WATER-BASED WELLBORE SERVICING FLUIDS WITH
HIGH TEMPERATURE FLUID LOSS CONTROL ADDITIVE
TECHNICAL FIELD
[0001] The invention relates to a fluid loss control additive. Particularly, the invention
relates to a fluid loss control additive for use in water-based drilling fluids used in oil and gas
applications. According to an embodiment, the fluid loss control additive is manufactured
under controlled conditions with specific amounts of raw materials. The fluid loss control
additive, manufactured in accordance with an embodiment, exhibits high temperature
stability.
BACKGROUND
[0002] Oil and gas hydrocarbons occur in some subterranean formations. In the
petroleum industry, a subterranean formation containing oil, gas, or water is referred to as a
reservoir. In order to produce oil or gas, a well is drilled into a reservoir or adjacent to a
reservoir. A well can include, without limitation, an oil, gas, or water production well, an
injection well, or a geothermal well. A well may include at least one wellbore. The wellbore
is drilled into a subterranean formation. The wellbore may be an open hole or cased hole. In
an open-hole wellbore, a tubing string may be placed into the wellbore. In a cased-hole
wellbore, a casing is placed into the wellbore that can also contain a tubing string. Drilling
fluids may be introduced into or flowed into the wellbore through the tubing string.
[0003] In drilling oil wells, a mud-like drilling fluid is pumped into the wellbore to
clean and cool the drill bit and to flush to the surface the rock cuttings that are torn loose by
the drill bit. The drilling fluid must have certain physical characteristics. The most important
of these is the viscosity and the water holding or retaining characteristics of the fluid. Drilling
fluids lubricate and flush rotary drill bit cuttings from the wellbore. They also provide
hydrostatic pressure or head in the wellbore to control pressures that may be encountered in
the subterranean formations. The density or weight of the drilling fluid creates a hydrostatic
pressure against the pipe that is greater than that in a porous subterranean formation traversed
by the wellbore. In water-based drilling fluids, this is due to the filtrate, or water in the
drilling fluid, that flows through the wellbore wall into the low pressure earth formation.
[0004] However, filtrate loss is a long-standing problem in the petroleum industry.
Filtrate loss can be described as the amount of drilling fluid filtrate lost into the subterranean
earth formation because of the pressure differential between the formation pressure and
hydrostatic pressure of the liquid in the wellbore. A sub-optimal fluid loss control may result
in creation of a bridge in a wellbore annulus opposite a permeable zone. This may result in
the isolation of a lower zone from the hydrostatic pressure above the bridge. It has been
observed that only a small amount of filtrate loss beneath such a bridge cause a drop in the
annular pressure to below that of the formation pressure. As a result, there is an influx of
formation fluids and pressure. This may create flow channels and require expensive remedial
work. The lost fluid may also damage sensitive formations. It is, therefore, important to
control fluid loss from wellbore servicing fluids to the surrounding formation.
SUMMARY
[0005] According to one embodiment, a method for reducing fluid loss from a waterbased
wellbore servicing fluid is disclosed. As described herein, the term "wellbore servicing
fluid" refers to a fluid which is pumped into a well during the drilling operation. The well
itself may be for gas, oil or any other purpose where such a fluid is used. According to the one
or more embodiments of the invention, the wellbore servicing fluid includes, without
limitation, a drilling fluid or mud, a completion fluid, a work-over fluid, a fracturing fluid, a
sweeping fluid, a cement composition and/or combinations thereof. The wellbore servicing
fluid may include fresh water, produced water, sea water, brines comprising sodium chloride,
calcium chloride and potassium chloride, sodium formate, potassium formate, sodium
bromide, calcium bromide, zinc chloride, zinc bromide and mixtures thereof.
[0006] The method includes combining a fluid loss control additive with the wellbore
servicing fluid. The fluid loss control additive comprises: about 1 weight part of a starch;
about 0.065 to about 0.26 weight parts of sodium monochloroacetate (SMCA); about 0.035 to
about 0.14 weight parts of an alkali; about 0.009 to about 0.0036 weight parts of a solvent;
about 0.0001 to about 0.0004 weight parts of a cross-linking agent; and water, wherein the
water is about 100 to about 300 percent by weight of the alkali. The method further involves
introducing the wellbore servicing fluid with the fluid loss control additive into a wellbore in
contact with a subterranean formation. The fluid loss control additive can be formulated to
substantially reduce fluid loss at a wellbore temperature ranging between ambient
temperature and about 350°F. The fluid loss control additive is substantially stable at a
temperature of about 350°F.
[0007] In another embodiment, a method for reducing fluid loss from a water-based
wellbore servicing fluid may include preparing the fluid loss control additive disclosed
earlier. The method includes the steps of: (1) dry mixing a natural starch and SMCA for a
first predetermined reaction time period; (2) spraying an alkaline solution onto the dry
mixture from step (1) for a second predetermined reaction time period to form a complex
starch mixture; and (3) treating the complex starch mixture for a third predetermined reaction
time period with a diluted cross-linking agent. The fluid loss control additive is substantially
stable at a temperature of about 350°F.
[0008] The first predetermined reaction time period may be around 20 minutes to
around 40 minutes. The second predetermined reaction time period may be around 45
minutes to around 75 minutes. The third predetermined reaction time period may be around
20 minutes to around 60 minutes. The formation of the complex starch mixture produces an
exothermic reaction. The formation of the complex starch mixture occurs without external
heating at a temperature of from about 45°C to about 70°C.
[0009] The alkaline solution comprises about 0.035 to about 0.14 weight parts of an
alkali and water, and wherein the water is about 100 to about 300 percent by weight of the
alkali. The diluted cross-linking agent comprises a cross-linking agent and a solvent in a 1:4
to 1:14 ratio. The cross-linking agent is selected from the group consisting of
epichlorohydrin, epoxy compounds, phosphorous oxychloride, cyanuric chloride,
formaldehyde and combinations thereof. The solvent may include isopropyl alcohol, n-propyl
alcohol, methyl alcohol and ethyl alcohol. The solvent may provide a suitable medium for the
mixing of the cross-linking agent and the starch complex. The wellbore servicing fluid may
include a monovalent or divalent brine.
[0010] The fluid loss control additive provides the wellbore servicing fluid with
effective rheology at 120° F and fluid loss control properties upto 350°F temperature. The
method further involves performing a drilling operation in a subterranean formation, and
wherein the wellbore servicing fluid with the fluid loss control additive is introduced into a
wellbore in contact with the subterranean formation during the drilling operation.
Detailed Description
[0011] It is common and economical to use water-based wellbore servicing fluids in
oil and gas well drilling operations. Water-base or water-based wellbore servicing fluids may
be substantially cheaper than oil-based fluids from the standpoint of cost, maintenance and
protecting the environment. Water based drilling fluid have advantages over oil based drilling
fluids as additives are nonhazardous, and environmentally accepted in all the regions of
world. The advantages of oil base mud in terms of shale stability, lubricity and high
temperature stability can be obtained in water based mud with careful selections of materials.
Filtrate loss may be controlled by increasing the filtrate viscosity to counter the normal
thermal thinning of the wellbore servicing fluid that occurs at downhole temperatures. In
order to reduce the loss of the fluid from the wellbore servicing fluid to the surrounding
formation, additives are suggested. These additives are commonly known as fluid loss
additives or "fluid loss control additives."
[0012] U.S. Pat. No. 4,123,366 discloses an additive that includes sodium
carboxymethylcellulose and sodium carboxymethyl starch for use in clay-based drilling mud.
The ratio of sodium carboxymethylcellulose and sodium carboxymethyl starch must be
present in a ratio of 3:2 to about 19:1. U.S. Pat. No. 4,652,384 discloses a cross-linked starch
based additive. However, it does not disclose that the additive is stable for use in HPHT wells
at temperatures of about 350°F. U.S. Pat. No. 5,009,267 discloses a fluid loss control additive
that includes a blend of two or more modified starches or a blend of one or more natural
starches with one or more modified starches. U.S. Pat. No. 5,851,959 discloses a modified
starch polymer having a content of amylopectin of at least 80% by weight. The patent
discloses fluid loss control at a maximum temperature of 285°F. U.S. Pat. Pub. No.
2004/0157748 discloses aqueous-based drilling fluids containing a starch polymer that has an
amylose content of at least 50% by weight.
[0013] Thus, the use of starch in well drilling fluid is well known. However,
conventional starches tend to break down at elevated temperatures at temperatures of 225°F
or higher when subject to that temperature for an extended time period. This is problematic
because high temperatures for extended periods of time are often encountered in deeper wells
during the drilling process. The breakdown of conventional starch results in an increase in the
consumption of the conventional starch needed in the mud.
[0014] There is, therefore, an industry requirement for a fluid loss control additive
that reduces filtrate loss to the surrounding formation at high temperatures. The fluid loss
control additive should not exhibit substantial loss of effectiveness in the presence of salt and
should be chemically stable at temperatures ranging from ambient temperature to about 350°
Fahrenheit. The fluid loss control additive should be compatible with other additives. The
fluid loss control additive should not harm the rheological performance/properties and should
not pose a detriment to the environment. The fluid loss control additive should be water
dispersible or soluble in aqueous wellbore servicing fluids. The fluid loss control additive
should exhibit optimal fluid loss control properties at normal ambient temperatures as well as
over a broad temperature range, including at about 350° Fahrenheit, encountered in high
pressure high temperature wells.
[0015] The fluid loss control additive, in accordance with the one or more
embodiments of the invention, can be manufactured under highly controlled temperature
conditions with specific measurements and compositions of raw materials. The fluid loss
control additive, therefore, is a highly and precisely engineered product. It can be used with
water-based well servicing fluids. The fluid loss control additive can substantially reduce
fluid loss while drilling hydrocarbon bearing formations. The fluid loss control additive can
be used in high pressure high temperature (HPHT) wells.
[0016] One embodiment of the invention involves manufacturing or formulating the
fluid loss control additive under controlled conditions and with specific compositions of raw
materials. The fluid loss control additive can be formulated by modifying raw or natural
starches. The natural starch can be derived from one or more plants including, corn, wheat,
maize, potato, rice, soy, sago, tapioca, or blends thereof. Waxy starches, such as, waxy maize
or waxy corn may also be used. In its pure form, starch is a white, tasteless and odorless
powder. It is insoluble in cold water or alcohol. Starch consists of two types of molecules: the
linear and helical amylose, and the branched amylopectin. The starch used in preparing the
fluid loss control additive may contain between 20% - 25% amylose and between 75% to
80% amylopectin content. However, starches having a different amylose-amylopectin amount
may also be used in formulating the fluid loss control additive.
[0017] According to one embodiment, the fluid loss control additive may be
manufactured in a batch process as follows. About 500 parts of natural starch can be dry
mixed with about 50 to 80 parts of sodium monochloro acetate ("SMCA"). This mixing may
be carried out in a suitable vessel known in the art. For example, the mixing may be carried
out in a double shaft paddle mixer. The mixing may be carried out for a first predetermined
reaction time period. The first predetermined reaction time period may be around 20 minutes
to around 40 minutes. Preferably, the first predetermined reaction time period may be around
25 minutes to around 35 minutes. The dry mixing of the powdered starch and SMCA imparts
heat energy and increases the temperature of the mixture from ambient temperature to about
35°C to about 40°C. Unlike conventional processes for manufacturing cross-linked starches,
the mixing of the starch and SMCA does not require any water.
[0018] In a separate mixing tank, about 20 to 40 parts of an alkali is dissolved in
about 60 to 80 parts of water. The alkali may be selected from a group consisting of sodium
hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate, sodium
bicarbonate, and combinations thereof. Preferably, the alkali is sodium hydroxide or
potassium hydroxide.
[0019] The alkaline solution prepared above is then sprayed onto the starch and
SMCA mixture for a second predetermined time period. The second predetermined reaction
time period is around 45 minutes to around 75 minutes. Preferably, the second predetermined
reaction time period is around 55 minutes to 65 minutes. This spraying may be carried out in
a suitable vessel, such as, a double shaft paddle mixer.
[0020] Alkalization and etherification reactions may take place simultaneously during
this process to result in the formation of a complex starch mixture. In the alkalization
reaction, starch is reacted with the alkali and alkaline starch is formed. The exothermic
reaction and mechanical mixing raises the temperature of the complex starch mixture to about
55°C - 60°C. No external heat is required during the mixing and spraying steps.
[0021] Upon completion of the above steps, the resultant complex starch mixture is
cross-linked with a small amount, about 0.05 to about 0.15 parts, of a cross-linking agent in
the presence of a suitable solvent at the mixture temperature of 55°C - 60°C. The crosslinking
agent can be selected from the group consisting of epichlorohydrin, epoxy
compounds, phosphorous oxychloride, cyanuric chloride, formaldehyde and combinations
thereof. The solvent may be selected from the group consisting of isopropyl alcohol,
methanol, ethanol, n-propyl alcohol or any other suitable solvent. The amount of the solvent
may be about 0.8 to 1 part.
[0022] The cross-linked starch mixture may be kept under mixing for a third
predetermined reaction time period. The third predetermined reaction time period may be
about 20 minutes to about 60 minutes to achieve a desired cross-linking of the starch.
Preferably, the third predetermined reaction time period may be about 30 minutes to about 45
minutes. This cross-linking step is vital to impart a low shear rate viscosity and high
temperature stability to the fluid loss control additive.
[0023] The cross-linked starch mixture formed after the cross-linking step may have
around 20 -25 moisture content. The cross-linked starch mixture may be completely or at
least partially dried in a suitable drying apparatus known in the art. For example, the crosslinked
starch mixture may be dried in a paddle drier. The drying can also be accomplished by
a heated drum dryer or extruder. The drying temperature may be maintained between 90°C
and 110°C depending on the moisture present in the raw materials constituting the crosslinked
mixture. The cross-linked starch mixture may be continued to be dried until its
moisture content may be reduced by 6% to about 10%.
[0024] The dried cross-linked starch mixture may be milled to a particle size
conventionally used in wellbore servicing fluids. The cross-lined starch mixture may also be
fed into a micro pulverizer where it is pulverized to a desired particle size. The desired
particle size may be dictated by the characteristics of the subterranean formation and the
properties of the wellbore servicing fluid. The resulting powdered mixture is screened
through vibrating sieves to separate out coarse powder from fine powder. The fine powder
may be packaged by a suitable packaging machine for use as a fluid loss control additive.
Advantageously, the manufacturing process does not generate any harmful by-products or
effluent waste.
[0025] During the manufacturing process, in accordance with the embodiment
described above, it is critical to maintain the specific amounts of the various raw materials.
For example, the amounts of alkali and SMCA, must be controlled in order to ensure that the
fluid loss control additive is stable at high temperatures up to 350°F. Similarly, the amount of
the cross-linking agent, the reaction temperatures and the first, second and third
predetermined reaction times must be controlled in order to increase thermal stability of fluid
loss control additive and to ensure its non-detrimental rheological performance at higher
temperature conditions.
[0026] The fluid loss control additive, manufactured in accordance with the above
embodiment, may include about 1 weight part of the starch; about 0.065 to about 0.26 weight
parts of sodium monochloroacetate (SMCA); about 0.035 to about 0.14 weight parts of the
alkali; about 0.009 to about 0.0036 weight parts of the solvent; about 0.0001 to about 0.0004
weight parts of a cross-linking agent; and water, wherein the water is about 100 to about 300
percent by weight of the alkali. In order to achieve the desired high temperature stability, in
one or more embodiments, the fluid loss control additive may consist essentially of the
specific composition of raw materials described above, namely, 1 weight part of the starch;
about 0.065 to about 0.26 weight parts of SMCA; about 0.035 to about 0.14 weight parts of
the alkali; about 0.009 to about 0.0036 weight parts of the solvent; about 0.0001 to about
0.0004 weight parts of a cross-linking agent; and water, wherein the water is about 100 to
about 300 percent by weight of the alkali.
[0027] The fluid loss control additive, manufactured in accordance with the above
embodiment, was tested as per API 13A test procedures for water-based wellbore servicing
fluids. The effectiveness of the product is checked by the American Petroleum Institute (API)
Fluid Loss Test after static aging of sample drilling fluids containing the starch at elevated
temperatures.
[0028] In one embodiment, a method for reducing fluid loss from a water-based
wellbore servicing fluid involves combining or adding the fluid loss control additive
manufactured in accordance with an embodiment of the invention with the wellbore servicing
fluid. It will be understood that in practice the amount of the fluid loss control additive added
to the wellbore servicing fluid will be different for different drilling operations and each
operator can use a particular or sufficient amount which they believe to be superior. The
wellbore servicing fluid with the additive may be introduced into a wellbore in any number of
ways known to those skilled in the art.
[0029] In another embodiment, a method for drilling a well involves employing a
water-based wellbore servicing fluid which includes the fluid loss control additive
manufactured in accordance with the embodiment of the invention.
[0030] The wellbore servicing fluid may also include dispersants, such as, surfactants
that improve flowability. For example, sorbitan monooleate, polyoxyethylene sorbitan
monooleate, ethoxylated butanol, and ethoxylated nonyl phenol, as well as various blends of
these surfactants may be added to the wellbore servicing fluid. The wellbore servicing fluid
may further include at least one component selected from a group consisting of weighting
agents, oxygen scavengers, biocides, pH modifiers, viscosifiers, corrosion inhibitors,
lubricants, friction inhibitors, scale inhibitors, and high temperature stabilizers. It is
understood that not all of the possible components may be present in any one wellbore
servicing fluid but their selection and use will differ for different drilling operations and each
operator will use different components depending on the situation.
[0031] The fluid loss control additive may reduce fluid loss by viscosifying the
filtrate. The fluid loss control additive may be used along with other additives. When
required, viscosifying agents may be added to assist the fluid loss control additive to provide
cleaning of the wellbore and improve suspension properties.
[0032] The fluid loss control additive may be used in aqueous wellbore servicing
fluids. Such fluids may be required for drilling water-sensitive shares. The aqueous wellbore
servicing fluids may be water or substantially any aqueous solution. Examples include natural
waters or brines or sea waters and/or waters softened or otherwise treated by means of ion
exchange resins, flocculating agents, etc. Brine is a generic term for water containing a salt
such as a sodium, potassium, or calcium salt.
[0033] The fluid loss control additive may promote well bore stability, rheological
control and fluid loss control. The fluid loss control additive manages the amount of
wellbore servicing fluid used in downhole operations.
[0034] A result of inclusion of the fluid loss control additive may be better
pumpability characteristics of the wellbore servicing fluid. This may improve removal of the
fluid while reducing the possibility of lost circulation.
[0035] The wellbore servicing fluid may contain at least one inorganic or organic salt.
For example, the wellbore servicing fluid may include inorganic monovalent and polyvalent
metal salts, such as calcium chloride, sodium chloride, potassium chloride, magnesium
chloride, sodium formate potassium formate, sodium bromide, potassium bromide, zinc
chloride, zinc bromide, and ammonium chloride.
[0036] The wellbore servicing fluid can substantially reduce fluid loss without
permanently plugging or otherwise damaging the rheological formation.
[0037] The fluid loss control additive may cause substantial reductions in the rate of
water/fluid loss by filtration. The fluid loss control additive is easily mixable. The fluid loss
control additive exhibits enhanced stability at very high temperatures.
[0038] Conventional additives used in drilling operations start to degrade above
275°F, however, the fluid loss additive, in accordance with the one or more embodiments of
the invention, has been found to be stable at even temperatures of about 350°F. Since
exploration and production activities can involve operations in high temperature conditions,
the fluid loss control additive of the invention may be highly suitable for use even in high
temperature well conditions.
[0039] The fluid loss control additive is non-hazardous and is readily biodegradable
after completion of the desired treatment process involving the fluid loss control additive.
Accordingly, the fluid loss control additive can be used with confidence in environmentally
sensitive areas or in areas where the emphasis on environmental protection is critical.
[0040] Advantageously, the fluid loss control additive, as described herein, is
formulated with a renewable resource, such as, natural starch. Accordingly, it may be more
cost effective and environmentally safe when compared to expensive and non-eco-friendly
synthetic polymer-based additives. Such polymer-based additives may also not be suitable for
high temperature applications above 250°F. Additionally, these polymer-based additives may
only be soluble in oil-based (and not in water-based) wellbore servicing fluids unlike the fluid
loss control additive described here in accordance with the one or more embodiments of the
invention.
[0041] When synthetic polymer-based additives are used in the wellbore, a high
concentration of oil wet solids may be deposited on the face of the wellbore and the casing.
Cleaning up this buildup may be expensive. Since the fluid loss control additive, described
here in accordance with the one or more embodiments of the invention, is formulated with a
natural starch, it can substantially minimize the wellbore cleanup related issues associated
with synthetic polymer-based additives.
[0042] Exemplary test results have been described below.
Example 1
The fluid loss control properties of a base-pregel starch and an embodiment of the high
temperature stable fluid loss control agent of the invention were compared by introducing
both additives into potassium formate mud systems. The other components in the mud
systems, the mixing order of the other components in the mud systems, and the mixing time
of the other components are kept virtually identical. As can be seen in Table 1, the fluid loss
control exhibited by the base-pregel starch is uncontrolled at 350°F. On the other hand, the
filtrate loss exhibited by the mud system that includes an embodiment of the high temperature
stable fluid loss control agent of the invention is around a low 6.8 ml at 350°F.
Table 1
Example 2
The fluid loss control properties of a base-pregel starch and an embodiment of the high
temperature stable fluid loss control agent of the invention were compared by introducing
both additives into potassium chloride mud systems. The other components in the mud
systems, the mixing order of the other components in the mud systems, and the mixing time
of the other components are kept virtually identical. As can be seen in Table 2, the fluid loss
control exhibited by the base-pregel starch is uncontrolled at 350°F. On the other hand, the
filtrate loss exhibited by the mud system that includes an embodiment of the high temperature
stable fluid loss control agent of the invention is around a low 7.8 ml at 350°F.
Table 2
Time in HT Fluid Loss
Base-Pregel Starch
min Control Agent
Potassium chloride Potassium chloride
Mixing order of Components
mud mud
5 %Potassium Chloride ,bbl 2 0.914 0.914
MgO, ppb 1 1.2 1.2
Xanthan bio-polymer dispersed, ppb 10 1.75 1.75
Pregel starch Fluid loss agent, ppb 6.3 ...
HT Fluid loss control agent, ppb 5 ... 6.3
CaC03 M, ppb 15 15
CaC03 F, ppb 15 15
Polymeric temperature stabiliser, ppb 5 1 1
Fluid properties
Before After Before After
Rolled at 300°F,hrs - 16 - 16
Mud weight, ppg 8.7 9.1 8.7 9.1
Fann 35 rheology at 120°F temperature
600 rpm 46 38 57 42.5
300 rpm 34 28 43 33.5
200 rpm 28 23 39.5 27
100 rpm 20 16 31.5 19.5
6 rpm 9 5 17 5
3 rpm 7 3 16 3.5
PV, cP 12 10 14 9
Yield point, lb/100ft2 22 18 29 24.5
10-sec gel, lb/100ft2 8 4 15.5 3
10-min gel, lb/100ft2 10 6 16.5 3.5
pH 9.7 9.7 9.8 9.2
API fluid loss in ml 5.4 5.4 6.8 7.2
HTHP fluid loss testing at 350°F temperature
HTHP differential pressure psi 500 500
Uncontroll
HTHP filtrate ml 7.8
ed
Example 3
The fluid loss control properties of a base-pregel starch and an embodiment of the high
temperature stable fluid loss control agent of the invention were compared by introducing
both additives into sodium chloride mud systems. The tests were carried out by varying the
amount of water and CaC03 in the mud systems. The other components in the mud systems,
the mixing order of the other components in the mud systems, and the mixing time of the
other components are kept virtually identical. As can be seen in Table 3, the fluid loss control
exhibited by the base-pregel starch is uncontrolled at 300°F and 350°F. On the other hand, the
filtrate loss exhibited by the mud system that includes an embodiment of the high temperature
stable fluid loss control agent of the invention is lower than 9 ml.
Table 3
CaC03 F ppb 5 15 15 5 5
Fluid properties
Befo Befo Befo Befo
After After After After After After
re re re re
Hot rolled
300 300 - 250 300 - 250 300
Temperature °F
Hot rolled for, hrs 16 16 - 16 16 - 16 16
10.6 10.6
Mud weight, ppg 10 10 10 10 10.6 10.6 10.6 10.7
5 5
FANN 35 rheology at 120°F
600 rpm 35 18 57 43.5 64 61 35 79 82.5 56
300 rpm 22 12 41.5 32 44 42 22 60 63 42
200 rpm 18 10 34 23.5 36 33.5 18 51 54 36
100 rpm 12 6 25 17 25 22 12 42 44 29
6 rpm 4 2 11 8.5 8 6 5 20 20 12
3 rpm 2 1 11 8.5 6 4 4 19 19 11
PV, cP 13 6 15.5 11.5 20 19 13 19 19.5 14
Yield point,
9 6 26 205 24 23 9 41 43.5 28
lb/100ft2
10-sec gel, lb/100ft2 3 2 9 6.5 8 7 5 19 19 11
10-min gel, lb/100ft2 5 3 11 8 10 9 7 19.5 19.5 11
10.2
pH 9.38 9.4 8.9 10.1 9.84 9.21 9.86 9.8 9.56
6
Unco Unc
API FLUID LOSS,
5.4 ntrol 4.8 3.8 3.2 12 ontr 5.8 4.4 3.8
ml
led oiled
HTHP filtration loss testing
HTHP
- 350 - 350 - 300 350 - 300 350
Temperature °F
Differential
- 500 - 500 - 500 500 - 500 500
Pressure psi
Unco Unc Unc
HPHT filtrate loss
- ntrol - 8.8 - ontr ontr - 5.8 6.8
ml
led oiled oiled
Example 4
The fluid loss control properties of a base-pregel starch and an embodiment of the high
temperature stable fluid loss control agent of the invention were compared by introducing
both additives into calcium chloride mud systems. The tests were carried out by varying the
weights of the mud systems at different brine concentrations. The other components in the
mud systems, the mixing order of the other components in the mud systems, and the mixing
time of the other components are kept virtually identical. As can be seen in Table 4, the fluid
loss control exhibited by the base-pregel starch is uncontrolled at a temperature of 300°F. On
the other hand, the filtrate loss exhibited by the mud system that includes an embodiment of
the high temperature stable fluid loss control agent of the invention is 6 ml. or lower at
temperatures of 300°F and 350°F.
Table 4
II 1l ll> Till . ti n l l l iii"
Pressure psi 500 500 500 500 500 500 500 500
Temperature °F 250 300 250 300 300 350 300 350
Unc Un
ont con
Fluid Loss ml 23 33 5.4 5.2 3.6 6.0
roll trol
ed led
Example 5
The fluid loss control properties of a base-pregel starch and an embodiment of the high
temperature stable fluid loss control agent of the invention were compared by introducing
both additives into calcium bromide mud systems. The tests were carried out at the same
brine concentration levels. The other components in the mud systems, the mixing order of the
other components in the mud systems, and the mixing time of the other components are kept
virtually identical. As can be seen in Table 5, the fluid loss control exhibited by the basepregel
starch is uncontrolled at a temperature of 300°F. On the other hand, the filtrate loss
exhibited by the mud system that includes an embodiment of the high temperature stable fluid
loss control agent of the invention is 6 ml. or lower at temperatures of 300°F and 350°F.
Table 5
Base-Pregel Starch HT Fluid Loss Control Agent
SAMPLE COMPOSITION Time (min) 14.7 ppg CaBr2 brine 14.7 ppg CaBr2 brine
CaBr2 Brine 14.2 ppg ,bbl 8 0.91 0.91
Xanthan biopolymer ,ppb 5 1.5 1.5
HT Fluid loss control agent, ppb 5 6
Pregel starch Fluid loss agent ppb 6
MgO.ppb 5 2 2
Polymeric temperature stabiliser, ppb 5 2 2
CaC03 F,ppb 2 5 5
CaC03 M, ppb 2 45 45
Hot rolled in Hrs 16 16
HOT ROLL TEMPERATURE ° F Initial 250 300 Initial 250 300
Mud Weight, ppg 14.6 14.8 14.8 14.6 14.7 14.7
FANN 35 RHEOLOY AT 120°F
600 RPM 66 49 20 >300 205 180.5
300 RPM 36 39 11 >300 124 119
200 RPM 24 25 9 292 98 93
00 RPM 13 17 6 188 60 61.5
6 RPM 3 6 3 59.5 11 8.5
3 RPM 1 3 2 48.5 7.5 5.5
GELS 10" lbs/1 00ft2 2 2 1 46 9 5
GELS 10' Ibs/100ft2 5 3 2 62 11 7.5
APPARENT VISC.cP 33 24.5 10 NA 102.5 90.25
PLASTIC VISC CP. 30 10 9 NA 8 1 61.5
YIELD POINT lbs/1 00ft2 6 29 2 NA 43 51.5
H 6.1 6.13 5.84 7.87 7.64 7.0
API FLUID LOSS ml Uncontrolled Uncontrolled Uncontrolled 3.0 2.4 2.6
HTHP filtration loss testing
Pressure psi 500 500 500 500
Temperature F 250 300 300 350
Fluid Loss ml Uncontrolled Uncontrolled Uncontrolled 4.4 6.0
These test results are, however, merely illustrative of the invention and those skilled in the art
will recognize that many other variations may be employed within the teachings provided
herein. Such variations are considered to be encompassed within the scope of the invention as
set forth in the following claims.
[0043] As used herein, the words "comprise," "have," "include," and all grammatical
variations thereof are each intended to have an open, non-limiting meaning that does not
exclude additional elements or steps. As used herein, a "fluid" is a substance having a
continuous phase that tends to flow and to conform to the outline of its container when the
substance is tested at a temperature of 7 1 °F (22 °C) and a pressure of one atmosphere "atm"
(0.1 megapascals "MPa"). A fluid can be a liquid or gas.
[0044] Viscosity is an example of a physical property of a fluid. The viscosity of a
fluid is the dissipative behavior of fluid flow and includes, but is not limited to, kinematic
viscosity, shear strength, yield strength, surface tension, viscoplasticity, and thixotropicity.
Viscosity is commonly expressed in units of centipoise (cP), which is 1/100 poise. One poise
is equivalent to the units of dyne-sec/cm .
[0045] It should be understood that, as used herein, "first," "second," "third," etc., and
are arbitrarily assigned and are merely intended to differentiate between two or more reaction
times, etc., as the case may be, and does not indicate any particular sequence. Furthermore, it
is to be understood that the mere use of the term "first" does not require that there be any
"second," and the mere use of the term "second" does not require that there be any "third,"
etc.
[0046] Therefore, the present invention is well adapted to attain the ends and
advantages mentioned as well as those that are inherent therein. The particular embodiments
disclosed above are illustrative only, as the present invention may be modified and practiced
in different but equivalent manners apparent to those skilled in the art having the benefit of
the teachings herein. Furthermore, no limitations are intended to the details of formulation
herein described, other than as described in the claims below. It is, therefore, evident that the
particular illustrative embodiments disclosed above may be altered or modified and all such
variations are considered within the scope and spirit of the present invention. While
compositions and methods are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and methods also can "consist
essentially of or "consist of the various components and steps. In particular, every range of
values (of the form, "from about a to about b," or, equivalently, "from approximately a to b")
disclosed herein is to be understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have their plain, ordinary meaning
unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite
articles "a" or "an", as used in the claims, are defined herein to mean one or more than one of
the element that it introduces. If there is any conflict in the usages of a word or term in this
specification and one or more patent(s) or other documents that may be incorporated herein
by reference, the definitions that are consistent with this specification should be adopted.
CLAIMS
1. A method for reducing fluid loss from a water-based wellbore servicing fluid, comprising:
combining a fluid loss control additive with the wellbore servicing fluid, wherein the fluid
loss control additive comprises:
about 1 weight part of a starch;
about 0.065 to about 0.26 weight parts of sodium monochloroacetate (SMCA);
about 0.035 to about 0.14 weight parts of an alkali;
about 0.009 to about 0.0036 weight parts of a solvent;
about 0.0001 to about 0.0004 weight parts of a cross-linking agent; and
water, wherein the water is about 100 to about 300 percent by weight of the
alkali.
2. The method according to Claim 1, further comprising introducing the wellbore servicing
fluid with the fluid loss control additive into a wellbore in contact with a subterranean
formation.
3. The method according to Claim 2, wherein the fluid loss control additive is formulated to
substantially reduce fluid loss at a wellbore temperature ranging between about ambient
temperature and about 350°F.
4. The method according to Claim 1, wherein the fluid loss control additive is substantially
stable at a temperature of about 350°F.
5. The method according to Claim 1, wherein the wellbore servicing fluid comprises a drilling
fluid, a completion fluid, a work-over fluid, a fracturing fluid, a sweeping fluid, or
combinations thereof.
6. The method according to Claim 1, wherein the wellbore servicing fluid comprises fresh
water, produced water, sea water, calcium brines, sodium brines, potassium brines, and
mixtures thereof.
7. The method according to Claim 1, wherein the starch comprises at least one of corn, wheat,
rice, maize, waxy maize, potato, sago, soy, tapioca, or blends thereof.
8. The method according to Claim 1, wherein the alkali is selected from the group consisting
of sodium hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate, sodium
bicarbonate, and combinations thereof.
9. The method according to Claim 1, wherein the cross-linking agent is selected from the
group consisting of epichlorohydrin, epoxy compounds, phosphorous oxychloride, cyanuric
chloride, formaldehyde and combinations thereof.
10. The method according to Claim 1, wherein the solvent is selected from the group
consisting of isopropyl alcohol, n-propyl alcohol, methyl alcohol and ethyl alcohol, wherein
the solvent provides a medium for an uniform mixing of the cross-linking agent with the
starch.
11. The method according to Claim 1, wherein the wellbore servicing fluid further comprises
at least one component selected from a group consisting of weighting agents, oxygen
scavengers, biocides, pH modifiers, viscosifiers, surfactants, corrosion inhibitors, lubricants,
friction inhibitors, scale inhibitors, and high temperature stabilizers.
12. A method for reducing fluid loss from a water-based wellbore servicing fluid, comprising:
preparing a fluid loss control additive comprising:
(1) dry mixing a natural starch and SMCA for a first predetermined reaction
time period;
(2) spraying an alkaline solution onto the dry mixture from step (1) for a
second predetermined reaction time period to form a complex starch mixture;
and
(3) treating the complex starch mixture for a third predetermined reaction time
period with a diluted cross-linking agent,
wherein the fluid loss control additive is substantially stable at a temperature of about
350°F.
13. The method according to Claim 12, wherein the first predetermined reaction time period
is around 20 minutes to around 40 minutes.
14. The method according to Claim 12, wherein the second predetermined reaction time
period is around 45 minutes to around 75 minutes.
15. The method according to Claim 12, wherein the formation of the complex starch mixture
produces an exothermic reaction.
16. The method according to Claim 12, wherein the formation of the complex starch mixture
occurs without external heating at a temperature of from about 45°C to about 70°C.
17. The method according to Claim 12, wherein the third predetermined reaction time period
is around 20 minutes to around 60 minutes.
18. The method according to Claim 12, wherein the starch comprises at least one of corn,
wheat, rice, maize, waxy maize, potato, sago, tapioca, or blends thereof.
19. The method according to Claim 12, wherein the alkaline solution comprises about 0.035
to about 0.14 weight parts of an alkali and water, and wherein the water is about 100 to about
300 percent by weight of the alkali.
20. The method according to Claim 19, wherein the alkali is selected from the group
consisting of sodium hydroxide, potassium hydroxide, sodium carbonate, potassium
carbonate, sodium bicarbonate, and combinations thereof.
21. The method according to Claim 12, wherein the diluted cross-linking agent comprises a
cross-linking agent and a solvent in a 1:9 ratio, wherein the cross-linking agent is selected
from the group consisting of epichlorohydrin, epoxy compounds, phosphorous oxychloride,
cyanuric chloride, formaldehyde and combinations thereof, and wherein the solvent is
selected from the group consisting of isopropyl alcohol, n-propyl alcohol, methyl alcohol and
ethyl alcohol.
22. The method according to Claim 12, wherein the fluid loss control additive comprises:
about 1 weight part of a starch;
about 0.065 to about 0.26 weight parts of sodium monochloroacetate (SMCA);
about 0.035 to about 0.14 weight parts of an alkali;
about 0.009 to about 0.0036 weight parts of a solvent;
about 0.0001 to about 0.0004 weight parts of a cross-linking agent; and
water, wherein the water is about 100 to about 300 percent by weight of the
alkali.
23. The method according to Claim 12, further comprising combining the fluid loss control
additive with the wellbore servicing fluid.
24. The method according to Claim 12, wherein the wellbore servicing fluid comprises a
monovalent or divalent brine.
25. The method according to Claim 22, wherein the fluid loss control additive provides the
wellbore servicing fluid with effective rheology and fluid loss control properties at a
temperature upto 350°F.
26. The method according to Claim 12, further comprises performing a drilling operation in a
subterranean formation, and wherein the wellbore servicing fluid with the fluid loss control
additive is introduced into a wellbore in contact with the subterranean formation during the
drilling operation.