DESC:FIELD OF THE INVENTION
The present invention relates to drilling fluid system. More particularly, the present invention relates to a water-based drilling fluid system for controlling loss circulation in wellbores.

BACKGROUND
Natural resources such as oil and gas present in the subterranean formation are recovered by drilling a wellbore that penetrates the formation. During the drilling a fluid, called drilling fluid or mud, is injected into the well through a drill pipe and re-circulated to the surface in the annular area formed by the wellbore wall and drill string. Once back at the surface, the drilling fluid is physically and chemically treated and conditioned before it is pumped back into the well. The drilling fluid can be water-based, oil-based, pseudo-oil based or foam-based. Water-based drilling fluids are preferred these days over oil-based or pseudo oil-based for economic and environmental reasons.

The drilling operation involves driving by rotation a drilling apparatus including a column of drill pipes to the bottom of which is attached a multi-pronged/toothed drill bit. As the drill bit descends, it generates “cuttings”, or small bits of stone, clay, shale or sand. To facilitate drilling, these cuttings are to be continuously removed from the vicinity of the drill bit at the bottom of the hole. The drilling fluid is pumped down-hole through the drill pipe. The cuttings are removed from the down-hole to the surface by the drilling fluid through the annular space between the formation and the drill pipe.

In drilling operations the role of a drilling fluid is extremely important, and to perform these functions, an efficient drilling fluid must exhibit characteristics, such as desired rheological properties, capable of cooling and lubricating the drill bit as it grinds through the earth, fluid loss prevention, stability under various temperature and pressure operating conditions, stability against contaminating fluids, such as salt water, calcium sulfate, cement and potassium contaminated fluids, etc. A wide variety of additives may be added to the drilling fluid formulation to achieve the above properties.

Water-based drilling fluids have water as the continuous phase. The continuous phase may contain several dissolved or dispersed substances, including, alkalis, salts and surfactants, organic polymers in colloidal state, droplets of emulsified oil and various insoluble substances, such as barite, clay and cuttings in suspension.

One such conventional water-based drilling fluid is taught by US Pat. No. 5789349 which comprises a cross-linked polymeric fluid loss control agent obtained by reaction of an acrylamide monomer, a sulfonated anionic monomer and a non-sulfonated anionic monomer. Another aqueous drilling fluid is taught by US Pat. No. 7829506 which teaches a drilling fluid with aqueous base fluid, viscosifying polymer, starch and chloride-free clay stabilizer. Yet another water-based wellbore fluid is taught by US Pub. No. 20110136701 which comprises an aqueous fluid, a micronized weighting agent, a polysaccharide derivative, and at least one fatty acid ester derivative.

During the drilling operation, lost circulation occurs when drilling fluid flows into the geological formations instead of returning up from the annular area. Lost circulation can be a serious problem during the drilling of an oil or gas well as wellbore instability may result from shale hydration and dispersion. These conventional water-based drilling fluids used to drill through water-sensitive shale formations may cause wellbore instability. The polymers such as polyanionic cellulose and partially-hydrolyzed polyacrylamide are generally added in the conventional water-based drilling fluid system. Addition of these polymers in the fluid preparation may cause poor dispersion during the mixing process, and lead to formation of hard lumps or fish eyes, thereby reducing the product efficiency. The fish eyes are insoluble polymers surrounded by a gelatinous hydrated polymer which inhibits the hydration process, thereby making the dispersion of the fish eyes difficult. Other drawbacks of the traditionally used drilling fluid systems include wellbore instability, fracture carbonate formation, vugular formation, stuck pipes and depleted zones.

Another drawback of the known drilling fluid systems is that they may pose disposal problems. Stricter environmental regulations and guidelines around the world have made it a mandate to minimize environmental impact caused by the drilling operations. To meet the new stringent regulations, the oil and gas industry is striving to develop new drilling fluids and ancillary additives that meet the present demands in the field of wellbore drilling. Thus, there is a need to develop drilling fluids and additives thereof that have very little or no adverse effects on the environment or on the drilling economics. Yet another drawback of the known water-based drilling fluid systems is that they do not provide a high-performance efficiency comparable to that of the oil-based drilling fluid systems with regard to formation damage, lubricity, wellbore stability and penetration rates.

There is therefore felt a need to develop a rapid mix, water-based drilling fluid system which will overcome the afore-noted drawbacks of the traditional water-based drilling fluid systems.

OBJECTS
Accordingly, an object of the present invention is to provide a rapid-mix, water-based drilling fluid system for controlling loss circulation. The drilling fluid system of the present invention aims to improve wellbore stability, enhance the rate of penetration, provide effective shale inhibition, control high temperature high pressure (HTHP) filtrate loss, improve lubricity and reduce the risk of stuck pipe.

The drilling fluid system of the present invention has an improved rheology profile with no lumps or “fish eyes”, thereby, improving the Low Shear Rate Viscosity (LSRV) and gel strength.

The drilling fluid system of the present invention inhibits shale or gumbo clays from hydrating and minimizes bit balling. Further, the drilling fluid system of the present invention promotes cuttings encapsulation and minimizes cuttings dispersion.

Other objects, aspects and advantages of the present invention will be more apparent from the following description.

SUMMARY
According to an embodiment of the present invention, there is disclosed a drilling fluid system for controlling loss circulation, the system having an aqueous base fluid comprising:
at least one viscosifier including a biopolymer present in a concentration in the range of 2 to 10 % by weight;
at least one shale inhibitor including a liquid polyamine present in a concentration in the range of 10 to 30 % by weight;
at least one encapsulating agent including a cross-linked, anionic acrylamide polymer present in a concentration in the range of 2 to 6 % by weight;
at least one lubricating agent and borehole stabilizer including a high viscosity polymer present in a concentration in the range of 6 to 14 % by weight; and
at least one filtration control additive including a non-ionic starch derivative in a concentration in the range of 6 to 15 % by weight.

According to a preferred embodiment of the present invention, the drilling fluid system comprises at least one corrosion inhibitor including a liquid polyamine present in a concentration in the range of 2 to 4 % by weight.

According to a preferred embodiment of the present invention, the drilling fluid system has a pH in the range of 9.0 to 10.0.

According to a preferred embodiment of the present invention, the viscosifier is a biopolymer selected from polysaccharides and modified polysaccharides including xanthan gum, guar gum, wellum gums, gellan gums, succinoglycan, succinoglycan polysaccharides, scleroglycan, schleroglucan polysaccharides, polyvinylsaccharides, o-carboxychitosans, polyanionic cellulose, carboxymethylcellulose, hydroxyethylcellulose, hydroxypropylcellulose, natural and modified starches, and combinations thereof.

According to a preferred embodiment of the present invention, the viscosifier is clarified xanthan gum. According to one aspect of the present invention, the viscosifier is pre-dispersed in a water-miscible, oil-free and clay-free carrier fluid to obtain a drilling fluid system with improved rheology profile.

According to a preferred embodiment of the present invention, the at least one encapsulating agent is a cross-linked, anionic acrylamide polymer selected from polyacrylamide, partially hydrolyzed polyacrylamide, acrylamide copolymers, acrylamide terpolymers, acrylamide tetrapolymers, and combinations thereof. According to one aspect of the present invention, the encapsulating agent is a fully cross-linked, anionic, dispersed acrylamide polymer. The acrylamide polymer is more preferably a partially hydrolyzed polyacrylamide (PHPA).

According to a preferred embodiment of the present invention, the at least one lubricating agent and borehole stabilizer is a high viscosity polymer having viscosity in the range of about 2 to 10 cP. According to one aspect of the present invention, the at least one lubricating agent and borehole stabilizer is a polyanionic cellulose polymer. According to another aspect of the present invention, the lubricating agent and borehole stabilizer is suspended in a non-aromatic, ultra-clean mineral oil.

According to a preferred embodiment of the present invention, the at least one filtration control additive is a liquid polysaccharides derivative. According to one aspect of the invention, the filtration control additive is a liquid polyanionic cellulose. The filtration control additive may act synergistically with the viscosifier to enhance the Low Shear Rate Viscosity (LSRV).

According to one aspect of the present invention, a bridging agent including a salt, preferably sized calcium carbonate, is used in conjunction with the filtration control additive to produce thin, pliable and easily removable filter cakes.

DETAILED DESCRIPTION
The embodiments herein and the various features and advantageous details thereof are explained with reference to the non-limiting examples in the following description. The examples used herein are intended merely to facilitate an understanding of the ways in which the embodiments herein may be practiced and to further enable those of skill in the art to practice the embodiments herein. Accordingly, the examples should not be construed as limiting the scope of the embodiments herein.

The description herein after, of the specific embodiments will so fully reveal the general nature of the embodiments herein that others can, by applying current knowledge, readily modify and/or adapt for various applications such specific embodiments without departing from the generic concept, and, therefore, such adaptations and modifications should and are intended to be comprehended within the meaning and range of equivalents of the disclosed embodiments. It is to be understood that the phraseology or terminology employed herein is for the purpose of description and not of limitation. Therefore, while the embodiments herein have been described in terms of preferred embodiments, those skilled in the art will recognize that the embodiments herein can be practiced with modification within the spirit and scope of the embodiments as described herein.

The present invention teaches a drilling fluid system, particularly a drilling fluid system for controlling loss circulation. The drilling fluid system according to the present invention is a rapid mix drilling fluid system primarily comprising the following components in an aqueous base fluid: one or more viscosifiers, one or more shale inhibitors/clay hydration suppressants, one or more encapsulating agents, one or more lubricating agents and borehole stabilizers and one or more filtration control additives. Additionally, the drilling fluid system may further comprise corrosion inhibitors. The base fluid may be fresh water, sea water, brine, mixtures of water and water-soluble organic compounds.

The drilling fluid system according to the present invention provides superior drilling performance while meeting the environmental regulations. The rapid mix drilling fluid system improves wellbore stability. The system is designed to achieve high performance and thereby reduce the gap between conventional water-based mud and oil-based mud in drilling fluids. Further, the drilling fluid system of the present invention provides effective shale inhibition in water-based drilling fluids for safe, fast and superior performance. Additionally, the rapid mix drilling fluid system affords superior shale stability, improved lubricity, enhanced rate of penetration (ROP) and less risk of stuck pipe.

The drilling fluid system comprises one or more viscosifiers in a concentration in the range of about 2 to 10% by weight. In a preferred embodiment, the viscosifier is present in a concentration in the range of about 3 to 6 % by weight. The viscosifier includes one or more biopolymers. Suitable biopolymers include, but are not limited to, polysaccharides and modified polysaccharides including xanthan gum, guar gum, wellum gums, gellan gums, succinoglycan, succinoglycan polysaccharides, scleroglycan, schleroglucan polysaccharides, polyvinylsaccharides, o-carboxychitosans, polyanionic cellulose, carboxymethylcellulose, hydroxyethylcellulose, hydroxypropylcellulose, natural and modified starches, and mixtures thereof.

The viscosifiers are suitable for water-based drilling fluids from low-solids to highly weighted systems. This includes fresh water, salt, and some heavy brine systems.

According to a preferred embodiment, the viscosifier of the rapid mix drilling fluid system is a high yield, clarified xanthan gum which is pre-dispersed in a water-miscible, oil-free and clay-free carrier fluid. The high molecular-weight biopolymer is the primary economical shear-thinning viscosifier for displacement spacers to provide solids transport, solids suspension, friction reduction and improved displacement efficiency. The water-miscible carrier fluid helps at dispersing the biopolymer and preventing lumps or “fisheyes” so that the polymer rapidly and smoothly viscosifies without the need for high shear. As the biopolymer is pre-dispersed in a water-miscible carrier fluid, it provides a unique rheology profile much more readily than dry material. This is especially critical when the proper mixing equipment is not available. The viscosifier produces elevated Low Shear Rate Viscosity (LSRV) and high, but fragile, gel strengths.

The drilling fluid system comprises one or more shale inhibitors or clay hydration suppressants in a concentration in the range of about 10 to 30 % by weight. The shale inhibitor includes liquid polyamine. The shale inhibitor is suitable for polymer-based drilling and drill-in fluids. The shale inhibition is achieved by preventing water uptake by clays, and by providing superior cuttings integrity. Further, the shale inhibitor effectively inhibits shale or gumbo clays from hydrating and minimizes the potential for bit balling. It can be added directly to the drilling fluid system with no effect on viscosity or filtration properties.

The shale inhibitor of the present invention is a liquid additive that acts as a clay hydration suppressant by intercalating and reducing the space between clay platelets so that water molecules do not penetrate and cause shale swelling. The shale inhibitor provides outstanding shale inhibition and minimizes dilution rates. The shale inhibitor enables a drilling fluid system having a buffered pH in the range of 9.0 – 10.0, thereby eliminating any need for adding caustic soda or potassium hydroxide. Further, the shale inhibitor improves the inhibitive properties and temperature resistance of the drilling fluid. It reduces the clay damage & hydration associate with conventional water-based drilling system. The amine-based shale inhibitor of the present invention is thermally stable & flexible additive.

The drilling fluid system comprises one or more encapsulating agents in a concentration in the range of 2 to 6 % by weight. The encapsulating agent is a cross-linked, anionic acrylamide polymer which provides cuttings encapsulation and shale stabilization. In addition, the acrylamide polymer also acts as a viscosifier, friction reducer, flocculant and fluid loss controller.

Suitable acrylamide polymer may be selected from polyacrylamide (“PA”, i.e., acrylamide homopolymer having substantially less than about 1% of its acrylamide groups converted to carboxylate groups), partially hydrolyzed polyacrylamide (“PHPA”, i.e., acrylamide homopolymers having more than about 1%, but not 100%, of its acrylamide groups converted to carboxylate groups), acrylamide copolymers, acrylamide terpolymers containing to acrylamide, a second species and a third species, and acrylamide tetrapolymers containing acrylamide, acrylate, a third species, and a fourth species, and mixtures thereof.

In a preferred embodiment, the encapsulating agent is a fully cross-linked, anionic, dispersed acrylamide polymer that can be used in solids-free drilling fluids to obtain cuttings encapsulation, improve wellbore stability and enhance solids removal by flocculating the undesired solids. In reduced-bentonite muds, it extends bentonite to increase viscosity, flocculates the drill solids for more efficient removal, encapsulates cuttings and improves wellbore stability. The encapsulating agent can also be used in mud systems using make-up waters from freshwater to saltwater. The agent acts as an excellent cuttings encapsulator to suppress cuttings dispersion.

The drilling fluid system comprises one or more lubricating agents and borehole stabilizers in a concentration in the range of 6 to 14 % by weight. The lubricating agent and borehole stabilizer includes at least one high viscosity polymer having a viscosity in the range of about 2 to 10 cP. The high viscosity polymer is preferably suspended in an ultra-clean mineral oil that contains no aromatic. The polymer can be a cellulose, particularly a polyanionic cellulose polymer, which acts as a lubricant and borehole stabilizer. The polymer also reduces fluid loss in the mud system, and produces thin, slick, tough filter cake.

As a suspension in mineral oil, the polymer is more readily dispersible in the mud without formation of “fish eye”, as compared to the polymer in its dry form. Further, the lubricating agent and borehole stabilizer reduces friction and increases the lubricity of the drilling fluid, thereby promoting faster penetration rates while reducing torque and drag. It further inhibits the hydration of drill solids and encapsulates the drill solids for easier removal. It exhibits superior mixing in low shear environments. Additionally, the stability and performance of the polymer is maintained during a freeze and thaw cycle.
A preferred embodiment of the drilling fluid system comprises one or more corrosion inhibitors in a concentration in the range of 2 to 4 % by weight. The corrosion inhibitor is a liquid polyamine corrosion inhibitor suitable for use in polymer-based drilling and drill-in fluids, and systems which are sensitive to brines. The corrosion inhibitor assists in increasing the pH in water-based systems. The corrosion inhibitor is compatible with different brine fluids and helps to prevent general corrosion attack on casing, tubing and downhole tools in contact with clear completion brines. It protects both tubular goods and completion tools exposed to work over or clear completion brines.

The drilling fluid system of the present invention further comprises a filtration control additive in a concentration in the range of 6 to 14 % by weight. The filtration control additive is a special starch derivative intended for reducing high temperature high pressure (HTHP) filtrate loss for water-based fluids. Suitable filtration control additives may be selected liquid polysaccharide derivatives. The filtration control additive is preferably a liquid polyanionic cellulose.

The additive is non-ionic in nature and suitable for fluids containing salts or ion sensitive additives. The additive reduces fluid loss, and further contributes to elevated LSRV compared to conventional fluid-loss additives. Unlike most polyanionic cellulose or starch-based additives which thin the sized salt system, the liquid polysaccharides derivative used as the filtration control additive increases the LSRV.

The filtration control additive can be used in all water-based fluids including drilling, completion and workover. A bridging agent may be used with the filtration control additive to obtain a thin, pliable and easily removable filter cake. The bridging agent can be a sized salt such as sized calcium carbonate. The filtration control additive acts synergistically with the biopolymer viscosifier to further enhance the Low Shear Rate Viscosity (LSRV).

The drilling fluid system is environmentally friendly and readily biodegradable. The high mixing rates result in reduced downtime in event of lost circulation. The drilling fluid system reduces stuck pipe or hole instability and provides better performance than conventional water-based muds. The system is economical in comparison with oil-based mud systems. Further, the system avoids formation damage due to the absence of solids in the system. Therefore, fractured carbonate formations with low permeability could be protected effectively when drilling with the present drilling fluid system.

The present invention will now be described with the help of following specific embodiments which are only intended to exemplify the invention and shall not be construed to limit the scope and ambit of the invention.

Tables below indicate the characteristics of the components of the drilling fluid system in accordance to the present invention.

Table I: Physical and chemical characteristics of clarified xanthan gum
Physical appearance
Specific gravity
Solubility
Flash point Cream-to-tan colored fluid suspension
1.0-1.1
Soluble in water
> 65°C

Table II: Physical and chemical characteristics of liquid polyamine shale inhibitor
Physical appearance
Specific gravity
Solubility
Flash Point
pH Clear liquid
1.0 – 1.07
Soluble in water
>200°F (>93°C)
9.0 – 10.0

Table III: Physical and chemical characteristics of cross-linked, anionic acrylamide polymer encapsulating agent
Physical appearance
Specific gravity
Pour point
Solubility in water Off white viscous liquid
0.95-1.0
Below (-) 30°C
Soluble

Table IV: Physical and chemical characteristics of liquid polyamine corrosion inhibitor
Physical appearance
Specific gravity
Solubility
Flash Point
pH Clear liquid
1.0 – 1.1
Soluble in water
>200°F (>93°C)
9.0 – 10.0

Table V: Physical and chemical characteristics of filtration control additive
Physical appearance
Specific gravity
Solubility in water White to off-white liquid
1.02-1.08
Soluble

EXAMPLES
The drilling fluid/mud formulations were aged, with rolling, for 16 hours at 150° F, and then analyzed using OFITE Extreme pressure and lubricity tester to determine the lubricity coefficient of the drilling fluid, API water loss, etc. The rheological properties of the fluid were determined by FANN Viscometer as described in "Standard Procedure for Testing Drilling Fluids", American Petroleum Institute, API RP 13B. Other properties such as mud weight and pH were also checked. Table 1 below lists sea water mud formulations obtained using the drilling fluid system of present invention:
Table 1
Components Mixing
Time (mins) Formulation
1 2 3 4 5 6
Sea Water (L/m³) 962.14 982.14 954.94 962.14 904 904
Xanthan gum (L/m³) 10 10 10 10 10 10 10
Liquid polyamine (L/m³) 10 12 12 12 12 30 30
##PHPA L (L/m³) 5 3 5.2 5.2 5.2 5.2 5.2
^PAC L (L/m³) 10 10 7.8 7.8 -- 14 --
Starch L (L/m³) -- -- -- 7.8 -- 12
Polyamine corrosion inhibitor (L/m³) 5 2.86 2.86 2 2.86 2.86 2.86
^^KCl Brine (80kg/m3) (L/m³) 5 -- -- 7.2 -- 14 14

Formulation 1:
The water-based drilling fluid of formulation 1 was prepared by adding 10 L/m3 of xanthan gum, 12 L/m³ of liquid polyamine, 3 L/m³ of PHPA, 10 L/m³ of PAC, 2.86 L/m3 of polyamine corrosion inhibitor to 962.14 L/m3 of sea water.

Formulation 2:
The water-based drilling fluid of formulation 2 was prepared by adding 10 L/m3 of xanthan gum, 12 L/m³ of liquid polyamine, 5.2 L/m³ of PHPA, 7.8 L/m³ of PAC, 2.86 L/m3 of polyamine corrosion inhibitor to 982.14 L/m3 of sea water.

Formulation 3:
The water-based drilling fluid of formulation 3 was prepared by adding 10 L/m3 of xanthan gum, 12 L/m³ of liquid polyamine, 5.2 L/m³ of PHPA, 7.8 L/m³ of PAC, 2 L/m3 of polyamine corrosion inhibitor, 7.2 (80 kg/m3) KCl Brine to 954.94 L/m3 of sea water.

Formulation 4:
The water-based drilling fluid of formulation 4 was prepared by adding 10 L/m3 of xanthan gum, 12 L/m³ of liquid polyamine, 5.2 L/m³ of PHPA, 7.8 L/m³ of starch derivative, 2.86 L/m3 of polyamine corrosion inhibitor to 962.14 L/m3 of sea water.

Formulation 5:
The water-based drilling fluid of formulation 5 was prepared by adding 10 L/m3 of xanthan gum, 30 L/m³ of liquid polyamine, 5.2 L/m³ of PHPA, 14 L/m³ of PAC, 2.86 L/m3 of polyamine corrosion inhibitor, 14 (80 kg/m3) KCl Brine to 904 L/m3 of sea water.

Formulation 6:
The water-based drilling fluid of formulation 6 was prepared by adding 10 L/m3 of xanthan gum, 30 L/m³ of liquid polyamine, 5.2 L/m³ of PHPA, 12 L/m³ of starch derivative, 2.86 L/m3 of polyamine corrosion inhibitor, 14 (80 kg/m3) KCl Brine to 904 L/m3 of sea water.

*BHR: Before hot roll
**AHR: After hot roll
#RPM: revolution per minute
##PHPA L: partially-hydrolyzed polyacrylamide liquid
^PAC L: polyanionic cellulose liquid
^^KCl: Potassium chloride

Table 2 represents performance of rapid mix drilling fluid system in sea water
Period of Aging 16 Hours at 150°F Formulation 1 Formulation 2 Formulation 3
Rheology using FANN Viscometer at 25°C *BHR **AHR *BHR **AHR *BHR **AHR
600 RPM# 69 60 75 67 79 64
300 RPM# 21 46 58 51 61 49
200 RPM# 43 38 51 45 53 42
100 RPM# 32 30 38 35 41 34
6 RPM# 13 16 15 20 16 19
3 RPM# 11 13 13 17 13 16
GELS 10" lbs/100 ft2 12 15 14 19 14 18
GELS 10' lbs/100 ft2 14 18 17 21 16 20
APPARENT VISC.cP 34.5 30 37.5 33.5 39.5 32
PLASTIC VISC cP. 18 14 17 16 18 15
YIELD POINT lbs/100 ft2 33 32 41 35 43 34
API water loss over all 30 minutes ml 10.2 12.8 6.8 7.8 7.4 10.2
2L3-L6 9 10 11 14 10 13
pH 9.63 9.19 9.72 9.11 9.75 9.05
Lubricity Coefficient 0.174 0.189 0.167 0.184 0.177 0.186
Mud Weight (PPG) 8.6 8.6 8.6 8.6 8.6 8.6
mud formulations 1, 2 & 3.
Table 2

Table 3 represents performance of rapid mix drilling fluid system in sea water mud regarding formulations 4, 5 & 6.

Table 3

Period of Aging 16 Hours at 150°F Formulation 4 Formulation 5 Formulation 6
Rheology using FANN Viscometer at 25°C *BHR **AHR *BHR **AHR *BHR **AHR

600 RPM 59 45 130 112 85 67
300 RPM 46 37 103 88 66 51
200 RPM 40 33 89 76 57 44
100 RPM 32 27 71 60 45 35
6 RPM 16 16 27 23 18 16
3 RPM 14 14 22 18 16 13
GELS 10" lbs/100 ft2 16 15 24 22 21 15
GELS 10' lbs/100 ft2 18 16 32 27 27 21
APPARENT VISC.cP 29.5 22.5 65 56 42.5 33.5
PLASTIC VISC cP. 13 8 27 24 19 16
YIELD POINT lbs/100 ft2 33 29 76 64 47 35
API water loss over all 30 minutes ml 10.8 16.4 7.2 7.8 7.8 8.6
2L3-L6 12 12 17 13 14 10
pH 9.72 9.69 9.17 9.01 9.22 9.05
Lubricity Coefficient 0.180 0.179 0.158 0.163 0.162 0.162
Mud Weight (PPG) 8.6 8.6 8.6 8.6 8.6 8.6

The performance of a drilling fluid during drilling operations is influenced by its properties including, but not limited to, mud viscosity, density, pH, filtration loss and lubricity coefficient. To study the drilling fluid system of the present invention, six different water-based drilling fluid formulations having different additive concentrations likes fluid loss control agent and KCl brine were analyzed. The analysis was performed by means of properties including the rheological properties, yield point, gel strength, mud density, fluid loss and lubricity coefficient. The fundamental reason for choosing to study the rheological properties, plastic viscosity, yield point and gel strength, as well as the filtration properties, fluid loss and lubricity coefficient, is the relevance these properties offer to the overall drilling mud performance. Filtration rate is often the most important property of a drilling fluid, particularly when drilling permeable formations where the hydrostatic pressure exceeds the formation pressure. Proper control of filtration can prevent or minimize wall sticking and drag and improve borehole stability.

In formulation 2, the PHPA-L concentration was increased from 3 (formulation 1) to 5.2 (L/m3) and the concentration of PAC L was reduced from 10 (formulation 1) to 7.8 (L/m3). The mud formulation 1 compared to the formulation 2 provided better rheological profiles and less fluid loss in both before and after hot rolled mud. Whereas, the mud formulation 3 with 7.2 (L/m3) of KCl brine, also improved the rheological profiles in both before and after hot rolled mud. It was observed that the API fluid loss was higher in after hot rolled mud.

In formulations 4 and 6, PAC L was replaced with Starch L at concentration 7.8 to 12 (L/m3), respectively. In the formulation 4, the rheological profiles were drastically reduced, and the API fluid loss was higher in before and after hot rolled mud. When compared to the formulation 4, the formulation 6 provided better rheological profiles and API fluid loss were controlled. In formulation 5, the PAC L concentration was increased to 14 (L/m3) with 14 (L/m3) of KCl brine. The formulation 5 provided the highest rheological profiles with effectively controlled API fluid loss in before and after hot rolled. Among the six formulations, the formulation 5 provided the best performance in rheological properties, plastic viscosity, yield point, and gel strength, as well as API fluid loss and lubricity coefficient. The formulation 5 indicated significantly improved results for the overall drilling fluid performance.

Embodiment of the present invention is applicable over a wide number of uses and other embodiments may be developed beyond the embodiment discussed heretofore. Only the most preferred embodiments and their uses have been described herein for purpose of example, illustrating the advantages over the prior art obtained through the present invention; the invention is not limited to these specific embodiments or their specified uses. Thus, the forms of the invention described herein are to be taken as illustrative only and other embodiments may be selected without departing from the scope of the present invention. It should also be understood that additional changes and modifications, within the scope of the invention, will be apparent to one skilled in the art and that various modifications to the composition described herein may fall within the scope of the invention.
,CLAIMS:We Claim:

1. A drilling fluid system for controlling loss circulation, said system having an aqueous base fluid comprising:
at least one viscosifier including a biopolymer present in a concentration in the range of 2 to 10 % by weight;
at least one shale inhibitor including a liquid polyamine present in a concentration in the range of 10 to 30 % by weight;
at least one encapsulating agent including a cross-linked, anionic acrylamide polymer present in a concentration in the range of 2 to 6 % by weight;
at least one lubricating agent and borehole stabilizer including a high viscosity polymer present in a concentration in the range of 6 to 14 % by weight; and
at least one filtration control additive including a non-ionic starch derivative in a concentration in the range of 6 to 15 % by weight.

2. The drilling fluid system as claimed in claim 1, wherein said system comprises at least one corrosion inhibitor including a liquid polyamine present in a concentration in the range of 2 to 4% by weight.

3. The drilling fluid system as claimed in claim 1, wherein said system has a pH in the range of 9.0 to 10.0.

4. The drilling fluid system as claimed in claim 1, wherein said at least one viscosifier is a biopolymer selected from polysaccharides and modified polysaccharides including xanthan gum, guar gum, wellum gums, gellan gums, succinoglycan, succinoglycan polysaccharides, scleroglycan, schleroglucan polysaccharides, polyvinylsaccharides, o-carboxychitosans, polyanionic cellulose, carboxymethylcellulose, hydroxyethylcellulose, hydroxypropylcellulose, natural and modified starches, and combinations thereof.

5. The drilling fluid system as claimed in claim 4, wherein said biopolymer is clarified xanthan gum.

6. The drilling fluid system as claimed in claim 1, wherein said at least one viscosifier is pre-dispersed in a water-miscible, oil-free and clay-free carrier fluid to obtain a system with unique rheology profile.

7. The drilling fluid system as claimed in claim 1, wherein said at least one encapsulating agent is a cross-linked, anionic acrylamide polymer selected from polyacrylamide, partially hydrolyzed polyacrylamide, acrylamide copolymers, acrylamide terpolymers, acrylamide tetrapolymers, and combinations thereof.

8. The drilling fluid system as claimed in claim 1, wherein said at least one encapsulating agent is a fully cross-linked, anionic, dispersed acrylamide polymer.

9. The drilling fluid system as claimed in claim 1, wherein said at least one lubricating agent and borehole stabilizer is a high viscosity polymer having viscosity in the range of about 2 to 10 cP.

10. The drilling fluid system as claimed in claim 8, wherein said at least one lubricating agent and borehole stabilizer is a polyanionic cellulose polymer.

11. The drilling fluid system as claimed in claim 1, wherein said at least one lubricating agent and borehole stabilizer is suspended in a non-aromatic, ultra-clean mineral oil.

12. The drilling fluid system as claimed in claim 1, wherein said filtration control additive is a liquid polysaccharides derivative.

13. The drilling fluid system as claimed in claim 11, wherein a bridging agent including a salt, preferably sized calcium carbonate, is added with said filtration control additive.