U.S. patent application number 15/278331 was filed with the patent office on 2017-01-19 for aqueous solution and method for use thereof.
The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Jian He, Richard Hutchins, Li Jiang, Timothy G. J. Jones, Chad Kraemer, Bruno Lecerf, Jack Li, Murtaza Ziauddin.
Application Number | 20170015891 15/278331 |
Document ID | / |
Family ID | 53006135 |
Filed Date | 2017-01-19 |
United States Patent
Application |
20170015891 |
Kind Code |
A1 |
Jiang; Li ; et al. |
January 19, 2017 |
AQUEOUS SOLUTION AND METHOD FOR USE THEREOF
Abstract
Oilfield treatment compositions contain water, hydrochloric acid
at a concentration between 15 wt % and 45.7 wt % and a first and
second fixing agent. The first fixing agent comprises urea, a urea
derivative or both. The second fixing agent may be a mixture or
amines and alcohols. These compositions provide corrosion
inhibition when exposed to steel. The compositions may also contain
an inhibitor aid.
Inventors: |
Jiang; Li; (Katy, TX)
; Lecerf; Bruno; (Houston, TX) ; Jones; Timothy G.
J.; (Cambridge, GB) ; Ziauddin; Murtaza;
(Katy, TX) ; Hutchins; Richard; (Sugar Land,
TX) ; He; Jian; (Sugar Land, TX) ; Li;
Jack; (Sugar Land, TX) ; Kraemer; Chad; (Katy,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Family ID: |
53006135 |
Appl. No.: |
15/278331 |
Filed: |
September 28, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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14072395 |
Nov 5, 2013 |
9476287 |
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15278331 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C23F 11/04 20130101;
C09K 8/54 20130101; E21B 41/02 20130101; E21B 43/28 20130101; E21B
43/26 20130101; C09K 2208/32 20130101 |
International
Class: |
C09K 8/54 20060101
C09K008/54; E21B 43/26 20060101 E21B043/26; E21B 41/02 20060101
E21B041/02 |
Claims
1. A composition, comprising: (i) water at a concentration lower
than or equal to 20 wt %; (ii) hydrochloric acid at a concentration
between 15 wt % and 45.7 wt %; (iii) a first fixing agent
comprising urea, a urea derivative or both; and (iv) a second
fixing agent, wherein the first fixing agent:hydrochloric acid
molar ratio is between 0.4 and 3.0 inclusive.
2. The composition of claim 1, wherein the urea derivative
comprises 1,1-dimethylurea, 1,3-dimethylurea, 1,1-diethylurea,
1,3-diethylurea, 1,1-diallylurea, 1,3-diallylurea,
1,1-dipropylurea, 1,3-dipropylurea, 1,1-dibutylurea,
1,3-dibutylurea, 1,1,3,3-tetramethylurea, 1,1,3,3-tetraethylurea,
1,1,3,3-tetrapropylurea, 1,1,3,3-tetrabutylurea, ethyleneurea,
propyleneurea, 1,3-dimethylpropyleneurea or
1,3-dimethylethyleneurea, or combinations thereof.
3. The composition of claim 1, wherein the second fixing agent
comprises a mixture of amines and alcohols.
4. The composition of claim 3, wherein the concentration of the
second fixing agent is between 0.1 wt % and 0.5 wt % inclusive.
5. The composition of claim 3, further comprising an inhibitor aid
comprising a mixture of phenyl ketones and quarternary amines.
6. The composition of claim 5, wherein the concentration of the
inhibitor aid is between 0.4 wt % and 0.8 wt % inclusive.
7. The composition of claim 1, further comprising hydrofluoric acid
at a concentration higher than or equal to 0.25 wt %.
8.-20. (canceled)
Description
RELATED APPLICATION DATA
[0001] None.
BACKGROUND
[0002] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0003] The technical field generally, but not exclusively, relates
to high-concentration hydrochloric acid (HCl) solutions with urea,
and uses thereof. Previously known solutions of HCl with urea, for
example as described in U.S. Pat. No. 4,466,893, utilize urea with
low HCl concentrations (at or below 15%) and in the presence of
various plant-based polysaccharide gums. HCl above 15% was
determined to be deleterious to the properties of previously
available solutions.
SUMMARY
[0004] In an aspect, embodiments relate to compositions comprising
water at a concentration lower than or equal to 20 wt %,
hydrochloric acid at a concentration between 15 wt % and 45.7 wt %,
and a first fixing agent comprising urea, a urea derivative or
both, and a second fixing agent. The first fixing
agent:hydrochloric acid molar ratio is between 0.4 and 3.0.
[0005] In a further aspect, embodiments relate to methods for
inhibiting the corrosion of steel exposed to an acidic composition.
A composition is prepared that comprises water at a concentration
lower than or equal to 20 wt %, hydrochloric acid at a
concentration between 15 wt % and 45.7 wt %, and a first fixing
agent comprising urea, a urea derivative or both, and a second
fixing agent. The first fixing agent:hydrochloric acid molar ratio
is between 0.4 and 3.0. Then, steel is exposed to the
composition.
[0006] In yet a further aspect, embodiments relate to methods for
treating a subterranean well having a wellbore, at least one steel
casing and a formation. A composition is prepared that comprises
water at a concentration lower than or equal to 20 wt %,
hydrochloric acid at a concentration between 15 wt % and 45.7 wt %,
and a first fixing agent comprising urea, a urea derivative or
both, and a second fixing agent. The first fixing
agent:hydrochloric acid molar ratio is between 0.4 and 3.0. An
oilfield treatment fluid that includes the composition is provided
to a high-pressure pump. The high-pressure pump is operated to
place the composition in the well such that the composition
contacts the steel casing.
[0007] This summary is provided to introduce a selection of
concepts that are further described below in the illustrative
embodiments. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter. Further embodiments, forms, objects, features,
advantages, aspects, and benefits shall become apparent from the
following description and drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 depicts example equipment to treat a wellbore and/or
a formation fluidly coupled to the wellbore.
DETAILED DESCRIPTION OF SOME ILLUSTRATIVE EMBODIMENTS
[0009] For the purposes of promoting an understanding of the
principles of the disclosure, reference will now be made to the
embodiments illustrated in the drawings and specific language will
be used to describe the same. It will nevertheless be understood
that no limitation of the scope of the claimed subject matter is
thereby intended, any alterations and further modifications in the
illustrated embodiments, and any further applications of the
principles of the application as illustrated therein as would
normally occur to one skilled in the art to which the disclosure
relates are contemplated herein.
[0010] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure. In addition, the compositions
used/disclosed herein can also comprise some components other than
those cited. In the summary and this detailed description, each
numerical value should be read once as modified by the term "about"
(unless already expressly so modified), and then read again as not
so modified unless otherwise indicated in context. Also, in the
summary and this detailed description, it should be understood that
a concentration range listed or described as being useful,
suitable, or the like, is intended that any and every concentration
within the range, including the end points, is to be considered as
having been stated. For example, "a range of from 1 to 10" is to be
read as indicating each and every possible number along the
continuum between about 1 and about 10. Thus, even if specific data
points within the range, or even no data points within the range,
are explicitly identified or refer to only a few specific, it is to
be understood that the Applicant appreciates and understands that
any and all data points within the range are to be considered to
have been specified, and that the Applicant possessed knowledge of
the entire range and all points within the range.
[0011] The term "substantially no polysaccharides" as utilized
herein should be understood broadly. An example solution having
substantially no polysaccharides includes a solution without any
polysaccharides intentionally present in the solution. Another
example solution having substantially no polysaccharides includes a
fluid having polysaccharides only incidentally, for example as part
of an additive, and not in an amount sufficient to support
development of higher viscosity in the fluid. Example amounts of
polysaccharides present in a solution include less than 0.24 g/L (2
lbm/1000 gal), less than 0.12 g/L (1 lbm/1000 gal), less than 0.06
g/L (0.5 lbm/gal), less than 0.012 g/L (0.1 lbm/1000 gal) and a
solution having no polysaccharides. Yet another example solution
having substantially no polysaccharides includes a fluid having no
detectable polysaccharides, where the detection is performed
through rheological testing. Yet another example solution having
substantially no polysaccharides contemplates that polysaccharides
include materials such as: galactomannans such as guar gum, gum
karaya, gum tragacanth, gum ghatti, gum acacia, gum konjak, shariz,
locus, psyllium, tamarind, gum tara, carrageenan, gum kauri, and
modified guars such as hydroxy-propyl guar, hydroxy-ethyl guar,
carboxy-methyl hydroxy-ethyl guar, and carboxy-methyl
hydroxy-propyl guar.
[0012] The term "formation" as utilized herein should be understood
broadly. A formation includes any underground fluidly porous
formation, and can include without limitation any oil, gas,
condensate, mixed hydrocarbons, paraffin, kerogen, water, and/or
CO.sub.2 accepting or providing formations. A formation can be
fluidly coupled to a wellbore, which may be an injector well, a
producer well, a monitoring well and/or a fluid storage well. The
wellbore may penetrate the formation vertically, horizontally, in a
deviated orientation, or combinations of these. The formation may
include any geology, including at least a sandstone, limestone,
dolomite, shale, tar sand, and/or unconsolidated formation. The
wellbore may be an individual wellbore and/or a part of a set of
wellbores directionally deviated from a number of close proximity
surface wellbores (e.g. off a pad or rig) or single initiating
wellbore that divides into multiple wellbores below the
surface.
[0013] The term "oilfield treatment fluid" as utilized herein
should be understood broadly. In certain embodiments, an oilfield
treatment fluid includes any fluid having utility in an oilfield
type application, including a gas, oil, geothermal, or injector
well. In certain embodiments, an oilfield treatment fluid includes
any fluid having utility in any formation or wellbore described
herein. In certain embodiments, an oilfield treatment fluid
includes a matrix acidizing fluid, a wellbore cleanup fluid, a
pickling fluid, a near wellbore damage cleanup fluid, a surfactant
treatment fluid, an unviscosified fracture fluid (e.g. slick water
fracture fluid), and/or any other fluid consistent with the fluids
otherwise described herein. An oilfield treatment fluid may include
any type of additive known in the art, which are not listed herein
for purposes of clarity of the present description, but which may
include at least friction reducers, inhibitors, surfactants and/or
wetting agents, fluid diverting agents, particulates, acid
retarders (except where otherwise provided herein), organic acids,
chelating agents, energizing agents (e.g. CO.sub.2 or N.sub.2), gas
generating agents, solvents, emulsifying agents, flowback control
agents, resins, breakers, and/or non-polysaccharide based
viscosifying agents.
[0014] The term "high pressure pump" as utilized herein should be
understood broadly. In certain embodiments, a high pressure pump
includes a positive displacement pump that provides an oilfield
relevant pumping rate--for example at least 80 L/min (0.5 bbl/min
or bpm), although the specific example is not limiting. A high
pressure pump includes a pump capable of pumping fluids at an
oilfield relevant pressure, including at least 3.5 MPa (500 psi),
at least 6.9 MPa (1,000 psi), at least 13.8 MPa (2,000 psi), at
least 34.5 MPa (5,000 psi), at least 68.9 MPa (10,000 psi), up to
103.4 MPa (15,000 psi), and/or at even greater pressures. Pumps
suitable for oilfield cementing, matrix acidizing, and/or hydraulic
fracturing treatments are available as high pressure pumps,
although other pumps may be utilized.
[0015] The term "treatment concentration" as utilized herein should
be understood broadly. A treatment concentration in the context of
an HCl concentration is a final concentration of the fluid before
the fluid is placed in the wellbore and/or the formation for the
treatment. The treatment concentration may be the mix concentration
available from the HCl containing fluid at the wellsite or other
location where the fluid is provided from. The treatment
concentration may be modified by dilution before the treating
and/or during the treating. Additionally, the treatment
concentration may be modified by the provision of additives to the
fluid. Example and non-limiting treatment concentrations include
7.5%, 15%, 20%, 28%, 36%, and/or up to 45.7% HCl concentration in
the fluid.
[0016] In certain embodiments, a treatment concentration is
determined upstream of additives deliver (e.g. at a blender,
hopper, or mixing tub) and the concentration change from the
addition of the additives is ignored. In certain embodiments, the
treatment concentration is a liquid phase or acid phase
concentration of a portion of the final fluid--for example when the
fluid is an energized or emulsified fluid. In certain embodiments
the treatment concentration exceeds 15%. In certain embodiments,
the fluid concentration exceeds 36% or exceeds 37%.
[0017] The term "urea derivative" as used herein should be
understood broadly. An example urea derivative includes any urea
compound having at least one of the four nitrogen bonded hydrogens
substituted. The substitution products may be anything, but include
at least any hydrocarbon group, and may include substitutions on
one or both of the urea nitrogens. Additionally or alternatively,
substitutions may include cyclic groups (e.g. ethylene urea),
aromatic groups, and/or nitrogen containing hydrocarbon groups. The
inclusion of a urea derivative in the present disclosure should not
be read as limiting to other urea derivatives which may be used as
an alternative or addition.
[0018] Applicant has determined that a first fixing agent (FA1) and
a second fixing agent (FA2) have utility in inhibiting corrosion of
steel exposed to hydrochloric acid solutions. In an aspect,
embodiments relate to compositions that comprise water at a
concentration lower than or equal to 20 wt %, hydrochloric acid, a
first fixing agent and a second fixing agent. The water
concentration may be lower than 10 wt %. The hydrochloric acid
concentration may be between 15 wt % and 45.7 wt %, or between 15
wt % and 40 wt % or between 15 wt % and 37 wt %. The FA1 comprises
urea, a urea derivative or both. The molar ratio FA1:HCl may be
between 0.4 and 3.0 inclusive, or between 0.75 and 2.4 inclusive or
between 1.0 and 2.4 inclusive.
[0019] In a further aspect, embodiments relate to methods for
inhibiting the corrosion of steel exposed to an acidic composition.
A composition is prepared that comprises water at a concentration
lower than or equal to 20 wt %, hydrochloric acid, a first fixing
agent and a second fixing agent. The water concentration may be
lower than 10 wt %. The hydrochloric acid concentration may be
between 15 wt % and 45.7 wt %, or between 15 wt % and 40 wt % or
between 15 wt % and 37 wt %. The FA1 comprises urea, a urea
derivative or both. The molar ratio FA1:HCl may be between 0.4 and
3.0 inclusive, or between 0.75 and 2.4 inclusive or between 1.0 and
2.4 inclusive. The steel is then exposed to the composition.
Further improvements are realized in that urea and urea derivatives
as fixing agents are less costly and more environmentally friendly
than other corrosion inhibitors known in the art.
[0020] In yet a further aspect, embodiments relate to methods for
treating a subterranean well having a steel casing. A composition
is prepared that comprises water at a concentration lower than or
equal to 20 wt %, hydrochloric acid, a first fixing agent and a
second fixing agent. The water concentration may be lower than 10
wt %. The hydrochloric acid concentration may be between 15 wt %
and 45.7 wt %, or between 15 wt % and 40 wt % or between 15 wt %
and 37 wt %. The FA1 comprises urea, a urea derivative or both. The
molar ratio FA1:HCl may be between 0.4 and 3.0 inclusive, or
between 0.75 and 2.4 inclusive or between 1.0 and 2.4 inclusive. An
oilfield treatment fluid that includes the composition is provided
to a high-pressure pump. The high-pressure pump is operated to
place the composition in the well such that the composition
contacts the steel casing.
[0021] The hydrochloric acid may be transported to a wellsite, the
acid having a concentration between 28 wt % and 45.7 wt %. The acid
may then be diluted to a treatment concentration before providing
the oilfield treatment fluid to the high-pressure pump.
[0022] The operation of the pump may comprise at least one of (i)
injecting the treatment fluid into the formation at matrix rates;
(ii) injecting the treatment fluid into the formation at a pressure
equal to that necessary to fracture the formation; and (iii)
contacting at least one of the wellbore and the formation with the
oilfield treatment fluid.
[0023] For all aspects, the urea derivatives may comprise
1,1-dimethylurea, 1,3-dimethylurea, 1,1-diethylurea,
1,3-diethylurea, 1,1-diallylurea, 1,3-diallylurea,
1,1-dipropylurea, 1,3-dipropylurea, 1,1-dibutylurea,
1,3-dibutylurea, 1,1,3,3-tetramethylurea, 1,1,3,3-tetraethylurea,
1,1,3,3-tetrapropylurea, 1,1,3,3-tetrabutylurea, ethyleneurea,
propyleneurea, 1,3-dimethylpropyleneurea or
1,3-dimethylethyleneurea, or combinations thereof.
[0024] For all aspects, the second fixing agent (FA2) may comprise
a mixture of amines and alcohols. The FA2 concentration may be
between 0.1 wt % and 0.5 wt % inclusive, or between 0.2 wt % and
0.5 wt % inclusive.
[0025] For all aspects, the compositions may further comprise an
inhibitor aid (IA) that comprises a mixture of phenyl ketones and
quaternary amines. The IA concentration may be between 0.4 wt % and
0.8 wt % inclusive, or between 0.5 wt % and 0.8 wt % inclusive.
[0026] For all aspects, the compositions may further comprise
hydrofluoric acid (HF) at a concentration higher than or equal to
0.25 wt %. The HF may be present at concentrations up to 2%, up to
6%, up to 10%, up to 15%, or greater amounts. The HF may be present
in addition to the amount of HCl, and/or as a substitution for an
amount of the HCl.
[0027] Referencing FIG. 1, a system 100 is depicted having example
equipment to treat a wellbore 106 and/or a formation 108 fluidly
coupled to the wellbore 106. The formation 108 may be any type of
formation with a bottomhole temperature up to at least 177.degree.
C. (350.degree. F.). The wellbore 106 is depicted as a vertical,
cased and cemented wellbore 106, having perforations providing
fluid communication between the formation 108 and the interior of
the wellbore 106. However, none of the particular features of the
wellbore 106 are limiting, and the example is provided only to
provide an example context 100 for a procedure.
[0028] The system 100 includes a high-pressure pump 104 having a
source of an aqueous solution 102. In a first example, the aqueous
solution 102 includes a FA1 and HCl, the HCl in an amount between
5% and 45.7% inclusive, and the FA1 present in a FA1:HCl molar
ratio between 0.4 and 3.0 inclusive. The aqueous solution 102
further includes water in an amount sufficient to dissolve the HCl
and the FA1, and the aqueous solution 102 includes substantially no
polysaccharides. The high pressure pump 104 is fluidly coupled to
the wellbore 106, through high pressure lines 120 in the example.
The example system 100 includes a tubing 126 in the wellbore 106.
The tubing 126 is optional and non-limiting. In certain examples,
the tubing 106 may be omitted, a coiled tubing unit (not shown) may
be present, and/or the high pressure pump 104 may be fluidly
coupled to the casing or annulus 128. The tubing or casing may be
made of steel.
[0029] Certain additives (not shown) may be added to the aqueous
solution 102 to provide an oilfield treatment fluid. Additives may
be added at a blender (not shown), at a mixing tub of the high
pressure pump 104, and/or by any other method. In certain
embodiments, a second fluid 110 may be a diluting fluid, and the
aqueous solution 102 combined with some amount of the second fluid
110 may make up the oilfield treatment fluid. The diluting fluid
may contain no HCl, and/or HCl at a lower concentration than the
aqueous solution 102. The second fluid 110 may additionally or
alternatively include any other materials to be added to the
oilfield treatment fluid, including additional amounts of an FA1,
or of FA2 or IA or both. In certain embodiments, an additional FA1
solution 112 is present and may be added to the aqueous solution
102 during a portion or all of the times when the aqueous solution
102 is being utilized. The additional FA1 solution 112 may include
the same or a different FA1 from the aqueous solution 102, may
include all of the FA1 for the oilfield treatment fluid, and/or may
include FA1 at a distinct concentration from the aqueous
solution.
[0030] The high-pressure pump 104 can treat the wellbore 106 and/or
the formation 108, for example by positioning fluid therein, by
injecting the fluid into the wellbore 106, and/or by injecting the
fluid into the formation 108. Example and non-limiting operations
include any oilfield treatment without limitation. Potential fluid
flows include flowing from the high-pressure pump 104 into the
tubing 126, into the formation 108, and/or into the annulus 128.
The fluid may be recirculated out of the well before entering the
formation 108, for example utilizing a back side pump 114. In the
example, the annulus 128 is shown in fluid communication with the
tubing 126, although in certain embodiments the annulus 128 and the
tubing 126 may be isolated (e.g. with a packer). Another example
fluid flow includes flowing the oilfield treatment fluid into the
formation at a matrix rate (e.g. a rate at which the formation is
able to accept fluid flow through normal porous flow), and/or at a
rate that produces a pressure exceeding a hydraulic fracturing
pressure. The fluid flow into the formation may be either flowed
back out of the formation, and/or flushed away from the near
wellbore area with a follow up fluid. Fluid flowed to the formation
may be flowed to a pit or containment (not shown), back into a
fluid tank, prepared for treatment, and/or managed in any other
manner known in the art. Acid remaining in the returning fluid may
be recovered or neutralized.
[0031] Another example fluid flow includes the aqueous solution 102
including HCl, with FA1 being optional and in certain embodiments
not present in the aqueous solution 102. The example fluid flow
includes a second aqueous solution 116 including FA1 (urea or a
urea derivative). The fluid flow includes, sequentially, a first
high pressure pump 104 and a second high pressure pump 118 treating
the formation 108. The second high-pressure pump 118 in the example
is fluidly coupled to the tubing 126 through a second high pressure
line 122. The fluid delivery arrangement is optional and
non-limiting. In certain embodiments, a single pump may deliver
both the aqueous solution 102 and the second aqueous solution 116.
In the example, either the first aqueous solution 102 or the second
aqueous solution 116 may be delivered first, and one or more of the
solutions 102, 116 may be delivered in multiple stages, including
potentially some stages where the solutions 102, 116 are mixed.
[0032] The schematic flow descriptions which follow provide
illustrative embodiments of performing procedures for treating
formations and/or wellbores. Operations illustrated are understood
to be examples only, and operations may be combined or divided, and
added or removed, as well as re-ordered in whole or part, unless
stated explicitly to the contrary herein. Certain operations
illustrated may be implemented by a computer executing a computer
program product on a computer readable medium, where the computer
program product comprises instructions causing the computer to
execute one or more of the operations, or to issue commands to
other devices to execute one or more of the operations.
[0033] Without limitation, it is contemplated the procedure
includes any one of a number of specific embodiments. An example
includes treating with the first oilfield treatment fluid and then
the second oilfield treatment fluid, or treating with the second
oilfield treatment fluid then the first oilfield treatment fluid.
An example includes the first oilfield treatment fluid including no
FA1, including FA1 in an amount distinct from the amount of FA1 in
the second oilfield treatment fluid, and/or including FA1 in an
amount that is the same or similar to the amount of FA1 in the
second oilfield treatment fluid. An example includes the second
oilfield treatment fluid including no HCl, including HCl in an
amount distinct from the amount of HCl in the first oilfield
treatment fluid, and/or including FA1 in an amount that is the same
or similar to the amount of FA1 in the first oilfield treatment
fluid. The first and second oilfield treatment fluids do not
include both the HCl amount and the FA1 amount present in identical
amounts with each other, although either one of the HCl amount or
the FA1 amount may be present in identical amounts with each other.
Additionally, it is contemplated that multiple stages of the first
oilfield treatment fluid and/or the second oilfield treatment fluid
may be performed, which stages may be equal or unequal in size or
number, and/or which may include spacer fluids or not between any
one or more of the stages.
[0034] As is evident from the figures and text presented above, a
variety of embodiments according to the present disclosure are
contemplated.
[0035] The present disclosure may be further illustrated by the
following examples. These examples do not limit the scope of the
disclosure.
EXAMPLES
[0036] The following examples disclose the results of corrosion
tests performed with N80 steel coupons. The tests conformed to
standard procedures published by the American Society for Testing
and Materials (ASTM). The pitting index is a qualitative visual
evaluation of the number of pits that have developed on the coupon
surface. The index scale is between 0 and 5, and skilled
practitioners endeavor to achieve a pitting index of at most 2. The
corrosion rate is expressed in lb/ft.sup.2, an oilfield unit that
has no SI equivalent. In the oilfield, most practitioners limit the
corrosion rate to at most 0.05 lb/ft.sup.2.
[0037] Chemicals used during the tests were hydrochloric acid
(HCl), a first fixing agent FA1 (urea or ethyleneurea [EU]), a
second fixing agent FA2 (High Temperature Corrosion Inhibitor,
available from Nalco, Sugar Land, Tex., USA) and an inhibitor aid
(CRONOX 247 ES, available from Baker Petrolite, Houston, Tex.,
USA). Second fixing agent FA2 is a mixture of amines and alcohols.
The inhibitor aid is a mixture of phenyl ketones and quaternary
amines.
Example 1
[0038] A 15 wt % solution of HCl was prepared by diluting 37 wt %
HCl with urea (FA1) and water. Corrosion tests were performed
during which the HCl solution was tested alone, with FA1, and with
FA1 and FA2. The solutions were heated to 93.degree. C.
(200.degree. F.) during which a steel coupon was immersed in each
solution for four hours. The results are presented in Table 1.
TABLE-US-00001 TABLE 1 Corrosion test results: N80 steel;
93.degree. C.; 4 h Acid Formulation Corrosion Results FA1/HCl
Corrosion (molar Inhibitor Pitting Rate Fluid ratio) FA2 aid Index
(lb/ft.sup.2) 15% HCl N/A N/A N/A 3 0.6990 15% HCl + Urea 1 N/A N/A
3 0.4635 15% HCl + Urea 1 0.1% N/A 1 0.0068
[0039] Compared to the control solution of 15% HCl, the presence of
FA1 alone at an FA1/HCl molar ratio equal to 1 reduced the
corrosion rate by more than 33%; however, the corrosion rate was
significantly higher than 0.05 lb/ft.sup.2. Satisfactory corrosion
inhibition was observed by adding a small amount of FA2.
Example 2
[0040] A 15 wt % solution of HCl was prepared by diluting 37 wt %
HCl with urea (FA1) and water. Corrosion tests were performed
during which the HCl solution was tested alone, and with a mixture
of FA2 and inhibitor aid. The solutions were heated to 135.degree.
C. (275.degree. F.) during which a steel coupon was immersed in
each solution for four hours. The results are presented in Table
2.
TABLE-US-00002 TABLE 2 Corrosion test results: N80 steel;
135.degree. C.; 4 h Acid Formulation Corrosion Results FA1/HCl
Corrosion (molar Inhibitor Pitting Rate Fluid ratio) FA2 aid Index
(lb/ft.sup.2) 15% HCl N/A N/A N/A 4 0.6484 15% HCl + Urea 0.4 N/A
N/A 4 0.1066 15% HCl + Urea 0.4 0.1% 0.4% 0 0.0091
[0041] The presence of FA1 at a molar ratio FA1/HCl=0.4 reduced the
corrosion rate more than six fold compared to a solution of 15% HCl
alone. However, the corrosion rate remained above 0.05 lb/ft.sup.2.
Satisfactory results were obtained when both FA2 and inhibitor aid
were present.
[0042] The examples provided herein are illustrative only and do
not limit the scope of the disclosure.
[0043] While the disclosure has provided specific and detailed
descriptions to various embodiments, the same is to be considered
as illustrative and not restrictive in character. Although only a
few example embodiments have been described in detail above, those
skilled in the art will readily appreciate that many modifications
are possible in the example embodiments without materially
departing from this invention. Accordingly, all such modifications
are intended to be included within the scope of this disclosure as
defined in the following claims. In the claims, means-plus-function
clauses are intended to cover the structures described herein as
performing the recited function and not only structural
equivalents, but also equivalent structures. Thus, although a nail
and a screw may not be structural equivalents in that a nail
employs a cylindrical surface to secure wooden parts together,
whereas a screw employs a helical surface, in the environment of
fastening wooden parts, a nail and a screw may be equivalent
structures.
[0044] Moreover, in reading the claims, it is intended that when
words such as "a," "an," "at least one," or "at least one portion"
are used there is no intention to limit the claim to only one item
unless specifically stated to the contrary in the claim. When the
language "at least a portion" and/or "a portion" is used the item
can include a portion and/or the entire item unless specifically
stated to the contrary. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn.112, paragraph 6 for any
limitations of any of the claims herein, except for those in which
the claim expressly uses the words `means for` together with an
associated function.
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