A DRILLING FLUID COMPOSITION COMPRISING MICROBUBBLES
FIELD OF THE INVENTION
[0001] The present invention relates generally to well drilling and servicing fluids. In particular,
the present invention relates to a light weight well drilling and servicing fluid composition
comprising microbubbles, which exhibits improved properties for drilling operations in oil and
gas wells, particularly, for drilling or servicing wells in a subterranean formation comprising
lost circulation zones or in depleted, low pressure reservoirs.
BACKGROUND OF THE INVENTION
[0002] During the drilling of wells for hydrocarbon recovery, drilling fluids are circulated in
wellbores. The differential pressure of hydrostatic column is generally greater than the
formation pressure, especially in low pressure or depleted zones, which leads to invasion by the
drilling fluids. In addition, openings in the rocks, ability of fluids to move through the rocks,
and porosity and permeability of the zones may account for the occurrence of invasion. The
invasion further leads to formation damage which poses problems during drilling operations.
[0003] Many zones contain formation clays which become hydrated when they come in contact
with water such as filtrate from the drilling fluids. These hydrated clays tend to block the
producing zones, primarily sands, by obstructing the movement of oil and gas to the borehole
and affecting their production. In addition, these zones are also damaged by solids which are
carried into the openings with the fluid. The movement of drilling fluids and filtrate through
these openings also causes the dislodging and migration of solids and in turn, lodging and
blocking of the movement of produced hydrocarbons.
[0004] In order to combat the differential pressure, filtrate control methods have long been used
to control the movement of drilling fluids and filtrate into and through the formation openings.
This method comprises adding particles to the drilling fluid, and allowing the particles to get
deposited onto the borehole wall, while circulating and drilling, in order to plug and seal the
borehole. The particles added to the drilling fluid generally include bentonite, starch, lignins,
polymers, barite, drilled solids and combinations thereof. In addition, viscosity of the filtrate
provides some control when drilling with drilling fluids comprising water soluble polymers.
However, these methods suffer from some drawbacks. Although the wall-cake formed provides
for a semipermeable barrier, some filtrate moves through and into the zone both before and after
the wall-cake is formed. When filtrate moves through, the solids are screened out and left in the
cake which causes the cake to become thicker further leading to differential sticking of the drill
string. Further, some filtrate water is allowed to contact the producing zone which affects the
production of hydrocarbons.
[0005] Most of the oil fields have depleted on account of continuous production of
hydrocarbons. The depleted or low pressure reservoirs offer a great challenge for drilling
operations. Most of the times, these depleted reservoirs are composed of fractured layers
interbedded with each other, each layer having a different pore pressure. The low pressure
reservoirs offer various other problems which include lost circulation, instability of multipressure
sequences with one fluid, differential sticking and formation damage. Lost circulation
is defined as the total or partial loss of drilling fluids or cement slurries into highly permeable
zones, cavernous formations and natural or induced fractures during drilling or cementing
operations. Lost circulation may prove to be an expensive and a time-consuming problem.
During drilling, this loss may vary from a gradual lowering of the mud in the pits to a complete
loss of returns. The major consequences of lost circulation may include blowout due to a drop
in mud level; sticking in drill pipe due to poor cutting removal; lack of zonal isolation due to
insufficient cement fill-up; excessive cost on account of mud loss, excessive rig time and
remedial cementing operations; and extensive formation damage due to losses to the producing
zone. When the solids in the mud are not sufficiently fine to seal the formation face in upper
unconsolidated formations, seepage losses may occur. Partial losses may frequently occur in
highly permeable gravels, small natural fractures or as a result of fracture initiation. Complete
losses are usually confined to long gravel sections, large natural fractures, wide induced
fractures, or cavernous formations. Loss of drilling fluid is a very costly affair and significantly
increases the operational cost.
[0006] Many methods have been devised to restore circulation while drilling which include
gunk and reverse gunk squeezes, high fluid loss squeezes and cement squeezes. Many products
have also been employed to restore circulation which include fibrous, flaky and granular
materials and bridging materials. Chemically activated cross-linked pill (CACP) has also been
used, when drilling with drilling fluids comprising synthetic polymer based fluids, to cure and
limit losses. Efforts have also been made to reduce slurry density in order to restore circulation.
However, there have been areas of losses which do not adequately respond to these methods or
the products or even to a combination of the two. Further, while using these approaches, it
becomes difficult to attain required optimum bridging and density without the loss of desirable
slurry properties such as strength and resistance to corrosive fluids.
[0007] Other methods in the state of the art to eliminate lost circulation of drilling fluids include
aerating drilling fluids such as horizontal and under balanced drilling. Horizontal drilling has
increased the need to drill across low pressure and highly fractured or permeable zones thus
leading to exposure of numerous fractures or openings having low formation pressures. This
situation has amplified the problem of lost circulation and formation invasion and has
necessitated the use of underbalanced drilling such as use of air, mist, foam, stable foam and
air-entrained drilling fluids. The use of underbalanced drilling has increased as the development
of low pressure operations has acquired more importance. However, there are short-comings
associated these methods which include hole-cleaning, control of formation fluids, corrosion,
and requirement of expensive equipment. In addition, such fluids are not capable of
recirculating and therefore require constant generation and circulation within the wellbore as
the drilling proceeds.
[0008] Other problems associated with low pressure reservoirs include mud loss. The drilling
fluid provides higher hydrostatic head as compared to the low mud pore pressure leading to
mud loss. Mud loss situation arises while drilling areas such as natural fractures, fissures,
caverns and sub-hydrostatic formations. Many a times, uncontrollable and unavoidable mud
losses occur in fractured formations. The state of the art materials to tackle mud loss situations
include the use of conventional loss control materials and bridging agents. Conventional
methods to control mud loss include near balanced drilling with hollow glass spheres (HGS).
In addition, under-balanced drilling has also been used, however, this method involves extra
time and equipment which results in significantly increased operational costs.
[0009] In light of the above problems, drilling through depleted or low pressure reservoirs
requires low density drilling fluids which offer a means of bridging and sealing the formation.
For eliminating lost circulation, borehole instability, mud loss and differential sticking problems
in low pressure reservoirs, an aphron or microbubble based drilling fluid has been used in the
state of the art. An aphron is composed of an air core enveloped by a polymerlsurfactant shell.
The surfactants in the fluid convert the entrained air into aphrons or microbubbles. The aphron
comprising drilling fluid exhibits high Low Shear Rate Viscosity (LSRV) which has been
indicated by recent studies to be helpful in controlling the invasion of drilling fluids and filtrate
by creating a high resistance to movement of the fluid into the formation openings. Viscosity
becomes very high on account of very slow rate of movement of the drilling fluid thereby
leaving the fluid contained within the borehole with a very slight penetration. This property has
proven to be beneficial in protecting the zones from damage as well as reducing differential
sticking. However, the drawbacks associated with the methods include instability of gas bubbles
due to collapsing or expanding, increased costs and a need of extra equipment and special
protection measures. In addition, these methods provide for the required hydrostatic pressure to
attain stability which further accounts for increased costs.
[0010] In addition, these state of the art methods do not provide any solution for drilling through
depleted reservoirs with alternate sand and shale formation, which is much more critical.
Further, these state of the art methods do not provide any solution for areas where well activity
and mud loss problems prevail together.
[0011] In light of the above, there is a need in the field of well drilling operations for a light
weight well drilling and servicing fluid composition which eliminates fluid loss, formation
damage, lost circulation and differential sticking problems. In addition, there is a need for a
drilling fluid composition which provides stability to multi-pressure sequences and boreholes,
thereby saving precious rig time. Further, there is a need for a drilling fluid composition which
is capable of combating the mud loss and may be used in drilling the mud loss prone areas.
There is also a need for a drilling fluid composition which exhibits improved desired parameters
such as enhanced low shear rate viscosity, enhanced recirculation capability, high yield stress,
improved shear thinning behavior and enhanced stability. In addition, there is a need for a
drilling fluid composition which may effectively be used in drilling depleted reservoirs with
shale formation and minimal mud loss.
OBJECTS OF THE INVENTION
[0012] It is a primary object of the present invention to provide a drilling fluid composi'tion
comprising stable microbubbles which is recirculateable and exhibits enhanced low shear rate
viscosity.
[0013] It is another object of the present invention to provide a drilling fluid composition which
exhibits enhanced recirculation capability, high yield stress, improved shear thinning behavior
and enhanced stability.
[0014] It is still another object of the present invention to provide a drilling fluid composition
which eliminates fluid loss, formation damage, lost circulation and differential sticking
problems.
[0015] It is yet another object of the present invention to provide a drilling fluid composition
which may be used in both mud loss prone areas and depleted reservoirs with shale formation
and minimal mud loss.
[0016] It is still another object of the present invention to provide a method of bridging and
sealing subterranean formations at the surface of a borehole during well drilling and servicing
operations.
[0017] These and other objects and advantages of the present invention will become apparent
from the following description of the invention.
SUMMARY OF THE INVENTION
[0018] The present invention provides a drilling fluid composition comprising microbubbles,
the composition comprising: a low shear rate viscosity enhancer in the range of 1% to 1.4% by
weight in the composition; one or more surfactants in the range of 0.3% to 0.4% by weight in
the composition; one or more stabilizers in the range of 0.1% to 0.5% by weight in the
composition; and balance comprising an aqueous liquid. In an embodiment of the present
invention, the aqueous liquid comprises shale stabilizers. In an embodiment of the present
invention, composition comprises a co-surfactant. In an embodiment of the present invention,
the co-surfactant is present in an amount of 0.3% by weight in the composition. The drilling
fluid composition of the present invention comprises one or more viscosifiers, suspending
agents, weighting agents, corrosion inhibitors, soluble salts, biocides, fungicides, bridging
agents, deflocculants, lubricity additives, fluid loss control additives, pH buffering agents, and
other additives. The drilling fluid composition of the present invention comprises 15% to 25%
by volume of microbubbles. The drilling fluid composition of the present invention exhibits a
shear thinning index of at least 10. The shear thinning index of the present composition may
vary in the range of 10 to 56. The drilling fluid composition of the present invention exhibits a
low shear rate viscosity in the range of 25,000 centipoise to 130,000 centipoise. The drilling
fluid composition of the present invention exhibits a moderate low shear rate viscosity in the
range of 25,000 centipoise to 50,000 centipoise for drilling depleted reservoirs. The drilling
fluid composition of the present invention exhibits a high low shear rate viscosity in the range
of 100,000 centipoise to 130,000 centipoise. The drilling fluid composition of the present
invention operates at a pressure in the range of 24.6 to 351 kg/cm2 and a temperature in the
range of 20 to 1 10°C.
DETAILED DESCRIPTION OF THE INVENTION
[0019] The present invention is described in detail below for purposes of illustration only.
Modifications within the spirit and scope of the present invention, set forth in the appended
claims, will be readily apparent to one of skill in the art. Unless defined otherwise, terminology
and abbreviations, as used herein, have their ordinary meaning. The terms "at least one" and
"one or more" have been used interchangeably and are intended to have the same meaning.
Following are some exemplary definitions of terms used in this specification and the appended
claims.
Low Shear Rate Viscosity (LSRV): The term is measured by a Brookfield viscometer using L-3
spindle at 0.3 rprn (rotations per minute).
Shear Thinning Index: The term is an indicative of the shear thinning characteristics of the fluid
and may be calculated as the ratio of the Brookfield viscosity at 0.5 rprn to the Brookfield
viscosity at 100 rpm.
Rheological Properties: These properties are measured with Apparent Viscosity (AV), Plastic
Viscosity (PV) and Yield Point (YP).
Apparent Viscosity: ,The term refers to half of the 600 rprn dial reading of the formulation
measured by Fann V G meter.
Plastic Viscosity: The term refers to the difference between 600 rprn dial reading and 300 rprn
dial reading of the formulation in Fann V G meter.
Yieldpoint: The term refers to the difference between 300 rprn dial reading and Plastic Viscosity
of the formulation in Fann V G meter.
[0020] The present invention provides a drilling fluid composition with enhanced and superior
performance parameters for different drilling operations in oil and gas wells. The drilling fluid
composition of the present invention eliminates fluid loss control, formation damage, lost
circulation and differential sticking problems. The drilling fluid composition also provides
stability to multi-pressure sequences and borehole stability. The drilling fluid composition has
other improved desired parameters such as enhanced low shear rate viscosity, recirculation
capability and enhanced stability.
[0021] The following disclosure is provided in order to enable a person having ordinary skill in
the art to practice the invention. Exemplary embodiments are provided only for illustrative
purposes and various modifications will be readily apparent to persons skilled in the art. The
general principles defined herein may be applied to other embodiments and applications without
departing from the spirit and scope of the invention. Also, the terminology and phraseology
used is for the purpose of describing exemplary embodiments and should not be considered
limiting. Thus, the present invention is to be accorded the widest scope encompassing numerous
alternatives, modifications and equivalents consistent with the principles and features disclosed.
For purpose of clarity, details relating to technical material that is known in the technical fields
related to the invention have not been described in detail so as not to unnecessarily obscure the
present invention.
[0022] The design of light weight drilling fluids for these drilling techniques is a critical task,
particularly, for depleted or low pressure reservoirs, as often, they are composed of fractured
interbedded layers with different pore pressures, usually depleted water-wet sands and pressured
shale. There are several other problems associated with these kind of reservoirs such as fluid
loss control, stabilization of multi-pressure sequences with one fluid, possible differential
sticking and formation damage. Drilling throughout such depleted or low pressure reservoirs
without complication is the most challenging task. Such reservoirs also suffer from lost
circulation and mud loss problems. In this regard, the drilling fluid composition described herein
has been designed and tested for an anticipated broad range of parameters and conditions that
may occur during different drilling operations in oil and gas wells.
[0023] The drilling fluid composition of the present invention comprises an aqueous liquid
having a low shear rate viscosity enhancer hydrated therein, one or more surfactants and one or
more stabilizers, the drilling fluid composition comprising microbubbles.
[0024] The aqueous liquid of the composition of the present invention, in which the low shear
rate viscosity enhancer is hydrated, may be any aqueous liquid which is compatible with the
enhancer employed. The aqueous liquid may be selected from a group consisting of technical
water, sea water, and brine. Brine comprises one or.more soluble salts selected from a group
consisting of sodium chloride, calcium chloride, sodium bromide, potassium bromide, calcium
bromide, zinc bromide, sodium formate, potassium fonnate and cesium formate.
[0025] In an exemplary embodiment of the present invention, the brine comprises sodium
chloride.
[0026] The drilling fluid composition of the present invention exhibits a Low Shear Rate
Viscosity in the range of 25,000 centipoise (cp) to 130,000 centipoise. The proportions in which
the components are provided in the composition allows the composition to operate at a Low
Shear Rate Viscosity as low as 25,000 centipoise and as high as 130,000 centipoise.
[0027] In an exemplary embodiment of the present invention, the aqueous liquid comprises
shale stabilizers. The shale stabilizers may include potassium chloride and choline chloride. For
drilling depleted reservoirs with alternate sand and shale formation and minimal mud loss, a
drilling fluid with low to moderate low shear rate viscosity is required. In accordance with the
embodiment, shale stabilizers may be added in the drilling fluid of the present invention to
achieve the required low shear rate viscosity suited for such type of reservoirs. Potassium
chloride is present in the drilling fluid of the present invention in an amount ranging from 4.0%
to 6.0% in about 500 mL of aqueous liquid. Choline chloride is present in the drilling fluid of
the present invention in an amount of 2.0% in about 500 mL of aqueous liquid. In accordance
with the embodiment, the drilling fluid composition of the present invention may be maintained
at a low to moderate Low Shear Rate Viscosity in the range of 25,000 centipoise (cp) to 50,000
centipoise to drill such depleted reservoirs which require a drilling fluid to have a low to
moderate Low Shear Rate Viscosity. A low to moderate Low Shear Rate Viscosity of the
drilling fluid composition of the present invention may be varied, as necessary, depending upon
the condition of such reservoirs, by varying the amount of shale stabilizers.
[0028] The low shear rate viscosity enhancer employed in the drilling fluid composition of the
present invention is selected from a group consisting of water-soluble polymers. The low shear
rate viscosity enhancer increases the low shear rate viscosity of the drilling fluid composition
such that the composition exhibits improved characteristics such as high yield stress and shear
thinning behavior. The low shear rate viscosity enhancer enhances the low shear rate viscosity
of the drilling fluid composition of the present invention such that the composition exhibits a
shear thinning index (STI) of at least 10. The shear thinning index of the present composition
may vary in the range of 10 to 56. The composition of the present invention preferably employs
bio-polymers produced by the action of bacteria, fungi, or other microorganisms on a suitable
substrate. The drilling fluid composition of the present invention may be maintained at a high
Low Shear Rate Viscosity in the range of 100,000 centipoise to 130,000 centipoise to drill areas
with severe mud loss conditions which require a drilling fluid to have a high Low Shear Rate
Viscosity. A high Low Shear Rate Viscosity of the drilling fluid composition of the present
invention may be varied, as necessary, depending upon the mud loss intensity, by varying the
amount of low shear rate viscosity enhancer.
[0029] In an exemplary embodiment of the present invention, low shear rate viscosity enhancer
is a bio-polymer produced by the action of bacteria Xanthomonas compestris, also known as
xanthan gums.
[0030] The low shear rate viscosity enhancer is required in an amount sufficient to impart the
desired low shear rate viscosity to the drilling fluid composition. The low shear rate viscosity
enhancer is present in the drilling fluid composition of the present invention in an amount
ranging from 1 .O% to 1.4% in about 500 mL of aqueous liquid.
[0031] The one or more surfactants are employed in the drilling fluid composition of the present
invention to create microbubbles and therefore, the nature of the surfactants and their
compatibility with other additives being mixed in the composition bear a significant impact over
final properties of the composition. In addition, surfactants are temperature sensitive, therefore
selection of a surfactant also depends upon the maximum bottom-hole temperature expected.
The one or more surfactants employed in the drilling fluid composition of the present invention
are selected from a group consisting of anionic surfactants and non-ionic surfactants. The
anionic surfactants preferably employed in the drilling fluid composition of the present
invention are alkyl ether sulphonates. The anionic surfactant is present in the drilling fluid
composition of the present invention in an amount ranging from 0.3% to 0.4% in about 500 mL
of aqueous liquid. The non-ionic surfactants preferably employed in the drilling fluid
composition of the present invention are linear primary alcohol ethoxylates. The non-ionic
surfactant is present in the drilling fluid composition of the present invention in an amount
ranging from 0.3% to 0.4% in about 500 mL of aqueous liquid.
100321 In an exemplary embodiment of the present invention, the anionic surfactant is a mixture
of polyoxyethylene ether and polyoxyethylene sulphonate.
[0033] In an exemplary embodiment of the present invention, the non-ionic surfactant is alkyl
aryl polyether alcohol.
[0034] The one or more surfactants employed in the drilling fluid composition of the present
invention may hrther comprise a co-surfactant. The co-surfactant employed in the drilling fluid
I:
i; composition of the present invention is amphoteric in nature, preferably comprising betaine v -
4
group of compounds. The co-surfactant is present in the drilling fluid composition of the present i -
i
invention in an amount of 0.3% in about 500 mL of aqueous liquid. i
[0035] In an exemplary embodiment of the present invention, the co-surfactant is
cocamidopropyl betaine. I;
[0036] The one or more stabilizers are employed in the drilling fluid composition of the present
invention to form a tough elastic membrane around the gas or air core. The one or more
stabilizers employed in the drilling fluid composition of the present invention are selected from
a group consisting of saturated fatty acids, un-saturated fatty acids and polyalcohols. The
saturated fatty acid is present in the drilling fluid composition of the present invention in an
amount ranging from 0.1% to 0.2% in about 500 mL of aqueous liquid. The un-saturated fatty
acid is present in the drilling fluid composition of the present invention in an amount of 0.1%
in about 500 mL of aqueous liquid. The polyalcohol is present in the drilling fluid composition
of the present invention in an amount ranging from 0.1% to 0.5% in about 500 mL of aqueous
liquid.
[0037] In an exemplary embodiment of the present invention, the saturated fatty acid is stearic
acid.
[0038] In an exemplary embodiment of the present invention, the un-saturated fatty acid is oleic
acid.
[0039] In an exemplary embodiment of the present invention, the polyalcohol is polyvinyl
alcohol.
[0040] The drilling fluid composition of the present invention may generally comprise materials
well known in the art to provide various characteristics or properties to the composition. Thus,
the drilling fluid composition of the present invention may comprise one or more viscosifiers,
suspending agents, weighting agents, corrosion inhibitors, soluble salts, biocides, fungicides,
seepage loss control additives, bridging agents, deflocculants, lubricity additives, shale control
additives and other additives, as desired. The biocides employed in the drilling fluid
composition of the present invention may comprise aldehyde group of compounds generally
used to eliminate any bacterial growth. The biocides are present in the drilling fluid composition
of the present invention in an amount of 0.1% in about 500 mL of aqueous liquid. The shale
control additives employed in the drilling fluid composition of the present invention may
comprise potassium chloride and choline chloride. Potassium chloride is present in the drilling
fluid composition of the present invention in an amount ranging from 4.0% to 6.0% in about
500 mL of aqueous liquid, Choline chloride is present in the drilling fluid composition of the
present invention in an amount of 2.0% in about 500 mL of aqueous liquid. Other additives
employed in the drilling fluid composition of the present invention may comprise soda ash for
reducing the hardness of water. Soda ash is present in the drilling fluid composition of the
present invention in an amount of 0.1% in about 500 mL of aqueous liquid.
[0041] The drilling fluid composition of the present invention may comprise one or more
materials which function as encapsulating or fluid loss control additives to further restrict the
entry of liquid from the fluid to the contacted shale. Representative fluid loss control additives
known in the art generally control filtration loss. Such additives may include partially
solubilized starch, gelatinized starch, starch derivatives, cellulose derivatives, humic acid salts
(lignite salts), lignosulfonates, gums, synthetic water soluble polymers, and mixtures thereof.
Synthetic polymers may comprise Hydroxy ethyl cellulose (HEC). The fluid loss control
additives are present in the drilling fluid composition of the present invention in an amount
ranging from 0.3% to 0.5% in about 500 mL of aqueous liquid.
[0042] The drilling fluid composition of the present invention should have a basic pH,
preferably in the range of 9 to 10. It is well known in the art that a desired basic pH may be
obtained by the addition of a pH buffering agent to the drilling fluid composition. The pH
buffering agent may be selected from a group consisting of potassium hydroxide, potassium
carbonate, potassium humate, sodium hydroxide, sodium carbonate, sodium humate,
magnesium oxide, calcium hydroxide, zinc oxide, and mixtures thereof. The pH buffering agent
is present in the drilling fluid composition of the present invention in an amount ranging from
0.1% to 0.6% in about 500 mL of aqueous liquid. The preferred pH buffering agent is
magnesium oxide.
[0043] The drilling fluid composition of the present invention comprise microbubbles. The
drilling fluid composition of the present invention comprises about 15% to about 25% by
volume of microbubbles. The quantity of microbubbles in the drilling fluid composition of the
present invention depends on the fluid density required. Thus, the density of the circulating
drilling fluid composition may be monitored on the surface and a co-surfactant may be added if
the density is too high so as to maintain the desired density. Similarly, weight material may be
added to the drilling fluid composition if the density is too low. The microbubbles of the present
invention are stable up to a temperature of 110°C.
[0044] The microbubble comprising drilling fluid composition of the present invention is noncoalescing
and recirculateable. The drilling fluid composition of the present invention
comprises microbubbles in an amount to achieve a desired density characterized by a uniform
dispersion of microbubbles when the composition is under high pressure conditions, the density
preferably in the range of 0.48 to 7.2 g/cm3. The drilling fluid composition of the present
invention is capable of functioning at a pressure in the range of 24.6 to 351 kg/cm2 and a
temperature in the range of 20 to 1 10°C. The drilling fluid composition of the present invention
exhibits a Low Shear Rate Viscosity in the range of 25,000 centipoise (cp) to 130,000
centipoise. The proportions in which the components are provided in the composition allows
the composition to operate at a Low Shear Rate Viscosity as low as 25,000 centipoise and as
high as 130,000 centipoise. The drilling fluid composition of the present invention exhibits a
high Low Shear Rate Viscosity in the range of 100,000 centipoise to 130,000 centipoise (cp)
and may, therefore, be used in areas with severe mud loss conditions which require a drilling
fluid to have a high Low Shear Rate Viscosity. The drilling fluid composition of the present
invention may also be maintained at a low to moderate Low Shear Rate Viscosity in the range
of 25,000 centipoise to 50,000 centipoise and may, therefore, be used to drill depleted reservoirs
which require a drilling fluid to have a low to moderate Low Shear Rate Viscosity. The
microbubbles comprising drilling fluid composition of the present invention may be circulated
as conventional drilling fluids and provide for a self-correcting air-locking system to control
fluid loss. An agglomerate of microbubbles contained in the drilling fluid composition works
near pore-throat, expands to create network, and thus, air lock passage.
[0045] The present invention also provides a process for preparing the drilling fluid
composition and injecting into a wellbore which comprises the steps as provided herein below.
[0046] A first mud pit mixture is prepared by mixing one or more stabilizers and one or more
surfactants. The one or more stabilizers are selected from a group consisting of saturated fatty
acids, un-saturated fatty acids and polyalcohols. The saturated fatty acid preferably employed
in preparing the first mixture is stearic acid. The un-saturated fatty acid preferably employed
in preparing the first mixture is oleic acid. The polyalcohol preferably employed in preparing
the first mixture is polyvinyl alcohol. The one or more surfactants are selected from a group
consisting of anionic surfactants and non-ionic surfactants. The anionic surfactants preferably
employed in preparing the first mixture are alkyl ether sulphonates. The non-ionic surfactants
preferably employed in preparing the first mixture are linear primary alcohol ethoxylates. The
one or more surfactants employed in preparing the first mixture may further comprise a cosurfactant.
The co-surfactant employed in preparing the first mixture is amphoteric in nature,
preferably comprising betaine group of compounds.
[0047] The first mud pit mixture of the present invention may generally comprise materials well
known in the art to provide various characteristics or properties to the drilling fluid composition.
Thus, the drilling fluid composition may comprise one or more Polyols and fluid loss control
additives. The fluid loss control additives further restrict the entry of liquid from the fluid to the
contacted shale. Representative fluid loss control additives known in the art generally control
filtration loss. Such additives may include partially solubilized starch, gelatinized starch, starch
derivatives, cellulose derivatives, humic acid salts (lignite salts), lignosulfonates, gums,
synthetic water soluble polymers, and mixtures thereof. Synthetic polymers may comprise
Hydroxy ethyl cellulose (HEC). Further, to achieve a basic pH in the range of 9 to 10, a pH
buffering agent may be added to the drilling fluid composition. The pH buffering agent may be
selected from a group consisting of potassium hydroxide, potassium carbonate, potassium
humate, sodium hydroxide, sodium carbonate, sodium humate, magnesium oxide, calcium
hydroxide, zinc oxide, and mixtures thereof. The preferred pH buffering agent is magnesium
oxide.
[0048] A second mud pit mixture is prepared by mixing an aqueous liquid and a low shear rate
viscosity enhancer. The aqueous liquid of the present invention, in which the low shear rate
viscosity enhancer is hydrated, may be any aqueous liquid which is compatible with the
enhancer employed. The aqueous liquid may be selected from a group consisting of technical
water, sea water, and brine. The low shear rate viscosity enhancer is selected from a group
consisting of water-soluble polymers. The low shear rate viscosity enhancer increases the low
shear rate viscosity of the drilling fluid composition such that the composition exhibits
improved characteristics such as high yield stress and shear thinning behavior. The low shear
rate viscosity enhancer preferably comprises bio-polymers produced by the action of bacteria,
fungi, or other microorganisms on a suitable substrate.
[0049] The second mud pit mixture of the present invention may generally comprise viscosifiers
or suspending agents in addition to the bio-polymers required, weighting agents, corrosion
inhibitors, soluble salts, biocides, fbngicides, seepage loss control additives, bridging agents,
deflocculants, lubricity additives, shale control additives, and other additives as desired. The
biocides may comprise aldehyde group of compounds generally used to eliminate any bacterial
growth. The shale control additives employed in the drilling fluid composition of the present
invention may comprise potassium chloride and choline chloride. Other additives employed in
the drilling fluid composition of the present invention may comprise soda ash for reducing the
hardness of water.
[0050] The first and the second mud pit mixtures are thoroughly mixed in a silverson mixer to
generate stable microbubbles. The present invention eliminates the use of any specific device
for creating microbubbles such as a cavitation device or a microbubble generator. The present
invention employs a silverson mixer which comprises an upper mixing head and a lower mixing
head facing opposite to each other. The upper head pulls ingredients down from the surface and
provides a coarse disintegration action while the lower head draws materials up from the base
of the mixer which further reduces the particle size to accelerate solubilisation. This combined
effect of the two opposite heads of the mixer properly mixes the buoyant materials of the
mixtures which are required to be dispersed rapidly to create microbubbles. Alternatively, in
accordance with the present invention, when mixing of the first and the second mud pit mixtures
is done with hoppers, agitators employed in the mud pits create sufficient shearing to disperse
all ingredients thoroughly and create microbubbles. The mixing is done at an ambient
temperature in the range of 60 to 70°C and at a pressure in the range of 3.5 1 to 4.92 kg/cm2 to
obtain a drilling fluid composition comprising stable microbubbles of weight 0.7 Specific
gravity (SG). Bubbles created are finally divided into microbubbles, thereby reducing the
density of the composition. The microbubbles, in accordance with the present invention, are
substantially uniform in size.
[0051] The drilling fluid composition comprising the microbubbles is directed to a rig pump,
which injects the drilling fluid composition into a wellbore, where it picks up drill cuttings made
by the drill and returns them to the surface, wherefiom the drill cuttings and other solids are
removed. The drilling fluid composition may be circulated in the wellbores having a bottomhole
temperature of 80 to 90°C at a speed in the range of 1.8 to 3.41 m3/min and at a pressure
in the range of 9.70 to 161.7 kg/cm2. The drilling fluid composition is under considerable
pressure which is composed of hydrostatic pressure as well as pressure loss created by the
circulating system. This fluid pressure, apparently, compensates for the excess pressure within
the microbubbles such that the microbubbles are stabilized for a period of time until they are
circulated up the borehole. This allows the microbubbles to penetrate within the pore spaces of
the exposed formation with lower pore pressure and expand within the formation, and seal the
pore spaces from the entry of any fluid. Microfractures and such other formations are filled with
the microbubbles which likewise expand within the formation to seal the microfractures. After
completion of the drilling operation, the drilling fluid may be returned for recycle and
recirculation.
[0052] In accordance with the present invention, the drilling fluid composition comprising
stable microbubbles is obtained by increasing the Low Shear rate Viscosity of the composition.
A microbubble is made up of a core comprising an internal phase, usually of air or gas,
encapsulated in an outer viscous shell. This shell contains surfactant molecules positioned in
such a way that they produce an effective barrier against coalescence with adjacent
microbubbles. In accordance with an embodiment of the present invention, a blend of two
different surfactants along with one or more stabilizers are added in the drilling fluid
composition, as particularly disclosed herein. In accordance with an embodiment of the present
invention, a co-surfactant is added to the drilling fluid composition, as particularly disclosed
herein, either continuously or intermittently until a desired quantity of stable microbubbles is
generated. In accordance with an embodiment of the present invention, low hydrophilelipophile
balance (HLB) surfactants, natural polymers and ionic charged polymers may be
added to enhance the stability of the microbubbles. In contrast to a normal air bubble which is
stabilized by a surfactant monolayer, the outer shell of a stable microbubble of the present
invention consists of a much robust surfactant tri-layer. The surfactant tri-layer shell protects
the bubble and helps to prevent leakage of air from the core and thus allows stable microbubble
to survive the downhole pressure during the drilling operations. The stability of microbubble is
dependent on the bulk fluid viscosity and inter-facial tension. In accordance with an
embodiment of the present invention, the stability of the microbubbles may be enhanced by
incorporating one or more stabilizers into the drilling fluid composition as particularly disclosed
herein. The microbubbles of the present invention use encapsulated air available in most
circulating fluids which is stabilized by a polymer/surfactant shell. In accordance with an
embodiment of the present invention, the microbubbles are stable up to a temperature of 110°C.
[0053] The one or more surfactants employed in the drilling fluid composition of the present
invention to create stable microbubbles must be compatible with the low shear rate viscosity
enhancer present in the drilling fluid composition to create the desired low shear rate viscosity.
It may be apparent to a person of ordinary skill in the art that prior to preparing the drilling
fluids and generating the microbubbles, various anionic and non-ionic surfactants may be
screened for their suitability and compatibility and selected 'for use in the drilling fluid
composition of the present invention. In accordance with the present invention, in addition to
the selection of surfactants based on their compatibility with other additives in the drilling fluid
composition and their temperature sensitivity as disclosed herein above, screening of surfactants
is done based on a their half-life stability to determine if a surfactant can be used in the present
invention to generate the microbubbles. The one or more suitable surfactants are selected using
the screening procedure as disclosed herein below:
Hot rolling study is carried out by placing the drilling fluids comprising different surfactants or
surfactant blends in a roller oven for about16 hours at a required temperature and then cooling
at room temperature. Thereafter, the cooled fluid is agitated for about 1 to 2 minutes in Hamilton
beach mixture. Finally, the half-life of the microbubbles is calculated by the following formula
and microbubbles are selected based on their half-life calculations.
tl" firs) = 0.693/ K air, wherein K air is rate coefficient for loss of air
[0054] In accordance with the invention, drilling fluid composition has demonstrated surprising
and unexpected results. Empirically, drilling fluid composition of the present invention
exhibits, by way of example, enhanced low shear rate viscosity, high recirculation capability,
high yield stress, improved shear thinning behavior and enhanced stability than compositions
of the art. Further, compositions of the invention eliminate, by way of example, fluid loss,
formation damage, lost circulation and differential sticking problems.
[0055] Various drilling fluid compositions are prepared and tested for their applicability in
different drilling operations in oil and gas wells, in accordance with an embodiment of the
present invention. The preparation of the drilling fluid compositions and the tests conducted on
the compositions have been disclosed by way of examples.
Examples
[0056] In exemplary embodiment of the present invention, drilling fluid compositions are
prepared in accordance with oil and gas well drilling operation requirements. The drilling fluid
compositions are prepared by mixing different percentages of low shear rate viscosity enhancer
with different types of aqueous liquids, and different percentages of one or more surfactants and
one or more stabilizers. It may be apparent to a person of ordinary skill in the art that various
other chemicals may be added to the drilling fluids to conduct different tests.
Example 1- Drilling fluid comvosition with technical water
[0057] A first drilling fluid composition is prepared in about 500 mL technical water as aqueous
liquid by mixing therein, 1 .O% low shear rate viscosity enhancer, 0.3% anionic surfactant, 0.3%
non-ionic surfactant, 0.3% co-surfactant, 0.2% stabilizer-I (saturated fatty acid), 0.1%
stabilizer-I1 (unsaturated fatty acid) and 0.1% stabilizer-I11 (polyalcohol). Other ingredients
which may be added to the first drilling fluid composition include, by way of example, 0.1%
soda ash, 0.1% biocide, 0.4% fluid loss control additive, 0.1% pH buffering agent and 0.5%
polyol. The drilling fluid composition is then tested to check its applicability for different
drilling operations in wellbores. It may be apparent to a person of ordinary skill in the art that
the drilling fluids may be tested according to know-how in the art techniques, some of which
have been described above. Further, the test conditions comprise before and after hot roll study
at a temperature of up to 1 10°C, as described herein above.
[0058] First drilling fluid composition with technical water is provided in Table 1 and its
respective test results for different parameters have been listed in Table 2.
S.No.
I.
2.
3.
4.
5.
Component
Aqueous liquid
Low shear rate viscosity
enhancer
Ingredient
Technical water
Xanthomonas Compestris
polymer
Concentration
500 mL
1 .O%
Surfactant
Anionic Surfactant
Non-ionic surfactant
Co-surfactant
Blend of Polyoxyethylene
ether and Polyoxyethylene
sulphonate
Alkyl aryl polyether alcohol
Cocamido propyl betaine
0.3%
0.3%
0.3%
Stabilizer
Stabilizer-I- Saturated
fatty acid
Stabilizer-11- Unsaturated
fatty acid
Stabilizer-111- Polyalcohol
Fluid loss control additive
Stearic acid
Oleic acid
Poly vinyl alcohol
Hydroxy ethyl cellulose
W C )
0.2%
0.1%
0.1%
0.4%
6. 1 pH buffering agent I Magnesium oxide 0.1%
I I I
7.
I I I
(Table 1)
8.
I I
Soda Ash
9.
Pv (Plastic Viscosity)
(in CP)
Biocide
S.No.
1.
Yp (Yield Point)
(in lb/100 ft2)
-
Polyol
Gel 0110
(in lbI100 ft2)
Low shear rate viscosity (LSRV)
0.1%
Para formaldehyde
Properties
Specific Gravity
0.1%
Polyol Gd-I1
1 8. 1 HPHT fluid loss
0.5%
Before Hot Roll
testing (BHR)
0.72
I
After Hot roll testing at
11O0C (AHR)
0.75
7.
(Table 2)
[0059] Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. The test results indicate that the
rheology characteristics of the drilling fluid composition are high, owing to the presence of one
or more surfactants and one or more stabilizers. The test results indicate that the Yield Point
(YP) of the drilling fluid composition decreases from 1 10 to 104, and the Plastic Viscosity (PV)
of the drilling fluid composition decreases from 35 to 22.
API F/L (fluid loss)
9. LSRV (0.5rpm) / LSRV (1 OOrpm)
Shear Thinning Index (STI)
[0060] In addition, the test results indicate that the drilling fluid composition minimizes the API
fluid loss and HPHT (High Pressure High Temperature) fluid loss.
[0061] Low shear rate viscosity is also measured after hot roll testing at 1 1 O°C. It may be noted
by a person of ordinary skill in the art that it is difficult to achieve a high low shear rate viscosity
and even more difficult to maintain it. The test results indicate that the drilling fluid composition
of the present invention possesses a high low shear rate viscosity of 2,82,000 cp before the
testing and 1,10,000 cp after the testing. Thus, the hot roll test indicates that the drilling fluid
composition of the present invention prepared with technical water successfully attains a high
low shear rate viscosity which further allows the drilling fluid composition of the present
invention to achieve high recirculation capability, high yield stress, improved shear thinning
behavior and enhanced stability and therefore, work effectively in different drilling operations
of oil and gas wells.
Example 2- Drilling fluid Composition with technical water
[0062] A second drilling fluid composition is prepared in about 500 mL technical water as
aqueous liquid by mixing therein, 1.0% low shear rate viscosity enhancer, 0.3% anionic
surfactant, 0.3% non-ionic surfactant and 0.3% co-surfactant. There is no stabilizer added to the
drilling fluid composition to observe the effect of absence of the stabilizers on the drilling fluid
composition of the present invention. It may be apparent to a per'son of ordinary skill in the art
that various other chemicals may be added to the drilling fluids to conduct different tests. Other
ingredients which may be added to the second drilling fluid composition include, by way of
example, 0.1% soda ash, 0.1% biocide, 0.4% fluid loss control additive, 0.1% pH buffering
agent and 0.5% polyol. The drilling fluid composition is then tested to check its applicability
for different drilling operations in wellbores. It may be apparent to a person of ordinary skill in
the art that the drilling fluids may be tested according to know-how in the art techniques, some
of which have been described above. Further, the test conditions comprise before and after hot
roll study at a temperature of up to 1 1 O°C, as described herein above.
[0063] Second drilling fluid composition with technical water is provided in Table 3 and its
respective test results for different parameters have been listed in Table 4.
Component Ingredient I Concentration I
I I I
3. 1 Surfactant
1. I Aqueous liquid I Technical water
2.
I Blend of Polyoxyethylene /
500 mL
Anionic Surfactant I ether and Polyoxyethylene /
Low shear rate viscosity
enhancer
I sulphonate
Non-ionic surfactant I Alkyl aryl polyether alcohol / 0.3%
Xanthomonas Compestris
polymer
1 .O%
I I I
Stabilizer
I I
Co-surfactant I Cocamido propyl betaine
Nil
0.3%
Stabilizer-I- Saturated
fatty acid
Stearic acid
Stabilizer-11- Unsaturated
fatty acid
Stabilizer-111- Polyalcohol I Poly vinyl alcohol
Oleic acid
Nil
Fluid loss control additive
Nil
pH buffering agent I Magnesium oxide
Biocide I Para formaldehyde I 0.1% I
Hydroxy ethyl cellulose
(HEC)
0.1%
I I
Pol yo1 I Polyol Gd-I1 I 0.5% I
0.4%
Soda Ash
(Table 3)
- 0.1%
(in CP)
S.No.
1.
Properties Before Hot Roll
Specific Gravity
After Hot roll testing at
4.
testing (BHR)
0.82
Yp (Yield Point)
[0064] Based on test results, various observations can be drawn. It may be apparent to a person
1 10°C (AHR)
0.84
5.
6.
7.
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. The test results indicate that the
(Table 4)
(in lb1100 ft2)
Gel 0110
(in lb1100 ft2)
Low shear rate viscosity (LSRV)
LSRV (0.5) / LSRV (100)
Shear Thinning Index (STI)
rheology characteristics of the drilling fluid composition are low, owing to the absence of
stabilizers. The test results indicate that the Yield Point (YP) of the drilling fluid composition
25/40
1,44,000 cp
decreases from 76 to 49, and the Plastic Viscosity (PV) of the drilling fluid composition
1 5/22
12,000 cp
62050 / 1600
38
decreases from 22 to 1 1.
[0065] Low shear rate viscosity is also measured after hot roll testing at 1 1 O°C. It may be noted
by a person of ordinary skill in the art that it is difficult to achieve a high low shear rate viscosity
and even more difficult to maintain it. The test results indicate that the drilling fluid composition
of the present invention possesses a reduced low shear rate viscosity of 12,000 cp afier the
testing. Thus, the comparative test results indicate that the drilling fluid composition of the
present invention comprising one or more stabilizers work more effectively in different drilling
operations of oil and gas wells.
Example 3- Drilling fluid Composition with sea water
[0066] A third drilling fluid composition is prepared in about 500 mL sea water as aqueous
liquid by mixing therein, 1.2% low shear rate viscosity enhancer, 0.3% anionic surfactant, 0.3%
non-ionic surfactant, 0.3% co-surfactant and 0.2% stabilizer4 (saturated fatty acid), 0.1%
stabilizer-I1 (unsaturated fatty acid) and 0.1% stabilizer-111 (polyalcohol). It may be apparent to
a person of ordinary skill in the art that various other chemicals may be added to the drilling
fluids to conduct different tests. Other ingredients which may be added to the third drilling fluid
composition include, by way of example, 0.1 % soda ash, 0.1 % biocide, 0.3% fluid loss control
additive, 0.1% pH buffering agent and 0.5% polyol. The drilling fluid composition is then tested
to check its applicability for different drilling operations in wellbores. It may be apparent to a
person of ordinary skill in the art that the drilling fluids may be tested according to know-how
in the art techniques, some of which have been described above. Further, the test conditions
comprise before and after hot roll study at a temperature of up to 1 10°C, as described herein
above.
[0067] Third drilling fluid composition with sea water is provided in Table 5 and its respective
test results for different parameters have been listed in Table 6.
$.
.i
6.. .6/". ? ..... .
V . . .EL-', *. F." 8. . - ." -7, . . ., a -- , ' .,
S.No.
1.
2.
3.
Component
Aqueous liquid
Low shear rate viscosity
enhancer
Ingredient
Sea water
Xanthomonas Compestris
polymer
Concentration
500 mL
1.2%
Surfactant
Anionic Surfactant
Non-ionic surfactant
Blend of Polyoxyethylene
ether and Polyoxyethylene
sulphonate
Alkyl aryl polyether alcohol
0.3%
0.3%
Stabilizer-I- Saturated
4.
fatty acid
Stabilizer-11- Unsaturated
Co-surfactant
fatty acid
Stabilizer-111- Polyalcohol
Fluid loss control additive
Stabilizer
Cocamido propyl betaine 0.3%
0.1%
Oleic acid
Stearic acid
Poly vinyl alcohol
0.2%
Hydroxy ethyl cellulose
W C )
0.3%
I
6. 1 pH buffering agent I Magnesium oxide
I I I
0.1%
7. I Soda Ash
I I I
(Table 5)
8. 1 Biocide I Para formaldehyde
I I I
Properties
-
0.1%
9.
Specific Gravity
0.1%
Pv (Plastic Viscosity)
(in CP)
Polyol
Yp (Yield Point)
(in lb1100 ft2)
Gel 0110
Polyol Gd-I1
(in lbI100 ft2)
0.5%
Low shear rate viscosity (LSRV)
API F/L (fluid loss)
LSRV (0.5) / LSRV (100)
Shear Thinning Index (STI)
(Tat
Before Hot Roll
testing (BHR)
After Hot roll testing at
llO°C (AHR)
[0068] Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. The test results indicate that the
rheology characteristics of the drilling fluid composition are high, owing to the presence of one
or more surfactants and one or more stabilizers. The test results indicate that the Yield Point
(YP) of the drilling fluid composition decreases from 100 to 80, and the Plastic Viscosity (PV)
of the drilling fluid composition increases from 25 to 30.
[0069] In addition, the test results indicate that the drilling fluid composition minimizes the API
fluid loss.
[0070] Low shear rate viscosity is also measured after hot roll testing at 1 1 O°C. It may be noted
by a person of ordinary skill in the art that it is difficult to achieve a high low shear rate viscosity
and even more difficult to maintain it. The test results indicate that the drilling fluid composition
of the present invention possesses a high low shear rate viscosity of 1,96,000 cp before the
testing and 1,20,000 cp after the testing. Thus, the hot roll test indicates that the drilling fluid
composition of the present invention prepared with sea water successfblly attains a high low
shear rate viscosity which further allows the drilling fluid composition of the present invention
to achieve high recirculation capability, high yield stress, improved shear thinning behavior and
enhanced stability and therefore, work effectively in different drilling operations of oil and gas
wells.
Example 4- Drilling; fluid composition with brine solution
[0071] A fourth drilling fluid composition is prepared in brine solution with 1.20 specific
gravity as aqueous liquid by mixing therein, 1.4% low shear rate viscosity enhancer, 0.3%
anionic surfactant, 0.3% non-ionic surfactant, 0.3% co-surfactant and 0.2% stabilizer-I
(saturated fatty acid), 0.1% stabilizer-I1 (unsaturated fatty acid) and 0.1% stabilizer-I11
(polyalcohol). It may be apparent to a person of ordinary skill in the art that various other
chemicals may be added to the drilling fluids to conduct different tests. Other ingredients which
may be added to the fourth drilling fluid composition include, by way of example, 0.1% soda
ash, 0.1% biocide, 0.5% fluid loss control additive, 0.6% pH buffering agent and 0.5% polyol.
The drilling fluid composition is then tested to check its applicability for different drilling
operations in wellbores. It may be apparent to a person of ordinary skill in the art that the drilling
fluids may be tested according to know-how in the art techniques, some of which have been
described above. Further, the test conditions comprise before and after hot roll study at a
temperature of up to 1 10°C, as described herein above.
100721 Fourth drilling fluid composition with brine solution is provided in Table 7 and its
respective test results for different parameters have been listed in Table 8.
S.No.
1.
2.
Ingredient
Brine solution (Sodium
chloride)
Xanthomonas Compestris
polymer
Component
Aqueous liquid
Low shear rate viscosity
enhancer
Concentration
1.20 Sp. Gr.
1.4%
3.
4.
5.
Surfactant
0.3%
0.3%
0.3%
Anionic Surfactant
Non-ionic surfactant
Co-surfactant
Blend of Polyoxyethylene
ether and Polyoxyethylene
sulphonate
Alkyl aryl polyether alcohol
Cocamido propyl betaine
Stabilizer
Stabilizer-I- Saturated fatty
acid
Stabilizer-11- Unsaturated fatty
acid
Stabilizer-111- Polyalcohol
Fluid loss control additive
Stearic acid
Oleic acid
Poly vinyl alcohol
Hydroxy ethyl cellulose (HEC)
0.2%
0.1%
0.1%
0.5%
6. / pH buffering agent
1 7. / Soda Ash
Magnesium oxide 0.6%
Para formaldehyde 0.1%
Polyol Gd-I1 0.5%
(Table 7)
After Hot roll testing at
1.
Before S.No. Hot Roll
I I I
I I I I I
(Table 8)
Properties
Specific Gravity
3. I Low shear rate viscosity (LSRV)
4.
100731 Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. Low shear rate viscosity is
measured after hot roll testing at 1 1 O°C. It may be noted by a pe;son of ordinary skill in the art
that it is difficult to achieve a high low shear rate viscosity and even more difficult to maintain
it. The test results indicate that the drilling fluid composition of the present invention possesses
a high low shear rate viscosity of 3,50,000 cp before the testing and 1,30,000 cp after the testing.
Thus, the hot roll test indicates that the drilling fluid composition of the present invention
prepared with brine solution successfully attains a high low shear rate viscosity which further
allows the drilling fluid composition of the present invention to achieve high recirculation
testing (BHR)
1.01
3,50,000 cp
LSRV (0.5rpm) / LSRV (100rpm)
Shear Thinning Index (STI)
capability, high yield stress, improved shear thinning behavior and enhanced stability and
therefore, work effectively in different drilling operations of oil and gas wells.
llO°C (AHR)
1.02
1,30,000 cp
4679011452
32
Example 5- Drilling fluid com_positions with shale control additives
[0074] A fifth, sixth and seventh drilling fluid compositions are prepared with different
concentrations of shale control additives to test the suitability of the drilling fluid compositions
of the present invention with such additives for depleted reservoirs with alternate sand and shale
formation. It may be apparent to a person of ordinary skill in the art that various other chemicals
may be added to the drilling fluids to conduct different tests. A fifth drilling fluid composition
is prepared by mixing therein, 2% Choline chloride as shale control additive, 1.0% low shear
rate viscosity enhancer, no anionic surfactant, 0.3% non-ionic surfactant, 0.3% co-surfactant
and 0.2% stabilizer-I (saturated fatty acid), 0.1% stabilizer-I1 (unsaturated fatty acid) and 0.1%
stabilizer-I11 (polyalcohol). Other ingredients which may be added to the fifth drilling fluid
composition include, by way of example, 0.1% soda ash, 0.1% biocide, 0.3% fluid loss control
additive, 0.3% pH buffering agent and 0.5% polyol. A sixth drilling fluid composition is
prepared by mixing therein, 4% Potassium chloride as shale control additive, 1.0% low shear
rate viscosity enhancer, no anionic surfactant, 0.3% non-ionic surfactant, 0.3% co-surfactant
and 0.2% stabilizer-I (saturated fatty acid), 0.1% stabilizer-I1 (unsaturated fatty acid) and 0.1%
stabilizer-I11 (polyalcohol). Other ingredients which may be added to the sixth drilling fluid
composition include, by way of example, 0.1% soda ash, 0.1% biocide, 0.3% fluid loss control
additive, 0.3% pH buffering agent and 0.5% polyol. A seventh drilling fluid composition is
prepared by mixing therein, 6% Potassium chloride as shale control additive, 1.0% low shear
rate viscosity enhancer, 0.4% anionic surfactant, 0.3% non-ionic surfactant, 0.3% co-surfactant
and 0.2% stabilizer-I (saturated fatty acid), 0.1% stabilizer-I1 (unsaturated fatty acid) and 0.1%
stabilizer-I11 (polyalcohol). Other ingredients which may be added to the seventh drilling fluid
composition include, by way of example, 0.1% soda ash, 0.1% biocide, 0.3% fluid loss control
additive, 0.3% pH buffering agent and 0.1% polyol. These drilling fluid compositions are then
tested to check its applicability for different drilling operations in wellbores. It may be apparent
to a person of ordinary skill in the art that the drilling fluids may be tested according to knowhow
in the art techniques, some of which have been described above. Further, the test conditions
comprise before and after hot roll study at a temperature of up to 1 10°C, as described herein
above.
[0075] Fifth, sixth and seventh drilling fluid compositions with shale control additives are
provided in Table 9 and their respective test results for different parameters have been listed in
Table 10.
Nil
S.No.
1.
2.
Component
Shale control
additive
Low shear rate
viscosity enhancer
Ingredient
Choline chloride
Potassium chloride
Xanthomonas
Compestris
polymer
3.
4.
Drilling
Fluid
Composition
-5
2%
-
1 .O%
Drilling
Fluid
Composition
-6
-
4%
1 .O%
Surfactant
Drilling
Fluid
Composition
-7
-
6%
1 .O%
0.3%
0.3%
0.2%
Anionic Surfactant
Non-ionic
surfactant
Co-surfactant
0.4%
0.3%
0.3%
0.2%
Blend of
Polyoxyethylene
ether and
Polyoxyethylene
sulphonate
Alkyl aryl
polyether alcohol
Cocamido propyl
betaine
Nil
0.3%
0.3%
Stabilizer
Stabilizer-1-
Saturated fatty acid
Stearic acid 0.2%
Stabilizer-11-
Unsaturated fatty
acid
Oleic acid
0.1%
Poly vinyl alcohol
Polyalcohol
Fluid loss control
0.3%
additive cellulose (HEC)
pH buffering agent
Soda Ash
Magnesium oxide 1 0.3%
Biocide Para formaldehyde I 0.1 %
Pol yo1 Polyol Gd-I1 0.5%
(Table 9)
Properties After Hot Roll After Hot roll After Hot roll
I testing at I testing at I testing at 92OC I
I llO°C (AHR) I llO°C (AHR) I (MR) I
I Drilling Fluid I Drilling Fluid I Drilling Fluid I
Compositiond Composition-6 Composition-7
Specific Gravity 0.85 0.85 0.88
Low shear rate viscosity 44,000 cp 50,000 cp 1,28,000 cp
(LSRV)
LSRV (0.5) / LSRV (100) 6670611380
Shear Thinning Index (STI) 48
(Table 10)
[0076] Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. Low shear rate viscosity is
measured after hot roll testing at 1 1 0°C and 92°C. For drilling depleted reservoirs with alternate
sand and shale formation and minimal mud loss, a drilling fluid with low to moderate low shear
rate viscosity is required. The test results indicate that the drilling fluid compositions of the
present invention possess a low shear rate viscosity as low as 44,000 cp which may effectively
be used to drill such depleted reservoirs with shale formation and minimal mud loss. Thus, the
hot roll test indicates that the drilling fluid compositions of the present invention prepared with
shale control additives successfully attain a low to moderate low shear rate viscosity particularly
suited for drilling depleted reservoirs.
Example 6- Effect of higher temperature on the Drilling fluid composition of the present
invention
[0077] To test the effect of higher temperature on the drilling fluid composition of the present
invention, an eighth drilling fluid composition is prepared in 500 mL sea water as aqueous liquid
by mixing therein, 1.2% low shear rate viscosity enhancer, 0.4% anionic surfactant, 0.4% nonionic
surfactant, 0.3% co-surfactant and 0.2% stabilizer-I (saturated fatty acid), 0.1% stabilizer-
I1 (unsaturated fatty acid) and 0.1 % stabilizer-I11 (polyalcohol). It may be apparent to a person
of ordinary skill in the art that various other chemicals may be added to the drilling fluids to
conduct different tests. Other ingredients which may be added to the eighth drilling fluid
composition include, by way of example, 0.1% soda ash, 0.1% biocide, 0.3% fluid loss control
additive, 0.3% pH buffering agent and 0.5% polyol. The drilling fluid composition is then tested
to check its applicability for different drilling operations in wellbores. It may be apparent to a
person of ordinary skill in the art that the drilling fluids may be tested according to know-how
in the art techniques, some of which have been described above. Further, the test conditions
comprise before and after hot roll study at a temperature of up to 130°C, as described herein
above.
[0078] Eighth drilling fluid composition with sea water is provided in Table 11 and its
respective test results for different parameters have been listed in Table 12.
Component Ingredient 1 Concentration
Aqueous liquid
I
Low shear rate viscosity
Sea water
Xanthomonas Compestris
enhancer polymer
Surfactant
500 mL
1.2%
Blend of Polyoxyethylene
Anionic Surfactant ether and Polyoxyethylene
sulphonate
Non-ionic surfactant Alkyl aryl polyether alcohol
Stabilizer
I
Stabilizer-I- Saturated
fatty acid
Cocamido propyl betaine
Stearic acid
0.3%
Stabilizer-11- Unsaturated
fatty acid
Poly vinyl alcohol
Fluid loss control additive
0.1%
Hydroxy ethyl cellulose
(HEC)
6. 1 pH buffering agent
0.3%
Magnesium oxide
I
7. I Soda Ash
I
8. 1 Biocide Para formaldehyde 0.1%
I I I I I
(Table 1 1)
I
9. 1 Polyol I Polyol Gd-I1
130°C (AHR)
0.5%
S.No. Properties
1.
2
Before Hot Roll
Specific Gravity
PH
After Hot roll testing at
0.75
9.97
0.75
9.36
Pv (Plastic Viscosity)
(in CP)
f I
(in lb/100 fi2) I I
48
Yp (Yield Point)
(in lb1100 ft2)
Gel 0110
27
I I
(Table 12)
150
55/60
Low shear rate viscosity (LSRV) 1 1,88,000 cp
[0079] Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. The test results indicate that the
rheology characteristics of the drilling fluid composition are high, owing to the presence of one
or more surfactants and one or more stabilizers. The test results indicate that the Yield Point
(YP) of the drilling fluid composition decreases from 150 to 8 1, and the Plastic Viscosity (PV)
of the drilling fluid composition decreases from 48 to 27.
8 1
35/39
0
[0080] Low shear rate viscosity is also measured after hot roll testing at 130°C. It may be noted
by a person of ordinary skill in the art that it is difficult to achieve a high low shear rate viscosity
and even more difficult to maintain it. The test results indicate that the drilling fluid composition
of the present invention possesses no low shear rate viscosity at a high temperature of 130°C.
Thus, the comparative test results indicate that the drilling fluid composition of the present
invention work effectively at a temperature below 130°C, preferably, at a temperature up to
110°C for different drilling operations of oil and gas wells.
Example 7- Properties of the Drilling fluid composition of the present invention
[0081] The test results for different parameters of the drilling fluid composition of the present
invention is provided in Table 13.
I S.No. 1 Properties I Before Hot Roll I After Hot roll testing1 at
I I I testing (BHR)
1 10°C (AHR)
1.
2
3.
Specific Gravity
PH
4.
1 7- 1 API F/L I 7.2 ml I 6.0 ml I
Pv (Plastic Viscosity)
(in CP)
5.
6.
0.79 (6.5 ppg)
9.71
Yp (Yield Point)
(in lbI100 ft2)
(Table 13)
0.79 (6.5 ppg)
9.24
4 1
Gel 0110
(in lb/100 ft2)
Low shear rate viscosity (LSRV)
8.
9.
10.
[0082] Based on test results, various observations can be drawn. It may be apparent to a person
of ordinary skill in the art that these observations are merely examples and several other
inferences and observations can be drawn from the test results. The test results indicate that the
rheology characteristics of the drilling fluid composition are high, owing to the presence of one
or more surfactants and one or more stabilizers. The test results indicate that the Yield Point
(YP) of the drilling fluid composition decreases from 96 to 81, and the Plastic Viscosity (PV)
of the drilling fluid composition decreases from 41 to 27.
27
96
[0083] Low shear rate viscosity is also measured after hot roll testing at 1 1 O°C. It may be noted
by a person of ordinary skill in the art that it is difficult to achieve a high low shear rate viscosity
and even more difficult to maintain it. The test results indicate that the drilling fluid composition
8 1
34/43
1,28,000 cp
HPHT F/L 1 10°C & 35.1 kg/cm2
Lubricity coefficient
LSRV (0.5) / LSRV (100)
Shear Thinning Index (STI)
35/39
84,000 cp
-
-
0.9 ml
0.1 1
106000/1 908
5 5
of the present invention possesses a high low shear rate viscosity of 1,28,000 cp before the
testing and 84,000 cp after the testing. Thus, the hot roll test indicates that the drilling fluid
composition of the present invention successfully attains a high low shear rate viscosity which
further allows the drilling fluid of the present invention to achieve high recirculation capability,
high yield stress, improved shear thinning behavior and enhanced stability and therefore, work
effectively in different drilling operations of oil and gas wells.
Field demonstration-1 with the Drilling fluid composition of the present invention
[0084] The field demonstration was success~llyp erformed at South Heera field in HSD- 8H
(Rig- Trident-11) well. Drilling was performed on a section which consisted of Mukta & Bassein
formations having a known history of drilling fluid loss of 40 to 60 Barrels per hour with drilling
fluids of the state of the art. Drilling was performed with the drilling fluid composition of the
present invention. Drilling of this section was successfully completed in 28 hours without any
loss of drilling fluid and zero well bore complications. There was no complication while drilling
or wiper trip and 5"perforated liner was lowered smoothly.
Field demonstration-2 with the Drilling fluid composition of the present invention
[0085] Subsequent field trials have been done on WB-12-H (valiant Driller) and WN-1- 32
(GD Chaaru). The laboratory tests have shown favorable results. The feeding pressure to hopper
was in the range of 2.1 to 4.9 kg/cm2 for a water based mud. Micro-bubble mud preparation
(drilling fluid composition) was facilitated by jet shearing system and heavy duty mixing pumps
with proper suction at hopper. Drilling of this section was successfully completed without any
loss of drilling fluid and zero well bore complications.
Field demonstration3 with the Drilling fluid composition of the present invention
[0086] The field demonstration was successfully performed to drill the final phase (8W section)
of the well with a target depth (TD) of 2800m in Galeky field. The drilling was successfully
completed by drilling 581m length to target depth in 7 days without any complication. This
section covered mid tipam sand-2 (TS-2) through tipam sand-1 (TS-I) and lower Girujan clay
formations. TS-1 started at 2533.5m of measure depth (MD) and ended at 2701m (MD). The
well was drilled to 2812m (MD) in the TS-2 formation from 2231m (MD) in the Girujan clay
formation after lowering 9%'' casing at 2226m (MD). After successful completion of 8W
section drilling to target depth, all required electrologs were recorded successfblly. Thereafter,
final 5%" production casing was lowered upto bottom smoothly with casing shoe at 281 1m and
cemented successfully. The casing details are provided in Table No. 14.
[0087] Casinp details:
asing sizes Casing shoe depth (m) Drilling days
I Total- 57 /
I11 5%" 281 1 19
(Table 14)
[0088] Phase I:
The first phase of the well was drilled up to 505m with high viscous gel (HVG) and 13-318"
casing keeping shoe was lowered at 499m. Mud parameters were maintained as follows:
Specific gravity (SG): 1.05-1.08, Viscosity (Vis): 48-5 1 sec (seconds), and pH: 9.0.
[0089] Phase 11:
The well was drilled up to 223 1m in 12W section with Gel-carboxy methyl cellulose (CMC)-
Lignite mud system with inclination (INC)- 32.46O and azimuth (AZh4)- 307.32O at 2197.59m.
9-518" casing keeping shoe was lowered at 2226 m & Float/collar at 2201m. Mud circulation
was performed. Average SG of cement slurry was 1.90 with plug hit at the rate of 150 ksc
(kglsquare centimeter). This section covered alluvium, namsang, upper sandstone and upper
Girujan clay formations. Kick of point (KOP) was at 1576.26m. Mud parameters were
maintained as follows: SG: 1.1 1 - 1.17, Viscosity (Vis): 45-47 sec, pH: 9.0, API FluidlLoss (API
FIL): 10-12 cc (cubic centimeter), Plastic viscosity (Pv) I Yield Point (Yp) (PvlYp): 13-15129-
32, and Gel 0110: 10-13120-28.
[0090] Phase 111:
The final phase (223 1-28 12m) was drilled successfully using the drilling fluid composition of
the present invention. This section covered mid TS-2 through TS-1 and lower Girujan clay
formations. TS-1 started at 2533.5m (MD) and ended at 2701m (MD). RTEX-MLL-(Deep
shallow and medium Resistivity)- SP (Spontaneous) - GRC (Gama Ray-caliper) -0RIT logs in
the interval of 2800-2220m and Digital Acoustic Log-Gama Ray (DAL-GR) logs were
recorded. The 8W section was drilled in L-profile with 31° inclination in 304O azimuth. The
caliper logs showed washout in the Girujan clay section and gauged hole in TS-1 and TS-2 upto
target depth (28 12m, MD).
[0091] Mud Parameters were maintained as follows: SG: 0.95-1.06, Viscosity: 65-80 sec, API
FIL: 6.6- 5 . 2 C~ak~e ~thi ckness < 0.5mm, PvlYp: 12-14132-63, Gel 0110: 15-30128-36, Sand
0.3%, Solid 6%, LSRV (Centi Poise (CPS)): 104000-1 08000, KC1 3.58-3.8%, and Salinity 28.1 -
[0092] Production Testing:
SBT (Segmented Bond Tool) - GR (Gama Ray)- CCL (Casing Collar Locator) logs were
recorded fi-om 2786 -2150m. The intervals 2740 -2736 my 273 1- 2726 m & 2724 -27 19 m were
perforated in TS-2. The well was activated by compressor application. A zone of interest was
tested in TS-2 and results showed that the zone was an oil producer zone with poor influx of
oil. The parameters of zone were recorded as WIC (Water cut)- 90-98%, and water salinity: 1.05
[0093] Mud Parameters (Phase 111):
The results are provided in Table No. 15
(Table 15)
Results:
The results showed that the drilling was smooth and without any complication in drilling
8 %section of the well using drilling fluid composition of the present invention.
[0094] Based on the test results in Tables 1 to 15 and field demonstrations 1 to 3, it may be
apparent to a person skilled in the art that improvements may be made in various parameters
particularly required for a drilling fluid to work effectively in drilling well operations. These
improvements may include, without any limitation, increase in low shear rate viscosity,
reduction of fluid loss and increase in rheological parameters. It may be apparent from Tables
1 to 15 that the drilling fluid compositions of the present invention have achieved improvement
in almost all the properties or parameters. Furthermore, drilling fluid compositions with one or
more stabilizers and one or more surfactants in addition to bio-polymer show high low shear
rate viscosity, high recirculation capability, high yield stress, improved shear thinning behavior
and enhanced stability. Furthermore, the drilling fluid compositions of the present invention
may be prepared, without limitation, in technical water, sea water, and brine solution, each for
which possesses almost all properties or parameters suitable for different drilling operations of
oil and gas wells. In addition, the drilling fluid compositions of the present invention may
achieve a low to moderate low shear rate viscosity, particularly desired for drilling depleted
reservoirs with shale formation and minimal mud loss. Thus, it may be apparent to a person of
ordinary skill in the art, that drilling fluid compositions of the present invention have
demonstrated surprising and unexpected results.
ADVANTAGES OF THE PRESENT INVENTION:
[0095] The drilling fluid composition of the present invention offer the following advantages:
Improved desired parameters such as enhanced low shear rate viscosity, enhanced
recirculation capability, high yield stress, improved shear thinning behavior and
enhanced stability.
Cost-effective and time-saving system.
Elimination of fluid loss, formation damage, lost circulation and differential sticking
problems.
Useful in areas where the well activity and mud loss problems exist together. The
drilling fluid compositions of the present invention are capable of combating mud loss.
Useful in drilling through depleted reservoirs with alternate sand and shale formation.
Provides stability to multi-pressure sequences and boreholes, thereby saving precious
rig time.
May be circulated as conventional drilling fluid and conventional solid control
equipment may be used.
Solid free, therefore, no mud cake or very fine mud cake is formed. Thus, the chances
of differential sticking are minimized.
Biodegradable and therefore, there is no residue formed.
Does not require any elaborative arrangement to run as required in state of the art light
weight drilling fluids including air, foam, mist and hollow glass spheres.
[0096] While the present invention has been shown and described with reference to preferred
embodiments, it will be understood by those skilled in the art that various changes in form and
detail may be made therein without departing from or offending the spirit and scope of the
invention as defined by the appended claims.

We claim:
1. A drilling fluid composition comprising microbubbles, the composition comprising:
a) a low shear rate viscosity enhancer, wherein the low shear rate viscosity enhancer is
present in the range of 1 % to 1.4% by weight in the composition;
b) at least one surfactant, wherein the at least one surfactant is present in the range of 0.3%
to 0.4% by weight in the composition;
c) at least one stabilizer, wherein the at least one stabilizer is present in the range of 0.1 %
to 0.5% by weight in the composition; and
d) balance comprising an aqueous liquid;
wherein the composition comprises 15% to 25% by volume of microbubbles;
wherein the composition exhibits a shear thinning index of at least 10; and
wherein. the composition exhibits a low shear rate viscosity in the range of 25,000
centipoise to 130,000 centipoise.
2. The composition as claimed in claim 1, wherein the microbubbles are stable up to a
temperature of 1 10°C.
3. The composition as claimed in claim 1, wherein the low shear rate viscosity enhancer is a
polymer, preferably a bio-polymer, which is dispersed in the aqueous liquid.
4. The composition as claimed in claim 3, wherein the low shear rate viscosity enhancer is a
bio-polymer produced by the action of bacteria Xanthomonas compestris.
5. The composition as claimed in claim 1, wherein the surfactant is selected from a group
consisting of anionic surfactants and non-ionic surfactants.
6. The composition as claimed in claim 5, wherein the anionic surfactant is present in the range
of 0.3% to 0.4% by weight in the composition.
7. The composition as claimed in claims 5 and 6, wherein the anionic surfactant is an alkyl
ether sulphonate.
8. The composition as claimed in claim 7, wherein the anionic surfactant is a mixture of
polyoxyethylene ether and polyoxyethylene sulphonate.
9. The composition as claimed in claim 5, wherein the non-ionic surfactant is present in the
range of 0.3% to 0.4% by weight in the composition.
10. The composition as claimed in claims 5 and 9, wherein the non-ionic surfactant is a linear
primary alcohol ethoxylate.
11. The composition as claimed in claim 10, wherein the non-ionic surfactant is alkyl aryl
polyether alcohol.
12. The composition as claimed in claim 1, wherein the composition comprises a co-surfactant
selected from betaine group of compounds, preferably cocamidopropyl betaine.
13. The composition as claimed in claim 12, wherein the co-surfactant is present in an amount
of 0.3% by weight in the composition.
14. The composition as claimed in claim 1, wherein the stabilizer is selected fiom a group
consisting of saturated fatty acids, un-saturated fatty acids and polyalcohols.
15. The composition as claimed in claim 14, wherein the saturated fatty acid is present in the
range of 0.1% to 0.2% by weight in the composition.
16. The composition as claimed in claims 14 and 15, wherein the saturated fatty acid is stearic
acid.
17. The composition as claimed in claim 14, wherein the un-saturated fatty acid is present in an
amount of 0.1 % by weight in the composition.
18. The composition as claimed in claims 14 and 17, wherein the un-saturated fatty acid is oleic
acid.
19. The composition as claimed in claim 14, wherein the polyalcohol is present in the range of
0.1% to 0.5% by weight in the composition.
20. The composition as claimed in claims 14 and 19, wherein the polyalcohol is polyvinyl
alcohol.
21. The composition as claimed in claim 1, wherein the aqueous liquid is selected fiom a group
consisting of technical water, sea water, and brine.
22. The composition as claimed in claim 21, wherein brine comprises one or more soluble salts
selected from a group consisting of sodium chloride, potassium chloride, calcium chloride,
sodium bromide, potassium bromide, calcium bromide, zinc bromide, sodium formate,
potassium formate and cesium formate, preferably sodium chloride.
23. The composition as claimed in claim 1, wherein the aqueous liquid comprises shale
stabilizers.
24. The composition as claimed in claim 23, wherein the shale stabilizers comprise potassium
chloride and choline chloride.
25. The composition as claimed in claim 24, wherein potassium chloride is present in the range
of 4.0% to 6.0% by weight in the composition
26. The composition as claimed in claim 24, wherein choline chloride is present in an amount
of 2.0% by weight in the composition.
27. The composition as claimed in claims 1 to 26 comprising one or more viscosifiers,
suspending agents, weighting agents, corrosion inhibitors, soluble salts, biocides,
fungicides, bridging agents, deflocculants, lubricity additives, fluid loss control additives,
pH buffering agents, and other additives.
28. The composition as claimed in claim 27, wherein the biocide is present in an amount of
0.1% by weight in the composition.
29. The composition as claimed in claims 27 and 28, wherein the biocide is paraformaldehyde.
30. The composition as claimed in claim 27, wherein the fluid loss control additive is selected
from a group consisting of partially solubilized starch, gelatinized starch, starch derivatives,
cellulose derivatives, humic acid salts (lignite salts), lignosulfonates, gums, synthetic water
soluble polymers, and mixture thereof.
3 1. The composition as claimed in claim 30, wherein the fluid loss control additive is present in
the range of 0.3% to 0.5% by weight in the composition.
32. The composition as claimed in claims 30 and 3 1, wherein the fluid loss control additive is
Hydroxy ethyl cellulose (HEC).
33. The composition as claimed in claim 27, wherein the pH buffering agent is selected from a
group consisting of potassium hydroxide, potassium carbonate, potassium humate, sodium
hydroxide, sodium carbonate, sodium humate, magnesium oxide, calcium hydroxide, zinc
oxide, and mixtures thereof.
34. The composition as claimed in claim 33, wherein the pH buffering agent is present in the
range of 0.1% to 0.6% by weight in the composition.
35. The composition as claimed in claims 33 and 34, wherein the pH buffering agent is
magnesium oxide.
36. The composition as claimed in claim 27, wherein other additives comprise soda ash and
polyol.
37. The composition as claimed in claim 36, wherein soda ash is present in an amount of 0.1%
by weight in the composition.
38. The composition as claimed in claim 36, wherein polyol is present in an amount of 0.5% by
weight in the composition.
39. The composition as claimed in claims 1 to 38, wherein the composition exhibits a moderate
low shear rate viscosity in the range of 25,000 centipoise to 50,000 centipoise for drilling
depleted reservoirs.
40. The composition as claimed in claims 1 to 22 and 27 to 38, wherein the composition exhibits
a high low shear rate viscosity in the range of 100,000 centipoise to 130,000 centipoise.
41. The composition as claimed in one or more of the preceding claims, wherein the density of
the composition is preferably in the range of 0.48 to 7.2 g/cm3.
42. The composition as claimed in one or more of the preceding claims, wherein the
composition operates at a pressure in the range of 24.6 to 35 1 kg/cm2 and a temperature of
up to 1 10°C.