WO2010065634A2

WO2010065634A2 - Lubricant for water-based muds and methods of use thereof

Info

Publication number: WO2010065634A2
Application number: PCT/US2009/066404
Authority: WO
Inventors: Eugene Dakin
Original assignee: M-I L.L.C.
Priority date: 2008-12-04
Filing date: 2009-12-02
Publication date: 2010-06-10
Also published as: WO2010065634A3

Abstract

A water-based wellbore fluid that includes an aqueous fluid; a mixed metal oxide-clay complex; and a lubricant, wherein the lubricant comprises: a carrier agent comprising a Lewis base; and at least one fatty acid is disclosed.

Description

LUBRICANT FOR WATER-BASED MUDS AND METHODS OF USE

THEREOF

BACKGROUND OF INVENTION Field of the Invention

[0001] Embodiments disclosed herein relate to components of wellbore fluids (muds).

More specifically, embodiments relate to water-based muds and components thereof.

Background Art

[0002] During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.

[0003] In most rotary drilling procedures the drilling fluid takes the form of a "mud," i.e., a liquid having solids suspended therein. The solids function to impart desired rheological properties to the drilling fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well.

[0004] 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 wellbore 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. [0005] There is an increasing need for drilling fluids having the rheological profiles that enable wells to be drilled more easily. Drilling fluids having tailored rheological 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, reducing the exposure of 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).

[0006] 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. 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 lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.

[0007] Drilling fluids are typically classified according to their base material. The drilling mud may be either a water-based mud having solid particles suspended therein or an oil-based mud with water or brine emulsified in the oil to form a discontinuous phase and solid particles suspended in the oil continuous phase. [0008] On both offshore and inland drilling barges and rigs, drill cuttings are conveyed up the hole by the drilling fluid. Water-based drilling fluids may be suitable for drilling in certain types of formations; however, for proper drilling in other formations, it is desirable to use an oil-based drilling fluid. With an oil-based drilling fluid, the cuttings, besides ordinarily containing moisture, are coated with an adherent film or layer of oily drilling fluid which may penetrate into the interior of each cutting. This is true despite the use of various vibrating screens, mechanical separation devices, and various chemical and washing techniques. Because of pollution to the environment, whether on water or on land, the cuttings cannot be properly discarded until the pollutants have been removed.

[0009] Thus, historically, the majority of oil and gas exploration has been performed with water-based muds. The primary reason for this preference is price and environmental compatibility. The used mud and cuttings from wells drilled with water-based muds can be readily disposed of onsite at most onshore locations and discharged from platforms in many U.S. offshore waters, as long as they meet current effluent limitations guidelines, discharge standards, and other permit limits. As described above, traditional oil-based muds made from diesel or mineral oils, while being substantially more expensive than water-based drilling fluids, are environmentally hazardous.

[0010] As a result, the use of oil-based muds has been limited to those situations where they are necessary. The selection of an oil-based wellbore fluid involves a careful balance of both the good and bad characteristics of such fluids in a particular application. An especially beneficial property of oil-based muds is their excellent lubrication qualities. These lubrication properties permit the drilling of wells having a significant vertical deviation, as is typical of off-shore or deep water drilling operations or when a horizontal well is desired. In such highly deviated holes, torque and drag on the drill string are a significant problem because the drill pipe lies against the low side of the hole, and the risk of pipe sticking is high when water-based muds are used. In contrast oil-based muds provide a thin, slick filter cake which helps to prevent pipe sticking. [0011] Oil-based muds typically have excellent lubricity properties in comparison to water based muds, which reduces sticking of the drill pipe due to a reduction in frictional drag. The lubricating characteristics (lubricity) of the drilling mud provides the only known means for reducing the friction. Additionally, the use of oil-based muds is also common in high temperature wells because oil muds generally exhibit desirable rheological properties over a wider range of temperatures than water-based muds.

[0012] Thus, components or additives imparting a lubricating effect on water-based muds are desirable. Previously used lubricating materials include, for example, mineral oils, animal and vegetable oils and esters. However, with increasingly stricter regulations regarding the biodegradability of drilling fluids and their constituents, the use of the otherwise particularly suitable mineral oils is increasingly restrictive. Accordingly, there exists a continuing need for water-based muds having improved properties including lubricity.

SUMMARY OF INVENTION

[0013] In one aspect, embodiments disclosed herein relate to a water-based wellbore fluid that includes an aqueous fluid; a mixed metal oxide-clay complex; and a lubricant, wherein the lubricant comprises: a carrier agent comprising a Lewis base; and at least one fatty acid.

[0014] In another aspect, embodiments disclosed herein relate to a method of treating a wellbore that includes mixing an aqueous fluid, a mixed metal oxide-clay complex; and a lubricant to form a water-based wellbore fluid, wherein the lubricant comprises: a carrier agent a Lewis base; and at least one fatty acid; and using said water-based wellbore fluid during a drilling operation.

[0015] In yet another aspect, embodiments disclosed herein relate to a lubricant used in wellbore fluids that includes a carrier agent comprising a Lewis base; and at least one fatty acid.

[0016] Other aspects and advantages of the invention will be apparent from the following description and the appended claims. DETAILED DESCRIPTION

[0017] In one aspect, embodiments disclosed herein relate to lubricants used in water- based wellbore fluid formulations. In particular, embodiments described herein relate to the use of lubricants having fatty acids therein capable of imparting lubricity upon a wellbore fluid without negatively interacting with other components of the wellbore fluid. Such embodiments may find particular use in water-based fluids containing, inter alia, mixed metal oxide and clay complexes. One of ordinary skill in the art will recognize that drilling or wellbore fluids may also comprise various other additives such as viscosifiers, gelling agents, bridging agents, and fluid loss control agents, as known in the art. The lubricant may be formed from several components, including at least one fatty acid, a weak acid, a weak base, an amphoteric chemotrope, and combinations thereof.

[0018] Lubricant

[0019] In one embodiment, a lubricant may be comprised of a Lewis base-containing carrier agent and at least one fatty acid (in water). The carrier agent may then serve as a carrier for the fatty acid component of the lubricant into the wellbore fluid, by ionic interaction between the fatty acid and the Lewis base atom and/or hydrogen bonding with terminal hydroxyl groups that may optionally be present on the carrier agent.

[0020] Fatty acids suitable for use in embodiments of the present disclosure may include fatty acids such as butyric acid (C4), caproic acid (C6), caprylic acid (C8), capric acid (ClO), lauric acid (C 12), mysristic acid (C 14), palmitic acid (C 16), stearic acid (Cl 8), etc, in addition to unsaturated fatty acids such as myristoleic acid (C 14), palmitoleic acid (C 16), oleic acid (C 18), linoleic acid (C 18), alpha-linoleic acid (C 18), erucic acid (C22), etc, or mixtures thereof. Fatty acids are desirable as they may be non-toxic and readily biodegradable. The long chain fatty acids may also provide derivatives that have desirable viscosity/rheological profiles.

[0021] In mixed metal oxide fluid systems, where the rheological properties are derived from interaction between mixed metal oxides and clay particles, addition of a lubricant to the fluid may cause the lubricant to undesirably interact with the mixed metal oxide-clay complex to result in a sudden drop in viscosity and render the fluid unsuitable for its intended purpose. For example, conventional lubricants or even a fatty acid such as oleic acid, if added alone (without a carrier), may interact with other components of the wellbore fluid, e.g., a surface-charged clay such as bentonite, and prevent such component from properly interacting with other fluid components, e.g., a mixed metal oxide component (also referred to as a "bentonite extender"). By providing a component capable of "carrying" the oleic acid (or other fatty acid) into the cationic drilling fluid system (containing the metal oxide-clay complex), interference by the oleic acid with interactions between other components of the wellbore fluid may be prevented and/or reduced. Additionally, lubricity may be provided by the long chains of the fatty acid and the stability of the complex may be increased.

[0022] As mentioned above, the carrier agent may include a Lewis base to which the acid end of the fatty acid may be attracted, reducing or preventing the acid end from interacting with the charged surface of the clay (and displacing the mixed metal oxide). Additionally, the carrier agent may include a net cationic charge, increasing the cationic concentration of the already charged (cationic) drilling fluid system. By increasing the cationic charge, the effect of an anionic lubricant component on the charged clay surface may be reduced or minimized, which thus reduces or minimizes the effect on the fluid rheology.

[0023] Nitrogen-containing compounds in the oxidation state III possess a lone pair of electrons available to donate. Thus, in a particular embodiment, the carrier agent may be an amine, including including secondary, tertiary, or quaternary amines such as alkyl amines, alkanol amines, or alkoxy amines. Depending on the pH of the wellbore fluid in which the amine is being used, as well as the specific amine being used, it is also possible that the nitrogen atom may be protonated. However, while specific reference to amines are being made, it is within the scope of the present disclosure that other Lewis bases known in the art such as phosphine derivatives could alternatively be used.

[0024] In a particular embodiment, the amine may be a polyamine, i.e., a compound having more than two amino groups. Such polyamines may include those such as ethylene diamine, diethylene triamine, triethylene tetraamine, other polyethylene amines, and the like (including branched and substituted derivatives thereof). However, it also within the scope of the present disclosure that, in addition to hydrocarbon based polyamines, polyamine may be an inorganic-based polymer formed by polymerization of alkanol amines and/or alkoxy amines with various acids having at least two reactive groups such as boric acid, phosphoric acid, adipic acid, aluminum hydroxide, and the like. The inventors of the present disclosure believe that use of such inorganic polyamines may provide for a stronger carrying effect, minimizing the potential interaction between the carried fatty acid and mixed metal oxide-clay complex.

[0025] Particular examples of such amines that may be reacted with a compound such as boric acid include triethanolamine, diethanolamine, morpholine, or combinations thereof. However, one skilled in the art would appreciate that other compounds may be used, such as propanolamines derivatives. With use of alkanolamines, for example, it is also possible that in addition to the Lewis base center, the fatty acids may also have some interactions (hydrogen bonding) with terminal hydroxyl groups present in the compound.

[0026] Furthermore, an amphoteric chemotrope component may optionally be added to the lubricant to allow for good dispersion of the lubricant, and thus increased stability thereof (as dispersed or emulsed droplets), particularly when a long chain fatty acid is added to a wellbore fluid that contains salt, for example. As used herein, an amphoteric chemotrope refers to a compound that exhibits dual properties of being amphoteric (a substance that can react as either an acid or a base) and chemotropic (the way in which a substance orients itself in relation to other chemicals). In a particular embodiment, the amphoteric chemotrope may be hydrotropic (the way in which a substance orients itself in relation to water). Use of this class of compounds may allow for the stabilization of a lubricant that is not otherwise stabilized by conventional components in the wellbore fluid. For example, the addition of a lubricant to a wellbore fluid that contains salt may result in an unstable dispersion of the lubricant in the wellbore fluid. The presence of an amphoteric chemotrope in the lubricant may stabilize the dispersion of the lubricant in such a wellbore fluid and thus may be referred to as a brine compatibility agent as a result of its ability to transform an otherwise unstable mixture into a stabilized wellbore fluid. [0027] In a particular embodiment, the amphoteric chemotrope may be a quaternary ammonium compound represented by the formulae below:

where Rl may be an alkyl or alkenyl group having at least 8 carbons; R2 may be an alkyl group having 2-6 carbon atoms; R3 may be an alkyl group having at least 4 carbons; n may be either 2 or 3; x + y is greater than 5, preferably 5-20; z ranges from 0 to 3; B is hydrogen, an oxyalkyl or alkyl having 1 to 4 carbons, and M is a counter anion, such as a halide. However, one skilled in the art would appreciate that that there may be a balance between the Rl / R2 chain and the sum of x + y. That is, if the Rl / R2 chain possesses more than 22 carbons, it may be desirable to increase the amount of alkoxylation to greater than 20 so that the compound remains amphiphilic, and vice versa. In particular embodiments, the Rl may be derived from various fatty acids such as butanoic acid (C4), hexanoic acid (C6), octanoic acid (C8), decanoic acid (ClO), dodecanoic acid (C 12), tetradecanoic acid (C 14), hexadecanoic acid (C 16), octadecanoic acid (C 18), etc.

[0028] Further, the counter anions to the quaternaries of the present disclosure may include a variety of counter anions such as the conjugate base to any mineral or strong organic acid, such as halide ion, nitrate ion, sulfate ion, acetate ion, alkyl sulfonate ion, haloalkylsulfonate ions, and the like. Additionally, one skilled in the art would appreciate that additional variations such as substitutions, etc., may exist, so long as they do not alter the nature of the compound to stabilize water-based wellbore fluids.

[0029] Examples of suitable amphoteric chemotropes may include quaternary ammonium salts, including quaternary ammonium halides such as chlorides. In a particular embodiment, the amphoteric chemotrope may be an alkoxylated quaternary ammonium chloride (ethoxylated or propoxylated) including quaternary ammonium chlorides derived from fatty amines. Examples of such alkoxylated quaternary ammonium chloride may be isotridecyloxypropyl poly(5)oxyethylene methyl ammonium chloride or coco poly(15)oxy ethylene methyl ammonium chloride. Commercial examples of suitable amphoteric chemotropes include Q- 17-5 and Q-C- 15, which are both ethoxylated quaternary ammonium chlorides, available from Air Products and Chemicals (Allentown, PA).

[0030] One exemplary lubricant formulation may include (by volume) about 30-70 percent water, about 0.1-15 percent of the boric acid, about 10-40 percent of the triethanolamine, about 0.1-20 percent of the fatty acid, and about 0-20 percent of amphoteric chemotrope. In one particular embodiment of the present disclosure, the lubricant may be comprised of (by volume) about 40-60 percent water, about 3-10 percent boric acid, about 15-25 percent triethanolamine, about 5-15 percent oleic acid, and about 5-20 percent amphoteric chemotrope.

[0031] Wellbore Fluid Formulation

[0032] As mentioned above, the lubricants of the present disclosure may find particular use in a water-based wellbore fluid that includes a mixed metal oxide-clay complex and an aqueous base fluid.

[0033] The aqueous fluid of the wellbore 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 wellbore 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, aluminum, magnesium, potassium, strontium, and lithium, salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, 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 wellbore 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 wellbore 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.

[0034] Additionally, the water-based wellbore fluid may include a mixed metal oxide-clay complex. Such clays may include those having surface charges thereon, including, for example, bentonite, saponite, hectonite, and kaolinite. One commercial example of such a clay source is GELPLEX™, an untreated bentonite, which is available from M-I L.L.C. (Houston, TX). Clay flakes are made up of a number of crystal platelets each being called a unit layer. The unit layers stack together face-to- face and are held in place by weak attractive forces between the ionic surfaces of the unit layer. The distance between corresponding planes in adjacent unit layers is called the c-spacing. Clay swelling is a phenomenon in which water molecules surround a clay crystal structure (based on attraction to the ionic surface) and position themselves to increase the structure's c-spacing, thus resulting in an increase in volume. Two types of swelling may occur. Surface hydration is one type of swelling in which water molecules are adsorbed on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen atoms exposed on the crystal surfaces. Subsequent layers of water molecules align to form a quasi-crystalline structure between clay's unit layers which results in an increased c-spacing. Various types of clays swell in this manner. Osmotic swelling is a second type of swelling. Where the concentration of cations between unit layers in a clay mineral is higher than the cation concentration in the surrounding water, water is osmotically drawn between the unit layers and the c-spacing is increased. Osmotic swelling results in larger overall volume increases than surface hydration. However, only certain clays, like sodium montmorillonite (bentonite), swell in this manner.

[0035] As mentioned above, the ionic surfaces of such clays are usually attractive to cations such as sodium or potassium. However, when exposed to other cations, the unit layer can serve as cation exchange sites for other cations available in the system. When metal cations, such as in the form of mixed metal oxides are added to a fluid, the metal cations may replace the sodium or potassium cations. However, as these metal ions are polyvalent, the metals may more strongly associate with the clay surface and/or with neighboring clay platelets. Such phenomenon is described in more detail in U.S. Patent Nos. 5,232,627 and 4,664,843, for example. One commercial example of a mixed metal oxide is DRILPLEX™ Mixed Metal Oxide, also available from M-I L.L.C. (Houston, TX). It is postulated that the interaction between clay and a mixed metal oxide not only increases the viscosity of the fluid by swelling of the clay as well as formation of a unique electrostatic environment through association of the clay and mixed metal oxide, but the particle complex may also act as a bridging agent to help plug pores of a formation and reduce filtration losses.

[0036] In addition to these components, the wellbore fluids may also include other conventional additives known in the art of wellbore fluids, including conventional bridging agents, weighting agents, viscosifiers, gelling agents, fluid loss control agents, foaming agents, etc. For example, conventional viscosifiers, such as water soluble polymers and polyamide resins, may also be used. The amount of viscosifier used in the composition can vary upon the end use of the composition. However, normally about 0.1% to 10% by weight range is sufficient for most applications.

[0037] In one embodiment, the water-based wellbore fluid may include a weighting agent. Weighting agents or density materials suitable for use the fluids disclosed herein include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like. The quantity of such material added, if any, may depend upon the desired density of the final composition. Typically, weighting agent is added to result in a wellbore fluid density of up to about 24 pounds per gallon. The weighting agent may be added up to 21 pounds per gallon in one embodiment, and up to 19.5 pounds per gallon in another embodiment.

[0038] Conventional bridging agents may include bridging materials suitable for use in the present disclosure include graphite, calcium carbonate (preferably, marble), dolomite (MgCO3.CaCO3), celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof.

[0039] Defoaming agents may include various ester-, alcohol-, or hydrocarbon-based compounds as known in the art. Two commercial examples of defoaming agents include DEFOAM™-A and DEFOAM™-X, both of which are available from M-I L.L.C. (Houston, Texas). [0040] A variety of fluid loss control agents may be added to the wellbore fluids disclosed herein and are generally selected from a group consisting of synthetic organic polymers, biopolymers, polysaccharide derivatives, and mixtures thereof. In one embodiment, the fluid loss control agent should be selected to have low toxicity, compatibility with additional wellbore fluid components, and water-solubility. Fluid loss control agents may include, for example, FLO-PLEX™ which is available from M-I L. L. C. (Houston, TX), a water-soluble polysaccharide derivative which is effective in salt-containing wellbore fluids, resistant to bacterial degradation, and which provides fluid loss control without lowering the yield-point value or destroying the low-end rheology of other components of the wellbore fluid.

[0041] Other additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, soda ash, surfactants, shale inhibitors, filtration reducers, dispersants, interfacial tension reducers, pH buffers or pH adjusting agents, mutual solvents, thinners (such as lignins and tannins), thinning agents and cleaning agents. Suitable pH adjusting agents for use in the fluids disclosed herein may include, for example, sodium hydroxide, sodium carbonate, potassium hydroxide and potassium carbonate. In a particular embodiment, a potassium-containing pH-adjusting agent may be used to simultaneously adjust the pH and provide clay inhibition and a lower dispersion effect to minimize an overload of low-gravity solids and high-gravity solids from dispersing into the fluid system. The addition of such agents should be well known to one of ordinary skill in the art of formulating wellbore fluids and muds.

[0042] The water-based fluids described herein may be used during a drilling operation. The fluid may be pumped down to the bottom of the well through a drill pipe, where the fluid emerges through ports in the drilling bit, for example. In one embodiment, the fluid may be used in conjunction with any drilling operation, which may include, for example, vertical drilling, extended reach drilling, and directional drilling. One skilled in the art would recognize that water-based drilling muds may be prepared with a large variety of formulations. Specific formulations may depend on the state of drilling a well at a particular time, for example, depending on the depth and/or the composition of the formation. The drilling mud compositions described above may be adapted to provide improved water-based drilling muds under conditions of high temperature and pressure, such as those encountered in deep wells.

[0043] Sample Formulations

[0044] The following examples were used to test the effectiveness of water-based wellbore fluids that contain lubricants as disclosed herein. In the following examples, various additives commercially available from M-I L.L.C. (Houston, Texas) are used, including: GELPLEX™, a gelling agent comprising untreated sodium bentonite; DRILPLEX™, a mixed metal oxide; FLO-PLEX®, a water- soluble polysaccharide derivative used to control filtration and to control fluid loss; barite; EMI-795, a clay inhibitor; and EMI-1008, a lignosulphonate suppressant.

PA-IO is a lubricant available from Alpine Specialty Chemical (Houston, Texas). Referring to Table 1 , below, the formulations of the water-based fluids for Samples 1-2 are shown, with three Comparative Samples ("CS-l-CS-3") being water, no lubricant added thereto, and a known lubricant added thereto. The lubricant component of the wellbore fluid formulations for Samples 1 and 2 shown in Table 1 is comprised of 53.57% water (30 mL), 5.36% boric acid (3 g industrial -99%), 21.43% triethanolamine (12 mL 99%), 10.71% oleic acid (6 mL Acme chemicals; no tall oil), and 8.93% amphoteric chemotrope (5 mL ECF- 1989, an ethoxylated quaternary ammonium chloride, available from M-I L.L.C. (Houston, Texas)).

Table 1. Wellbore fluid Formulations

[0045] The rheological properties, gels properties, plastic viscosity, and yield point of the various mud formulations at 120 °F after shear rates of 600 θ (rpm), 300 θ, 200 θ, 100 θ, 6 θ, and 3 θ, as shown below in Table 2, were determined using a Farm Model 35 Viscometer available from Farm Instrument Company.

Table 2. Rheology of Various Mud Formulations at 120 ⁰F

[0046] Lubricity coefficients for both smooth-on-smooth ("Lubricity CoF") surfaces and knurled-on-smooth ("LEM CoF") surfaces were determined at room temperature on the LEM at 200 rpm with a load of 32 psi using a 1.25" knurled bob; the test medium was steel. The Lubricity CoF for water was determined to be 0.320 and the LEM CoF was determined to be 0.36. The lubricant had the most positive effects when lubricating the fluid under either smooth (Lubricity CoF) or rough knurled-on-smooth (LEM CoF) surfaces, particularly when compared to Comparative Sample 3, which contained a known lubricant PA- 10®.

[0047] Advantages of the embodiments disclosed herein may include enhanced rheological properties of the fluids that incorporate lubricants as described herein. Additionally, the incorporation of a carrier for the at least one fatty acid may provide beneficial lubricating properties as well as prevent the at least one fatty acid from interfering with other components of a wellbore fluid. The at least one fatty acid component of the lubricant may impart beneficial lubricity to the wellbore fluid as well as beneficial water solubility characteristics due to the polar alcohol functional groups in the fatty acids.

[0048] 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

CLAIMSWhat is claimed:

1. A water-based wellbore fluid, comprising: an aqueous fluid; a mixed metal oxide-clay complex; and a lubricant, wherein the lubricant comprises: a carrier agent comprising a Lewis base; and at least one fatty acid.

2. The wellbore fluid of claim 1, wherein the at least one fatty acid comprises butyric acid, caproic acid, caprylic acid, capric acid, lauric acid, mysristic acid, palmitic acid, stearic acid, myristoleic acid, palmitoleic acid, oleic acid, linoleic acid, alpha-linoleic acid, erucic acid, or combinations thereof.

3. The wellbore fluid of claim 2, wherein the at least one fatty acid comprises oleic acid.

4. The wellbore fluid of claim 1, wherein the carrier agent comprises an inorganic polyamine.

5. The wellbore fluid of claim 4, wherein the carrier agent comprises a reaction product between boric acid and at least one secondary or tertiary alkanol amine.

6. The wellbore fluid of claim 5, wherein the secondary or tertiary alkanol amine comprises at least one of triethanolamine, diethanolamine, or morpholine.

7. The wellbore fluid of claim 1, wherein the lubricant further comprises: an amphoteric chemotrope.

8. The wellbore fluid of claim 7, wherein the amphoteric chemotrope comprises an ethoxylated quaternary ammonium chloride, a quaternary ammonium salt, an alkoxylated quaternary ammonium chloride, quaternary ammonium chlorides derived from fatty amines, or combinations thereof.

9. The wellbore fluid of claim 1, wherein the mixed metal oxide-clay complex comprises at least one surface charged clay.

10. The wellbore fluid of claim 9, wherein the at least one surface charged clay comprises at least one of bentonite, saponite, hectonite, or kaolinite.

11. The wellbore fluid of claim 1, further comprising: at least one of a gelling agent, a viscosifier, a bridging agent, a fluid loss control agent, a foaming agent, a wetting agent, a surfactant, a shale inhibitor, a filtration reducer, a dispersant, an interfacial tension reducer, a pH buffer, a mutual solvent, a thinner, a thinning agent, a cleaning agent, soda ash, or combinations thereof.

12. A method of treating a wellbore, comprising: mixing an aqueous fluid, a mixed metal oxide-clay complex; and a lubricant to form a water-based wellbore fluid, wherein the lubricant comprises: a carrier agent a Lewis base; and at least one fatty acid; and using said water-based wellbore fluid during a drilling operation.

13. The method of claim 12, wherein the at least one fatty acid comprises butyric acid, caproic acid, caprylic acid, capric acid, lauric acid, mysristic acid, palmitic acid, stearic acid, myristoleic acid, palmitoleic acid, oleic acid, linoleic acid, alpha-linoleic acid, erucic acid, or combinations thereof.

14. The method of claim 14, wherein the at least one fatty acid comprises oleic acid.

15. The method of claim 12, wherein the carrier agent comprises an inorganic polyamine.

16. The method of claim 15, wherein the carrier agent comprises a reaction product between boric acid and at least one secondary or tertiary alkanol amine.

17. The method of claim 16, wherein the secondary or tertiary alkanol amine comprises at least one of triethanolamine, diethanolamine, and morpholine.

18. The method of claim 12, wherein the lubricant further comprises: an amphoteric chemotrope.

19. The method of claim 18, wherein the amphoteric chemotrope comprises an ethoxylated quaternary ammonium chloride, a quaternary ammonium salt, an alkoxylated quaternary ammonium chloride, quaternary ammonium chlorides derived from fatty amines, or combinations thereof.

20. The method of claim 12, wherein the mixed metal oxide-clay complex comprises at least one surface charged clay.

21. The method of claim 20, wherein the at least one surface charged clay comprises at least one of bentonite, saponite, hectonite, or kaolinite.

22. A lubricant used in wellbore fluids, comprising: a carrier agent comprising a Lewis base; and at least one fatty acid.

23. The lubricant of claim 22, wherein the at least one fatty acid comprises butyric acid, caproic acid, caprylic acid, capric acid, lauric acid, mysristic acid, palmitic acid, stearic acid, myristoleic acid, palmitoleic acid, oleic acid, linoleic acid, alpha-linoleic acid, erucic acid, or combinations thereof.

24. The lubricant of claim 23, wherein the at least one fatty acid comprises oleic acid.

25. The lubricant of claim 22, wherein the carrier agent comprises an inorganic polyamine.

26. The lubricant of claim 24, wherein the carrier agent comprises a reaction product between boric acid and at least one secondary or tertiary alkanol amine.

27. The lubricant of claim 26, wherein the secondary or tertiary alkanol amine comprises at least one of triethanolamine, diethanolamine, and morpholine.

28. The lubricant of claim 22, wherein the lubricant further comprises: an amphoteric chemotrope.

9. The lubricant of claim 28, wherein the amphoteric chemotrope comprises an ethoxylated quaternary ammonium chloride, a quaternary ammonium salt, an alkoxylated quaternary ammonium chloride, quaternary ammonium chlorides derived from fatty amines, or combinations thereof.