U.S. patent application number 13/662878 was filed with the patent office on 2014-05-01 for withanolide corrosion inhibitor for carbon steel.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERICES, INC.. Invention is credited to Ravikant S. Belakshe, Achala V. Danait, Lalit Pandurang Salgaonkar.
Application Number | 20140119984 13/662878 |
Document ID | / |
Family ID | 50547418 |
Filed Date | 2014-05-01 |
United States Patent
Application |
20140119984 |
Kind Code |
A1 |
Belakshe; Ravikant S. ; et
al. |
May 1, 2014 |
WITHANOLIDE CORROSION INHIBITOR FOR CARBON STEEL
Abstract
Acidic fluids used in wells or pipelines cause corrosion of
carbon steel. Methods for inhibiting corrosion include contacting
carbon steel with a fluid having an aqueous acidic phase including
a material selected from the group consisting of: a material of a
plant in the Solanaceae family, an extract of a material of a plant
in the Solanaceae family, a withanolide, a source of a withanolide,
a withanolide derivative, a source of a withanolide derivative, and
any combination thereof. The methods have wide application in
various kinds of operations involved in the production or
transportation of oil and gas, such as acid stimulation in a well
or remedial treatment in a pipeline.
Inventors: |
Belakshe; Ravikant S.;
(Pune, IN) ; Salgaonkar; Lalit Pandurang; (Pune,
IN) ; Danait; Achala V.; (Pune, IN) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
50547418 |
Appl. No.: |
13/662878 |
Filed: |
October 29, 2012 |
Current U.S.
Class: |
422/12 ;
166/312 |
Current CPC
Class: |
C23F 11/04 20130101;
C09K 8/54 20130101; F16L 58/00 20130101; C09K 2208/32 20130101;
C09K 8/74 20130101; E21B 41/02 20130101 |
Class at
Publication: |
422/12 ;
166/312 |
International
Class: |
C23F 11/04 20060101
C23F011/04; E21B 37/06 20060101 E21B037/06 |
Claims
1. A method of treating a portion of a well or a pipeline with a
fluid comprising an aqueous acidic phase, the method comprising the
steps of: (A) forming the fluid comprising an aqueous acidic phase,
the fluid additionally comprising a material selected from the
group consisting of: a material of a plant in the Solanaceae
family, an extract of a material of a plant in the Solanaceae
family, a withanolide, a source of a withanolide, a withanolide
derivative, a source of a withanolide derivative, and any
combination thereof; and (B) introducing the fluid into the portion
of the well or pipeline; wherein the fluid contacts carbon steel in
the well or pipeline.
2. A method of inhibiting corrosion of carbon steel to be contacted
with a fluid comprising an aqueous acidic phase, the method
comprising the steps of: (A) forming the fluid comprising an
aqueous acidic phase, the fluid additionally comprising a material
selected from the group consisting of: a material of a plant in the
Solanaceae family, an extract of a material of a plant in the
Solanaceae family, a withanolide, a source of a withanolide, a
withanolide derivative, a source of a withanolide derivative, and
any combination thereof; and (B) contacting the carbon steel with
the fluid.
3. A method of contacting carbon steel with a fluid comprising an
aqueous acidic phase, the method comprising the step of: including
in the fluid a material selected from the group consisting of: a
material of a plant in the Solanaceae family, an extract of a
material of a plant in the Solanaceae family, a withanolide, a
source of a withanolide, a withanolide derivative, a source of a
withanolide derivative, and any combination thereof.
4. The method according to claim 3, wherein the fluid is a
water-based fluid.
5. The method according to claim 3, wherein the aqueous acidic
phase comprises a water-soluble salt.
6. The method according to claim 3, wherein the aqueous acidic
phase comprises one or more salts selected from the group
consisting of alkali metal halides.
7. The method according to claim 3, wherein the aqueous acidic
phase comprises an acid selected from the group consisting of:
hydrochloric acid, hydrofluoric acid, formic acid, acetic acid,
citric acid, and any mixture thereof present in the aqueous acid
solution in a concentration in the range of from about 2% to about
35% by weight of water.
8. The method according to claim 3, wherein the aqueous acidic
phase comprises a mineral acid having a pKa(1) less than -1.74.
9. The method according to claim 3, wherein the aqueous acidic
phase comprises an organic acid having a pKa(1) lesser than 5.
10. The method according to claim 3, wherein the aqueous acidic
phase has a pH less than 4.
11. The method according to claim 3, wherein the material of a
plant in the Solanaceae family is of the root of the plant.
12. The method according to claim 3, wherein the plant in the
Solanaceae family is also selected for producing a withanolide.
13. The method according to claim 3, wherein the plant in the
Solanaceae family is also in a genera selected from the group
consisting of: Datura, Dunalia, Iochroma, Lycium, Nicandra,
Physalis, Salpichroa, Solanum, Withania, and Jaborosa.
14. The method according to claim 3, wherein the plant in the
Solanaceae family is also in the genera Withania.
15. The method according to claim 3, wherein the extract is in
particulate form when being added to the fluid.
16. The method according to claim 3, wherein the extract is in a
liquid solution when being added to the fluid.
17. The method according to claim 3, wherein the material is
biodegradable.
18. The method according to claim 3, wherein the material is a
concentration in the range of from about 0.01% wt/vol to about 20%
wt/vol of the aqueous acid solution.
19. The method according to claim 3, wherein the fluid additionally
comprises a corrosion inhibitor intensifier.
20. The method according to claim 3, wherein the fluid additionally
comprises potassium iodide.
21. The method according to claim 3, wherein a design temperature
is at a temperature of greater than 200.degree. F.
22. The method according to claim 3, wherein a design temperature
for contacting of the carbon steel and the fluid is less than
300.degree. F.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
TECHNICAL FIELD
[0002] The inventions are in the field of producing crude oil or
natural gas from subterranean formations. More particularly, the
inventions relate to corrosion inhibition of carbon steel in wells
or transportation pipelines.
BACKGROUND
Acidic Fluids, Corrosion, and Inhibition
[0003] Acidic fluids are present in a multitude of operations in
the oil and gas industry. For example, acidic fluids are often used
in wells penetrating subterranean formations. Such acidic fluids
may be used, for example, in stimulation operations or clean-up
operations in oil and gas wells. Acidic stimulation operations may
use these treatment fluids in hydraulic fracturing and matrix
acidizing treatments. In operations using acidic well fluids, metal
surfaces of piping, tubing, pumps, blending equipment, downhole
tools, etc. may be exposed to the acidic fluid.
[0004] Acidic fluids are sometimes used in pipelines that are used
for the transportation of hydrocarbons. For example, acidic fluids
may be used in an exothermic reaction to generate heat in a
pipeline to help remediate paraffin wax buildup in the pipeline.
Paraffin wax deposition is found practically whenever crude oil is
produced and transported. Paraffin wax deposition obstructs the
flow of oil, lowering oil production and interfering with
transportation.
[0005] Acidic fluids can include one or more of a variety of acids,
such as hydrochloric acid, acetic acid, formic acid, hydrofluoric
acid, or any combination of such acids. In addition, many fluids
used in the oil and gas industry include a water source that may
incidentally contain certain amounts of acid, which may cause the
fluid to be at least slightly acidic.
[0006] Even weakly acidic fluids can be problematic in that they
can cause corrosion of metals. Corrosion can occur anywhere in a
well production system or pipeline system, including anywhere
downhole in a well or in surface lines and equipment.
[0007] The expense of repairing or replacing corrosion damaged
equipment is extremely high. The corrosion problem is exacerbated
by the elevated temperatures encountered in deeper formations. The
increased corrosion rate of the ferrous and other metals comprising
the tubular goods and other equipment results in quantities of the
acidic solution being neutralized before it ever enters the
subterranean formation, which can compound the deeper penetration
problem discussed above. In addition, the partial neutralization of
the acid from undesired corrosion reactions can result in the
production of quantities of metal ions that are highly undesirable
in the subterranean formation.
[0008] To combat this potential corrosion problem in operations
with acidic well fluids, corrosion inhibitors have been used to
reduce corrosion to metals and metal alloys with varying degrees of
success. A difficulty encountered with the use of some conventional
corrosion inhibitors is the limited temperature range over which
they may function effectively. For example, certain conventional
antimony-based inhibitor formulations have been limited to
temperatures above 270.degree. F. and do not appear to function
effectively below this temperature.
[0009] Another drawback of some conventional corrosion inhibitors
is that certain components of these corrosion inhibitors may not be
compatible with the environmental standards in some regions of the
world. For example, quaternary ammonium compounds, mercaptan-based
compounds, and "Mannich" condensation compounds have been used as
corrosion inhibitors. However, these compounds generally are not
acceptable under stricter environmental regulations, such as those
applicable or that will become applicable in the North Sea region.
Consequently, operators in some regions may be forced to suffer
increased corrosion problems, resort to using corrosion inhibitor
formulations that may be less effective, or forgo the use of
certain acidic treatment fluids.
[0010] Yet another drawback of some convention corrosion inhibitors
is the high cost.
[0011] Well Treatment--Acidizing
[0012] A widely used stimulation technique is acidizing, in which a
treatment fluid including or forming an aqueous acid solution is
introduced into the formation to dissolve acid-soluble materials.
This can accomplish a number of purposes, which can be, for
example, to help remove residual fluid material or filtercake
damage or to increase the permeability of a treatment zone. In this
way, hydrocarbon fluids can more easily flow from the formation
into the well. In addition, an acid treatment can facilitate the
flow of injected treatment fluids from the well into the formation.
This procedure enhances production by increasing the effective well
radius.
[0013] Acidizing techniques can be carried out as matrix acidizing
procedures or as acid fracturing procedures.
[0014] In matrix acidizing, an acidizing fluid is injected from the
well into the formation at a rate and pressure below the pressure
sufficient to create a fracture in the formation. In sandstone
formations, the acid primarily removes or dissolves acid soluble
damage in the near wellbore region and is thus classically
considered a damage removal technique and not a stimulation
technique. In carbonate formations, the goal is to actually run a
stimulation treatment where the acid dissolves the carbonate rock
to create interconnected channels called wormholes in the rock.
[0015] In acid fracturing, an acidizing fluid is pumped into a
carbonate formation at a sufficient pressure to cause fracturing of
the formation and creating differential (non-uniform) etching
fracture conductivity. Acid fracturing involves the formation of
one or more fractures in the formation and the introduction of an
aqueous acidizing fluid into the fractures to etch the fracture
faces, whereby flow channels are formed when the fractures close.
The aqueous acidizing fluid also enlarges the pore spaces in the
fracture faces and in the formation.
[0016] Greater details, methodology, and exceptions can be found in
"Production Enhancement with Acid Stimulation" 2.sup.nd edition by
Leonard Kalfayan (PennWell 2008), SPE 129329, SPE 123869, SPE
121464, SPE 121803, SPE 121008, IPTC 10693, SPE 66564-PA, and the
references contained therein.
[0017] The use of the term "acidizing" herein refers to both matrix
and fracturing types of acidizing treatments, and more
specifically, refers to the general process of introducing an acid
down hole to perform a desired function, e.g., to acidize a portion
of a subterranean formation or any damage contained therein.
[0018] Pipelines, Pipeline Fluids, and Pipeline Corrosion
[0019] Hydrocarbon is typically produced from a well at relatively
high temperature compared to ambient conditions on the surface.
After a hydrocarbon flows from a subterranean formation into the
production tubulars of the wellbore, it is transported through the
tubulars of the wellbore to the wellhead. Further, the hydrocarbon
produced at the wellhead must be transported to a refinery to be
processed and separated into various components, e.g., to make
various grades of fuels and oils. A common method of transporting
hydrocarbon is through pipelines. Pipelines are at or near the
surface of the ground or can be subsea at or near the seabed. The
temperature of the pipelines is much lower than the temperature of
the subterranean formation.
[0020] As crude oil flows through the production tubulars from the
hydrocarbon-bearing formation through the wellbore toward the
surface, the surrounding temperature of the wellbore tends to
decline toward the surface, allowing heat to dissipate from the
fluid and causing the hydrocarbon fluid to begin to cool. Further,
as the crude oil is moved through cross-country pipelines, it can
lose heat energy to the ground or environment and cool to a
temperature well below 120.degree. F. (49.degree. C.). Thus, the
hot crude oil from a subterranean formation tends to be cooled as
it flows through these conduits.
[0021] As the temperature of the crude oil falls, paraffin wax in
the crude oil tends to become a solid, waxy material that falls out
of the crude oil and paraffin deposits accumulate on the inner
walls of the production tubing and pipelines. This can be
particularly problematic in subsea pipelines because the
surrounding water on the seafloor is very cold, typically about
39.degree. F. (4.degree. C.).
[0022] To help prevent paraffin deposits, some cross-country
pipelines are heated, which is very costly. However, this is not
feasible for subsea pipelines, which are in direct contact with the
surrounding cold seawater.
[0023] As the paraffin wax deposits build up on the inside wall of
a conduit, the opening for fluid flow through the pipeline becomes
smaller and smaller. Unless at least some of the buildup is removed
from time to time, eventually the deposits can increase to the
point where the conduit becomes choked. Also, sometimes some of the
paraffin deposits will release from the inside wall of a pipeline
and cause a blockage. Such a blockage can occur anywhere in the
pipeline. This paraffin deposition leads to reduced crude oil flow
and under extreme conditions leads to complete blockage of the
pipelines.
[0024] Removal of the paraffin wax deposits is attempted through
three main approaches: mechanical, thermal, and chemical. Often, a
combination of two or more of these types of approaches is
employed. One of the thermal-chemical approaches is to use an
acid-base reaction to generate heat, but this can also expose the
metal of the pipeline to acid corrosion.
SUMMARY OF THE INVENTION
[0025] In an embodiment, a method of treating a portion of a well
or a pipeline with a fluid comprising an aqueous acidic phase is
provided, the method comprising the steps of: (A) forming the fluid
comprising an aqueous acidic phase, the fluid additionally
comprising a material selected from the group consisting of: a
material of a plant in the Solanaceae family, an extract of a
material of a plant in the Solanaceae family, a withanolide, a
source of a withanolide, a withanolide derivative, a source of a
withanolide derivative, and any combination thereof; and (B)
introducing the fluid into the portion of the well or pipeline;
wherein the fluid contacts carbon steel in the well or
pipeline.
[0026] In another embodiment, a method of inhibiting corrosion of
carbon steel to be contacted with a fluid comprising an aqueous
acidic phase is provided, the method comprising the steps of: (A)
forming the fluid comprising an aqueous acidic phase, the fluid
additionally comprising a material selected from the group
consisting of: a material of a plant in the Solanaceae family, an
extract of a material of a plant in the Solanaceae family, a
withanolide, a source of a withanolide, a withanolide derivative, a
source of a withanolide derivative, and any combination thereof;
and (B) contacting the carbon steel with the fluid.
[0027] In yet another embodiment, method of contacting carbon steel
with a fluid comprising an aqueous acidic phase is provided, the
method comprising the step of: including in the fluid a material
selected from the group consisting of: a material of a plant in the
Solanaceae family, an extract of a material of a plant in the
Solanaceae family, a withanolide, a source of a withanolide, a
withanolide derivative, a source of a withanolide derivative, and
any combination thereof.
[0028] These and other aspects of the invention will be apparent to
one skilled in the art upon reading the following detailed
description. While the invention is susceptible to various
modifications and alternative forms, specific embodiments thereof
will be described in detail and shown by 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.
DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST
MODE
Definitions and Usages
[0029] Interpretation
[0030] The words or terms used herein have their plain, ordinary
meaning in the field of this disclosure, except to the extent
explicitly and clearly defined in this disclosure or unless the
specific context otherwise requires a different meaning.
[0031] If there is any conflict in the usages of a word or term in
this disclosure and one or more patent(s) or other documents that
may be incorporated by reference, the definitions that are
consistent with this specification should be adopted.
[0032] The words "comprising," "containing," "including," "having,"
and all grammatical variations thereof are intended to have an
open, non-limiting meaning. For example, a composition comprising a
component does not exclude it from having additional components, an
apparatus comprising a part does not exclude it from having
additional parts, and a method having a step does not exclude it
having additional steps. When such terms are used, the
compositions, apparatuses, and methods that "consist essentially
of" or "consist of" the specified components, parts, and steps are
specifically included and disclosed.
[0033] The indefinite articles "a" or "an" mean one or more than
one of the component, part, or step that the article
introduces.
[0034] Whenever a numerical range of degree or measurement with a
lower limit and an upper limit is disclosed, any number and any
range falling within the range is also intended to be specifically
disclosed. For example, every range of values (in the form "from a
to b," or "from about a to about b," or "from about a to b," "from
approximately a to b," and any similar expressions, where "a" and
"b" represent numerical values of degree or measurement) is to be
understood to set forth every number and range encompassed within
the broader range of values.
[0035] Well Servicing and Well Fluids
[0036] To produce oil or gas from a reservoir, a wellbore is
drilled into a subterranean formation, which may be the reservoir
or adjacent to the reservoir. The "wellbore" refers to the drilled
hole, including a cased or uncased portion of the well. As used
herein, the "borehole" refers to the inside wellbore wall, that is,
the rock face or wall that bounds the drilled hole. A wellbore can
have portions that are vertical and horizontal, and it can have
portions that are straight, curved, or branched. The wellhead is
the surface termination of a wellbore, which surface may be on land
or on a seabed. As used herein, "uphole" and "downhole" and similar
terms are relative to the wellhead, regardless of whether a
wellbore portion is vertical or horizontal.
[0037] Generally, well services include a wide variety of
operations that may be performed in oil, gas, geothermal, or water
wells, such as drilling, cementing, completion, and intervention.
Well services are designed to facilitate or enhance the production
of desirable fluids such as oil or gas from or through a
subterranean formation. A well service usually involves introducing
a well fluid into a well.
[0038] Drilling, completion, and intervention operations can
include various types of treatments that are commonly performed on
a well or subterranean formation. For example, a treatment for
fluid-loss control can be used during any of drilling, completion,
and intervention operations. During completion or intervention,
stimulation is a type of treatment performed to enhance or restore
the productivity of oil and gas from a well. Stimulation treatments
fall into two main groups: hydraulic fracturing and matrix
treatments. Fracturing treatments are performed above the fracture
pressure of the subterranean formation to create or extend a highly
permeable flow path between the formation and the wellbore. Matrix
treatments are performed below the fracture pressure of the
formation. Other types of completion or intervention treatments can
include, for example, gravel packing, consolidation, and
controlling excessive water production.
[0039] Well and Pipeline Terms
[0040] A "well" includes a wellhead and at least one wellbore from
the wellhead penetrating the earth. The "wellhead" is the surface
termination of a wellbore, which surface may be on land or on a
seabed. A "well site" is the geographical location of a wellhead of
a well. It may include related facilities, such as a tank battery,
separators, compressor stations, heating or other equipment, and
fluid pits. If offshore, a well site can include a platform.
[0041] The "wellbore" refers to the drilled hole, including any
cased or uncased portions of the well or any other tubulars in the
well. The "borehole" usually refers to the inside wellbore wall,
that is, the rock surface or wall that bounds the drilled hole. A
wellbore can have portions that are vertical, horizontal, or
anything in between, and it can have portions that are straight,
curved, or branched. As used herein, "uphole," "downhole," and
similar terms are relative to the direction of the wellhead,
regardless of whether a wellbore portion is vertical or
horizontal.
[0042] A wellbore can be used as a production or injection
wellbore. A production wellbore is used to produce hydrocarbons
from the reservoir. An injection wellbore is used to inject a
fluid, e.g., liquid water or steam, to drive oil or gas to a
production wellbore.
[0043] As used herein, introducing "into a well" means introducing
at least into and through the wellhead. According to various
techniques known in the art, tubulars, equipment, tools, or well
fluids can be directed from the wellhead into any desired portion
of the wellbore.
[0044] As used herein, the word "tubular" means any kind of body in
the general form of a tube. Examples of tubulars include, but are
not limited to, a drill pipe, a casing, a tubing string, a line
pipe, and a transportation pipe. Tubulars can also be used to
transport fluids such as oil, gas, water, liquefied methane,
coolants, and heated fluids into or out of a subterranean
formation. For example, a tubular can be placed underground to
transport produced hydrocarbons or water from a subterranean
formation to another location.
[0045] "Pipeline transport" refers to a conduit made from pipes
connected end-to-end for long-distance fluid transport. Oil or gas
pipelines are made from steel or plastic tubulars with inner
diameter typically from about 4 to about 60 inches (about 10 to
about 150 cm). Most pipelines are typically buried at a depth of
about 3 to about 6 feet (about 1 meter to about 2 meter). To
protect pipes from impact, abrasion, and corrosion, a variety of
methods are used. These can include wood lagging (wood slats),
concrete coating, rockshield, high-density polyethylene, imported
sand padding, and padding machines. The oil is kept in motion by
pump stations along the pipeline, and usually flows at speed of
about 3.3 to 20 ft/s (1 to 6 meters per second).
[0046] Gathering pipelines are a group of smaller interconnected
pipelines forming complex networks with the purpose of bringing
crude oil or natural gas from several nearby wells to a treatment
plant or processing facility. In this group, pipelines are usually
relatively short (usually about 100 to about 1000 yards or meters)
and with small diameters (usually about 4 to about 12 inches). Also
sub-sea pipelines for collecting product from deep water production
platforms are considered gathering systems.
[0047] Transportation pipelines are mainly long pipes (many miles
or kilometers) with large diameters (larger than about 12 inches or
about 30 cm), moving products (oil, gas, refined products) between
cities, countries, and even continents. These transportation
networks include several compressor stations in gas lines or pump
stations for crude oil or multi-product pipelines.
[0048] Distribution pipelines are composed of several
interconnected pipelines with small diameters (usually about 1 to
about 4 inches), used to take the products to the final consumer.
An example of distribution pipelines is feeder lines to distribute
natural gas to homes and businesses downstream. Pipelines at
terminals for distributing products to tanks and storage facilities
are included in this group.
[0049] As used herein, the term "annulus" means the space between
two generally cylindrical objects, one inside the other. The
objects can be concentric or eccentric. Without limitation, one of
the objects can be a tubular and the other object can be an
enclosed conduit. The enclosed conduit can be a wellbore or
borehole or it can be another tubular. The following are some
non-limiting examples illustrating some situations in which an
annulus can exist. Referring to an oil, gas, or water well, in an
open hole well, the space between the outside of a tubing string
and the borehole of the wellbore is an annulus. In a cased hole,
the space between the outside of the casing and the borehole is an
annulus. In addition, in a cased hole there may be an annulus
between the outside cylindrical portion of a tubular such as a
production tubing string and the inside cylindrical portion of the
casing. An annulus can be a space through which a fluid can flow or
it can be filled with a material or object that blocks fluid flow,
such as a packing element. Unless otherwise clear from the context,
as used herein an annulus is a space through which a fluid can
flow.
[0050] As used herein, a "well fluid" broadly refers to any fluid
adapted to be introduced into a well for any purpose. A well fluid
can be, for example, a drilling fluid, a cementing composition, a
treatment fluid, or a spacer fluid. If a well fluid is to be used
in a relatively small volume, for example less than about 200
barrels (about 8,400 US gallons or about 32 m.sup.3), it is
sometimes referred to as a wash, dump, slug, or pill.
[0051] As used herein, the word "treatment" refers to any treatment
for changing a condition of a portion of a pipeline, a wellbore, or
a subterranean formation adjacent a wellbore; however, the word
"treatment" does not necessarily imply any particular treatment
purpose. A treatment usually involves introducing a well fluid for
the treatment, in which case it may be referred to as a treatment
fluid, into a well. As used herein, a "treatment fluid" is a fluid
used in a treatment. The word "treatment" in the term "treatment
fluid" does not necessarily imply any particular treatment or
action by the fluid.
[0052] A "portion" of a well or pipeline refers to any downhole
portion of the well or any portion of the length of a pipeline.
[0053] A "zone" refers to an interval of rock along a wellbore that
is differentiated from uphole and downhole zones based on
hydrocarbon content or other features, such as permeability,
composition, perforations or other fluid communication with the
wellbore, faults, or fractures. A zone of a wellbore that
penetrates a hydrocarbon-bearing zone that is capable of producing
hydrocarbon is referred to as a "production zone." A "treatment
zone" refers to an interval of rock along a wellbore into which a
well fluid is directed to flow from the wellbore. As used herein,
"into a treatment zone" means into and through the wellhead and,
additionally, through the wellbore and into the treatment zone.
[0054] Generally, the greater the depth of the formation, the
higher the static temperature and pressure of the formation.
Initially, the static pressure equals the initial pressure in the
formation before production. After production begins, the static
pressure approaches the average reservoir pressure.
[0055] A "design" refers to the estimate or measure of one or more
parameters planned or expected for a particular fluid or stage of a
treatment or well service. For example, a fluid can be designed to
have components that provide a minimum viscosity for at least a
specified time under expected downhole conditions. A well service
may include design parameters such as fluid volume to be pumped,
required pumping time for a treatment, or the shear conditions of
the pumping.
[0056] The term "design temperature" refers to an estimate or
measurement of the actual temperature at the downhole environment
at the time of a treatment. For example, the design temperature for
a well treatment takes into account not only the bottom hole static
temperature ("BHST"), but also the effect of the temperature of the
well fluid on the BHST during treatment. The design temperature for
a well fluid is sometimes referred to as the bottom hole
circulation temperature ("BHCT"). Because well treatment fluids may
be considerably cooler than BHST, the difference between the two
temperatures can be quite large. Ultimately, if left undisturbed, a
subterranean formation will return to the BHST.
[0057] Substances, Chemicals, and Derivatives
[0058] A substance can be a pure chemical or a mixture of two or
more different chemicals.
[0059] A pure chemical is a sample of matter that cannot be
separated into simpler components without chemical change. A
chemical element is composed of atoms with identical atomic number.
A chemical compound is formed from different elements chemically
combined in definite proportions by mass.
[0060] An atom or molecule is the smallest particle of a chemical
that retains the chemical properties of the element or compound. A
molecule is two or more chemically bound atoms with characteristic
composition and structure. Making or breaking bonds in a molecule
changes it to a different chemical.
[0061] A metal is an element, compound, or alloy that is a good
conductor of both electricity and heat. Metals are usually
malleable, ductile, and shiny, that is they reflect most of
incident light. In a metal, atoms readily lose electrons to form
positive ions (cations). Those ions are surrounded by de-localized
electrons, which are responsible for the conductivity. The solid
thus produced is held together by electrostatic interactions
between the ions and the electron cloud, which are called metallic
bonds.
[0062] An ionic compound is made of distinguishable ions, including
at least one cation (a positively charged ion) and at least one
anion (a negatively charged ion), held together by electrostatic
forces. An ion is an atom or molecule that has acquired a charge by
either gaining or losing electrons. An ion can be a single atom or
molecular. An ion can be separated from an ionic compound, for
example, by dissolving the ions of the compound in a polar
solvent.
[0063] As used herein, "modified" or "derivative" means a compound
or substance formed by a chemical process from a parent compound or
substance, wherein the chemical backbone skeleton of the parent
compound or substance is retained in the derivative. The chemical
process preferably includes at most a few chemical reaction steps,
and more preferably only one or two chemical reaction steps. As
used herein, a "chemical reaction step" is a chemical reaction
between two chemical reactant species to produce at least one
chemically different species from the reactants (regardless of the
number of transient chemical species that may be formed during the
reaction). An example of a chemical step is a substitution
reaction. Substitution on the reactive sites of a polymeric
material may be partial or complete.
[0064] Physical States and Phases
[0065] As used herein, "phase" is used to refer to a substance
having a chemical composition and physical state that is
distinguishable from an adjacent phase of a substance having a
different chemical composition or a different physical state.
[0066] The word "material" is anything made of matter, constituted
of one or more phases. Rock, water, air, metal, cement slurry,
sand, and wood are all examples of materials. The word "material"
can refer to a single phase of a substance on a bulk scale (larger
than a particle) or a bulk scale of a mixture of phases, depending
on the context.
[0067] As used herein, if not other otherwise specifically stated,
the physical state or phase of a substance (or mixture of
substances) and other physical properties are determined at a
temperature of 77.degree. F. (25.degree. C.) and a pressure of 1
atmosphere (Standard Laboratory Conditions) without applied
shear.
[0068] Particles
[0069] As used herein, a "particle" refers to a body having a
finite mass and sufficient cohesion such that it can be considered
as an entity but having relatively small dimensions. A particle can
be of any size ranging from molecular scale to macroscopic,
depending on context.
[0070] A particle can be in any physical state. For example, a
particle of a substance in a solid state can be as small as a few
molecules on the scale of nanometers up to a large particle on the
scale of a few millimeters, such as large grains of sand.
Similarly, a particle of a substance in a liquid state can be as
small as a few molecules on the scale of nanometers up to a large
drop on the scale of a few millimeters. A particle of a substance
in a gas state is a single atom or molecule that is separated from
other atoms or molecules such that intermolecular attractions have
relatively little effect on their respective motions.
[0071] As used herein, particulate or particulate material refers
to matter in the physical form of distinct particles in a solid or
liquid state (which means such an association of a few atoms or
molecules). As used herein, a particulate is a grouping of
particles having similar chemical composition and particle size
ranges anywhere in the range of about 0.5 micrometer (500 nm),
e.g., microscopic clay particles, to about 3 millimeters, e.g.,
large grains of sand.
[0072] A particulate can be of solid or liquid particles. As used
herein, however, unless the context otherwise requires, particulate
refers to a solid particulate. Of course, a solid particulate is a
particulate of particles that are in the solid physical state, that
is, the constituent atoms, ions, or molecules are sufficiently
restricted in their relative movement to result in a fixed shape
for each of the particles.
[0073] It should be understood that the terms "particle" and
"particulate," includes all known shapes of particles including
substantially rounded, spherical, oblong, ellipsoid, rod-like,
fiber, polyhedral (such as cubic materials), etc., and mixtures
thereof. For example, the term "particulate" as used herein is
intended to include solid particles having the physical shape of
platelets, shavings, flakes, ribbons, rods, strips, spheroids,
toroids, pellets, tablets or any other physical shape.
[0074] Dispersions
[0075] A dispersion is a system in which particles of a substance
of one chemical composition and physical state are dispersed in
another substance of a different chemical composition or physical
state. In addition, phases can be nested. If a substance has more
than one phase, the most external phase is referred to as the
continuous phase of the substance as a whole, regardless of the
number of different internal phases or nested phases.
[0076] A dispersion can be classified different ways, including,
for example, based on the size of the dispersed particles, the
uniformity or lack of uniformity of the dispersion, and, if a
fluid, whether or not precipitation occurs.
[0077] A dispersion is considered to be heterogeneous if the
dispersed particles are not dissolved and are greater than about 1
nanometer in size. (For reference, the diameter of a molecule of
toluene is about 1 nm and a molecule of water is about 0.3 nm).
[0078] Heterogeneous dispersions can have gas, liquid, or solid as
an external phase. For example, in a case where the dispersed-phase
particles are liquid in an external phase that is another liquid,
this kind of heterogeneous dispersion is more particularly referred
to as an emulsion. A solid dispersed phase in a continuous liquid
phase is referred to as a sol, suspension, or slurry, partly
depending on the size of the dispersed solid particulate.
[0079] A dispersion is considered to be homogeneous if the
dispersed particles are dissolved in solution or the particles are
less than about 1 nanometer in size. Even if not dissolved, a
dispersion is considered to be homogeneous if the dispersed
particles are less than about 1 nanometer in size.
[0080] A solution is a special type of homogeneous mixture. A
solution is considered homogeneous: (a) because the ratio of solute
to solvent is the same throughout the solution; and (b) because
solute will never settle out of solution, even under powerful
centrifugation, which is due to intermolecular attraction between
the solvent and the solute. An aqueous solution, for example,
saltwater, is a homogenous solution in which water is the solvent
and salt is the solute.
[0081] One may also refer to the solvated state, in which a solute
ion or molecule is complexed by solvent molecules. A chemical that
is dissolved in solution is in a solvated state. The solvated state
is distinct from dissolution and solubility. Dissolution is a
kinetic process, and is quantified by its rate. Solubility
quantifies the concentration of the solute at which there is
dynamic equilibrium between the rate of dissolution and the rate of
precipitation of the solute. Dissolution and solubility can be
dependent on temperature and pressure, and may be dependent on
other factors, such as salinity or pH of an aqueous phase.
[0082] Solubility Terms
[0083] A substance is considered to be "soluble" in a liquid if at
least 10 grams of the substance can be dissolved in one liter of
the liquid when tested at 77.degree. F. and 1 atmosphere pressure
for 2 hours and considered to be "insoluble" if less than 1 gram
per liter soluble and "sparingly soluble" for intermediate
solubility values.
[0084] As will be appreciated by a person of skill in the art, the
hydratability, dispersibility, or solubility of a substance in
water can be dependent on the salinity, pH, or other substances in
the water. Accordingly, the salinity, pH, and additive selection of
the water can be modified to facilitate the hydratability,
dispersibility, or solubility of a substance in aqueous solution.
To the extent not specified, the hydratability, dispersibility, or
solubility of a substance in water is determined in deionized
water, at neutral pH, and without any other additives.
[0085] The "source" of a chemical species in a solution or in a
fluid composition can be a material or substance that makes the
chemical species chemically available immediately or it can be a
material or substance that gradually or later releases the chemical
species to become chemically available.
[0086] Fluids
[0087] A fluid can be a single phase or a dispersion. In general, a
fluid is an amorphous substance that is or has a continuous phase
of particles that are smaller than about 1 micrometer that tends to
flow and to conform to the outline of its container.
[0088] Examples of fluids are gases and liquids. A gas (in the
sense of a physical state) refers to an amorphous substance that
has a high tendency to disperse (at the molecular level) and a
relatively high compressibility. A liquid refers to an amorphous
substance that has little tendency to disperse (at the molecular
level) and relatively high incompressibility. The tendency to
disperse is related to Intermolecular Forces (also known as van der
Waal's Forces). (A continuous mass of a particulate, e.g., a powder
or sand, can tend to flow as a fluid depending on many factors such
as particle size distribution, particle shape distribution, the
proportion and nature of any wetting liquid or other surface
coating on the particles, and many other variables. Nevertheless,
as used herein, a fluid does not refer to a continuous mass of
particulate as the sizes of the solid particles of a mass of a
particulate are too large to be appreciably affected by the range
of Intermolecular Forces.)
[0089] As used herein, a fluid is a substance that behaves as a
fluid under Standard Laboratory Conditions, that is, at 77.degree.
F. (25.degree. C.) temperature and 1 atmosphere pressure, and at
the higher temperatures and pressures usually occurring in
subterranean formations without applied shear.
[0090] Every fluid inherently has at least a continuous phase. A
fluid can have more than one phase. The continuous phase of a well
fluid is a liquid under Standard Laboratory Conditions. For
example, a well fluid can be in the form of be a suspension (solid
particles dispersed in a liquid phase), an emulsion (liquid
particles dispersed in another liquid phase), or a foam (a gas
phase dispersed in a liquid phase).
[0091] As used herein, a water-based fluid means that water or an
aqueous solution is the dominant material of the continuous phase,
that is, greater than 50% by weight, of the continuous phase of the
fluid.
[0092] In contrast, "oil-based" means that oil is the dominant
material by weight of the continuous phase of the fluid. In this
context, the oil of an oil-based fluid can be any oil.
[0093] In the context of a well fluid, oil is understood to refer
to an oil liquid, whereas gas is understood to refer to a physical
state of a substance, in contrast to a liquid. In general, an oil
is any substance that is liquid under Standard Laboratory
Conditions, is hydrophobic, and soluble in organic solvents. Oils
have a high carbon and hydrogen content and are relatively
non-polar substances, for example, having a polarity of 3 or less
on the Snyder polarity index. This general definition includes
classes such as petrochemical oils, vegetable oils, and many
organic solvents. All oils can be traced back to organic
sources.
[0094] Apparent Viscosity of a Fluid
[0095] Viscosity is a measure of the resistance of a fluid to flow.
In everyday terms, viscosity is "thickness" or "internal friction."
Thus, pure water is "thin," having a relatively low viscosity
whereas honey is "thick," having a relatively higher viscosity. Put
simply, the less viscous the fluid is, the greater its ease of
movement (fluidity). More precisely, viscosity is defined as the
ratio of shear stress to shear rate.
[0096] A fluid moving along solid boundary will incur a shear
stress on that boundary. The no-slip condition dictates that the
speed of the fluid at the boundary (relative to the boundary) is
zero, but at some distance from the boundary the flow speed must
equal that of the fluid. The region between these two points is
aptly named the boundary layer. For all Newtonian fluids in laminar
flow, the shear stress is proportional to the strain rate in the
fluid where the viscosity is the constant of proportionality.
However for non-Newtonian fluids, this is no longer the case as for
these fluids the viscosity is not constant. The shear stress is
imparted onto the boundary as a result of this loss of
velocity.
[0097] A Newtonian fluid (named after Isaac Newton) is a fluid for
which stress versus strain rate curve is linear and passes through
the origin. The constant of proportionality is known as the
viscosity. Examples of Newtonian fluids include water and most
gases. Newton's law of viscosity is an approximation that holds for
some substances but not others.
[0098] Non-Newtonian fluids exhibit a more complicated relationship
between shear stress and velocity gradient (i.e., shear rate) than
simple linearity. Thus, there exist a number of forms of
non-Newtonian fluids. Shear thickening fluids have an apparent
viscosity that increases with increasing the rate of shear. Shear
thinning fluids have a viscosity that decreases with increasing
rate of shear. Thixotropic fluids become less viscous over time at
a constant shear rate. Rheopectic fluids become more viscous over
time at a constant shear rate. A Bingham plastic is a material that
behaves as a solid at low stresses but flows as a viscous fluid at
high stresses.
[0099] Most well fluids are non-Newtonian fluids. Accordingly, the
apparent viscosity of a fluid applies only under a particular set
of conditions including shear stress versus shear rate, which must
be specified or understood from the context. As used herein, a
reference to viscosity is actually a reference to an apparent
viscosity. Apparent viscosity is commonly expressed in units of
centipoise ("cP").
[0100] Like other physical properties, the viscosity of a Newtonian
fluid or the apparent viscosity of a non-Newtonian fluid may be
highly dependent on the physical conditions, primarily temperature
and pressure.
[0101] Gels and Deformation
[0102] The physical state of a gel is formed by a network of
interconnected molecules, such as a crosslinked polymer or a
network of micelles. The network gives a gel phase its structure
and an apparent yield point. At the molecular level, a gel is a
dispersion in which both the network of molecules is continuous and
the liquid is continuous. A gel is sometimes considered as a single
phase.
[0103] Technically, a "gel" is a semi-solid, jelly-like physical
state or phase that can have properties ranging from soft and weak
to hard and tough. Shearing stresses below a certain finite value
fail to produce permanent deformation. The minimum shear stress
which will produce permanent deformation is referred to as the
shear strength or gel strength of the gel.
[0104] In the oil and gas industry, however, the term "gel" may be
used to refer to any fluid having a viscosity-increasing agent,
regardless of whether it is a viscous fluid or meets the technical
definition for the physical state of a gel. A "base gel" is a term
used in the field for a fluid that includes a viscosity-increasing
agent, such as guar, but that excludes crosslinking agents.
Typically, a base gel is mixed with another fluid containing a
crosslinker, wherein the mixture is adapted to form a crosslinked
gel. Similarly, a "crosslinked gel" may refer to a substance having
a viscosity-increasing agent that is crosslinked, regardless of
whether it is a viscous fluid or meets the technical definition for
the physical state of a gel.
[0105] As used herein, a substance referred to as a "gel" is
subsumed by the concept of "fluid" if it is a pumpable fluid.
[0106] Viscosity and Gel Measurements
[0107] There are numerous ways of measuring and modeling viscous
properties, and new developments continue to be made. The methods
depend on the type of fluid for which viscosity is being measured.
A typical method for quality assurance or quality control (QA/QC)
purposes uses a couette device that measures viscosity as a
function of time, temperature, and shear rate, such as a FANN.TM.
Model 35 or Model 50 viscometer or a CHANDLER.TM. Model 5550 HPHT
viscometer. The viscosity-measuring instrument can be calibrated
using standard viscosity silicone oils or other standard viscosity
fluids.
[0108] Due to the geometry of most common viscosity-measuring
devices, however, solid particulate, especially if larger than silt
(larger than 74 micron), would interfere with the measurement on
some types of measuring devices. Therefore, the viscosity of a
fluid containing such solid particulate is usually inferred and
estimated by measuring the viscosity of a test fluid that is
similar to the fracturing fluid without any proppant or gravel that
would otherwise be included. However, as suspended particles (which
can be solid, gel, liquid, or gaseous bubbles) usually affect the
viscosity of a fluid, the actual viscosity of a suspension is
usually somewhat different from that of the continuous phase.
[0109] Unless otherwise specified, the apparent viscosity of a
fluid (excluding any suspended solid particulate larger than silt)
is measured with a FANN.TM. Model 35 type viscometer using an R1
rotor, B1 bob, and F1 torsion spring at a shear rate of 511 l/s,
and at a temperature of 77.degree. F. (25.degree. C.) and a
pressure of 1 atmosphere. For reference, the viscosity of pure
water is about 1 cP.
[0110] A substance is considered to be a fluid if it has an
apparent viscosity less than 5,000 cP (independent of any gel
characteristic).
[0111] Biodegradability
[0112] Biodegradable means the process by which complex molecules
are broken down by micro-organisms to produce simpler compounds.
Biodegradation can be either aerobic (with oxygen) or anaerobic
(without oxygen). The potential for biodegradation is commonly
measured on well fluids or their components to ensure that they do
not persist in the environment. A variety of tests exist to assess
biodegradation.
[0113] As used herein, a substance is considered "biodegradable" if
the substance passes a ready biodegradability test or an inherent
biodegradability test. It is preferred that a substance is first
tested for ready biodegradability, and only if the substance does
not pass at least one of the ready biodegradability tests then the
substance is tested for inherent biodegradability.
[0114] In accordance with Organisation for Economic Co-operation
and Development (OECD) guidelines, the following six tests permit
the screening of chemicals for ready biodegradability. As used
herein, a substance showing more than 60% biodegradability in 28
days according to any one of the six ready biodegradability tests
is considered a pass level for classifying it as "readily
biodegradable," and it may be assumed that the substance will
undergo rapid and ultimate degradation in the environment. The six
ready biodegradability tests are: (1) 301A: DOC Die-Away; (2) 301B:
CO.sub.2 Evolution (Modified Sturm Test); (3) 301C: MITI (I)
(Ministry of International Trade and Industry, Japan); (4) 301D:
Closed Bottle; (5) 301E: Modified OECD Screening; and (6) 301F:
Manometric Respirometry. The six ready biodegradability tests are
described below.
[0115] For the 301A test, a measured volume of inoculated mineral
medium, containing 10 mg to 40 mg dissolved organic carbon per
liter (DOC/1) from the substance as the nominal sole source of
organic carbon, is aerated in the dark or diffuse light at
22.+-.2.degree. C. Degradation is followed by DOC analysis at
frequent intervals over a 28-day period. The degree of
biodegradation is calculated by expressing the concentration of DOC
removed (corrected for that in the blank inoculum control) as a
percentage of the concentration initially present. Primary
biodegradation may also be calculated from supplemental chemical
analysis for parent compound made at the beginning and end of
incubation.
[0116] For the 301B test, a measured volume of inoculated mineral
medium, containing 10 mg to 20 mg DOC or total organic carbon per
liter from the substance as the nominal sole source of organic
carbon is aerated by the passage of carbon dioxide-free air at a
controlled rate in the dark or in diffuse light. Degradation is
followed over 28 days by determining the carbon dioxide produced.
The CO.sub.2 is trapped in barium or sodium hydroxide and is
measured by titration of the residual hydroxide or as inorganic
carbon. The amount of carbon dioxide produced from the test
substance (corrected for that derived from the blank inoculum) is
expressed as a percentage of ThCO.sub.2. The degree of
biodegradation may also be calculated from supplemental DOC
analysis made at the beginning and end of incubation.
[0117] For the 301C test, the oxygen uptake by a stirred solution,
or suspension, of the substance in a mineral medium, inoculated
with specially grown, unadapted micro-organisms, is measured
automatically over a period of 28 days in a darkened, enclosed
respirometer at 25+/-1.degree. C. Evolved carbon dioxide is
absorbed by soda lime. Biodegradation is expressed as the
percentage oxygen uptake (corrected for blank uptake) of the
theoretical uptake (ThOD). The percentage primary biodegradation is
also calculated from supplemental specific chemical analysis made
at the beginning and end of incubation, and optionally ultimate
biodegradation by DOC analysis.
[0118] For the 301D test, a solution of the substance in mineral
medium, usually at 2-5 milligrams per liter (mg/l), is inoculated
with a relatively small number of micro-organisms from a mixed
population and kept in completely full, closed bottles in the dark
at constant temperature. Degradation is followed by analysis of
dissolved oxygen over a 28 day period. The amount of oxygen taken
up by the microbial population during biodegradation of the test
substance, corrected for uptake by the blank inoculum run in
parallel, is expressed as a percentage of ThOD or, less
satisfactorily COD.
[0119] For the 301E test, a measured volume of mineral medium
containing 10 to 40 mg DOC/1 of the substance as the nominal sole
source of organic carbon is inoculated with 0.5 ml effluent per
liter of medium. The mixture is aerated in the dark or diffused
light at 22+2.degree. C. Degradation is followed by DOC analysis at
frequent intervals over a 28 day period. The degree of
biodegradation is calculated by expressing the concentration of DOC
removed (corrected for that in the blank inoculums control) as a
percentage of the concentration initially present. Primary
biodegradation may also be calculated from supplemental chemical
analysis for the parent compound made at the beginning and end of
incubation.
[0120] For the 301F test, a measured volume of inoculated mineral
medium, containing 100 mg of the substance per liter giving at
least 50 to 100 mg ThOD/1 as the nominal sole source of organic
carbon, is stirred in a closed flask at a constant temperature
(+1.degree. C. or closer) for up to 28 days. The consumption of
oxygen is determined either by measuring the quantity of oxygen
(produced electrolytically) required to maintain constant gas
volume in the respirometer flask or from the change in volume or
pressure (or a combination of the two) in the apparatus. Evolved
carbon dioxide is absorbed in a solution of potassium hydroxide or
another suitable absorbent. The amount of oxygen taken up by the
microbial population during biodegradation of the test substance
(corrected for uptake by blank inoculum, run in parallel) is
expressed as a percentage of ThOD or, less satisfactorily, COD.
Optionally, primary biodegradation may also be calculated from
supplemental specific chemical analysis made at the beginning and
end of incubation, and ultimate biodegradation by DOC analysis.
[0121] In accordance with OECD guidelines, the following three
tests permit the testing of chemicals for inherent
biodegradability. As used herein, a substance with a biodegradation
or biodegradation rate of >20% is regarded as "inherently
primary biodegradable." A substance with a biodegradation or
biodegradation rate of >70% is regarded as "inherently ultimate
biodegradable." As used herein, a substance passes the inherent
biodegradability test if the substance is either regarded as
inherently primary biodegradable or inherently ultimate
biodegradable when tested according to any one of three inherent
biodegradability tests. The three tests are: (1) 302A: 1981
Modified SCAS Test; (2) 302B: 1992 Zahn-Wellens Test; and (3) 302C:
1981 Modified MITI Test. Inherent biodegradability refers to tests
which allow prolonged exposure of the test compound to
microorganisms, a more favorable test compound to biomass ratio,
and chemical or other conditions which favor biodegradation. The
three inherent biodegradability tests are described below.
[0122] For the 302A test, activated sludge from a sewage treatment
plant is placed in an aeration (SCAS) unit. The substance and
settled domestic sewage are added, and the mixture is aerated for
23 hours. The aeration is then stopped, the sludge allowed to
settle and the supernatant liquor is removed. The sludge remaining
in the aeration chamber is then mixed with a further aliquot of the
substance and sewage and the cycle is repeated. Biodegradation is
established by determination of the dissolved organic carbon
content of the supernatant liquor. This value is compared with that
found for the liquor obtained from a control tube dosed with
settled sewage only.
[0123] For the 302B test, a mixture containing the substance,
mineral nutrients, and a relatively large amount of activated
sludge in aqueous medium is agitated and aerated at 20.degree. C.
to 25.degree. C. in the dark or in diffuse light for up to 28 days.
A blank control, containing activated sludge and mineral nutrients
but no substance, is run in parallel. The biodegradation process is
monitored by determination of DOC (or COD) in filtered samples
taken at daily or other time intervals. The ratio of eliminated DOC
(or COD), corrected for the blank, after each time interval, to the
initial DOC value is expressed as the percentage biodegradation at
the sampling time. The percentage biodegradation is plotted against
time to give the biodegradation curve.
[0124] For the 302C test, an automated closed-system oxygen
consumption measuring apparatus (BOD-meter) is used. The substance
to be tested is inoculated in the testing vessels with
micro-organisms. During the test period, the biochemical oxygen
demand is measured continuously by means of a BOD-meter.
Biodegradability is calculated on the basis of BOD and supplemental
chemical analysis, such as measurement of the dissolved organic
carbon concentration, concentration of residual chemicals, etc.
[0125] General Measurement Terms
[0126] Unless otherwise specified or unless the context otherwise
clearly requires, any ratio or percentage means by weight.
[0127] Unless otherwise specified or unless the context otherwise
clearly requires, the phrase "by weight of the water" means the
weight of the water of the continuous phase of the fluid without
the weight of any viscosity-increasing agent, dissolved salt,
suspended particulate, or other materials or additives that may be
present in the water.
[0128] As used herein, "% wt/vol" means the mass-volume percentage,
sometimes referred to as weight-volume percentage or percent weight
per volume and often abbreviated as % m/v or % w/v, which describes
the mass of the solute in g per 100 mL of the liquid. Mass-volume
percentage is often used for solutions made from a solid solute
dissolved in a liquid. For example, a 40% w/v sugar solution
contains 40 g of sugar per 100 mL of liquid.
[0129] If there is any difference between U.S. or Imperial units,
U.S. units are intended. For example, "gal/Mgal" means U.S. gallons
per thousand U.S. gallons.
[0130] Unless otherwise specified, mesh sizes are in U.S. Standard
Mesh.
[0131] The micrometer (.mu.m) may sometimes be referred to herein
as a micron.
[0132] General Description
[0133] There have been various corrosion inhibitors and
intensifiers developed to minimize corrosion of metal tubulars
which occurs due to acid treatments commonly used in oilfield
operations. Acid treatments involve mineral acids (such as
hydrochloric acids commonly in a concentration of about 7.5% to
about 15%) or organic acids (such as acetic acids or formic acids).
Corrosion tendencies and rates using mineral acids are higher than
for organic acids. Corrosion rates using organic acids are
relatively lower, but not negligible. In addition, corrosion rates
tend to increase substantially at elevated temperatures.
[0134] Use of chemical corrosion inhibitors is quite common in
production and processing operations. Depending on the acids used,
different corrosion inhibitors have been developed and added to
well fluids or pipeline fluids to minimize the corrosion and hence
protect and enhance the life of metal tubulars. Existing corrosion
inhibitors are classified as either strong mineral acid (e.g., HCl)
corrosion inhibitors or organic acid inhibitors. This is due to the
difference in mechanism of inhibition. Particularly challenging is
the development of new chemistries, which maintain good protection
of materials under a variety of conditions while being
environmentally acceptable.
[0135] It has been discovered that Withania somnifera extract has
excellent corrosion inhibition properties in mineral acid fluids
(such as hydrochloric acid) or in organic acids (such as formic
acid and acetic acid) fluids on carbon steel, including at high
concentrations of such acids or at high temperatures up to at least
275.degree. F.
[0136] In an embodiment, a method of treating a portion of a well
or a pipeline with a fluid comprising an aqueous acidic phase is
provided, the method comprising the steps of: (A) forming the fluid
comprising an aqueous acidic phase, the fluid additionally
comprising a material selected from the group consisting of: a
material of a plant in the Solanaceae family, an extract of a
material of a plant in the Solanaceae family, a withanolide, a
source of a withanolide, a withanolide derivative, a source of a
withanolide derivative, and any combination thereof; and (B)
introducing the fluid into the portion of the well or pipeline;
wherein the fluid contacts carbon steel in the well or
pipeline.
[0137] In another embodiment, a method of inhibiting corrosion of
carbon steel to be contacted with a fluid comprising an aqueous
acidic phase is provided, the method comprising the steps of: (A)
forming the fluid comprising an aqueous acidic phase, the fluid
additionally comprising a material selected from the group
consisting of: a material of a plant in the Solanaceae family, an
extract of a material of a plant in the Solanaceae family, a
withanolide, a source of a withanolide, a withanolide derivative, a
source of a withanolide derivative, and any combination thereof;
and (B) contacting the carbon steel with the fluid.
[0138] In yet another embodiment, method of contacting carbon steel
with a fluid comprising an aqueous acidic phase is provided, the
method comprising the step of: including in the fluid a material
selected from the group consisting of: a material of a plant in the
Solanaceae family, an extract of a material of a plant in the
Solanaceae family, a withanolide, a source of a withanolide, a
withanolide derivative, a source of a withanolide derivative, and
any combination thereof.
[0139] Such methods have wide application in various kinds of
operations involved in the production or pipeline transportation of
oil and gas, such as acid stimulation in a well or remedial
treatment in a pipeline.
[0140] In embodiments of the invention, Withania somnifera is used
to provide corrosion inhibition in mineral acids or in organic
acids, which is a distinct advantage.
[0141] For example, as discussed in more detail below, tests
conducted with Withania somnifera extract in 15% HCl acid recipes
resulted in a corrosion loss of only 0.0364 lb/ft.sup.2 at
250.degree. F., which is significantly lower than the acceptable
maximum value of 0.05 lb/ft.sup.2.
[0142] Tests conducted with Withania somnifera extract in the
organic acid recipes prepared in brine resulted in a corrosion loss
of only 0.004 lb/ft.sup.2 at 200.degree. F., which is marginal and
significantly lower than the acceptable maximum value of 0.05
lb/ft.sup.2. At a high temperature of 275.degree. F., corrosion
loss is 0.027 lb/ft.sup.2, which is below the acceptable maximum
value.
[0143] Extract of Withania somnifera is commercially and
economically available, for example, in India.
[0144] Withania somnifera extract is routinely used for medicinal
purposes.
[0145] The extract is compatible with aqueous acid formulations
commonly used in well fluids or pipeline fluids.
[0146] Further, both the solid powder and the liquid extract being
natural compounds are extremely safe to handle during
transportation and use at the field locations. There are no
reported values of flammability, reactivity and hence is not a
health or environmental hazard.
[0147] Hence, the extract of Withania somnifera, either in solid
powder or aqueous liquid form, can be used for application as a
corrosion inhibitor in acid treatments worldwide. The use of
extract of Withania somnifera as a corrosion inhibitor can satisfy
the long pending requirements of North Sea oil operations. The
present invention provides a very simple effective natural and
environmentally green product to inhibit corrosion in different
types of acids.
[0148] In view of the points highlighted above, Withania somnifera
extract can serve as an excellent choice for a corrosion inhibitor
in mineral acids as well as organic acids and also comply with all
health, safety and environment standards.
Withania Somnifera, Family Solanaceae, Extracts, and
Withanolides
[0149] Withania somnifera, also known as Ashwagandha in ayurvedic
medicine, is a short shrub which grows in all dry parts and
sub-tropical parts of India, South Africa, Congo, Egypt, Morocco,
Jordan and Afghanistan. The naturally occurring plant products are
eco-friendly, compatible, nonpolluting, easily available,
biodegradable and economic to be used as corrosion inhibitors.
[0150] Biologically, Withania somnifera is classified as follows:
Kingdom: Plantae; Subkingdom: Tracheobionta; Division:
Magnoliophyta; Class: Magnoliopsida; Subclass: Asteridae; Order:
Solanales; Family: Solanaceae; Subfamily: Asteroideae; Genus:
Withania; Species: Withania somnifera.
[0151] The powder of Withania somnifera is extracted twice (from
the roots of the plant), once with organic solvents and once with
water so as to extract both solvent and water soluble components.
Then these extracts are evaporated to remove solvents (organic and
water). The thick slurry obtained after evaporation from these two
stages is mixed and dissolved in some water. A small amount of
glycerol or sorbitol is added to this mixture to make the solution
soluble or dispersible in water.
[0152] The extract of Withania somnifera is believed to contain
mostly withanolides (also known as steroidal lactones).
Withanolides are produced via oxidation of steroids. Withaferin A,
the first withanolide to be isolated, was found in Withania
somnifera. Structurally, withanolides consist of a C.sub.28 steroid
backbone bound to a six-membered lactone ring. For example,
steroidal lactones can be ergostane type steroids with a C.sub.28
basic skeleton with a side chain of C.sub.9 units of which a
six-membered lactone ring is included. Withanolides include a group
of at least 300 naturally occurring chemical compounds.
Withanolides occur as secondary metabolites primarily in genera of
the Nightshade family.
[0153] In addition to withanolides, Withania somnifera extract is
believed to contain some alkaloids. Withanolides have oxygen atoms
and alkaloids have N and S atoms. It is believed that can any of
these withanolide or alkaloid molecules can be adsorbed on a carbon
steel surface. Without being limited by any theory, it is believed
that this adsorption can block the discharge of H.sup.+ and
dissolution of metal ions. According to the invention, it is
believed that any of the withanolides or alkaloids that can be
extracted from Withania somnifera would function as a corrosion
inhibitor for carbon steel.
[0154] Genera within the Solanaceae (nightshade) family that have
been found to produce withanolides include the following: Datura,
Dunalia, Iochroma, Lycium, Nicandra, Physalis, Salpichroa, Solanum,
Withania, and Jaborosa. The genus Withania is further organized
into 65 species, subspecies, varieties, forms, and cultivars. Two
of the species, W. somnifera (also known as Ashwagandha) and W.
coagulans (also known as Ashutosh booti), are economically
significant, and are cultivated in several regions for their
medicinal uses. All genera from the Family Solanaceae that produce
withanolides are expected to exhibit the corrosion inhibition
properties demonstrated by Withania somnifera.
[0155] Accordingly, it is contemplated that any of the plants of
the Solanaceae (nightshade) family would be useful as a corrosion
inhibitor for carbon steel.
[0156] Based on this discovery that Withania somnifera extract is
an effective corrosion inhibitor for carbon steel, it is
contemplated that it may not be necessary to extract from the plant
prior to use as a corrosion inhibitor. For example, the plant
material is expected to release at least some of the active
corrosion inhibitor into the fluid, especially if used in the fluid
at an elevated temperature (above Standard Laboratory Conditions up
to as high as about 300.degree. F.). Accordingly, for example, a
material of any of the plants of the Solanaceae (nightshade)
family, are contemplated by this invention. It is contemplated that
such a material be in the form of a ground or powdered plant
material. In addition, it is believed the withanolides are formed
primarily in the roots of such plants, and, accordingly, material
from the roots is preferred.
[0157] In addition, it is contemplated that other sources of
withanolides, including synthetic withanolides, would be suitable
for use according to the invention. Natural plant sources of
withanolides are expected to be cheaper than synthetic sources,
however.
Corrosion and Inhibition
[0158] Corrosion of metals can occur anywhere in an oil or gas
production system, such as in the downhole tubulars, equipment, and
tools of a well, in surface lines and equipment, or transportation
pipelines and equipment.
[0159] In general, "corrosion" is the loss of metal due to chemical
or electrochemical reactions, which could eventually destroy a
structure. The corrosion rate will vary with time depending on the
particular conditions to which a metal is exposed, such as the
amount of water, pH, other chemicals, temperature, and pressure.
Examples of common types of corrosion include, but are not limited
to, the rusting of metal, the dissolution of a metal in an acidic
solution, oxidation of a metal, chemical attack of a metal,
electrochemical attack of a metal, and patina development on the
surface of a metal.
[0160] Even weakly acidic fluids can be problematic in that they
can cause corrosion of metals. As used herein with reference to the
problem of corrosion, "acid" or "acidity" refers to a
Bronsted-Lowry acid or acidity.
[0161] As used herein, the term "inhibit" or "inhibitor" refers to
slowing down or lessening the tendency of a phenomenon (e.g.,
corrosion) to occur or the degree to which that phenomenon occurs.
The term "inhibit" or "inhibitor" does not imply any particular
mechanism, or degree of inhibition.
[0162] Accordingly, the term "corrosion inhibitor" means a material
that has the property of reducing, slowing down, or lessening the
tendency to corrosion.
[0163] When included, a corrosion inhibitor is preferably in a
concentration of at least 0.1% by weight of a fluid. More
preferably, the corrosion inhibitor is in a concentration in the
range of 0.1% to 20% by weight of the fluid.
[0164] A corrosion inhibitor intensifier enhances the effectiveness
of a corrosion inhibitor over the effectiveness of the corrosion
inhibitor without the corrosion inhibitor intensifier. According to
a preferred embodiment of the invention, the corrosion inhibitor
intensifier is selected from the group consisting of: formic acid
and potassium iodide.
[0165] The corrosion inhibitor intensifier is preferably in a
concentration of at least 0.1% by weight of the fluid. More
preferably, the corrosion inhibitor intensifier is in a
concentration in the range of 0.1% to 20% by weight of the
fluid.
Theoretical Discussion
[0166] Mineral Acids and Organic Acids
[0167] Strongly acidic solutions tend to be more corrosive to
metals.
[0168] The pH value represents the acidity of a solution. The
potential of hydrogen (pH) is defined as the negative logarithm to
the base 10 of the hydrogen concentration, represented as [H.sup.+]
in moles/liter.
pH=-log.sub.10 [H.sup.+]
[0169] Mineral acids tend to dissociate in water more easily than
organic acids, to produce H.sup.+ions and decrease the pH of the
solution. Organic acids tend to dissociate more slowly than mineral
acids and less completely.
[0170] Relative acid strengths for Bronsted-Lowry acids are
expressed by the dissociation constant (pKa). A given acid will
give up its proton to the base of an acid with a higher pKa value.
The bases of a given acid will deprotonate an acid with a lower pKa
value. In case there is more than one acid functionality for a
chemical, "pKa(1)" makes it clear that the dissociation constant
relates to the first dissociation.
[0171] The pKa of acids plays important role in above activities as
shown in Table 1.
TABLE-US-00001 TABLE 1 Acid Base pKa(1) Strong Acids HCIO.sub.4
CIO.sub.4.sup.- -10 In Water HI I.sup.- -10 H.sub.2SO.sub.4
HSO.sub.4.sup.- -10 HBr Br.sup.- -9 HCI CI.sup.- -7 HNO.sub.3
NO.sub.3.sup.- -2 H.sub.3O.sup.+ H.sub.2O -1.74 Weak Acids
CCI.sub.3CO.sub.2H CCI.sub.3CO.sub.2.sup.- 0.52 In Water
HSO.sub.4.sup.- SO.sub.4.sup.-2 1.99 H.sub.3PO.sub.4
H.sub.2PO.sub.4.sup.- 2.12 CH.sub.2CICO.sub.2H
CH.sub.2CICO.sub.2.sup.- 2.85 HF F.sup.- 3.17 HNO.sub.2
NO.sub.2.sup.- 3.3 CH.sub.3CO.sub.2H CH.sub.3CO.sub.2.sup.- 4.75
C.sub.5H.sub.5NH.sup.+ C.sub.5H.sub.5N 5.25 H.sub.2CO.sub.3
HCO.sub.3.sup.- 6.35 H.sub.2S HS.sup.- 7.0 NH.sub.4.sup.+ NH.sub.3
9.24 HCO.sub.3.sup.- CO.sub.3.sup.-2 10.33 CH.sub.3NH.sub.3.sup.+
CH.sub.3NH.sub.2 10.56 H.sub.2O OH.sup.- 15.74
[0172] Water (H.sub.2O) is the base of the hydronium ion,
H.sub.3O.sup.+, which has a pka -1.74. An acid having a pKa less
than that of hydronium ion, pKa -1.74, is considered a strong
acid.
[0173] For example, hydrochloric acid (HCl) has a pKa -7, which is
greater than the pKa of the hydronium ion, pKa -1.74. This means
that HCl will give up its protons to water essentially completely
to form the H.sub.3O.sup.+cation. For this reason, HCl is
classified as a strong acid in water. One can assume that all of
the HCl in a water solution is 100% dissociated, meaning that both
the hydronium ion concentration and the chloride ion concentration
correspond directly to the amount of added HCl.
[0174] Acetic acid (CH.sub.3CO.sub.2H) has a pKa of 4.75, greater
than that of the hydronium ion, but less than that of water itself,
15.74. This means that acetic acid can dissociate in water, but
only to a small extent. Thus, acetic acid is classified as a weak
acid.
[0175] Acid Corrosion of Metals
[0176] As mineral acids are stronger acids than organic acids,
mineral acids tend to be more corrosive than organic acids. In
addition, at elevated temperatures the dissociation rate increases
significantly, and hence, all else being equal, an acid becomes
more corrosive.
[0177] The mechanism of corrosion for both cases (mineral acids and
organic acids) is expected to be same, the only difference is in
the rate of corrosion. The rate of corrosion will depend upon the
availability of H.sup.+ ion released from acid. Mineral acids
dissociate completely to give more H.sup.+ ions as compared to
organic acids.
[0178] Aluminum Corrosion Resistance
[0179] Aluminum is a chemical element in the boron group with
symbol Al and atomic number 13. It is silvery white. Aluminum is
the third most abundant element (after oxygen and silicon), and the
most abundant metal, in the Earth's crust. It makes up about 8% by
weight of the Earth's solid surface. Aluminum metal is so
chemically reactive that native specimens are rare and limited to
extreme reducing environments. Instead, it is found combined in
over 270 different minerals. The chief ore of aluminum is
bauxite.
[0180] Aluminum metal is essentially 100% aluminum. Aluminum and
its alloys are generally not sufficiently strong for use in
oilfield applications. In addition, aluminum and its alloys are
susceptible to hydrogen embrittlement.
[0181] Aluminum is remarkable for the metal's low density and for
its ability to resist corrosion due to the phenomenon of
passivation. Although aluminum is an active metal, as indicated in
the electromotive force series, it is resistant to corrosion in
many environments.
[0182] Without being limited by any theory, it is believed that the
corrosion resistance of aluminum results from the formation of a
passive oxide film, which is 0.005 to 0.010 micron thick in air. A
thin protective film is also formed in water at ambient
temperatures. As temperature increases, the film becomes thicker
and more protective. This film is stable in aqueous media when the
pH is between about 4.0 and 8.5. The oxide film is naturally
self-renewing and accidental abrasion or other mechanical damage of
the surface film is rapidly repaired. However, the protective film
does not form in water or steam above approximately 446.degree. F.
(230.degree. C.).
[0183] Aluminum is an amphoteric metal, i.e., it corrodes under
both acid and alkaline conditions. The acidity or alkalinity of the
environment significantly affects the corrosion behavior of
aluminum alloys. At lower and higher pH, aluminum is more likely to
corrode, but by no means always does so.
[0184] In acidic conditions, the aluminum oxide is generally more
rapidly attacked than aluminum itself, and more general corrosion
should result as the oxide is first attacked, exposing the aluminum
metal. Acid waters containing chlorides are especially corrosive to
aluminum. Although sulfate-containing waters of low pH are also
corrosive to aluminum, they are less corrosive than
chloride-containing acids. Exceptions are acetic acid, nitric acid
above 80% concentration by weight, and sulfuric acid of 98 to 100%
concentration by weight.
[0185] Accordingly, aluminum exhibits good resistance to nearly all
concentrations of acetic acid at room temperature and has been used
extensively for its storage and shipment. For example, aluminum is
fairly resistant to 97 and 99% acetic acid to the boiling point,
but is attacked very rapidly in concentrations nearly 100% or
containing excess (CH3CO).sub.2O. Bruce D. Craig, "Hand Book of
Corrosion Data," 2nd edition, Page 88.
[0186] When aluminum is exposed to alkaline conditions corrosion
may occur, and when the oxide film is perforated locally,
accelerated attack occurs because aluminum is attacked more rapidly
than its oxide under alkaline conditions. The result of this kind
of attack is pitting of the metal. An exception to corrosion under
alkaline conditions is to ammonium hydroxide above about 30%
concentration by weight.
[0187] Aluminum and its alloys are resistant to attack by most
organic chemicals, but some organic chemicals will react with
aluminum if they are free of water and at elevated temperatures,
usually near their boiling points.
[0188] Iron and Steel Corrosion
[0189] Iron is a chemical element with the symbol Fe (from Latin:
ferrum) and atomic number 26. It is a metal in the first transition
series. It is the most common element (by mass) forming the planet
Earth as a whole, forming much of Earth's outer and inner core. It
is the fourth most common element in the Earth's crust. Iron exists
in a wide range of oxidation states, -2 to +8, although +2 and +3
are the most common. Elemental iron is reactive to oxygen and
water. Fresh iron surfaces appear lustrous silvery-gray, but
oxidize in normal air to give iron oxides, also known as rust.
Unlike many other metals which form passivating oxide layers, iron
oxides occupy more volume than iron metal, and thus iron oxides
flake off and expose fresh surfaces for corrosion.
[0190] Pure iron is softer than aluminum, but iron is significantly
hardened and strengthened by impurities from the smelting process,
such as carbon. A certain proportion of carbon (between 0.2% and
2.1%) produces steel, which may be up to 1,000 times harder than
pure iron. Crude iron metal is produced in blast furnaces, where
ore is reduced by coke to pig iron, which has high carbon content.
Further refinement with oxygen reduces the carbon content to the
correct proportion to make steel.
[0191] Carbon steel is steel where the main interstitial alloying
constituent is carbon. As the carbon content rises, steel has the
ability to become harder and stronger through heat treating, but
this also makes it less ductile. Regardless of the heat treatment,
higher carbon content reduces weldability. In carbon steels, the
higher carbon content lowers the melting point. The typical
composition of carbon steel is an alloy of iron containing no more
than 2.0 wt % of carbon.
[0192] The term "carbon steel" may also be used in reference to
steel which is not stainless steel; in this use carbon steel may
include alloy steels.
[0193] The American Iron and Steel Institute (AISI) defines carbon
steel as the following: "Steel is considered to be carbon steel
when no minimum content is specified or required for chromium,
cobalt, molybdenum, nickel, niobium, titanium, tungsten, vanadium
or zirconium, or any other element to be added to obtain a desired
alloying effect; when the specified minimum for copper does not
exceed 1.04 percent; or when the maximum content specified for any
of the following elements does not exceed the percentages noted:
manganese 1.65, silicon 0.60, copper 0.60."
[0194] Generally speaking, carbon steels contain up to 2% total
alloying elements and can be subdivided into low-carbon steels,
medium-carbon steels, high-carbon steels, and ultrahigh-carbon
steels. Low-carbon steels contain up to 0.30% C. Medium-carbon
steels are similar to low-carbon steels except that the carbon
ranges from 0.30 to 0.60% and the manganese from 0.60 to 1.65%.
Ultrahigh-carbon steels are experimental alloys containing 1.25 to
2.0% C.
[0195] Steels and low carbon iron alloys with other metals (alloy
steels) are by far the most common metals in industrial use, due to
their great range of desirable properties and the abundance of
iron. Steel is commonly used in oilfield and pipeline tubulars and
equipment.
[0196] For example, carbon steel is usually used in tubes for the
production of oil, for example "N-80", "J-55", or "P-110," having
the following typical composition ranges, by weight: 0.20% to 0.45%
C, 0.15% to 0.40% Si; 0.60% to 1.60% Mn; 0.03% maximum S; 0.03%
maximum P; 1.60% maximum Cr; 0.50% maximum Ni; 0.70% maximum No;
0.25% maximum Cu; and balance Fe (greater than 94%).
[0197] Without being limited by any theory, it is believed the
corrosion of steel is attributable to the reactivity of iron (Fe).
Corrosion of iron alloys such as steel is expected to occur much
faster and uninhibited compared to aluminum. Thus, iron and its
alloys are much more susceptible to corrosion than aluminum in
acidic solutions. For example, in contrast to aluminum, steel is
attacked quite rapidly by all concentrations of acetic acid even at
room temperature. Therefore, steel is normally unacceptable for use
in acetic acid service. Bruce D. Craig, "Hand Book of Corrosion
Data," 2nd edition, Page 88.
[0198] In the range of pH 4 to 10, the corrosion rate of iron or
steel is relatively independent of the pH of the solution. In this
pH range, the corrosion rate is governed largely by the rate at
which oxygen reacts with absorbed atomic hydrogen, thereby
depolarizing the surface and allowing the reduction reaction to
continue.
[0199] For acidic pH values below 4, ferrous oxide (FeO) is
soluble. Thus, the oxide dissolves as it is formed rather than
depositing on the metal surface to form a film. In the absence of
the protective oxide film, the metal surface is in direct contact
with the acid solution, and the corrosion reaction proceeds at a
greater rate than it does at higher pH values. It is also observed
that hydrogen is produced in acid solutions below a pH of 4,
indicating that the corrosion rate no longer depends entirely on
depolarization by oxygen, but on a combination of the two factors
(hydrogen evolution and depolarization).
[0200] For pH values above about 10, the corrosion rate is observed
to fall as pH is increased. This is believed to be due to an
increase in the rate of the reaction of oxygen with Fe(OH).sub.2
(hydrated FeO) in the oxide layer to form the more protective
Fe.sub.2O.sub.3 (note that this effect is not observed in deaerated
water at high temperatures).
[0201] As used herein, the term "carbon steel" does not include
stainless steel. Stainless steel differs from carbon steel by
amount of chromium present.
[0202] In metallurgy, stainless steel, also known as inox steel or
inox from French "inoxydable," is defined as a steel alloy with a
minimum of 11.5% chromium content by weight. Stainless steel does
not corrode, rust, or stain with water as ordinary steel does, but
despite the name it is not fully stain-proof, most notably under
low oxygen, high salinity, or poor circulation environments. It is
also called corrosion-resistant steel or CRES when the alloy type
and grade are not detailed. There are different grades and surface
finishes of stainless steel to suit the intended environment.
Stainless steel is used where both the properties of steel and
resistance to corrosion are required.
[0203] Stainless steel differs from carbon steel by the amount of
chromium present. Unprotected carbon steel rusts readily when
exposed to air and moisture. This iron oxide film (the rust) is
active and accelerates corrosion by forming more iron oxide, and
due to the dissimilar size of the iron and iron oxide molecules
(iron oxide is larger) these tend to flake and fall away. Stainless
steels contain sufficient chromium to form a passive film of
chromium oxide, which prevents further surface corrosion and blocks
corrosion from spreading into the internal material of the metal,
and due to the similar size of the steel and oxide molecules they
bond very strongly and remain attached to the surface. Passivation
only occurs if the proportion of chromium is high enough and in the
presence of oxygen.
[0204] Corrosion Inhibition of Aluminum vs. Carbon Steel
[0205] Without being limited by any theory, inhibitors that work on
the polymer film-forming phenomenon are expected to work similar on
metals such as aluminum or carbon steel. However, those that work
on the adsorption phenomenon of inhibitor molecules on the surface
of the metal are expected to have different inhibition efficiencies
on aluminum and carbon steel because their adsorption efficiencies
will depend upon the chemical nature of the metal.
[0206] Withania Somnifera or Withanolides as Corrosion
Inhibitor
[0207] Due to the presence of heteroatoms in Withania somnifera
extract (primarily comprising one or more withanolides), it is
believed that the inhibition mechanism is based on the adsorption
phenomenon.
[0208] Although Withania somnifera is known to be an inhibitor for
aluminum at low concentrations of acid and under lower pressures
and temperatures, it is surprising that it would work as a
corrosion inhibitor for carbon steel, which has a much higher
tendency to corrode compared to aluminum. It is unexpected that
extract of Withania somnifera or other sources of withanolides
would be useful as a corrosion inhibitor for carbon steel,
especially in the cases of carbon steel exposed to higher
concentrations of strong or weak acids or under higher pressure or
temperature conditions, as may be required in a well or pipeline
environment. Such properties are required, however, for an
inhibitor used with carbon steel in the oil and gas industry and
pipeline industry.
[0209] Withania somnifera is an example of a readily available
plant source for one or more withanolides. As shown below, Withania
somnifera can be used as a corrosion inhibitor for carbon steel,
including in high concentrations of mineral acid or organic acid or
at design pressures at least as high as 1,000 psi and temperatures
at least as high as 275.degree. F.
Fluids, Methods, and Applications
[0210] As discussed above, a method according to the invention
includes contacting carbon steel with a fluid comprising an aqueous
acidic phase. The method includes the step of including in the
fluid a material selected from the group consisting of: a material
of a plant in the Solanaceae family, an extract of a material of a
plant in the Solanaceae family, a withanolide, a source of a
withanolide, a withanolide derivative, a source of a withanolide
derivative, and any combination thereof.
[0211] Carbon steel commonly used in wells or pipelines include,
without limitation, J55 steel, N-80 steel, and P-110 steel.
[0212] In an embodiment of the invention, the fluid is a
water-based fluid. It should be appreciated, however, that the
fluid can be an emulsion for certain applications in a well or
pipeline, either an oil-in-water emulsion or a water-in-oil
emulsion. It should also be appreciated, that the fluid can include
a suspended solid particulate, such as a proppant or gravel, which
may be used with acidizing fluids in certain applications in a
well, as known in the art.
[0213] In an embodiment, the aqueous acidic phase includes one or
more water-soluble salts. Such salts can have various purposes in a
well or pipeline fluid. For example, a salt can be used as a
weighting agent. By way of another example, a salt can be used to
help stabilize the rock of a subterranean formation when it
contacts water. The salt can be dissolved in the water phase of a
fluid. The water-soluble salt can be, for example, selected from
the group consisting of alkali metal halides, such as KCl or NaCl,
which are commonly used in well or pipeline fluids. Unfortunately,
dissolved salts can also exacerbate corrosion of certain metals.
Another commonly used salt used as a weighting agent is barium
sulfate.
[0214] In an embodiment, the fluid can be viscosified for various
purposes, such as to help suspend a particulate or control or
divert penetration of an acidizing fluid into the rock of a
subterranean formation, according to techniques known in the art.
For example, in an embodiment, the aqueous fluid is viscosified
with a viscosity-increasing agent, such as a water-soluble
polysaccharide or viscoelastic surfactant, according to such
techniques known in the art. A well fluid for use in a method
according to the invention can include a cross-linker for a
water-soluble polysaccharide or water-soluble polysaccharide
derivative.
[0215] In an embodiment, the aqueous acidic phase is acidified with
one or more Bronsted-Lowry acids. For example, the acid can be
selected from the group consisting of: hydrochloric acid,
hydrofluoric acid, formic acid, acetic acid, citric acid, and any
mixture thereof. Preferably, the acid present in the aqueous acid
solution in a concentration in the range of from about 2% to about
35% by weight of water. More preferably, the acid is in a
concentration of at least 7% by weight of the water up to about 28%
by weight of the water.
[0216] In an embodiment, the aqueous acidic phase includes a
mineral acid having a pKa(1) less than -1.74. In another
embodiment, the aqueous acidic phase comprises an organic acid
having a pKa(1) less than 5.
[0217] In an embodiment, the aqueous acidic phase has a pH less
than 4.
[0218] In an embodiment, the material of a plant in the Solanaceae
family is of the root of the plant.
[0219] In another embodiment, the plant in the Solanaceae family is
also selected for producing a withanolide. For example, in an
embodiment, the plant in the Solanaceae family is also in a genera
selected from the group consisting of: Datura, Dunalia, Iochroma,
Lycium, Nicandra, Physalis, Salpichroa, Solanum, Withania, and
Jaborosas. Preferably, the plant in the Solanaceae family is also
in the genera Withania.
[0220] In an embodiment, an extract is in particulate form when
being added to the fluid. For example, the extract can be in the
form of a powder. In another embodiment, the extract is in a liquid
solution when being added to the fluid.
[0221] For example, a withanolide used in the methods according to
the invention can be extracted from plant material containing the
withanolide. It is believed, however, that it is not necessary to
extract the withanolide from the plant material. For example, a
root of the Family Solanaceae of plants that includes one or more
withanolides, can be used as a source of the corrosion inhibitor.
The other materials of the root are not expected to interfere in
the applications of the methods according to the inventions. It may
be, however, that other materials of the plant or extract are
corrosion inhibitors or corrosion inhibitor intensifiers for carbon
steel.
[0222] Preferably, the withanolide or source of withanolide is in
the form of a particulate prior to the step of combining with the
aqueous acid solution. Most preferably, the size of the particulate
of the corrosion inhibitor is in the range of a powder. The
particulate may be suspended in a liquid for ease of handling and
mixing prior to the step of combining. For example, the corrosion
inhibitor can be suspended in an oil phase.
[0223] It is to be understood that the well fluid can be, for
example, in the form of a suspension or an emulsion during the step
of contacting.
[0224] Preferably, the material used as a corrosion inhibitor is
biodegradable according to a test for biodegradability.
[0225] In an embodiment, the material is a concentration in the
range of from about 0.01% wt/vol to about 20% wt/vol of the aqueous
acid solution. More preferably, the withanolide is combined with
the aqueous acid solution in an effective amount to provide at
least measurable corrosion inhibition for the metal to be contacted
by the well fluid in the well under the design conditions of
contacting.
[0226] In an embodiment, the fluid additionally comprises a
corrosion inhibitor intensifier. For example, the fluid can
additionally comprise potassium iodide.
[0227] In an embodiment, the method has a design temperature for
contacting of the carbon steel and the fluid is at least
200.degree. F. In another embodiment, a design temperature for
contacting of the carbon steel and the fluid is less than
300.degree. F.
[0228] A well fluid for use in a method according to the invention
can include, for example, one or more additives selected from the
group consisting of inorganic water-soluble salts, weighting
agents, surfactants, surface modifying agents, gas, nitrogen,
carbon dioxide, foamers, bases, buffers, alcohols, fluid-loss
control additives, conventional corrosion inhibitors, corrosion
inhibitor intensifiers, scale inhibitors, catalysts, clay control
agents, biocides, friction reducers, antifoam agents, bridging
agents, dispersants, flocculants, H.sub.2S scavengers, CO.sub.2
scavengers, oxygen scavengers, lubricants, viscosifiers, oxidizers,
breakers, breaker aids, relative permeability modifiers,
particulate materials, proppant particulates, resins, tackifying
agents, wetting agents, coating enhancement agents, and any
combination thereof.
[0229] The method can further include the step of flowing back at
least some of the well fluid from the well or pipeline after
contacting the carbon steel.
[0230] The methods can be used for various types of well or
pipeline fluids comprising an aqueous acid solution and associated
methods. For example, the methods have particular application with
matrix acidizing or acid fracturing fluids, which are strongly
acidic. The methods also have particular application in hydrocarbon
transportation pipelines that use acidic fluids.
[0231] According to another embodiment of the invention, the method
includes the steps of: forming a fluid according to the invention;
and introducing the treatment fluid into a well or pipeline.
[0232] A well fluid can be prepared at the job site, prepared at a
plant or facility prior to use, or certain components of the well
fluid can be pre-mixed prior to use and then transported to the job
site. Certain components of the well fluid may be provided as a
"dry mix" to be combined with fluid or other components prior to or
during introducing the well fluid into the well.
[0233] In certain embodiments, the preparation of a well fluid can
be done at the job site in a method characterized as being
performed "on the fly." The term "on-the-fly" is used herein to
include methods of combining two or more components wherein a
flowing stream of one element is continuously introduced into
flowing stream of another component so that the streams are
combined and mixed while continuing to flow as a single stream as
part of the on-going treatment. Such mixing can also be described
as "real-time" mixing.
[0234] Often the step of introducing a well fluid into a well is
within a relatively short period after forming the well fluid, for
example, within 30 minutes to one hour. More preferably, the step
of delivering the well fluid is immediately after the step of
forming the well fluid, which is "on the fly."
[0235] It should be understood that the step of delivering a well
fluid into a well can advantageously include the use of one or more
fluid pumps.
[0236] After the acid is spent for its intended purpose, the fluid
can be flowed back from the well or out of the pipeline.
EXAMPLES
[0237] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the entire scope of the invention.
[0238] Static Corrosion Weight-Loss Test Procedure
[0239] Static weight-loss corrosion tests were performed as
follows. High pressure, high temperature ("HPHT") static weight
loss corrosion testing was performed in individual HASTELLOY.TM.
model B-2 autoclaves. Weighing of the metal specimens (sometimes
referred to in the art as "coupons") was on a balance accurate to
0.001 gram (g).
[0240] The metal alloy specimens were cleaned by degreasing with
acetone followed by removal of the surface scale by lightly bead
blasting the surface. Each specimen of approximate surface area 4.4
in.sup.2 was accurately measured in square inches and accurately
weighed in grams.
[0241] Test fluids were prepared by mixing the desired
components.
[0242] 100 ml of each test fluid was placed into a glass cell,
followed by introduction of a metal specimen. After capping the
cell, the container with the test fluid and the alloy specimen were
placed in the autoclave. The autoclave was filled with a heat
transfer medium and pressurized to a test pressure of 1,000 psi
with nitrogen gas. Heating was accomplished using EUROTHERM.TM.
controllers that adjust a specific heating ramp up to the test
temperature via a computer control. Pressure was maintained using a
back pressure regulator assembly which allows for automatic
bleed-off of excess pressure developed during heating and
corrosion. Test times were contact times and included heat up and
cool down times. The test times were the total contact time of the
test fluid on the specimen.
[0243] At the end of the test time, the alloy test specimen was
removed from the test fluid, then cleaned with acetone and a light
brushing to remove surface deposits, and finally dried and
weighed.
[0244] The corrosion loss in units of lb/ft.sup.2 was calculated
using the following equations:
Weight loss in g=(Wt.B g-Wt.A g)
Weight loss (grams).times.[144 in.sup.2/ft.sup.2/(453.6
g/lb.times.S.A. in.sup.2)]=corrosion loss lb/ft.sup.2
where "S.A. in.sup.2" is the surface area of a coupon measured in
square inches, "Wt.B" was the weight in grams of the coupon before
testing, and where "Wt.A" is the weight in grams of the coupon
after testing.
[0245] According to this method, the standard for an acceptable
corrosion loss for carbon steel is less than or equal to 0.05
lb/ft.sup.2 under the design conditions of acid and concentration
and of fluid contact time at a specified temperature and
pressure.
[0246] Experimental details, including test fluid compositions,
type of metal alloy specimen, and the testing time and temperature,
are discussed below.
[0247] Corrosion Testing of Withania somnifera Extract in Mineral
Acid on Carbon Steel
[0248] Static weight-loss corrosion tests were conducted regarding
Withania somnifera extract (liquid) as a corrosion inhibitor in
mineral acid fluids on specimens of carbon steel. Representative
testing is shown in Table 2, below. The mineral acid was
concentrated (15% by weight) hydrochloric acid (HCl). The test
specimens used were of "N-80" steel.
[0249] A representative control test with 15% HCl fluid (without
any Withania somnifera extract) on a test specimen of N-80 carbon
steel for 6 hours at 275.degree. F. gave an unacceptable corrosion
loss of 0.7957 lb/ft.sup.2.
[0250] Testing with Withania somnifera extract (liquid) in
concentrated mineral acid (e.g., 15% HCl) demonstrated it can
provide corrosion inhibition for carbon steel. The corrosion
inhibiting effect of the Withania somnifera extract is improved
when used in conjunction with an intensifier, such as potassium
iodide or potassium iodide with formic acid. For example, as can be
seen in Table 2 below, at mineral acid concentrations of 15% HCl
and at a temperature of 250.degree. F. for 6 hours, the Withania
somnifera extract (liquid) with an intensifier gives an acceptable
corrosion loss for carbon steel of less than 0.05 lb/ft.sup.2. In
15% HCl at higher temperatures, an intensifier may be required
along with the Withania somnifera extract as inhibitor, to achieve
acceptable corrosion loss values under such design conditions. The
testing of Table 2 shows that Withania somnifera extract in a
concentrated mineral acid can provide corrosion inhibition for up
to at least 6 hours and up to at least 275.degree. F. for carbon
steel.
TABLE-US-00002 TABLE 2 Conc. of Conc. of Contact Corrosion
inhibitor Conc. of acid Temp. Time Loss (% v/v) intensifier (% by
wt) (.degree. F.) (hours) Alloy (lb/ft.sup.2) Pitting NA NA 15% HCl
275 6 N-80 0.7957 Yes 5% 100 lbs/Mgal 15% HCl 250 6 N-80 0.0364
None potassium iodide 15% 120 lbs/Mgal 15% HCl 275 6 N-80 0.078
None potassium iodide + 6% v/v formic acid 15% 120 lbs/Mgal 15% HCl
300 6 N-80 0.2657 Yes potassium iodide
[0251] Corrosion Testing of Withania somnifera Extract in Organic
Acids on Carbon Steel
[0252] Static weight-loss corrosion tests were conducted regarding
Withania somnifera extract (powder) as a corrosion inhibitor in
organic acid fluids on specimens of carbon steel. Representative
testing is shown in Table 3, below. The organic acid was a mixture
of (9% by volume) formic acid and (13% by volume) acetic acid. The
test specimens used were of "N-80" steel.
[0253] A representative control test in an aqueous organic acid
fluid (without any Withania somnifera extract) on a test specimen
of N-80 carbon steel for 6 hours at 275.degree. F. gave an
unacceptable corrosion loss of 0.6165 lb/ft.sup.2.
[0254] Tests conducted using Withania somnifera sextract (powder
form) with organic acid mixtures of 9% formic acid and 13% acetic
acid prepared in 1.04 specific gravity NaCl brine, resulted in very
low values of corrosion loss up to at least 275.degree. F., much
lower than the acceptable corrosion loss of less than 0.05
lb/ft.sup.2. These tests were done with powdered sample of Withania
somnifera.
TABLE-US-00003 TABLE 3 Conc. of intensifier Conc. of potassium
Contact Corrosion inhibitor iodide Conc. of acids Temp Time Loss
(lb/Mgal) (lb/Mgal) (% by vol.) (.degree. F.) (hours) Alloy
(lb/ft.sup.2) Pitting NA NA 9% Formic acid + 275 6 N-80 0.6165 Yes
13% Acetic acid + 1.04 spg. NaCl brine 50 20 9% Formic acid + 200 6
N-80 0.0040 None 13% Acetic acid + 1.04 spg. NaCl brine 50 20 9%
Formic acid + 225 6 N-80 0.0048 None 13% Acetic acid + 1.04 spg.
NaCl brine 50 50 9% Formic acid + 250 6 N-80 0.0196 None 13% Acetic
acid + 1.04 spg. NaCl brine 75 100 9% Formic acid + 275 6 N-80
0.0270 None 13% Acetic acid + 1.04 spg. NaCl brine 75 100 9% Formic
acid + 300 6 N-80 0.2813 Yes 13% Acetic acid + 1.04 spg. NaCl
brine
[0255] The above data demonstrates the corrosion inhibition
properties of Withania somnifera in mineral acids as well as
organic acids.
CONCLUSION
[0256] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein.
[0257] The particular embodiments disclosed above are illustrative
only, as the present invention may be modified and practiced in
different but equivalent manners apparent to those skilled in the
art having the benefit of the teachings herein. It is, therefore,
evident that the particular illustrative embodiments disclosed
above may be altered or modified and all such variations are
considered within the scope and spirit of the present
invention.
[0258] The various elements or steps according to the disclosed
elements or steps can be combined advantageously or practiced
together in various combinations or sub-combinations of elements or
sequences of steps to increase the efficiency and benefits that can
be obtained from the invention.
[0259] The invention illustratively disclosed herein suitably may
be practiced in the absence of any element or step that is not
specifically disclosed or claimed.
[0260] Furthermore, no limitations are intended to the details of
construction, composition, design, or steps herein shown, other
than as described in the claims.
* * * * *