DESC:FIELD OF THE INVENTION
The present invention relates to drilling fluid formulations and associated methods. More particularly, the present invention relates to drilling fluid formulations containing weighting agents and methods for formulating such fluids.

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 of the wellbore a drilling fluid is generally used for cooling and lubricating the drill bit as it grinds through the earth’s crust. Further, as the drill bit descends, it generates “cuttings”, or small bits of stone, clay, shale or sand. An important function of the drilling fluid is to transport these cuttings back up to the earth’s surface, and provide a hydrostatic pressure to prevent formation fluids from entering into the wellbore.

In order to prevent the formation fluids from entering the wellbore, the hydrostatic pressure of the drilling fluid in the wellbore should be greater than the pressure of the formation fluids. The hydrostatic pressure of the drilling fluid is a function of its density, and depth of the wellbore. Accordingly, density is an important property of the drilling fluid for preventing undesirable flow of formation fluids into the wellbore. To increase the density, weighting agents are commonly added to the drilling fluids. These weighting agents are typically inert, high specific gravity, finely ground solid materials. Preferred weighting agents include powdered minerals of barite, calcite, hematite, ilmentite, manganese tetraoxide and galena.

In the past years, barite has been commonly used as a weighting agent in the drilling fluids owing to its inertness, easy availability and low cost. Barite is a mineral composed of barium sulfate (BaSO4), which is a high-density mineral used as a weighting agent in drilling fluids. Barite is chemically inert and insoluble. The low hardness barite is preferred as it prevents abrasion and erosion of the drilling equipment. Due to the high density of barite it is used to formulate drilling fluids of the desired weights required to control the range of subsurface pressures normally encountered in oil and gas drilling. US Pat. No. 7176165 teaches using sized barite weighting agent having a particle diameter between 4 µm to 20 µm in a wellbore fluid to prevent problems with sag and resulting variations in density. Another US Pat. No. 8476201 teaches using barite particles having size less than about 45 µm as weighting agents in an invert emulsion drilling fluid for extending the emulsion stability and reducing the sag potential.

Yet another US Pat. No. 9676988 teaches manufacturing a solid phase barite containing material for use in wellbore fluids in which at least 50 vol% barite particles having a diameter in the range of 1 µm to 10 µm and at least 90 vol % barite particles having a diameter in the range of 4 µm to 20 µm are contacted with a liquid to form relatively large particles with at least 90 vol % of the barite particles having a diameter of at least 30 µm.

The barite used in the drilling fluids taught by the prior arts has a specific gravity of at least 4.2. The high specific gravity of barite can produce mud weights in excess of 19 lb/gal. Further, it is easily millable to a particle size that reduces settling and minimizes losses on shaker screens. However, barite filter-cake removal after the drilling operation is a huge problem due to low solubility of barite in the available fluids.

A further drawback of using barite is that the lower grade barite has a required density, however, impure barium sulfate can contain significant quantities of contaminants. These non-barite contaminants not only affect the fluid quality but also significantly increase the required quantity of drilling fluid. Therefore, excess addition of barite to drilling fluid formulation may lead to increase in the waste generation.

Further, more recently, the dwindling supplies and increased consumption of premium barite has led to a significant increase in the prices and a reduction in specific gravity of most commercial grades of barite. This has led to the use of alternative weighting agents, such as ilmenite and hematite. However, higher density of these materials impacts both the rheology of the fluids and the settling rate of the weight material. Further, their relatively high hardness can result in abrasion/erosion of the tubular and surface equipment. Another drawback of these iron oxide-containing minerals is that their magnetic characteristic has the potential to affect the operation of direction drilling and some other downhole tools.

Furthermore, as the wellbores are drilled deeper the pressure of the formation fluids increases. To counteract this increase in pressure and prevent the inflow of the formation fluids, a higher concentration of the weighting agents may be included in the drilling fluid. However, increasing the concentration of the weighting agent may be problematic as particle sedimentation or “sag” may occur. The sag phenomenon arises from the settling out of particles from the wellbore fluid. This settling out causes significant localized variations in mud density or “mud weight,” both higher and lower than the nominal or desired mud weight. Among other things, particle sedimentation may result in stuck pipe or a plugged annulus. In addition to particle sedimentation, increasing the concentration of the weighting agent may also increase the viscosity of the drilling fluid. Excessive viscosity may have adverse effects on equivalent circulating density which may result in an increase in pumping requirements for circulation of the drilling fluid in the wellbore.

There is therefore felt a need for a drilling fluid formulation which will overcome the afore-noted drawbacks of traditional drilling fluids.

OBJECTS
Some of the objects of the present invention, which at least one embodiment herein satisfies, are as follows:
It is an object of the present invention to provide a drilling fluid formulation which has a high density, does not cause particle sedimentation or sag and has no impact on drilling fluid rheology.

It is another object of the present invention to provide a drilling fluid formulation containing barite having specific gravity between about 4.1 to 4.25

It is yet another object of the present invention to provide a drilling fluid formulation which is cost effective.

It is a further object of the present invention to provide method for formulating the drilling fluid without organophilic clay and organophilic lignite.

SUMMARY OF THE INVENTION
According to a preferred embodiment of the present invention, is provided a drilling fluid formulation including a base fluid and an additive mixture, wherein the additive mixture comprises barite having specific gravity of about 4.25 in a concentration of about 422 Kg/m3, about 651 Kg/m3 and about 1339 Kg/m3 for about 10.5, 12 and 16.5 PPG of mud weight, respectively.

According to another preferred embodiment of the present invention, is provided a drilling fluid formulation including a base fluid and an additive mixture, wherein the additive mixture comprises barite having specific gravity of about 4.1 in a concentration of about 426 Kg/m3, about 658 Kg/m3 and about 1352 Kg/m3 for about 10.5, 12 and 16.5 PPG of mud weight, respectively.

The additive mixture may further comprise an emulsifier, a viscosifier, a rheology modifier and a fluid loss control agent. According to the preferred embodiment, the drilling fluid formulation comprises said base fluid (olefin base oil) and water (Cacl2 brine), said oil to water ratio being about 70:30 for about 10.5, 12 and 16.5 PPG mud weight.

According to the preferred embodiment, barite used as weighting agent has a particle size between 50 – 100 microns. The formulation according to preferred embodiment has a density in the range of about 10.5 lb/gal to about 22 lb/gal.

In the preferred embodiment, the base fluid is selected from diesel, paraffin, blended ester, internal olefin, and combinations thereof. The emulsifier is a polyamide, more preferably, a dicarboxylic acid terminated polyamide. The viscosifier is selected from a saturated fatty acid derivate. The rheology modifier is selected from a dicarboxylic acid. The fluid loss control agent is selected from a fatty acid is modified with a dicarboxylic acid.

According to the preferred embodiment, the formulation is stable and effective at a temperature up to 300 °F, reduces the filter cake thickness by 10 to 25%, and is significantly free from organophilic clay and organophilic lignite.

BRIEF DESCRIPTION OF THE ACCOMPANYING DRAWINGS
The present invention will now be described with the help of the accompanying drawings, in which:

FIG. 1 illustrates a graph showing the comparison of standpipe pressure (SPP) vs depth between traditional drilling fluid formulation and drilling fluid formulation of the present invention.

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 relates to drilling fluid formulations and methods for obtaining the formulations. Accordingly, the present invention provides a drilling fluid formulation having a desired density without an undesirable increase in the viscosity. Also, the drilling fluid formulation of the present invention inhibits particle sedimentation, and enhances emulsion stability.

In accordance to a preferred embodiment of the present invention, a drilling fluid formulation comprising a weighting agent is provided. The weighing agent should have the following characteristics: lower plastic viscosity value for high density mud; low settling nature and providing low sag, easily removable from the reservoir by mechanical or chemical method, hard enough not to create fines during drilling, contain minimum coarse particles to prevent abrasion, to be sustainable and readily obtainable in bulk quantities, environment friendly and cost effective.

During oil drilling processes weighting agent, as well as drill cuttings can create sedimentation or sag that can lead to serious problems in the drilling well such as loss of well control, stuck pipe and lost circulation. The sag formation is due to settling out of particles from wellbore drilling fluid. This settling out causes significant localized variations in mud density or “mud weight,” both higher and lower than the nominal or desired mud weight. The phenomenon generally arises when the wellbore or drilling fluid is circulating bottoms-up after a trip, logging or casing run. In general, light mud is followed by heavy mud in a bottoms-up circulation. In order to avoid the low-grade barite sagging in drilling fluid, the drilling fluid is provided with superior barite having specific gravity between 4.1 to 4.25. The weighting agent is preferably barite having specific gravity greater than 4.1, more preferably the weighting agent is barite having specific gravity in the range of 4.1 to 4.25. In addition, barite having specific gravity 4.25 leads to formation of easier to remove less thickness filter cake. From the results in a drilling fluid and cement slurry of enhanced stability, which assists in avoiding drilling problems such as sagging and cement channeling.

The main role of the weighting materials in the drilling fluid is to increase mud density and provide the borehole stability. It also creates sufficient hydrostatic pressure in the hole and minimizes fluid loss by formation of thick filter cake on the walls of the drill well. Further increase in density of mud also results in increasing the penetration rate; whereas if the density is excessive it can lead to differential sticking of the drill string. On the other hand, barite is prone to sag, and so requires adequate viscosifiers to keep it in suspension.

In accordance to a preferred embodiment of the present invention, an oil-based drilling fluid formulation is provided. The drilling fluid formulation includes a base fluid and an additive mixture. The base fluid (olefin base oil) and water (Cacl2 brine) are typically used in a ratio of about 70:30 for 10.5, 12 and 16.5 PPG mud weight. Wherein the additive mixture comprises barite having specific gravity of about 4.1 to 4.25. The concentration of barite having specific gravity of about 4.1 is about 426 Kg/m3, about 658 Kg/m3 and about 1352 Kg/m3 for about 10.5, 12 and 16.5 PPG of mud weight, respectively. The concentration of barite having specific gravity of about 4.25 is about 422 Kg/m3, about 651 Kg/m3 and about 1339 Kg/m3 for about 10.5, 12 and 16.5 PPG of mud weight, respectively. Thus, typically the concentration of barite in the additive mixture is in the range of about 422 – 426 Kg/m3, 651 – 658 Kg/m3, and 1339 – 1352 Kg/m3 for about 10.5, 12 and 16.5 PPG of mud weight, respectively. The particle size of barite is preferably between 50 – 100 microns, more preferably ~ 75microns. The drilling fluid has a density of greater than about 10.5 lb/gal. Preferably, the drilling fluid has a density of about 10.5 lb/gal to about 22 lb/gal.

In accordance to an embodiment of the present invention, the base fluid may be selected from aqueous-based fluids (e.g., water, oil-in-water emulsions) and oleaginous-based fluids (e.g., invert emulsions). Suitable oleaginous fluids include, but are not limited to, a -olefins, internal olefins, alkanes, aromatic solvents, cycloalkanes, liquefied petroleum gas, kerosene, diesel oils, crude oils, gas oils, fuel oils, paraffin oils, mineral oils, low-toxicity mineral oils, olefins, esters, amides, synthetic oils (e.g., polyolefins), polydiorganosiloxanes, siloxanes, organosiloxanes, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof. Preferably, the base fluid is selected from diesel, paraffin, blended ester, internal olefin or combinations thereof. Generally, the base fluid may be present in an amount sufficient to form a pumpable drilling fluid formulation.

Further, the drilling fluid formulation may comprise a viscosifier for increasing the viscosity of the drilling fluid and imparting a sufficient carrying capacity to the drilling fluid, enabling the drilling fluid to transport drill cuttings and/or weighting materials, and prevent the undesired settling of the drilling cuttings and/or weighting materials. Some examples of suitable viscosifiers, include, but are not limited to, clays and clay derivatives, polymeric additives, diatomaceous earth, polysaccharides such as starches, and combinations thereof.

In addition, the drilling fluids may further comprise additional additives. Examples of such additives include, but are not limited to, emulsifiers, wetting agents, dispersing agents, shale inhibitors, pH-control agents, rheology modifiers, fluid loss control agents, filtration-control agents, lost-circulation materials, alkalinity sources such as lime and calcium hydroxide, salts, or combinations thereof.

The formulation is stable and effective at a temperature up to 300 °F. The formulation is significantly free from organophilic clay and organophilic lignite. Using the drilling fluid formulation, the filter cake thickness can be reduced by 10 to 25 %. The formulation showed good low shear rheology and facilitates better hole cleaning and sag control. The formulation showed less Plastic Viscosity (PV) results implying lower equivalent circulating densities (ECD) at faster drilling rate. The formulation showed a less PV value and enhanced the rate of penetration (ROP).

The preferred embodiment of the present invention will now be exemplified with the help of the following non-limiting examples which shall not be construed to limit the scope and ambit of the invention.

In the present invention of inverted emulsion mud system, emulsifier trade name “EMSTABER” was provided with stable water-in-oil emulsion at the temperature of 300°F. Viscosifier trade name “VISBUILDER” acted as gellent to the barite in more suspension and showed minimal changes in the rheological after dynamic ageing. The rheology modifier trade name “ULTRAMOD” enhanced the yield point and gel strength of the mud system without affecting the plastic viscosity. The fluid loss control agent trade name “FCPLUS” effectively controlled the HTHP fluid loss of drilling fluid formulation. Barite having specific gravity 4.1 and 4.25 were used as weighing agents in the drilling fluid formulation.

EXAMPLES
Example 1 – Mud Formulation
Mud formulation was prepared as follows. To the Poly Alpha Olefin PAO as a base fluid, the following components were added and mixed as follows: 1) EMSTABER from Oren Hydrocarbons act as a emulsifier, followed by mixing for 3 minutes; 2) lime (Ca(OH)2), followed by mixing for 3 minutes; 3) water and calcium chloride, followed by mixing for 10 minutes; 4) VISBUILDER from Oren Hydrocarbons act as a Viscosifier, followed by mixing for 10 minutes; 5) ULTRAMOD from Oren Hydrocarbons act as a rheology modifier, followed by mixing for 3 minutes; 6) FC PLUS from Oren Hydrocarbons act as a fluid loss control additive, followed by mixing for 3 minutes; and 7) barite (4.1 & 4.25) weighing agent, followed by mixing for 10 minutes.

Mud formulation used in PAO base oil with Barite 4.1 illustrated in Table I
Table I
Component Mud Formulation
I II III
PAO (L/m3) 554.34 513.43 396.91
EMSTABER (L/m3) 36.09 40.60 45.11
Lime (kg/m3) 8.6 8.6 8.6
Water (L/m3) 237.14 219.9 169.9
Calcium Chloride (kg/m3) 82.7 76.7 59.6
VISBUILDER (kg/m3) 11.4 11.4 11.4
ULTRAMOD (L/m3) 6.35 6.35 6.35
FC PLUS (L/m3) 8.57 8.57 8.57
Barite 4.1 (kg/m3) 426.3 658 1352
Mud concentration (lbm/gal) 10.5 12 16.5
Oil: Water Ratio 70:30 70:30 70:30

Mud formulation used in PAO base oil with Barite 4.25 illustrated in Table II
Table II

Component Mud Formulation
I a II a III a
PAO (L/m3) 557.43 518.26 406.89
EMSTABER (L/m3) 36.09 40.60 45.11
Lime (kg/m3) 8.6 8.6 8.6
Water (L/m3) 238.5 221.9 174.57
Calcium Chloride (kg/m3) 83.2 77.4 61.1
VISBUILDER (kg/m3) 11.4 11.4 11.4
ULTRAMOD (L/m3) 6.35 6.35 6.35
FC PLUS (L/m3) 8.57 8.57 8.57
Barite 4.25 (kg/m3) 422 651 1339
Mud concentration (lbm/gal) 10.5 12 16.5
Oil: Water Ratio 70:30 70:30 70:30

Table III – Performance characteristics of mud formulation I and I a
Period of Aging
16 Hours @300°F Mud formulation I Mud formulation Ia
RHEOLOGY @ 49°C BHR AHR BHR AHR
600 RPM 187 82 192 88
300 RPM 140 58 144 64
200 RPM 121 45 122 50
100 RPM 87 34 89 37
6 RPM 34 15 35 16
3 RPM 25 12 26 13
10" 41 15 42 16
10' 46 18 50 20
APPARENT VISCOSITY cP 93.5 41 96 44
PLASTIC VISCOSITY cP 47 24 48 24
YIELD POINT lbs/100 ft² 93 34 96 40
Mud Weight ppg 10.5 10.5 10.5 10.5
50% Mud pH in 75:25 (IPA/Water Solution) 7.12 7.14 7.19 7.13
Electrical Stability @ 120°F 701 673 692 647
HTHP FLUID LOSS (Overall 30 minutes) 500 Psi differential pressure@300°F ml 3.8 ml 4.2 ml
Filter cake thickness mm 1.57 1.24
Density at Bottom 1.2615 1.2683 1.2650 1.2723
Density at Top 1.2600 1.2594 1.2603 1.2583
Dynamic Sagging test @300°F 0.500 0.502 0.501 0.503

Table IV – Performance characteristics of mud formulation II and II a
Period of Aging
16 Hours @300°F Mud formulation II Mud formulation IIa
RHEOLOGY @ 49°C AHR BHR BHR AHR
600 RPM 199 145 202 147
300 RPM 136 97 138 100
200 RPM 110 73 115 77
100 RPM 81 49 87 50
6 RPM 40 21 45 24
3 RPM 32 18 34 19
10" 37 23 47 23
10' 51 26 59 29
APPARENT VISCOSITY cP 99.5 72.5 101 73.5
PLASTIC VISCOSITY cP 63 48 64 47
YIELD POINT lbs/100 ft² 73 49 74 53
Mud Weight ppg 12.1 12.1 12.1 12.1
50% Mud pH in 75:25 (IPA/Water Solution) 7.34 7.43 7.27 7.21
Electrical Stability @ 120°F 1155 619 1251 719
HTHP FLUID LOSS (Overall 30 minutes) 500 Psi differential pressure@300°F ml 4.0 ml 3.8 ml
Filter cake thickness mm 2.79 2.24
Density at Bottom 1.4370 1.4364 1.4376 1.4371
Density at Top 1.4358 1.4281 1.4258 1.4224
Dynamic Sagging test @300°F 0.500 0.501 0.502 0.503

Table V – Performance characteristics of mud formulation III and IIIa
Period of Aging
16 Hours @300°F Mud formulation III Mud formulation IIIa
RHEOLOGY @ 49°C BHR AHR BHR AHR
600 RPM 285 181 292 185
300 RPM 201 119 203 124
200 RPM 164 94 169 97
100 RPM 125 63 126 65
6 RPM 66 27 66 30
3 RPM 54 21 53 25
10" 60 22 66 28
10' 69 26 69 32
APPARENT VISCOSITY cP 142.5 90.5 146 92.5
PLASTIC VISCOSITY cP 84 62 89 61
YIELD POINT lbs/100 ft² 117 57 114 63
Mud Weight ppg 16.5 16.5 16.5 16.5
50% Mud pH in 75:25 (IPA/Water Solution) 7.14 7.18 7.38 7.22
Electrical Stability @ 120°F 1528 496 1591 598
HTHP FLUID LOSS (Overall 30 minutes) 500 Psi differential pressure@300°F ml 4.6 ml 3.4 ml
Filter cake thickness µm 3.43 2.96
Density at Bottom 1.9768 1.9754 1.9770 1.9764
Density at Top 1.9597 1.9547 1.9582 1.9601
Dynamic Sagging test @300°F 0.502 0.503 0.502 0.502

The evaluation of the drilling fluid formulation was performed through mud weights 10.5, 12 and 16.5 PPG and drilling mud samples prepared in which one sample contained barite having specific gravity 4.1 and second sample contained barite having specific gravity 4.25. Barites having specific gravity 4.25 showed significant results and reduced quantity of barite consumption in the drilling mud, which in turn decreased the quantity of waste generated. The barite having specific gravity 4.25 was identified as a weighting agent suitable for use in drilling and completion fluids, which offered significant advantages in the control of formation damage. The performance properties of drilling fluid system showed similar physical and rheological properties using barite having specific gravity 4.1 and 4.25 as weighting agents in drilling fluids.

Figure 1 of the accompanying drawings illustrates a graph showing the comparison of standpipe pressure (SPP) vs depth between oil-based mud of test 1 and oil-based mud of test 2. It is observed that using the oil-based mud comprising barite having specific gravity 4.25, the drilling fluid can reach greater depth at reduced standpipe pressure.

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 construction described herein may fall within the scope of the invention.
,CLAIMS:We Claim:

1. A drilling fluid formulation including a base fluid and an additive mixture, wherein the additive mixture comprises barite having specific gravity of about 4.25.

2. The drilling fluid formulation as claimed in claim 1, wherein concentration of said barite having specific gravity of about 4.25 is about 422 Kg/m3, about 651 Kg/m3 and about 1339 Kg/m3 for about 10.5 PPG, 12 PPG and 16.5 PPG mud weight, respectively.

3. A drilling fluid formulation including a base fluid and an additive mixture, wherein the additive mixture comprises barite having specific gravity of about 4.1.

4. The drilling fluid formulation as claimed in claim 3, wherein concentration of said barite having specific gravity of about 4.1 is about 426 Kg/m3, about 658 Kg/m3 and about 1352 Kg/m3 for about 10.5 PPG, 12 PPG and 16.5 PPG mud weight, respectively.

5. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said additive mixture further comprises an emulsifier, a viscosifier, a rheology modifier and a fluid loss control agent.

6. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said drilling fluid formulation comprises said base fluid and water (CaCl2 brine), said oil to water ratio being in the range of about 70:30 for about 10.5 PPG, 12 PPG and 16.5 PPG mud weight.

7. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said barite has a particle size between 50 – 100 microns.

8. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said formulation has a density in the range of about 10.5 lb/gal to about 22 lb/gal.

9. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said base fluid is selected from diesel, paraffin, blended ester, internal olefin, and combinations thereof.

10. The drilling fluid formulation as claimed in claim 5, wherein the emulsifier is a dicarboxylic acid terminated polyamide.

11. The drilling fluid formulation as claimed in claim 5, wherein the viscosifier is a saturated fatty acid derivative.

12. The drilling fluid formulation as claimed in claim 5, wherein the rheology modifier is a dicarboxylic acid.

13. The drilling fluid formulation as claimed in claim 5, wherein the fluid loss control agent is a fatty acid modified with a dicarboxylic acid.

14. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said formulation is stable and effective at a temperature up to 300 °F.

15. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein the filter cake thickness is reduced by 10 to 25 %.

16. The drilling fluid formulation as claimed in anyone of the preceding claims, wherein said formulation is significantly free from organophilic clay and organophilic lignite.