE-US-00007 TABLE D SBR 1006 After Hot Rolling Initial Initial
16 hr. @ 300.degree. F. Temperature, .degree. F. 82 150 150 API
Rheology 600 115 66 184 300 64 38 130 200 46 28 125 100 28 18 115 6
6 5 91 3 4 4 91 PV 51 28 54 YP 13 10 76 10''/10' Gels 8/19 7/15
105/112 LSRV Peak 41,000 27,300 83,000 2 Minute 41,000 27,300
54,800 HTHP Fluid Loss @ 300.degree. F. Spurt, mL Trace 1.0 30
Minute, mL 12.5 29.5
[0085] Other and further embodiments utilizing one or more aspects
of the inventions described above can be devised without departing
from the spirit of Applicant's invention. For example, other,
equivalent polymers not listed herein, or co-polymers of such
polyphenolic materials, may be used in the compositions without
deviating from the scope of this disclosure. Further, the various
methods and embodiments of the methods of manufacture and assembly
of the system, as well as location specifications, can be included
in combination with each other to produce variations of the
disclosed methods and embodiments. Discussion of singular elements
can include plural elements and vice-versa.
[0086] The order of steps can occur in a variety of sequences
unless otherwise specifically limited. The various steps described
herein can be combined with other steps, interlineated with the
stated steps, and/or split into multiple steps. Similarly, elements
have been described functionally and can be embodied as separate
components or can be combined into components having multiple
functions.
[0087] The inventions have been described in the context of
preferred and other embodiments and not every embodiment of the
invention has been described. Obvious modifications and alterations
to the described embodiments are available to those of ordinary
skill in the art. The disclosed and undisclosed embodiments are not
intended to limit or restrict the scope or applicability of the
invention conceived of by the Applicants, but rather, in conformity
with the patent laws, Applicants intend to fully protect all such
modifications and improvements that come within the scope or range
of equivalent of the following claims.
* * * * *