Starch-based additives for MONO-valent and di-valent brines, water-based fluid formulations comprising said additives, and methods of drilling and / or treating wells with said formulations

Abstract

A pumpable water-based mud includes at least one base brine that is a mono-valent base brine or a di-valent base brine; at least one modified and / or derivatized starch-based additive; at least one or more secondary viscosifiers / pH buffer; and wherein the mono-valent base brine or di-valent base brine has a density of at least about 8.4 lb / gal up to about 18.0 lb / gal and is free of biopolymers or a biopolymer component; wherein the derivatized starch-base additive does not require heating to enhance yield of the derivatized starch-base in the mono-valent base brine or di-valent base brine. Related methods of treating a well with pumpable water-based muds are also disclosed.

Description

STARCH-BASED ADDITIVES FOR MONO-VALENT AND DI-VALENT BRINES, WATER-BASED FLUID FORMULATIONS COMPRISING SAID ADDITIVES, AND METHODS OF DRILLING AND / OR TREATING WELLS WITH SAID FORMULATIONSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This patent application claims priority benefit of United States Provisional Patent Application Serial Numbers 63 / 665,054, filed 27 June 2024, which is entirely incorporated herein by reference.FIELD

[0002] The present disclosure relates to one or more starch-based additives (hereinafter “starch additive” or “starch additives”) and one or more water-based fluid or mud formulations (hereinafter “WBM” or “WBMs”) comprising the present starch additives for drilling and / or treating wells with the WBMs. The present starch additives and / or WBMs may control and optimize viscosity and fluid loss associated with the WBMs and improve well stability of the wells. Additionally, the present disclosure relates to improved methods of controlling and optimizing the WBM fluid losses and well stabilities by drilling and / or treating the wells with the WBMs comprising the present starch additives. The present starch additives, WBMs, and methods disclosed herein may be suitable for drilling and / or treating one or more zones of the wells with WBMs.BACKGROUND

[0003] Known water-based mud systems (hereinafter “mud system” or “mud systems”) are traditionally used for drilling and treating one or more zones of wells. For example, specifically-designed mud systems may be utilized for drilling reservoir zones of the wells and are typically referred to as drill-in fluid systems. Often, these drill-in fluid systems are di-valent brine-based mud systems, such as, for example, DIPRO (commercially available from M-l L.L.C, located in Houston, TX), which is also a biopolymer-free mud system and usable as a reservoir drill-in fluid (hereinafter “RDF” or “RDFs”). It is also known that this biopolymer-free mud system requires pre-heating the di-valent base brine to yield starchalong with a purified MgO-based additive to crosslink calcium ions disposed within the divalent base brine. However, use of traditional starches and brine viscosifiers in this biopolymer-free mud system does not provide the ideal RDF at low brine densities. Moreover, these traditional starches and brine viscosifiers are not optimal in RDFs comprising mono-valent base brines, since yield properties are not consistent or heat is required for the product to yield. The starch additives disclosed herein do not require additional biopolymer(s) and yield improved and consistent viscosities in both monovalent and di-valent brines. Furthermore, the starch additives disclosed herein do not require brine heating or pre-heating to yield viscosities, which not only provides a better sustainable starch option for RDFs but also provides a solution to operational challenges associated with low density brines such as monovalent brine-based and di-valent brinebased RDFs. Additionally, the divalent systems disclosed herein eliminates the need to heat the brine to get the product to yield, thus lowering the CF for the ultimate application of the product at a mixing plant. Monovalent systems applications less product is added because the system eliminates the need of xanthan which yields viscosity.SUMMARY

[0004] 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.

[0005] In some embodiments, a pumpable water-based mud including: at least one base brine that is a mono-valent base brine or a di-valent base brine; at least one modified and / or derivatized starch-based additive; at least one or more secondary viscosifiers / pH buffer; and wherein the mono-valent base brine or di-valent base brine has a density of at least about 8.4 Ib / gal up to about 18.0 Ib / gal and is free of biopolymers or a biopolymer component; wherein the derivatized starch-base additive does not require heating to enhance yield of the derivatized starch-base in the mono-valent base brine or di-valent base brine.

[0006] In some embodiments, a method of drilling or treating a well with a water-based drilling mud, the method including pumping the water-based mud of claim 1 into at least one zone of the well either during or following a water-based wellbore operation.

[0007] In some embodiments a method of treating a well, the method including: mixing at least one base brine that is a mono-valent base brine or a di-valent base brine, at least one modified and / or derivatized starch-based additive, at least one viscosity enhancing additive, and at least one bridging agent together to form water-based mud, wherein the di-valent base brine has a divalent brine density of at least about 8.4 Ib / gal up to about 18.0 Ib / gal and is free of biopolymers or a biopolymer component; wherein the derivatized starch-base additive does not require heating to enhance yield of the derivatized starch- base in the mono-valent base brine or di-valent base brine and pumping the water-based mud into at least one zone of the well either during or following a water-based fluid wellbore operation.DETAILED DESCRIPTION

[0008] Illustrative examples of the subject matter claimed below will now be disclosed. In the interest of clarity, not all features of an actual implementation are described in this specification. It will be appreciated that in the development of any such actual implementation, numerous implementation-specific decisions may be made to achieve the developers’ specific goals, such as compliance with system -related and business- related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort, even if complex and time-consuming, would be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

[0009] Further, as used herein, the article “a” is intended to have its ordinary meaning in the patent arts, namely “one or more.” Herein, the term “about” when applied to a value generally means within the tolerance range of the equipment used to produce the value, or in some examples, means plus or minus 10%, or plus or minus 5%, or plus or minus 1 %, unless otherwise expressly specified. Further, herein the term “substantially” as used herein means a majority, or almost all, or all, or an amount with a range of about 51 % toabout 100%, for example. Moreover, examples herein are intended to be illustrative only and are presented for discussion purposes and not by way of limitation.

[0010] Where a numerical limit or range is stated, the endpoints are or may be included. Also, all values and subranges within a numerical limit or range are specifically included as if explicitly written out.

[0011] As used herein, the phrases “selected from the group consisting of,” “chosen from,” and the like include mixtures of the specified materials. Terms such as “contains”, and the like are meant to include “including at least” unless otherwise specifically noted.

[0012] The methods and water based mud disclosed herein may be utilized in a variety of subterranean operations that involve subterranean drilling, drilling-in (without displacement of the fluid for completion operations) and fracturing. In some embodiments, the water base mud formulation disclosed herein may be used to control leak-off of completion brine after perforating and before gravel packing or frac-packing. The water base mud may also be used in an additional or alternate embodiment to isolate the completion and wellbore fluid after gravel packing by spotting the water base mud inside the screen device. In an embodiment, the bridging agents of the water base mud comprises calcium carbonate such that the calcium carbonate block the openings in the screen device, the pores of the formation, the fractures in the wellbore or the formation, or a combination thereof. Further, the filter cake may degrade after temporarily sealing for fluid loss during the treatment and / or drilling operation and / or may help restore permeability and conductivity for reservoir fluid production. In an alternative or additional embodiment, the entire filter cake need not be entirely soluble following degradation; it may be sufficient only that enough degradation occurs so as to allow the residue of the degraded or partially degraded filter cake to be lifted off of the sealed surface by a low backflow pressure from produced reservoir fluids.

[0013] In one or more embodiments, the starch additives disclosed herein may be, comprise, or consist of one or more natural starches, one or more natural starches that have been chemically modified or modified by at least one chemical reaction, one or more modified starches, one or more derivatized starches, or a combination thereof. In some embodiments, the starch additives disclosed herein may be, comprise, or consist of one or more modified and / or derivatized starches, such as, for example, one or more pre-gelatinized starches, one or more hydroxyethyl starches, one or more carboxymethyl starches, one or more anionic starches, one or more cationic starches, or a combination thereof. In at least one embodiment, the one or more modified starches may be, comprise, or consist of one or more hydroxypropyl starches, one or more carboxymethyl starches, one or more pre-gelatinized starches, one or more crosslinked starches, one or more oxidized starches, or a combination thereof. In an embodiment, the one or more natural starches may be derived from at least one natural product, such as, for example, corn, wheat, oats, rice, and / or potato (including but not limited to tapioca, plantain, pea, and cassava). In some embodiments, the starch additives disclosed herein may comprise or consist of one or more non-ionic polymers, at least one linear polymer, at least one branched polymer, or a combination thereof. In at least one embodiment, the starch additives disclosed herein may have thermal stability up to about 280 °F or less.

[0014] The starch additives disclosed herein may be included or incorporated into, mixed or disposed within, or utilized as at least one component of one or more waterbased mud or fluid formulations (hereinafter “the fluid formulation” or “the fluid formulations”). The fluid formulations comprising the starch additives disclosed herein may be suitable and / or usable for drilling and / or treating at least one borehole, wellbore, and / or well (collectively referred to hereinafter as “the well”) that may be or may have been drilled with at least one water-based drilling fluids and / or water-based drilling mud (collectively referred to hereinafter as “water-based mud” or “water-based muds”). Additionally, the well may be, for example, at least one oil well, at least one gas well, at least one geothermal well, at least one steam-injection well, or one or more similar wells. In some embodiments, the present starch additives and / or water-based muds may separately control and optimize viscosity and fluid loss associated with the water-based muds. In some embodiments, the fluid formulations disclosed herein may be, comprise, or consist of the water-based mud used to drill the well. In other embodiments, the waterbased mud used to drill the well may include, comprise, or consist of the fluid formulation and / or the starch additive disclosed herein. The present disclosure should not be deemed as limited to a specific embodiment or type of well that was or is drilled with the fluid formulation or the water-based mud.

[0015] Besides comprising the present starch additives, the fluid formulations disclosed herein may further comprise at least one base fluid or brine (hereinafter “the brine”) which may be a mono-valent base brine, a di-valent base brine, or a combination thereof. Additionally, the fluid formulations may be biopolymer-free water-based fluid or mud or may be free of any or all biopolymer (i.e. , polymer produced by or from a strain of bacteria) and synthetically I genetically modified polymers. In an embodiment, the biopolymer excluded from the fluid formulations may be a polysaccharide biopolymer, such as, for example, XC polymer or xanthan gum. In some embodiments, the fluid formulations may be, comprise, or consist of one or more di-valent brine-based, biopolymer-free water-based fluids or muds. For example, the fluid formulations may be, comprise, or consist of DIPRO (commercially available from M-l L.L.C, located in Houston, TX), which is a biopolymer-free, divalent brine-based fluid formulation having a density or mud weight of about 8.4 pounds per gallon (hereinafter “ppg”) or more and / or about 18.0 ppg or less.

[0016] In one or more embodiments, the fluid formulations and / or the water-based muds disclosed herein may be, comprise, or consist of at least one wellbore fluid and / or at least one drilling fluid (collectively referred to hereinafter as “the at least one drilling fluid”) and / or may have a major liquid phase comprising the brine, water and / or saltwater, or a combination thereof. The fluid formulations and / or the water-based muds disclosed herein may comprise at least one selected from freshwater, seawater, lime, potassium, silicate, or a combination thereof. In some embodiments, the fluid formulations and / or the water-based muds disclosed herein may contain, include, comprise, or consist of the brine and the brine may be, comprise, or consist of, for example, seawater, aqueous base fluids, or solutions wherein the salt concentration is less than that of sea water, or aqueous fluids or 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, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, phosphates, silicates, fluorides, or a combination thereof. Salts that may be incorporated into given brines include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, the brine that may be used in the fluid formulations and / or the water-based muds disclosed herein may be mono-valent or divalent, natural orsynthetic, with synthetic brines tending to be much simpler in composition. Brines may include, but are not limited to, brines including water and one or more salts (e.g., one or more organic salts and / or one or more inorganic salts). One of ordinary skill in the art would appreciate that the above salts may be present in the fluid formulations and / or the water-based muds or may be added according to methods known in the art. Further, the amount of the aqueous-based continuous phase should be sufficient to form the fluid formulations and / or the water-based muds. This amount may range from nearly about 100% to less than about 30 % of the fluid formulations and / or the water-based muds by volume.

[0017] In some embodiments, the fluid formulations and / or the water-based muds disclosed herein may be a high-performance water-based mud comprising one or more inhibition agents as inhibitor of reactive shale swelling. Prevention of shale swelling is key to the water-based mud performance because wellbore integrity depends on inhibitive properties of WBM. Additionally, prevention of shale swelling and consequent reduction in shale dispersion reduces costs associate with the wellbore drilling processes by reducing the volumes of dilution needed to maintain acceptable viscosities for the fluid formulations and / or the water-based muds. In some embodiments, the pH values of the fluid formulations and / or the water-based formulations may encompass the range of 4.0 to 12 pH.

[0018] In at least one embodiment, the fluid formulations and / or the water-based muds comprising the starch additives disclosed herein may have thermal stability up to about 280 °F or less.

[0019] In yet another embodiment, the fluid formulations and / or the water-based muds disclosed herein may be used alone or in combination with one or more conventional or additional additives. The additional additives, that may further be included in the present fluid formulations and / or water-based muds, may include, but not limited to, for example, additional viscosifiers, fluid loss control agents, shale inhibitors, lubricants, corrosion inhibitors, surfactants, dispersants, interfacial tension reducers, pH buffers, additional thinners, or at least one mixture thereof. Inclusion of such additional additives in the present fluid formulations and / or water-based muds should be well known to one ofordinary skill in the art of formulating water-based wellbore fluids, fluid formulations, or water-based muds.

[0020] In some embodiments, the starch additive may be one or more modified and / or derivatized starches, the brine may comprise a mono-valent or di-valent base brine, primary viscosifiers may be at least one branched-chain starch derivate that also controls filtrate loss. Additionally, the one or more secondary viscosifiers / pH buffer may comprise fine-particle, highly reactive magnesium compound. Further, the at least one bridging agent may comprise sized particles such as, for example, sized calcium carbonate and / or a sized salt, such as, for example, NaCI solid particles. In at least one embodiment, the calcium carbonate (or any bridging material) may comprise sized calcium carbonate particles having a broad range of median particle sizes (dso) between 2 microns to 500 microns, depending on required bridging of pore throats on permeable formation or micro fracture downhole.

[0021] In some embodiments, the fluid formulations, the water-based muds, and / or fluid formation components disclosed herein may be mixed on site for use, or may be provided in pre-mixed blends of solid materials to which the brine, water, and / or other liquid components may be added prior to pumping, introducing, and / or disposing the fluid formulations and / or water-based muds into the well. After the fluid formulation components are mixed together with a sufficient amount or volume of the brine and optional water, the fluid formulations and / or water-based muds are pumpable and may be pumped, disposed, or introduced into the well and allowed to move to at least one zone of the one or more zones of the well. The fluid formulation components may be added to the brine and optional water on location at a well-site of the well where it is to be used, or may carried out at other locations than the well-site of the well. If the well-site location is selected for carrying out this mixing / formulating step, the fluid formulation components may be dispersed into the brine and optional water and sufficiently mixed together to form the fluid formulations or water-based muds, and the formed fluid formulations or waterbased muds may be emplaced, disposed, and / or circulated in the well or the at least one zone of the well using one or more techniques known in the art. In some embodiments, the fluid formulations disclosed herein may have a density or mud weight of about 18 ppg or less.

[0022] In one or more embodiments, optional water utilized in the fluid formulations and / or water-based muds disclosed herein may be fresh water such as, for example, tap water, low mineral water, salt-free water, or native production waters. In some embodiments, other water, such as, for example, the brine or salt water may be optionally used or used in combination with the fresh water. Further, the fluid formulations disclosed herein may have a brine and / or water content of about 95 % by volume or less.

[0023] In one or more embodiments, the fluid formulation components may comprise one or more optional additives which may be dependent upon the wellbore operation to be accomplished with or achieved by the fluid formulation. In some embodiments, the fluid formulation or water-based mud may be a brine fluid, a drilling fluid, a completion fluid, a drill-in fluid, a RDF, a workover and intervention fluid, a cementing fluid, an enhanced oil recovery fluids, a spacer fluid, a well testing and sampling fluids, a drilling additives and specialty fluids, a wellbore cleanup fluids, or a combination thereof. Additionally, the optional additives disclosed herein may comprise one or more chemicals, one or more polymers, one or more clays, one or more viscosifiers, one or more suspension agents, one or more dispersing agents, one or more antifoam agents, one or more surfactants, one or more retarders, one or more expansion agents, one or more weighting agents, one or more fluid loss control agents, one or more shale inhibitors, one or more corrosion inhibitors, one or more lubricants, one or more emulsifiers, one or more foamers, or a combination thereof.

[0024] In at least one embodiment, the fluid formulations and / or the water-based muds disclosed herein may be used in or suitable one or more wellbore operations and / or methods which may include drilling at least one wellbore (i.e. , the well) into subterranean formations in a manner similar to those wherein conventional water-based wellbore fluids are used. The present fluid formulations and / or water-based muds may be circulated through the drill pipe, through the bit, and up the annular space between the pipe and the formation or the metal casing to the surface. The fluid formulations and / or the water-based muds disclosed herein may perform several different functions during the wellbore operations and / or drilling methods, such as, for example, cooling the bit, removing drilled cuttings from the bottom of the hole, suspending, coating, and / or encapsulating thecuttings, coating walls of the wellbore, and / or weighting the material within the wellbore when circulation is interrupted.

[0025] In one or more embodiments, the methods disclosed herein may comprise mixing the fluid formulation components and the brine and optional water together to form the fluid formulations disclosed herein, wherein the formed fluid formulations are pumpable water-based mud slurries. The methods disclosed herein may comprise pumping the formed fluid formulations or pumpable water-based mud slurries (collectively referred to hereinafter as “the pumped formulations and slurries”) into the well and / or allowing the pumped formulations or slurries to set for an amount of time for treating the well. In some embodiments, the methods disclosed herein may comprise drilling the wells with the WBMs prior to treating the wells with the pumped formulations and slurries. For example, the pumped formulations and slurries may have been pumped, disposed, or introduced into the well following a water-based wellbore operation or water-based drilling operation. Further, the methods disclosed herein may comprise one or more of the fluid formulation components prior to mixing with the water to form the pumpable formulations and slurries.

[0026] In some embodiments, the methods disclosed drill and / or treat the well or at least one zone of the well with the fluid formulations, water-based muds, and / or fluid formulation components disclosed herein. The starch additives disclosed herein do not require the fluid formulations or water-based muds to contain an additional biopolymer and provide and achieve improved and synergistic viscosities when utilized with both mono-valent and di-valent base brines. Additionally, the present starch additives do not require brine heating or pre-heating to provide and achieve the improved synergistic viscosities. Moreover, the present starch additives provide and achieve stable fluid formulations and water-based muds that reduce or prevent fluid loss of the fluid formulations and water-based muds into the formations of the wells.

[0027] In some embodiments, the drilling fluids may be used during formation of a borehole and / or wellbore to be used for carbon capture, utilization, and storage (CCUS) and / or for recovery and use of geothermal energy. Geothermal energy is a promising source of renewable energy that captures energy from heat generated within the earth. For example, geothermal energy may be used to heat structures (e.g., buildings) and / orto generate electricity (e.g., by heating water to generate steam and drive a turbine with the steam). The drilling fluids described herein may be used to form boreholes and / or wellbores used to circulate a fluid that is heated within the earth formation through which the borehole and / or wellbore extends. The heated fluid may be circulated to the surface where the captured heat may be recovered to heat a structure and / or generate electricity, followed by recirculation of the fluid to the earth formation to continue the cycle.CCUS facilitates the capture, use, and / or storage of carbon (e.g., carbon dioxide), which has a goal of achieving carbon neutrality and / or net zero carbon emissions (NZE). CCUS may facilitate the capture of carbon dioxide from large point sources (e.g., power plants, refineries, cement plants, other industrial processing plants, or other industrial facilities that use fossil fuels, biomass fuels, or other fuels that generate carbon dioxide). The captured carbon dioxide may be converted into valuable products such as, for example, ethanol, sustainable aviation fuel, chemicals, and mineral aggregates. Alternatively, the carbon dioxide may be stored in geologic formations, such as in depleted hydrocarbon reservoirs. The carbon dioxide may be introduced into the earth formation through a borehole and / or wellbore formed using the drilling fluids described herein. In the earth formation, the carbon dioxide may be dispersed in an aqueous phase and stored as carbon dioxide, in mineral form (e.g., as a carbonate, such as calcium carbonate, magnesium carbonate, iron(ll) carbonate), or as another form of carbon.Experiments / Examples

[0028] Example 0 - Comparative yield of known branched starch derivative and inventive starch derivative in divalent brine, with no heat to base brine applied. Example 0 shows how the starch can yield better in divalent brines without the need to pre-heat the brine. (See Table 1 )Measured rheology at 75F - Comparative yield of 10 Ib / bbl known starch derivative B vs Inventive derivative starch in divalent brines, no heat applied13.0 ppg CaBr2Brine w / 3ppb pH9.5ppg CaCI2Brine w / 3ppb pH bufferKnown Starch New inventive Derv Known Starch New inventive Derv B Starch Derv B Derv Starch600RPM 29 37 72 93300RPM1 8 22 46 58200RPM14 1 7 35 46100RPM9 12 22 316RPM 2 5 3 83RPM 1 5 2 6PV 11 15 26 35YP 7 7 20 2310" Gel 2 6 2 610' Gel2 1 0 2 8Table 1

[0029] Example 1 - Comparative Formulations and Inventive Fluid Formulations 1 (monovalent brine) and 2, 3 (divalent brine). Example 1 shows how the starch can yield viscosity in monovalent brine and offers both viscosity and fluid loss control. (See Tables 2 - 10).Formulation 1 - 10.3 Ib / gal Monovalent Brine-Based Formulation, 1 bblConventional Monovalent Inventive StarchMud Monovalent MudWater, lb 300.1 300.1NaCI dry, lb 70.4 70.4Known branched polymer, lb 1.0Known branched starch A, lb 7.0Inventive Starch Derv., lb — 10.0 pH Buffer, lb 1.0 3.0Calcium Carbonate Blend, lb 50.0 50.0Table 2Table 3Table 4 F Rheology Conventional Inventive StarchMonovalent Mud Monovalent MudInitial Aged Initial AgedDynamic Aged @ °F 220 220600 rpm 52 51 44 45300 rpm 38 38 31 31200 rpm 32 33 26 25100 rpm 24 26 18 186 rpm 10 11 7 63 rpm 9 9 6 510 sec / 10 min 10 / 12 10 / 11 7 / 11 6 / 7PV 14 13 13 14YP 24 25 18 17 pH 10.2 9.5 10.2 10.130 min HTHP @ 2206.0 5.0 through a discTable 5Formulation 2 - 9.7 Ib / gal Divalent Brine-Based Formulation, 1 bblConventional Divalent Brine- Inventive Starch DivalentBased Mud Brine-Based MudWater, lb 341.9 341.9CaCl2 dry, lb 22.6 22.6Known branched starch B, lb 12.0Secondary known starch C, lb 1.25Inventive Starch Derv., lb 12.0 pH Buffer, lb 3.0 3.0Secondary pH Buffer, lb 0.5Calcium Carbonate Blend, lb 50.0 50.0Table 6120F Rheology Conventional Divalent Mud Inventive Starch Divalent MudInitial Rolled Initial RolledHR @ °F 190 190600 rpm 51 50 54 55300 rpm 34 37 39 39200 rpm 29 33 33 32100 rpm 22 26 26 256 rpm 11 12 13 123 rpm 10 11 12 1110sec / 10min 10 / 14 14 / 17 13 / 22 12 / 16PV 25 25 15 16YP 17 13 24 23 pH — 10.15 10.0 9.430 min HTHP @ 220F, 5.4 3.5 through a discTable 7Formulation 3, Divalent Brine-Based Mud, 11.0 Inventive DervIb / gal Mud Starch117.2Freshwater, ppb296.811 .6 CaCl2 Brine, ppb10.0Inventive Derv Starch, ppb3.0 pH Buffer, ppb38.0Calcium Carbonate Blend, ppbTable 8Mud Dynamically Aged 16 hr at 215FRheology @120°F Initial Aged600 rpm 90 86300 rpm 63 60200 rpm 51 49100 rpm 36 356 rpm 10 113 rpm 8 810 sec. gel 9 810 min. gel 10 9PV, cP 27 26YP, lb / 100sqft 36 34pH 9.2 8.9Table 9HTHP Fluid Loss at 215F throughTime discSpurt (30 sec), mL 1.830 min, mL 5.060 min, mL 6.64-hr, mL 11.5Table 10

[0030] Example 2 - Static Thermal Stability for Inventive Fluid Formulation 1 (monovalent brine).10.3 Ib / gal Inventive Starch Formulation 1 bblMudWater, lb 300.1NaCI dry, lb 70.4Inventive Starch Derv., lb 10.0 pH Buffer, lb 3.0Calcium Carbonate Blend, lb 50.0Table 11

[0031] Shows the inventive fluid formulation as a monovalent brine-based, biopolymer- free water-based mud or RDF, wherein the density or mud weight of the inventive fluidformulation is 10.3 ppg. After static heat aging for three-days at 220 °F, the delta, the density or mud weight of the inventive fluid formulation, was about 0.19 ppg, which indicates stable fluid. After static heat aging for six-days at 220 °F, the delta, density or mud weight of the inventive fluid formulation, was about 0.23 ppg, which confirms the previous stable fluid observation. (See Table 11 ).

[0032] Example 3 - Breaker Assessment for Inventive Fluid Formulations 4 (monovalent brine) and 5 (divalent brine). Example 3 shows starch yields with no heat applied, good rheology, and fluid loss. (See Tables 12 - 21 ).Formulation 4, Monovalent Brine- Reference Mud Inventive StarchBased Mud, 9.2 Ib / gal Mud DervWater 324.0 324.0KCI dry, lb 22.52 22.52Shale inhibitor, lb 3.5 3.5Primary known starch B, lb 12.0Inventive Derv Starch, lb — 12.0Secondary known starch C, lb 3.0Secondary pH Buffer, lb 5.0 pH Buffer, lb 2.0 2.0Calcium Carbonate Blend, lb 30.0 30.0Table 12

[0033] Shows the inventive fluid formulation as a monovalent brine, biopolymer-free water-based mud, wherein the density or mud weight of the inventive fluid formulation is9.2 ppg. The properties associated with this inventive fluid formulation are shown below in Tables 11 - 19:120F Rheology Reference Mud Inventive Starch Derv MudInitial Aged Initial AgedDynamic Aged @ °F 85 85600 rpm 52 36 45 52300 rpm 43 26 32 37200 rpm 39 21 26 30100 rpm 34 18 19 226 rpm18g7 73 rpm 17 8 6 6PV 34 10 13 15YP 16 16 19 2210 sec Gel 15 8 7 710 min Gel 29 12 10 8 pH 9.9 9.7 10.7 10.7Table 13HTHP @85F, 300 psi , Reference Mud Inventive Derv Starch through a disc MudSpurt 1.8 01 min 05 min 07.5 min 0.115 min 0.825 min 1.430 min 4.9 1.81 hr 7.0 3.316 hr 21.2 16.3Table 14Breaker Formulation 1 bblFreshwater, ppb 56.5 vol %Chellant 40.0 vol%Enzyme 3.5 vol%Table 15Parameter Reference Mud Inventive Derv Starch Mud% Return to ProductionFlow 94% 99%Initial Breaker pH 8.0 4.5Final Breaker pH 9.4 5.4Soak time @ 85F 14 days 14 DaysTable 16

[0034] Formulation 5 - Viscosity Breakage TestFormulation 5, Divalent Brine- Inventive Starch Derv Based Mud, 11 Ib / gal MudWater 298.0CaCI2dry, lb 94.9Inventive Derv Starch, lb 8.5 pH Buffer, lb 1.5Calcium Carbonate Blend, lb 60.0Table 17120F Rheology Inventive Starch Derv MudInitial AgedDynamic Aged @ °F 150 150600 rpm 73 89300 rpm 49 62200 rpm 40 51100 rpm 28 376 rpmg 123 rpm 7 10PV 24 27YP 25 3510 sec Gel 7 10W min Gel 11 12 pH 8.34 8.1Table 18HTHP @150F, 500 psi, Inventive Derv Starch through a disc Mud, mlSpurt 2.01 min 2.54 min 3,o9 min 3.430 min 4.42 hr 7.84 hr 8.3Table 1915% HCI Breaker Formulation 1 bbl11 .9 Ib / gal Brine 59.8 vol %HCI 39.0 vol%Corrosion Inhibitor 1 .0 vol%Table 20Parameter Inventive Derv Starch Mud% Return to ProductionFlow 100%Soak time @ 150F 4 hrTable 21

[0035] Example 4 - Inventive Fluid Formulation 6, includes an internal breaker and shale inhibitor. Example shows 2 formulations of 11 ppg divalent (CaCI2) formulations using the inventive derivative starch (one with internal breaker & one without). Data shows comparable properties and stabilities (viscosities & fluid loss). (See Tables 22 - 24).Formulation 6, Divalent Inventive Starch Derv Inventive Starch Derv Brine-Based Mud, 11 Ib / galMudWater 137.6 140.211.6 Ib / gal CaCI2, lb 246.0 244.4Inventive Derv Starch, lb 8.5 8.5 pH Buffer, lb 1.5 1.5Shale Inhibitor, vol% 2.0 2.0Internal Breaker, lb 1.0Calcium Carbonate Blend, lb 60.0 60.0Table 22120F Rheology Inventive Starch Derv Mud Inventive Starch Derv MudInternal Breaker No Internal BreakerInitial Aged Initial AgedDynamic Aged @ °F 150 150 150 150600 rpm 51 53 50 54300 rpm 34 37 33 38200 rpm 28 30 27 30100 rpm 20 22 19 226 rpm 6 86 83 rpm 5 7 5 7PV 17 16 17 18YP 17 21 16 1610 sec Gel 6 7 6 710 min Gel 9 9 8 9 pH 8.4 8.6 8.3 8.8Table 23HTHP @150F, 500 Inventive Derv Starch Mud Inventive Derv Starch Mud - psi, through a disc - Internal Breaker, ml No Internal Breaker, mlSpurt 1.4 1.430 min 4.6 4.51 hr 6.0 6.04 hr 10.2 10.3Table 24

[0036] Example 5 - Inventive Fluid Formulation 7 at 265 °FInventive StarchMonovalent MudWater, lb 300.1NaCI dry, lb 70.4Inventive Starch Derv., lb 10.0 pH Buffer, lb 3.0Thermal extender, lb 4.0Calcium Carbonate Blend, lb 50.0Table 25

[0037] This inventive fluid formulation is a monovalent brine-based, biopolymer-free water-based mud, wherein the density or mud weight of the inventive fluid formulation is 10.3 ppg. The properties associated with Inventive Fluid Formulation 7 are shown in Tables 25 and 26.120F Rheology Inventive Starch Derv MudInitial AgedDynamic Aged @ °F 265600 rpm 38 39300 rpm 29 29200 rpm 24 23100 rpm 19 196 rpm1 1 83 rpm 10 8PV 9 10YP 20 1910 sec Gel 13 1010 min Gel 22 10 pH - 10.51Table 26

[0038] Example 6: Gravel pack application using ZnBr? brine (divalent) with inventive starch derivative. Example shows yield in ZnBr2 of ISD at low pHs (5.3). (See Tables 27 and 28).Formulation, 1 bbl Load, Lb19.2 ppg ZnBr Brine 184.75Water, 146.3Inventive starch Derv 9.0CaCl2 dry 23.8CaBr2 dry 176.04 pH Buffer 4.0Thermal extender 4.0Table 27120F Rheology New Starch InventiveRoom T Initial 24 hr 48 hr600 rpm 260 261 265300 rpm 179 180 182200 rpm 146 148 148100 rpm 108 108 1086 rPm43 43 423 rpm 37 36 36PV 81 81 83YP 98 99 99LSYP 31 29 30 pH 5.3 5.3 5.3Table 28

[0039] The foregoing description, for purposes of explanation, used specific nomenclature to provide a thorough understanding of the disclosure. However, it will be apparent to one skilled in the art that the specific details are not required in order to practice the systems and methods described herein. The foregoing descriptions of specific examples are presented for purposes of illustration and description. They are not intended to be exhaustive of or to limit this disclosure to the precise forms described. Obviously, many modifications and variations are possible in view of the above teachings. The examples are shown and described in order to best explain the principles of this disclosure and practical applications, to thereby enable others skilled in the art to best utilize this disclosure and various examples with various modifications as are suited to the particular use contemplated. It is intended that the scope of this disclosure be defined by the claims and their equivalents below

Claims

CLAIMSWhat is claimed is:1 . A pumpable water-based mud comprising: at least one base brine that is a mono-valent base brine or a di-valent base brine; at least one modified and / or derivatized starch-based additive; at least one or more secondary viscosifiers / pH buffer; wherein the mono-valent base brine or di-valent base brine has a density of at least about 8.4 Ib / gal up to about 18.0 Ib / gal and is free of biopolymers or a biopolymer component; and wherein the derivatized starch-base additive does not require heating to enhance yield of the derivatized starch-base in the mono-valent base brine or di-valent base brine.

2. The water-based mud of claim 1 , wherein the water-based mud comprises optionally at least one bridging agent.

3. The water-based mud of claim 2, wherein the at least one bridging agent comprises sized particles having a median particle size (dso) of 2 microns to 500 microns.

4. The water-based mud of claim 3, wherein the sized particles comprise calcium carbonate particles.

5. The water-based mud of claim 1 , wherein the at least one or more secondary viscosifiers / pH buffer comprises at least one reactive magnesium compound.

6. The water-based mud of claim 1 , wherein a pH of the water-based mud is at least in the range of 4.0-12.0.

7. The water-based mud of claim 1 , wherein the water-based mud comprises optionally additives comprising additional viscosifiers, fluid loss control agents, shale inhibitors, lubricants, corrosion inhibitors, surfactants, dispersants, interfacial tension reducers, pH buffers, additional thinners, or at least one mixture thereof.

8. The water-based mud of claim 1 , further comprising: internal filtercake breaker materials9. The water-based mud of claim 1 , further comprising: a thermal or temperature stabilizing additive wherein the thermal or temperature stabilizing additive comprises amines, glycols, anti-oxidants or a combination thereof.

10. The water-based mud of claim 1 , wherein the derivatized starch-base additive is a fluid loss control additive.11 . The water-based mud of claim 1 , wherein the derivatized starch-base additive is a viscosifier.

12. A method of drilling or treating a well with a water-based drilling mud, the method comprising: pumping the water-based mud of claim 1 into at least one zone of the well either during or following a water-based wellbore operation.

13. The method of claim 12, further comprising: forming a filtercake at the at least one zone of the well wherein the filtercake comprises starch and bridging agent particles.

14. The method of claim 12, further comprising: drilling the at least one zone of the well with the water-based drilling mud before pumping the water-based mud into the at least one zone.

15. A method of treating a well, the method comprising: mixing at least one base brine that is a mono-valent base brine or a di-valent base brine, at least one modified and / or derivatized starch-based additive, at least one viscosity enhancing additive, and at least one bridging agent together to formwater-based mud, wherein the di-valent base brine has a divalent brine density of at least about 8.4 Ib / gal up to about 18.0 Ib / gal and is free of biopolymers or a biopolymer component; wherein the derivatized starch-base additive does not require heating to enhance yield of the derivatized starch-base in the mono-valent base brine or di-valent base brine and pumping the water-based mud into at least one zone of the well either during or following a water-based fluid wellbore operation.

16. The method of claim 15, wherein the derivatized starch-base additive comprises an additional viscosifier.

17. The method of claim 15, wherein the derivatized starch-base additive is a fluid loss control additive.

18. The method of claim 15, wherein the derivatized starch-base additive is a viscosifier.

19. The method of claim 15, wherein the water-based mud comprises optionally at least one bridging agent.

20. The method of claim 15, wherein the water-based mud comprises optionally additives comprising additional viscosifiers, fluid loss control agents, shale inhibitors, lubricants, corrosion inhibitors, surfactants, dispersants, interfacial tension reducers, pH buffers, additional thinners, a thermal or temperature stabilizing additive or at least one mixture thereof.

21. The method of claim 15, wherein the method comprises completion applications comprising gravel pack, screen running fluids, and / or pills.

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