Patent Application
20200407621
Embodiments of the disclosure generally relate to emulsified drilling fluids and methods of making and using emulsified drilling fluids. Specifically, embodiments of the present disclosure relate to drilling fluids having at least one surfactant and methods of making and using drilling fluids having at least one surfactant.
Drilling fluids in the oil and gas industries perform a myriad of tasks, including cleaning a well, holding cuttings in suspension, reducing friction, lubricating the drilling tools, maintaining stability of a wellbore, and preventing fluid loss, to name a few. While water-based drilling fluids can be environmentally friendly and cost-efficient, they corrode metal tools and disintegrate clays and salts, making them an undesirable choice for many applications. Oil-based fluids are more compatible with tooling, but are also more costly and cause concerns with handling, as discharging whole fluid or cuttings generated with oil-based fluids is not permitted in many offshore-drilling areas.
To overcome these difficulties, emulsified drilling fluids may be used. Direct emulsified drilling fluids are oil-in-water (O/W) emulsions in which oil droplets are dispersed in a water-based fluid. These emulsified drilling fluids are able to utilize characteristics of both oil-based and water-based fluids. However, as oil and water are incompatible, while the oil and water phases may be mechanically mixed under high shear to form the emulsion, the drilling fluid formed remains unstable and the phases may begin to separate after time.
Drilling fluids may utilize stabilizers to help stabilize the dispersed phases; however, conventional stabilizers require expensive additives or a specific pH range to effectively stabilize the dispersed oil and water phases for prolonged periods of time.
Accordingly, an ongoing need exists for stabilized emulsion drilling fluids that can maintain both oil and water phases for prolonged periods of time without the use of additional additives or specified required conditions, such as pH. The present embodiments address these needs by providing emulsified drilling fluids and methods of making and using emulsified drilling fluids with improved rheology and stability without requiring additives or a required pH range.
In one embodiment, the present disclosure relates to drilling fluids comprising an aqueous phase, an oleaginous phase, and at least one surfactant having the formula R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms and x is an integer from 1 to 10. In some embodiments, the surfactant may have a hydrophilic-lipophilic balance (HLB) of from 8 to 16.
In additional embodiments, the present disclosure relates to methods of producing a drilling fluid by mixing an aqueous phase, an oleaginous phase, and at least one surfactant having the formula R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms and x is an integer from 1 to 10. The method also includes shearing the mixture to form the drilling fluid. In some embodiments, the surfactant may have an HLB of from 8 to 16.
Still further embodiments of the present disclosure include methods of using a drilling fluid by mixing an aqueous phase, an oleaginous phase, and at least one surfactant having the formula R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms and x is an integer from 1 to 10 to produce a mixture. The method also includes shearing the mixture to form the drilling fluid, pumping the drilling fluid into a subterranean formation, and circulating the drilling fluid in the subterranean formation. In some embodiments, the surfactant may have an HLB of from 8 to 16.
Further embodiments of the present disclosure include methods of using a drilling fluid to drill a subterranean formation by mixing an aqueous phase, an oleaginous phase, and at least one surfactant having the formula R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms and x is an integer from 1 to 10 to produce a mixture. The method also includes shearing the mixture to form the drilling fluid, pumping the drilling fluid through a drill string in a drill bit located in the subterranean formation, transporting rock cuttings from the drill bit to a surface of the subterranean formation, and circulating the drilling fluid in the subterranean formation. In some embodiments, the surfactant may have an HLB of from 8 to 16.
Additional features and advantages of the described embodiments will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the described embodiments, including the detailed description which follows as well as the claims.
Embodiments of the present disclosure are directed to emulsified drilling fluids and methods of making and using emulsified drilling fluids. The embodiments include, among other things, emulsified drilling fluids that include an aqueous phase, an oleaginous phase, and at least one surfactant. The embodiments also include methods of producing an emulsion fluid by mixing an aqueous phase, an oleaginous phase, and at least one surfactant and shearing the mixture. Further embodiments include methods of using the drilling fluids by mixing an aqueous phase, an oleaginous phase, and at least one surfactant, shearing the mixture, pumping the drilling fluid into to a subterranean formation, and, in some embodiments, into a drill string, and circulating the drilling fluid in the subterranean formation.
As a non-limiting example, the drilling fluids of the present disclosure may be used in the oil and gas drilling industries, such as for drilling in oil and gas wells. Oil and gas wells may be formed in subterranean portions of the Earth, sometimes referred to as subterranean geological formations. The wellbore may serve to connect natural resources, such as petrochemical products, to a ground level surface. In some embodiments, a wellbore may be formed in the geological formation, such as by a drilling procedure. To drill a subterranean well or wellbore, a drill string including a drill bit and drill collars to weight the drill bit is inserted into a predrilled hole and rotated to cut into the rock at the bottom of the hole, producing rock cuttings. Commonly, the drilling fluid, known as “drilling mud,” may be utilized during the drilling process. To remove the rock cuttings from the bottom of the wellbore, drilling fluid is pumped down through the drill string to the drill bit. The drilling fluid may cool the drill bit and lift the rock cuttings away from the drill bit and may carry the rock cuttings upwards as the drilling fluid is recirculated back to the surface. The drilling fluid serves several functions in the drilling process. The drilling fluid may provide lubrication and may cool the drill bit. The drilling fluid may also transport rock cuttings from the drill bit to the surface, which may be referred to as “cleaning” the wellbore. Additionally, the drilling fluid may provide hydrostatic pressure in the wellbore to provide support to the sidewalls of the wellbore and prevent the sidewalls from collapsing and caving in on the drill string. The drilling fluid may also prevent fluids in the downhole formations from flowing into the wellbore during drilling operations.
To accomplish these functions, the drilling fluid may be formulated to have specific characteristics, such as density, viscosity, solids content, pump-ability and hole-cleaning capability, among others. In particular, the drilling fluid may be formulated to have a density in a range suitable to provide the necessary hydrostatic pressure to support the sidewalls of the wellbore and prevent fluids in the formation from flowing into the wellbore. Additionally, the drilling fluids may be formulated to have specific rheological properties that allow the drilling fluid to be pumped down through the drill string while still capturing and conveying rock cuttings from the drill bit to the top of the wellbore. In some embodiments, the drilling fluids may include solid particles suspended in a base fluid. The solid particles, sometimes referred to as a weighting agent, may increase the density of the drilling fluid to help the drilling fluid support the sidewalls of the wellbore are well as increase the hydrostatic pressure to keep fluids from the formation from flowing into the wellbore. In other embodiments, the drilling fluids may be able to provide the necessary hydrostatic pressure without the use of solid particles to increase the density of the fluid.
Conventional drilling fluids that utilize solid weighting agents, such as barite, encounter difficulties as the solids separate from the liquid and settle in the wellbore, known as barite sag. Barite sag typically occurs when flow of drilling fluid through the wellbore is stopped for a period of time during which the drilling fluid is static, but barite sag may also occur at decreased flow or annular velocity of the drilling fluid. Barite sag may also be worsened by reduced viscosity or reduced gel strength drilling fluids, reduced shear rate conditions, greater downhole temperatures and other conditions. Settling of the solid weighting material may cause variations in the density of drilling fluid throughout the wellbore. For example, the drilling fluid in the bottom of the wellbore may have a greater density due to settling of the solids towards the bottom of the wellbore caused by gravity, and the drilling fluid near the surface may have a lesser density. Barite sag conditions may lead to stuck pipe conditions, reductions in the hole-cleaning ability of the drilling fluid, or both. The hole-cleaning ability of a drilling fluid refers to the ability of the drilling fluid to capture rock cuttings from the drilling zone and convey them to the surface of the wellbore.
The drilling fluids of the present disclosure may overcome these difficulties by providing improved rheology characteristics, such as viscosity, gel strength and shear strength. Additionally, in some embodiments, the drilling fluid of the present disclosure may not contain solid weighting agents, thus obviating the barite sag problems experienced by conventional drilling fluids. Embodiments of the present disclosure generally relate to emulsified drilling fluids containing an aqueous phase, an oleaginous phase, and at least one surfactant. As used throughout the disclosure, “aqueous phase” refers to a fluid containing, producing, resembling, or having the properties of water. Similarly, “oleaginous phase” refers to a fluid containing, producing, resembling, or having the properties of oil.
As stated, the aqueous phase may be any suitable fluid containing, producing, resembling, or having the properties of water. The aqueous phase in some embodiments may contain water, including freshwater or seawater. The aqueous phase may contain brine, including natural and synthetic brine, such as saturated brine or formate brine. The aqueous phase in some embodiments may use water containing organic compounds or salt. Without being bound by any particular theory, salt or other organic compounds may be incorporated into the aqueous phase to control the density of the emulsified drilling fluid. Increasing the saturation of the aqueous phase by increasing the salt concentration or the level of other organic compounds in the aqueous phase may increase the density of the drilling fluid. Suitable salts include but are not limited to alkali metal chlorides, hydroxides, or carboxylates. In some embodiments, suitable salts may include sodium, calcium, cesium, zinc, aluminum, magnesium, potassium, strontium, silicon, lithium, chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, sulfates, phosphates, oxides, fluorides and combinations of these. In some particular embodiments, brine may be used in the aqueous phase. Without being bound by any particular theory, brine may be used to create osmotic balance between the drilling fluid and the subterranean formation.
In some embodiments, the drilling fluid may contain from 10 weight percent (wt %) to 70 wt % of the aqueous phase based on the total weight of the drilling fluid. In some embodiments, the drilling fluid may contain from 28 pounds per barrel (lb/bbl) to 630 lbs/bbl, such as from 30 to 600 lbs/bbl, from 50 to 500 lbs/bbl, from 100 to 500 lb/bbl, 200 to 500 lbs/bbl, or 300 to 600 lbs/bbl of the aqueous phase.
The drilling fluid of the present embodiments also includes an oleaginous phase. As stated, the oleaginous phase refers to a fluid containing, producing, resembling, or having the properties of oil. The oleaginous phase may be oil, such as natural or synthetic liquid oil. The oleaginous phase may be or may contain diesel oil, mineral oil, hydrogenated or unhydrogenated olefins such as poly-alpha olefins, linear and branched olefins, poly-diorganosiloxanes, silxoanes, organosiloxanes, esters of fatty acids, straight chain, branched or cyclical alkyl ethers of fatty acids, or combinations of any of these. The oleaginous phase may contain esters, ethers, acetals, dialkylcarbonates, hydrocarbons or combinations of any of these. In some embodiments, the oleaginous phase may contain or may be oils derived from petroleum, such as mineral oils, diesel oils, linear olefins, paraffin, other petroleum-based oils, and combinations of these oils or oils derived from plants, such as safra oil, for example.
The drilling fluid may contain from 10 wt % to 90 wt % of the oleaginous phase based on the total weight of the drilling fluid. The drilling fluid may contain from 28 lb/bbl to 810 lb/bbl of the oleaginous phase based on the total weight of the drilling fluid, such as from 30 to 800 lb/bbl, from 50 to 800 lb/bbl, from 75 to 800 lb/bbl, or from 100 to 800 lb/bbl. In some embodiments, the drilling fluid may contain from 200 to 800 lb/bbl, or 300 to 600 lb/bbl, or 500 to 810 lb/bbl of the oleaginous phase.
The emulsified drilling fluid may include at least one surfactant. According to one or more embodiments, the surfactant may have the chemical structure of Formula (I):
R—(OC2H4)x—OH Formula (I)
In Formula (I), R is a hydrocarbyl group having from 8 to 20 carbon atoms and x is an integer from 1 to 10. As used in this disclosure, a “hydrocarbyl group” refers to a chemical group consisting of carbon and hydrogen. Typically, a hydrocarbyl group may be analogous to a hydrocarbon molecule with a single missing hydrogen (where the hydrocarbyl group is connected to another chemical group). The hydrocarbyl group may contain saturated or unsaturated carbon atoms in any arrangement, including straight (linear), branched, aromatic, or combinations of any of these configurations. The hydrocarbyl R group in some embodiments may be an alkyl (—CH3), alkenyl (—CH═CH2), alkynyl (—C—CH), or cyclic hydrocarbyl group, such as a phenyl group, which may be attached to a hydrocarbyl chain.
In some embodiments, R may have from 8 to 20 carbons, such as from 10 to 20 carbons, 8 to 18 carbons, 10 to 18 carbons, from 10 to 16 carbons, from 8 to 14 carbons, from 8 to 12 carbons, or from 12 to 20 carbons, or from 8 to 15 carbons, or from 14 to 20 carbons, or from 16 to 20 carbons, or from 18 to 20 carbons, or from 12 to 16 carbons, or from 12 to 15, or from 12 to 14 carbons. In some embodiments, R may have 12 carbons, or 13 carbons, or 14 carbons or 15 carbons. In some particular embodiments, R may have 13 carbons, and, in some embodiments, R may be C13H27 (isotridecyl) or may contain an isotridecyl group.
In Formula (I), x is an integer between 1 and 10. In some embodiments, x may be 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10. In some embodiments, x may be an integer from 5 to 10, from 5 and 9, from 7 to 10, or from 7 to 9. In some embodiments, x may be an integer greater than or equal to 5, such as an integer greater than or equal to 7, or greater than or equal to 8.
The surfactant may be amphiphilic, meaning that it has a hydrophobic tail (the non-polar R group) and a hydrophilic head (the polar —OH groups from ethylene oxide and the alcohol group) that may lower the surface tension between two liquids or between a liquid. In some embodiments, the surfactant may have a hydrophilic-lipophilic balance (HLB) of from 8 to 16. Without being bound by any particular theory, the HLB of the compound is the measure of the degree to which it is hydrophilic or lipophilic, which may be determined by calculating values for the regions of the molecules in accordance with the Griffin Method in accordance with Equation 1:
In Equation 1, Mh is the molecular mass of the hydrophilic portion of the molecule and M is the molecular mass of the entire molecule. The resulting HLB value gives a result on a scale of from 0 to 20 in which a value of 0 indicates to a completely hydrophobic/lipophilic molecule and a value of 20 corresponds to a completely hydrophilic/lipophobic molecule. Generally, a molecule having an HLB of less than 10 is lipid-soluble (and thus water-insoluble) and a molecule having an HLB of greater than 10 is water-soluble (and thus lipid-insoluble). In some embodiments, the surfactant may have an HLB of from 8 to 16. The surfactant may have an HLB of from 10 to 16, or from 12 to 16, or from 8 to 14, or from 10 to 14, or from 12 to 16, or from 12 to 14, or from 8 to 12, or from 13 to 16. In some embodiments, the surfactant may have an HLB of 12, or 12.5, or 12.75, or 13 or 13.5, or 14. This HLB value may indicate that the surfactant has both hydrophilic and lipophilic affinities (as the surfactant is amphiphilic) but has a slightly greater tendency towards being hydrophilic/lipophobic, and thus, may be at least partially water-soluble.
The drilling fluid may contain from 0.01 wt % to 20 wt % of the surfactant based on the total weight of the drilling fluid. The drilling fluid may contain from 0.02 lb/bbl to 180 lb/bbl of the surfactant based on the total weight of the drilling fluid, such as from 0.02 to 150 lb/bbl, or from 0.05 to 150 lb/bbl. In some embodiments, the drilling fluid may contain from 0.1 to 150 lb/bbl, or from 0.1 to 100 lb/bbl, or from 1 to 100 lb/bbl of the surfactant.
The surfactant may be a reaction product of a fatty alcohol ethoxylated with ethylene oxide. As used throughout the disclosure, a fatty alcohol refers to a compound having a hydroxyl (—OH) group and at least one alkyl chain (—R) group. The ethoxylated alcohol compound may be made by reacting a fatty alcohol with ethylene oxide. The ethoxylation reaction in some embodiments may be conducted at an elevated temperature and in the presence of an anionic catalyst, such as potassium hydroxide (KOH), for example. The ethoxylation reaction may proceed according to Equation 2:
The fatty alcohols used as the reactant in Equation 2 to make the ethoxylated alcohol compound could include any alcohols having formula R—OH, where R is a saturated or unsaturated, linear, or branched hydrocarbyl group having from 8 to 20 carbon atoms, from 10 to 16 carbon atoms, or from 12 to 14 carbon atoms. In some embodiments, R may be a saturated linear hydrocarbyl group. Alternatively, the fatty alcohol may include R that is a branched hydrocarbyl group.
In some embodiments, the R—OH group of the surfactant may be a naturally-derived or synthetically-derived fatty alcohol. Non-limiting examples of suitable fatty alcohols may include, but are not limited to capryl alcohol, perlargonic alcohol, decanol (decyl alcohol), undecanol, dodecanol (lauryl alcohol), tridecanol (tridecyl alcohol), myristyl alcohol (1-tetradecanol), pentadecanol (pentadecyl alcohol), cetyl alcohol, palmitoleyl alcohol, heptadecanol (heptadecyl alcohol) stearyl alcohol, nonadecyl alcohol, arachidyl alcohol, other naturally-occurring fatty alcohols, other synthetic fatty alcohols, or combinations of any of these.
The fatty alcohol may be a naturally occurring fatty alcohol, such as a fatty alcohol obtained from natural sources, such as animal fats or vegetable oils, like coconut oil. The fatty alcohol may be a hydrogenated naturally-occurring unsaturated fatty alcohol. Alternatively, the fatty alcohol may be a synthetic fatty alcohol, such as those obtained from a petroleum source through one or more synthesis reactions. For example, the fatty alcohol may be produced through the oligomerization of ethylene derived from a petroleum source or through the hydroformylation of alkenes followed by hydrogenation of the hydroformylation reaction product.
As shown in Equation 2, the reaction product may have the general chemical formula R—(OCH2CH2)x—OH, where R is a saturated or unsaturated, linear or branched hydrocarbyl group having from 8 to 20 carbon atoms. According to some embodiments, the R group may be an iso-tridecyl group (—C13H27), as depicted in Chemical Structure A. It should be understood that Chemical Structure A depicts one possible embodiment of the surfactant of Formula (I) in which the R group is an iso-tridecyl group, which is used as a non-limiting example. In some embodiments, Chemical Structure (A) may have 8 ethoxy groups (that is, x equals 8 in Chemical Structure (A)) such that the surfactant is a tridecyl alcohol ethyoxylate with an 8:1 molar ratio of ethylene oxide condensate to branched isotridecyl alcohol having the chemical formula C13H27—(OCH2CH2)8—OH.
Generally, an x:1 molar ratio of the fatty alcohol to the ethylene oxide may be utilized to control the level of ethoxylation in Equation 2. In some embodiments, x may be an integer from 1 to 10. For instance, x may be 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10. In some embodiments, the surfactant may be the reaction product of fatty alcohol ethoxylated with ethylene oxide at an 8:1 molar ratio of fatty alcohol to ethylene oxide. In some particular embodiments, the surfactant may be a synthetic alcohol oxylate and may be an ethylene oxide condensate of isotridecyl alcohol. The surfactant may be produced by an 8:1 molar ratio of ethylene oxide to isotridecyl alcohol. In some particular embodiments, the surfactant may be produced by an 8:1 molar ratio of ethylene oxide condensate to synthetic branched isotridecyl alcohol.
In some embodiments, the drilling fluid may contain at least one additive other than the surfactant. The one or more additives may be any additives known to be suitable for drilling fluids. As non-limiting examples, suitable additives may include weighting agents, fluid loss control agents, lost circulation control agents, other surfactants, antifoaming agents, supplemental emulsifiers, weighting agent, fluid loss additives, viscosity adjusters, an alkali reserve, specialty additives, and combinations of these. In particular some embodiments, the one or more additives may include organoclay, such as VG 69 organoclay, an amine-treated bentonite used as a viscosifier and gelling agent, commercially available from Schlumberger (Houston, Tex.). The one or more additives may also include a filtration control agent, such as ADAPTA® brand filtration control agent, methylstyrene acrylate copolymer used to provide filtration control in non-aqueous systems and to improve viscosity by reducing, commercially available from Halliburton (Houston, Tex.). In some embodiments, the drilling fluid may contain both an organo clay and a filtration control agent.
In some embodiments, the one or more additives may include a viscosifier, also referred to as a rheology modifier, which may be added to the drilling fluid to impart non-Newtonian fluid rheology to the drilling fluid to facilitate lifting and conveying rock cuttings to the surface of the wellbore. Examples of viscosifiers may include, but are not limited to bentonite, polyacrylamide, polyanionic cellulose, or combinations of these viscosifiers. In some embodiments, the drilling fluid may include xanthum gum, a polysaccharide commonly referred to XC polymer. The XC polymer may be added to the water-based drilling fluid to produce a flat velocity profile of the water-based drilling fluid in annular flow, which may help to improve the efficiency of the drilling fluid, in particular lower density drilling fluids, in lifting and conveying rock cuttings to the surface.
In some embodiments, the drilling fluid may contain from 0.01 wt % to 20 wt % of the one or more additives based on the total weight of the drilling fluid. The drilling fluid may contain from 0.02 lb/bbl to 180 lb/bbl of the one or more additives based on the total weight of the drilling fluid, such as from 0.02 to 150 lb/bbl, or from 0.05 to 150 lb/bbl. In some embodiments, the drilling fluid may contain from 0.1 to 150 lb/bbl, or from 0.1 to 100 lb/bbl, or from 1 to 100 lb/bbl of the one or more additives.
In some embodiments, the one or more additives may include solids, sometimes referred to as weighting material, which may be dispersed in the drilling fluid. The solids may be finely divided solids having a high specific gravity (SG) that may be added to the drilling fluid to increase the density of the drilling fluid. Examples of weighting materials suitable for use as the solid include, but are not limited to, barite (minimum SG of 4.20 grams per centimeter cubed (g/cm3)), hematite (minimum SG of 5.05 g/cm3), calcium carbonate (minimum SG of 2.7-2.8 g/cm3), siderite (minimum SG of 3.8 g/cm3), ilmenite (minimum SG of 4.6 g/cm3), other weighting materials, or any combination of these weighting materials. In some embodiments, the drilling fluid may include barite as the solid.
In embodiments, the drilling fluid may have a solids content of from 1 wt % to 80 wt % based on the weight of the solid weighing material based on the total weight of the drilling fluid. The drilling fluid may have a solids content of from 2.5 lb/bbl to 720 lb/bbl, such as from 2.5 to 720 lb/bbl, or 2.5 to 700 lb/bbl. In some embodiments, the drilling fluid may have a solids content of from 5 to 700 lb/bbl, from 50 to 500 lb/bbl, or from 100 to 600 lb/bbl.
Alternatively, in some embodiments, solids may not be needed to stabilize the drilling fluid. Thus, in some embodiments, the drilling fluid may not contain solids, or may not contain more than 2 lbs/bbl, such as less than 1 lb/bbl of solids.
As stated, the addition of solids may be used to control the density of the drilling fluid. In some embodiments, the drilling fluid may have a density of from 50 pounds of mass per cubic foot (pcf) to 160 pcf, as measured using a mud balance in accordance with the American Petroleum Institute (API) recommended practice 13B-2. For instance, the drilling fluid may have a density of from 50 pcf to 150 pcf, from 50 pcf to 140 pcf, from 75 pcf to 160 pcf, from 75 pcf to 150 pcf, from 75 pcf to 140 pcf, from 100 pcf to 160 pcf, from 100 pcf to 150 pcf, or from 100 pcf to 140 pcf. In some embodiments, the drilling fluid may have a density of from 50 pcf to 75 pcf, or from 75 pcf to 100 pcf, or from 120 pcf to 160 pcf. In some embodiments, lower mud weights may be used when drilling depleted formations.
Embodiments of the disclosure further relate to methods of producing a drilling fluid. The produced drilling fluids may be in accordance with any of the embodiments previously described. The method may involve mixing an aqueous phase, an oleaginous phase, and at least one surfactant to produce a mixture and shearing the mixture. The aqueous phase, oleaginous phase, and surfactant may be in accordance with any of the embodiments previously described.
In some embodiments, the mixture may be mixed at a shear speed of from 4000 rotations per minute (RPM) to 16000 RPM. The mixture may be mixed at a shear speed of from 4000 RPM to 15000 RPM, or from 5000 RPM to 15000 RPM, or from 5000 RPM to 1000 RPM, or from 8000 RPM to 16000 RPM, or from 10000 RPM to 16000 RPM, or from 12000 RPM to 16000 RPM. Without being bound by any particular theory, shearing the mixture may disperse the oleaginous phase in the aqueous phase to produce the drilling fluid, which may be emulsified. The amphiphilic nature of the surfactant may stabilize both the oleaginous oil-based phase and the aqueous water-based phase to produce a stabilized emulsified drilling fluid. In some embodiments, the oil to water ratio (OWR) may range from 5:95 to 95:5.
Embodiments of the disclosure may also relate to methods for using the drilling fluid. The drilling fluid may be in accordance with any of the embodiments previously described. In some embodiments, the drilling fluid may be introduced into a subterranean formation. Introducing may involve injecting the drilling fluid into the subterranean formation, which in some embodiments, may be a well. The drilling fluid may be circulated within the subterranean formation. In some embodiments, a mud pump may be used to inject the drilling fluid into the subterranean formation.
In some specific embodiments the disclosure relates to methods of using the drilling fluid for oil and gas drilling. The methods may include pumping the drilling fluid through a drill string to a drill bit and recirculating the drilling fluid. Recirculating the fluid may allow the drilling fluid to cool and lubricate the drill bit and to lift rock cuttings away from the drill bit, carrying the cuttings upwards to the surface to clean the wellbore. The drilling fluid may additionally provide hydrostatic pressure to support the sidewalls of the wellbore and prevent the sidewalls from collapsing onto the drill string.
As previously described, fluid rheology is an important parameter of drilling fluid performance. For critical offshore applications with extreme temperature and pressure requirements, the viscosity profile of the fluid often is measured with a controlled temperature and pressure viscometer (for instance, an iX77 Rheometer, commercially available from Fann Instruments (Houston, Tex.)). Fluids can be tested at temperatures of less than 35° F. to 500° F., with pressures of up to 20,000 pounds per square inch (psi). Cold-fluid rheology may be important because of the low temperatures that the fluid is exposed to in deepwater risers. High temperatures can be encountered in deep wells or in geothermally heated wells. The fluid may be under tremendous pressure downhole, and its viscosity profile can change accordingly. The rheological behavior of the drilling fluid, such as gel strength, plastic viscosity, and yield point, may be determined from measurements of the viscosity, shear stress, and shear rate.
The gel strength of a drilling fluid refers to the shear stress of the drilling fluid measured at a low shear rate following a defined period of time during which the drilling fluid is maintained in a static state. The gel strength may be an indication of how well the drilling fluid would be able to suspend cuttings once the pump is shut down, as well as an indication of barite sag. The drilling fluids of the present disclosure may have a gel strength after 10 seconds of from 1 lbf/100 ft2 to 50 lbf/100 ft2. For instance, the drilling fluids may have a gel strength after 10 seconds of from 1 lbf/100 ft2 to 30 lbf/100 ft2, from 10 lbf/100 ft2 to 30 lbf/100 ft2, from 10 lbf/100 ft2 to 25 lbf/100 ft2, from 15 lbf/100 ft2 to 30 lbf/100 ft2, from 15 lbf/100 ft2 to 50 lbf/100 ft2, from 20 lbf/100 ft2 to 50 lbf/100 ft2, from 15 lbf/100 ft2 to 25 lbf/100 ft2, or from 15 lbf/100 ft2 to 30 lbf/100 ft2.
Similarly, the drilling fluids of the present disclosure may have a gel strength after 10 minutes of from 1 lbf/100 ft2 to 60 lbf/100 ft2. For instance, the drilling fluids may have a gel strength after 10 minutes of from 1 lbf/100 ft2 to 40 lbf/100 ft2, from 10 lbf/100 ft2 to 30 lbf/100 ft2, from 10 lbf/100 ft2 to 50 lbf/100 ft2, from 15 lbf/100 ft2 to 30 lbf/100 ft2, from 15 lbf/100 ft2 to 50 lbf/100 ft2, from 20 lbf/100 ft2 to 50 lbf/100 ft2, from 15 lbf/100 ft2 to 25 lbf/100 ft2, or from 15 lbf/100 ft2 to 30 lbf/100 ft2.
The rheological behavior of the drilling fluid may be determined by measuring the shear stress on the drilling fluid at different shear rates, which may be accomplished by measuring the shear stress and/or shear rate on the drilling fluid. The various shear rates are utilized, as drilling fluid behaves as a rigid body at low stress but flows as a viscous fluid at higher shear stress. The rheology of the drilling fluid may be characterized by the plastic viscosity (PV) in centipoises (cP) and the yield point (YP), which are parameters from the Bingham plastic rheology model. The PV is related to the resistance of the drilling fluid to flow due to mechanical interaction between the solids of the drilling fluid and represents the viscosity of the drilling fluid extrapolated to infinite shear rate. The PV reflects the type and concentration of the solids in the drilling fluid. The PV of a drilling fluid may be estimated by measuring the shear stress of the drilling fluid using the previously described rheometer at spindle speeds of 300 rotations per minute (rpm) and 600 rpm and subtracting the 300 rpm viscosity measurement from the 600 rpm viscosity measurement according to Equation 3:
PV (cP)=(viscosity at 600 rpm)−(viscosity at 300 rpm) Equation 3
The drilling fluids of the present disclosure may have a PV of from 10 cP to 60 cP. For instance, the drilling fluids may have a PV of from 10 cP to 55 cP, from 10 cP to 50 cP, 15 cP to 55 cP, from 15 cP to 50 cP, from 25 cP to 45 cP, from 25 cP to 40 cP, from 30 cP to 60 cP, from 30 cP to 55 cP, from 30 cP to 50 cP, from 30 cP to 45 cP, or from 30 cP to 40 cP. In some embodiments, the drilling may have a PV of from 25 cP to 60 cP or from 30 cP to 55 cP.
The YP represents the shear stress below which the drilling fluid behaves as a rigid body and above which the drilling fluid flows as a viscous fluid. In other words, the YP represents the amount of stress required to move the drilling fluid from a static condition. The YP is expressed as a force per area, such as pounds of force per one hundred square feet (lbf/100 ft2) for example. YP provides an indication of the rock cuttings carrying capacity of the drilling fluid through the annulus, which in simplified terms gives an indication of the drilling fluid's hole-cleaning ability. A drilling fluid having a YP of equal to or greater than 15 lbf/100 ft2 is considered acceptable for drilling. The YP is determined by extrapolating the Bingham plastic rheology model to a shear rate of zero. The YP may be estimated from the PV (as measured n accordance with Equation 3, as previously described) according to Equation 4:
YP=(300 RPM reading)−PV Equation 4
The drilling fluids of the present disclosure may have a YP of from 10 lbf/100 ft2 to 100 lbf/100 ft2. For instance, the drilling fluids may have a YP of from 10 lbf/100 ft2 to 80 lbf/100 ft2, from 10 lbf/100 ft2 to 70 lbf/100 ft2, from 20 lbf/100 ft2 to 80 lbf/100 ft2, from 20 lbf/100 ft2 to 70 lbf/100 ft2, from 30 lbf/100 ft2 to 100 lbf/100 ft2, from 30 lbf/100 ft2 to 80 lbf/100 ft2, from 30 lbf/100 ft2 to 70 lbf/100 ft2, from 35 lbf/100 ft2 to 100 lbf/100 ft2, from 35 lbf/100 ft2 to 80 lbf/100 ft2, or from 35 lbf/100 ft2 to 70 lbf/100 ft2. In one or more embodiments, the drilling fluid may have a YP of from 20 lbf/100 ft2 to 80 lbf/100 ft2 or from 30 lbf/100 ft2 to 70 lbf/100 ft2.
As mentioned, the drilling fluid of the present disclosure may have improved characteristics over conventional drilling fluids, for instance, density, viscosity, solids content, pump-ability and hole-cleaning capability, among other characteristics. These attributes will be demonstrated by the Examples that follow.
To demonstrate the improved rheological properties of the present embodiments, Example 1 was formulated in accordance with the present disclosure by mixing half of a barrel (bbl) of water as the aqueous phase with half a barrel of oil as the oleaginous phase by first taking water in a mud cup. After 5 minutes of shearing at 11000 RPM using a Fann 35 viscometer, a surfactant in accordance with the present embodiments, a natural fatty alcohol ethoxylate with an HLB of 13.4 and a carbon length of 10-16 carbons, was added to the mixture followed by with starch, MgO, and CaCO3. The amount of each additive component is listed in Table 1 in pounds per barrel (lbs/bbl). After another 5 minutes of shearing, xantham gum polymer, referred to as XC polymer, was added to the mixture for a total mix time of about 35 minutes. Without being bound by any particular theory, XC polymer may act as a viscosifier, starch may allow for improved filtration control, MgO may act as a buffer, and CaCO3 may act as a bridging agent.
1Xantham gum polymer, commercially available from Schlumberger (Houston, TX).
Example 1 was tested to determine the viscosity after shearing at various shear speeds using a Fann 35 viscometer. The fluid was sheared until it reached a temperature of 120° F., at which the rheological properties of the fluid were measured. The gel strength of Example 1 was also determined, both after 10 seconds and after 10 minutes to determine both the gelling behavior and progressive gelling behavior of the fluid. Likewise, the plastic viscosity (PV) and yield point (YP) of Example 1 were measured, along with the fluid loss at 220° F.
As shown in Table 2, Example 1 exhibits good rheology in terms of viscosity over a wide range of shear speeds, gel strength, shear strength, plastic viscosity and yield point. Moreover, Example 1 exhibits these improved rheology readings without required additives, or a necessary pH range.
A first aspect of the disclosure is directed to a drilling fluid comprising an aqueous phase; an oleaginous phase; and at least one surfactant comprising the formula: R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms, and x is an integer from 1 and 10.
A second aspect of the disclosure includes the first aspect, where the surfactant has a hydrophilic-lipophilic balance (HLB) of from 8 to 16.
A third aspect of the disclosure includes the first or second aspects, where the drilling fluid comprises from 28 to 630 pounds per barrel (lb/bbl) of the aqueous phase based on the total weight of the drilling fluid.
A fourth aspect of the disclosure includes any of the first through third aspects, where the drilling fluid comprises from 28 to 810 lb/bbl of the oleaginous phase based on the total weight of the drilling fluid.
A fifth aspect of the disclosure includes any of the first through fourth aspects, where the drilling fluid comprises from 0.02 to 180 lb/bbl of the surfactant based on the total weight of the drilling fluid.
A sixth aspect of the disclosure includes any of the first through fifth aspects, where the oleaginous phase comprises one or more components selected from the group consisting of natural oil, synthetic oil, diesel oil, mineral oil, hydrogenanted olefins, unhydrogenated olefins, and combinations thereof.
A seventh aspect of the disclosure includes any of the first through sixth aspects, where the oleaginous phase comprises one or more components selected from the group consisting of poly-alpha olefins, linear olefins, branched olefins, polydiorganosiloxanes, silxoanes, organosiloxanes, esters, ethers, acetals, dialkylcarbonates, hydrocarbons, fatty acids, esters of fatty acids, straight chain, branched or cyclical alkyl ethers of fatty acids, and combinations thereof.
An eighth aspect of the disclosure includes any of the first through seventh aspects, where the drilling fluid contains from 0.02 to 180 lb/bbl of one or more additives selected from the group consisting of weighting agents, fluid loss control agents, lost circulation control agents, other surfactants, antifoaming agents, specialty additives, and combinations thereof.
A ninth aspect of the disclosure includes any of the first through eighth aspects, where R is: an alkyl group comprising 10 to 16 carbons; or an alkenyl group comprising from 10 to 16 carbon atoms.
A tenth aspect of the disclosure includes any of the first through ninth aspects, where x is from 5 to 10.
An eleventh aspect of the disclosure includes any of the first through tenth aspects, where x is from 7 to 9.
A twelfth aspect of the disclosure includes any of the first through eleventh aspects, where R comprises 13 carbons.
A thirteenth aspect of the disclosure includes any of the first through twelfth aspects, where R is an isotridecyl group
A fourteenth aspect of the disclosure includes any of the first through thirteenth aspects, where the surfactant has an HLB of from 12 to 14.
A fifteenth aspect of the disclosure includes any of the first through fourteenth aspects, where the surfactant is a naturally-derived fatty alcohol.
A sixteenth aspect of the disclosure includes any of the first through fourteenth aspects, where the surfactant is a synthetically-derived fatty alcohol.
A seventeenth aspect of the disclosure includes any of the first through sixteenth aspects, where the surfactant comprises ethylene oxide condensate of branched isotridecyl alcohol.
An eighteenth aspect of the disclosure includes any of the first through seventeenth aspects, where the drilling fluid has a gel strength after 10 seconds of from 1 lbf/100 ft2 to 50 lbf/100 ft2.
A nineteenth aspect of the disclosure includes any of the first through eighteenth aspects, where the drilling fluid has a gel strength after 10 minutes of from 1 lbf/100 ft2 to 60 lbf/100 ft2.
A twentieth aspect of the disclosure includes any of the first through nineteenth aspects, where the drilling fluid has a plastic viscosity of from 10 cP to 60 cP.
A twenty-first aspect of the disclosure includes any of the first through twentieth aspects, where the drilling fluid has a yield point of from 10 lbf/100 ft2 to 100 lbf/100 ft2.
A twenty-second aspect of the disclosure is directed to a method of producing a drilling fluid, the method comprising: mixing an aqueous phase, an oleaginous phase, and at least one surfactant comprising the formula: R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms, and x is an integer from 1 and 10, to produce a mixture; and shearing the mixture to form the drilling fluid.
A twenty-third aspect of the disclosure includes the twenty-second aspect, where the surfactant has an HLB of from 8 to 16.
A twenty-fourth aspect of the disclosure is directed to a method of using a drilling fluid, the method comprising: mixing an aqueous phase, an oleaginous phase, and at least one surfactant comprising the formula: R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms, and x is an integer from 1 and 10, to produce a mixture; shearing the mixture to form the drilling fluid; pumping the drilling fluid into a subterranean formation; and circulating the drilling fluid in the subterranean formation.
A twenty-fifth aspect of the disclosure is directed to a method of using a drilling fluid to drill a subterranean formation, the method comprising: mixing an aqueous phase, an oleaginous phase, and at least one surfactant comprising the formula: R—(OC2H4)x—OH, where R is a hydrocarbyl group having from 8 to 20 carbon atoms, and x is an integer from 1 and 10, to produce a mixture; shearing the mixture to form the drilling fluid; pumping the drilling fluid through a drill string in a drill bit located in the subterranean formation; transporting rock cuttings from the drill bit to a surface of the subterranean formation; and circulating the drilling fluid in the subterranean formation.
A twenty-sixth aspect of the disclosure includes the twenty-fourth and twenty-fifth aspects, where the subterranean formation is a well.
A twenty-seventh aspect of the disclosure includes the twenty-fourth to twenty-sixth aspects, where the surfactant has an HLB of from 8 to 16.
A twenty-eighth aspect of the disclosure includes any of the twenty-second to twenty-seventh aspects, where the drilling fluid comprises from 28 to 630 lb/bbl of the aqueous phase based on the total weight of the drilling fluid.
A twenty-ninth aspect of the disclosure includes any of the twenty-second through twenty-eighth aspects, where the drilling fluid comprises from 28 to 810 lb/bbl of the oleaginous phase based on the total weight of the drilling fluid.
A thirtieth aspect of the disclosure includes any of the twenty-second to twenty-ninth aspects, where the drilling fluid comprises from 0.02 to 180 lb/bbl of the surfactant based on the total weight of the drilling fluid.
A thirty-first aspect of the disclosure includes any of the twenty-second through thirtieth aspects, where the oleaginous phase comprises one or more components selected from the group consisting of natural oil, synthetic oil, diesel oil, mineral oil, hydrogenanted olefins, unhydrogenated olefins, and combinations thereof.
A thirty-second aspect of the disclosure includes any of the twenty-second through thirty-first aspects, where the oleaginous phase comprises one or more components selected from the group consisting of poly-alpha olefins, linear olefins, branched olefins, polydiorganosiloxanes, silxoanes, organosiloxanes, esters, ethers, acetals, dialkylcarbonates, hydrocarbons, fatty acids, esters of fatty acids, straight chain, branched or cyclical alkyl ethers of fatty acids, and combinations thereof.
A thirty-third aspect of the disclosure includes any of the twenty-second through thirty-second aspects, where the drilling fluid contains from 0.02 to 180 lb/bbl of one or more additives selected from the group consisting of weighting agents, fluid loss control agents, lost circulation control agents, other surfactants, antifoaming agents, specialty additives, and combinations of these.
A thirty-fourth aspect of the disclosure includes any of the twenty-second through thirty-third aspects, where R is: an alkyl comprising from 10 to 16 carbon atoms; or an alkenyl group comprising from 10 to 16 carbon atoms.
A thirty-fifth aspect of the disclosure includes any of the twenty-second through thirty-fourth aspects, where x is from 5 to 10.
A thirty-sixth aspect of the disclosure includes any of the twenty-second through thirty-fifth aspects, where x is from 7 to 9.
A thirty-seventh aspect of the disclosure includes any of the twenty-second through thirty-sixth aspects, where R comprises 13 carbons.
A thirty-eighth aspect of the disclosure includes any of the twenty-second through thirty-seventh aspects, where R is an isotridecyl group (C13H27).
A thirty-ninth aspect of the disclosure includes any of the twenty-second through thirty-eighth aspects, where the surfactant has an HLB of from 12 to 14.
A fortieth aspect of the disclosure includes any of the twenty-second through thirty-ninth aspects, where the surfactant is a naturally-derived fatty alcohol.
A forty-first aspect of the disclosure includes any of the twenty-second through thirty-ninth aspects, where the surfactant is a synthetically-derived fatty alcohol.
A forty-second aspect of the disclosure includes any of the twenty-second through forty-first aspects, where the surfactant comprises ethylene oxide condensate of branched isotridecyl alcohol.
A forty-third aspect of the disclosure includes any of the twenty-second through forty-second aspects, where the drilling fluid has a gel strength after 10 seconds of from 1 lbf/100 ft2 to 50 lbf/100 ft2.
A forty-fourth aspect of the disclosure includes any of the twenty-second through forty-third aspects, where the drilling fluid has a gel strength after 10 minutes of from 1 lbf/100 ft2 to 60 lbf/100 ft2.
A forty-fifth aspect of the disclosure includes any of the twenty-second through forty-fourth aspects, where the drilling fluid has a plastic viscosity of from 10 cP to 60 cP.
A forty-sixth aspect of the disclosure includes any of the twenty-second through forty-fifth aspects, where the drilling fluid has a yield point of from 10 lbf/100 ft2 to 100 lbf/100 ft2.
The following description of the embodiments is exemplary and illustrative in nature and is in no way intended to be limiting it its application or use. As used throughout this disclosure, the singular forms “a,” “an” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a” component includes aspects having two or more such components, unless the context clearly indicates otherwise.
It should be apparent to those skilled in the art that various modifications and variations may be made to the embodiments described within without departing from the spirit and scope of the claimed subject matter. Thus, it is intended that the specification cover the modifications and variations of the various embodiments described within provided such modification and variations come within the scope of the appended claims and their equivalents.
It is noted that one or more of the following claims utilize the term “where” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.”
Having described the subject matter of the present disclosure in detail and by reference to specific embodiments of any of these, it is noted that the various details disclosed within should not be taken to imply that these details relate to elements that are essential components of the various embodiments described within, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Further, it should be apparent that modifications and variations are possible without departing from the scope of the present disclosure, including, but not limited to, embodiments defined in the appended claims. More specifically, although some aspects of the present disclosure are identified as particularly advantageous, it is contemplated that the present disclosure is not necessarily limited to these aspects.
This application is a continuation of U.S. Non-Provisional application Ser. No. 15/496,764 filed Apr. 25, 2017, which claims priority to U.S. Provisional Patent Application Ser. No. 62/454,189 filed Feb. 3, 2017, and U.S. Provisional Patent Application Ser. No. 62/454,192 filed Feb. 3, 2017, all of which are incorporated by reference herein in their entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62454189 | Feb 2017 | US | |
| 62454192 | Feb 2017 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 15496794 | Apr 2017 | US |
| Child | 17016997 | US |
