US20080064613A1

US20080064613A1 - Dispersant coated weighting agents

Info

Publication number: US20080064613A1
Application number: US11/741,199
Authority: US
Inventors: Jarrod Massam
Original assignee: MI LLC
Current assignee: MI LLC
Priority date: 2006-09-11
Filing date: 2007-04-27
Publication date: 2008-03-13
Also published as: CN103725264A; AU2007294625B2; EP2066759B1; US20120202718A1; WO2008033838A2; WO2008033838A3; CA2661918C; MX2009002464A; NZ575007A; CA2663192A1; DK2066759T3; EP1987112A1; CN103725264B; CN101511968A; CN101595197A; AR062751A1; MY150058A; EP2066759A2; AU2007296539A1; BRPI0716793A2

Abstract

A method of formulating a wellbore fluid that includes providing a base fluid; and adding a sized weighting agent coated with a dispersant made by the method of dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant is disclosed.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Patent Application No. 60/825,156, filed Sep. 11, 2006, the disclosure of which is incorporated herein by reference.

BACKGROUND OF INVENTION

1. Field of the Invention
The invention relates generally to fluids and surface coated solid materials for use in a wellbore fluid.
2. Background Art
When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
In general, drilling fluids should be pumpable under pressure down through strings of drilling pipe, then through and around the drilling bit head deep in the earth, and then returned back to the earth surface through an annulus between the outside of the drill stem and the hole wall or casing. Beyond providing drilling lubrication and efficiency, and retarding wear, drilling fluids should suspend and transport solid particles to the surface for screening out and disposal. In addition, the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the mud), generally finely ground barites (barium sulfate ore), and transport clay and other substances capable of adhering to and coating the borehole surface.
Drilling fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drilling bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it contains to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry all unwanted particulate matter from the bottom of the well bore to the surface. The drilling fluid formulation should also allow the cuttings and other unwanted particulate material to be removed or otherwise settle out from the liquid fraction.
There is an increasing need for drilling fluids having the Theological profiles that enable these wells to be drilled more easily. Drilling fluids having tailored Theological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the drill string to become stuck, among other issues. There is also the need from a drilling fluid hydraulics perspective (equivalent circulating density) to reduce the pressures required to circulate the fluid, this helps to avoid exposing the formation to excessive forces that can fracture the formation causing the fluid, and possibly the well, to be lost. In addition, an enhanced profile is necessary to prevent settlement or sag of the weighting agent in the fluid, if this occurs it can lead to an uneven density profile within the circulating fluid system which can result in well control (gas/fluid influx) and wellbore stability problems (caving/fractures).
To obtain the fluid characteristics required to meet these challenges, the fluid must be easy to pump so it requires the minimum amount of pressure to force it through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools. Or in other words, the fluid must have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the area for fluid flow is large and the velocity of the fluid is slow or where there are low shear conditions, the viscosity of the fluid needs to be as high as possible in order to suspend and transport the drilled cuttings. This also applies to the periods when the fluid is left static in the hole, where both cuttings and weighting materials need to be kept suspended to prevent settlement. However, it should also be noted that the viscosity of the fluid should not continue to increase under static conditions to unacceptable levels. Otherwise when the fluid needs to be circulated again this can lead to excessive pressures that can fracture the formation or alternatively it can lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.
Wellbore fluids must also contribute to the stability of the well bore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow or blow out of formation fluids or the collapse of pressured earth formations. The column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid. High-pressure formations may require a fluid with a specific gravity as high as 3.0.
A variety of materials are presently used to increase the density of wellbore fluids. These include dissolved salts such as sodium chloride, calcium chloride and calcium bromide. Alternatively, powdered minerals such as barite, calcite and hematite are added to a fluid to form a suspension of increased density. The use of finely divided metal, such as iron, as a weight material in a drilling fluid wherein the weight material includes iron/steel ball-shaped particles having a diameter less than 250 μm and preferentially between 15 and 75 μm has also been described. The use of finely powdered calcium or iron carbonate has also been proposed; however, the plastic viscosity of such fluids rapidly increases as the particle size decreases, limiting the utility of these materials.
One requirement of these wellbore fluid additives is that they form a stable suspension and do not readily settle out. A second requirement is that the suspension exhibit a low viscosity in order to facilitate pumping and to minimize the generation of high pressures. Finally, the wellbore fluid slurry should also exhibit low fluid loss.
Conventional weighting agents such as powdered barite exhibit an average particle diameter (d₅₀) in the range of 10-30 μm. To adequately suspend these materials requires the addition of a gellant such as bentonite for water-based fluids, or organically modified bentonite for oil-based fluids. A soluble polymer viscosifier such as xanthan gum may be also added to slow the rate of the sedimentation of the weighting agent. However, as more gellant is added to increase the suspension stability, the fluid viscosity (plastic viscosity and/or yield point) increases undesirably resulting in reduced pumpability. This is also the case if a viscosifier is used to maintain a desirable level of solids suspension.
The sedimentation (or “sag”) of particulate weighting agents becomes more critical in wellbores drilled at high angles from the vertical, in that a sag of, for example, one inch (2.54 cm) can result in a continuous column of reduced density fluid along the upper portion of the wellbore wall. Such high angle wells are frequently drilled over large distances in order to access, for example, remote portions of an oil reservoir. In such instances it is important to minimize a drilling fluid's plastic viscosity in order to reduce the pressure losses over the borehole length. At the same time a high density also should be maintained to prevent a blow out. Further, as noted above with particulate weighting materials the issues of sag become increasingly important to avoid differential sticking or the settling out of the particulate weighting agents on the low side of the wellbore.
Being able to formulate a drilling fluid having a high density and a low plastic viscosity is also important in deep high pressure wells where high-density wellbore fluids are required. High viscosities can result in an increase in pressure at the bottom of the hole under pumping conditions. This increase in “Equivalent Circulating Density” can result in opening fractures in the formation, and serious losses of the wellbore fluid into the fractured formation. Again the stability of the suspension is important in order to maintain the hydrostatic head to avoid a blow out. The goal of high-density fluids with low viscosity plus minimal sag of weighting material continues to be a challenge. Thus, there is a need for materials that increase fluid density while simultaneously providing improved suspension stability and minimizing both fluid loss and increases in viscosity.

SUMMARY OF INVENTION

In one aspect, embodiments disclosed herein relate to a method of formulating a wellbore fluid that includes providing a base fluid; and adding a sized weighting agent coated with a dispersant made by the method of dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant.
In another aspect, embodiments disclosed herein relate to a wellbore fluid that includes a base fluid; and a sized weighting agent coated with a dispersant made by the method of dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

BRIEF SUMMARY OF DRAWINGS

FIG. 1 shows a flow diagram of a dry blending process in accordance with one embodiment disclosed herein.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to dispersant coatings on weighting agents used in wellbore fluids. In another aspect, embodiments disclosed herein relate to the formulation of wellbore fluids that include dispersant coated weighting agents.
In one embodiment, a weighting agent may be coated with a dispersant by a dry blending process. The resultant coated weighting agent may be added in new drilling fluid formulations or added to existing formulations. The term “dry blending” refers to a process in which the weighting agent is mixed and coated with a dispersant in the absence of a solvent. An analogous process in the presence of solvent generating colloidal coated particles has been disclosed in U.S. Patent Application No. 20040127366 assigned to the assignee of the present application, which is herein incorporated by reference. As used herein the term “sized weighting agent” refers to weighting agents having particle size distribution reduced below conventional API specified distribution. Finally, one skilled in the art would recognize that the weighting agent may be dry blended with the dispersant in a comminution process (grinding) process or by other means such as, for example, thermal desorption.
Weighting Agent
Weighting agents used in embodiments disclosed herein may include a variety of compounds well known to one of skill in the art. In a particular embodiment, the weighting agent may be selected from materials including, for example, barium sulphate (barite), calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, and strontium sulphate. One having ordinary skill in the art would recognize that selection of a particular material may depend largely on the density of the material as typically, the lowest wellbore fluid viscosity at any particular density is obtained by using the highest density particles. However, other considerations may influence the choice of product such as cost, local availability, the power required for grinding, and whether the residual solids or filter cake may be readily removed from the well.
In one embodiment, the weighting agent may be a sized weighting agent having a d₉₀ranging from 1 to 25 μm and a d₅₀ranging from 0.5 to 10 μm. In another embodiment, the sized weighting agent includes particles having a d₉₀ranging from 2 to 8 μm and a d₅₀ranging from 0.5 to 4 μm. One of ordinary skill in the art would recognize that, depending on the sizing technique, the weighting agent may have a particle size distribution other than a monomodal distribution. That is, the weighting agent may have a particle size distribution that, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.
The use of sized weighting agents has been disclosed in U.S. Patent Application No. 20050277553 assigned to the assignee of the current application, which is herein incorporated by reference. Particles having these size distributions may be obtained by several means. For example, sized particles, such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially purchased. A coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size. Such techniques include jet-milling, high performance dry milling techniques, or any other technique that is known in the art generally for milling powdered products. In one embodiment, appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API barite grinding operation. Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API grade barite. However, in accordance with the present disclosure, these by-product fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein. In yet another embodiment, the sized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
Dispersant
In one embodiment, the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acid, phospholipids such as lecithin, including salts thereof and including mixtures therof. Synthetic polymers may also be utilized such as HYPERMER OM-1 (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example. Such polyacrylate esters may include polymers of stearyl methacrylate and/or butylacrylate. In another embodiment, the corresponding acids methacrylic acid and/or acrylic acid may be used. One skilled in the art would recognize that other acrylate or other unsaturated carboxylic acid monomers (or esters thereof) may be used to achieve substantially the same results as disclosed herein.
When the additive is to be used in water-based fluids, a water soluble polymer of molecular weight of at least 2000 Daltons may be used in a particular embodiment. Examples of such water soluble polymers may include a homopolymer or copolymer of any monomer selected from acrylic acid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido 2-propane sulphonic acid, acrylamide, styrene sulphonic acid, acrylic phosphate esters, methyl vinyl ether and vinyl acetate or salts thereof.
The polymeric dispersant may have an average molecular weight from about 10,000 Daltons to about 300,000 Daltons in one embodiment, from about 17,000 Daltons to about 40,000 Daltons in another embodiment, and from about 200,000-300,000 Daltons in yet another embodiment. One of ordinary skill in the art would recognize that when the dispersant is added to the weighting agent during a grinding process, intermediate molecular weight polymers (10,000-300,000 Daltons) may be used.
Further, it is specifically within the scope of the embodiments disclosed herein that the polymeric dispersant be polymerized prior to or simultaneously with the dry blending processes disclosed herein. Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization or combinations thereof.
Coating Process
Coating of the weighting agent with the dispersant may be performed in a dry blending process such that the process is substantially free of solvent. With reference to FIG. 1, one embodiment for producing a coated weighting agent is illustrated. The process includes blending the weighting agent 10 and a dispersant 12 at a desired ratio to form a blended material. In one embodiment, the weighting agent 10 may be unsized initially and rely on the blending process to grind the particles into the desired size range as disclosed above. Alternatively, the process may begin with sized weighting agents.
The blended material 14 may then be fed to a heat exchange system 16, such as a thermal desorption system. The mixture may be forwarded through the heat exchanger using a mixer 18, such as a screw conveyor. Upon cooling, the polymer may remain associated with the weighting agent. The polymer/weighting agent mixture 20 may then be separated into polymer coated weighting agent 22, unassociated polymer 24, and any agglomerates 26 that may have formed. The unassociated polymer 24 may optionally be recycled to the beginning of the process, if desired. In another embodiment, the dry blending process alone may serve to coat the weighting agent without heating.
Alternatively, a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process. In this embodiment, a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react a monomeric dispersant as described above onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent. In another embodiment, one may use a catalyzed process to form the polymer in the presence of the sized weighting agent. In yet another embodiment, the polymer may be preformed and may be thermally adsorbed onto the sized weighting agent.
According to yet another embodiment, the dispersant is coated onto the weighting agent during the grinding process. That is to say, coarse weighting agent is ground in the presence of a relatively high concentration of dispersant such that the newly formed surfaces of the fine particles are exposed to and thus coated by the dispersant. It is speculated that this allows the dispersant to find an acceptable conformation on the particle surface thus coating the surface. Alternatively it is speculated that because a relatively higher concentration of dispersant in the grinding fluid, as opposed to that in a drilling fluid, the dispersant is more likely to be adsorbed (either physically or chemically) to the particle surface. As that term is used in herein, “coating of the surface” is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art. By using such a definition, one of skill in the art should understand and appreciate that the dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult.
One of ordinary skill in the art would appreciate that the dry coated particles may be obtained from an oil-based slurry through methods such as spray drying and thermal desorption, for example.
In one embodiment, the dispersant may comprise from about 1% to about 10% of the total mass of the dispersant plus weighting agent.
Use in Wellbore Formulations.
In accordance with one embodiment, the dry coated weighting agent may be used in a wellbore fluid formulation. The wellbore fluid may be a water-based fluid, an invert emulsion or an oil-based fluid.
Water-based wellbore fluids may have an aqueous fluid as the base solvent and a dispersant coated weighting agent. The aqueous fluid may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof. For example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, sulfur, aluminum, magnesium, potassium, strontium, silicon, lithium, and phosphorus salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, fonnates, nitrates, oxides, and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In one embodiment, the density of the drilling fluid may be controlled by increasing the salt concentration in the brine (up to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.
The oil-based/invert emulsion wellbore fluids may include an oleaginous continuous phase, a non-oleaginous discontinuous phase, and a dispersant coated weighting agent. One of ordinary skill in the art would appreciate that the dispersant coated weighting agents described above may be modified in accordance with the desired application. For example, modifications may include the hydrophilic/hydrophobic nature of the dispersant.
The oleaginous fluid may be a liquid and more preferably is a natural or synthetic oil and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including poly(alpha-olefins), linear and branch olefins and the like, polydiorganosiloxanes, sitoxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof. The concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion. In one embodiment, the amount of oleaginous fluid is from about 30% to about 95% by volume and more preferably about 40% to about 90% by volume of the invert emulsion fluid. The oleaginous fluid, in one embodiment, may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.
The non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein is a liquid and may be an aqueous liquid. In one embodiment, the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof. The amount of the non-oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion Thus, in one embodiment, the amount of non-oleaginous fluid is less that about 70% by volume and preferably from about 1% to about 70% by volume. In another embodiment, the non-oleaginous fluid is preferably from about 5% to about 60% by volume of the invert emulsion fluid. The fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof. In a particular embodiment, coated barite or other weighting agents may be included in a wellbore fluid comprising an aqueous fluid that includes at least one of fresh water, sea water, brine, and combinations thereof
The fluids disclosed herein are especially useful in the drilling, completion and working over of subterranean oil and gas wells. In particular the fluids disclosed herein may find use in formulating drilling muds and completion fluids that allow for the easy and quick removal of the filter cake. Such muds and fluids are especially useful in the drilling of horizontal wells into hydrocarbon bearing formations.
Conventional methods can be used to prepare the drilling fluids disclosed herein in a manner analogous to those normally used, to prepare conventional water- and oil-based drilling fluids. In one embodiment, a desired quantity of water-based fluid and a suitable amount of the dispersant coated weighting agent are mixed together and the remaining components of the drilling fluid added sequentially with continuous mixing. In another embodiment, a desired quantity of oleaginous fluid such as a base oil, a non-oleaginous fluid and a suitable amount of the dispersant coated weighting agent are mixed together and the remaining components are added sequentially with continuous mixing. An invert emulsion may be formed by vigorously agitating, mixing or shearing the oleaginous fluid and the non-oleaginous fluid.
Other additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents. The addition of such agents should be well known to one of ordinary skill in the art of formulating drilling fluids and muds.
In yet another embodiment, an existing drilling fluid formulation may be modified with a dispersant coated weighting agent. For example, one may add dispersant-coated weighting agents of the present disclosure to the wellbore fluids disclosed in U.S. Patent Application 20040127366 (the '366 application) assigned to the assignee of the present application. The wellbore fluids of the '366 application contain colloidal coated weighting agent particles derived from a blending process in the presence of solvent. Further, one of ordinary skill would appreciate that the term “colloidal” refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application. However, one of ordinary skill in the art would recognize that the dispersant coated weighting agent of the present disclosure may be added to any type of existing wellbore fluid formulation.

EXAMPLES

The following examples include exemplary coated and uncoated weighting agents and experimental data showing their fluid loss and rheological properties. Oil-based drilling fluids were tested over a mud weight range of 12.5-22.0 ppg and temperatures of 250-350° F. using a polyacrylate polymer coated barite as the weighting material.

Example 1

A 14 pounds per gallon (ppg) fluid was formulated with EDC 99DW, a highly hydrogenated mineral oil (M-I LLC, Houston, Tex.), as the oleaginous phase. For the purpose of comparison, 14 ppg solutions were formulated with dispersant coated barite as well as uncoated barite. Quantities of each component are expressed in pounds per barrel (ppb) as shown in Table 1 below (EMUL HT™ and TRUVIS™ are each available from M-I LLC, Houston, Tex.).

TABLE 1

14 ppg Fluid Formulation

	Product	Purpose	ppb

EDC 99DW	Base oil	152
Barite	Density	354
EMUL HT ™	Emulsifier	7
TRUVIS ™	Viscosifier	4
Lime	Alkalinity	6
CaCl₂Brine	Brine	65

Polyacrylate polymer coated barite and uncoated barite in 14 ppg drilling fluids were formulated to an oil/water ratio (OWR) of 80/20 and aged at 250° F. for 16 hours. Rheological properties were determined using a Fann Model 35 viscometer, available from Fann Instrument Company. Fluid loss was measured with a saturated API high temperature, high pressure (HTHP) cell. Gel strength (i.e., measure of the suspending characteristics or thixotropic properties of a fluid) was evaluated by the 10 minute gel strength in pounds per 100 square feet, in accordance with procedures in API Bulletin RP 1313-2, 1990. Electrical stability (ES) of the emulsion was measured by the test described in “Composition and Properties of Drilling and Completion Fluids,” 5^thEd. H. C. H. Darley, George R. Gray, 1988, p. 116. The results are shown in Table 2 below.

TABLE 2

14 ppg Fluid Properties
14 ppg; OWR 80/20; 250° F.

	Fluid Property	Coated	Uncoated

PV (cP)	17	18
YP (lb/100 ft²)	7	15
Fann 35 6/3 rpm	3/2	8/7
10 min Gel (lb/100 ft²)	6	10
ES (v)	644	770
HTHP Fluid Loss (mL)	3.2	14.4

The results show an enhanced rheological profile with the coated barite giving a lower yield point (YP), low-shear rate viscosities and gel strength. The fluid loss also shows improvement when using the coated barite.

Example 2

In accordance with one embodiment, an existing fluid formulation may be weighted up with dispersant-coated weighting agents. The following experiments were carried out with a 16 ppg oil-based aged at 350° F. Quantities of each component are expressed in pounds per barrel (ppb) as shown in Table 3 below (EMUL HT™, VERSAGEL®, and VERSATROL® are each available from M-I LLC, Houston, Tex.).

TABLE 3

16 ppg Fluid Formulation

Product	Purpose	Coated (ppb)	Uncoated (ppb)

EDC99DW	Base oil	150	150
Barite	Density	156	135
EMUL HT ™	Emulsifier		10	10
VERSAGEL ® HT	Viscosifier	3	3
VERSATROL ® HT	Fluid loss	2.5	2.5
Lime	Alkalinity	6	6
CaCl₂Brine	Brine	66	66

Rheology and fluid loss tests were performed as described above. Static sag measurements were obtained from aging the formulated drilling fluid in a static condition at 350° F. for 16 hours. One skilled in the art will realize that this test procedure relates to the behavior of the drilling fluid while static in the well. The measurement records the volume of resulting free oil on top of the column of drilling fluid as well as the density of the top layer of the fluid column and the bottom layer of the fluid column. These densities are used to calculate the static sag factor, where the static sag factor=(topSG+botttomSG)/bottomSG. The results are shown below in Table 4.

TABLE 4

Weighted Up Fluid
16 ppg; AHR 350 F

	Fluid Property	Coated	Uncoated

PV (cP)	34	36
YP (lb/100 ft²)	8	10
3 rpm reading	3	3
ES (v)	691	631
HTHP Fluid Loss (mL)	5.6	8.4
Static Sag Factor	0.517	0.531

Although the results demonstrate comparable rheology, the dry coated barite gives a better static sag and fluid loss performance.

Example 3

A 20 ppg fluid was formulated to an OWR of 90/10 and aged at 350° F. Quantities of each component are expressed in pounds per barrel (ppb) as shown in Table 5 below (SUREMUL™ and VERSATROL™ are each available from M-I LLC, Houston, Tex.; BENTONE is available from N L Industries, New York, N.Y.).

TABLE 5

20 ppg Fluid Formulation

	Product	Purpose	ppb

EDC99DW	Base oil	120
Barite	Density	676
SUREMUL ™ EH	Emulsifier	10
BENTONE 150	Viscosifier	0.5
BENTONE 42	Viscosifier	1.0
VERSATROL ™ HT	Fluid loss	2.5
Lime	Alkalinity	6.0
CaCl2 brine	brine		24

Rheology and fluid loss tests were performed as described above. Fluid loss and rheology measurements are shown in Table 6 below.

TABLE 6

High Density Fluid Properties
20 ppg; OWR 90/10; 350° F.

	Fluid Property	Coated

	PV (cP)	42
	YP (lb/100 ft²)	1
	3 rpm reading	2
	ES (v)	1034
	HTHP Fluid Loss (mL)	4.4
	Static sag @ 375 F.	0.532

The results show that dry coated barite may be used to formulate a very high density drilling fluid without the high rheology typically associated with them. One of ordinary skill in the art would appreciate the difficulty in not only obtaining a low PV with a 20 ppg fluid but also the problems associated in mixing and dispersing/wetting a fine uncoated weighting agent into an oil-based fluid.

Example 4

The mixing, wetting and dispersibility of the barite in the 16 ppg oil-based fluid described above in Example 2 were tested as summarized in Table 5 below.

TABLE 7

Dispersion/Wetting Evaluations

16 ppg Fluid

5 min

10 min

60 min

	Coated	Uncoated	Coated	Uncoated	Coated	Uncoated

PV	56	83	55	78	55	66
YP	15	25	15	20	15	19

The results in Table 5 show that when adding the weight material to the formulated drilling fluid, the coated barite readily disperses and achieves its ultimate rheology within the first 5 minutes, whereas when adding the uncoated barite, it takes a much longer time to achieve its final rheology.

Example 5

A 14 pounds per gallon (ppg) fluid was formulated with DFJ as the oleaginous phase. Three 14 ppg were formulated with micronized manganese oxide: a mud containing uncoated micronized manganese oxide, drilling mud including uncoated micronized manganese oxide and a dispersant (EMI759, available from M-I LLC, Houston, Tex.), and a dispersant (EMI759) coated manganese oxide. The manganese oxide had a particle size distribution as follows: d₁₀=0.22 microns; d₅₀=0.99 microns; d₉₀=2.62 microns. Quantities of each component used in the mud formulations are given in Table 8 below, expressed in ppb (EMUL HT™, TRUVIS™, and ECOTROL® are each available from M-I LLC, Houston, Tex.).

TABLE 8

14 ppg Fluid Formulation

		Uncoated	Mud w/ Dispersant	Coated
		weighting	and uncoated	weighting
Product	Purpose	agent	weighting agent	agent

DF1	Base oil	168.67	157.62	157.03
Manganese Oxide	Density	325.44	325.66	340.22
EMUL HT ™	Emulsifier		10	10	10
EMI759	Dispersant or Coating	0	10	0
TRUVIS ™	Viscosifier	6	6	6
ECOTROL ®	Fluid loss additive	1	1	1
Lime	Alkalinity	6	6	6
CaCl₂Brine	Brine	18.66	18.87	17.83
Fresh Water		52.24	52.85	49.92

The above described drilling fluids were formulated to an oil/water ratio (OWR) of 80/20 and aged at 250° F. for 16 hours. Rheological properties were determined using a Fann Model 35 viscometer, available from Fann Instrument Company. Fluid loss was measured with a saturated API high temperature, high pressure (HTHP) cell. Gel strength (i.e., measure of the suspending characteristics or thixotropic properties of a fluid) was evaluated by the 10 minute gel strength in pounds per 100 square feet, in accordance with procedures in API Bulletin RP 1313-2, 1990. The results are shown in Table 9 below.

TABLE 9

14 ppg Fluid Properties
14 ppg; OWR 80/20; 250° F.

Fluid Property	Uncoated	Dispersant in Mud	Coated

PV (cP)	17	16	15
YP (lb/100 ft²)	11	7	4
Fann 35 6/3 rpm	6/5	4/4	2/2
10 min Gel (lb/100 ft²)	7/8	5/6	2/5
HTHP Fluid Loss (mL)	7.2	8	2.8
Static Sag Factor	0.527	0.518	0.516

The results show an enhanced Theological profile with the coated manganese oxide giving a lower yield point (YP), low-shear rate viscosities and gel strength. The fluid loss also shows improvement when using the dispersant coated manganese oxide. The results in Table 9 also show the benefit of coating the weighting agent with a dispersant as opposed to only including the dispersant in the mud formulation.
Advantageously, the benefits of the coated weight material may be optimum when a sized weighting agent is used. One skilled in the art would recognize that there may be benefits realized outside of a sized particle range, but a sized range may allow both ease of material dispersion and a requirement of fewer drilling fluid additives, such as an emulsifier and organoclay, to achieve the desired fluid properties. At higher mud weights (>16 ppg) there may be a considerable benefit in the ability of a dry-coated barite to be mixed and dispersed into the fluid compared with the difficulty of mixing and dispersing uncoated barite. Additionally, while conventional fluids do not allow for optimal performance in each of the aspects sag, rheology, and fluid loss, fluids such as those disclosed herein may allow optimization in each of those aspects. Further, because the coated weighting agent is formed in a dry process, it may be used without requiring additional weighting-up.
While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

1. A method of formulating a wellbore fluid comprising:

providing a base fluid; and

adding a sized weighting agent coated with a dispersant made by the method comprising:

dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant.

2. The method of claim 1, wherein the weighting agent is at least one selected from barite, calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, and strontium sulfate.

3. The method of claim 1, wherein the weighting agent is sized by the process of dry blending.

4. The method of claim 1, wherein the dry blending comprises dry blending a sized weighting agent and a dispersant.

5. The method of claim 1, wherein the sized weighting agent has a particle distribution given by d₉₀ranging from 2 to 8 μm.

6. The method of claim 1, wherein the sized weighting agent has a particle distribution given by d₅₀ranging from 0.5 to 4 μm.

7. The method of claim 1, wherein the dispersant comprises at least one selected from oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpa olefins sulfonic acid, alkaline earth metal salts thereof, and phospholipids.

8. The method of claim 1, wherein the dispersant comprises polyacrylate esters.

9. The method of claim 8, wherein the polyacrylate ester is at least one selected from polymers of stearyl methacrylate, butylacrylate, and acrylic acid.

10. The method of claim 1, wherein the base fluid is one selected from a water-based fluid, an oil-based fluid, and an invert emulsion.

11. The method of claim 1, wherein the wellbore fluid further comprises a colloidal coated weighting agent.

12. A wellbore fluid comprising:

a base fluid; and

a sized weighting agent coated with a dispersant made by the method comprising:

13. The wellbore fluid of claim 12, wherein the base fluid is one selected from a water-based fluid, an oil-based fluid, and an invert emulsion.

14. The wellbore fluid of claim 12, wherein the wellbore fluid further comprises: a colloidal coated weighting agent.

15. The wellbore fluid of claim 12, wherein the weighting agent is at least one selected from barite, calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, and strontium sulfate.

16. The wellbore fluid of claim 12, wherein the sized weighting agent has a particle distribution given by d₉₀ranging from 2 to 8 μm.

17. The wellbore fluid of claim 12, wherein the sized weighting agent has a particle distribution given by d₅₀ranging from 0.5 to 4 μm.

18. The wellbore fluid of claim 12, wherein the dispersant comprises at least one selected from oleic acid, polybasic fatty acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear alpa olefins sulfonic acid, alkaline earth metal salts thereof, and phospholipids.

19. The wellbore fluid of claim 12, wherein the dispersant comprises polyacrylate esters.

20. The wellbore fluid of claim 19, wherein the polyacrylate ester is at least one selected from polymers of stearyl methacrylate, butylacrylate, and acrylic acid.

21. The wellbore fluid of claim 12, wherein the weighting agent has a particle size distribution selected from at least one of a monomodal, bimodal, or polymodal distribution.