PATH TECHNOLOGY

BACKGROUND

[0001] This application claims the benefit of U.S. Provisional Application having Serial

No. 62/613818 filed on January 5, 2018 and U.S. Provisional Application having Serial No. 62/613820 filed on January 5, 2018, the entire contents of each are incorporated herein by reference in their entirety.

[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. The drilling mud may be either a water-based or an oil-based mud.

[0004] Many wells, especially in oil fields in shale formations (having water sensitivity) and/or deep-water/subsea environments, are drilled with synthetic/oil-based muds or drilling fluids. Because of the extremely high cost of intervention and high production rates, these wells require reliable completion techniques that prevent sand production and maximizes productivity throughout the entire life of the well. One such technique is open-hole gravel packing. [0005] There are two principal techniques used for gravel packing open holes: (1) the alternate path technique and (2) the a/b wave packing technique. The latter uses low- viscosity fluids, such as completion brines to carry the gravel from the surface and deposit it into the annulus between a sand-control screen and the wellbore. The alternate path technique, on the other hand, utilizes viscous carrier fluids; therefore, the packing mechanisms of these two techniques are significantly different. The alternate path technique allows bypassing of any bridges that may form in the annulus, caused by for example high leakoff into the formation due to filtercake erosion, or exceeding the fracturing pressure, or shale-sloughing/shale-swelling or localized formation collapse on the sand control screens.

[0006] In unconsolidated formations, sand control measures are implemented to stabilize formation sand. Common practice for controlling sand displacement includes placement of a gravel pack to hold formation sand in place. The gravel pack is typically deposited around a screen. The gravel pack filters the sand while still allowing formation fluid to flow through the gravel, the screen and a production pipe.

[0007] Most of the recently discovered deep-water fields contain a high fraction of shales, which are water-sensitive, although many have been gravel packed with water- based fluids. A very large fraction of them have been completed with viscous fluids using the alternate path technique. Viscoelastic surfactant (VES) solutions have been the most widely used carrier fluid in open hole gravel packing with the alternate path technique due to their low formation and gravel pack damage characteristics, their low drawdown requirements, their capability of incorporating filtercake cleanup chemicals into the carrier fluid, and their low friction pressures.

[0008] In wells drilled with synthetic or oil-based muds (often the case for high shale fractions and/or deep water wells), three main approaches have been used for gravel packing. A first approach involves displacement of the entire wellbore to water-based fluids at the end of drilling the reservoir section, and subsequently running the sand control screens into the open hole, setting the packer and gravel packing with a water based fluid. However, as experienced by several operators, the problem with this approach is that exposure of reactive shales to water-based fluids for prolonged time periods can cause shale collapse or swelling which effectively reduces the wellbore diameter and makes it impossible to install sand control screens to the target depth or shale dispersion into the carrier fluid during gravel packing which can have a significant impact on well productivity. The success of this approach is therefore heavily dependent on the reactivity of the shales.

[0009] One approach subsequently practiced involved installation of a pre-drilled

(perforated) liner in oil-based mud, then displacement of the entire wellbore to water based fluids, subsequent installation of the sand control screens to target depth and finally gravel packing with a water based fluid. This approach solved the problem of inability to run the screens to target depth, since shale collapse would occur onto the pre-drilled liner, and the space inside the predrilled liner would be substantially free of shales, allowing the screens to be installed to target depth. The problems with this approach were two fold. First, it involved two trips (one for predrilled liner installation and another for screen installation), which is costly, particularly in deep water where rig costs are high. Secondly, a smaller size screen had to be installed into the wellbore, which in some cases can limit production rates, and thus increase the costs.

[0010] In general, gravel packing with water-based fluids in an oil-based environment is inconvenient, time consuming, expensive, and often requires the use of spacer fluids to transition from oil-based reservoir drill-in-fluids to water based gravel packing fluids.

SUMMARY

[0011] 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.

[0012] In one aspect, embodiments disclosed herein relate to a method of gravel packing a wellbore in a subterranean formation, the wellbore comprising a cased section and an uncased section, includes: pumping into the wellbore a gravel pack composition including gravel and a carrier fluid including an invert emulsion fluid, the invert emulsion fluid including: an oleaginous external phase, wherein the oleaginous external phase has an organophilic clay viscosifier therein; a non-oleaginous internal phase; and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase; wherein the organophilic clay is swelled with a polar solvent that is added to the oleaginous phase prior to the addition of the organophilic clay.

[0013] In another aspect, embodiments disclosed herein relate to a gravel packing slurry, including: gravel; and an invert emulsion carrier fluid or gravel packing fluid including: an oleaginous external phase, wherein the oleaginous external phase has an organophilic clay viscosifier therein; a non-oleaginous internal phase; and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase; wherein the organophilic clay is swelled with a polar solvent that is added to the oleaginous phase prior to addition of the organophilic clay.

[0014] In yet another aspect, embodiments disclosed herein relate to a method of completing a wellbore penetrating a subterranean formation, the wellbore including a cased section and an uncased section, the method including: introducing gravel packing slurry, including gravel and invert emulsion fluid, into the uncased section of the wellbore, the invert emulsion fluid including: an oleaginous external phase, wherein the oleaginous external phase has a organophilic clay viscosifier dissolved therein; a non- oleaginous internal phase; and an emulsifier stabilizing the oleaginous external phase and the non-oleaginous internal phase; and running a liner or a sand control screen assembly to a selected depth within the uncased section of the wellbore in which the invert emulsion fluid is located wherein the organophilic clay is swelled with a polar solvent that is added to the oleaginous phase prior to the addition of the organophilic clay.

[0015] Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS [0016] FIG. 1 shows a schematic view of a completion interval depicting a gravel packing operation.

DETAILED DESCRIPTION

[0017] In one aspect, embodiments disclosed herein relate to methods of completion techniques that use invert emulsion fluids during the technique(s). More particularly, the present disclosure is directed toward the use of invert emulsion wellbore fluids in gravel packing and/or installing liners and/or sand control screens in a wellbore that may contain reactive shale or clay or in which the use of invert emulsion fluids may otherwise be desirable. As used herein, the expressions“reactive shale” or“reactive clay” or similar expressions may be used interchangeably and refer to those shale or clay materials that may swell, crumble, particalize, flake, slough off or otherwise deteriorate when exposed to aqueous fluids, particularly fresh water.

[0018] An invert emulsion is a water-in-oil emulsion, where an oleaginous fluid serves as a continuous phase and a non-oleaginous fluid serves as a discontinuous phase, the non- oleaginous fluid being stabilized or emulsed in the oleaginous fluid by an emulsifying agent. However, in one or more embodiments, the completion techniques of the present disclosure may use invert emulsion fluids having an oil/water ratio of less than 50/50, which may also be referred to as high internal phase ratio (HIPR) invert emulsions or high internal phase emulsions (HIPE). Such HIPR invert emulsions are discussed in more detail below. It is also understood that the completion techniques of the present disclosure may also be used in invert emulsion fluids having an oil/water ratio of more than 50/50.

[0019] As mentioned above, in the drilling of a well, the drilling fluid is typically circulated through the drill string, through the drill bit at the end of the drill string and up through the annulus between the drilled wellbore and drill string. The circulated drilling fluid is used to carry formation rock present as cuttings or drilled solids that are removed from the wellbore as the drilling fluid is circulated back to the surface.

[0020] In the construction of the well, a casing may be positioned within a portion of the drilled wellbore and cemented into place. The portion of the wellbore that is not lined with the casing forms the uncased or open hole section where, in accordance with some embodiments of the present disclosure, a sand control screen assembly is placed to facilitate gravel packing for controlling the migration and production of formation sand and to stabilize the formation of the open hole section.

[0021] Once the wellbore is drilled and the casing cemented into place, the well may be completed by installing sand screens and gravel packing the open hole section so that produced fluids from the formation are allowed to flow through the gravel pack and sand screen and may be recovered through the wellbore. The open hole section may be any orientation, including vertical and horizontal hole sections.

[0022] After the open hole and cased hole sections are displaced with the respective displacement fluids, the drilling string may be removed from the wellbore and the desired sand control screen assembly may be run or lowered to a selected depth within the open hole section of the well bore. The sand screen assembly may be run or lowered into the wellbore on a tubular member or wash pipe, which is used for conducting fluids between the sand screen and the surface. Running the sand screen assembly to the selected depth may include positioning the sand screen in vertical or non-vertical (horizontal) sections of the well. A packer may be positioned and set in the casing above the sand screen to isolate the interval being packed. A crossover service tool may also be provided with the assembly to selectively allow fluids to flow between the annulus formed by the open hole and the screen assembly and the interior of the tubular member and wash pipe.

[0023] Conventionally, with the sand control screen assembly in place, a gravel pack slurry containing gravel for forming the gravel pack and a water-based carrier fluid is introduced into the wellbore to facilitate gravel packing of the open hole section of wellbore in the annulus surrounding the sand control screen. The gravel pack slurry is typically introduced into the tubular member where it flows to the cross over tool into the annulus of the open hole section below the packer and the exterior of the sand control screen. As the gravel settles within the open hole section surrounding the screen, the carrier fluid passes through the screen and into the interior of the tubular member. The carrier fluid is conducted to the crossover tool and into the annulus between the casing and the tubular member above the packer.

[0024] As mentioned above, there are two techniques for gravel packing openhole horizontal wells:“a/b wave packing” and viscous-fluid packing or the“alternate path” technique. These techniques have completely different packing mechanisms, each having its own advantages and limitations. However, in accordance with the present disclosure, the invert emulsion gravel packing fluid of the present disclosure may be most suitable for use with viscous-fluid packing, also known as the“alternate path” technique.

[0025] Invert emulsion fluids of the present disclosure are formulated with viscosifiers

(such as those disclosed herein) to formulate a viscosified fluid that can be used to gravel pack by the alternate path technique. As shown in FIG. 1, a gravel slurry pumped through the interior 28 of tubular member 20 is diverted to flow through shunt tubes 22 on the outside of the screen assembly 24, which provide an alternative pathway for the gravel slurry. The gravel slurry exits from nozzles (not shown) on the shunt tubes 22 to form a pack 25 in a heel to toe manner. As the gravel settles within the open hole section 26 surrounding the screen 24, the carrier fluid passes through the screen 24 and into the interior 28 of the tubular member 20. The carrier fluid is conducted to the crossover tool 30 and into the annulus between the casing 27 and the tubular member 20 above the packer (not shown).

[0026] In one or more embodiments, the gravel particles may be ceramics, natural sand or other particulate materials suitable for such purposes. The gravel particles are sized so that they will not pass through the screen openings. Typical particle sizes in U.S. mesh size may range from about 12 mesh (1.68 mm) to about 70 mesh (0.210 mm); however, a combination of different particle sizes may be used. Examples of typical particle size combinations for the gravel particles are from about 12/20 mesh (1.68 mm/0.84l mm), 16/20 mesh (1.19 mm/0.84l mm), 16/30 mesh (1.19 mm/0.595 mm), 20/40 mesh (0.841 mm/0.420 mm), 30/50 mesh (0.595 mm/0297 mm), 40/60 mesh (0.420 mm/0.250 mm) and 40/70 mesh (0.420 mm/0.2l0 mm). The gravel particles may be coated with a resin to facilitate binding of the particles together. The resin-coated particles may be pre-cured or may cure in situ, such as by an overflush of a chemical binding agent or by elevated formation temperatures.

[0027] In addition to (or instead of) using the invert emulsion fluids of the present disclosure as a carrier fluid for gravel packing, in accordance with the present disclosure, the invert emulsions may also be used during the placement of sand control screens and/or liners, as well as other completion equipment.

[0028] The invert emulsion fluids of the present disclosure may be used with almost any type of liner or and/or sand control screen assembly. These may include pre-holed liners, slotted, liners, wire-wrapped screens, prepacked screens, direct-wrapped sand screens, mesh screens, premium-type screens, etc. Premium-type screens typically consist of multi-layers of mesh woven media along with a drainage layer. Premium-type screens do not have a well-defined screen opening size. In contrast, wire wrap screens consist of wire uniformly wrapped around a perforated base pipe. The wire wrap screens have a relatively uniform screen opening defined as gauge opening. Further, as described above, the sand control screen assembly may also include those with alternate flow paths or shunt tubes. Moreover, screen assemblies may also include those that include diverter valves for diverting fluid returns through a shorter pathway, preventing pressure build up during the gravel packing process. Other completion equipment with which the invert emulsions of the present disclosure may be used include packer assemblies (including swell packer assemblies), which separate upper annuli from lower production equipment in a well, or inflow control devices, which limit the inflow of fluids into the production tubing. The particular type of equipment is of no limitation on the present disclosure; rather, the invert emulsions of the present disclosure may be used with any type of equipment while the equipment is being run in the hole or during subsequent completion operations prior to the well being put into production. Further, depending on the arrangement, one or more of such completion equipment may be used in combination with each other.

[0029] In accordance with embodiments of the present disclosure, prior to installing sand control screens (using the invert emulsion fluids or not) and/or gravel packing (using the invert emulsion fluids or not), the drilling fluid may optionally be first displaced from the open hole section by a displacement fluid, and a second fluid may optionally be used to displace the fluid in a cased hole section. Displacement of the drilling fluids from the open hole section may be carried out by introducing the displacement fluid into the wellbore by passing the displacement fluid through the tubular drill string to the open hole section. As the displacement fluid is pumped through the drill string, the drilling fluids in the open hole section are carried upward through the annulus formed by the casing and the drill string. In a particular embodiment, if the formation includes reactive clays, the displacement fluid for the open hole section may include the invert emulsions of the present disclosure to help maintain the integrity of the open hole section containing reactive shales or clays that could otherwise be damaged if water- based fluids were used to displace the drilling fluids. In certain embodiments, the volume of first displacement fluid used may be sufficient to displace the open hole section plus the cased hole section up to the packer setting depth.

[0030] When a sufficient volume of the first displacement fluid is introduced into the wellbore to displace the drilling fluid from the open hole section of the wellbore, a second displacement fluid (optionally the same or different than the first) is used to displace at least a portion or all of the cased hole section of the wellbore. In certain embodiments, the volume of the second fluid may be sufficient to displace the entire cased section above the packer setting depth. This may be carried out by raising the end of the tubular drill string so that it is positioned within the cased hole section above the open hole section so that the second displacement fluid is discharged from the end of the drill string into the cased hole section.

[0031] Sand control screens and/or liners, or other completion equipment such as packer assemblies (including swell packer assemblies) or inflow control devices (limiting the inflow of fluids into the production tubing) are then run to target depth, which may optionally be in the presence of the invert emulsions of the present disclosure. The sand control screen may be a standalone sand screen or an expandable sand screen. After the sand control screen is installed, the well may be gravel packed with an invert emulsion fluid, as disclosed herein. Further, one of ordinary skill in the art would appreciate that one or more of such completion equipment may be used in combination.

[0032] Invert Emulsion Fluids

[0033] As mentioned above, there are two techniques for gravel packing openhole horizontal wells:“a/b wave packing” and viscous-fluid packing or the“alternate path” technique using b wave packing. These techniques have completely different gravel packing mechanisms, each having its own advantages and limitations a/b wave packing relies on the fluid velocity to transport the gravel and place the gravel pack within the open hole section of the wellbore a/b wave packing fluids are generally low viscosity fluids (e.g., brine) with low gravel concentration and carrying capacity (e.g., 1 to 2 pounds proppant added (ppa)). On the other hand, alternate path packing fluids rely on the fluid viscosity to carry the gravel and compared to a/b wave packing fluids these fluids have significantly higher viscosities and can effectively carry a considerably higher gravel concentration (e.g., 4 to 6 ppa). Conventional alternate path packing fluids are formulated as water-based fluids and therefore have limitations and drawbacks as discussed above for water-based fluids.

[0034] To make an invert emulsion system suitable as a gravel packing fluid for alternative path techniques the fluid needs to have three basic properties: 1) the fluid can suspend gravel; 2) low pumping friction, i.e., the fluid’s viscosity cannot be too high and should be shear-thinning; 3) and the fluid must have stability under pressure and at elevated temperature. The rheological profile and properties of a conventional 3- component invert emulsion system (i.e., oil, brine, and emulsifier) is affected by the oil to brine ratio (OBR). For example, at OBR from 90: 10 to 45:55, a conventional invert emulsion fluid has a low viscosity and Newtonian properties and gravel settles rapidly in such a fluid. At OBR of 40:60 to 35:65, a conventional invert emulsion fluid has a near-Newtonian profile and cannot completely suspend gravel but does slow down the settling of gravel. Thus, in conventional invert emulsion fluids that have an OBR of 30:70 or higher amount of oil the fluid has Newtonian or near-Newtonian characteristics and cannot suspend gravel sufficiently to be used as a gravel packing fluid for the alternate path technique.

[0035] Conversely, in conventional invert emulsions with a OBR of 30:70 or higher amount of water, the emulsion fluid has a non-Newtonian viscosity profile and, upon high shear, the fluid can be made very thick and have gravel suspension capability. For example, at an OBR of 20:80, the fluid looks like a paste and is very thick and can suspend gravel. These fluids have a power law type rheological profile and while they can suspend gravel the viscosity is too high causing the friction during pumping to be too high to be tolerable for downhole gravel packing applications

[0036] In one or more embodiments disclosed herein, an organophilic clay is added to the oil phase of an invert emulsion fluid to viscosify and otherwise modify the rheology of the fluid so that it has suitable properties to be used as a gravel packing fluid for alternative path placement techniques. Without being bound by theory it is believed that the synthetic polymer additive and/or the organophilic clay additive improves the shear thinning of the fluid, which helps reduce pumping pressure and friction during circulation, without affecting the ability of the fluid to adequately suspend gravel. The addition of organophilic clay allows for fluids with OBR values between about 70/30 to 25/75 to be suitable as gravel packing fluids for alternative path placement techniques.

[0037] In accordance with embodiments of the present disclosure, and in view of the invert emulsion fluids being shear thinning, the fluids may possess shear stress of less than 250 lb/lOO ft ² or less than 200 lb/lOO ft ² at 600 rpm, and a shear stress of less than 50 lb/lOO ft ² and/or 30 lb/lOO ft ² but at least 15 lb/lOO ft ² at 6 rpm and 3 rpm (all of which are measured using a Fann 35 Viscometer from Fann Instrument Company (Houston, Texas) at l40°F). [0038] The oleaginous fluid used to make up the oil phase may be a liquid and more preferably is a natural or synthetic oil and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including 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. In a particular embodiment, the fluids may be formulated using diesel oil or a synthetic oil as the external phase. In one or more embodiments, the amount of oleaginous fluid in the invert emulsion may be between about 30 and 70 volume percent or between about 40 and 60 volume percent.

[0039] The non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein is a liquid and preferably is an aqueous liquid. More preferably, the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof. For example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water. Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, 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 drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. In one embodiment, the density of the drilling fluid may be controlled by increasing the salt concentration in the brine (up to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium. In one or more embodiments, the amount of non-oleaginous fluid in the invert emulsion may be between about 30 and 70 volume percent or between about 40 and 60 volume percent.

[0040] In one or more embodiments, an organophilic clay is added to the oleaginous phase to viscosify the phase prior to mixing with the non-oleaginous phase and forming the invert emulsion. In one or more embodiments, the organophilic clay is swelled with a polar solvent that is added to the oleaginous phase prior to the addition of the organophilic clay. That is, a polar organic solvent is added to the oleaginous phase, which swells the organophilic clay to form a gel structure. In one or more embodiments, the polar solvent may be propylene carbonate. In one or more embodiments, the organophilic clay is a hectorite clay, such as VERSA-GEL HT, available from M-I LLC (Houston, TX). In one or more embodiments, the organophilic clay viscosifier is present in the invert emulsion fluid in an amount of about 1 - 8 ppb or 2 - 5 ppb.

[0041] In one or more embodiments, a synthetic polymer viscosifier may also be added to the oleaginous phase to viscosify the phase prior to mixing with the non-oleaginous phase and forming the invert emulsion. In one or more embodiments, the synthetic polymer viscosifier is an oil-soluble micelle polymer. That is, the synthetic polymer viscosifier forms micelles in the oleaginous phase. In more detailed embodiments, the synthetic polymer viscosifier is selected from a styrene-butadiene block copolymer, a polymethacrylate, an olefin copolymer, or a hydrogenated styrene-isoprene copolymer. In one or more embodiments, the synthetic polymer viscosifier is a styrene-butadiene block copolymer. In one or more embodiments, the synthetic polymer viscosifier is present in the invert emulsion fluid in an amount of about 0.1 - 4 ppb, 0.5 - 2 ppb, 1 - 8 ppb or 2 - 4 ppb.

[0042] Further, in order to form an invert emulsion or water-in-oil emulsion and emulsifier may be added to stabilize the dispersed non-oleaginous phase. The term “HLB” (Hydrophilic Lipophilic Balance) refers to the ratio of the hydrophilicity of the polar groups of the surface-active molecules to the hydrophobicity of the lipophilic part of the same molecules. One skilled in the art would appreciate that an HLB value may be calculated by considering the molecular weight contributions of the respective hydrophilic and lipophilic portions and taking the ratio thereof (divided by 5). Generally, the Bancroft rule applies to the behavior of emulsions: emulsifiers and emulsifying particles tend to promote dispersion of the phase in which they do not dissolve very well; for example, a compound that dissolves better in water than in oil tends to form oil-in-water emulsions (that is they promote the dispersion of oil droplets throughout a continuous phase of water). Emulsifiers are typically amphiphilic. That is, they possess both a hydrophilic portion and a hydrophobic portion. The chemistry and strength of the hydrophilic polar group compared with those of the lipophilic nonpolar group determine whether the emulsion forms as an oil-in-water or water-in-oil emulsion. In particular, emulsifiers may be evaluated based on their HLB value. Generally, to form a water-in-oil emulsion, an emulsifier (or a mixture of emulsifiers) having a low HLB, such as between 3 and 8, may be desirable. In a particular embodiment, the HLB value of the emulsifier may range from 4 to 6.

[0043] In particular embodiments, the emulsifier may be used in an amount ranging from

1 to 10 pounds per barrel, and from 2 to 6 or 2 to 9 pounds per barrel, in other particular embodiments. In one or more embodiments, the emulsifier may be an amine-based emulsifier, an amide-based emulsifier, a carboxylic-based emulsifier, a fatty acid-based emulsifier, fatty acids, soaps of fatty acids, amidoamines, polyamides, polyamines, fatty acid ester derivatives, ethoxylated fatty acids, ethoxylated alcohol, oleate esters, such as sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or alcohol derivatives and combinations of thereof. In particular embodiments, the emulsifier may be an amidoamine. For example, one or more embodiments, a fatty acid (one or more of a C10-C24 fatty acid, for example, which may include linear and/or branched, and saturated and/or unsaturated fatty acids) may be reacted with one or more ethyleneamines (e.g., ethylenediamine, diethylenetriamine, triethylenetetraamine, tetraethylenepentaamine) to produce one or more of amides, polyamides, and/or amidoamines, depending, for example, on the mole ratio of the polyamine to the fatty acid. In one or more embodiments, the emulsifier may be a dimer poly-carboxylic C12 to C22 fatty acid, trimer poly-carboxylic C12 to C22 fatty acid, tetramer poly- carboxylic C12 to C22 fatty acid, mixtures of these acids, or a polyamide wherein the polyamide is the condensation reaction product of a C12-C22 fatty acid and a polyamine selected from the group consisting of diethylenetriamine, triethylenetetramine; and tetraethyl enepentamine. In one or more embodiments, the emulsifier may be a blend of Cl 5-40 polyolefins, polyamides with a molecular weight greater than 1200, and amines. Emulsifiers of the present disclosure may have an amine number in the range of 25-50. The term“amine number” refers to the ratio of the mass of potassium hydroxide which consumes exactly as much acid on neutralization as does the sample being examined, to the mass of that sample. In one or more embodiments, the emulsifier may be a polyalkenyl succinimide compound.

[0044] In one or more embodiments, the emulsifier may be an alkoxylated ether acids. In one or more embodiments, an alkoxylated ether acid is an alkoxylated fatty alcohol terminated with a carboxylic acid, represented by the following formula:

[0046] where R is C ₆ -C ₂ 4 or -C(0)R ³ (where R ³ is C10-C22), R ¹ is H or C1-C4, R ² is C1-C5 and n may range from 0 to 20 in one or more embodiments (0 in some embodiments and 1-20 in other embodiments). Such compounds may be formed by the reaction of an alcohol with a polyether (such as poly(ethylene oxide), polypropylene 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 R ¹ 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 R ¹ is -CH _3, n may range up to 20 (and up to 15 in other embodiments). Further, selection of R (or R ³ ) and R ² may also depend on based on the hydrophilicity of the compound due to the extent of polyetherification (z.e., number of n). In selecting each R (or R ³ ), R ¹ , R ² , 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. For example, PRIMO-SURF, SUREWET, PRIMO-MUL, all available from M-I L.L.C. (Houston, TX), may serve as an emulsifier for the invert emulsion fluids disclosed herein. In one or more embodiments, the emulsifier may be a tall oil fatty acid (TOFA) amide, such as TOFA di ethanol amide. In one or more embodiments, the emulsifier may be a mono-ethanol amide, a di-ethanol amide, or an isopropanol amide. In one or more embodiments, the emulsifier may be an oleic-based amide, such as oleic acid di ethanol amide or similar amides with different head groups (e.g., oleyl sarcosinate and oleyl taurate). In one or more embodiments, the emulsifier may be a polyisobutylenesuccinic anhydride. Specific commercial emulsifiers that may be used include Schercomide SOA, available from Lubrizol, or AMADOL WE from Akzonobel.

[0047] In one or more embodiments, at least two emulsifiers may be used in invert emulsion fluids of the present disclosure, specifically, an amine based emulsifier (including the amides discussed above) that is used in combination with a carboxylic acid-based emulsifier (including those of the formula above). In one or more embodiments, the amount of amine-based emulsifier used may be modulated because inventors have found that too much amine has adverse effects on the invert emulsion fluid (specifically, on its gel structure). Conversely, the emulsion may have less stability than desired if only a carboxylic acid-based emulsifier is used. Thus, the amount of amine-based emulsifier may be limited to no more than 4 ppb and it may be necessary to use a mixture (e.g., at least two) of emulsifiers when an amine-based emulsifier is used.

[0048] In one or more embodiments, the invert emulsion fluids of the present disclosure may also include a rheology modifier. In one or more embodiments, the rheology modifier may be an alkoxylated alcohol. In more particular embodiments, the rheology modifier may be a C12-C18 alcohol, which is ethoxylated or propoxylated with 1 to 10 units. When included, the rheology modifier may be added in amounts between about 1 and 8 ppb or 2 and 4 ppb.

[0049] Other additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, 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.

[0050] Conventional viscosifying agents that may be used in the fluids disclosed herein include amine treated clays, oil soluble polymers, polyamide resins, polycarboxylic acids, and soaps. The amount of conventional 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. VG-69TM and VG-PLUSTM are organoclay materials distributed by M-I, L.L.C., Houston, Texas that may be used in the fluids disclosed herein. While such viscosifiers may be particularly useful during gravel packing by the alternative path technique, the viscosifiers may also be incorporated into the fluid formulation for other completion operations as well.

[0051] Additionally, lime or other alkaline materials are typically added to conventional invert emulsion drilling fluids and muds to maintain a reserve alkalinity.

[0052] Conventional methods can be used to prepare the gravel packing invert emulsion fluids disclosed herein in a manner analogous to those normally used to prepare conventional oil-based drilling fluids. In one embodiment, a desired quantity of oleaginous fluid such as a base oil and a suitable amount of polar solvent and an organophilic clay viscosifying agent 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.

[0053] In various embodiments, methods of gravel packing a section of a wellbore in a subterranean formation using an invert emulsion gravel packing fluidaccording to the present disclosure may comprise mixing an oleaginous fluid, an organophilic clay viscosifying agent, a non-oleaginous fluid, such as those described above, and in the ratios described above, to form an invert emulsion; adding gravel to the invert emulsion; and pumping the gravel packing fluid into a subterranean wellbore to gravel pack the wellbore with the alternative path technique. Specific formulations may depend on the state of the wellbore at a particular time, for example, depending on the depth of the section to be gravel packed and/or the composition of the formation.

[0054] EXAMPLES

[0055] The following examples were used to test the stability and rheological properties of invert emulsion fluids, such as those described in the present disclosure.

[0056] Example 1

[0057] Various invert emulsions were formulated having the following components, as shown below in Table 1. Specifically, the components include a mineral oil as the base oil (ESCAID 110). The brine used was a 14.2 ppg CaBr ₂ bring. The emulsifier was PRIMO-SURF, an amine-based emulsifier available from M-I LLC (Houston, TX). The oil phase viscosifier was POLAR- VIS, a di-block copolymer of styrene-butadiene, available from M-I LLC (Houston, TX). The rheology modifier was a C18-3EO ethoxylated alcohol.

[0058] The rheological properties of the various mud formulations were determined using a Fann Model 35 Viscometer, available from Fann Instrument Company. The rheology of the fluids was found to be similar both directly after formulation and after three weeks of aging at room temperature.

Table 1

[0059] Example 2

[0060] In this set of tests, the effect of temperature on the rheological profile of invert emulsion fluids containing POLAR- VIS was evaluated. An OBR = 50/50 fluid was formulated with 6 ppb PRIMO-SURF and 6 ppb POLAR- VIS. The viscosity was measured at 5 temperatures from 85°F to 250°F. It can be seen from Table 2 below, fluids’ viscosity decreases as temperature increases. However, the decrease from 85°F to 200°F is not significant, indicating the stability of the fluid. Also, the decrease is mainly in high shear rate region, which helps to reduce friction pressure and does not decrease the fluid’s gravel suspension capability. It is worth noting that by having POLAR- VIS in the invert emulsion fluid, the overall sensitivity of the fluid’s viscosity to temperature reduced significantly, that is, without POLAR- VIS the viscosity of an invert emulsion decreases much quicker as temperature increases

Table 2

[0061] Example 3

[0062] A fluid similar having the composition of Fluid #4 in Table 1 above was formulated and its rheology as a function of pressure and temperature was tested. The results are shown in Table 3 below.

Table 3

[0063] Example 4

[0064] The sensitivity of the formulation to the type of brine used was studied by forming two fluids, one using a CaBr ₂ brine and another using a NaBr brine. The formulation details and rheological results are shown in Table 4 below. Table 4

[0065] The data in Table 4 shows that the formulation is not sensitive to the type of brine. When the brine was switched from l4.2ppg CaBr ₂ to l2.5ppg NaBr ₂ as the internal phase, the same viscosity profile was developed.

[0066] Example 5

[0067] Static sand settling testing was performed on several fluid formulations. As shown in Table 5, fluids # 1, #3, and #4 are the same as the same numbered fluids described in Table 1 above. The oil, brine, and rheology modifier are all the same as for the samples in Table 1 above. All tests were performed with 6 ppa, where the sand/proppant used was 20/40 CARBOLITE.

Table 5

[0068] Example 6

[0069] Various invert emulsions were formulated having the following components, as shown below in Table 6. Specifically, the components include ESC AID 110, a mineral oil as the base oil. The brine was a 14.2 ppg CaBr ₂ brine. The emulsifier was one or more of PRIMO-SURF, SUREWET, PRIMO-MUL, all of these three products are available from M-I LLC (Houston, TX), Schercomide SOA, available from Lubrizol, and AMADOL WE, available from Akzonobel. The organophilic clay oil phase viscosifier was VERSAGEL HT, available from M-I LLC (Houston, TX).

Table 6 - Typical Fluid Formulations

[0070] Table 7 below shows the rheological profile of the fluid formulations above. The low shear rate rheology of the three fluids without propylene carbonate are much lower than those with propylene carbonate and those without propylene carbonate were not able to suspend 20/40 mesh gravel. The values for 600 RPM - 3 RPM are measured in lb/lOO ft ² .

Table 7 - Rheology Profile in Dial Readings Measured with Fann 35 for Fluids in Table 1

[0071] Table 8 below shows the Grace measurement at temperatures and pressures for fluid #7. Fluid rheology increases as pressure increases. Fluid is stable for temperature up to 300 ⁰ F. The values for 600 RPM - 3 RPM are measured in lb/lOO ft ² .

Table 8

[0072] 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.