U.S. patent application number 12/031094 was filed with the patent office on 2008-10-02 for downhole oilfield apparatus comprising a diamond-like carbon coating and methods of use.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Rashmi Bhavsar, Manuel Marya.
Application Number | 20080236842 12/031094 |
Document ID | / |
Family ID | 39792283 |
Filed Date | 2008-10-02 |
United States Patent
Application |
20080236842 |
Kind Code |
A1 |
Bhavsar; Rashmi ; et
al. |
October 2, 2008 |
DOWNHOLE OILFIELD APPARATUS COMPRISING A DIAMOND-LIKE CARBON
COATING AND METHODS OF USE
Abstract
Downhole apparatus and methods of using the apparatus are
described, the apparatus comprising at least one metallic component
having a DLC coating thereon, the coating present at least on one
or more internal passageways of the base metal or alloy to be
exposed to downhole environments. Methods of using an apparatus in
downhole oilfield operations are also described. This abstract
allows a searcher or other reader to quickly ascertain the subject
matter of the disclosure. It will not be used to interpret or limit
the scope or meaning of the claims.
Inventors: |
Bhavsar; Rashmi; (Houston,
TX) ; Marya; Manuel; (Pearland, TX) |
Correspondence
Address: |
SCHLUMBERGER RESERVOIR COMPLETIONS
14910 AIRLINE ROAD
ROSHARON
TX
77583
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
39792283 |
Appl. No.: |
12/031094 |
Filed: |
February 14, 2008 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60908236 |
Mar 27, 2007 |
|
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|
Current U.S.
Class: |
166/381 ;
166/113 |
Current CPC
Class: |
E21B 41/02 20130101 |
Class at
Publication: |
166/381 ;
166/113 |
International
Class: |
E21B 43/00 20060101
E21B043/00 |
Claims
1. A downhole oilfield apparatus of base metal or alloy having a
coating thereon comprising diamond-like carbon (DLC), the coating
present at least on one or more internal passageways of the base
metal or alloy to be exposed to downhole environments such as
completion and produced fluids, the apparatus selected from
downhole tools having one or more of the following functions:
control, change, isolate, restrict, and/or monitor flow of, or
transfer heat and/or momentum to or from, a fluid, solids, or
combinations of fluid and solids.
2. The downhole apparatus of claim 1 wherein the DLC coating is
deposited by a process selected from PVD, CVD, or any
enhanced-plasma CVD process such as the hollow cathode plasma ion
immersion process to provide anti-wear, ultra low friction, and
environmentally resistant surfaces.
3. The downhole apparatus of claim 1 wherein the base metal or
alloy is ferrous or non-ferrous and includes oilfield metallic
materials such as carbon steels, stainless steels, nickel alloys,
and titanium alloys.
4. The downhole apparatus of claim 1 with at its surfaces one or
more intermediate metallic or semi-metallic layers between the base
metal or alloy of claim 3 and the DLC coating to produce a
functionally graded material that permit the formation of an
adherent and slick DLC coating.
5. The downhole apparatus of claim 4 wherein the intermediate layer
comprises a metal, in particular selected from transition-metals
and/or carbide-forming elements; for instance silicon, chromium,
tantalum, titanium, and combinations thereof.
6. The downhole apparatus of claim 1 selected from subsurface
safety valves, packers, connectors, submersible pump components,
mandrels and components thereof, sensors, blow out preventer
components, bottom hole assemblies (BHA) or components thereof,
sucker rods, drill string components, valve components, power
cables, fiber optic connections and other tools, pressure sealing
elements for fluids, and sand-control equipments.
7. The downhole apparatus of claim 1 selected from: valves with
internal passageways, wherein the valve is selected from safety
valves, formation isolation valves, check valves, circulation
valves, gas lift valves, and frac valves; hydraulic chamber bores
and hydraulic piston bores; flow tube internal surfaces; internal
passageways of completion tools; seal bore assemblies; joints;
internal surfaces of pumps; bearings in powerdrive tools and
drilling tools; control line sections; threads and seal surfaces;
external surfaces of internal tubing, collets and like components;
nipples; plugs; pressure setting tools; locks; standing valves;
shock absorbers; packoffs; control-line protectors; polished bore
receptacles; unions; subs; sleeves; and on-off attachments.
8. A downhole apparatus comprising at least one component
comprising an internal surface comprising a base metal or alloy
having a DLC coating thereon, the DLC coating present at least on
some of the internal surface of the base metal or alloy to be
exposed to an downhole environment, the DLC coating derived from
PVD, CVD, or an enhanced-plasma CVD process such as the hollow
cathode plasma ion immersion process, the apparatus selected from
subsurface safety valves, packers, connectors, submersible pump
components, mandrels and components thereof, sensors, blow out
preventer components, bottom hole assemblies (BHA) or components
thereof, sucker rods, drill string components, power cables, fiber
optic connections and other tools, pressure sealing elements for
fluids, screens, valves having components defining internal
passageways, wherein the valve is selected from safety valves,
formation isolation valves, check valves, circulation valves, gas
lift valves, and frac valves; hydraulic chamber bores and hydraulic
piston bores; flow tube internal surfaces; internal passageways of
completion tools; seal bore assemblies; joints; internal surfaces
of pumps; bearings in powerdrive tools and drilling tools; control
line sections; threads and seal surfaces; external surfaces of
internal tubing, collets and like components; nipples; plugs;
pressure setting tools; locks; standing valves; shock absorbers;
packoffs; control-line protectors; polished bore receptacles;
unions; subs; sleeves; and on-off attachments.
9. The downhole apparatus of claim 8 comprising one or more
intermediate metallic layers between the base metal or alloy and
the DLC coating, wherein the intermediate layer comprises in
particular selected from transition-metals and/or carbide-forming
elements; for instance silicon, chromium, tantalum, titanium, and
combinations thereof.
10. A downhole apparatus comprising a hydraulic chamber, the
hydraulic chamber having an internal surface defined by a base
metal or alloy, at least some of the internal surface having a DLC
coating thereon, the DLC coating derived from PVD, CVD, or an
enhanced-plasma CVD process such as the hollow cathode plasma ion
immersion process.
11. A downhole flow control apparatus comprising at least one
internal passageway, this internal passageway having an internal
surface defined by a base metal or alloy, at least some of the
internal surface having a DLC coating thereon, the DLC coating
derived PVD, CVD, or an enhanced-plasma CVD process such as the
hollow cathode plasma ion immersion process.
12. A downhole pump apparatus comprising at least one component
having an internal passageway having an internal surface defined by
a base metal or alloy, at least some of the internal surface having
a DLC coating thereon, the DLC coating derived from PVD, CVD, or an
enhanced-plasma CVD process such as the hollow cathode plasma ion
immersion process.
13. A method comprising: (a) selecting a downhole apparatus
comprising a base metal or alloy having a DLC coating thereon
produced from PVD, CVD, or an enhanced-plasma CVD process such as
the hollow cathode plasma ion immersion process, the DLC coating
present at least on one or more internal passageways of the base
metal or alloy to be exposed to downhole environments, the
apparatus selected from downhole tools having one or more of the
following functions: control, change, isolate, restrict, and/or
monitor flow of, or transfer heat and/or momentum to or from, a
fluid, solids, or combinations of fluid and solids; and (b)
deploying and using the downhole apparatus downhole during a
downhole operation.
14. The method of claim 13 wherein the downhole operation is
selected from completion operations, pumping, circulating,
acidizing, fracturing, flow diverting and combinations thereof.
15. The method of claim 14 wherein the downhole operation is a
completion operation, and the downhole apparatus is selected from
one or more of packers, connectors, submersible pump components,
mandrels and components thereof, sensors, blow out preventer
components, bottom hole assemblies (BHA) or components thereof,
sucker rods, drill string components, power cables, communication
wires and cables, bulkheads such as those used in fiber optic
connections and other tools, pressure sealing elements for fluids,
screens, valves having components defining internal passageways,
wherein the valve is selected from safety valves, formation
isolation valves, check valves, circulation valves, gas lift
valves, and frac valves; hydraulic chamber bores and hydraulic
piston bores; flow tube internal surfaces; internal passageways of
completion tools; seal bore assemblies; joints; internal surfaces
of pumps; bearings in powerdrive tools and drilling tools; control
line sections; threads and seal surfaces; external surfaces of
internal tubing, collets and like components; nipples; plugs;
pressure setting tools; locks; standing valves; shock absorbers;
packoffs; control-line protectors; polished bore receptacles;
unions; subs; sleeves; and on-off attachments.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This claims the benefit of the following patent
applications: U.S. Ser. No. 11/612,088, entitled "INTERSTITIALLY
STRENGTHENED HIGH CARBON AND HIGH NITROGEN AUSTENITIC ALLOYS,
OILFIELD APPARATUS COMPRISING SAME, AND METHODS OF MAKING AND USING
SAME," filed Dec. 18, 2006.
BACKGROUND OF THE INVENTION
[0002] 1. Field of Invention
[0003] The present invention relates generally to the field of
coating materials useful for applications where corrosion and wear
are important to overcome, as found in oilfield exploration,
production, and testing, and more specifically to downhole oilfield
apparatus comprising one or more internal surfaces or passageways
with a diamond-like coating (DLC) finish.
[0004] 2. Related Art
[0005] Diamond-like coatings are known for various purposes. U.S.
Pat. Nos. 7,052,736 and 6,764,714 (Wei, et al.) disclose methods
for coating an interior surface of ferromagnetic and
non-ferromagnetic tubular structures with such coatings using
gaseous bonding precursors. Suitable silicon-containing gaseous
bonding precursors include silanes, trimethyl silanes, and the
like. Other suitable gaseous bonding precursors disclosed include
CH.sub.4, C.sub.2H.sub.2, N.sub.2 or Cr(CO).sub.6. The patents note
that when combinations of SiH.sub.4, CH.sub.4, C.sub.2H.sub.2,
N.sub.2 or Cr(CO).sub.6 are introduced, a coating containing
silicon, silicon nitrides, silicon carbides, diamond-like carbon
(DLC) and carbonitrides can be obtained. If a hydrocarbon gas is
used, such as CH.sub.4 or C.sub.2H.sub.2, an amorphous carbon film
forms. If an organometallic gas is used (such as Cr-, Al-,
Ti-containing precursors), a metallic or ceramic coating is
deposited. The term "amorphous carbon" is accepted in the art and
refers to a carbonaceous coating composed of a mixture of sp.sup.2
and sp.sup.3 hybridized carbon. sp.sup.2 carbon refers to double
bonded carbon commonly associated with graphite. sp.sup.3
hybridized carbon refers to single bonded carbon.
[0006] U.S. Pat. No. 6,450,271 (Tibbitts, et al.) discloses a
rotary-type drill bit for drilling subterranean formations having
areas or components having surfaces exhibiting a relatively low
adhesion, preferably nonwater-wettable (non-wettable by water),
over at least a portion thereof. Superabrasive materials such as
diamond, polycrystalline diamond, diamond-like-carbon (DLC),
nanocrystalline carbon, amorphous carbon and related
vapor-deposited (e.g., plasma vapor deposition or chemical vapor
deposition) carbon-based coatings such as carbon nitride and boron
nitride can be applied to large surface areas at temperatures (as
low as less than 300.degree. F.) below that which would affect the
metallurgical integrity of the bit material being coated. The
vapor-deposited, carbon-based coatings preferably achieve a
hardness of at least 3000 Vickers, provide a sliding coefficient of
friction of 0.2 or less, and are not wetted by water.
[0007] U.S. Pat. No. 5,831,743 (Ramos, et al.) discloses optical
probes for use downhole. After an oil well has been drilled, lined
and cased, and is producing, it may be desirable in situ (either at
the wellhead or downhole) to measure, and log record), the rate at
which fluid, and its several distinct components, is flowing out of
the geological formations through which the bore has been drilled
and is passing into and up the casing. A useful type of detector
system for this purpose is an optical probe, and the patent
describes a design of probe which has a doubly-angled tip, there
being measured the light totally internally reflected at the
interface, which depends on the ratio of the refractive indices of
the probe tip and fluid component in which it is immersed. The
exposed tip of each probe is protected from the fluid under test by
providing a hard, protective layer or coating on the tip, which
must not upset the optics of the probe--it should preferably be:
amorphous, so facilitating the formation of an optically flat
coating; adequately transparent at the probe's operating
wavelength; such that it may be deposited with controllable
thickness, and of a refractive index greater than that of the
probe's fiber optic (and than that of any likely fluid component),
so as not itself to cause total internal reflection of probe light.
Suitable materials are diamond (as polycrystalline diamond) and a
number of diamond-like substances, such as DLC, which is also known
as Amorphous Partially Hydrogenated Carbon (or a-C:H). DLC is
transparent in the infra-red region, has a refractive index around
2.2, and provides a smooth amorphous hydrophobic coating
finish.
[0008] U.S. Pat. No. 6,881,475 (Ohtani, et al.) discloses cutting
tools comprising a tungsten carbide (WC) base formed of a hard
phase with WC as the main component, and a bonded phase with a
transition metal such as cobalt as the main component. An amorphous
carbon film is applied to the base, and may include films such as a
hard carbon film, diamond-like carbon film, DLC film, or a-C:H,
i-carbon film. The tools are described as suitable for working on
aluminum and alloys thereof, and other non-ferrous materials such
as titanium, magnesium or copper. The tools are described as
effective for cutting a variety of materials and may be used for
ferrous alloys such as stainless steels in addition to non-ferrous
materials by virtue of the high hardness of the amorphous carbon
film.
[0009] The disclosures of all documents referred to herein are
expressly incorporated by reference herein in their entireties. As
may be seen, oilfield prior art has been restricted to uses of DLC
and similar carbon coatings in drill bits, specialty optical
sensors, and fluid-conveying-only tubes. There has not been
disclosure of their use in any sort of downhole tool used to
control, change, isolate, restrict, and/or monitor flow of a fluid,
solids, or transfer heat and/or momentum to fluids and/or solids.
Many downhole oilfield tools, such as safety valves, flow control
valves, packers, connectors, submersible pump components (for
example pump housings, shafts, impellers, and diffusers), mandrels
and components thereof, sand controls (screens), non-optical
sensors, blow out preventer components, bottom hole assemblies
(BHA) or components thereof, sucker rods, O-rings, T-rings,
gaskets, tube seals, valves and valve components, power cables,
communication wires and cables, bulkheads such as those used in
fiber optic connections and other downhole tools, pressure sealing
elements for fluids (gas, liquid, or combinations thereof), and the
like may be exposed during use to wide ranges of temperatures,
pressures, and environments; e.g. sour, brine, or seawater
environments for citing only a few examples. Many are also exposed
to very corrosive fluids comprising any number of abrasive elements
in a variety of sizes, for instance sand particles and metallic
debris from other downhole components. Therefore it would be of
considerable advantage to have available downhole oilfield tools of
this nature having DLC or other amorphous carbon-based coatings,
especially on their surfaces exposed to such aggressive
environments (these surfaces are typically internal surfaces and
passageways), so that they may have a high corrosion resistance
(including resistance to stress-corrosion and sulfide-stress
cracking, microbiological corrosion, etc), a high bond strength
(adhesion), high mechanical properties (e.g. static and dynamic
strength, resistance toward compressive loads, high fatigue
strength, etc) along with an ultra-low friction coefficient, as
needed in particular in the presence of sealing apparatus (e.g. a
piston moving in an internally coated borehole).
SUMMARY OF THE INVENTION
[0010] In accordance with the present invention, apparatus and
downhole methods of use thereof are described, the apparatus
comprising a base metal or alloy having a diamond-like carbon (DLC)
coating thereon comprising amorphous and/or crystalline carbon
produced by a process such as physical vapor deposition (PVD), and
CVD-like processes, including a process known as the hollow cathode
plasma ion immersion process and disclosed by SubOne Technology
(www.sub-one.com), the coating presents at least on some of
internal surfaces of the base metal or alloy to be exposed to
downhole environments, the apparatus selected from downhole
equipments having one or more of the following functions: control,
change, isolate, restrict, and/or monitor flow of, or transfer heat
and/or momentum to or from, a fluid, solids, or combinations of
fluid and solids. Apparatus of the invention typically operate in
aggressive environments, in which many metallic materials suffer
from corrosion and wear damages.
[0011] Exemplary apparatus of the invention may be termed
"completion accessories", "completion tools", or more generally
"well completions." The terms are used interchangeably herein. As
used in the industry, "completion accessory" product lines may be
further characterized as comprising tubing-mounted equipment and
flow control equipment, both of which may be used to customize well
completions. A general list might include, but is not limited to:
nipples, plugs, pressure settings tools, locks, standing valves,
shock absorbers, packoffs, protectors, joints (expansion, slip, and
safety), polished bore receptacles, unions, subs, sleeves, and
on-off attachments. A more specific list of tubing-mounted
equipment might include, but is not limited to, safety valves,
sliding sleeves, landing nipples, expansion joints, pumpout subs,
and other specialized items that are included in most tubing
strings for production or injection operations in the oil and gas
industry. Flow-control equipment comprises equipment that is
deployed inside the tubing string with standard slickline methods.
A list might include, but is not limited to locks, blanking plugs,
equalizing standing valves, circulating plugs, and other
specialized equipment. These tools are used to control flow into or
from the reservoir.
[0012] The base metal or alloy in apparatus of the invention may be
selected from ferrous and non-ferrous metals and alloys, and may be
non-magnetic, partially magnetic, or fully magnetic. Suitable
ferrous materials include the known and foreseeable various carbon
steels and stainless steels. Suitable non-ferrous metals include
nickel and titanium as examples and alloys thereof. Apparatus of
the invention may include coated ferrous components and coated
non-ferrous components, as well as non-coated metallic and
non-coated non-metallic components.
[0013] DLC coatings are typically inert carbon films with various
ratios of amorphous to crystalline carbon or carbon phases that
give them attractive properties for downhole applications such as
high resistance against contact loads and impacts (wear, abrasion),
high chemical resistance (inertness), good cohesion and adhesion to
materials frequently used in downhole tools (e.g. carbon steels,
stainless steels, nickel alloys), as well as low friction
coefficients (anti-stick properties) due to an extremely slick
surface finish. DLC coatings may be deposited through a variety of
techniques. Prior art includes many methods for the deposition of
DLC coatings from a variety of carbonaceous precursor materials
through a variety of processes, including: direct ion beam
deposition, pulsed laser ablation, filtered cathodic arc
deposition, ion beam conversion of condensed precursor, magnetron
sputtering, RF plasma-activated chemical vapor deposition, plasma
source ion implantation and deposition, and all sort of hybrid and
plasma enhanced CVD processes, including the plasma ion immersion
process for SubOne Technology (www.sub-one.com). Using the hollow
cathode plasma ion immersion process, they may be grown onto "cold"
metallic materials (at temperatures less than about 300.degree. C.
(570.degree. F.)) at reasonably fast rates and potentially over
long distances and areas (e.g. for well completions). The family of
DLC films covers a wide range of structures and compositions, thus
properties. These properties of DLC are controlled by
sp.sup.3/sp.sup.2 ratios (i.e. diamond/graphite structure ratios),
process gases (hydrogen, methane, ethane, siloxane, etc), hydrogen
content, interface design (layering), and deposition process.
[0014] Certain apparatus embodiments of the invention comprise one
or more intermediate metal layers between the base metal and the
DLC coating. One or more of these intermediate layers may be
selected from carbide-forming elements such as silicon, chromium,
tantalum, or other transition-metals.
[0015] In addition to the completion tools cited earlier, apparatus
within the invention include, but are not limited to packers,
connectors, submersible pump components (for example pump housings,
shafts, impellers, diffusers), mandrels and components thereof,
sensors, blow out preventer components, bottom hole assemblies
(BHA) or components thereof, sucker rods, drill string components,
tube seals, valve components, power cables, communication wires and
cables, bulkheads such as those used in fiber optic connections and
other tools, pressure sealing elements for fluids (gas, liquid, or
combinations thereof), sand controls (screens), sampling bottles,
HPHT dynamic seals, mud motor stators (e.g., of helical form and
metallic), SCAR family tools, pressure compensating sleeves, and
the like. Apparatus within the invention include those having one
or more of the follow features coated with a diamond-like coating:
components defining internal passageways of valves (for example
safety valves, formation isolation valves, check valves,
circulation valves, gas Lift valves, frac valves, and the like);
walls defining hydraulic chamber bores, hydraulic piston bores,
flow tube internal surfaces; components defining internal
passageways of completion tools (e.g. tubing-mounted equipment and
flow control equipment); seal bore assemblies; joints (expansion,
slip, and safety joints, for example); components defining internal
passageways and surfaces of low accessibility of pumps (housings,
impellers, diffusers, stages, and the like), for example as found
in submersible pumps, frac pumps, and the like; bearings in power
drive tools, drilling tools; control line sections; threads and
seal surfaces; external surfaces of internal tubing, collets and
like components (the surface will then be considered internal, and
a sub-element of a combination element; typically the surface is
then part of a component defining an internal passageway).
[0016] Certain apparatus embodiments may include low accessibility
portions. As used herein the term "low accessibility" means
internal surfaces of partially hollow or fully hollow downhole tool
components, as well as surface pits or crevices, or the roots of
threads.
[0017] Another major aspect of the invention includes methods of
using an apparatus of the invention in performing a defined task
downhole, one method comprising: [0018] (a) selecting an apparatus
of the invention according to a downhole operation to be performed;
and [0019] (b) deploying the apparatus during the downhole
operation.
[0020] Methods of the invention may include, but are not limited
to, those wherein the downhole operation is selected from various
completion operations, such as circulation, cleanout, pumpout, and
the like; acidizing, fracturing, flow diverting and other
operations. The environmental conditions of the wellbore during
running and retrieving of the apparatus may be the same or
different from the environmental conditions during use of the
apparatus downhole. Methods of the invention include those
comprising using a first apparatus of the invention to perform a
first task downhole, and a second apparatus of the invention to
perform a second task downhole. For example, a first packer
apparatus of the invention may be employed to block the wellbore
below a wellbore zone to be treated, followed by a second packer
apparatus of the invention positioned above the wellbore zone to be
treated.
[0021] The various aspects of the invention will become more
apparent upon review of the brief description of the drawings, the
detailed description of the invention, and the claims that
follow.
BRIEF DESCRIPTION OF THE DRAWINGS
[0022] The manner in which the objectives of the invention and
other desirable characteristics can be obtained is explained in the
following description and attached drawings in which:
[0023] FIGS. 1-8 are schematic cross-sectional views of apparatus
embodiments of the invention; and
[0024] FIGS. 9-11 are test samples of coated base materials.
[0025] It is to be noted, however, that the appended drawings are
highly schematic, not necessarily to scale, and illustrate only
typical embodiments of this invention, and are therefore not to be
considered limiting of its scope, for the invention may admit to
other equally effective embodiments.
DETAILED DESCRIPTION
[0026] In the following description, numerous details are set forth
to provide an understanding of the present invention. However, it
will be understood by those skilled in the art that the present
invention may be practiced without these details and that numerous
variations or modifications from the described embodiments may be
possible.
[0027] All phrases, derivations, collocations and multiword
expressions used herein, in particular in the claims that follow,
are expressly not limited to nouns and verbs. It is apparent that
meanings are not just expressed by nouns and verbs or single words.
Languages use a variety of ways to express content. The existence
of inventive concepts and the ways in which these are expressed
varies in language-cultures. For example, many lexicalized
compounds in Germanic languages are often expressed as
adjective-noun combinations, noun-preposition-noun combinations or
derivations in Romanic languages The possibility to include
phrases, derivations and collocations in the claims is essential
for high-quality patents, making it possible to reduce expressions
to their conceptual content, and all possible conceptual
combinations of words that are compatible with such content (either
within a language or across languages) are intended to be included
in the used phrases.
[0028] The invention describes shaped articles of manufacture
(apparatus) employing a base metal or alloy having a DLC coating
thereon comprising amorphous carbon, and methods of using the
apparatus in a downhole operation.
[0029] A "downhole apparatus" as used herein is an apparatus that
is utilized downhole in a downhole operation in a downhole
environment. A "well completion" apparatus is any apparatus used to
enable safe and efficient production from an oil or gas well. An
example is a subsurface safety valve (SSSV), a safety device
installed in the upper wellbore to provide emergency closure of the
producing conduits in the event of an emergency. Two types of
subsurface safety valve are available: surface-controlled and
subsurface controlled. In each case, the safety-valve system is
designed to be fail-safe, so that the wellbore is isolated in the
event of any system failure or damage to the surface
production-control facilities. A surface-controlled subsurface
safety valve (SCSSV), is a downhole safety valve that is operated
from surface facilities through a control line strapped to the
external surface of the production tubing. Two basic types of SCSSV
are common: wireline retrievable, whereby the principal
safety-valve components can be run and retrieved on slickline, and
tubing retrievable, in which the entire safety-valve assembly is
installed with the tubing string. The control system operates in a
fail-safe mode, with hydraulic control pressure used to hold open a
ball or flapper assembly that will close if the control pressure is
lost. A subsurface surface-controlled safety valve (SSCSV) is also
a downhole safety valve designed to close automatically in an
emergency situation. There are two basic operating mechanisms:
valves operated by an increase in fluid flow and valves operated by
a decrease in ambient pressure. Given the difficulties in testing
or confirming the efficiency of these valves, surface-controlled
safety valves are much more common.
[0030] As mentioned in the Summary of the Invention, exemplary
apparatus of the invention are completion accessories, including
tubing-mounted equipment and flow control equipment, both of which
may be used to customize well completions. Tubing-mounted equipment
includes, but is not limited to, sliding sleeves, landing nipples,
expansion joints, pumpout subs, and other specialized items that
are included in most tubing strings for production or injection
operations in the oil and gas industry. Flow-control comprises
equipment that is deployed inside the tubing string with standard
slickline methods. This includes locks, blanking plugs, equalizing
standing valves, circulating plugs, gas lift valves, and other
specialized equipment. These tools are used to control flow into or
from the reservoir. A non-exhaustive list of completion accessories
which may have a surface or surfaces exposed to downhole conditions
during their use, and which surfaces may have an amorphous carbon
coating, such as a DLC coating, may also include flow control
equipment (locks, blanking plugs and standing valves), tubing
mounted completion accessories (protectors, nipples, expansion
joints, adjustable unions, temporary tubing plugs, sliding sleeves,
safety joints, chemical injection nipples, On-Off attachments,
tubular accessories).
[0031] Downhole operations include, but are not limited to, well
pressure control, completion operations (which may range from
nothing but a packer on tubing above an openhole completion
("barefoot" completion), to a system of mechanical filtering
elements outside of perforated pipe, to a fully automated
measurement and control system that optimizes reservoir economics
without human intervention (an "intelligent" completion), well
stimulation operations, such as hydraulic fracturing, acidizing,
acid fracturing, fracture acidizing, fluid diversion or any other
downhole well activity, whether or not performed to restore or
enhance the productivity of a well.
[0032] Coatings suitable for use in the invention include DLC
coatings and other amorphous coatings comprising carbon. Though
"diamond-like", DLC coatings do not resemble crystalline diamond;
DLC coatings have a graphite-like color (black), they are not as
hard as diamond and they are mainly amorphous. Hydrogen, like other
additives such as nitrogen, silicon, sulfur, tungsten, titanium,
silver, and the like, are frequently used to control the mechanical
and tribological behavior of DLC coatings. Like diamond, DLC
coatings are chemically inert and are unmatched to protect
engineering materials against environmental degradations (e.g.
corrosion, wear, galling, etc.). Engineering materials to receive
DLC coatings that are primary interests include carbon and low
alloy steels, stainless steels, nickel-based alloys, titanium
alloys, and the like. DLC coatings of particular interest for use
as coatings for downhole apparatus (apparatus) of the invention may
have the following properties:
[0033] Hardness (Vickers)>1000 (in certain embodiments up to
3000);
[0034] Extreme smoothness and lubricity (i.e. a surface of low
friction coefficient with practically no cracks);
[0035] Thickness>5 .mu.m, in certain embodiments 25 .mu.m or
more;
[0036] High adhesion to metals typically used in oilfield
applications (to increase adhesion the coating may be applied with
pre-deposition of an interlayer and/or a chemical or mechanical
surface pretreatment (peening for instance); the interlayer may be
a functionally graded material, i.e. a material that itself is made
of layers of various chemical compositions and structures, for
instance to provide a high adhesion of the DLC coating on its
substrate and accommodate the difference in physical properties
between DLC and substrate.
[0037] Chemical resistance in oilfield environments (for example
comprising pH ranging from 0 to 14);
[0038] High resistance to thermal and mechanical loads (shocks,
vibrations);
[0039] Deposition temperatures such the base metal materials have
their bulk properties (i.e. away from surfaces) substantially
unaffected by the DLC coating process (i.e. no tempering,
softening, and the like); and
[0040] Inexpensive in Raw Materials (e.g. Carbon)
[0041] The previous characteristics may be achieved using a variety
of techniques. The prior art includes many methods for the
deposition of DLC coatings from a variety of carbonaceous precursor
materials through a variety of processes, including: direct ion
beam deposition, pulsed laser ablation, filtered cathodic arc
deposition, ion beam conversion of condensed precursor, magnetron
sputtering, RF plasma-activated chemical vapor deposition, plasma
source ion implantation and deposition, and all sort of hybrid
plasma-enhanced CVD processes. All of these processes are
well-known in the art and require little explanation here. U.S.
Pat. Nos. 7,052,736 and 6,764,714 (Wei, et al.), previously
incorporated herein by reference, disclose methods for coating an
interior surface of ferromagnetic and non-ferromagnetic tubular
structures with an amorphous carbon film when a hydrocarbon gas is
used, such as CH.sub.4 or C.sub.2H.sub.2. Suitable
silicon-containing gaseous bonding precursors include silanes,
trimethyl silanes, and the like, and other suitable gaseous bonding
precursors such as N.sub.2 or Cr(CO).sub.6 may be used. The patents
note that when combinations of SiH.sub.4, CH.sub.4, C.sub.2H.sub.2,
N.sub.2 or Cr(CO).sub.6 are introduced, a coating containing
silicon, silicon nitrides, silicon carbides, diamond-like carbon
(DLC) and carbonitrides may be obtained. By limiting SiH.sub.4,
N.sub.2 and Cr(CO).sub.6, a coating comprising a major amount of
DLC may be formed.
[0042] The previous characteristics may also be achieved using the
hollow cathode plasma ion immersion process (HCPIIP), as described
and marketed under the trade designation "Sub-One" by Sub-One
Technology, Pleasanton, Calif. (www.Sub-one.com). This process is
capable of applying high-performance coatings-extremely smooth,
hard, pure films--on the interior surfaces of parts exposed to
downhole conditions. DLC coatings are foreseen especially for
internal surfaces of downhole apparatus (but not exclusively) to
prevent all forms of corrosion (including stress-corrosion
cracking, sulfide stress cracking) and damages from external forces
(wear, erosion, etc) at oilfield temperatures and pressures. A
critical part of this invention is therefore the application of DLC
coatings to downhole apparatus with no restrictions on the internal
diameters and lengths; therefore, all parts, components, and the
like that define passageways of downhole apparatus may benefit from
an amorphous carbon coating, such as DLC coatings, and are
therefore considered within the invention. The processes and means
to achieve these coatings are not part of this invention, the
HCPIIP process and variants thereof being useful to produce the
coatings. Downhole apparatus or components thereof covered by this
invention include, but are not limited to:
[0043] Components defining internal passageways of downhole valves
(standing valves, safety valves, formation isolation valves, check
valves, circulation valves, gas lift valves, frac valves,
completion accessories, and the like);
[0044] Walls defining hydraulic chamber bores, hydraulic piston
bores, flow tube internal surfaces, and the like;
[0045] Components defining internal passageways of well
completions;
[0046] Seal bore assemblies;
[0047] Joints (including expansion, slip, and safety joints);
[0048] Components defining internal passageways of pumps (housing,
impellers, diffusers, stages, and the like; e.g. found in
electrical submersible pumps, frac pumps, and the like.
[0049] Bearings in powerdrive tools, drilling tools;
[0050] Control line sections used downhole;
[0051] All threads and seal surfaces used downhole;
[0052] External surfaces of internal tubing, collets and like
components (the surface will then be considered internal, and a
sub-element of a combination element; typically the surface is then
part of an internal passageway).
[0053] In addition to protecting surfaces from corrosive and
damaging environments, the use of amorphous carbon coatings such as
DLC non-stick surfaces may minimize scale problems in well
completions, for example in safety valves, thus providing a safer
work environment.
[0054] Base materials may be either ferrous or non-ferrous metals.
Of particular interest to well completions are carbon steels (e.g.
4130, 4140), stainless steels (e.g. 410, 420, 9 Cr-1 Mo), titanium
alloys (e.g. Ti-6 Al-4V), nickel alloys (e.g. 825, 925, 718, 725),
and cobalt alloys (e.g. MP35N).
[0055] FIGS. 1-8 illustrate examples of downhole apparatus of the
invention that may comprise several components, any or all of which
may comprise a DLC-coated surface. FIG. 1 illustrates a subsurface
safety valve 10 having a DLC coating 12 on a flow tube inner
surface. A threaded portion 14 is also coated with a DLC coating,
near a flap 16. A fail safe spring 18 is illustrated, as well as a
hydraulic piston bore 20 having a DLC coating 22 thereon. Also
illustrated is a bore of a hydraulic chamber housing 24, which may
also have a DLC coating.
[0056] FIGS. 2A, 2B, and 2C are schematic cross-sectional views of
a flow reversing valve of the invention in different modes of
operation. Any and all of the parts of the reversing valve may have
a DLC coating thereon, and may have one or more intermediate
layers, such as chrome, between the base metal and the DLC coating.
Illustrated are coiled tubing wall 32, an engineered section 32a of
coiled tubing wall 32, and a hydraulic system installed in
engineered section 32a. Engineered section 32a may either be formed
in the coiled tubing wall itself during fabrication of the coiled
tubing, or comprise a piece retrofitted into coiled tubing 32. An
opening 36 in CT wall 32 allows fluid communication with the
annulus formed between wall 32 and the inside diameter of a well
bore or well casing (not shown). FIG. 2A depicts the normal flow
mode, where fluid traverses through CT opening at 30, in the
direction of the arrow, through an opening 38 and channel in an
upper dart valve member 41, past dart 40, through a sleeve 54, and
finally past a flapper 76 of a flapper-style check valve.
[0057] Because of the nature of dart valve 40, a minimum pressure
differential is necessary in order to flow across the valve. This
pressure differential charges the hydraulic system by creating a
high pressure zone 42 above the valve and a low pressure zone
below. Note that the differential pressure that charges the
hydraulic system need not be limited to that created by flowing
across the dart valve and can be increased, for example, by adding
a flow restriction (such as an orifice) below the dart valve. The
pressure differential begins to move compensating piston 50 to
allow oil to flow above and shift dart valve 40 and flapper check
valve. Also, the differential begins to move pressure lock piston
62 to its locked position. As the flow rate increases, as shown in
FIG. 2B, pressure lock piston 62 continues to move down until the
piston lands on a seat that prevents further movement. Just before
pressure lock piston 62 seats, a seal takes place that prevents
flow of oil around the piston. Additional oil flow due to added
flow rate and greater pressure drop will now occur across the
hydraulic check valve, 46/48. If flow stops after pressure lock
piston 62 seats, pressure lock piston 62 will stay seated and
hydraulic check valve 46/48 will prevent the charged oil from
returning to compensation chamber 52. Consequently, the closed
volume of oil in high pressure chamber 42, a passage 45, and
annular chamber 47 above the dart valve will force it in the down
position, which also forces the flapper check valve 76 open with a
push sleeve 54. Once the system is charged and the pressure locked,
flow can take place in both directions (as indicated by the
double-headed arrow in FIG. 2C) across the flapper check valve and
dart valve. When reverse circulation is completed, solenoid 44 is
actuated to move ball 46 of the hydraulic check valve off its seat.
In doing so, stored pressure in high pressure chamber 42 is
released. The system returns to its original position, and flapper
check valve 76 and dart 40 are returned to their normal position
that prevents uphole flow.
[0058] FIG. 3 is a schematic side elevation view, partially in
cross-section, and not necessarily to scale, of a downhole
submersible pump 300 in accordance with the invention. Any and all
of the parts of downhole submersible pump 300 may have a DLC
coating thereon, and may have one or more intermediate layers, such
as chrome, between the base metal or alloy and the DLC coating.
Pump 300 includes two different pump stages indicated by dashed
line boxes 301 and 302 and connected through a connector 303. Also
illustrated is a pump housing 304 which houses pump stages 301 and
302. Pump intake 305 allows well or reservoir fluids to enter pump
300. A first set of impellers 306 and diffusers 307 move fluid
through stage 302 as depicted by curved line 308 (upwards in FIG.
3, although the invention is not so limited) toward second stage
301, having a different set of impellers 306' and diffusers 307',
eventually forcing fluid out through a discharge 309. Impellers 306
and 306' are all removably fastened to a pump shaft 310, which is
powered by one or more motors (not illustrated). In certain
embodiments, the stage producing the higher flow rate may be
positioned on the "bottom", in this case stage 302, although the
invention is not so limited. Sealing rings (not illustrated) may be
installed in stages directly below connector 303. Bearing housings
may be placed at the first stage below the top or last diffuser in
stage 302. The bearing housing location may increase one stage for
each housing length required. The top-most diffuser (nearest the
pump discharge) may have its male nest removed.
[0059] FIG. 4 is a schematic side elevation view, partially in
cross-section, of an embodiment of an oilfield tool component that
may comprise one or more DLC-coated components in accordance with
the invention. FIG. 4 illustrates an oilfield tool component 190
known under the trade designation A-2 Equalizing Standing Valve,
available from Schlumberger, modified in accordance with the
invention to include at least one amorphous carbon coated surface,
for example surfaces 191, 193, and 195. These valves include a
slickline-retrievable connection 192, a ball-and-seat-type check
valve 194 with integral running 196 and pulling 198 necks, and are
designed to hold pressure only from above. The equalizing standing
valve 190 may be used in intermittent gas lift wells to contain
fluid in the tubing string during an injection cycle. They may also
be used to set packers and test a tubing string. An appropriate
pulling tool and attached standing valve may be lowered into the
tubing until the assembly shoulders against the packing bore of the
nipple. The valve packing seals in the polished section. Downward
jarring releases the pulling tool for retrieval to the surface.
When removing the equalizing standing valve, upward jarring with
the appropriate pulling tool equalizes and removes the assembly,
and when the valve 190 approaches the well pressure control
components at the surface, magnets (not illustrated) may allow one
or more magnetic field sensors (not illustrated) to sense the
location of the magnets, and lessen the risk that the valve will
hit the inside top of the lubricator. This may reduce the risk that
the valve will be disconnected and possibly drop back into the well
bore.
[0060] FIG. 5 is a schematic side elevation view, partially in
cross-section, illustrating a sliding sleeve packoff assembly 500,
components of which incorporate a DLC coating in accordance with
the teachings of the invention. Sliding sleeve packoffs are
designed to be attached to a lock type that matches the integral
landing nipple in the sliding sleeve. When production from an upper
zone is not desired and the sliding sleeve leaks fluid between the
tubing and casing annulus when closed, a packoff is used to isolate
this zone. Packoff assemblies are used to isolate the sliding
sleeve ports and prevent migration of fluids between the tubing and
casing annulus, as well as to provide a path for flow of production
fluids to the surface. In operation, a running tool and pulling
tool appropriate for the attached lock 502 are used to install and
retrieve the sliding sleeve packoff assembly. Lock 502 attached to
the packoff anchors and seals in a tubing mounted sliding sleeve
504. The lock packing seals in an upper nipple bore 506 of sleeve
504, and packing 508 located on the lower end of the packoff seals
in the bottom polished bore 510 in the sliding sleeve. The
simplicity of the packoff design assures ease of setting and
unsetting of lock 502 and packoff assembly by standard slickline
methods. Downward jarring sets lock 502, and upward jarring
releases lock 502 from sliding sleeve 504 to allow retrieval of the
packoff assembly. The packoff is run into position on the
appropriate running tool by standard slickline methods and is
locked into upper nipple 506 integral to sliding sleeve 504. The
packoff allows restricted flow up the production tubing and
completely seals off the ported area in sliding sleeve 504. Lock
502 is released by upward jarring using the appropriate pulling
tool. Continued upward pulling removes the packoff assembly from
the bore of sliding sleeve 504, allowing it to be removed from the
well.
[0061] FIG. 6 is a schematic side elevation view, partially in
cross-section, illustrating a sliding sleeve 600 known under the
trade designation "CS-1-Series", available from Schlumberger,
modified in accordance with the invention to incorporate a DLC
coating on one or more components thereof. Sliding sleeves are used
to establish communication between the tubing string and the casing
annulus for single- or multiple-tubing string completions. Other
applications include equalizing pressure between an isolated
formation and the tubing string, spot acidizing and fracturing,
killing a well, and directing the flow from the casing to the
tubing in alternate or selective completions. As an option,
sizeable chokes can be installed on the sliding sleeve to adjust
the flow rate through the openings 602 and 602' (FIGS. 6A and 6B,
respectively) to the tubing annulus. The sliding sleeve components
may be manufactured from stainless steel or nickel alloys, modified
to comprise an amorphous carbon coating in accordance with the
invention. These sliding sleeves feature primary and secondary
seals (603 and 604) to reduce the possibility of total seal
failure, and equalizing slots 606 in the inner sleeve permit
gradual equalization between the tubing and casing annulus. Sliding
sleeves may be opened or closed using a shifting tool and standard
wireline and coiled tubing methods. The sliding sleeve known under
the trade designation CS-1U shifts up to open and down to close,
and the sliding sleeve known under the trade designation CS-1D
shifts down to open and up to close. The sliding sleeves may be
assembled to, and form part of, the tubing string, and generally
are available with separation tools and packoffs. Equalizing
pressure between the tubing and casing annulus is normally
accomplished by applying pressure or filling the tubing or casing
with fluid. Sliding sleeve 600 can also be opened even if
facilities for equalizing pressures beforehand are not available.
This requires careful monitoring of tubing and annulus pressures
while slowly opening the sleeve until equalization.
[0062] FIG. 7 is a schematic side elevation view, partially in
cross-section, illustrating an A-slip lock, 700, modified to
include a DLC coating in accordance with the invention. The A-slip
lock includes a slickline-retrievable anchor 702 with cup-type
seals 703, 704 used to lock and seal subsurface controls in tubing
strings that were installed without landing nipples. These slip
locks can be set at any depth in the tubing. The A-slip lock
comprises a fishing neck 705 that is attached to hardened slips 706
and mounted on a tapered body 707. A lower portion of tapered body
707 has cup-type seals 703, 704, energized by a pressure
differential from below the lock, to seal against the tubing wall.
The outer threads 706' on the lower end of slips 706 provide an
attachment point for subsurface control devices. During
installation, the A-slip lock and attached flow control device (not
illustrated) are made up to the appropriate A running tool and
lowered into the tubing using standard slickline methods. When the
desired depth is reached, a rapid upward pull on the slickline
moves tapered body 707 under slips 706. Upward jarring secures the
slip lock firmly against the tubing wall (not illustrated). Flowing
the well will energize cup-type seals 703, 704 against the tubing
wall. Before removing the A-slip lock, pressure must be equalized
across the lock assembly. Downward jarring with the appropriate
pulling tool drives tapered body 707 from beneath the slips. The
A-slip lock can then be slowly pulled from the well.
[0063] FIG. 8 is a schematic side elevation view, partially in
cross-section, illustrating a gravel pack 800 installed in a cased
well. Illustrated are production tubing 801, production casing 802,
a gravel pack packer 803, and a sump packer 806. A gravel pack
comprises sized particles 804 placed in between the sand face a
centralized screen, 805, which may have a DLC coating thereon in
accordance with the teachings of the invention. Gravel packs can be
used in both open holes, which may be under-reamed, and cased holes
and prevent sand from being produced through the pores between the
gravel particles. Gravel packing is the most widely used method of
controlling sand production. When properly designed and executed,
this method is highly effective for controlling sand, especially in
initial completions. In order to achieve long-term production in a
cased hole gravel pack, the gravel must be tightly packed in the
perforation tunnels and screen-casing annulus. However, the gravel
is erosive. Because of its low coefficient of friction, an a DLC
coating, will not only protect the tool surface but also enable the
sand to flow with less frictional resistance from the bore internal
surfaces.
[0064] Specific oilfield applications of the inventive apparatus
include well stimulation treatments. Stimulation treatments fall
into two main groups, hydraulic fracturing treatments and matrix
treatments. Fracturing treatments are performed above the fracture
pressure of the reservoir formation and create a highly conductive
flow path between the reservoir and the wellbore. Matrix treatments
are performed below the reservoir fracture pressure and generally
are designed to restore the natural permeability of the reservoir
following damage to the near-wellbore area.
[0065] Hydraulic fracturing, in the context of well workover and
intervention operations, is a stimulation treatment routinely
performed on oil and gas wells in low-permeability reservoirs.
Specially engineered fluids are pumped at high pressure and rate
into the reservoir interval to be treated, causing a vertical
fracture to open. The wings of the fracture extend away from the
wellbore in opposing directions according to the natural stresses
within the formation. Proppant, such as grains of sand of a
particular size, is mixed with the treatment fluid keep the
fracture open when the treatment is complete. Hydraulic fracturing
creates high-conductivity communication with a large area of
formation and bypasses any damage that may exist in the
near-wellbore area. Compositions of the invention may be used as
supplemental proppant materials.
[0066] In the context of well testing, hydraulic fracturing means
the process of injecting one or more fluids into a closed wellbore
with powerful hydraulic pumps to create enough downhole pressure to
crack or fracture the formation. The hydraulic pumps may include
components comprising one or more compositions of the invention.
This allows injection of proppant into the formation, thereby
creating a plane of high-permeability sand through which fluids can
flow. The proppant remains in place once the hydraulic pressure is
removed and therefore props open the fracture and enhances flow
into the wellbore.
[0067] Acidizing means the pumping of acid into the wellbore to
remove near-well formation damage and other damaging substances.
Acidizing commonly enhances production by increasing the effective
well radius. When performed at pressures above the pressure
required to fracture the formation, the procedure is often referred
to as acid fracturing. Fracture acidizing is another procedure for
production enhancement, in which acid, usually hydrochloric (HCl),
is injected into a carbonate formation at a pressure above the
formation-fracturing pressure. Flowing acid tends to etch the
fracture faces in a nonuniform pattern, forming conductive channels
that remain open without a propping agent after the fracture
closes. The length of the etched fracture limits the effectiveness
of an acid-fracture treatment. The fracture length depends on acid
leakoff and acid spending. If acid fluid-loss characteristics are
poor, excessive leakoff will terminate fracture extension.
Similarly, if the acid spends too rapidly, the etched portion of
the fracture will be too short. The major problem in fracture
acidizing is the development of wormholes in the fracture face;
these wormholes increase the reactive surface area and cause
excessive leakoff and rapid spending of the acid. To some extent,
this problem can be overcome by using inert fluid-loss additives to
bridge wormholes or by using viscosified acids. Fracture acidizing
is also called acid fracturing or acid-fracture treatment.
Apparatus of the invention maybe used in these applications.
[0068] In the oilfield context, a "wellbore" may be any type of
well, including, but not limited to, a producing well, a
non-producing well, an injection well, a fluid disposal well, an
experimental well, an exploratory well, and the like. Wellbores may
be vertical, horizontal, deviated some angle between vertical and
horizontal, and combinations thereof, for example a vertical well
with a non-vertical component.
EXAMPLES
[0069] Diamond-like coatings were tested in aqueous environments
with various hydronium ion concentrations, or PH, with temperatures
ranging from room temperature to water boiling. The DLC coatings
were applied on the internal surface of a 410 stainless steel (13
Cr-type) cylindrical piece (see FIGS. 9, 10A and 10B). Table 1
lists the visible results of the DLC coating after exposure for 24
hours. DLC coatings were produced using the "Sub-One" process
(Sub-One Technology, Pleasanton, Calif.) hollow cathode plasma
immersion ion processing (HCPIIP).
TABLE-US-00001 TABLE 1 DLC Exposure testing Conditions Results
Water PH = 9 24 hrs No effect on DLC Water PH = 7 24 hrs No effect
on DLC Water PH = 3 24 hrs No effect on DLC Pure HCl (10 min) No
effect on DLC Water PH = 0; 10% No effect on DLC NaCl Heavily No
effect on DLC concentrated NaOH in water
[0070] FIG. 11 shows a drawing of a seal testing device, wherein an
internal cylindrical surface is coated with a DLC coating and a
piston is moved cyclically from one side to the other by
controlling pressure on either side of this piston. FIG. 11, though
representing a test apparatus rather than a downhole oilfield
product, exemplifies the type of applications in which a DLC
coating, on internal surface of a borehole or other passageways,
may be used. In this example, testing has shown that the extreme
smoothness of the DLC coating improved the lifetime of the
elastomer seals. Furthermore, the absence of pitting or corrosion
damages on the internal surfaces of the borehole, as guaranteed by
the slick DLC coating, promote extended lifetime to the sealing
component. Preliminary tests under downhole typical temperatures
(e.g. 250.degree. F.) have shown that such active seals will have
unique advantages for the great diversity of downhole equipments
listed in this patent. Such active seals are covered in
applications listed in claims of this patent.
[0071] Although only a few exemplary embodiments of this invention
have been described in detail, those skilled in the art will
readily appreciate that many modifications are possible in the
exemplary embodiments without materially departing from the novel
teachings and advantages of this invention. Accordingly, all such
modifications are intended to be included within the scope of this
invention as defined in the following claims. In the claims, no
clauses are intended to be in the means-plus-function format
allowed by 35 U.S.C. .sctn. 112, paragraph 6 unless "means for" is
explicitly recited together with an associated function. "Means
for" clauses are intended to cover the structures described herein
as performing the recited function and not only structural
equivalents, but also equivalent structures.
* * * * *