Note: Descriptions are shown in the official language in which they were submitted.
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METHOD OF REMEDIATING BIT BALLING USING OXIDIZING
AGENTS
BACKGROUND OF INVENTION
Field of the Invention
[0001] Embodiments disclosed herein relate generally to methods for
treating drilling
equipment in a well. In particular, embodiments disclosed herein relate to
chemical
treatment of bit balling or clay compounded on a drill bit or other drilling
equipment.
Background Art
[0002] Hydrocarbons are found in subterranean formations. Production of
such
hydrocarbons is generally accomplished through the use of rotary drilling
technology, which requires the drilling, completing and working over of wells
penetrating producing formations.
[0003] To facilitate the drilling of a well, fluid is circulated through
the drill string,
out the bit and upward in an annular area between the drill string and the
wall of the
borehole. Common uses for well fluids include: lubrication and cooling of
drill bit
cutting surfaces while drilling generally or drilling-in (i.e., drilling in a
targeted
petroliferous formation), transportation of "cuttings" (pieces of formation
dislodged
by the cutting action of the teeth on a drill bit) to the surface, controlling
formation
fluid pressure to prevent blowouts, maintaining well stability, suspending
solids in
the well, minimizing fluid loss into and stabilizing the formation through
which the
well is being drilled, fracturing the formation in the vicinity of the well,
displacing
the fluid within the well with another fluid, cleaning the well, testing the
well,
transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a
packer,
abandoning the well or preparing the well for abandonment, and otherwise
treating
the well or the formation.
[0004] The selection of the type of drilling fluid to be used in a
drilling application
involves a careful balance of both the good and bad characteristics of the
drilling
fluids in the particular application and the type of well to be drilled.
However,
historically, water based drilling fluids have been used to drill a majority
of wells.
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Their lower cost and better environment acceptance as compared to oil based
drilling
fluids continue to make them the first option in drilling operations.
Frequently, the
selection of a fluid may depend on the type of formation through which the
well is
being drilled.
[0005] The types of subterranean formations, intersected by a well,
include sandstone,
limestone, shale, siltstone, etc., many of which may be at least partly
composed of
clays, including shales, mudstones, siltstones, and claystones. In penetrating
through such formations, many problems may be encountered including bit
balling,
swelling or sloughing of the wellbore, stuck pipe, and dispersion of drill
cuttings.
This may be particularly true when drilling with a water-based fluid due to
the high
reactivity of clay in an aqueous environment. When dry, the clay has too
little water
to stick together, and it is thus a friable and brittle solid. Conversely, in
a wet zone,
the material is essentially liquid-like with very little inherent strength and
can be
washed away. However, intermediate to these zones, the shale is a sticky
plastic
solid with greatly increased agglomeration properties and inherent strength.
[0006] When drilling a subterranean well, as the drill bit teeth penetrate
the
formation, drill chips are generated by the action of the bit. When these
cuttings are
exposed to conventional water-based muds, they usually imbibe water and are
rapidly dispersed. However recent advances in drilling fluid technology have
developed highly inhibitive muds which appear to reduce the hydration of shale
and
in doing so produce sticky, plastic shale fragments. These fragments adhere to
each
other and to the bottomhole assembly and cutting surfaces of the drill bit,
gradually
forming a large compacted mass of clay on the drilling equipment. This
process, or
phenomenon, of accumulation and impacting is generally referred to as
"balling" or
'packing off' of the drilling equipment.
[0007] Clay swelling during the drilling of a subterranean well can have a
tremendous
adverse impact on drilling operations. Bit balling reduces the efficiency of
the
drilling process because the drillstring eventually becomes locked. This
causes the
drilling equipment to skid on the bottom of the hole preventing it from
penetrating
uncut rock, therefore slowing the rate of penetration. Furthermore the overall
increase in bulk volume accompanying clay swelling impacts the stability of
the
borehole, and impedes removal of cuttings from beneath the drill bit,
increases
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friction between the drill bit and the sides of the borehole, and inhibits
formation of the thin
filter cake that seals formations. Clay swelling can also create other
drilling problems such as
loss of circulation or stuck pipe and increased viscosity of the drilling
fluid that slow drilling
and increase drilling costs. There have been advances in drilling fluid
technology for the
design of shale inhibitive fluids as well as drill bit technology; however,
when a shale
formation is unexpectedly encountered, or when bit balling nonetheless occurs,
the downtime
associated with either soaking the bit or tripping the bit is very costly and
undesirable.
[0008] Thus, given the frequency in which shale is encountered in
drilling
subterranean wells, the development of methods for reducing or treating clay
swelling remains
a continuing challenge in the oil and gas exploration industry.
SUMMARY OF INVENTION
[0009] In one aspect, embodiments disclosed herein relate to a method
of removing
clay compounded on drilling equipment in a well that includes contacting the
drilling
equipment with a treatment fluid comprising an oxidizing agent. Specifically,
the clay
compounded on the drilling equipment may be contacted. In a more specific
embodiment, the
invention relates to a method of removing clay compounded on drilling
equipment in a well,
comprising: contacting clay compounded on the drilling equipment with a
treatment fluid
comprising an oxidizing agent, wherein the oxidizing agent comprises at least
one of alkali
metal perborates, alkali metal persilicates, and perphosphates.
100101 In another aspect, embodiments disclosed herein relate to a method
of drilling a
wellbore though a clay-containing formation that includes drilling through the
formation with
a water-containing drilling fluid; reducing applied weight-on-bit when bit
balling detected;
emplacing a treatment fluid comprising an oxidizing agent to disrupt clay
compounded on
drilling equipment; and increasing weight-on-bit to continue drilling through
the formation.
[0011] Other aspects and advantages of the invention will be apparent from
the
following description and the appended claims.
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DETAILED DESCRIPTION
[00121 Embodiments disclosed herein are directed to methods that
enable the removal
of clay compounded on a drill bit (or other drilling equipment) in a well. In
particular,
embodiments disclosed herein are directed to contacting the drilling assembly
with a
treatment fluid which comprises an oxidizing agent.
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[0013] Clay minerals are generally crystalline in nature. The structure of
the clay's
crystals determines its properties. Typically, clays have a flaky, mica-type
structure.
Clay flakes are made up of a number of crystal platelets each being called a
unit
layer. The unit layers stack together face-to-face and are held in place by
weak
attractive forces. The distance between corresponding planes in adjacent unit
layers
is called the c-spacing.
[0014] Clay swelling is a phenomenon in which water molecules surround a
clay
crystal structure and position themselves to increase the structure's c-
spacing, thus
resulting in an increase in volume. Two types of swelling may occur. Surface
hydration is one type of swelling in which water molecules are adsorbed on
crystal
surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen
atoms
exposed on the crystal surfaces. Subsequent layers of water molecules align to
form
a quasi-crystalline structure between clay's unit layers which results in an
increased
c-spacing. All types of clays swell in this manner. Osmotic swelling is a
second
type of swelling. Where the concentration of cations between unit layers in a
clay
mineral is higher than the cation concentration in the surrounding water,
water is
osmotically drawn between the unit layers and the c-spacing is increased.
Osmotic
swelling results in larger overall volume increases than surface hydration.
However,
only certain clays, like sodium montmorillonite, swell in this manner.
[0015] Stress increases can induce brittle or tensile failure of the
formations, leading
to sloughing, cave in, and stuck pipe. Volume increases reduce the mechanical
strength of shales and cause swelling of wellbore, disintegration of cuttings
in
drilling fluid. The swelled excavated earth adheres to the walls of the
wellbore and
of the drilling equipment and forms a compact hard mass which gradually fills
the
entire wellbore annulus thus balling up of drilling tools and reducing the
effectiveness of the drilling bit.
[0016] Once clays have hydrated and compounded on a piece of drilling
equipment,
to avoid tripping / replacing the bit, various drilling techniques are
conventionally
attempted, including reducing weight on bit, increasing flow rate, and
increasing
RPM while the bit is off bottom, while soaking the bit in fresh water (so that
the
compounded clays can pass into their wet, dispersed state). However, in
accordance
with embodiments of the present disclosure, a treatment fluid comprised of an
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aqueous based fluid in which an oxidizing agent is incorporated prior to
delivery to
the balled up drilling equipment may be used to expedite remediation of the
balled
up equipment so that drilling may continue.
[0017] According to an embodiment of the present disclosure, the oxidizing
agent
comprises at least one peroxide. As used herein, "peroxide" refers to any
organic
and inorganic compounds whose structures include the peroxy-group, -0-0-. The
characteristic properties of peroxide compounds are the liberation of oxygen
as a
result of thermal decomposition and the decomposition into oxygen and water.
Inorganic peroxides (such as alkali or alkaline earth metals) first decompose
into a
metal hydroxide and hydrogen peroxide, prior to the decomposition of hydrogen
peroxide into oxygen and water. Their use as an oxidizing agent results from
the
instability of the peroxy bond. However, one skilled in the art would
appreciate that
the rate of decomposition is dependent on the temperature and concentration of
the
peroxide, as well as on the pH and the presence of impurities and stabilizers.
Thus,
in various embodiments, the oxidizing agent may comprise at least one compound
selected from the group consisting of hydrogen, alkali metal and alkaline
earth metal
peroxides and of inorganic salts of peroxyacids (also referred to as peracids)
such as
alkali metal percarbonates and perborates. In other embodiments, the oxidizing
agent may comprise at least one compound chosen from the group consisting of
hydrogen peroxide, sodium percarbonate, and sodium perborate. In a particular
embodiment, the oxidizing agent may be sodium percarbonate. Use of sodium
percarbonate may be particularly desirable in some embodiments, because when
used in a wellbore to aid in the removal of compounded clays from drilling
equipment, the byproducts of the reactions may include oxygen, water, and
sodium
carbonate (soda ash).
[0018] Further, while several particular compounds have been described
above, one
skilled in the art would appreciate that no limitation on the type of peroxy
compound
is intended by the present disclosure. Rather, similar to the peroxides cited
above,
which are active oxygen-releasing peroxide compounds, any compound that
similarly are a source of hydrogen peroxide (such as by hydrolysis) may be
used in
the fluids and methods of the present disclosure.
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[0019] Further, one skilled in the art would also appreciate that when
selecting the
oxidizing agent(s) for use in the treatment fluids according to the present
disclosure,
the chemistry of the drilling fluid used for the drilling operations may need
to be
taken into consideration. Indeed the treatment fluid, during the treatment
period,
may likely be in contact with the drilling fluid, which may have a very
complex
chemistry, and comprise a variety of different additives. Further, these
additives
could potentially react with the various compounds used in the treatment fluid
to
form by-products that may be undesirable. Thus, the type of oxidizing agent
used in
the methods of the present disclosure may be chosen depending on the types of
additives within the drilling fluid. For example, if biopolymers are contained
within
the drilling fluid, one skilled in the art may choose an oxidizing agent other
than a
perborate, as the borate by product may cause undesirable gellation of the
biopolymers.
[0020] Further, the oxidizing agents used in the fluids and methods
disclosed herein
may be stored at the drilling site (the rig), so as to be readily available
and for
immediate use once bit balling has been detected in the well. However, as one
with
skill in the art would appreciate, rigs' environments are usually humid and,
as
mentioned above, peroxides are highly reactive to water and moist
environments.
As a consequence, it may be desirable to prepare the oxidizing agent in such
as
manner so as to be stable when stored at the rig's conditions (temperature,
humidity)
in order to provide a long shelf life. Moreover, it may also be desirable to
use an
oxidizing agent having a delayed activity so that once mixed with the aqueous
based
continuous phase, the oxidizing agent may be protected so as to prevent it
from
generating all of the hydrogen peroxide during the mixing process or during
emplacement in the wellbore. However, the delay should not be so great so as
to
prevent rapid release once emplaced. This delay may be achieved by any
techniques
known from one skilled in the art such by, for example, encapsulation or acid
stabilization with conventional compounds used in these techniques and known
to
those with skill in the art.
[0021] According to a particular embodiment of the present disclosure, the
oxidizing
agent may be an encapsulated oxidizing agent. The use of capsules for the slow
or
controlled release of liquid or solid active ingredient and for the protection
of the
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active ingredient from any interactions with the exterior medium is well known
in
the art. For example, use of encapsulated oxidants is described in U.S. Patent
No.
6,861,394, which is assigned to the present assignee.
Typically, capsules may be formed by physical methods
such as spray coating, spray drying, pan coating, rotary disk atomization and
the
like; and chemical methods such as phase separation, interfacial
polymerization and
the like. Generally, release rates and solubility of the capsules are governed
by the
encapsulating material, capsule particle size, the thickness of the wall, the
permeability of the wall, as well as external environmental triggers. Thus,
for
example, the oxidizing agent may be provided with a coating sufficient to
control the
release of oxidant until a set of conditions selected by the operator occurs.
Some
general encapsulating materials may include natural and synthetic oils,
natural and
synthetic polymers and enteric polymers and mixtures thereof. However, many
methods of encapsulating may alternatively be used.
However, the encapsulant may be any conventional
compound known to be used in such technique by one skilled in the art. In a
particular embodiment, the encapsulant is a styrene-based polymer.
[0022] Many methods may be used to cause the release of the oxidant upon
the
occurrence of specific conditions desired by the operator. For example, the
oxidant
could be caused to be released by a change in temperature, pressure, pH,
abrasion or
any number of these or other environmental factors. In a particular
embodiment, the
method by which the oxidant is released from the encapsulating material for
the
disturbing compounded clays in a subterranean well is by having the oxidant
release
upon a change in pH in the downhole environment.
[0023] According to another particular embodiment, the oxidizing agent may
be an
acid stabilized oxidizing agent. As one with skill in the art would appreciate
an
acidic material may be added to a hydrogen peroxide solution in order to
prevent its
decomposition in water and oxygen. For example, hydrogen peroxide is typically
stabilized with phosphoric acid and/or acetanilide; however, one skilled in
the art
would appreciate that the present disclosure is not so limited.
[0024] Upon formulation, the treatment fluid may comprise from 0.0014 kg/L
(0.5
lb/bbl) to 0.1427 kg/L (50 lb/bbl) of the oxidizing agent in some embodiments,
and
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from 0.0143 kg/L (5 lb/bbl) to 0.1141 kg/L (40 lb/bbl) of the oxidizing agent
in
other embodiments.
[0025] The aqueous based continuous phase of the treatment fluid may be
any water
based fluid that is compatible with the oxidizing agent disclosed herein. The
aqueous based continuous phase may be selected from fresh water, sea water,
mixture of water and water soluble organic compounds and mixtures thereof. The
amount of the aqueous based continuous phase should be sufficient to form a
water
based treatment fluid.
[0026] The treatment fluid of the present disclosure may comprise a
weighting agent
known in the art in order to increase the density of the fluid, as required
for use in a
wellbore. The primary purpose for such weighting agents is to increase density
of
the treatment fluid so as to give it the density necessary to sit in the
region of the
compounded clay. That is, if the treatment fluid is not dense enough, it will
float up
the wellbore. Additionally, if the fluid doesn't have the appropriate density,
then the
pressures from the formation will be greater (or lower) than the hydrostatic
pressure
of the fluid against the wellbore walls and could thus induce formation fluids
to
enter the wellbore (or treatment fluid to enter the formation). The weighting
material may be added to the treatment fluid in a functionally effective
amount
largely dependent on the well being drilled. Weight agents suitable to use in
the
formulation of the treatment fluid of the claimed subject matter may be
generally
selected from galena, hematite, magnetite, iron oxides, illmenite, barite,
siderite,
celestite, dolomite, calcite, and the like or any conventional type or mixture
of
weighting agents known to one skilled in the art.
[0027] Other additives that could be present in the treatment fluids of
the claimed
subject matter include products such as lubricants, surfactants, corrosion
inhibitors,
antioxidants and pH buffers. Such compounds should be known to one of ordinary
skill in the art for formulating aqueous based fluids for use in subterranean
wells.
For example, such suitable lubricants may include fatty acid esters or other
lubricants known in the art of drilling fluid formulation. Further, such
surfactants
may include alkoxylated alcohols, such as ethoxylated alcohols having an HLB
between 10 and 15, but other surfactants known in the art of drilling fluid
formation
may alternatively be used.
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[0028] The method of use of the above-disclosed treatment fluids is
contemplated as
being within the scope of the claimed subject matter. The subject matter of
the
present disclosure is generally directed to a water based treatment fluid for
use in
subterranean wells that penetrate a subterranean formation that swells in the
presence of water. During the drilling of a subterranean well, hydrophilic
formations may be encountered. Their swelling may result in the drill bit
balling up
and being unable to drill further. Thus, according to one embodiment of the
present
disclosure, clay compounded on a portion of drilling equipment (such as the
drill bit
or other equipment including drill collars, stabilizers, pipe, etc.) may be
contacted
with a treatment fluid comprising an oxidizing agent.
[0029] Specifically, a treatment fluid may be introduced in the well and
brought into
contact with the clay of which removal is desired.
[0030] This treatment fluid may be administered to the region of the
wellbore in
which drilling equipment is stuck as a treatment pill. The treatment pill may
be
prepared by mixing the oxidizing agent and chosen additives with the aqueous
based
continuous phase. The oxidizing agent is mixed with the aqueous based fluid
for
sufficient time to insure that it is completely incorporated in the fluid.
Once the
treatment pill has been prepared, it may be emplaced in the wellbore so that
it may
be brought into contact with the balled up drilling equipment. This may be
achieved
by any conventional method known by one skilled in the art and for example by
injecting it into a work string, letting it flow to the bottom of the
wellbore, and then
out of the work string and into the annulus between the work string and the
casing or
wellbore. This batch of treatment is typically referred to as a "pill". The
treatment
pill may also be selectively emplaced in the wellbore, for example, by
spotting the
pill through a coil tube or by bullheading. Various methods of emplacing a
pill
known in the art are discussed, for example, in U.S. Patent Nos. 4,662,448,
6,325,149, 6,367,548, 6,790,812, and 6,763,888.
However, no limitation on the techniques by which the
treatment fluid of the present disclosure is emplaced is intended on the scope
of the
present application. After a period of time sufficient, i.e., several days, to
allow for
disruption or fragmentation of the compounded clay the fluid may be returned
to the
surface for collection and subsequent recovery techniques.
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[0031] The amount of treatment fluid contained in a pill used in the
practice of the
present disclosure may vary over a wide range depending upon the formations
penetrated by the drillstring and upon the extent of the bit balling.
Therefore, there
are no limitations in this regard. Generally, the size of the treatment pill
employed
in the practice of the invention may range between 10 and 50 bbl; however, one
skilled in the art would appreciate that depending on the size of the hole and
the
severity of bit balling, a larger volume may be used, for example, up to 100
bbls.
[0032] Further, the treatment fluid may be allowed to remain in contact
with the
balled up drilling equipment for a time sufficient to disrupt the clay
compounded on
the drilling equipment to such an extent that the clay becomes dispersed or a
loosely
adherent mass on the drilling equipment. The amount of time that the aqueous
composition remains in the formation will vary over a wide range depending on
factors such as well temperature, extent of the bit balling, etc. Thus, the
compounded clay should be sufficiently disrupted in an amount of time less
than that
required to disperse the clay if only soaked in fresh water (in the absence of
an
oxidizing agent). However, in particular embodiments, the amount of soak time
for
sufficient disruption of the bit balling may range from a duration of less
than 3
hours. However, one skilled in the art would appreciate that the soak time may
depend on factors such as the concentration of the active product, amount of
bit
balling present, temperature, and pressure.
[0033] Further, to reduce the amount of soak time (and thus downtime of
the well),
the drillstring may be rotated during the soaking period. Specifically, once
the
treatment fluid is in contact with the clay compounded on the drill bit and
anytime
during the treatment period, the drillstring may be rotated in order to
further mix the
downhole mixture, comprising clay, treatment fluid etc., so as to contact the
remaining treatment fluid with the residual clay still compounded on the drill
bit and
aid in disruption and dispersion of the clay.
[0034] According to yet another preferred embodiment, the drillstring is
rotated after
the soaking period. At the end of the treatment period, the drill string may
be rotated
in order to begin drilling again.
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[0035] Optionally, once enough clay has been disrupted sufficiently so
as to enable
the drilling operator to apply weight on bit (to proceed with drilling), it
may be
desirable to displace/wash the residual treatment fluid containing dispersed
clay
particles. For example, the previously balled up equipment and region of the
wellbore may be washed with a wash fluid such as by contacting or circulating
within the borehole the wash fluid. Such wash fluids may include water, brine
or
other conventional wash fluids. In this manner, the major components of the
clay
may be removed from the equipment, and the clay that was compounded on the
equipment may then be essentially completely removed from the wellbore. In a
particular embodiment, the washing of the residual treatment fluid may be done
while rotating the drillstring.
[0036] EXAMPLES
[0037] The present disclosure is further exemplified by the examples
below which are
presented to illustrate certain specific embodiments of the disclosure.
[0038] Example 1
[0039] A sticky clay material (a red clay from Britt ranch (Wheeler
county, section 6,
block 5, TX)) was balled onto the end of rod stirrers (one for a control and
one for a
sample treatment fluid) to simulate clay compounded on a drill bit. The
stirrers were
submerged in and left to soak in treatment fluids for 30 minutes. The test was
conducted at room temperature and at a pressure of 6.894 MPa (1000 psi), and
after
conclusion of the test, the amount of clay remaining on the stirrers was
measured.
The test details are shown below in Table 1.
Table 1
Control Treatment Sample 1
Clay initially deposited (g) 170 151
Rotation speed of the stirrer (rad.s-1) 9.3 (89 rpm) 11.5 (110 rpm)
Treatment fluid 300 mL water 300 mL water + 20 g sodium
percarbonate
Remaining clay after treatment (g) 169 102
[0040] No removal of clay from the stirrer which was soaked only in
water was
observed. However, a reduction of 32.5% of the clay deposited on the stirrer
contacted with the treatment fluid comprising an oxidizing agent was observed.
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[0041] Example 2
[0042] Similar to Example 1, clay was balled onto the end of rod
stirrers (one for a
control and one for a sample treatment fluid). The stirrers were submerged and
left
to soak in the treatment fluids (water or oxidizing agent) for 1 hour. The
experiment
was conducted at room temperature and at a pressure of 6.894 MPa (1000 psi),
and
after conclusion of the test, the amount of clay remaining on the stirrers
were
measured. The test details are shown below in Table 2.
Table 2
Control Treatment Sample 2
Clay initially deposited (g) 148.8 169.0
Rotation speed of the stirrer (rad.s-1) 10.5 (100 rpm) 10.5 (100 rpm)
Treatment fluid 350 mL water 350 mL water + 20g sodium
percarbonate
Remaining clay after treatment (g) 146.2 83
[0043] A slight reduction (1.7%) of the clay deposited on the stirrer
was observed
after the treatment with water. A higher decrease (51%) of the clay deposited
on the
stirrer contacted with the treatment fluid comprising an oxidizing agent was
observed.
[0044] Example 3
[0045] Two different treatment fluids (Samples 3 and 4) were prepared.
Sample 3
included 350 mL of water, 5 g of sodium percarbonate, 0.1 g of D-limonene and
¨2-
3 g of DAWN , available from Procter & Gamble (Cincinnati, OH). Sample 3 was
compared to Sample 4, which was comprised of 350 mL of water and 1 Og of
OXICLEAN (sodium hypochlorite with potassium and sodium hydroxide),
available from Church and Dwight Co. (Princeton, NJ). Similar to Example 1,
clay
was balled onto the end of rod stirrers (one for each sample). The stirrers
were
submerged in and left to soak in the treatment fluids. The experiment was
conducted
at 150 F and at a pressure of 1 atm.. The stirrers were rotated while soaking
in the
treatment fluids for 1 hour, and after conclusion of the test, the amount of
clay
remaining on the stirrers were measured. The test details are shown below in
Table 3.
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Table 3
Treatment Sample 3 Treatment Sample 4
Clay initially deposited (g) 113.8 111.7
Remaining clay after treatment (g) 57.7 75.5
[0046] A higher decrease (49.2%) in clay is observed for Sample 3 (sodium
percarbonate) than for Sample 4 (sodium hypochlorite) for which a decrease of
32.4% was observed.
[0047] Example 4
[0048] Similar to Example 1, clay was balled onto the end of rod stirrers
(one for a
control and one for a sample treatment fluid). Sample 5 was formed with
BIOADDTM 1105, an acid stabilized hydrogen peroxide available from Shrieve
Chemical Products, Inc. (The Woodlands, Texas). The stirrers were submerged
and
left to soak in the treatment fluids (water or oxidizing agent) for 45 minutes
in
rheology heating cups. The experiment was conducted at 65.5 C (150 F) and at a
pressure of 6.894 MPa (1000 psi). The stirrers were maintained static during
the
experiment and, after conclusion of the test, the amount of clay remaining on
the
stirrers was measured. The test details are shown below in Table 4.
Table 4
Control Treatment Sample 5
Clay initially deposited (g) 42.8 44.9
Treatment fluid 180 g water 140 g water + 40 g BIOADDTM 1105
Remaining clay after treatment (g) 43.8 25.5
100491 In the case of the treatment with an oxidizing agent, a reduction
of 57% of
clay compounded on the stirrer is observed, while the control showed a gain in
weight. While visual inspection of the control showed a loss of clay from the
stirrer
(some clay is observed to be in bottom of control cup), the increased weight
of the
control clay remaining on the stirrer may be explained by absorption of water
by the
remaining clay.
[0050] To shorten the effect of clay absorbing water during the
experiment, the clay
was soaked in water for 10 minutes at 65.5 C (150 F), weighed and then
subjected
to experiment. The experiment was conducted at 65.5 C (150 F) and at a
pressure
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WO 2009/137738
PCT/US2009/043226
of 1 atm. The stirrers were maintained static and soaked during 45 minutes,
and
after conclusion of the test, the amount of clay remaining on the stirrers was
measured. The test details are shown below in Table 5.
Table 5
Control Treatment Sample 6
Clay initially deposited after soaking (g) 59.7 56
Treatment fluid 100 mL water 80 mL water + 20 g BIOADDTM
1105
Remaining clay after treatment (g) 55.7 30.4
[0051] A loss of 45.7% was observed on the stirrer treated with the
oxidizing agent
compared to a loss of 5.7% on the control stirrer.
[0052] Example 5
[0053] In the example, an active composition of EMI-1995, available
from M-I LLC
(Houston, Texas), that contains a mixture of oxidizing agent, surfactant, and
lubricant was tested in Sample 7. Clay (40g wet, 25.38g dry) was balled onto
the
end of rod stirrers (one for a control and one for a sample treatment fluid),
dried at
65.5 C (150 F) for 16 hr and weighed (to determine the amount of clay material
present with the moisture removed). The stirrers were then submerged in
bottles
containing the treatment fluids (water or oxidizing agent) for 55 minutes. The
experiment was conducted at room temperature and at a pressure of 1 atm. The
stirrers were maintained static during the experiment. After the treatment
period, the
remaining clay on the stirrers was dried at 65.5 C (150 F) for 16 hours and
weighed
for comparison against the initial amounts of clay on the stirrers. The test
details are
shown below in Table 6.
Table 6
Control Treatment Sample 7
Clay initially deposited after drying (g) 25.38 25.38
Treatment fluid 350 mL water 280 mL water + 70 mL active
composition
Remaining clay after treatment and drying (g) 23.5 14.32
[0054] A decrease of 43.57% was observed on the stirrer soaked in
the treatment fluid
comprising the active composition while only a 7.91% decrease was observed on
the
control stirrer.
14
CA 02723799 2012-11-02
77680-173
[0055]
Advantageously, embodiments of the present disclosure may provide for at
least one of the following. Methods of the present disclosure allow for
efficient
removal of compounded clays such that tripping of the bit is not required each
time
bit balling occurs. Thus, use of the treatment fluids is less costly and time
consuming as compared to conventional remedial techniques.
Further, the
treatments fluids may be selected to be non-toxic, resulting in natural by-
products
such as oxygen, water, and carbonate.
[0056]
While the invention has been described with respect to a limited number of
embodiments, those skilled in the art, having benefit of this disclosure, will
appreciate that other embodiments can be devised which do not depart from the
scope of the invention as disclosed herein.
