MATERIALS AND METHODS TO PREVENT FLUID LOSS IN SUBTERRANEAN FORMATIONS

Abstract

Methods of preventing fluid loss in a downhole formation may include preparing an emulsion containing: an oleaginous phase; an aqueous phase; one or more fibers; injecting the emulsion into the wellbore; allowing the one or more fibers within the emulsion to seal a permeable interval of the formation. In another aspect, methods of stimulating hydrocarbon production in a wellbore may include: injecting a diverting treatment into a subterranean formation, the diverting treatment containing: a non-oleaginous fluid, an oleaginous fluid, and one or more fibers; injecting a stimulating treatment into the subterranean formation; and stimulating the production of hydrocarbons.

Description

CROSS REFERENCE TO RELATED APPLICATION

This patent application claims the benefit of: U.S. Provisional Patent Application Ser. No. 61/692460 filed Aug. 23, 2012, which is incorporated herein by reference in its entirety.

BACKGROUND

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 the 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.

Wellbore fluids are circulated downhole to remove rock, and may deliver agents to combat the variety of issues described above. Fluid compositions may be water- or oil-based and may comprise weighting agents, surfactants, proppants, viscosifiers, fluid loss additives and polymers. However, for a wellbore fluid to perform all of its functions and allow wellbore operations to continue, the fluid must stay in the borehole.

Frequently, undesirable formation conditions are encountered in which substantial amounts or, in some cases, practically all of the wellbore fluid may be lost to the formation. For example, wellbore fluid can leave the borehole through large or small fissures or fractures in the formation or through a highly porous rock matrix surrounding the borehole. Lost circulation is a recurring problem, characterized by loss of wellbore fluids into downhole formations. Fluid losses affect a number of stages in hydrocarbon production including drilling, completions and production operations, for example. Wellbore fluid loss can occur naturally in earthen formations that are fractured, highly permeable, porous, cavernous or vugular. These earth formations can include shale, sands, gravel, shell beds, reef deposits, limestone, dolomite and chalk, among others.

In some applications, controlling the proper placement of wellbore fluid treatments is of particular significance because injected fluids tend to migrate to higher permeability zones, or “thief zones,” rather than to those having lower permeability. This can present difficulties for fluid treatments that are intended to target low permeability zones. For example, in production and completion operations, acid washes may be used downhole to degrade an acid-sensitive matrix like limestone or dolomite. Due to variations in the permeability of a producing formation, an acid treatment enters the most permeable intervals of the wellbore, which can further increase the interval's permeability and capacity to hold treatment fluids. In order to prevent this uneven distribution, acid must be diverted from the most permeable intervals of the formation into the less permeable intervals. Thus, prior to the introduction of treatment fluids, it may be advantageous to selectively plug high permeability regions of the formation so that the treating solution remains in contact with lower permeability regions.

A number of techniques have been developed to control fluid placement, diverting the fluids from high permeability zones to regions of interest, particularly by using a lost circulation material (LCM) to seal or block further loss of circulation into thief zones. These LCMs may generally be classified by their mechanism of action such as surface plugging or interstitial bridging, for example. In addition to traditional LCMs, polymers that crosslink or absorb fluids and cement or gunk squeezes have also been employed to reduce or stop the flow of fluids into loosely consolidated formations.

Wellbore fluids containing LCMs are useful for a variety of wellbore operations. For example, in drilling and completion operations, sealing thief zones prevents lost circulation of wellbore fluids and decreases the volume of fluid required. In stimulation and production, LCM fluids decrease fluid flow to highly permeable intervals, enabling the direction of subsequently injected treatments to low permeability intervals and improving uniform contact between the formation and the treatment fluid.

Sealing thief zones optimizes wellbore operations in the short term and maximizes hydrocarbon extraction and overall economic output in the long term. However, if not properly designed, treatments injected into the well can fail to seal the thief zones or, in some cases, hamper operations by decreasing or stopping production by damaging formation permeability.

BRIEF DESCRIPTION OF THE DRAWINGS

The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of embodiments of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:

FIGS. 1-3 illustrate the collected mass versus time for various embodiments of the present disclosure.

FIG. 4 illustrates shear rate versus viscosity for various embodiments of the present disclosure.

FIG. 5 illustrates the collected mass versus time for embodiments of the present disclosure.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In one aspect, embodiments of the instant disclosure are directed to methods of preventing fluid loss in a downhole formation that include injecting the emulsion into the wellbore, the emulsion containing: an oleaginous phase; an aqueous phase; one or more fibers; and allowing the one or more fibers within the emulsion to seal a permeable interval of the formation.

In another aspect, embodiments of the instant disclosure are directed to methods of stimulating hydrocarbon production in a wellbore that include: injecting a diverting treatment into a subterranean formation, the diverting treatment containing: a non-oleaginous fluid, an oleaginous fluid, and one or more fibers; injecting a stimulating treatment into the subterranean formation; and stimulating the production of hydrocarbons.

Other aspects and advantages of the invention will be apparent from the following detailed description and the appended claims.

DETAILED DESCRIPTION

Embodiments disclosed herein relate to methods of reducing fluid flow into highly permeable or loosely consolidated formations during wellbore operations in subterranean formations. Materials and methods described herein may be applied in hydrocarbon exploration, production, and recovery processes, such as drilling, well completions, and production.

In one or more embodiments, an emulsion containing fibers and/or other solids of various shapes and chemical properties may be used to effectively plug thief zones. For example, wellbore fluids may contain solids having various shapes, sizes and rigidity, including, but not limited to, fibers, spheres, flakes, and irregular shapes to plug high permeability paths present in oil and gas reservoirs. High permeability paths may be naturally formed fractures, hydraulically induced man-made fractures, dissolved channels or cavities in carbonate rocks, or large and well connected interstices existing among the rock grains.

In certain embodiments, emulsions and solids interact with each other to create a mass that is resistant to flow in large openings such as fractures, channels and cavities in subterranean formations. The interactions between the emulsion and solids may include: (1) forming a pseudo-rigid lump by the interfacial force—the droplets from the emulsion pull the solids close to one another by the wetting characteristics of the solids; (2) the solids or mixtures of solids aggregate into a porous network which provides high resistance to emulsion flow through such a network; and/or (3) a combination of the two interacting mechanisms.

In some embodiments, wellbore fluids of the present disclosure may be formulated as a drill-in fluid that enters the formation to seal thief zones. In other embodiments, wellbore fluids may be used as completion fluids, work-over fluids, spacer fluids and liquid plugs. For example, as completion fluids, wellbore fluids described herein may be placed in the well or annulus thereof to temporarily or permanently seal thief zones in order to facilitate final operations prior to initiation of production. In one or more embodiments, placement of the wellbore fluid may precede a treatment such as an acid treatment or steamflooding to initiate hydrocarbon production, where the wellbore fluid may be added into an injection well or a production well. In other embodiments, when a formation is to be fractured by a fracturing fluid, the wellbore fluid may be used to seal thief zones (prior to the introduction of the fracturing fluid, for example) to decrease the loss of fluid into the formation and increase hydraulic pressure in the region of the well desired to be fractured.

In other embodiments, when multiple fractures are to be created by a fracturing fluid along a single horizontal well penetrating through a formation, the wellbore fluid may be used to seal the fractures created in earlier fluid injection stages to decrease the loss of fluid into the earlier fractures and increase hydraulic pressure in the region of the well desired to be fractured.

In one or more embodiments, wellbore fluids in accordance with the present disclosure may include a combination of one or more fiber components and/or at least one particulate weighting agent. In other embodiments, wellbore fluids may include a number of other additives known to those of ordinary skill in the art of wellbore fluid formulations, such as wetting agents, viscosifiers, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents, rheological additives and cleaning agents.

Fiber Component

By plugging porous or vugular zones of the formation, fluid loss compositions containing engineered combinations of solid materials may provide an immediate blockage, preventing fluid flow therethrough and facilitating further wellbore operations, including drilling, completion, stimulation, or production operations. In particular embodiments, by utilizing the unique properties of three-dimensional shapes of fibrous materials and/or combinations of fiber types, such materials may interact synergistically to form a seal that arrests the flow of wellbore fluids into or through the formation. The volume fraction of each component in the emulsion-solids mixture is formulated and altered based on the size and shape of the opening to be plugged.

As used herein, the terms “fiber” and “fibrous” are used to denote a high aspect ratio molecular or macromolecular structure, which may have a length greater than either its diameter or width (i.e., a length that is greater than the other two dimensions). Without being limited by any particular theory, it is believed that as fibers present in a wellbore fluid enter fractures in the formation, the fibers trap and entangle other particles present in the surrounding fluid, creating an impermeable barrier that prevents further fluid flow therethrough. The fiber component of a selected wellbore fluid may also act to create a heterogeneous three-dimensional network that can trap particulates of varying sizes, generating a mass that prevents fluid flow therethrough. In addition, the shape of the fiber component may also be varied depending on the downhole conditions. In some embodiments, the fiber component may include fibers of various shapes such as, for example, multi-lobed, curved, hooked, tapered, or dumbbell. In other embodiments, high-surface area “hairy” fibers may be incorporated into wellbore fluid formulations to provide a fiber component that may aggregate more efficiently and improve stability in certain emulsion states.

In one or more embodiments, a fiber component in a wellbore fluid may degrade under downhole conditions in a duration that is suitable for the selected operation. Degradation of the fibers may be assisted or accelerated by a wash containing an appropriate dissolver or a wash or additive that changes the pH or salinity of the surrounding wellbore fluid. The degradation may also be assisted by an increase in temperature, such as when the treatment is performed before enhanced recovery techniques such as steamflooding. For example, a diverting or fluid loss composition may have a relatively low acid solubility at room temperature, but upon exposure to elevated temperatures, such as 100° C. and greater, the solubility of a fiber component of the fluid loss composition may be increased to substantially or completely soluble.

In some embodiments, the surface area of the fiber component of the fluid loss composition may be used to tune properties that include the susceptibility of the fiber component to dissolve in acids or solvents. As a matter of practical application, the diameter of the fiber may be used as a parameter that determines both the performance of the fiber as a lost circulation material and the rate at which the fiber degrades when exposed to acids and solvents at a particular temperature. In some embodiments, it may also be desirable that the fibers be able to pass through a gravel or sand pack so as to permit effective treatment of a formation located behind the pack.

The hydrophobicity and/or hydrophilicity may also be used to tune the stability of the fiber component in a particular emulsion. Depending on the composition of the emulsion and the overall hydrophobicity or hydrophilicity of the fiber component of the wellbore fluids, the fiber component may have increased or decreased aggregation properties that vary with the composition of the surrounding emulsions. For example, hydrophilic fibers may tune the flocculation of fibers in a water-in-oil emulsion, while hydrophobic fibers may increase aggregation in water-in-oil emulsions. In some embodiments, a blend of hydrophobic and hydrophilic fibers may be added to a diverting or fluid loss composition to tune the flocculation properties and stability of the fiber component in the emulsion, in addition to modifying the sealing properties of the fluid loss composition.

In one or more embodiments, the fiber component added to the wellbore fluid compositions of the present disclosure may include hydrophobic (or equivalently oleophilic) polymeric fibers that may be selected from, for example, polyolefins and polyaromatics that may include homopolymers, copolymers, and multi-block interpolymers of ethylene, tetrafluoroethylene, vinylidene fluoride, propylene, butene, 1-butene, 4-methyl-1-pentene, styrene, p-phenyene-2,6-benzobisoxazole, aramids, and the like. In other embodiments, the hydrophobic polymeric fibers may be selected from polyurethanes such as those formed from the reaction of diisocyanate and a polyol, polyester, polyether, or polycarbonate polyol.

In some embodiments, fibers may be selected from hydrophilic fibers composed of polymers or co-polymers of esters, amides, or other similar materials. Examples include polylactic acid, polyhydroxyalkanoates, polycaprolactones, polyhydroxybutyrates, polyethylene terephthalates, polytriphenylene terephthalate, polybutylene terephthalate, polyvinyl alcohols, polyacrylamide, partially hydrolyzed polyacrylamide, polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers or higher order polymers (terpolymers, quaternary polymers, etc.) of these materials. In some embodiments, the fiber component may be an acid soluble fiber that may include polyamides such as nylon 6, nylon 6,6, and combinations thereof. In other embodiments, the hydrophilic fiber component may be at least one of polymers or co-polymers of esters that include, for example, substituted and unsubstituted polylactide, polyglycolide, polylactic acid, poly(lactic-co-glycolic acid), and polyglycolic acid, poly(ε-caprolactone), and combinations thereof. Suitable hydrophilic fibers may also be selected from celluloses and cellulose derivatives such as hydroxypropyl cellulose, hydroxyethyl cellulose, and carboxymethyl cellulose.

In one or more embodiments, the fiber component may be selected from hydrophilic inorganic fibers that include glasses or acid soluble minerals such as calcium carbonate (e.g., calcite, vaterite, aragonite, limestone), magnesium carbonate (e.g., magnesite), calcium/magnesium carbonates (e.g., dolomite), calcium oxide, and magnesium oxide. In particular embodiments, inorganic fibers may have high aspect ratio crystal habits or acicular form. In particular embodiments, the fiber component may be MaxCO3™ available commercially from Schlumberger Technology Corporation (Houston, Tex.). A further description of wellbore fluids containing fibers that may be used with embodiments of the present disclosure is discussed in U.S. Pat. Nos. 7,833,950 and 7,275,596 assigned to the assignee of the present application, and incorporated by reference herein.

In one or more embodiments, various fibers may be added to wellbore fluids in accordance with this disclosure in an amount ranging from a lower limit equal or greater than 0.01 ppg, 0.1 ppg, 0.5 ppg, 1 ppg, and 5 ppg, to an upper limit of 0.5 ppg, 1 ppg, 5 ppg, 10 ppg, and 15 ppg, where the concentration of the fiber component, or combinations thereof, may range from any lower limit to any upper limit. In some applications, it also may be desirable for the amounts of each fiber type to be in excess of the ranges described above. Moreover, it is within the scope of the present disclosure for any of the above described fibers to be combined as required by downhole conditions.

In embodiments, the fibers may have lengths within the range of 100 μm to 20 mm. In other embodiments, the fibers may have lengths within the range of 500 μm to 15 mm.

In embodiments, the diameter of the fibers may fall within the range of 0.1 μm to 60 μm. In yet another embodiment, the diameter of the fibers may be within the range of 0.5 μm to 50 μm. In particular embodiments, a fiber having a diameter in the range of 20 μm to 50 μm may be used, and a fiber having a diameter of 1 to 15 μm may be used.

Particulate Weighting Agents

Wellbore fluids in accordance with the present disclosure may also include one or more particulate weighting agents. Particulate-based wellbore fluid formulations may include use of particles frequently referred to in the art as weighting materials, or materials that aid in weighting up a fluid to a desired density. Particulate weighting agents may incorporate into interstitial spaces present in the three dimensional network formed by the fibers, increasing the strength of the seal formed by the fiber and particulate plug. In some embodiments, the fiber component and the particulate weighting agents may act synergistically to form a plug, decreasing the total amount of either component required. Additional discussion of fluid loss compositions containing mixtures of fibers and particulates is presented in U.S. Patent Publication 2010/0152070 assigned to the assignee of the present application, and incorporated by reference herein.

Examples of particulate weighting agents suitable for use in the present disclosure include graphite, celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof. In other embodiments, particulate weighting agents may be selected from one or more of the materials including, for example, barium sulfate (barite), ilmenite, hematite or other iron ores, olivine, siderite, and strontium sulfate. In yet other embodiments, particulate weighting agents may be one or more selected from materials that dissolve in response to pH such as magnesium oxide, calcium carbonate (e.g., calcite, marble, aragonite), dolomite (MgCO₃.CaCO₃) and the like.

In some embodiments, surface-modified particulate weighting agents may be used. For example, the surface-modified particulate weighting agents may include a hydrophobic or hydrophilic coating to control fluid rheology and the overall plugging properties of the wellbore fluid composition. In some embodiments, the surface of the particulate weighting agents may be chemically modified by a number of synthetic techniques. Surface functionality of the particles may be tailored to improve solubility, dispersibility, or introduce reactive functional groups. This may be achieved by reacting the particulate weighting agents with organosilanes or siloxanes, in which reactive silane groups present on the molecule may become covalently bound to the surface of the particles. Non-limiting examples of compounds that may be used to functionalize the particulate weighting agents include aminoalkylsilanes such as aminopropyltriethoxysilane, aminomethyltriethoxysilane, trimethoxy[3-(phenylamino)propyl]silane, and trimethyl[3-(triethoxysilyl)propyl]ammonium chloride; alkoxyorganomercapto silanes such as bis(3-(triethoxysilylpropyl)tetrasulfide, bis(3-(triethoxysilylpropyl) disulfide, vinyltrimethoxy silane, vinyltriethoxy silane, 3-mercaptopropyltrimethoxy silane; 3-mercaptopropyltriethoxy silane; 3-aminopropyltriethoxysilane and 3-aminopropyltrimethoxysilane; alkoxysilanes, diethyl dichlorosilane, phenyl ethyl diethoxy silane, methyl phenyl dichlorosilane, vinyl silane, 3,3,3-trifluoropropylmethyl dichlorosilane, trimethylbutoxy silane, sym-diphenyltetramethyl disiloxane, octamethyl trisiloxane, octamethyl cyclotetrasiloxane, hexamethyl disiloxane, pentamethyl dichlorosilane, trimethyl chlorosilane, trimethyl methoxysilane, trimethyl ethoxysilane, methyl trichlorosilane, methyl triethoxysilane, methyl trimethoxysilane, hexamethyl cyclotrisiloxane, hexamethyldisiloxane, gamma-methacryloxypropyl trimethoxy silane, hexaethyldisiloxane, dimethyl dichlorosilane, dimethyl dimethoxy silane, and dimethyl diethoxysilane.

In other embodiment, silicone polymers that contain reactive end groups may be covalently linked to the surface of the particulate weighting agents. Reactive silicone polymers may include, for example, bis-3-methacryloxy-2-hydroxypropyloxypropyl-polydimetllylsiloxane, polydimethylsiloxanes comprising 3 to 200 dimethylsiloxy units, trimethyl siloxy or hydroxydimethylsiloxy end blocked poly(dimethylsiloxane) polymer, polysiloxanes, and mixtures thereof.

The particle size of the particulate agents may be selected depending on the target application, the level of fluid loss, formation type, and/or the size of fractures predicted for a given formation. In addition, the three dimensional structure of the particulate weighting agents may be used to tune the overall performance of the wellbore fluid compositions of the present disclosure. For example, depending on the application, the particulate weighting agent may be spherical or pseudo-spherical, or be in the form of powder, beads, chips, platelets, flakes or combinations of any of the above. In some embodiments, the average particle size (d₅₀) of the particulate agents may range from a lower limit of greater than 5 nm, 10 nm, 30 nm, 50 nm, 100 nm, 200 nm, 500 nm, 700 nm, 0.5 micron, 1 micron, 1.2 microns, 1.5 microns, 3 microns, 5 microns, or 7.5 microns to an upper limit of less than 500 nm, 700 microns, 1 micron, 3 microns, 5 microns, 10 microns, 15 microns, 20 microns, 100 microns, where the particles may range from any lower limit to any upper limit. The above described particle ranges may be achieved by grinding down the materials to the desired particle size or by precipitation of the material from a bottoms up assembly approach. 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 amount of particulate weighting agent present in the wellbore fluid may depend on the fluid loss levels, the anticipated fractures, the density limits for the fluid in a given wellbore and/or pumping limitations, etc. In one or more embodiments, one or more particulate weighting agents may be added to wellbore fluids in accordance with this disclosure in an amount ranging from a lower limit equal or greater than 0.1 ppg, 0.5 ppg, 1 ppg, 5 ppg, and 10 ppg, to an upper limit of 1 ppg, 5 ppg, 10 ppg, 20 ppg, and 25 ppg, where the concentration of the particulate weighting agent, or combinations thereof, may range from any lower limit to any upper limit. In some embodiments, the ratio of fibers to particulates may range from 100/1 to 1/100 ratio by weight (wt/wt).

Emulsions

In one or more embodiments, wellbore fluids in accordance with the present disclosure may contain an invert emulsion, such as a water-in-oil emulsion, having a discontinuous aqueous phase and a continuous oleaginous phase. In other embodiments, wellbore fluids may be an emulsion having an aqueous continuous phase and an oleaginous discontinuous phase such as an oil-in-water emulsion. It is also within the scope of this disclosure that a wellbore fluid is formulated to contain a high-internal phase ratio (HIPR) emulsion, such that the overall volume of the internal discontinuous phase of the emulsion is greater than that of the continuous phase.

Oil-in-water emulsions are stabilized by both electrostatic stabilization (electric double layer between the two phases) and steric stabilization (van der Waals repulsive forces), whereas invert emulsions (water-in-oil) are stabilized by steric stabilization. Because only one mechanism can be used to stabilize an invert emulsion, invert emulsions may be more difficult to stabilize, particularly at higher levels of the internal phase, and may become more viscous.

In one or more embodiments, wellbore fluids may include an aqueous phase that contains at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof. For example, the aqueous phase 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, 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 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 pills disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In one embodiment, the density of the pill 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.

Wellbore fluids in accordance with the present disclosure may contain an oleaginous phase that includes one or more oleaginous liquids such as natural or synthetic oils; diesel oils; mineral oil; 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; similar compounds known to one of skill in the art; and mixtures thereof. Selection between an aqueous fluid and an oleaginous fluid may depend, for example, on the type of drilling fluid being used in the well when the lost circulation event occurs. Use of the same fluid type may reduce contamination and allow drilling to continue upon plugging of the formation fractures/fissures, etc.

In one or more embodiments, wellbore fluids of the present disclosure may possess a high shear viscosity of less than 500 centipoise (cp) at 100 sec-1, and a low shear viscosity of less than 1000 cp at 25 sec-1 at reservoir temperature.

Stimulating Treatments

Following placement of a diverting treatment formulated in accordance with the present disclosure, fluid flow into thief zones may be decreased or stopped, which may allow for more uniform contact between less permeable intervals and any subsequent wellbore treatments or stimulating treatments known in the art.

In some embodiments, by sealing higher permeability regions or intervals of the wellbore, one or more stimulating treatment may be applied to increase the porosity and permeability of targeted intervals in order to increase the production of hydrocarbons. In one or more embodiments, the stimulating treatment may be an acid wash containing one or more acids such as mineral acids that include hydrochloric acid, hydrofluoric acid, nitric acid, phosphoric acid and sulfuric acid, or organic acids such as formic acid, acetic acid, glycolic acid, citric acid and phosphonic acid.

As another example, plugging thief zones may increase the effectiveness of enhanced oil recovery techniques like steam flooding. In steam flooding, steam is injected into a neighboring injection well. When steam enters the reservoir, it heats up the crude oil and reduces its viscosity. The hot water that condenses from the steam and the steam itself generate an artificial drive that sweeps oil toward producing wells. The driving force of the steam flood is then used to drive hydrocarbons into the production well.

Application

When formulated as a fluid loss pill or diverting treatment, wellbore fluids in accordance with the present specification may be injected into a work string, flow to bottom of the wellbore, and then out of the work string and into the annulus between the work string and the casing or wellbore. The pill may be pushed by injection of other completion fluids to a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location. Positioning the pill in a manner such as this is often referred to as “spotting” the pill. The fluid loss pill or diverting treatment may then react with the brine to form a plug near the wellbore surface, to reduce fluid flow into the formation.

In other embodiments, the wellbore fluids of the present disclosure may be selectively emplaced in the wellbore, for example, by spotting the pill through a coil tube or by bullheading. A downhole anemometer or similar tool may be used to detect fluid flows downhole that indicate where fluid may be lost to the formation. The relative location of the fluid loss may be determined such as through the use of radioactive tags present along the pipe string. Various methods of emplacing a pill known in the art are discussed, for example, in U.S. Pat. Nos. 4,662,448, 6,325,149, 6,367,548, 6,790,812, 6,763,888, which are herein incorporated by reference in their entirety.

EXAMPLES

The subsequent examples are provided to further illustrate the application and the use of the methods and compositions in accordance with the present disclosure.

Example 1

In the following example, sample formulations were assayed to determine their effectiveness in blocking the flow into a cylindrical channel. Samples were prepared and 130 mL of each sample was applied to a funnel ending in an opening diameter of 1 cm. Where indicated, samples were formulated with a polylactic acid fiber having a diameter of approximately 50 microns and an approximate length of 1 cm at concentration of 18 grams per liter (about 150 ppg). Sample emulsions were formulated with kerosene as the oil phase. Following preparation, accumulated mass (g) of the sample compositions were measured and recorded as a function of time (s) and plotted in FIG. 1, where Sample 1 is a mixture of fresh water and fibers; Sample 2 is fresh water alone; Sample 3 is a 30/70 oil-in-water emulsion containing fibers prepared and mixed at 1000 rpm prior to application; Sample 4 is a 30/70 oil-in-water emulsion containing fibers prepared and mixed at 2500 rpm prior to application; Sample 5 is a 50% w/w mixture of honey in water with fibers; Sample 6 is a mixture of water, a viscoelastic surfactant, and fibers; and Sample 7 is a 70/30 water-in-oil emulsion prepared with a 200 kppm brine and fibers that was mixed at 6000 rpm prior to application.

In Example 1, the water-in-oil emulsion containing fibers (Sample 7) performed better plugging/bridging than the other fluids, which may be explained by the combination of the viscosity of the base fluid and the flocculation rate of the fibers. For the fresh water with fibers (Sample 1) and the oil-in-water emulsions (Samples 3 and 4), fiber flocs were observed at the funnel entrance, but base fluid remained mobile through the funnel opening.

Sample 5 and Sample 6 exhibited high viscosity but did not produce a plug and fibers were recovered with the sample passed through the funnel. Thus, it appears that, when fibers are used for bridging purposes, the high viscosity of the base fluid is necessary but not sufficient to produce a plug at the entrance of the funnel and the flocculation rate of the fibers may need to be adjusted in order to produce a substantial plug.

Example 2

In a further illustrative example, an embodiment of the present disclosure was assayed against a series of comparative samples that were formulated with a viscoelastic surfactant, fibers, hydrochloric acid, and varying concentrations of calcium carbonate. Where indicated, samples were formulated with a polylactic acid fiber having a diameter of approximately 50 microns and an approximate length of 1 cm at concentration of 18 grams per liter (about 150 ppg). Sample emulsions were formulated with kerosene as the oil phase. Samples were assayed using a pour-in/pour-out test of 150 ml in a funnel with an opening diameter of 1 cm. The collected mass (g) was measured versus time (s) and plotted in FIG. 2 for a number of samples. With particular reference to FIG. 2, Sample 8 is a formulation containing a viscoelastic surfactant, fibers, hydrochloric acid, and enough calcium carbonate to neutralize 60% of the hydrochloric acid; Sample 9 is substantially identical to Sample 8, but without any added calcium carbonate; Sample 10 is substantially identical to Sample 8, but with enough calcium carbonate added to neutralize 80% of the hydrochloric acid; Sample 11 is a 70/30 water-in-oil emulsion prepared with a 200 kppm brine, kerosene, and fibers that was mixed at 6000 rpm prior to application.

For samples, once a plug formed or the flow slowed, 100 ml of the respective base fluid (without fibers) was added in order to destabilize the plug. The times corresponding to when the base fluid was added are shown in FIG. 2 by dashed vertical lines. Here again water-in-oil (w/o) emulsion (with brine) performs better plugging of the funnel and, unlike treatments containing viscoelastic surfactants, does not exhibit a pH dependent maximum viscosity. The percent acid neutralization was calculated based upon a calibrated value of 22 g of calcium carbonate to 100 ml of the solution for 100% neutralization.

Example 3

In another example, embodiments of the present disclosure were assayed against a series of comparative samples that were formulated with a viscoelastic surfactant, fibers, hydrochloric acid and varying concentrations of calcium carbonate. Where indicated, samples were formulated with a polylactic acid fiber having a diameter of approximately 50 microns and an approximate length of 1 cm at a concentration of 18 g/L. Sample emulsions were formulated with kerosene as the oil phase. Samples were assayed using a pour-in/pour-out test of 150 ml in a funnel with an opening diameter of 1 cm. For samples, once a plug formed, 100 ml of the base fluid (without fibers) was added to destabilize the plug. Results are shown in FIG. 3 depicting a graph of collected mass (g) versus time (s). The times corresponding to when the base fluid was added are indicated in FIG. 3 by dashed vertical lines. Sample 12 is a formulation containing a viscoelastic surfactant, fibers, and hydrochloric acid; Sample 13 is a formulation containing a viscoelastic surfactant, fibers, hydrochloric acid, and enough calcium carbonate to neutralize the hydrochloric acid; Sample 15 is a formulation containing a viscoelastic surfactant, fibers, and water; Sample 14 is a formulation containing a 70/30 oil-in-water emulsion and fibers that was mixed at 6000 rpm prior to application; and Sample 16 is an 70/30 water-in-oil emulsion containing fibers that was mixed at 6000 rpm prior to application.

For Samples 14, 15 and 16 of Example 3, the rheological profiles were also studied at 25° C. as illustrated in FIG. 4. It is noted in this Example that the water-in-oil emulsion (Sample 16) performs better than oil-in-water emulsion (Sample 14) even though their viscosity is in within the same range.

Upon inspection of the two types of emulsion under the microscope (not shown), it was found that the fibers are mostly oil-wet. In the water-in-oil emulsion, the water droplets are trapped within the fiber network and plug the space between the fibers. In the oil-in-water emulsion, oil droplets coalesce and spread around the fiber. Thus, it is envisioned that modifying the hydrophobic or hydrophilic character of the fibers may be used in conjunction with particular emulsions to modify the rheology and plugging effectiveness of fluid loss compositions for differing types of emulsions, e.g., water-in-oil or oil-in-water.

Example 4

In a further example, an experiment was carried out to lower the fiber concentration in particular embodiments of the present disclosure. Where indicated, samples were formulated with a polylactic acid fiber having a diameter of approximately 50 microns and an approximate length of 1 cm at concentration of 18 g/L. Sample emulsions were formulated with kerosene as the oil phase. Samples were assayed using a pour-in/pour-out test of 150 ml of a selected sample in a funnel with an opening diameter of 1 cm. FIG. 5 depicts a graph of collected mass (g) versus time (s). For samples, once a plug was formed, 100 ml of the respective base fluid (without fibers) was added to destabilize the plug. The times corresponding to the addition of base fluid are represented in FIG. 5 by dashed vertical lines. With particular reference to FIG. 5, Sample 17 is a 70/30 water-in oil emulsion containing 6 ppg of Pr100, a proppant having an average particle size of approximately 150 microns (100 mesh); Sample 18 is a formulation containing a viscoelastic surfactant, fibers, hydrochloric acid, and enough calcium carbonate to neutralize the hydrochloric acid; Sample 19 is a 30/70 water-in-oil emulsion containing fibers at a concentration of 112.5 lbs/1000 gal (13.5 g/L); Sample 20 is a 70/30 water-in-oil emulsion containing fibers at a concentration of 150 lbs/1000 gal (18 g/L); and Sample 21 is a 70/30 water-in-oil emulsion containing fibers at a concentration of 150 lbs/1000 gal (18 g/L) and 6 ppg of Pr100 particulate weighting agent.

The results in FIG. 5 indicate that when Pr100 is added at 3 ppg (360 g/L) to the solution of emulsion and fibers, the fluid loss composition performs better than the equivalent sample formulation without proppant. When proppant was used with the emulsion alone (Sample 17), a plug was not formed even with a concentration of 6 ppg (720 g/L) and the solution flowed out the funnel. This is mainly due to the size of the proppant which is very small compared to the funnel diameter, and also due to the viscosity of the emulsion which is not sufficient to suspend the proppant. When the fibers are present in the solution, the same proppant will be trapped in the fiber network.

In the present disclosure, Applicant has discovered that, by partitioning a fiber component within an emulsified fluid, the fiber component may be organized within the discontinuous or continuous phase depending on the apparent hydrophobicity/hydrophilicity. The organization of the fiber component within the emulsion creates a fibrous network that is more effective in plugging and blocking fissures and crevices within a wellbore. Moreover, when particulate solids are added to fibrous fluid loss compositions, the particulate solids may incorporate into the fibrous network and increase the density and durability of the resulting seal. Emulsified fluids may also increase the stability of fibers in solution and decrease sagging and/or precipitation, which allows the fibers to be delivered into the fluid loss zone without settling out or agglomerating prematurely.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. Moreover, embodiments may be performed in the absence of any component not explicitly described herein.

In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A method of preventing fluid loss in a downhole formation, comprising:

injecting the emulsion into the wellbore, the emulsion comprising: an oleaginous phase, an aqueous phase, one or more fibers; and

allowing the one or more fibers within the emulsion to seal a permeable interval of the downhole formation.

2. The method of claim 1, wherein the emulsion is a water-in-oil emulsion.

3. The method of claim 1, wherein the emulsion is an oil-in-water emulsion.

4. The method of claim 1, wherein the average length of the one or more fibers ranges from 100 μm to 20 mm.

5. The method of claim 1, wherein the one or more fibers are added at a concentration of 1 ppg to 15 ppg.

6. The method of claim 1, wherein the one or more fibers are oleophilic.

7. The method of claim 6, wherein the one or more fibers are selected from a group consisting of homopolymers, copolymers, multi-block interpolymers, and higher order polymers of ethylene, tetrafluoroethylene, vinylidene fluoride, propylene, butene, 1-butene, 4-methyl-1-pentene, styrene, p-phenylene-2,6-benzobisoxazole, aramids, and urethanes.

8. The method of claim 1, wherein the one or more fibers are hydrophilic.

9. The method of claim 8, wherein the one or more fibers are selected from a group consisting of polymers, copolymers, multi-block interpolymers, and higher order polymers of polylactic acid, polyhydroxyalkanoates, polycaprolactones, polyhydroxybutyrates, polyethylene terephthalates, polytriphenylene terephthalate, polybutylene terephthalate, polyvinyl alcohols, polyacrylamide, partially hydrolyzed polyacrylamide, polyvinyl acetate, and partially hydrolyzed polyvinyl acetate.

10. The method of claim 1, wherein the one or more fibers are one or more hydrophilic inorganic fibers selected from a group consisting of calcium carbonate, calcium/magnesium carbonate, magnesium carbonate, magnesium oxide, and calcium oxide.

11. The method of claim 1, wherein the one or more fibers are high surface area fibers.

12. The method of claim 1, further comprising injecting an acid to dissolve the one or more fibers, thereby stimulating production of hydrocarbons.

13. The method of claim 1, wherein the emulsion further comprises one or more particulate weighting agents.

14. The method of claim 13, wherein the particulate weighting agents are acid soluble.

15. The method of claim 13, wherein the particulate weighting agents have an average particle size (d50) that ranges from 100 nm to 100 μm.

16. The method of claim 13, wherein the particulate weighting agents are added at a concentration that ranges from 1 ppg to 20 ppg.

17. A method of stimulating hydrocarbon production in a wellbore comprising:

injecting a diverting treatment into a subterranean formation, the diverting treatment comprising: a non-oleaginous fluid, an oleaginous fluid, and one or more fibers;

injecting a stimulating treatment into the subterranean formation; and

stimulating the production of hydrocarbons.

18. The method of claim 17, wherein the diverting treatment further comprises at least one particulate solid.

19. The method of claim 17, wherein the diverting treatment is an invert emulsion.

20. The method of claim 17, wherein the stimulating treatment is an acid wash.