WO2016029030A1

WO2016029030A1 - Method to enhance fiber bridging for improved lost circulation control

Info

Publication number: WO2016029030A1
Application number: PCT/US2015/046137
Authority: WO
Inventors: Anastasia SHALAGINA; Diankui Fu; Nicolas Droger
Original assignee: M-I L.L.C.
Priority date: 2014-08-21
Filing date: 2015-08-20
Publication date: 2016-02-25

Abstract

An oil-based wellbore fluid may include an oil-based continuous phase, a non-oleaginous discontinuous phase, a lost circulation material and a water absorbing material.

Description

METHOD TO ENHANCE FIBER BRIDGING FOR IMPROVED LOST

CIRCULATION CONTROL

BACKGROUND

[0001] This application claims the benefit of U.S. Provisional Application No. 62/039981 filed on August 21, 2014, incorporated by reference herein in its entirety.

[0002] During the drilling of a wellbore, various fluids are 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, a 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] Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively. When the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is often maintained at a higher pressure than the pore pressure. However, when wellbore pressures are maintained above the pore pressure, the pressure exerted by the wellbore fluids may exceed the fracture resistance of the formation and fractures and induced mud losses may occur. Further, formation fractures may result in the loss of wellbore fluid that decreases the hydrostatic pressure in the wellbore, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure may define an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, one constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients through the depth of the well. [0004] As stated above, wellbore fluids are circulated downhole to remove rock, as well as deliver agents to combat the variety of issues described above. The selection of the type of a wellbore fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the wellbore fluids in the particular application and the type of well to be drilled. Frequently, the selection of a fluid may depend on the type of formation through which the well is being drilled. Fluid compositions may be water- or oil-based and may contain weighting agents, surfactants, proppants, viscosifiers, and fluid loss additives. However, fluid loss may impede wellbore operations, as fluids escape into the surrounding formation. During drilling operations, variations in formation composition may lead to undesirable fluid loss events in which substantial amounts of wellbore fluid are lost to the formation through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole. While fluid loss is often associated with drilling applications, other fluids may experience fluid loss into the formation including wellbore fluids used in completions, drill-in operations, productions. Lost circulation is an uncontrolled flow of a wellbore fluid (such as a drilling mud) into a fractured formation, and may occur naturally in formations that are fractured, highly permeable, porous, cavernous, vugular, or can be artificially induced by excessive mud pressures.

[0005] As previously discussed, lost circulation may also result from induced pressure during drilling, thereby giving the fluid a channel to travel away. Specifically, induced mud losses may occur when the mud weight, which is often tuned for well control to maintain a stable wellbore, exceeds the fracture resistance of the formations. A particularly challenging situation arises in depleted reservoirs, in which the drop in pore pressure effectively weakens a wellbore through permeable, potentially hydrocarbon- bearing rock formation, but neighboring or inter-bedded low permeability rocks maintain their pore pressure. This can make the drilling of certain depleted zones impossible because the mud weight employed to support lower permeability rocks such as shale may exceed the fracture resistance of high permeability sands and silts. Another unintentional method by which lost circulation can result is through the inability to remove low and high gravity solids from fluids. Without being able to remove such solids, the fluid density can increase, thereby increasing the hole pressure, and if such hole pressure exceeds the formation fracture pressure, fractures and fluid loss can result. Thus, over the decades, lost circulation has been one of the most time consuming and cost inflating events in drilling operations.

[0006] Various methods have been used to restore circulation of a drilling fluid when a lost circulation event occurred, particularly the use of "lost circulation materials" (LCM) that seal or block further loss of circulation. LCM may generally be classified into several categories: surface plugging, interstitial bridging, and/or combinations thereof. In addition to traditional LCM pills, crosslinkable or absorbing polymers, and cement or gunk squeezes have also been employed to combat fluid loss downhole.

BRIEF DESCRIPTION OF DRAWINGS

[0007] FIG. 1 illustrates fluid loss in a fractured formation, in accordance with aspects of the present disclosure.

[0008] FIG. 2 illustrates a mechanism of reducing fluid loss, in accordance with aspects of the present disclosure.

[0009] FIG. 3 illustrates a mechanism of triggering the viscosity reduction of an oil- based drilling fluid, in accordance with aspects of the present disclosure.

[0010] FIG. 4 illustrates the viscosity of an oil-based drilling mud (OBM) as a function of the water content, in accordance with aspects of the present disclosure.

[0011] FIG. 5 illustrates microscopic images of carboxymethyl cellulose, in accordance with aspects of the present disclosure.

DETAILED DESCRIPTION

[0012] Embodiments disclosed herein relate generally to methods of treating fluid loss in downhole formations. More specifically, embodiments disclosed herein relate to wellbore fluids for downhole applications formed of an oil-based continuous phase, a water-based dispersed phase, a lost circulation material and a water absorbing material. The inventors of the present disclosure have found that the presence of a water absorbing material in the wellbore fluid allows for reduction of the viscosity of the oil-based wellbore fluid to occur in situ. The triggered viscosity reduction of the wellbore fluid may promote bridging performance of the lost circulation material, as well as sealing of the lost circulation zone. [0013] The base fluids described herein may be oil-based wellbore fluids, such as an invert emulsion where a non-oleaginous fluid is emulsed within an oleaginous continuous fluid. Suitable oleaginous fluids may be a natural, mineral or synthetic oil and in some embodiments, the oleaginous fluid may be selected from the group including petroleum oil, a natural oil, a mineral oil, a silicone oil, a synthetically derived oil, such as hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, 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.

[0014] As mentioned above, the wellbore fluid may be an invert emulsion having a continuous oleaginous phase and a discontinuous aqueous (or non-oleaginous liquid) phase, among other substances and additives. Non-oleaginous liquids may, in some embodiments, include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds, and mixtures thereof. In various embodiments, the non-oleaginous fluid may be a brine, which 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, sulfates, silicates, phosphates and fluorides. Salts that may be incorporated in a 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.

[0015] The amount of oleaginous liquid in the invert emulsion fluid may vary depending upon the particular oleaginous fluid used, the particular non-oleaginous fluid used, and the particular application in which the invert emulsion fluid is to be employed. However, in some embodiments, the amount of oleaginous liquid may be sufficient to form a stable emulsion when used as the continuous phase. The amount of non-oleaginous liquid in the invert emulsion fluid may vary depending upon the particular non-oleaginous fluid used, the emulsifier selected to stabilize the non-oleaginous phase, and the particular application in which the invert emulsion fluid is to be employed.

[0016] In one or more embodiments, the oil based fluid may contain up to 60 or 70 or 80 vol. % water or other non-oleaginous fluids, and at least 20, 30, 40, 50, 60, or 70 vol. % of oleaginous fluids. The volume concentration of the non-oleaginous phase affects the viscosity of an invert emulsion. Specifically, the higher the internal content, the higher the viscosity of the emulsion. Plastic viscosities in the range of 10-100 cP and yield stress in the range of 10-40 lb/ 100 ft² may be desirable for the formulation of the wellbore fluids of the present disclosure to carry the LCM materials within the pill and reduce or prevent premature plug formation by the LCM materials. In yet another embodiment, the plastic viscosity may range from about 20 to about 50 cP, and the yield stress may range from about 10 to about 20 lb/100 ft².

[0017] However, embodiments of the present disclosure may utilize a viscosity reduction in situ upon desired placement of the fluid to the region of the wellbore needing treatment by the LCM materials. Viscosity reduction may be achieved by disrupting the invert emulsion, such as by the shear forces generated at the bit, when the amount of non- oleaginous fluid present in the internal phase is reduced by the absorption of at least a portion of the non-oleaginous fluid by the water absorbing material also present in the fluid. Specifically, the shear forces generated by the passage of the wellbore fluid through a restriction, e.g. nozzles of a drill bit, may produce enough stress to disrupt the invert emulsion enough to expose the water or other non-oleaginous fluid present in the oil-based fluid to the water absorbing material such that at least a portion of the water or other non-oleaginous fluid is absorbed, thereby reducing the emulsified phase and the viscosity as a result. The reduced viscosity may allow for plug formations and bridging of fractures in the formation in the region of the wellbore that is experiencing fluid loss.

[0018] The water absorbing material may be an inorganic or an organic compound.

Inorganic absorbing materials can be selected from the class of molecular sieves such as zeolites which are able to absorb water due to their microporous frameworks, or silica and aluminosilicates. Organic absorbing materials may include polymeric materials that have the ability to swell (change volume) in response to contact with water, also referred to as water swellable materials. Such water swellable materials comprise water swellable rubbers, natural or synthetic superabsorbent polymers, or combinations thereof that include, but are not limited to cellulose, carboxymethyl cellulose, polyacrylates, polyacrylamide copolymers, hydrogels, ethylene maleic anhydride copolymers, polyvinyl alcohol copolymers, cross-linked polyethylene oxide, starch grafted copolymer of polyacrylonitrile, wherein the absorption of water molecules is done through hydrogen bonding. In various embodiments, the water absorbing materials may be effective in absorbing the water, or other non-oleaginous phase, from an oil-based emulsion under shearing which is applied to facilitate the interaction of the absorbent material with the previously emulsified water droplets. According to various embodiments, the water absorbing material may be used in a concentration from about 1% wt. to about 10% wt by the total weight of the invert emulsion. In one or more embodiments, the concentration of the water absorbing material may range from about 1% wt. to about 3% wt. The size of the water absorbing material may influence the swelling or absorption mechanism. In various embodiments, the water absorbing material may have a particle size ranging from about 0.5 mm to about 5 mm. In yet another embodiment, the water absorbing material has a particle size ranging from about 1 mm to about 3 mm.

[0019] In the context of the present disclosure, the term "swell" and similar terms such as

"swellable" are used herein to indicate an increase in volume of a swellable material, whereas absorption may but does not necessarily result in a volume change. A swellable material can swell greater than about 2 times its dried volume when placed in contact with water. For example, the swellable material can swell greater than about 3 times, 4 times, 5 times, 6 times, 7 times, or greater its dried volume when placed in contact with water. Typically, this increase in volume is due to the incorporation of the molecular components of an activating agent, such as water, into the swellable material itself, but other swelling mechanisms or techniques may be used, if desired.

[0020] In one or more embodiments described herein, the organic absorbing material is a superabsorbent polymer (SAP). Superabsorbent polymers are swellable, crosslinked polymers that have the ability to absorb and retain extremely large amounts of water, relative to their own mass, with the concomitant swelling. In one embodiment, the wellbore fluid contains SAP from about 1% wt. to about 10% wt. by the total weight of the invert emulsion. In one or more embodiments, the swelling time of the superabsorbent polymer may range from about 30 minutes to about 10 hours. In yet another embodiment, the swelling time of the superabsorbent polymer may range from about 10 minutes to 10 hours.

[0021] As mentioned above, another component of the wellbore fluids of this disclosure is a lost circulation material (LCM), which forms the resulting plug or seal upon the reduction in viscosity. Examples of such LCM products include fibrous, flaky, and granular materials, as well as their blended compositions, that may include wood fiber, paper, mica, cellophane, nut shells, coarse graphite and calcium carbonate, for example. The type and the concentration of the LCM materials used depend on the particular type of well conditions and may be tailored depending on the severity of the fluid loss since the size of the fracture taking mud is seldom known.

[0022] Various embodiments of the present disclosure may use fibrous LCM materials, wherein the fibers have an elongated structure which may be spun into filaments or used as a component of a composite material such as paper. While some embodiments may use a synthetic fiber, other embodiments may include either a naturally occurring fibrous material, and/or a synthetic fibrous material, wherein the fibrous material may provide additional compressive strength to the resulting plug or seal. In one or more embodiments, the fibers used are selected from the group of polyesters, acrylic polymers, polyamides, polyolefins, polyaramides, polyurethanes, vinyl polymers, glass fibers, carbon fibers, regenerated cellulose (rayon), natural fibers or blends thereof.

[0023] FIG. 3 depicts the swelling mechanism of a water absorbing material upon contact with an invert emulsion 300 disrupted by the shear forces generated at the bit, when the water 301 is exposed to the water absorbing material 302 (e.g., SAP). Upon disruption of the emulsion 300, the water absorbing material 302 transforms water 301 from an emulsified state to an absorbed state. As such, some of the water droplets 301 present in the oil-based emulsion 300 will be retained inside the water absorbing material, such as within the polymer matrix of the superabsorbent polymer 302, with the formation of a swollen state 303 of the polymer. Time, temperature, shear rate and the concentration of the absorbing material (e.g., SAP) are parameters that may have an effect on the removal of the water phase from an emulsion. The swollen state of the polymer occurs prior to reaching a lost circulation zone. Thus, the swollen state of the polymer 303 may serve as a part of an LCM pill, helping thus to seal a lost circulation zone. Therefore, the use of the LCM fibers in the presence of the water absorbing material has a synergistic effect on the rheological properties of the wellbore fluid, depicted in an improved fluid loss control, compared to a conventional mechanism of reducing fluid loss in a fracture formation, as shown in FIGS. 1 and 2. Specifically, a conventional mechanism of reducing loss of fluids 101 in a formation 100 (FIG. l), starts with bridging of the LCM fibers 201 at the entrance or inside of a fractured formation 200, when a fiber network with void spaces is formed, and continues with plugging the void spaces in the fiber network by fine solid particles 202 (FIG.2). Reducing the viscosity of the base fluid in this manner improves the bridging efficiency in terms of fiber loading, but under a certain value of the fluid viscosity, the fluid is not able to sustain the fibers and other solids inside the LCM pill before it reaches the lost circulation zone.

[0024] As seen in FIG. 4, separation of the water from the invert emulsion lowers the water content of the emulsion and therefore triggers a reduction in the oil-based fluid viscosity followed by bridging of the LCM fibers, closing the fissures and pores through which the drilling fluid would be lost. In various embodiments, the entire amount of water present in the invert emulsion may be removed from the emulsion; however, the present disclosure is not limited and may also involve partial removal of water. For example, removal of 50 % of water from the initial invert emulsion comprising 70 % oil / 30 % water may lead to a decrease of the fluid viscosity from 15.6 to 9.6 cP as shown in FIG. 4.

[0025] Other additives that may be included in the wellbore fluids disclosed herein include for example, weighting agents, wetting agents, organophilic clays, viscosifiers, 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.

[0026] Emulsifiers that may be used in the fluids disclosed herein include, for example, fatty acids, soaps of fatty acids, amidoamines, polyamides, polyamines, oleate esters, such as sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or alcohol derivatives and combinations or derivatives of the above. Additionally, lime or other alkaline materials may be added to conventional invert emulsion drilling fluids and muds to maintain a reserve alkalinity.

[0027] In various embodiments, the invert emulsion may be a high internal phase ratio

(HIPR) emulsion, wherein the aqueous or non-oleaginous fluid within the oleaginous fluid is present in a volume amount that is more than the non-oleaginous fluid. While a number of possible emulsifiers may be used, one class of emulsifiers is alkoxylated ether acids. In one or more embodiments, an alkoxylated ether acid is an alkoxylated fatty alcohol terminated with an carboxylic acid, represented by the following formula:

where R is C₆-C₂₄ or -C(0)R³ (where R³ is C10-C22), R¹ is H or C1-C4, R² is C1-C5 and n may range from 1 to 20. Such compound may be formed by the reaction of an alcohol with a polyether (such as poly(ethylene oxide), poly(propylene oxide), poly(butylene oxide), or copolymers of ethylene oxide, propylene oxide, and/or butylene oxide) to form an alkoxylated alcohol. The alkoxylated alcohol may then be reacted with an a- halocarboxylic acid (such as chloroacetic acid, chloropropionic acid, etc.) to form the alkoxylated ether acid. In a particular embodiment, the selection of n may be based on the lipophilicity of the compound and the type of polyether used in the alkoxylation. In some particular embodiments, where R¹ is H (formed from reaction with poly(ethylene oxide)), n may be 2 to 10 (between 2 and 5 in some embodiments and between 2 and 4 in more particular embodiments). In other particular embodiments, where R¹ is -(¾, n may range up to 20 (and up to 15 in other embodiments). Further, selection of R (or R³) and R² may also depend on based on the hydrophilicity of the compound due to the extent of polyetherification (e.g., number of n). In selecting each R (or R³), R¹, R², and n, the relative hydrophilicity and lipophilicity contributed by each selection may be considered so that the desired HLB value may be achieved. Further, while this emulsifier may be particularly suitable for use in creating a fluid having a greater than 50 % non-oleaginous internal phase, embodiments of the present disclosure may also include invert emulsion fluids formed with such emulsifier at lower internal phase amounts. Wetting agents that may be suitable for use in the fluids disclosed herein include crude tall oil, oxidized crude tall oil, surfactants, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates, and the like, and combinations or derivatives of these. [0029] Organophilic clays, normally amine treated clays, may be useful as viscosifiers and/or emulsion stabilizers in the fluid composition disclosed herein. Other viscosifiers, such as oil soluble polymers, polyamide resins, polycarboxylic acids and soaps can 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 6% by weight range is sufficient for most applications.

[0030] The wellbore fluid of the present disclosure additionally includes a weighting material, sometimes referred to as a weighting agent. Weighting agents are conventionally used in wellbore fluids to balance the pressure requirements of the well. Weighting agents may be selected from one or more of the materials including, for example, barite, hematite, iron oxide, calcium carbonate, magnesium carbonate, organic and inorganic salts of magnesium, calcium chloride, calcium bromide, magnesium chloride, zinc halides and combinations thereof.

[0031] Conventional methods can be used to prepare the wellbore fluids disclosed herein, in a manner analogous to those normally used to prepare conventional oil-based wellbore fluids. In one embodiment, a desired quantity of oleaginous fluid such as a base oil and a suitable amount of an emulsifier are mixed together and the remaining components are added sequentially with continuous mixing. An invert emulsion may also be formed by vigorously agitating, mixing or shearing the oleaginous fluid and the non-oleaginous fluid.

[0032] Application of LCM-forming components adjacent a permeable formation may be accomplished by methods known in the art. For example, "thief zones" or permeable intervals will often be at or near the bottom of the wellbore and will begin to absorb wellbore fluids when exposed during drilling operations. In such situations, a LCM treatment may be spotted adjacent the permeable formation by pumping a slug or pill of the treatment down and out of the drill pipe or drill bit as is known in the art. It may be, however, that the permeable formation is at a point farther up in the wellbore, which may result, for example, from failure of a previous seal. In such cases, the drill pipe may be raised as is known in the art so that the pill or slug of the LCM treatment may be deposited adjacent the permeable formation. The volume of the slug of LCM treatment that is spotted adjacent the permeable formation may range from less than that of the open hole to more than double that of the open hole. [0033] One embodiment of the present disclosure involves a method of reducing loss of wellbore fluid in a wellbore to a formation. In one such illustrative embodiment, the method comprises pumping an oil-based wellbore fluid into a wellbore through a plurality of nozzles of a drill bit. The wellbore fluid comprises an oil-based continuous phase, a water-based dispersed phase, a lost circulation material and a water absorbing material that is introduced in the wellbore in a non-swollen state. In one embodiment, the components of the wellbore fluid are simultaneously pumped into the wellbore. In another embodiment, the components of the wellbore fluid may be pumped sequentially. As such, in one embodiment of the present disclosure, the lost circulation material and/or water absorbing material are introduced into the wellbore after initially pumping the base fluid, such as upon experiencing fluid loss to the formation.

[0034] As previously discussed, the shear forces generated by the passage of the wellbore fluid through a restriction, e.g. a perforation or a drill bit may produce enough stress to disrupt the emulsion to expose the water to the water absorbing material. Thus, when the emulsion is sheared, the water from the emulsion may be exposed to the water absorbing material which, upon contact with water, swells with the formation of a swollen state prior to reaching a lost circulation zone. The swelling, which triggers a reduction in the viscosity of the oil-based wellbore fluid (e.g., invert emulsion) may aid in the bridging performance of the LCM materials to bridge and seal the fissures, fractures and/or pores through which the wellbore fluid is lost. Without being bond by theory, the inventors of the present disclosure believe that the superabsorbent material in a swollen state may also maintain particle shape, thus being able to assist in plugging the lost circulation zone and achieving enhanced bridging efficiency of the LCM material.

[0035] EXAMPLES

[0036] The following examples are provided to further illustrate the application and the use of the methods of the present disclosure. The present examples tested different wellbore fluids formulations to asses their rheological properties while providing increased viscosity upon swelling of the water absorbing material.

[0037] The first option of a wellbore fluid formulation used as control for comparison with other formulations is an oil-based fluid comprising 70 % oil / 30 % water. Two sample formulations were prepared by mixing the oil-based fluid used as control with carboxymethyl cellulose for various lengths of time. [0038] To fully asses the rheological properties of the formulations, the viscosity of the resulting wellbore fluids was measured using a Chandler 3500 Viscometer.

[0039] Table 1 below shows the reduction of the emulsion viscosity for an OBM (70 % oil / 30 % water) treated with carboxymethyl cellulose.

Table 1.

[0040] The data comparison with the control sample revealed the reduction of the emulsion viscosity for oil-based fluids treated with carboxymethyl cellulose. As seen in Table 1, the OBM viscosity decreased twice from 15.6 to 8.4 cP after mixing the formulation for 1.5 hours under ambient conditions, indicating that more than 50 % water was removed from an emulsified state.

[0041] As seen in FIG. 5, upon contact with water from the disrupted invert emulsion, the cellulose particles swell, growing 2-3 times in size. As seen in FIG. 5, tiny fibrils can be distinguished on the microscopic image of the initial cellulose material. As shown in FIG. 5, after swelling in the disrupted invert emulsion, the cellulose particles resemble pieces of a dense crosslinked gel. These swollen particles may serve as part of the LCM pill, thus helping to seal a lost circulation zone.

[0042] Advantageously, embodiments of the present disclosure may provide wellbore fluids and methods of reducing loss circulation with such wellbore fluids that include an oil-based continuous phase, a water-based dispersed phase, a lost circulation material and a water absorbing material. The use of a water absorbent material in the wellbore fluids of the present disclosure advantageously allows for controlling the reduction of viscosity of the wellbore fluids in situ, promoting thus bridging performance of the fiber components in an LCM pill, as well as sealing of the lost circulation zone. Although the preceding description has been described herein with reference to particular means, materials and embodiments, it is not intended to be limited to the particulars disclosed herein; rather, it extends to all functionally equivalent structures, methods and uses, such as are within the scope of the appended claims.

Claims

CLAIMS What is claimed:

1. An oil-based wellbore fluid, comprising:

an oil-based continuous phase;

a non-oleaginous discontinuous phase;

a lost circulation material; and

a water absorbing material.

2. The wellbore fluid of claim 1, wherein the oil-based wellbore fluid is an invert emulsion.

3. The wellbore fluid of claim 1, wherein the water absorbing material comprises a synthetic polymer, a superabsorbent polymer, a natural polymer, or combinations thereof.

4. The wellbore fluid of claim 3, wherein the water absorbing material comprises a superabsorbent polymer.

5. The wellbore fluid of claim 4, wherein the superabsorbent polymer is selected from the group of polyacrylamide copolymers, ethylene maleic anhydride copolymers, carboxymethyl cellulose, polyvinyl alcohol copolymers, cross-linked polyethylene oxide, starch grafted copolymer of polyacrylonitrile.

6. The wellbore fluid of claim 3, wherein the water absorbing material has a particle size from about 0.5 mm to about 5 mm.

7. The wellbore fluid of claim 3, wherein the water absorbing material comprises particles having particle sizes from about 1 mm to about 3 mm.

8. The wellbore fluid of claim 1, wherein the water absorbing material is used in a concentration from about 1% wt. to about 10% wt. by the total weight of the invert emulsion].

9. The wellbore fluid of claim 1, wherein the oil-based continuous phase is selected from the group of petroleum oil, a natural oil, a synthetically derived oil, a mineral oil, a silicone oil, or a combination thereof.

10. The wellbore fluid of claim 1, wherein the lost circulation material is a fibrous material.

11. The wellbore fluid of claim 10, wherein the fibrous material is selected from the group consisting of natural polymers, synthetic polymers, and mixtures thereof.

12. The wellbore fluid of claim 11, wherein the fibrous structure is selected form the group of polyesters, acrylics, polyamides, polyolefins, polyaramides, polyurethanes, vinyl polymers, glass fibers, carbon fibers, regenerated cellulose (rayon), natural fibers or blends thereof.

13. A method of reducing loss of wellbore fluid in a wellbore to a formation, comprising: pumping an oil-based wellbore fluid into a wellbore through a plurality of nozzles of a drill bit, the wellbore fluid comprising:

an oil-based continuous phase;

a non-oleaginous discontinuous phase;

a lost circulation material; and

a water absorbing material;

whereby pumping the oil-based wellbore fluid through the nozzles of the drill bit disrupts the non-oleaginous discontinuous phase; and

exposes the water absorbing material to the disrupted non-oleaginous discontinuous phase.

14. The method of claim 13, wherein the exposure of the water absorbing material causes swelling of the water absorbing material with the formation of a swollen state.

15. The method of claim 14, wherein the formation of the swollen state occurs prior to the reaching a lost circulation zone.

16. The method of claim 14, wherein the swelling of the water absorbing material causes reduction of viscosity of the wellbore fluid.

17. The method of claim 13, further comprising allowing the lost circulation material to enter a lost circulation zone and to form a seal or a plug at an entrance of a fracture, fissure or vug or inside a fracture, fissure or vug, thereby reducing the loss circulation.

18. The method of claim 13, wherein the lost circulation material is a fibrous material.

19. The method of claim 18, wherein the fibrous material is selected from the group consisting of natural polymers, synthetic polymers, and mixtures thereof.