Sepiolite containing drilling fluid compositions and methods of using the same

Abstract

A drilling mud containing sepiolite and potassium carbonate and which is free of potassium chloride is useful in high temperature reservoirs, such as geothermal wells.

Description

SEPIOLITE CONTAINING DRILLING FLUID COMPOSITIONS AND METHODS OF USING THE SAMESPECIFICATIONBackground

[0001] The past fifty years has seen an increase in interest in the recovery of geothermal energy from hard rock formations such as granite, grandodiorite, quartzite, greywacke, basalt, rhyolite and volcanic tuff which, typically, are 3,000 to 5,000 meters below the earth’s surface. During drilling of a geothermal well, heat is extracted from the rock formation and taken up by a drilling fluid or mud circulating through a pipeline.

[0002] A geothermal energy production site normally consists of a hole drilled into the earth to a depth at which the temperature of the surrounding rock formation is sufficient to heat the drilling mud which lubricates the drill bit and extracts cuttings from the borehole. Pipelines for geothermal systems are generally optimized for closed circulation of the fluid, commonly by a pipe in a pipe system having a vertical element running from the surface of the earth to a suitable depth in the formation. The drilling mud is typically pumped down to the end of the outer portion the pipe where it is redirected to the inner portion of the pipe. A horizontal pipe element is then run roughly horizontally to a sufficient length to ensure heating of the fluid pumped through it. Heat is taken up by the mud circulating through the pipeline.

[0003] Geothermal systems operate at elevated temperatures above 500°F and often operate at supercritical temperatures at or above 750 °F. In order to operate at such supercritical temperatures, at least some of the drilling at the vertical element and the horizontal element of the pipe must be undertaken through rock formations at supercritical temperatures.

[0004] The supercritical temperature needed for geothermal drilling along with the hardness of the rock (typically 240+ MPa compressive strength) aggravates drilling of geothermal formations. While conventional drilling fluids or muds are incompatible in the recovery of geothermal energy, a multitude of drilling fluids have been identified for potential use. Generally, such fluids omit material additives from established petroleum drilling fluids used in the recovery of energy closer to the earth’s surface. However, such efforts have largely been unsuccessful due to thermal decomposition of the fluids.

[0005] Alternative drilling fluids suitable for use at the supercritical temperatures of geothermal reservoirs are therefore desired.Drawings

[0006] FIG. 1 shows the rheological profile of a fluid containing sepiolite and graphene nanospheres after being aged for 18 hours at 520 °F.

[0007] FIG. 2 shows the rheological profile of a fluid containing sepiolite and graphene nanospheres after being aged for 86 hours at 520 °F.

[0008] FIG. 3 illustrates percentile changes in viscosity while aging a fluid containing sepiolite and graphene from 18 to 86 hours at 520 °F.

[0009] FIG. 4 illustrates preservation of viscosity values at ascending temperatures from 120 °F. to 482 °F and descending temperatures from 482 °F to 120 °F. after a fluid containing sepiolite and graphene nanospheres has been aged 18 hours at 520° F.

[0010] FIG. 5 illustrates preservation of viscosity values at ascending temperatures from 120 °F. to 482 °F. and descending temperatures from 482 °F. to 120 °F. after a fluid containing sepiolite and graphene nanospheres has been aged 86 hours at 520° F.Detailed Description

[0011] Certain terms are used herein and in the appended claims to refer to particular components. As one skilled in the art will appreciate, different persons may refer to a component by different names. This document does not intend to distinguish between components that differ in name but not function.

[0012] Also, the terms "including" and "comprising" and variants thereof are used herein and in the appended claims in an open-ended fashion, and thus should be interpreted to mean "including, but not limited to . . .."

[0013] The suffix "(s)" as used herein is intended to include both the singular and the plural of the term that it modifies, thereby including at least one of that term. Reference herein and in the appended claims to components and aspects in a singular tense does notnecessarily limit the present disclosure or appended claims to only one such component or aspect, but should be interpreted generally to mean one or more, as may be suitable and desirable in each particular instance. The use of the terms "a" and "an" and "the" and similar variants in the context of describing the embodiments (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context.

[0014] All ranges disclosed herein are inclusive of the endpoints. A numerical range having a lower endpoint and an upper endpoint shall further encompass any number and any range falling within the lower endpoint and the upper endpoint. For example, every range of values in the form “from a to b” or “from about a to about b” or “from about a to b” and any similar expressions, where “a” and “b” represent numerical values of degree or measurement is to be understood to set forth every number and range encompassed within the broader range of values and inclusive of the endpoints.

[0015] The fluid disclosed herein is referred to as a drilling fluid. However, it should be understood that the term drilling fluid is synonymous with wellbore fluid and is not intended to limit the application of this fluid from other downhole applications, such as a completion fluid, packer fluid, fracturing fluid, or thermal transfer enhancement fluid.

[0016] The aqueous-based drilling fluid disclosed herein can contain sepiolite. The amount of sepiolite in the drilling fluid is that sufficient to prevent or control gelation ofthe fluid under conditions experienced in the high temperature drilling or other operations of the well. In an embodiment, the amount of sepiolite in the drilling fluid may be between from about 4 to about 15 Ib / bbl, between from about 5 to about 10 Ib / bbl, or at an amount in such range, such asy around 7 Ib / bbl. As used herein, the unit of barrel (bbl.) is equivalent to 42 gallons.

[0017] The Brunauer-Emmett-Teller (BET) surface area of the sepiolite may be between from about 280 to about 360 m2 / g. In an embodiment, the sepiolite may be treated. For instance, the sepiolite may be treated with quaternary alkyl-ammonium salts as well as acid and thermal treated sepiolite including those modified with alkylammonium cations such as octylammonium, hexadecylammonium, tetradecyltrimethylammonium and hexadecyltrimethylammonium. However, untreated sepiolites are preferred.

[0018] The aqueous-based drilling fluid may contain graphene. The amount of graphene can change depending upon the application and use of the drilling fluid. As an example, the amount of graphene in the fluid could range from about 3.5 to about 24 Ib / bbl, from about 4 to about 20 Ib / bbl, or any amount within such ranges.; The bulk density of the graphene may be from about 0.01 to about 0.5 g / cc (more typically between from about 0.02 to about 0.3 g / cc) and the surface area (BET) of the graphene may be from about 110 to about 140 m2 / g. Typically, the concentration of the sepiolite in the drilling fluid is greater than the concentration of graphene.

[0019] The density of the fluid can be greater than 8 pounds per gallon and may be between from about 8 to about 12 pounds per gallon (lb / gal.). Tn an embodiment, the density of the fluid is about 9 pounds per gallon (lb / gal).

[0020] In an embodiment, the drilling fluid may further contain a surfactant or surfaceactive agent as a wetting agent for the solids. In an embodiment, the wetting agent is a nonionic surfactant, such as alkoxylated surfactants like ethoxylated nonionic surfactants. As an example, the wetting agent may be a non-ionic surfactant of formulaRO — (-AO — )a— H, where R designates an alkyl group having 2 to 12 carbon atoms, and AO designates an oxyethylene or oxypropylene group (in a ratio between the number of oxyethylene:oxypropylene groups of between 1 :2 and 5:6) with “a” being between 7 and 16. In an embodiment, the hydrophilic-lipophilic balance (HLB) of the wetting agent may be greater than 8.0, greater than 10.0, or even greater than 12.0. If present, the amount of surfactant wetting agent in the drilling fluid could range from about 0.2 to about 0.75 pounds per barrel, or from about 0.25 to about 0.35 pounds per barrel.

[0021] The drilling fluid can be used as a fluid in wells having a range of temperatures, such as temperatures lower than a geothermal well. For example, the drilling fluid may be used in traditional petroleum oil and gas wells like those having a bottomhole temperature from 150 °F. to 450 °F. Advantageously, the drilling fluid can also be used at significantly higher temperatures, such as those common in the treatment of geothermal wells, generallyhaving internal temperatures from 500 °F. to over 1200 °F. In one or more embodiments, the drilling fluid is used at supercritical temperatures at or above 750 °F.

[0022] The pH of the drilling fluid may be alkaline. In one or more embodiments, the pH of the drilling fluid generally is higher than an aqueous-based drilling mud containing potassium chloride. Typically, the pH of the drilling fluid is from about 4.0, from about 7.5, to about 12.5, or can be any value between thereto such as about 9.5 to about 12.0. In addition to providing the requisite alkalinity for the rheological profile of the drilling fluid, the alkaline conditions of the drilling mud are also instrumental in minimizing corrosion within the reservoir. Further, the alkaline condition of the drilling fluid allows for appreciable buffering of formation-sourced acid gases.

[0023] The graphene may be synthetic or natural in origin. The graphene is typically characterized by lamellae platelets. For example, the platelets can exhibit a lamella thickness index (LTI) between from about 2 to about 30, or between from about 6 to about 10. The LTI may be calculated by dividing the surface area of the graphene by the surface area of single-layered graphene. In one or more embodiments, the graphene particles may be in the form of about 2 to about 30 graphene layers bound in a lamellar fashion.

[0024] The graphene may be synthetically prepared using various known techniques, for example by chemical vapor deposition. In another embodiment, the graphene may be a graphene prepared by an exfoliation process (chemical or mechanical) of natural graphiticsources synthetic or mined from the earth. In one or more embodiments, the graphene is unmodified (not subjected to surface chemistry modifications other than those naturally imparted by the basic preparation processes like exfoliation). However, a person having ordinary skill in the art will appreciate that other graphene materials industrially classified by the general term of graphene or graphitic nanoplatelet (GNP) can be utilized within the spirit of the disclosure.

[0025] The particle size of the graphene can vary depending on the use parameters and / or the type of graphene used. In an embodiment, the graphene is between from about 0.3 to about 4 microns, or may be within that range from about 0.5 to about 1 micron. As an example, the bulk density of the graphene is between from about 0.1 to 1 g / cc, or can be within that range, such as from about 0.2 to about 0.3 g / cc.

[0026] The drilling fluid can contain a brine that may include a salt and water. In one or more embodiments, the drilling fluid contains a potassium salt, such as potassium carbonate or potassium hydroxide. An aqueous brine containing a potassium salt may be referred to as a potassium brine. The amount of brine or salt in the fluid is that required to impart the requisite viscosity to the drilling mud and inhibit rearrangement of the sepiolite structure from its favorable fibrous state at temperatures. In the absence of potassium, rearrangement of the sepiolite structure is likely to occur at well temperatures in excess of 500 °F. and especially when the well is characterized by supercritical temperatures. In anembodiment, the potassium brine has a specific gravity greater than 1, such as from about1 .0 to about 2.0, or within that range, such as from about 1 .1 to about 1 .5

[0027] Since chloride ions can cause premature or excessive gelation of the fluid at low shear rates, the fluid may be preferably free of chloride ions. Premature or excessive gelation of the drilling fluid causes wellbore instability due to high surge and swab pressures. Further, the presence of chloride in the drilling fluid can render the fluid unable to chemically neutralize the naturally occurring acid gases often encountered while geothermal drilling, including hydrogen sulfide and carbon dioxide. Since effective removal of drilled cuttings from the geothermal reservoir are negatively impacted by the presence of chloride anions in the drilling fluid, the potassium salt is preferably free or essentially free of chloride ions, ft should be understood that a fluid free or essentially free of chloride ions can mean that there could still be trace amounts of chloride ions, such as those already present in the water source used in the fluid, contamination, or trace amounts in a fluid additive. Chloride ion concentrations up to 250ppm, 500ppm, lOOOppm, or even 2000 ppm would be considered chloride ion free. Along with improving the rheological properties of known drilling fluids, the lack of chlorides, such as potassium chloride, in the drilling fluid renders the fluid more compatible with the environment as disposal of the drilling fluid is free of high levels of potentially hazardous chloride ions.

[0028] In an embodiment, the drilling fluid may contain carbonate salt, such as potassium carbonate, as a buffering base. The carbonate salt can be soluble in the drilling fluids. The presence of the soluble carbonate buffer does not adversely affect the performance of the drilling fluid. This is especially important in those situations where the drilling fluid is to be used as in traditional oil and gas wells and, in those cases, the performance of the drilling fluid provides unexpected results and is counter-intuitive as to what may be expected. In gas wells, for instance, carbonates are known to form when carbon dioxide (a common constituted in natural gas and present in most formations) dissolves in water to form carbonic acid. The carbonic acid in turn lowers the pH of the fluid which causes hydroxyl ions in the drilling fluid to revert to bicarbonates and carbonate ions. Carbonate contamination is thus known to adversely affect traditional drilling fluids, especially those containing bentonite, by elevating the gel strength of the drilling fluid and thus compromise the performance of the drilling fluid. When used, however, in the drilling fluids of the present disclosure, the addition of potassium carbonate does not adversely affect gel strength. The drilling fluid disclosed herein is highly stable at elevated downhole conditions due, in part, to high alkalinity and its unusual tolerance for carbonate contamination.

[0029] The amount of soluble carbonate salt in the fluid should be sufficient to effectively enable neutralization by the buffering base carbonate anion of naturallyoccurring acid gases, such as hydrogen sulfide and carbon dioxide, which are often encountered in the geothermal reservoir during the drilling process. Such gases, if not neutralized, potentially result in the corrosion of downhole equipment, including drill string hardware and tool joints.

[0030] The drilling fluid further may contain an insoluble calcium carbonate. For example, the drilling fluid may contain a calcium carbonate having a particle size distribution, D50, between 0.5 and 15 microns, or having a size therebetween, such as around 10 microns. In one or more embodiments, the amount of insoluble calcium carbonate in the drilling fluid is between from about 70 to 110 pounds per barrel. The specific gravity of the insoluble calcium carbonate can be between from about 2.5 to about 3.0.

[0031] The rheological properties and shear thinning of the drilling fluid enables cuttings to be lifted from the hole and further enables the drilling mud to overcome the dangers of irreversible gel formation resulting from the drilling fluid remaining uncirculated in the hole for extended periods. The drilling fluid may be circulated under shear and has particular applicability in the drilling of geothermal wells having a bottomhole temperature from about 500 °F to about 1200 °F. Aqueous wellbore fluids often lose their rheological properties when operated at high temperatures. At high temperatures, their shear stress levels will either drop extremely low or increase extremelyhigh, rendering the fluid either too thin or too thick to function as a suitable wellbore fluid.High temperature shear stress performance of a drilling fluid may be evaluated by measuring shear stress of a drilling fluid after aging the drilling fluid at high temperature. Shear stress (dyn / cm2) is typically measured by loading the fluid into a rheometer, such as a Grace Model M5600 or Fann 35 rheometer, and shearing the fluid at different shear rates, such as 3 rotations per minutes (rpm), 6 rpm, 30 rpm, 60 rpm, 100 rpm, 200 rpm, 300 rpm, 600 rpm, etc. Instead of rpm, these shear rates are often given in their equivalency, by multiplying by 1.703 conversion factor, in the unit reciprocal seconds (sec1). For example, 1021 sec1is equivalent to 600 rpm and 580 sec1is equivalent to 300 rpm. The fluid temperature at which the shear stress is measured may be held constant as the shear rates is changed. Often the same series of shear rates are tested at range of different temperatures. The fluid may be aged by placing the fluid in nitrogen pressurized aging cell, such as a Parr® Series 4740 Pressure Vessel or Fann® 802P HT Aging Cell, at a set temperature for a set amount of time. The fluid may also be dynamically aged by rolling the sample using an aging cell with rolling capability, such as a Rigchina® Model RCRO-4 roller oven, at set temperature and pressure for a given amount of time.

[0032] The shear stress performance level of the drilling fluid when exposed to elevated temperatures has been observed not to substantially vary with the aging of the drilling fluid at a given shear rate. In some embodiments, the drilling fluid has a shearstress of 90 dyn / cm2to 300 dyn / cm2measured at a shear rate of 1021 sec'1at 120°F after aging at 520° F for at least 72 hours. In other embodiments, the drilling fluid’s shear stress at the same measurement conditions, can be 90 dyn / cm2to 250 dyn / cm2, 90 dyn / cm2to 175 dyn / cm2, or 90 dyn / cm2to 140 dyn / cm2. In some embodiments, the percent change in the aged drilling fluid is no greater than 10% and in other cases the percent change is no greater than 5%. As illustrated in FIGs. 1 and 2, shear stress performance of drilling fluids at a defined shear rate aged at 520° F for 86 hours is negligible compared to the same drilling fluid when aged for 18 hours. In some instances, the difference is negligible (for instance, at a shear rate of 1025 sec1); the difference is less than 10% (for instance, at a shear rate of 580 sec'1).

[0033] In an embodiment, the drilling fluid may be prepared by adding sepiolite clay to a potassium brine and then treating the brine with a surfactant wetting agent. The graphene may then be added to the brine. When present, ground calcium carbonate or buffering salt may then be added to the brine.

[0034] Examples

[0035] The following examples are illustrative of some of the embodiments of the disclosure. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the description set forth herein. It is intendedthat the specification, together with the examples, be considered exemplary only, with the scope and spirit of the disclosure being indicated by the claims which follow.

[0036] All percentages set forth in the Examples are given in terms of weight units except as may otherwise be indicated.

[0037] Example 1. A fluid was prepared over 15 minutes total shearing time on a Silverson mixer at a speed of 8,000 rpm. Sepiolite was added to a 14 wt. percent potassium carbonate brine having a specific gravity of 1.13 and the mixture sheared for approximately 5 minutes. To the brine was then added insoluble calcium carbonate having a particle size distribution, D50, of 10 microns, commercially available as TrueCarb 10 from Newpark Drilling Fluids LLC as well as an ethoxylated ester non-ionic surfactant as wetting agent. An exfoliated graphene nanoplatelet without surface modification, commercially available as GrapheneBlack™ from NanoXplore, was then added. The graphene had a bulk density between 0.2 and 0.3 g / cc, a particle size distribution, D50, between 0.5 and 1 microns and a Lamellar Thickness Index between 6 and 10 The mixture was then sheared for 5 additional minutes. Table I summarizes the aqueous fluid having a density of 10.9 Ib / gallon and specific gravity of 1.31.Table I

[0038] The fluid was transferred to an aging cell and pressurized to 500 psi with nitrogen gas. The fluid in the aging cell was aged for a given amount of time at 520° F. Afterward, the fluid was loaded into a rheometer. Performance of the fluid was then evaluated by aging the fluid at 520° F for 72 hours in an aging cell pressurized with 500 psi of nitrogen gas pressure, after which the sample was cooled and an aliquot was removed, suitable in volume for analysis in the rheometer. Another sample of the fluid was also aged at 706°F for 96 hours in a Parr Instrument Company Series 4740 High Pressure High Temperature Vessel with 75mL Moveable head vessel and a Vessel M WP Rating of 7900 psi at up to 538 °C . Rheology testing was then conducted on a Fann 35 rheometer maintained at 120° F, the rheometer having a R1B1 rotor and bob assembly while the fluid was sheared at various speeds at 120° F. The plastic viscosity (PV) and yield point (YP) were determined in accordance with testing procedures outlined in API Recommended Practice 13 -Bl Third Edition, December 2003. The results are set forth in Table II:Table II

[0039] The data in Table II represents the shear stress Fann dial reading of the Fann 35 and may be converted to dyn / cm2by multiplying the dial reading by 5.11. For example, a Fann dial reading of 33.2, measured at 600 rpm (102l ‘s) after 72 hours aging at 520°F, converts to 169 dyn / cm2.

[0040] Example 2, A drilling fluid was prepared over 15 minutes total shearing time on a Silverson mixer at a speed of 8,000 rpm. To a potassium carbonate brine (specific gravity of 1.13) was added sepiolite clay having a surface area (BET) of 320 m2 / g (commercially available as Pangel S9 from Tolsa Group). The mixture was sheared for 5 minutes. A nonionic surfactant, commercially available as Tomadol 900 from Evonik Operations GmbH, was added to the mixture followed by the addition of graphene nanospheres having a bulk density of 0.025 g / cc and a surface area (BET) between 110 and 140 m2 / g (commercially available as NCN from Nabors New Energy Transition Solutions). The mixture was then sheared for 5 minutes. The fluid was then treated TrueCarb 10 and sheared for a final 5 minutes. Table III summarizes the aqueous fluid having a density of10.73 Ib / gal:Table III

[0041] The fluid was transferred to an aging cell and pressurized to 500 psi with nitrogen gas. The fluid in the aging cell was dynamically aged by rolling for a given amount of time at 520°F. Afterward, the fluid was loaded into a Grace Model M5600 rheometer and viscosity was measured over the temperature range of 120°F to approximately 485°F (the upper temperature limit being determined by the capability of the instrument).

[0042] Performance of the fluid was then evaluated by aging the fluid at 520°F for 18 hours in a Rigchina® Model RCRO-4 Roller Oven, a dynamic aging cell, pressurized with 500 psi of nitrogen gas pressure, after which the sample was cooled and an aliquot was removed, suitable in volume for analysis in the viscometer. The rheology data for the aliquot is shown in FIG. 1, measured at 123°F, 202°F, 301°F, 399°F, and 482°F. The remaining fluid sample was further aged at 520°F for a total aging time of 86 hours. FIG. 2 depicts the viscometer readings at the same temperatures.

[0043] The changes in rheological properties over time is noted by comparing FIGs. 1 and 2. The shear stress values at a given temperature over time indicates high preservationof shear stress value at higher shear rates, along with favorable improvements in flow property curves at the lower shear rates, improving with the longer aging time in the oven at 520°F. As demonstrated in FIGs. 1 and 2, the percent change in shear stress at a shear rate of approximately 1021 sec-1of the fluid at 520 °F aged for 18 hours compared to the same drilling fluid sample aged to 86 hours is substantially zero, the shear stress being approximately 44 dyn / cm2Thus, desirable drilling fluid properties are preserved and improved with extended time at temperature.

[0044] The percent changes in viscosity while aging the fluid sample from 18 to 86 hours at the various shear rates ranging from 5.1 sec1to 1021.4 secT is illustrated in FIG.3. FIGs. 4 and 5 plot viscosity vs. temperature of the drilling fluid sample where the drilling fluid was analyzed at ascending temperatures from 120° F to 482° F and descending temperatures from 482° F to 120° F. Fig.4 is for the drilling fluid sample aged for 18 hours. Fig.5 is for the drilling fluid sample aged for 86 hours. The figures illustrate the influence of shear and temperature upon the recovery of viscosity throughout the testing cycle and illustrate favorable shear stress values are preserved at each temperature of testing as shear rate is varied. This is indicative of the preservation of low shear rate fluid flow properties (the shear stress values) useful in the suspension and transport of solids in the drilling fluid. In addition, reductions in the shear stresses at high shear rates favors a lower consumption of energy to pump the fluids at high velocities and the ability to incorporate largerquantities of solids into the drilling fluids with minimal impact upon the overall rheological properties of the drilling fluids.

Claims

CLAIMSWhat is claimed is:

1. An aqueous-based drilling fluid comprising:(a) sepiolite;(b) graphene; and(c) a potassium brine, comprising water.

2. The aqueous-based drilling fluid of claim 1, wherein the graphene constitutes nanoplatelets having a lamella thickness index (LTI) from about 2 to about 30.

3. The aqueous-based drilling fluid of claim 1, wherein the potassium of the brine is potassium carbonate or potassium hydroxide.

4. The aqueous-based drilling fluid of claim 1 , wherein the specific gravity of the potassium brine is from about 1.0 to about 2.0.

5. The aqueous-based drilling fluid of claim 1, further comprising calcium carbonate.

6. The aqueous-based drilling fluid of claim 1, wherein the drilling fluid has a shear stress of 90 to 250 (dyn / cm2) measured at a shear rate of 1021 sec'1at 120°F after aging at 520° F for at least 72 hours.

7. The aqueous-based drilling fluid of claim 1, wherein the drilling fluid exhibits a percent change of less than 10% for shear stress measured at a shear rate of 1021 sec'1at 120°F when aged for 86 hours at 520° F for 86 hours from the drilling fluid aged 18 hours at the same conditions.

8. The aqueous-based drilling fluid of claim 1, wherein at least one of the following is true:(a) the density of the fluid is from about 8 to about 12 pounds per gallon;(b) the specific gravity of the potassium brine is greater than 1 ;(c) the fluid further comprises a surfactant wetting agent;(d) the graphene is exfoliated graphene without surface modification;(e) the fluid further comprises a soluble carbonate salt; or(f) the concentration of the sepiolite is greater than the concentration of graphene.

9. An aqueous-based drilling fluid comprising:(a) sepiolite;(b) graphene having a lamella thickness index (LTI) of from about 2 to about 30;(c) a potassium brine comprising water; and(d) insoluble calcium carbonate.

10. The aqueous-based drilling fluid of claim 9, wherein at least one of the following is true:(a) the graphene constitutes nanoplatelets having a lamella thickness index (LTI) from about 2 to about 30;(b) the fluid further comprises a soluble carbonate salt of calcium carbonate or potassium carbonate;(c) the potassium brine comprises potassium hydroxide;(d) the specific gravity of the brine is greater than 1 ;(e) the density of the fluid is from about 8 to about 12 pounds per gallon;(f) the concentration of the sepiolite is greater than the concentration of graphene;(g) the aqueous-based drilling fluid further comprises a surfactant wetting agent;(h) the D50 of the insoluble calcium carbonate is 10 microns;(i) the aqueous fluid further comprises a non-ionic wetting agent;(j) the graphene is exfoliated graphene without surface modification;(k) the brine is a potassium carbonate brine having a specific gravity greater than 1; and(l) the graphene comprises nanoplatelets.

11. A method comprising: forming an aqueous-based drilling fluid by: adding sepiolite clay to a brine; treating the brine with a surfactant wetting agent; and adding graphene; and shearing the drill fluid.

12. The method of claim 11, further comprising treating the drilling fluid with ground calcium carbonate.

13. The method of claim 11, wherein at least one of the following is true:(a) the drilling fluid further comprises ground calcium carbonate having a D50 of 10 microns;(b) the drilling fluid further comprises a nonionic surfactant as wetting agent surfactant; and(c) the brine is a potassium carbonate brine having a specific gravity greater than1.

14. The method of claim 11 , wherein the graphene comprises nanoplatelets.

15. The method of claim 11 , further comprising pumping the drilling fluid into a well having a temperature of over 500 °F.

16. The method of claim 11 , wherein the drilling fluid has a shear stress of 90 to 250 (dyn / cm2) measured at a shear rate of 1021 sec1at 120°F after 520° F when aged for at least 72 hours.

17. A method of drilling a geothermal well having a downhole temperature over 500 °F comprising:(a) pumping into the well an aqueous-based drilling fluid comprising:(i) sepiolite;(ii) graphene;(iii) potassium brine, comprising water; and(b) circulating the fluid in the well.

18. The method of claim 17, wherein the temperature in the geothermal well is from about 500 °F to about 1200 °F.

19. The method of claim 17, wherein the temperature in the geothermal well is greater than 700 °F.

20. The method of claim 17 wherein the drilling fluid further comprises insoluble calcium carbonate with a D50 of 10.

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