U.S. patent application number 13/485612 was filed with the patent office on 2013-05-30 for materials with environmental degradability, methods of use and making.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is Don Aldridge, Jason Baihly, Rashmi B. Bhavsar, Manuel P. Marya, Nitin Y. Vaidya. Invention is credited to Don Aldridge, Jason Baihly, Rashmi B. Bhavsar, Manuel P. Marya, Nitin Y. Vaidya.
Application Number | 20130133897 13/485612 |
Document ID | / |
Family ID | 49673813 |
Filed Date | 2013-05-30 |
United States Patent
Application |
20130133897 |
Kind Code |
A1 |
Baihly; Jason ; et
al. |
May 30, 2013 |
MATERIALS WITH ENVIRONMENTAL DEGRADABILITY, METHODS OF USE AND
MAKING
Abstract
A valve device for restricting flow is provided that includes a
degradable portion. A method of temporarily blocking flow is also
provided which includes a degradable portion of an oilfield
element.
Inventors: |
Baihly; Jason; (Katy,
TX) ; Aldridge; Don; (Manvel, TX) ; Bhavsar;
Rashmi B.; (Houston, TX) ; Marya; Manuel P.;
(Sugar Land, TX) ; Vaidya; Nitin Y.; (Missouri
City, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baihly; Jason
Aldridge; Don
Bhavsar; Rashmi B.
Marya; Manuel P.
Vaidya; Nitin Y. |
Katy
Manvel
Houston
Sugar Land
Missouri City |
TX
TX
TX
TX
TX |
US
US
US
US
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
49673813 |
Appl. No.: |
13/485612 |
Filed: |
May 31, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
12371727 |
Feb 16, 2009 |
8211248 |
|
|
13485612 |
|
|
|
|
11427796 |
Jun 30, 2006 |
8231947 |
|
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12371727 |
|
|
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|
Current U.S.
Class: |
166/376 ;
138/46 |
Current CPC
Class: |
C22C 21/10 20130101;
C22C 21/003 20130101; C22F 1/047 20130101; E21B 34/063 20130101;
E21B 2200/04 20200501; E21B 34/06 20130101; C22F 1/04 20130101;
F16K 25/005 20130101; C22C 21/08 20130101; E21B 2200/05 20200501;
C22C 21/00 20130101; F16K 15/048 20130101 |
Class at
Publication: |
166/376 ;
138/46 |
International
Class: |
E21B 34/06 20060101
E21B034/06 |
Claims
1. A valve device for at least partially obstructing flow, the
valve device comprising: a valve body portion; a securing portion
of the valve body portion configured to securely position the valve
body portion in a predetermined location; a valve seat portion of
the valve body portion; an obstructing portion configured to engage
against the valve seat portion and restrict flow therepast; and a
degradable portion of the valve body portion configured to degrade
when exposed to specific environmental conditions.
2. The valve device of claim 1, wherein the degradable portion
includes the valve body portion.
3. The valve device of claim 2, wherein the degradable portion
further includes the obstructing portion.
4. The valve device of claim 1, wherein the degradable portion
includes the securing portion so that, upon degradation thereof,
the valve body portion is no longer secured in the predetermined
location.
5. The valve device of claim 4, wherein the securing portion is a
bolt member.
6. The valve device of claim 1, wherein the degradable portion
comprises aluminum.
7. The valve device of claim 6, wherein the degradable portion
comprises magnesium.
8. The valve device of claim 6, wherein the degradable portion
comprises zinc.
9. The valve device of claim 6, wherein the degradable portion
comprises a non-metal.
10. A method of temporarily blocking flow in a well bore, the
method comprising: positioning an oilfield element in a wellbore to
block fluid flow therepast; exposing the oilfield element to a
wellbore condition; and degrading a degradable portion of the
oilfield element so as to allow fluid flow to resume therepast.
11. The method of claim 10, wherein positioning an oilfield element
in a wellbore to block fluid flow therepast includes positioning a
valve body portion of a valve device within a wellbore, the valve
body portion having a valve seat portion; placing a blocking
portion of the valve device in the wellbore configured to engage
the valve seat portion and block fluid therepast; and engaging the
valve seat portion of the valve body portion with the blocking
portion to block fluid flow therepast.
12. The method of claim 11, wherein the blocking portion is a
ball.
13. The method of claim 11, wherein the degradable portion of the
oilfield element is the valve device.
14. The method of claim 11, wherein the degradable portion of the
oilfield element is the valve seat portion.
15. The method of claim 11, wherein the degradable portion of the
oilfield element is the valve body portion.
16. The method of claim 11, wherein the degradable portion is an
engaging portion of the valve body portion configured to secure the
valve body portion within the wellbore.
17. The method of claim 10, including releasing a chemical from the
degradable portion upon the degradation thereof.
18. The method of claim 17, wherein the chemical released from the
degradable portion is selected to provide an identifiable signature
within the wellbore fluids detectable by a downhole sensor.
19. The method of claim 17 including verifying degradation of the
degradable portion by the downhole sensor.
20. The method of claim 10, wherein the oilfield element is a
packer.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of U.S.
Non-Provisional application Ser. No. 12/371,727 filed Feb. 16,
2009, and is a continuation-in-part of U.S. patent application Ser.
No. 11/427,796 filed Jun. 30, 2006, both of which are hereby
incorporated in their entirety herein.
FIELD
[0002] The invention relates to flow restriction devices and, more
particularly, to flow restriction devices having a degradable
portion.
BACKGROUND
[0003] Materials that react to external stimuli, for instances
changes to their surrounding environments, have been the subject of
significant research in view of the potential they offer to sectors
of the economy as diverse as the medical, consumer-market,
transportation, chemical and petro-chemical sectors. For example,
such an advanced material that would have the remarkable ability to
degrade in order to actuate a well-defined function as a response
to a change in its surrounding may be desirable because no or
limited external human intervention would be necessary to actuate
the function. Such a material, essentially self-actuated by changes
in its surrounding (e.g., the presence or ingress of a specific
fluid, or a change in temperature or pressure, among other possible
changes) may potentially replace costly and complicated designs and
may be most advantageous in situations where accessibility is
limited or even considered to be impossible.
[0004] In a variety of subterranean and wellbore environments, such
as hydrocarbon exploration and production, water production, carbon
sequestration, or geothermal power generation, equipment of all
sorts (e.g., subsurface valves, flow controllers, zone-isolation
packers, plugs, sliding sleeves, accessories, etc) may be deployed
for a multitude of applications, in particular to control or
regulate the displacement of subterranean gases and liquids between
subsurface zones. Some of these equipments are commonly
characterized by relatively complex mechanical designs that are
controlled remotely from the rig at ground level via wirelines,
hydraulic control lines, or coil tubings.
[0005] Alternatively it may be desirable and economically
advantageous to have controls that do not rely on lengthy and
costly wirelines, hydraulic control lines, or coil tubings.
Furthermore, in countless situations, a subterranean piece of
equipment may need to be actuated only once, after which it may no
longer present any usefulness, and may even become disadvantageous
when for instance the equipment must be retrieved by risky and
costly interventions. In such situations, the control or actuation
mechanisms may be more conveniently imbedded within the equipment.
In other applications, it may be beneficial to utilize the inherent
ability of a material for reacting in the presence of an
environmental change; for instance such a material may be applied
to chemically sense the presence of formation water in a
hydrocarbon well. In other foreseen applications, such a degradable
material, if complemented by high mechanical strengths, may present
new advantages in aquatic environments not only to withstand
elevated differential pressures but also to control equipments
deployed underwater with no or limited intervention.
[0006] In some instances, by way of example only, in the petroleum
industry, it may be desirable to deploy a piece of equipment,
apparatus, or device that performs a pre-determined function under
differential pressures and then degrades such that the device no
longer requires retrieval or removal by some method. By way of
example only it may be advantageous to perform a multiple-stage
oilfield operation such as that disclosed in U.S. Pat. No.
6,725,929. However, after the so-called ball, dart or plug is
released in the wellbore to block gas and liquid transfers between
isolated zones, it may be desirable to remove it by milling,
flow-back, or alternate methods of intervention. In some instances,
it may be simply more advantageous to manufacture equipments or
devices, such as, by way of example only, balls, darts or plugs
using a material that is mechanically strong (hard) and degrades
under specific conditions, such as in the presence of
water-containing fluids like fresh water, seawater, formation
water, brines, acids and bases.
[0007] Unfortunately, the degradability of metallic materials, as
defined by their lack of stability in a defined environment, as
well as their ability to rapidly degrade (as opposed to the slow
and uniform rusting or weight loss corrosion of steels for
instance) may, in some instances, be accompanied with a number of
undesirable characteristics. For example, among the very few metals
that react and eventually fully degrade in water, both sodium metal
and lithium metal, in addition to having low mechanical strengths,
are water-reactive to the point they present great hazard along
with great manufacturing, procurement, shipping and, handling
challenges. Calcium metal is another reactive metal that in spite
of being lesser reactive and slower to reacts than either sodium or
lithium does not possess enough mechanical strength for normal
engineering applications. Like sodium metal and lithium metal,
calcium metal is thus unfit to many of the pressure-holding
applications found for instances in the chemical and petroleum
industries. When deficient, the properties of metals may be
enhanced by alloying, meaning the chemical mixing of two or more
metals and some other substances to form an end product, or alloy,
with new properties that may be suitable for practical use.
However, the alloying of lithium, sodium, or calcium metals with
other metals and substances is not without major metallurgical and
manufacturing challenges, and therefore the likelihood of creating
an alloy with attractive engineering combinations of high strength,
high toughness, and the proper degradability and rate of
degradation (in a specific condition) is not only doubtful but also
difficult to economically justify.
[0008] Table 1 compares several properties of pure metals with that
of exploratory alloys in their annealed conditions (i.e., in the
absence of cold working). Are listed in Table 1 measurements of
hardness (Vickers hardness, as defined in the ASTM E370 standard)
and galvanic corrosion potential, as simply established from
voltage average readings of dissimilar metals and alloys
electrically coupled by a aqueous electrolyte (here a sodium
chloride enriched water). In this document, hardness and
microhardness are considered to be fully interchangeable words;
i.e., no distinction is made between the two words. Vickers
hardness, or Vickers Microhardness, is a well-accepted and
straight-forward measure that may be monotonically correlated to
the mechanical strength of metals or alloys; e.g., the greater the
hardness, the higher the mechanical strength of the material.
Differently, galvanic corrosion potential is an electro-chemical
measure of reactivity, more precisely degradability, in an aqueous
electrolytic environment, as produced by the coupling of materials
with unlike chemical potentials. Though a low galvanic corrosion
potential correlates to high degradability in water-containing
fluid and often to high rates of degradation, rates of degradation
are also influenced by other factors (e.g., water chemistry,
temperature, pressure, and anode-to-cathode surface areas).
Therefore, simplistically correlating rate of degradation to
corrosion potential, despite being macroscopically correct as shown
in Table 1, is not fully accurate for materials exhibiting
especially comparable corrosion potentials. With these materials,
factors such as temperature and water chemistry often have greater
impacts on the rates of degradation than the galvanic corrosion
potential itself. Galvanic corrosion potential and degradability
may be considered purely as thermodynamic quantities, whereas rate
of degradation is a kinetic quantity that is also influenced by
other factors.
TABLE-US-00001 TABLE 1 Vickers Galvanic hardness corrosion number
potential (HVN) (Volts)* Aluminum metal (99.99 wt. %) 33.3 -0.60
Magnesium metal (99.99 wt. %) 32.5 -0.90 Calcium metal (99.99 wt.
%) 23.1 -1.12 80Al--10Ga--10In ** 33.4 -1.48
80Al--5Ga--5Zn--5Bi--5Sn ** 33.7 -1.28
75Al--5Ga--5Zn--5Bi--5Sn--5Mg ** 40.0 -1.38
65Al--10Ga--10Zn--5Bi--5Sn--5Mg ** 39.2 -1.28 *Galvanic corrosion
potential was measured against a pure copper electrode (99.99 wt.
%) in a 5 percent by eight sodium chloride aqueous solution; i.e.,
5 wt. % NaCl in water. ** All alloy compositions are listed in
weight percent (wt. %); e.g. 80 wt. % Al--10 wt. % Ga--10 wt. %
In.
[0009] Of all aluminum alloys, those referred as the
"heat-treatable" alloys exhibit some of the most useful
combinations of mechanical strength (hardness), impact toughness,
and manufacturability; i.e., the ability to readily make useful
articles of manufactures. These alloys are also characterized as
being precipitation or age-hardenable because they are hardened or
strengthened (the two words are interchangeable) by heat treatments
that typically consist of three consecutive steps: (1) a
solutionizing (solution annealing) heat-treatment for the
dissolution of solid phases in a solid .alpha.-aluminum (a refers
to pure aluminum's phase), (2) a quenching or rapid cooling for the
development of a supersaturated .alpha.-aluminum phase at a given
low temperature (e.g., ambient), and (3) an ageing heat treatment
for the precipitation either at room temperature (natural aging) or
elevated temperature (artificial aging or precipitation heat
treatment) of solute atoms within intra-granular phases. During
ageing, the solute atoms that were put into solid solution in the
.alpha.-aluminum phase at the solutionizing temperature and then
trapped by the quench are allowed to diffuse and form atomic
clusters within the .quadrature.-aluminum phase. These clusters or
ultra fine intra-granular phases result in a highly effective and
macroscopic strengthening (hardening) that provides some of the
best combinations of mechanical strength and impact toughness.
[0010] An important attribute of age-hardenable alloys is a
temperature-dependent equilibrium solid solubility characterized by
increasing alloying element solubility with increasing temperature
(up to a temperature above which melting starts). The general
requirement for age hardenability of supersaturated solid solutions
involves the formation of finely dispersed precipitates during
ageing heat treatment. The ageing must be accomplished not only
below the so-called equilibrium solvus temperature, but below a
metastable miscibility gap often referred as the Guinier-Preston
(GP) zone solvus line. For the development of optimal mechanical
properties, age-hardening alloys must therefore be heat-treated
according to predetermined temperature vs. time cycles. Failures in
following an appropriate heat-treatment cycle may result in only
limited strengthening (hardening); however any strengthening
(hardening) would still be evidence of an ageing response. The
presence of age-hardening novel aluminum alloys that possess the
unusual ability to degrade in water-containing fluids is a large
part of the alloys disclosed herein.
BRIEF DESCRIPTION OF THE FIGURES
[0011] FIG. 1 is a perspective view of a flapper valve;
[0012] FIG. 2 is a side elevational cross sectional view of a ball
valve; and
[0013] FIG. 3 is a side elevational view of a tubular within a
wellbore.
DETAILED DESCRIPTION
[0014] All alloys shown in Table 2 (including commercially
available 6061 alloy) were prepared by induction melting. The
alloys were either prepared from commercial alloys, within which
alloying elements were introduced from pure metals, or from pure
metals. The commercial alloys and the alloying elements were all
melted, magnetically, and mechanically stirred in a single
refractory crucible. All melts were subsequently poured into 3-in
diameter cylindrical stainless steel moulds, resulting in solid
ingots weighting approximately 300 grams. The alloy ingots were
cross-sections, metallographically examined (results not shown
herein), and hardness tested either directly after casting (i.e.,
in their as-cast condition after the ingots had reached ambient
temperature) and/or after ageing heat treatments. The induction
furnace was consistently maintained at temperatures below
700.degree. C. (1290.degree. F.) to ensure a rapid melting of all
alloying elements but also minimize evaporation losses of volatiles
metals such as magnesium. Gaseous argon protection was provided in
order to minimize the oxidation of the alloying elements at
elevated temperatures and maintain a consistency in the appearance
of the cast ingots. All ingots were solidified and cooled at
ambient temperature in their stainless steel moulds.
[0015] Solutionizing (solution annealing) was subsequently
conducted at 454.degree. C. (850.degree. F.) for 3 hours to create
a supersaturated solution. For purposes of simplifications, all
alloys were solutionized at this single temperature, even though in
reality each alloy has its own and optimal solutionizing (solution
annealing) temperature; i.e., each alloy has a unique temperature
where solubility of the alloying elements is maximized, and this
temperature is normally the preferred solutionizing temperature.
Optimal solutionizing (solution annealing) temperatures are not
disclosed in this document, as they remain proprietary.
[0016] Immediately after solutionizing (solution annealing), the
alloys were oil quenched (fast cooled) to retain their
supersaturated state at ambient temperature, and then aged at
170.degree. C. (340.degree. F.) in order to destabilize the
supersaturated state and force the formation of a new and harder
microstructure with fine precipitates dispersed within an
E-aluminum matrix phase. Grain boundary-phase were also observed,
but their consequences on alloy properties are not discussed
herein, since not relevant to the invention. Vickers microhardness
measurements, carried out with 500 g load in accordance with the
ASTM E370 standard, were measured at various stages of the ageing
heat-treatment all across ingot cross-sections. Though herein are
only reported the arithmetic averages of the hardness readings, at
least ten microhardness measurements were conducted at each stage
of the ageing heat treatment. Hardness was monitored over time for
as long as several weeks with the intention to fully replicate the
ageing of an alloy in a warm subterranean environment. Hardness vs.
time curves were generated to quantify and compare the
age-hardening response of the different alloys, as well as the
stability of the formed precipitates. FIGS. 1 and 2 compares
hardness vs. time responses of 6061 and HT alloy 20, a novel alloy
disclosed in Table 2. Despite an evident scatter in the data
plotted on FIGS. 1-2 that is characteristic of microstructural
imperfections, the novel alloy of FIG. 2 is considerably harder
(stronger), exhibiting an average and maximum hardness of about 120
compared to approximately 80 for the cast 6061 alloy in peak-aged
condition. Like other well-known age-hardenable alloys, when
heat-treated too long at temperatures or over-aged, the novel
alloys then experience softening, in stark contrast to the
hardening observed earlier during ageing. Rapid decrease in
hardness during over-ageing is a direct indication that the formed
precipitates are not thermally stable. In stark contrast, stable
precipitates, as revealed by no or barely detectable hardness decay
over time, may be preferred for most subterranean applications.
[0017] As a substitute to hardness vs. time curves (similar to that
of FIGS. 1-2), important hardness results are instead summarized in
Table 2 for all 26 novel alloys. Also included in Table 2 are their
nominal chemical compositions. For comparison purpose, a 6061 alloy
(i.e., a non-degradable and commercially-available aluminum alloy),
remelted in the same conditions are the novel alloys is also
included in Table 2. Reported in Table 2 are the as-cast hardness
(a measure of the hardness after casting and with no subsequent
heat-treatment of any sorts) and the peak hardness (i.e., the
maximum hardness observed during ageing heat treatment). An
increase in hardness from as-cast to aged (heat-treated) conditions
is an undeniable proof of age-hardenability.
[0018] In Table 2 the alloys are not categorized in the order they
were formulated and thus shaped into ingots; instead they are
ranked according to their magnesium content (in percent) to
specifically demonstrate the contribution of magnesium as an
alloying element. In Table 2, alloying element contents, expressed
in percent by weight (wt. %) are as follows: 0.5 to 8.0 wt. %
magnesium (Mg), 0.5 to 8.0 wt. % gallium (Ga), 0 to 2.5 wt. %
indium (Ga), 0 to 2.3 wt. % silicon (Si), and 0 to 4.3 wt. % zinc
(Zn).
[0019] All alloys were purposely formulated to demonstrate a wide
range of magnesium and gallium, along with other alloying elements
found in several series of commercial aluminum alloys, among
others. FIG. 3, which depicts hardness results from all 26 alloys
of Table 2, further reveals that all the novel alloys responded to
age-hardening; i.e., they may be strengthened by heat-treatments as
are commercial alloys such as the 6061 alloy. While magnesium is
known to be an effective solid-solution hardening element that is
essential to several commercial alloys, gallium is equally
well-known for creating grain-boundary embrittlement by liquation;
in other words gallium is known to lower mechanical strength
(hardness), specifically by promoting a low-temperature creep-type
deformation behavior. In fact in the prior art, gallium--like many
low-melting point metals (mercury, tin, lead)--is considered to be
detrimental to aluminum; thus gallium like other low-melting point
elements is only present in commercial aluminum alloys in impurity
levels; removal of these elements even in trace quantities has
traditionally been chief in achieving high-quality aluminum alloys
for industrial use. FIGS. 4 to 8 confirm that magnesium is also a
key contributor in raising hardness in the inventive alloys, either
in as-cast or aged condition (heat-treated condition). However,
magnesium alone does not suffice to generate an elevated age
hardening, unless magnesium is properly combined with gallium, as
shown in FIGS. 5 and 8. The data show that hardness values well in
excess to that of commercially-available 6061 may be achieved with
appropriate combinations of magnesium and gallium (a peak hardness
of 140 HVN, well in excess of the measured value in the 80s for the
6061 alloy is reported herein). Not only a maximum hardening occurs
at intermediate gallium percentage, as shown in FIG. 5, the ratio
of magnesium-to-gallium is also demonstrated to be important. A
ratio of in the vicinity of 2 is shown to result in maximum
hardness; for practical purposes, magnesium-to-gallium ratios
between 0.5 and 3.5 may be recommended to create a variety of
mechanical strengths and rates of degradation.
[0020] Furthermore, as pointed out by FIG. 6, silicon (an element
essential to alloy 6061 to cause age-hardening) is not seen to
influence hardness measurably in any of the novel alloys. Unlike
magnesium, zinc (FIG. 7) only appears to slightly reduce hardness,
an indication that the addition of zinc in the alloys of this
invention interferes with the ageing heat-treatment and the
magnesium-gallium alloying. The role of zinc in the novel alloys is
thus quite different to that seen in typical commercial aluminum
alloys. In many commercial aluminum alloys, zinc is utilized to
produce high strength with suitable resistance against corrosion
and stress-corrosion cracking.
TABLE-US-00002 TABLE 2 Mg Ga In Si Zn As-cast HT to (wt. %) (wt. %)
(wt. %) (wt. %) (wt. %) Mg/Ga HVN Peak HVN 6061- 1.0 0.0 0.0 0.6
0.1 -- 55 78 alloy HT alloy 0 0.5 0.5 0.5 0.0 0.0 1.00 42 78 HT
alloy 1 0.5 1.0 1.0 0.0 0.0 0.50 42 78 HT alloy 2 2.0 1.0 1.0 0.0
0.0 2.00 50 90 HT alloy 3 2.1 6.5 2.5 1.1 4.2 0.32 49 75 HT alloy 4
2.2 8.0 2.1 1.1 0.1 0.33 50 85 HT alloy 5 2.2 4.7 0.0 1.1 4.4 0.46
67 97 HT alloy 6 2.2 4.4 1.4 1.1 2.2 0.50 51 88 HT alloy 7 2.2 4.7
1.5 1.1 0.1 0.48 51 89 HT alloy 8 2.3 4.9 0.0 0.5 0.1 0.46 55 104
HT alloy 9 2.3 3.4 1.3 2.3 0.1 0.66 52 100 HT alloy 10 2.3 4.8 0.0
1.4 0.1 0.48 66 100 HT alloy 11 2.3 5.1 0.0 0.6 0.1 0.45 63 107 HT
alloy 12 2.3 3.5 1.3 0.6 0.1 0.65 51 96 HT alloy 13 2.3 2.4 0.0 0.6
0.1 0.99 57 94 HT alloy 14 2.4 2.4 0.0 1.2 0.1 0.99 58 91 HT alloy
15 2.4 2.3 0.0 0.6 0.1 1.01 62 100 HT alloy 16 3.5 1.0 1.0 0.0 0.0
3.50 60 99 HT alloy 17 4.3 4.4 0.0 0.5 4.3 0.98 91 125 HT alloy 18
4.4 4.4 1.4 1.1 0.1 1.00 66 104 HT alloy 19 4.4 4.7 0.0 2.2 0.1
0.94 69 108 HT alloy 20 4.5 4.5 0.0 1.1 0.1 1.00 75 123 HT alloy 21
4.5 3.4 1.2 0.5 0.1 1.32 69 125 HT alloy 22 6.2 4.1 1.5 1.2 4.1
1.50 86 111 HT alloy 23 6.6 3.3 1.2 0.5 0.1 1.97 75 143 HT alloy 24
8.0 3.8 1.6 1.2 0.0 2.10 88 132 HT alloy 25 8.0 3.8 1.6 0.0 0.0
2.11 85 136 * HT stands for heat-treatable. HVN stands for Hardness
Vickers Number; here measured under a 500 g indentation load.
[0021] Galvanic corrosion potentials of several of the 26 alloys of
Table 2 are summarized in Table 3. Galvanic corrosion potential is
a valuable indicator of the degradability of the alloy in
water-containing environments. Galvanic corrosion potential is here
measured by connecting to a voltmeter two electrodes immersed in an
electrically conductive 5 wt. % sodium chloride aqueous solution.
One electrode is made of one of the test alloys, and the other of a
reference material, here selected to be some commercially pure
copper (e.g., 99.99% Cu). The voltage, directly read on the
voltmeter was determined to be the galvanic corrosion potential.
Most generally novel alloys characterized by galvanic corrosion
potentials lesser than about -1.2 were observed to exhibit high
degradabilities; i.e., they react with the surrounding fluid and
produced a characteristic gaseous bubbling. For comparison
purposes, galvanic corrosion potentials of magnesium and calcium
are shown in Table 1 under the same exact test conditions. Some
novel alloys were found to be calcium-like by being highly and
rapidly degradable at ambient temperature, while others were found
to only rapidly degrade in a calcium-like manner at elevated
temperatures and despite the fact that their galvanic corrosion
potential is lower than that of either magnesium or calcium. For
those alloys not listed in Table 3 but included in Table 2, the
measured corrosion potentials were between -1.25 and -1.45.
Generally, the lowest potentials were for those alloys containing
indium. It is clear from Table 3 that gallium and indium are both
responsible for the degradability of the novel alloys while other
elements tend to either enhance or reduce degradability and rates
of degradation. With the alloys of this invention, the contribution
of gallium is two-fold: gallium increases both hardness (strength)
and degradability.
TABLE-US-00003 TABLE 3 As-cast (V) HT to Peak (V) Cast 6061 -0.60
-0.60 HT alloy 4 -1.47 -1.42 HT alloy 5 -1.30 -1.31 HT alloy 7
-1.42 -1.41 HT alloy 8 -1.30 -1.30 HT alloy 10 -1.28 -1.35 HT alloy
11.sup..dagger. -1.32 -1.29 HT alloy 13 -1.28 -1.27 HT alloy 14
-1.28 -1.32 HT alloy 15 -1.30 -1.32 HT alloy 19 -1.29 -1.36 HT
alloy 20* -1.31 -1.32 .sup..dagger.Galvanic corrosion potential was
found to increase slightly as bubbling proceeded. *Galvanic
corrosion potential was unstable, thus making the measurement
unreliable.
[0022] Another type of material useful in forming oilfield elements
comprises a combination of normally insoluble metal or alloys with
metallurgically-soluble (partially/wholly) and/or blendable
elements selected from other metals or alloys, semi-metallic
elements, and/or non-metallic elements; thus new compositions to
form new complex alloys and composite structures of poor stability
in the designated fluid environment. Examples of metals
preferentially selected to develop high strength include iron,
titanium, copper, combinations of these, and the like, among other
metals. Second metals, semi-metallic elements, and non-metallic
elements contemplated are any metal, semi-metallic element, or
non-metallic element that will form a non-durable (degradable)
composition with the first element. Examples include metals such as
gallium, indium, tin, antimony, combinations of these, and the
like; semi-metallic elements such as carboxylated carbon (e.g. in
graphitic or nanotube form), and organic compounds such as
sulfonated polystyrene, styrene sulfonic acid, and compositions
comprising non-metallic materials such as oxides (anhydride),
carbonates, sulfides, chlorides, bromides, acid-producing or basic
producing polymers, or in general fluid pH changing polymers. Many
of these non-metallic materials may contain metals that are
chemically-bonded to non-metallic elements (wherein the bonds may
be ionic, covalent, or any degree thereof). These materials
include, but are not limited to, alkaline and alkaline-earth
oxides, sulfides, chlorides, bromides, and the like. These
materials, alone, are at least partially water-soluble and, when
properly combined (e.g. blended) with normally insoluble metals and
alloys, will degrade the chemical resistance of the normally
insoluble metals by changing the designated fluid chemistry,
including its corrosiveness, thus creating galvanic cells, among
other possible mechanisms of degradations. Examples of normally
insoluble metals and alloys made soluble through the additions of
elements, including polymers, that would directly destabilize the
metallic state of the normally insoluble element for a soluble
ionic state (e.g. galvanic corrosion, lower pH created by
acid-polymers), or indirectly by promoting ionic compounds such as
hydroxides, known to predictably dissolve in the designated fluid
environment. Also contemplated are exothermic reactions occurring
in fluid such as water that may act as trigger to the degradation
of one of the composition. The ratio of normally insoluble metal to
metallurgically soluble or blendable elements is dependent on the
end use of the oilfield element, the pressure, temperature, and
element lifetime requirements as well as the fluid environment
compositions, and, without limiting the applications, may range
from 4:1 to 1:1 for instance.
[0023] Another group of materials useful in oilfield elements
includes one or more solubility-modified high strength and/or
high-toughness polymeric materials that may be selected from
polyamides (including but not limited to aromatic polyamides),
polyethers, and liquid crystal polymers. As used herein, the term
"polyamide" denotes a macromolecule containing a plurality of amide
groups, i.e., groups of the formula --NH--C(.dbd.O)-- and/or
--C(.dbd.O)--NH--. Polyamides as a class of polymer are well known
in the chemical arts, and are commonly prepared via a condensation
polymerization process whereby diamines are reacted with
dicarboxylic acid (diacids). Copolymers of polyamides and
polyethers may also be used, and may be prepared by reacting
diamines with diacids.
[0024] Useful aromatic polyamides include those generically known
as aramids. Aramids are highly aromatic polyamides characterized by
their flame retardant properties and high strength. They have been
used in protective clothing, dust-filter bags, tire cord, and
bullet-resistant structures. They may be derived from reaction of
aromatic diamines, such as para- and/or meta-phenylenediamine, and
a second monomer, such as terephthaloyl chloride.
[0025] Polyethers as a class of polymer are also well known, where
one type of polyether is commonly prepared by reaction of an
alkylene oxide (e.g., ethylene oxide) with an initiating group
(e.g., methanol). The term "polyether" as used herein denotes a
macromolecule containing a plurality of ether groups, i.e., groups
of the formula R--O--R where R represents an organic
(carbon-containing) group. At present, many polyethers are
commercially available that have terminating groups selected from
amine, hydroxyl and carboxylic acid. Polyethers having two amine
terminating groups may be used according to U.S. Pat. No.
6,956,099, incorporated herein by reference, to introduce polyether
blocks into a polyamide copolymer. This approach provides blocks of
polyether groups within a polyamide copolymer.
[0026] As noted in U.S. Pat. No. 5,057,600, incorporated herein by
reference, "poly(etheretherketone)" or "PEEK" refers to a polymeric
material which comprises poly(etheretherketone), i.e.,
[poly(oxy-p-phenyleneoxy-p-phenylenecarbonyl-p-phenylene]. PEEK is
a widely available semi-crystalline or amorphous high performance
thermoplastic polymeric material. PEEK is soluble in only a few
solvents. Some of the solvents require high temperatures while
other solvents such as sulfuric acid, sulfonate the PEEK molecules,
which alters the polymer and complicates characterization. Solution
properties of PEEK have been studied by Berk, C. and Berry, G. C.,
J. Polym. Sci.: Part B: Polym. Phys., 28, 1873 (1990); Bishop et
al., Macromolecules, 18, 86 (1985); Roovers et al., Macromolecules,
26, 3826 (1993); and Roovers, et al., Macromolecules, 23, 1611
(1990).
[0027] Other similar polymeric (PEEK-type polymers) materials such
as poly(aryletherketone) (PAEK), poly(etherketone) (PEK), or
poly(etherketoneketone) (PEKK), may also be polymers. Further,
poly(etheretheretherketone) (PEEEK),
poly(etheretherketoneetherketone) (PEEKEK),
poly(etheretherketoneketone) (PEEKK), poly
etherketoneetherketoneketone) (PEKEKK) are also to be considered as
PEEK-type polymers, both individually and as mixtures and as
copolymers with each other. Polymer mixtures of these PEEK-type
polymers with poly(phenylene sulfide) or "PPS" are also.
[0028] Other degradable materials include those described in U.S.
patent application Ser. No. 11/162,184 filed Aug. 31, 2005, and
U.S. patent application Ser. No. 11/427,233, filed Jun. 28, 2006,
all of which are incorporated by reference in their entirety
herein.
[0029] Although the alloys and other materials disclosed and
claimed herein are not limited in utility to oilfield applications
(but instead may find utility in many applications in which
hardness (strength) and degradability in a water-containing
environment are desired), it is envisioned that the alloys and
other materials disclosed and claimed herein will have utility in
the manufacture of oilfield devices. For example, the manufacture
of plugs, valves, sleeves, sensors, temporary protective elements,
chemical-release devices, encapsulations, and even proppants.
Additionally, oilfield devices include, but is not limited to one
or more items or assemblies selected from tubing, blow out
preventers, sucker rods, O-rings, T-rings, jointed pipe, electric
submersible pumps, packers, centralizers, hangers, plugs, plug
catchers, check valves, universal valves, spotting valves,
differential valves, circulation valves, equalizing valves, safety
valves, fluid flow control valves, connectors, disconnect tools,
downhole filters, motorheads, retrieval and fishing tools, bottom
hole assemblies, seal assemblies, snap latch assemblies, anchor
latch assemblies, shear-type anchor latch assemblies, no-go
locators, and the like. These oilfield devices can be used in a
number of well operations, including fracturing and stimulation
operations.
[0030] Well operations include, but are not limited to, well
stimulation operations, such as hydraulic fracturing, acidizing,
acid fracturing, fracture acidizing, or any other well treatment,
whether or not performed to restore or enhance the productivity of
a well. 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.
[0031] 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.
[0032] In the context of well testing, hydraulic fracturing means
the process of pumping into a closed wellbore with powerful
hydraulic pumps to create enough downhole pressure to crack or
fracture the formation. 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.
[0033] Acidizing means the pumping of acid into the wellbore to
remove near-well formation damage and other damaging substances.
This procedure 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 a 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 non-uniform 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.
[0034] 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.
[0035] In addition, it may be desirable to use more than one
material as disclosed herein in an apparatus. It may also be
desirable in some instances to coat the apparatus comprising the
degradable material with a material which will delay the contact
between the water-containing atmosphere and the degradable
material. For example, a plug, dart or ball for subterranean use
may be coated with thin plastic layers or degradable polymers to
ensure that it does not begin to degrade immediately upon
introduction to the water-containing environment. As used herein,
the term degrade means any instance in which the integrity of the
material is compromised and it fails to serve its purpose. For
example, degrading includes, but is not necessarily limited to,
dissolving, partial or complete dissolution, or breaking apart into
multiple pieces.
[0036] FIGS. 1 and 2 are exemplary valves with which the degradable
material may be utilized. As shown in FIG. 1, a ball valve
mechanism 5 can include a body 10, a seat portion 15 and a ball
portion 20. The ball valve mechanism 5 can be secured by a securing
mechanism 25, such as a bolt, or the ball valve mechanism 5 can be
held in place by an external support, such as a shelf or lip on the
inner surface of a tubular member. Any or all of the ball valve
mechanism 5 can be constructed from a degradable material,
including but not limited to the body 10, seat portion 15, ball
portion 20 and the securing mechanism 25, so long that as a result
of the degradation, a flow path is opened past the location at
which the valve 5 was positioned.
[0037] Similar to FIG. 1, the flapper valve 30 detailed in FIG. 2
can include a valve body 35, a flapper portion 40 and a hinge
connection mechanism 45 between the valve body 35 and flapper
portion 40. Similar to the ball valve mechanism 5, the flapper
valve 30 can be secured by a securing mechanism, such as a bolt, or
the flapper valve mechanism 30 can be held in place by an external
support 50, such as a shelf or lip on the inner surface of a
tubular member. Any or all of the flapper valve mechanism 30 can be
constructed from a degradable material, including but not limited
to the body 35, flapper portion 40 and the external support 50, a
flow path is opened past the location at which the valve 30 was
positioned.
[0038] FIG. 3 illustrates a tubular string 55 positioned within a
wellbore 60. A series of packers 65 are positioned within the
annulus about the outer surface 70 of the tubular string 55 and
include a metal frame portion 75 and a sealing portion 80 which
engages the wall 85 of the wellbore 60. The metal frame portion 75
of the packers 65 can be formed of a degradable material so that,
as the frame portion 75 degrades, the packer 65 comes free from the
tubular string 55 and can drop down the wellbore 60. Alternatively,
a securing mechanism 90, such as a bolt, connecting the packer 65
to the outer surface 70 of the tubular string 55 can be formed of a
degradable material so that, as the securing mechanism 90 degrades,
the packer 65 is no longer secured to the tubular string 55. Other
oilfield elements known to be positionable within the annulus, such
as a slip, can further be constructed to include a degradable
material so that, upon degradation of the material, a flow path is
formed therepast or the oilfield element can drop away from the
tubular to a position downhole.
[0039] Within the tubular string 55 are a series of seat members
95. The seat members 95 include an upwardly facing concave portion
100 to receive a dropped element 105, such as a ball, therein to
provide a fluid barrier. As shown, the seat members 95 can further
include a downwardly, facing concave portion 110 which can also be
configured to provide a fluid barrier. As shown in FIG. 3, the seat
members 95 can be secured to the tubular string 55 by a securing
mechanism 115, such as a bolt. Alternatively, for example, the seat
members 95 can be placed on a ledge 120 extending from an inner
surface 125 of the tubular string 55. The dropped element 105 can
be formed of a degradable material so that, as the dropped element
105 degrades, the flow path through the seat member 95 is reopened.
Additionally, the seat member 95 can be completely or partially
formed of a degradable material, the securing mechanism 115 can be
formed of a degradable material, and/or the ledge 120 extending
from the inner surface 125 of the tubular string 55 can be formed
of a degradable material.
[0040] In addition to the oilfield elements described above, it is
contemplated that valves, plugs, balls, seats and other oilfield
elements made of a degradable material can be situated to block
flow toward the surface until degradation occurs. In particular,
these oilfield elements can be configured to block flow from a
formation to a position uphole.
[0041] Certain embodiments and features have been described using a
set of numerical upper limits and a set of numerical lower limits.
It should be appreciated that ranges from any lower limit to any
upper limit are contemplated unless otherwise indicated. Certain
lower limits, upper limits and ranges appear in one or more claims
below. All numerical values are "about" or "approximately" the
indicated value, and take into account experimental error and
variations that would be expected by a person having ordinary skill
in the art.
[0042] Various terms have been defined above. To the extent a term
used in a claim is not defined above, it should be given the
broadest definition persons in the pertinent art have given that
term as reflected in at least one printed publication or issued
patent. Furthermore, all patents, test procedures, and other
documents cited in this application are fully incorporated by
reference to the extent such disclosure is not inconsistent with
this application and for all jurisdictions in which such
incorporation is permitted.
[0043] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *