CA2768162A1 - Non-toxic, shale inhibitive water-based wellbore fluid - Google Patents
Non-toxic, shale inhibitive water-based wellbore fluid Download PDFInfo
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Abstract
A wellbore fluid may include an aqueous base fluid; a natural amine having at least one amine group and at least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50%
decrease in light output, or the natural amine or biopolymer trigger hormesis.
decrease in light output, or the natural amine or biopolymer trigger hormesis.
Description
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 NON-TOXIC, SHALE INHIBITIVE WATER-BASED WELLBORE FLUID
BACKGROUND OF INVENTION
Field of the Invention [00011 Embodiments disclosed herein relate generally to shale hydration inhibition agents for use in water-based wellbore fluid. In particular, embodiments disclosed herein relate to natural amine shale hydration inhibition agents in wellbore fluids and their use in wellbore operations.
Background Art [00021 To facilitate the drilling of a well, fluid is circulated through the drill string, out the bit and upward in an annular area between the drill string and the wall of the borehole. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
[00031 Drilling fluids are typically classified according to their base material. The selection of the type of drilling fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the drilling fluids in the particular application and the type of well to be drilled. In oil-based fluids, solid particles are suspended in oil (the continuous phase), and water or brine may be emulsified with the oil. In water-based fluids, solid particles are suspended in water or brine (continuous phase) including solid particles such as 1) clays and organic colloids added to provide necessary viscosity and filtration properties; 2) heavy minerals whose function is to PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 increase the drilling fluid's density; and 3) formation solids that become dispersed in the drilling fluid during the drilling operation. Historically, water based drilling fluids have been used to drill a majority of wells. Their lower cost and better environment acceptance as compared to oil based drilling fluids continue to make them the first option in drilling operations. However, as mentioned above, the selection of a fluid frequently may depend on the type of formation through which the well is being drilled. Where the formation solids are clay minerals that swell, the presence of either type of formation solids in the drilling fluid can greatly increase drilling time and costs.
[0004] The types of subterranean formations, intersected by a well, which may be at least partly composed of clays, including shales, mudstones, siltstones, and claystones. In penetrating through such formations, many problems may be encountered including bit balling, swelling or sloughing of the wellbore, stuck pipe, and dispersion of drill cuttings.
This may be particularly true when drilling with a water-based fluid due to the high reactivity of clay in an aqueous environment.
[0005] Clay minerals are generally crystalline in nature. The structure of a clay's crystals determines its properties. Typically, clays have a flaky, mica-type structure.
Clay flakes are made up of a number of crystal platelets stacked face-to-face. Each platelet is called a unit layer, and the surfaces of the unit layer are called basal surfaces. Each unit layer is composed of multiple sheets, which may include octahedral sheets and tetrahedral sheets.
Octahedral sheets are composed of either aluminum or magnesium atoms octahedrally coordinated with the oxygen atoms of hydroxyls, whereas tetrahedral sheets consist of silicon atoms tetrahedrally coordinated with oxygen atoms.
[0006] Sheets within a unit layer link together by sharing oxygen atoms. When this linking occurs between one octahedral and one tetrahedral sheet, one basal surface consists of exposed oxygen atoms while the other basal surface has exposed hydroxyls. It is also quite common for two tetrahedral sheets to bond with one octahedral sheet by sharing oxygen atoms. The resulting structure, known as the Hoffman structure, has an octahedral sheet that is sandwiched between the two tetrahedral sheets. As a result, both basal surfaces in a Hoffman structure are composed of exposed oxygen atoms.
The unit PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 layers stack together face-to-face and are held in place by weak attractive forces. The distance between corresponding planes in adjacent unit layers is called the d-spacing. A
clay crystal structure with a unit layer consisting of three sheets typically has a d-spacing of about 9.5x10"7 mm.
[0007] In clay mineral crystals, atoms having different valences commonly will be positioned within the sheets of the structure to create a negative potential at the crystal surface, which causes cations to be adsorbed thereto. These adsorbed cations are called exchangeable cations because they may chemically trade places with other cations when the clay crystal is suspended in water. In addition, ions may also be adsorbed on the clay crystal edges and exchange with other ions in the water.
[0008] The type of substitutions occurring within the clay crystal structure and the exchangeable cations adsorbed on the crystal surface greatly affect clay swelling, a property of primary importance in the drilling fluid industry. Clay swelling is a phenomenon in which water molecules surround a clay crystal structure and position themselves to increase the structure's d-spacing thus resulting in an increase in volume.
Two types of swelling may occur: surface hydration and osmotic swelling.
[0009] Surface hydration is one type of swelling in which water molecules are adsorbed on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen atoms exposed on the crystal surfaces. Subsequent layers of water molecules align to form a quasi-crystalline structure between unit layers, which results in an increased d-spacing. Virtually all types of clays swell in this manner.
[00101 Osmotic swelling is a second type of swelling. Where the concentration of cations between unit layers in a clay mineral is higher than the cation concentration in the surrounding water, water is osmotically drawn between the unit layers and the d-spacing is increased. Osmotic swelling results in larger overall volume increases than surface hydration. However, only certain clays, like sodium montmorillonite, swell in this manner.
[0011] Exchangeable cations found in clay minerals are reported to have a significant impact on the amount of swelling that takes place. The exchangeable cations compete PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 with water molecules for the available reactive sites in the clay structure.
Generally cations with high valences are more strongly adsorbed than ones with low valences.
Thus, clays with low valence exchangeable cations will swell more than clays whose exchangeable cations have high valences.
[0012] Clay swelling during the drilling of a subterranean well can have a tremendous adverse impact on drilling operations. The overall increase in bulk volume accompanying clay swelling impedes removal of cuttings from beneath the drill bit, increases friction between the drill string and the sides of the borehole, and inhibits formation of the thin filter cake that seals formations. Clay swelling can also create other drilling problems such as loss of circulation or stuck pipe that slow drilling and increase drilling costs. Thus, given the frequency in which gumbo shale is encountered in drilling subterranean wells, the development of a substance and method for reducing clay swelling remains a continuing challenge in the oil and gas exploration industry.
[0013] One method to reduce clay swelling is to use salts in drilling fluids.
Salts generally reduce the swelling of clays; however, salts can flocculate the clays resulting in both high fluid losses and an almost complete loss of thixotropy. Further, increasing salinity often decreases the functional characteristics of drilling fluid additives.
[0014] Another method for controlling clay swelling is to use organic shale inhibitor molecules in drilling fluids. It is believed that the organic shale inhibitor molecules are absorbed on the surfaces of clays with the added organic shale inhibitor completing with water molecules for clay reactive sites and thus serve to reduce clay swelling. Organic shale inhibitors can be cationic, anionic, or nonionic. Cationic organic shale inhibitors dissociate into organic cations and inorganic anions, while anionic organic shale inhibitors dissociate into inorganic cationic and organic anions. Nonionic shale inhibitor molecules do not dissociate.
[0015] In the oil and gas industry, it is desirable that additives (shale inhibitors as well as any other additives) work both onshore and offshore and in fresh and salt water environments. In addition, as drilling operations and drilling waste disposal impact plant and animal life and water sources, drilling fluid additives should have low toxicity levels.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 If a wellbore fluid (and all of its component parts) is non-toxic or has extremely low toxicity (below governmental requirements) disposal options may include pump-off, land spreading, land spraying, etc., which are not available for fluids having higher toxicity levels. For example, in Canada, fluids may only be disposed by such means if the fluid (and/or each of its components) has an EC50 (effective concentration causing a maximum 50% response from microorganisms) greater than 75 (a valued between 75 and 90 is slightly toxic, but still disposable, while a value greater than 90 is non-toxic) for a particular microtoxicity assay measuring the light reduction from fluid samples having microorganisms contained therein.
[0016] Accordingly, there exists a continuing need for developments in shale hydration inhibition agents for water based fluids, and in particular shale inhibitive water-based fluids that have low toxicity.
SUMMARY OF INVENTION
[0017] In one aspect, embodiments disclosed herein relate to a wellbore fluid that includes an aqueous base fluid; a natural amine having at least one amine group and at least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis.
[0018] In another aspect, embodiments disclosed herein relate to a method of drilling, that includes circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:
an aqueous base fluid; a natural amine having at least one amine group and at least a C3 oleophilic backbone; andan unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis; where the method also includes collecting the wellbore fluid and drilled cuttings from the wellbore; and disposing of at least one of the wellbore fluid or drilled cuttings by one of disposed of mix-bury-cover, land-spreading, pump-off, or land-spraying.
[0019] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
DETAILED DESCRIPTION
[0020] In one aspect, embodiments disclosed herein relate to a water-based wellbore fluid for use in drilling wells through a formation containing shale that swells in the presence of water. Generally the wellbore fluids of the present disclosure may be formulated to include an aqueous continuous phase, a natural amine, and an unmodified biopolymer viscosifier, and such formulations may be considered non-toxic or have extremely low toxicity.
[0021] Toxicity, as referred to in the present disclosure, may be measured by a bioassay-based toxicity assessment known as MICROTOX (Strategic Diagnostics, Inc., Newark DE) to screen for the presence of components that are toxic to life forms, including microorganisms, macroorganisms, and vegetation. While trout and shrimp assays have historically been used to evaluate toxicity, the MICROTOX test is based on monitoring changes in the level of light emission from a marine luminescent bacterium (Vibrio fischeri) when exposed to a toxic substance or sample containing toxic materials, and may be used to provide a more rapid, real-time measurement of acute toxicity.
The MICROTOX test may use a MICROTOX 500 Analyze, which is a very sensitive analyzer for the measurement of light from a luminescent bacterial reagent.
The Analyzer offers a wide dynamic test range of light measurement (from 0 to approximately 120,000,000 photon counts), which are automatically selected and calibrated for high accuracy readings. The instrument reads light produced by luminescent bacteria (Vibrio fischeri) after exposure to a test sample and compares it to PATENT APPLICATION
ATTORNEY DOCKET NO. 0554M58001 CLIENT REF. NO. 81057005US01 the light output of a control (reagent blank). The degree of percent light loss (an indication of metabolic inhibition in the test organisms) indicates the relative toxicity of the sample.
[00221 In accordance with embodiments of the present disclosure, each of the fluid's components may have a MICROTOX EC50 (or IC50) value of at least 75%, and at least 90% in yet another embodiment over a 15 minute test period at 15C. An value refers to the effective concentration (or inhibitory concentration for an IC50) of a sample that reduces light emission of the test organism by 50% over the test period. The results of the MICROTOX test are given as a percentage of the original sample, i.e., the EC50 value for the sample is a concentration that is at least 75% (or at least 90%) of the concentration of the original sample. In other words, an EC50 value of 75%
means that 75% of the original concentration of the sample results in a 50% decrease in light output.
In some instances, however, an EC50 value cannot be determined because a 50%
reduction in light output is not achieved. In such instances, the highest percent effect, or the greatest decrease in light that was observed during the test (often at 81.9% of the original test concentration) may be recorded. If the greatest decrease is less than a 50%
reduction in light, then a lesser amount of metabolic inhibition in the test organisms is indicated than if an EC50 value could be calculated. Thus, if the greatest decrease is less than 50%, a sample may be considered non-toxic. In a more particular embodiment, one or more of the fluid components may have a negative gamma value (ratio of light lost to light remaining), i.e., the sample stimulated bacterial light output, indicating that the bacterium is experiencing hormesis, or a generally-favorable biological response causing the bacterium to grow or flourish.
[00231 It is noted that the particular test used to ensure sufficiently low toxicity for the wellbore fluid (and/or its components) is not a limitation on the present disclosure, but if the MICROTOX test were applied to the wellbore fluid (and/or its components), the fluid (and/or fluid components) would have the requisite EC50 values when tested in line with the specifications set forth in Appendix 4 of Guide 50: Drilling Waste Management, October 1996 (Alberta Energy and Utilities Board) ("Directive 50"), which is herein incorporated by reference in its entirety. Further, it is also noted that a sample that PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 "passes" one particular toxicity test may not necessarily "pass" a different test because different toxicants may affect one bioassay differently than the other. For example, hydrocarbons exhibit a strong toxic response within the MICROTOX test, but may have little effect on other bioassays such as the rainbow trout test, whereas ammonia may have a stronger toxic response within the rainbow trout test, as compared to the MICROTOX test.
[00241 In various embodiments, the shale inhibitor and the biopolymer viscosifier selected for use in the wellbore fluids of the present disclosure may each have an MICROTOX EC50 value (according to the specifications set forth in Directive 50) of at least 75%. In a more particular embodiment, at least one of the shale inhibitor and the biopolymer viscosifier may have a MICROTOX EC50 value of at least 90%. In an even more particular embodiment, at least one of the shale inhibitor and the biopolymer viscosifier may each trigger hormesis under the MICROTOX test.
[00251 A natural amine shale hydration inhibition agent is included in the formulation of the wellbore fluids of the present disclosure so that the hydration of shale and shale like formations is inhibited. In accordance with various embodiments of the present disclosure, the natural amine shale inhibitor may be a naturally occurring amine having an oleophilic backbone component, and a naturally occurring polyamine in more particular embodiments. In various embodiments, the shale inhibitors may include from I to 7 amine groups, but may include more in other embodiments. The oleophilic backbone of the amine may be a linear, branched alkyl group, cyclic alkyl, or heterocyclic aromatic groups, and in particular embodiments, may be at least a C3 group.
In a particular embodiment, the natural amine shale inhibitors of the present disclosure may be relatively small molecules, having a molecular weight of less than 700, or a molecular weight of less than 500, or 250 in more particular embodiments. The inventors of the present disclosure theorize that the shale inhibition occurs by the interaction of the nitrogen atoms from the amine(s) with the active groups on the clay surface in combination with the carbon backbone of the oleophilic portion of the amine repelling water from interacting with the clay surface. Thus, the natural amine should be present in sufficient concentration to reduce either or both the surface hydration based swelling PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 and/or the osmotic based swelling of the shale clay. When drilling through a formation having water-swellable clays therein, a wellbore fluid having the additives of the present disclosure may be circulated therein to reduce the swelling of clays or shale hydration.
[00261 Various embodiments may include at least one amino acid or at least one naturally occurring species based on an amino acid (such as folic acid, etc).
In a particular embodiment, the shale inhibitor may include one or more of pantothenic acid, folic acid, biotin, niacin, L-arginine, L-lysine, asparagine, glutamine, histadine, aspartic acid, glutamic acid, 5-hydroxytryptophan, tryptophan, serotonin, and beta-alanine.
However, other natural amines may also be used.
[00271 In particular embodiments, the amine shale inhibitor of the present disclosure may be non-ionic, the amine(s) being a primary, secondary, or tertiary amine(s).
Many conventional shale hydration inhibition agents rely on a cationic character so that the cationic character may exchange with exchangeable cations found on the surface of the shale or other swellable clay. While such mechanism for shale hydration may be suitable for some wells (such as off-shore wells), land-based drilling presents a need for low electrical conductivity fluids. The use of quaternary amines results in the inclusion of an anionic species (often inorganic halides), thus increasing the electrical conductivity of the fluid. Specifically, low conductivity may be desired for certain disposal options of cuttings on-shore. On the type of disposal, land disposal of water-based fluids and cuttings is an environmental concern due to a potential for high conductivity/salinity which cause a possibility of leaching and groundwater contamination. Salt, unlike hydrocarbons, cannot biodegrade but may accumulate in soils, which have a limited capacity to accept salts. If salt levels become too high, the soils may be damaged and the soil's ability to naturally degrade organic materials by microorganisms present in the soil can be inhibited. However, in another embodiment, if a quaternary amine is used, an organic salt (such as citrate, etc.) may be preferred to reduce the presence of inorganic anions such as halides.
[00281 Using natural amines of the present disclosure that are also non-ionic, shale hydration inhibition may be achieved without increasing the electrical conductivity of the PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 wellbore fluid. Thus, such fluids may be classified as low electrical conductivity fluids.
As used herein, a "low electrical conductivity fluid" refers to a fluid having an electrical conductivity of no more than 10,000 S/cm. However, in accordance with particular embodiments of the present disclosure, fluids having electrical conductivities of less than about 3000 S/cm may be achieved, and less than about 2000 S/cm in more particular embodiments.
[0029] The natural amines of the present disclosure may be added to a wellbore fluid in concentrations sufficient to deal with the clay swelling problems at hand.
Concentrations between about 0.5 pounds per barrel (ppb) and 10 ppb are contemplated and are considered to be functionally effective to reduce swelling. of clays which swell in the presence of water.
[0030] The wellbore fluids may also include a biopolymer viscosifying agent in order to alter or maintain the rheological properties of the fluid. The primary purpose for such viscosifying agents is to control the viscosity and potential changes in viscosity of the drilling fluid. Viscosity control is particularly important because often a subterranean formation may have a temperature significantly higher than the surface temperature.
Thus a wellbore fluid may undergo temperature extremes of nearly freezing temperatures to nearly the boiling temperature of water or higher during the course of its transit from the surface to the drill bit and back. One of skill in the art should know and understand that such changes in temperature can result in significant changes in the rheological properties of fluids. Thus in order to control and/or moderate the rheology changes, viscosity agents and rheology control agents may be included in the formulation of the wellbore fluid.
[0031] Viscosifying agents suitable for use in the formulation of the fluids of the present disclosure may be generally selected from any type of natural biopolymer suitable for use in aqueous based drilling fluids. Exemplary biopolymers may include starches, celluloses, and various gums, such as xanthan gum, gellan gum, welan gum, and schleroglucan gum. Such starches may include potato starch, corn starch, tapioca starch, wheat starch and rice starch, etc. In accordance with various embodiments of the present PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 disclosure, the biopolymer viscosifying agents may be unmodified (i.e., without derivitization). Additionally, within particular embodiments, the biopolymer viscosifiers may have an H2S content of less than 0.1 mg/L, and less than 0.05 mg/L in more particular embodiments. Hydrogen sulfide is often used in the packaging of biopolymers to kill any bacteria; however, the presence of such a bactericide during the wellbore formulation may render an otherwise non-toxic component relatively toxic.
Thus, it may be desirable to wash any residual H2S from the biopolymers prior to incorporation of the component into the wellbore fluid. Generally, the biopolymers may be present in an amount ranging from 0.5 to 5 pounds per barrel (1.43 to 14.27 kg/m3); however, more or less may be used depending on the particular wellbore diameter, annular velocity, cutting carrying capacity, quiescent time expected or desired.
100321 The aqueous based continuous phase may generally be any water based fluid phase that is compatible with the formulation of a drilling fluid and is compatible with the shale hydration inhibition agents disclosed herein. In a particular embodiment, the aqueous based continuous phase may include fresh water. However, in alternative embodiments, the fluid may include at least one of fresh water, mixtures of water and water soluble organic compounds and mixtures thereof. In a particular embodiment, the aqueous fluid may be selected to be within the electrical conductivity limits described above. One skilled in the art would appreciate that conductivity requirements of a fluid may depend on the regulatory requirements for disposal of fluids/cuttings in a particular jurisdiction, and thus, for jurisdictions having relatively higher conductivity limits, inclusion of some salt in the fluid may be provided. In such instances, for example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water.
Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, PATENT APPLICATION
ATTORNEY DOCKET NO. 055421358001 CLIENT REF. NO. 81057005US01 phosphates, silicates and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. One of ordinary skill would appreciate that the above salts may be present in the base fluid, or alternatively, may be added according to the method disclosed herein. Further, the amount of the aqueous based continuous phase should be sufficient to form a water based drilling fluid. This amount may range from nearly 100%
of the wellbore fluid to less than 30% of the wellbore fluid by volume.
Preferably, the aqueous based continuous phase may constitute from about 95 to about 30% by volume and preferably from about 90 to about 40% by volume of the wellbore fluid.
[0033] The wellbore fluids of the present disclosure may include a weight material or weighting agent in order to increase the density of the fluid. The primary purpose for such weighting materials is to increase the density of the fluid so as to prevent kick-backs and blow-outs. Thus the weighting agent may be added to the drilling fluid in a functionally effective amount largely dependent on the nature of the formation being drilled. Weighting agents or density materials suitable for use the fluids disclosed herein include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like, mixtures and combinations of these compounds and similar such weight materials that may be used in the formulation of wellbore fluids.
The quantity of such material added, if any, may depend upon the desired density of the final composition. Typically, weighting agent is added to result in a drilling fluid density of up to about 24 pounds per gallon. The weighting agent may be added up to 21 pounds per gallon in one embodiment, and up to 19.5 pounds per gallon in another embodiment.
[0034] In addition to the other components previously noted, materials generically referred to as thinners and fluid loss control agents may also optionally added to water-based wellbore fluid formulations. Of these additional materials, each may be added to the formulation in a concentration as rheologically and functionally required by drilling conditions.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005USO 1 [0035] In certain embodiments, the methods of the present disclosure comprise providing a wellbore fluid (e.g., a drilling fluid, reservoir drill-in fluid, fracturing fluid, etc.) of the present disclosure that comprises an aqueous base fluid, a natural amine shale-inhibiting component, and a natural viscosifier; and placing the wellbore fluid in a subterranean formation. The shale-inhibiting component and viscosifier may be added to the wellbore fluid individually or as a pre-mixed additive that comprises the shale-inhibiting component and/or viscosifier, as well as other optional components. The shale-inhibiting component and/or viscosifier may be added to the wellbore fluid prior to, during, or subsequent to placing the wellbore fluid in the subterranean formation.
[0036] A wellbore fluid according to the disclosure may be used in a method for drilling a well into a subterranean formation in a manner similar to those wherein conventional wellbore fluids are used. In the process of drilling the well, a wellbore fluid is circulated through the drill pipe, through the bit, and up the annular space between the pipe and the formation or steel casing to the surface. The wellbore fluid performs several different functions, such as cooling the bit, removing drilled cuttings from the bottom of the hole, suspending the cuttings and weighting the material when the circulation is interrupted.
[0037] The natural amine shale inhibitor and/or biopolymer viscosifier may be added to the base fluid on location at the well-site where it is to be used, or it can be carried out at another location than the well-site. If the well-site location is selected for carrying out this step, then the natural amine and the biopolymer may immediately be dispersed in an aqueous fluid, and the resulting wellbore fluid may immediately be emplaced in the well using techniques known in the art.
[0038] Another embodiment of the present method includes a method of reducing the swelling of shale in a well whereby a water-base fluid formulated in accordance with the teachings of this disclosure is circulated in a well. The methods and fluids of the present disclosure 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. Examples of suitable subterranean drilling operations include, but are not limited to, water well drilling, oil/gas well drilling, utilities drilling, tunneling, PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 construction/installation of subterranean pipelines and service lines, and the like. These subterranean drilling operations may be utilized, inter alia, to drill a well bore in a subterranean formation, or to stimulate the production of fluids from a subterranean formation, as well as or for a number of other purposes. In certain embodiments, the present disclosure provides methods of drilling at least a portion of a well bore to penetrate a subterranean formation.
[00391 Further, because of the low or non-toxic nature of the fluid, upon circulation in the well, the fluid may be collected at the rig surface and disposed of by any one of mix-bury-cover, land-spreading, pump-off, and/or land spraying. Mix-Bury-Cover is a disposal method in which the drilling waste solids and/or fluids are mixed into subsoil below the rooting zone and above the water table, and then covered with clean subsoil and topsoil. In addition to toxicity requirements, Mix-Bury-Cover also possesses trace element and nitrogen limits, maximum chloride concentration, and maximum hydrocarbon content.
[00401 Landspreading is a disposal method whereby the drilling waste is spread on-site and incorporated into the subsoil. Landspraying is a disposal method in which the waste sprayed off-site on to topsoil (can, but not necessarily, be incorporated therein). In addition to toxicity requirements, Landspreading and Landspraying also possess trace element and nitrogen limits, maximum chloride and sodium concentrations, maximum hydrocarbon and total dissolved solids contents, and electrical conductivity limits.
[00411 Pump-off is a disposal method for clear liquids from the drilling waste, in which the clear liquids are applied off-site, such as on to vegetated land, through hoses or irrigation equipment while the solid components of the waste may be disposed of by any other method. In addition to toxicity and clear liquid requirements, Pump-off also possess trace element and nitrogen limits, maximum chloride and sodium concentrations, and maximum hydrocarbon and total dissolved solids contents.
[00421 Further, depending on the formulation of the fluid (and preexisting MICROTOX or other bioassays for each fluid additive), additional screening (MICROTOX or otherwise) may be necessary for the collected waste fluid prior to PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 disposal. If a fluid is over the governmental requirements for disposal (such as by incorporation of bactericide, corrosion inhibitor, etc.), reduction of the toxicity may be achieved by one or more of aeration, pH adjustment, charcoal addition, flocculation, centrifugation, filtration, chemical precipitation, chemical oxidation, and/or natural biodegradation so that the toxicity requirements may be met for waste disposal by one of the above-described methods. Such disposal may occur after one or more waste reduction treatments that include dewatering, hydrocarbon separation, activated carbon treatment, precipitation of heavy metals, or any other remedial measure to meet the disposal requirements. Removal of hydrocarbons may be particularly desirable if the drilling operation involved any of disposal of drill stem testing wastes to the sump, freeing of stuck pipe using hydrocarbons, a kick, blow, or well flow, horizontal drilling, or drilling of an underbalanced well.
[00431 EXAMPLES
[00441 Example 1 [00451 Various natural amines were tested at l0kg/m3 in distilled water in accordance with the MICROTOX test described in Directive 50, and various starches were tested in distilled water at various concentrations. The starches included E5829A and potato starches from ChemStar (Minneapolis, MN) and Fleischmann's corn starch (ConAgra Foods, Inc., Omaha, NE). The EC50 results are shown below in Table IA
and 1B, respectively.
Table 1 A
Sample pH Treatment EC50 (15min) Highest Result k /m3 Initial/adjusted % Effective Conc.
Folic Acid 6.94/- N/A >100 -- Pass Pantothenic acid 6.07/- N/A >100 - Pass L-lysine 6.19/- N/A Hormesis -- Pass 5-HTP 6.3/- N/A -- 28.13* Pass Biotin 7.20 N/A Hormesis -- Pass Table 1 B
Sample Concentration pH Initial/adjusted Treatment EC50 (15min) [kg/M3]
PATENT APPLICATION
ATTORNEY DOCKET NO.05542/358001 CLIENT REF. NO. 81057005US01 E5829A 15 10.47/6.95 Centrifuged 90.35 E5829B 15 10.49/6.4 Centrifuged 171.7 Corn Starch 2 7.5/- Centrifuged >100%
Corn Starch 4 7.5/- Centrifuged Hormesis [00461 Example 2 [00471 Various amines were formulated at a concentration of 10 kg/m3 in combination with 1kg/m3 soda ash and 25 kg/m3 bentonite in water. Rheological measurements were taken at room temperature on a Fann 35 Viscometer (Fann Instrument Company) before and after aging at room temperature for 20 hours. Bentonite is 100% smectite, and the shale inhibitive effect of the amines may be determined by comparing the rheological properties of a baseline fluid (soda ash and bentonite in water) to the fluid samples incorporating an amine. Lower rheological properties indicates an inhibitive effect. The results are shown in Tables 2A and 2B below.
Table 2A - Before Aging Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-Lysine YP 1 0 0.5 1.5 0.5 1.5 0.5 10s 1 0.5 0.5 0.5 0.5 1 0.5 10m 3 0.5 1 3.5 0.5 2 1.5 H 9.95 7.40 9.64 9.61 4.93 10.19 8.66 Table 2B - After Aging Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-Lysine YP 1.5 0.5 0.5 0 0.5 1 1 10S 0.5 0.5 0.5 0 0.5 0.5 0.5 10m 1.5 0.5 0.5 1 0.5 2.5 1 H 9.79 7.91 9.22 9.45 4.94 10.11 8.82 PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005USOI
[00481 Additional formulations of the amines were formulated at 10 kg/m3 in combination with soda ash (to reach pH 9.5-10.5 before aging) and 50 kg/m3 bentonite.
The rheological measurements were taken at room temperature before and after aging at room temperature for 20 hours. The results are shown in Tables 3A and 3B
below.
Table 3A - Before Aging Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine Acid Acid YP 4.5 2 1 3.5 2 5 4 10s 2.5 2.5 1 2.5 2 3 3.5 tom 6.5 4 3 5.5 4 7.5 5 p H 9.64 10.39 9.63 9.74 9.54 10.55 9.41 Table 3B - After Aging Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine Acid Acid YP 4.5 1.5 1.5 2.5 1 3 4 10s 2 1.5 0.5 1.5 2.5 1.5 4 10m 5.5 3 3 4 3 5 6.5 pH 9.63 10.12 9.23 9.60 9.49 10.48 9.58 [0049] Example 3 [0050] Various fluid samples having various natural amines in combination with other fluid components, including a viscosifier, were formulated as shown in Table 4A below.
The rheological properties of the fluid are shown Table 4A and the MICROTOX
test results are shown in Table 4B. FEDZAN D is a xanthan gum available and CalCarb 0 and SAFECARB products are calcium carbonate particles, all of which are available from M-I SWACO (Houston, Texas).
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 Table 4A
Component Baseline Folic Acid Pantothenic Acid Niacin Water (D-I) Balance Balance Balance Balance Soda Ash [kg/m3] 2.8 2.8 2.8 2.8 FedZan D [kg/m3] 2.6 2.6 2.6 2.6 Folic Acid [kg/m3] 10 Corn Starch [kg/m3] 15 15 15 15 Pantothenic Acid [kg/m3] 10 Niacin [kg/m3] 10 CalCarb 0 [kg/m3] 15 15 15 15 SafeCarb 20 [kg/m3] 35 35 35 35 SafeCarb 40 [kg/m3] 15 15 15 15 Bentonite [kg/m3] 25 25 25 25 Measured Properties PV [mPa*s] 12 12 14 7 YP [Pa] 9.5 8.5 10.5 7.5 Sec Gel 4.5 4.5 5 3.5 10 Min Gel 6 6 7 5 API Fluid Loss (7.5 min x 2) 10 9.6 10 9 Table 4B
Sample pH Initial/adjusted Treatment EC50 (15min) Highest Result Effective Conc.
Baseline 10.55/6.74 Centrifuged -- 24.17* Pass Folic Acid 10.31t8.52 Centrifuged -- 38.91 * Pass Pantothenic acid 9.73/6.67 Centrifuged -- 34.67* Pass Niacin 7.60/- Centrifuged -- 27.48* Pass [00511 Example 4 [00521 The first step was to develop a formulation that provided the rheology and fluid loss control sought in the objective using Xanthan Gum (Fedzan D) to raise low end PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 rheology and Starch (E5829A) to aid in fluid loss control. KLA-GARD B is an amine shale inhibitor available from M-I SWACO (Houston, Texas). The product components used in the samples include the following components at the respective concentrations:
= Xanthan Gum - 5 kg/m3 = FEDPAC UL - 5 kg/m3 = Starch - 3 kg/m3 = KLA-GARD B - 30 L/m3 (3%v/v) = Calcium Carbonate "0" - 15 kg/m3 = SAFECARB 20 - 35 kg/m3 = SAFECARB 40 - 15 kg/m3 = Lime - 0.25 kg/m3 [0053] Eight fluid samples from the above concentrations, comparing equal concentrations of FEDZAN D vs. Duovis and E5829A vs. E5829B starches, each with and without KLA-GARD B, were formulated as shown below in Table 5. Distilled water was used for formulating the mud to prevent the chlorine in tap water from interfering with MICROTOX testing.
Table 5 Mud Sample #
A B C D E F G H
m' Duovis 5 5 - - 5 5 k m' FEDPAC UL
[kg/M3] 5 5 5 5 5 5 5 5 k m3 3 - 3 3 - 3 m' [LJM3]
Cal Carb "0 [kg/M3] 15 15 15 15 15 15 15 15 ma k m' 15 15 15 15 15 15 15 15 Lime m' 0.25 0.25 0.25 0.25 0.5 0.5 0.5 0.5 [0054] Samples A, B, C and D were tested for rheology, API fluid loss, and MICROTOX 15 Min EC50, the results of which are shown in Table 6 below.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005 US01 Table 6 Mud Sample #
A B C D
API FL 10.4 9.4 10.4 9.4 cc 3Omin cP
cP
cP
cP
cP
cP
Gel 10s/10m 7.5/11.0 8.0/11.0 6.5/9.0 7.0/9.0 Pa mPa=S
YP 20.5 22.5 18.5 20.0 Pa Microtox 15 min EC50 105.6% 68.1% 181.9% 148.5%
[%] PASS FAIL PASS PASS
Pass/Fail [00551 Samples E-H were built with no KLA-GARD B, and were used to determine the effectiveness of the KLA-GARD B inhibitor. All samples had 50 kg/m3 of Federal Gel added to simulate reactive solids. The rheology was checked on each sample after 15 minutes of mixing, and again after sitting over-night (20 hours). The results are shown in Table 7 below.
Table 7 Mud Sample #
A E B F C G D H
15 Minutes cP
cP
cP
cP
cP
cP
Gel10s/10m 9.0/12.0 18.0/33.5 9.5/13.0 18.5/29.5 8.0/12.5 16.0/26.5 8.0/11.0 18.0128.0 Pa PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 mPa=s YP 21.5 44.0 23.0 44.5 21.0 41.0 21.0 47.0 Pa 20 Hours cP
cP
cP
I&I
-ICPI
Gel10s/10m 9.5/12.0 20.0/28.5 9.5/13.0 21.0/30.0 8.5/11.5 17.5/26.0 8.5/11.0 18.0/26.0 Pa mPas YP 25.0 57.0 27.0 55.5 22.5 47.0 23.5 50.0 Pa [0056] Similar formulations are compared side by side with and without KLA-GARD B
to show the effectiveness of the inhibitor in preventing hydration of reactive solids.
Samples containing DUOVIS are also shown having thinner high-end rheologies than the samples containing FEDZAN D.
[0057] Embodiments of the present disclosure may provide at least one of the following advantages. The natural amines of the present disclosure may perform as a shale inhibitor to reduce the swelling or hydration of shales during drilling.
Moreover, such additives possess extremely low toxicity and also do not significantly contribute to an increase in the electrical conductivity of the fluid, allowing for broader applicability for land disposal due to environmental concerns for disposal of toxic and/or high conductivity fluids/cuttings.
[0058] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 NON-TOXIC, SHALE INHIBITIVE WATER-BASED WELLBORE FLUID
BACKGROUND OF INVENTION
Field of the Invention [00011 Embodiments disclosed herein relate generally to shale hydration inhibition agents for use in water-based wellbore fluid. In particular, embodiments disclosed herein relate to natural amine shale hydration inhibition agents in wellbore fluids and their use in wellbore operations.
Background Art [00021 To facilitate the drilling of a well, fluid is circulated through the drill string, out the bit and upward in an annular area between the drill string and the wall of the borehole. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
[00031 Drilling fluids are typically classified according to their base material. The selection of the type of drilling fluid to be used in a drilling application involves a careful balance of both the good and bad characteristics of the drilling fluids in the particular application and the type of well to be drilled. In oil-based fluids, solid particles are suspended in oil (the continuous phase), and water or brine may be emulsified with the oil. In water-based fluids, solid particles are suspended in water or brine (continuous phase) including solid particles such as 1) clays and organic colloids added to provide necessary viscosity and filtration properties; 2) heavy minerals whose function is to PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 increase the drilling fluid's density; and 3) formation solids that become dispersed in the drilling fluid during the drilling operation. Historically, water based drilling fluids have been used to drill a majority of wells. Their lower cost and better environment acceptance as compared to oil based drilling fluids continue to make them the first option in drilling operations. However, as mentioned above, the selection of a fluid frequently may depend on the type of formation through which the well is being drilled. Where the formation solids are clay minerals that swell, the presence of either type of formation solids in the drilling fluid can greatly increase drilling time and costs.
[0004] The types of subterranean formations, intersected by a well, which may be at least partly composed of clays, including shales, mudstones, siltstones, and claystones. In penetrating through such formations, many problems may be encountered including bit balling, swelling or sloughing of the wellbore, stuck pipe, and dispersion of drill cuttings.
This may be particularly true when drilling with a water-based fluid due to the high reactivity of clay in an aqueous environment.
[0005] Clay minerals are generally crystalline in nature. The structure of a clay's crystals determines its properties. Typically, clays have a flaky, mica-type structure.
Clay flakes are made up of a number of crystal platelets stacked face-to-face. Each platelet is called a unit layer, and the surfaces of the unit layer are called basal surfaces. Each unit layer is composed of multiple sheets, which may include octahedral sheets and tetrahedral sheets.
Octahedral sheets are composed of either aluminum or magnesium atoms octahedrally coordinated with the oxygen atoms of hydroxyls, whereas tetrahedral sheets consist of silicon atoms tetrahedrally coordinated with oxygen atoms.
[0006] Sheets within a unit layer link together by sharing oxygen atoms. When this linking occurs between one octahedral and one tetrahedral sheet, one basal surface consists of exposed oxygen atoms while the other basal surface has exposed hydroxyls. It is also quite common for two tetrahedral sheets to bond with one octahedral sheet by sharing oxygen atoms. The resulting structure, known as the Hoffman structure, has an octahedral sheet that is sandwiched between the two tetrahedral sheets. As a result, both basal surfaces in a Hoffman structure are composed of exposed oxygen atoms.
The unit PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 layers stack together face-to-face and are held in place by weak attractive forces. The distance between corresponding planes in adjacent unit layers is called the d-spacing. A
clay crystal structure with a unit layer consisting of three sheets typically has a d-spacing of about 9.5x10"7 mm.
[0007] In clay mineral crystals, atoms having different valences commonly will be positioned within the sheets of the structure to create a negative potential at the crystal surface, which causes cations to be adsorbed thereto. These adsorbed cations are called exchangeable cations because they may chemically trade places with other cations when the clay crystal is suspended in water. In addition, ions may also be adsorbed on the clay crystal edges and exchange with other ions in the water.
[0008] The type of substitutions occurring within the clay crystal structure and the exchangeable cations adsorbed on the crystal surface greatly affect clay swelling, a property of primary importance in the drilling fluid industry. Clay swelling is a phenomenon in which water molecules surround a clay crystal structure and position themselves to increase the structure's d-spacing thus resulting in an increase in volume.
Two types of swelling may occur: surface hydration and osmotic swelling.
[0009] Surface hydration is one type of swelling in which water molecules are adsorbed on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen atoms exposed on the crystal surfaces. Subsequent layers of water molecules align to form a quasi-crystalline structure between unit layers, which results in an increased d-spacing. Virtually all types of clays swell in this manner.
[00101 Osmotic swelling is a second type of swelling. Where the concentration of cations between unit layers in a clay mineral is higher than the cation concentration in the surrounding water, water is osmotically drawn between the unit layers and the d-spacing is increased. Osmotic swelling results in larger overall volume increases than surface hydration. However, only certain clays, like sodium montmorillonite, swell in this manner.
[0011] Exchangeable cations found in clay minerals are reported to have a significant impact on the amount of swelling that takes place. The exchangeable cations compete PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 with water molecules for the available reactive sites in the clay structure.
Generally cations with high valences are more strongly adsorbed than ones with low valences.
Thus, clays with low valence exchangeable cations will swell more than clays whose exchangeable cations have high valences.
[0012] Clay swelling during the drilling of a subterranean well can have a tremendous adverse impact on drilling operations. The overall increase in bulk volume accompanying clay swelling impedes removal of cuttings from beneath the drill bit, increases friction between the drill string and the sides of the borehole, and inhibits formation of the thin filter cake that seals formations. Clay swelling can also create other drilling problems such as loss of circulation or stuck pipe that slow drilling and increase drilling costs. Thus, given the frequency in which gumbo shale is encountered in drilling subterranean wells, the development of a substance and method for reducing clay swelling remains a continuing challenge in the oil and gas exploration industry.
[0013] One method to reduce clay swelling is to use salts in drilling fluids.
Salts generally reduce the swelling of clays; however, salts can flocculate the clays resulting in both high fluid losses and an almost complete loss of thixotropy. Further, increasing salinity often decreases the functional characteristics of drilling fluid additives.
[0014] Another method for controlling clay swelling is to use organic shale inhibitor molecules in drilling fluids. It is believed that the organic shale inhibitor molecules are absorbed on the surfaces of clays with the added organic shale inhibitor completing with water molecules for clay reactive sites and thus serve to reduce clay swelling. Organic shale inhibitors can be cationic, anionic, or nonionic. Cationic organic shale inhibitors dissociate into organic cations and inorganic anions, while anionic organic shale inhibitors dissociate into inorganic cationic and organic anions. Nonionic shale inhibitor molecules do not dissociate.
[0015] In the oil and gas industry, it is desirable that additives (shale inhibitors as well as any other additives) work both onshore and offshore and in fresh and salt water environments. In addition, as drilling operations and drilling waste disposal impact plant and animal life and water sources, drilling fluid additives should have low toxicity levels.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 If a wellbore fluid (and all of its component parts) is non-toxic or has extremely low toxicity (below governmental requirements) disposal options may include pump-off, land spreading, land spraying, etc., which are not available for fluids having higher toxicity levels. For example, in Canada, fluids may only be disposed by such means if the fluid (and/or each of its components) has an EC50 (effective concentration causing a maximum 50% response from microorganisms) greater than 75 (a valued between 75 and 90 is slightly toxic, but still disposable, while a value greater than 90 is non-toxic) for a particular microtoxicity assay measuring the light reduction from fluid samples having microorganisms contained therein.
[0016] Accordingly, there exists a continuing need for developments in shale hydration inhibition agents for water based fluids, and in particular shale inhibitive water-based fluids that have low toxicity.
SUMMARY OF INVENTION
[0017] In one aspect, embodiments disclosed herein relate to a wellbore fluid that includes an aqueous base fluid; a natural amine having at least one amine group and at least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis.
[0018] In another aspect, embodiments disclosed herein relate to a method of drilling, that includes circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:
an aqueous base fluid; a natural amine having at least one amine group and at least a C3 oleophilic backbone; andan unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis; where the method also includes collecting the wellbore fluid and drilled cuttings from the wellbore; and disposing of at least one of the wellbore fluid or drilled cuttings by one of disposed of mix-bury-cover, land-spreading, pump-off, or land-spraying.
[0019] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
DETAILED DESCRIPTION
[0020] In one aspect, embodiments disclosed herein relate to a water-based wellbore fluid for use in drilling wells through a formation containing shale that swells in the presence of water. Generally the wellbore fluids of the present disclosure may be formulated to include an aqueous continuous phase, a natural amine, and an unmodified biopolymer viscosifier, and such formulations may be considered non-toxic or have extremely low toxicity.
[0021] Toxicity, as referred to in the present disclosure, may be measured by a bioassay-based toxicity assessment known as MICROTOX (Strategic Diagnostics, Inc., Newark DE) to screen for the presence of components that are toxic to life forms, including microorganisms, macroorganisms, and vegetation. While trout and shrimp assays have historically been used to evaluate toxicity, the MICROTOX test is based on monitoring changes in the level of light emission from a marine luminescent bacterium (Vibrio fischeri) when exposed to a toxic substance or sample containing toxic materials, and may be used to provide a more rapid, real-time measurement of acute toxicity.
The MICROTOX test may use a MICROTOX 500 Analyze, which is a very sensitive analyzer for the measurement of light from a luminescent bacterial reagent.
The Analyzer offers a wide dynamic test range of light measurement (from 0 to approximately 120,000,000 photon counts), which are automatically selected and calibrated for high accuracy readings. The instrument reads light produced by luminescent bacteria (Vibrio fischeri) after exposure to a test sample and compares it to PATENT APPLICATION
ATTORNEY DOCKET NO. 0554M58001 CLIENT REF. NO. 81057005US01 the light output of a control (reagent blank). The degree of percent light loss (an indication of metabolic inhibition in the test organisms) indicates the relative toxicity of the sample.
[00221 In accordance with embodiments of the present disclosure, each of the fluid's components may have a MICROTOX EC50 (or IC50) value of at least 75%, and at least 90% in yet another embodiment over a 15 minute test period at 15C. An value refers to the effective concentration (or inhibitory concentration for an IC50) of a sample that reduces light emission of the test organism by 50% over the test period. The results of the MICROTOX test are given as a percentage of the original sample, i.e., the EC50 value for the sample is a concentration that is at least 75% (or at least 90%) of the concentration of the original sample. In other words, an EC50 value of 75%
means that 75% of the original concentration of the sample results in a 50% decrease in light output.
In some instances, however, an EC50 value cannot be determined because a 50%
reduction in light output is not achieved. In such instances, the highest percent effect, or the greatest decrease in light that was observed during the test (often at 81.9% of the original test concentration) may be recorded. If the greatest decrease is less than a 50%
reduction in light, then a lesser amount of metabolic inhibition in the test organisms is indicated than if an EC50 value could be calculated. Thus, if the greatest decrease is less than 50%, a sample may be considered non-toxic. In a more particular embodiment, one or more of the fluid components may have a negative gamma value (ratio of light lost to light remaining), i.e., the sample stimulated bacterial light output, indicating that the bacterium is experiencing hormesis, or a generally-favorable biological response causing the bacterium to grow or flourish.
[00231 It is noted that the particular test used to ensure sufficiently low toxicity for the wellbore fluid (and/or its components) is not a limitation on the present disclosure, but if the MICROTOX test were applied to the wellbore fluid (and/or its components), the fluid (and/or fluid components) would have the requisite EC50 values when tested in line with the specifications set forth in Appendix 4 of Guide 50: Drilling Waste Management, October 1996 (Alberta Energy and Utilities Board) ("Directive 50"), which is herein incorporated by reference in its entirety. Further, it is also noted that a sample that PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 "passes" one particular toxicity test may not necessarily "pass" a different test because different toxicants may affect one bioassay differently than the other. For example, hydrocarbons exhibit a strong toxic response within the MICROTOX test, but may have little effect on other bioassays such as the rainbow trout test, whereas ammonia may have a stronger toxic response within the rainbow trout test, as compared to the MICROTOX test.
[00241 In various embodiments, the shale inhibitor and the biopolymer viscosifier selected for use in the wellbore fluids of the present disclosure may each have an MICROTOX EC50 value (according to the specifications set forth in Directive 50) of at least 75%. In a more particular embodiment, at least one of the shale inhibitor and the biopolymer viscosifier may have a MICROTOX EC50 value of at least 90%. In an even more particular embodiment, at least one of the shale inhibitor and the biopolymer viscosifier may each trigger hormesis under the MICROTOX test.
[00251 A natural amine shale hydration inhibition agent is included in the formulation of the wellbore fluids of the present disclosure so that the hydration of shale and shale like formations is inhibited. In accordance with various embodiments of the present disclosure, the natural amine shale inhibitor may be a naturally occurring amine having an oleophilic backbone component, and a naturally occurring polyamine in more particular embodiments. In various embodiments, the shale inhibitors may include from I to 7 amine groups, but may include more in other embodiments. The oleophilic backbone of the amine may be a linear, branched alkyl group, cyclic alkyl, or heterocyclic aromatic groups, and in particular embodiments, may be at least a C3 group.
In a particular embodiment, the natural amine shale inhibitors of the present disclosure may be relatively small molecules, having a molecular weight of less than 700, or a molecular weight of less than 500, or 250 in more particular embodiments. The inventors of the present disclosure theorize that the shale inhibition occurs by the interaction of the nitrogen atoms from the amine(s) with the active groups on the clay surface in combination with the carbon backbone of the oleophilic portion of the amine repelling water from interacting with the clay surface. Thus, the natural amine should be present in sufficient concentration to reduce either or both the surface hydration based swelling PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 and/or the osmotic based swelling of the shale clay. When drilling through a formation having water-swellable clays therein, a wellbore fluid having the additives of the present disclosure may be circulated therein to reduce the swelling of clays or shale hydration.
[00261 Various embodiments may include at least one amino acid or at least one naturally occurring species based on an amino acid (such as folic acid, etc).
In a particular embodiment, the shale inhibitor may include one or more of pantothenic acid, folic acid, biotin, niacin, L-arginine, L-lysine, asparagine, glutamine, histadine, aspartic acid, glutamic acid, 5-hydroxytryptophan, tryptophan, serotonin, and beta-alanine.
However, other natural amines may also be used.
[00271 In particular embodiments, the amine shale inhibitor of the present disclosure may be non-ionic, the amine(s) being a primary, secondary, or tertiary amine(s).
Many conventional shale hydration inhibition agents rely on a cationic character so that the cationic character may exchange with exchangeable cations found on the surface of the shale or other swellable clay. While such mechanism for shale hydration may be suitable for some wells (such as off-shore wells), land-based drilling presents a need for low electrical conductivity fluids. The use of quaternary amines results in the inclusion of an anionic species (often inorganic halides), thus increasing the electrical conductivity of the fluid. Specifically, low conductivity may be desired for certain disposal options of cuttings on-shore. On the type of disposal, land disposal of water-based fluids and cuttings is an environmental concern due to a potential for high conductivity/salinity which cause a possibility of leaching and groundwater contamination. Salt, unlike hydrocarbons, cannot biodegrade but may accumulate in soils, which have a limited capacity to accept salts. If salt levels become too high, the soils may be damaged and the soil's ability to naturally degrade organic materials by microorganisms present in the soil can be inhibited. However, in another embodiment, if a quaternary amine is used, an organic salt (such as citrate, etc.) may be preferred to reduce the presence of inorganic anions such as halides.
[00281 Using natural amines of the present disclosure that are also non-ionic, shale hydration inhibition may be achieved without increasing the electrical conductivity of the PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 wellbore fluid. Thus, such fluids may be classified as low electrical conductivity fluids.
As used herein, a "low electrical conductivity fluid" refers to a fluid having an electrical conductivity of no more than 10,000 S/cm. However, in accordance with particular embodiments of the present disclosure, fluids having electrical conductivities of less than about 3000 S/cm may be achieved, and less than about 2000 S/cm in more particular embodiments.
[0029] The natural amines of the present disclosure may be added to a wellbore fluid in concentrations sufficient to deal with the clay swelling problems at hand.
Concentrations between about 0.5 pounds per barrel (ppb) and 10 ppb are contemplated and are considered to be functionally effective to reduce swelling. of clays which swell in the presence of water.
[0030] The wellbore fluids may also include a biopolymer viscosifying agent in order to alter or maintain the rheological properties of the fluid. The primary purpose for such viscosifying agents is to control the viscosity and potential changes in viscosity of the drilling fluid. Viscosity control is particularly important because often a subterranean formation may have a temperature significantly higher than the surface temperature.
Thus a wellbore fluid may undergo temperature extremes of nearly freezing temperatures to nearly the boiling temperature of water or higher during the course of its transit from the surface to the drill bit and back. One of skill in the art should know and understand that such changes in temperature can result in significant changes in the rheological properties of fluids. Thus in order to control and/or moderate the rheology changes, viscosity agents and rheology control agents may be included in the formulation of the wellbore fluid.
[0031] Viscosifying agents suitable for use in the formulation of the fluids of the present disclosure may be generally selected from any type of natural biopolymer suitable for use in aqueous based drilling fluids. Exemplary biopolymers may include starches, celluloses, and various gums, such as xanthan gum, gellan gum, welan gum, and schleroglucan gum. Such starches may include potato starch, corn starch, tapioca starch, wheat starch and rice starch, etc. In accordance with various embodiments of the present PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 disclosure, the biopolymer viscosifying agents may be unmodified (i.e., without derivitization). Additionally, within particular embodiments, the biopolymer viscosifiers may have an H2S content of less than 0.1 mg/L, and less than 0.05 mg/L in more particular embodiments. Hydrogen sulfide is often used in the packaging of biopolymers to kill any bacteria; however, the presence of such a bactericide during the wellbore formulation may render an otherwise non-toxic component relatively toxic.
Thus, it may be desirable to wash any residual H2S from the biopolymers prior to incorporation of the component into the wellbore fluid. Generally, the biopolymers may be present in an amount ranging from 0.5 to 5 pounds per barrel (1.43 to 14.27 kg/m3); however, more or less may be used depending on the particular wellbore diameter, annular velocity, cutting carrying capacity, quiescent time expected or desired.
100321 The aqueous based continuous phase may generally be any water based fluid phase that is compatible with the formulation of a drilling fluid and is compatible with the shale hydration inhibition agents disclosed herein. In a particular embodiment, the aqueous based continuous phase may include fresh water. However, in alternative embodiments, the fluid may include at least one of fresh water, mixtures of water and water soluble organic compounds and mixtures thereof. In a particular embodiment, the aqueous fluid may be selected to be within the electrical conductivity limits described above. One skilled in the art would appreciate that conductivity requirements of a fluid may depend on the regulatory requirements for disposal of fluids/cuttings in a particular jurisdiction, and thus, for jurisdictions having relatively higher conductivity limits, inclusion of some salt in the fluid may be provided. In such instances, for example, the aqueous fluid may be formulated with mixtures of desired salts in fresh water.
Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example. In various embodiments of the drilling fluid disclosed herein, the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water. Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, PATENT APPLICATION
ATTORNEY DOCKET NO. 055421358001 CLIENT REF. NO. 81057005US01 phosphates, silicates and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution. One of ordinary skill would appreciate that the above salts may be present in the base fluid, or alternatively, may be added according to the method disclosed herein. Further, the amount of the aqueous based continuous phase should be sufficient to form a water based drilling fluid. This amount may range from nearly 100%
of the wellbore fluid to less than 30% of the wellbore fluid by volume.
Preferably, the aqueous based continuous phase may constitute from about 95 to about 30% by volume and preferably from about 90 to about 40% by volume of the wellbore fluid.
[0033] The wellbore fluids of the present disclosure may include a weight material or weighting agent in order to increase the density of the fluid. The primary purpose for such weighting materials is to increase the density of the fluid so as to prevent kick-backs and blow-outs. Thus the weighting agent may be added to the drilling fluid in a functionally effective amount largely dependent on the nature of the formation being drilled. Weighting agents or density materials suitable for use the fluids disclosed herein include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like, mixtures and combinations of these compounds and similar such weight materials that may be used in the formulation of wellbore fluids.
The quantity of such material added, if any, may depend upon the desired density of the final composition. Typically, weighting agent is added to result in a drilling fluid density of up to about 24 pounds per gallon. The weighting agent may be added up to 21 pounds per gallon in one embodiment, and up to 19.5 pounds per gallon in another embodiment.
[0034] In addition to the other components previously noted, materials generically referred to as thinners and fluid loss control agents may also optionally added to water-based wellbore fluid formulations. Of these additional materials, each may be added to the formulation in a concentration as rheologically and functionally required by drilling conditions.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005USO 1 [0035] In certain embodiments, the methods of the present disclosure comprise providing a wellbore fluid (e.g., a drilling fluid, reservoir drill-in fluid, fracturing fluid, etc.) of the present disclosure that comprises an aqueous base fluid, a natural amine shale-inhibiting component, and a natural viscosifier; and placing the wellbore fluid in a subterranean formation. The shale-inhibiting component and viscosifier may be added to the wellbore fluid individually or as a pre-mixed additive that comprises the shale-inhibiting component and/or viscosifier, as well as other optional components. The shale-inhibiting component and/or viscosifier may be added to the wellbore fluid prior to, during, or subsequent to placing the wellbore fluid in the subterranean formation.
[0036] A wellbore fluid according to the disclosure may be used in a method for drilling a well into a subterranean formation in a manner similar to those wherein conventional wellbore fluids are used. In the process of drilling the well, a wellbore fluid is circulated through the drill pipe, through the bit, and up the annular space between the pipe and the formation or steel casing to the surface. The wellbore fluid performs several different functions, such as cooling the bit, removing drilled cuttings from the bottom of the hole, suspending the cuttings and weighting the material when the circulation is interrupted.
[0037] The natural amine shale inhibitor and/or biopolymer viscosifier may be added to the base fluid on location at the well-site where it is to be used, or it can be carried out at another location than the well-site. If the well-site location is selected for carrying out this step, then the natural amine and the biopolymer may immediately be dispersed in an aqueous fluid, and the resulting wellbore fluid may immediately be emplaced in the well using techniques known in the art.
[0038] Another embodiment of the present method includes a method of reducing the swelling of shale in a well whereby a water-base fluid formulated in accordance with the teachings of this disclosure is circulated in a well. The methods and fluids of the present disclosure 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. Examples of suitable subterranean drilling operations include, but are not limited to, water well drilling, oil/gas well drilling, utilities drilling, tunneling, PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 construction/installation of subterranean pipelines and service lines, and the like. These subterranean drilling operations may be utilized, inter alia, to drill a well bore in a subterranean formation, or to stimulate the production of fluids from a subterranean formation, as well as or for a number of other purposes. In certain embodiments, the present disclosure provides methods of drilling at least a portion of a well bore to penetrate a subterranean formation.
[00391 Further, because of the low or non-toxic nature of the fluid, upon circulation in the well, the fluid may be collected at the rig surface and disposed of by any one of mix-bury-cover, land-spreading, pump-off, and/or land spraying. Mix-Bury-Cover is a disposal method in which the drilling waste solids and/or fluids are mixed into subsoil below the rooting zone and above the water table, and then covered with clean subsoil and topsoil. In addition to toxicity requirements, Mix-Bury-Cover also possesses trace element and nitrogen limits, maximum chloride concentration, and maximum hydrocarbon content.
[00401 Landspreading is a disposal method whereby the drilling waste is spread on-site and incorporated into the subsoil. Landspraying is a disposal method in which the waste sprayed off-site on to topsoil (can, but not necessarily, be incorporated therein). In addition to toxicity requirements, Landspreading and Landspraying also possess trace element and nitrogen limits, maximum chloride and sodium concentrations, maximum hydrocarbon and total dissolved solids contents, and electrical conductivity limits.
[00411 Pump-off is a disposal method for clear liquids from the drilling waste, in which the clear liquids are applied off-site, such as on to vegetated land, through hoses or irrigation equipment while the solid components of the waste may be disposed of by any other method. In addition to toxicity and clear liquid requirements, Pump-off also possess trace element and nitrogen limits, maximum chloride and sodium concentrations, and maximum hydrocarbon and total dissolved solids contents.
[00421 Further, depending on the formulation of the fluid (and preexisting MICROTOX or other bioassays for each fluid additive), additional screening (MICROTOX or otherwise) may be necessary for the collected waste fluid prior to PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 disposal. If a fluid is over the governmental requirements for disposal (such as by incorporation of bactericide, corrosion inhibitor, etc.), reduction of the toxicity may be achieved by one or more of aeration, pH adjustment, charcoal addition, flocculation, centrifugation, filtration, chemical precipitation, chemical oxidation, and/or natural biodegradation so that the toxicity requirements may be met for waste disposal by one of the above-described methods. Such disposal may occur after one or more waste reduction treatments that include dewatering, hydrocarbon separation, activated carbon treatment, precipitation of heavy metals, or any other remedial measure to meet the disposal requirements. Removal of hydrocarbons may be particularly desirable if the drilling operation involved any of disposal of drill stem testing wastes to the sump, freeing of stuck pipe using hydrocarbons, a kick, blow, or well flow, horizontal drilling, or drilling of an underbalanced well.
[00431 EXAMPLES
[00441 Example 1 [00451 Various natural amines were tested at l0kg/m3 in distilled water in accordance with the MICROTOX test described in Directive 50, and various starches were tested in distilled water at various concentrations. The starches included E5829A and potato starches from ChemStar (Minneapolis, MN) and Fleischmann's corn starch (ConAgra Foods, Inc., Omaha, NE). The EC50 results are shown below in Table IA
and 1B, respectively.
Table 1 A
Sample pH Treatment EC50 (15min) Highest Result k /m3 Initial/adjusted % Effective Conc.
Folic Acid 6.94/- N/A >100 -- Pass Pantothenic acid 6.07/- N/A >100 - Pass L-lysine 6.19/- N/A Hormesis -- Pass 5-HTP 6.3/- N/A -- 28.13* Pass Biotin 7.20 N/A Hormesis -- Pass Table 1 B
Sample Concentration pH Initial/adjusted Treatment EC50 (15min) [kg/M3]
PATENT APPLICATION
ATTORNEY DOCKET NO.05542/358001 CLIENT REF. NO. 81057005US01 E5829A 15 10.47/6.95 Centrifuged 90.35 E5829B 15 10.49/6.4 Centrifuged 171.7 Corn Starch 2 7.5/- Centrifuged >100%
Corn Starch 4 7.5/- Centrifuged Hormesis [00461 Example 2 [00471 Various amines were formulated at a concentration of 10 kg/m3 in combination with 1kg/m3 soda ash and 25 kg/m3 bentonite in water. Rheological measurements were taken at room temperature on a Fann 35 Viscometer (Fann Instrument Company) before and after aging at room temperature for 20 hours. Bentonite is 100% smectite, and the shale inhibitive effect of the amines may be determined by comparing the rheological properties of a baseline fluid (soda ash and bentonite in water) to the fluid samples incorporating an amine. Lower rheological properties indicates an inhibitive effect. The results are shown in Tables 2A and 2B below.
Table 2A - Before Aging Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-Lysine YP 1 0 0.5 1.5 0.5 1.5 0.5 10s 1 0.5 0.5 0.5 0.5 1 0.5 10m 3 0.5 1 3.5 0.5 2 1.5 H 9.95 7.40 9.64 9.61 4.93 10.19 8.66 Table 2B - After Aging Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-Lysine YP 1.5 0.5 0.5 0 0.5 1 1 10S 0.5 0.5 0.5 0 0.5 0.5 0.5 10m 1.5 0.5 0.5 1 0.5 2.5 1 H 9.79 7.91 9.22 9.45 4.94 10.11 8.82 PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005USOI
[00481 Additional formulations of the amines were formulated at 10 kg/m3 in combination with soda ash (to reach pH 9.5-10.5 before aging) and 50 kg/m3 bentonite.
The rheological measurements were taken at room temperature before and after aging at room temperature for 20 hours. The results are shown in Tables 3A and 3B
below.
Table 3A - Before Aging Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine Acid Acid YP 4.5 2 1 3.5 2 5 4 10s 2.5 2.5 1 2.5 2 3 3.5 tom 6.5 4 3 5.5 4 7.5 5 p H 9.64 10.39 9.63 9.74 9.54 10.55 9.41 Table 3B - After Aging Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine Acid Acid YP 4.5 1.5 1.5 2.5 1 3 4 10s 2 1.5 0.5 1.5 2.5 1.5 4 10m 5.5 3 3 4 3 5 6.5 pH 9.63 10.12 9.23 9.60 9.49 10.48 9.58 [0049] Example 3 [0050] Various fluid samples having various natural amines in combination with other fluid components, including a viscosifier, were formulated as shown in Table 4A below.
The rheological properties of the fluid are shown Table 4A and the MICROTOX
test results are shown in Table 4B. FEDZAN D is a xanthan gum available and CalCarb 0 and SAFECARB products are calcium carbonate particles, all of which are available from M-I SWACO (Houston, Texas).
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 Table 4A
Component Baseline Folic Acid Pantothenic Acid Niacin Water (D-I) Balance Balance Balance Balance Soda Ash [kg/m3] 2.8 2.8 2.8 2.8 FedZan D [kg/m3] 2.6 2.6 2.6 2.6 Folic Acid [kg/m3] 10 Corn Starch [kg/m3] 15 15 15 15 Pantothenic Acid [kg/m3] 10 Niacin [kg/m3] 10 CalCarb 0 [kg/m3] 15 15 15 15 SafeCarb 20 [kg/m3] 35 35 35 35 SafeCarb 40 [kg/m3] 15 15 15 15 Bentonite [kg/m3] 25 25 25 25 Measured Properties PV [mPa*s] 12 12 14 7 YP [Pa] 9.5 8.5 10.5 7.5 Sec Gel 4.5 4.5 5 3.5 10 Min Gel 6 6 7 5 API Fluid Loss (7.5 min x 2) 10 9.6 10 9 Table 4B
Sample pH Initial/adjusted Treatment EC50 (15min) Highest Result Effective Conc.
Baseline 10.55/6.74 Centrifuged -- 24.17* Pass Folic Acid 10.31t8.52 Centrifuged -- 38.91 * Pass Pantothenic acid 9.73/6.67 Centrifuged -- 34.67* Pass Niacin 7.60/- Centrifuged -- 27.48* Pass [00511 Example 4 [00521 The first step was to develop a formulation that provided the rheology and fluid loss control sought in the objective using Xanthan Gum (Fedzan D) to raise low end PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 rheology and Starch (E5829A) to aid in fluid loss control. KLA-GARD B is an amine shale inhibitor available from M-I SWACO (Houston, Texas). The product components used in the samples include the following components at the respective concentrations:
= Xanthan Gum - 5 kg/m3 = FEDPAC UL - 5 kg/m3 = Starch - 3 kg/m3 = KLA-GARD B - 30 L/m3 (3%v/v) = Calcium Carbonate "0" - 15 kg/m3 = SAFECARB 20 - 35 kg/m3 = SAFECARB 40 - 15 kg/m3 = Lime - 0.25 kg/m3 [0053] Eight fluid samples from the above concentrations, comparing equal concentrations of FEDZAN D vs. Duovis and E5829A vs. E5829B starches, each with and without KLA-GARD B, were formulated as shown below in Table 5. Distilled water was used for formulating the mud to prevent the chlorine in tap water from interfering with MICROTOX testing.
Table 5 Mud Sample #
A B C D E F G H
m' Duovis 5 5 - - 5 5 k m' FEDPAC UL
[kg/M3] 5 5 5 5 5 5 5 5 k m3 3 - 3 3 - 3 m' [LJM3]
Cal Carb "0 [kg/M3] 15 15 15 15 15 15 15 15 ma k m' 15 15 15 15 15 15 15 15 Lime m' 0.25 0.25 0.25 0.25 0.5 0.5 0.5 0.5 [0054] Samples A, B, C and D were tested for rheology, API fluid loss, and MICROTOX 15 Min EC50, the results of which are shown in Table 6 below.
PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005 US01 Table 6 Mud Sample #
A B C D
API FL 10.4 9.4 10.4 9.4 cc 3Omin cP
cP
cP
cP
cP
cP
Gel 10s/10m 7.5/11.0 8.0/11.0 6.5/9.0 7.0/9.0 Pa mPa=S
YP 20.5 22.5 18.5 20.0 Pa Microtox 15 min EC50 105.6% 68.1% 181.9% 148.5%
[%] PASS FAIL PASS PASS
Pass/Fail [00551 Samples E-H were built with no KLA-GARD B, and were used to determine the effectiveness of the KLA-GARD B inhibitor. All samples had 50 kg/m3 of Federal Gel added to simulate reactive solids. The rheology was checked on each sample after 15 minutes of mixing, and again after sitting over-night (20 hours). The results are shown in Table 7 below.
Table 7 Mud Sample #
A E B F C G D H
15 Minutes cP
cP
cP
cP
cP
cP
Gel10s/10m 9.0/12.0 18.0/33.5 9.5/13.0 18.5/29.5 8.0/12.5 16.0/26.5 8.0/11.0 18.0128.0 Pa PATENT APPLICATION
ATTORNEY DOCKET NO. 05542/358001 CLIENT REF. NO. 81057005US01 mPa=s YP 21.5 44.0 23.0 44.5 21.0 41.0 21.0 47.0 Pa 20 Hours cP
cP
cP
I&I
-ICPI
Gel10s/10m 9.5/12.0 20.0/28.5 9.5/13.0 21.0/30.0 8.5/11.5 17.5/26.0 8.5/11.0 18.0/26.0 Pa mPas YP 25.0 57.0 27.0 55.5 22.5 47.0 23.5 50.0 Pa [0056] Similar formulations are compared side by side with and without KLA-GARD B
to show the effectiveness of the inhibitor in preventing hydration of reactive solids.
Samples containing DUOVIS are also shown having thinner high-end rheologies than the samples containing FEDZAN D.
[0057] Embodiments of the present disclosure may provide at least one of the following advantages. The natural amines of the present disclosure may perform as a shale inhibitor to reduce the swelling or hydration of shales during drilling.
Moreover, such additives possess extremely low toxicity and also do not significantly contribute to an increase in the electrical conductivity of the fluid, allowing for broader applicability for land disposal due to environmental concerns for disposal of toxic and/or high conductivity fluids/cuttings.
[0058] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.
Claims (25)
1. A wellbore fluid, comprising:
an aqueous base fluid;
a natural amine having at least one amine group and at least a C3 oleophilic backbone;
and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis.
an aqueous base fluid;
a natural amine having at least one amine group and at least a C3 oleophilic backbone;
and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis.
2. The wellbore fluid of claim 1, wherein the at least one amine group is a primary, secondary, or tertiary amine.
3. The wellbore fluid of claim 1, wherein the natural amine comprises at least two amine groups.
4. The wellbore fluid of claim 1, wherein the oleophilic backbone comprises a linear or branched alkyl, a cyclic alkyl, or a heterocyclic aromatic group.
5. The wellbore fluid of claim 1, wherein the natural amine comprises at least one amino acid or at least one naturally occurring species based on an amino acid.
6. The wellbore fluid of claim 1, wherein natural amine comprises one or more of pantothenic acid, folic acid, biotin, niacin, L-arginine, L-lysine, asparagine, glutamine, histadine, aspartic acid, glutamic acid, or beta-alanine.
7. The wellbore fluid of claim 1, wherein the natural amine has a molecular weight of less than 500.
8. The wellbore fluid of claim 6, wherein the natural amine has a molecular weight of less than 250.
9. The wellbore fluid of claim 1, wherein at least one of the natural amine and the biopolymer viscosifier have an EC50 value of at least 90%.
10. The wellbore fluid of claim 1, wherein at least one of the natural amine and the biopolymer viscosifier cause hormesis in Vibrio fischeri.
11. The wellbore fluid of claim 1, wherein the aqueous base fluid is selected to have an electrical conductivity of no more than 10,000 µS/cm.
12. The wellbore fluid of claim 11, wherein the aqueous base fluid is selected to have an electrical conductivity of less than 3000 µS/cm.
13. The wellbore fluid of claim 1, wherein the aqueous base fluid comprises at least one of fresh water, mixtures of water and water soluble organic compounds and mixtures thereof.
14. A method of drilling, comprising:
circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:
an aqueous base fluid;
a natural amine having at least one amine group and at least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis;
collecting the wellbore fluid and drilled cuttings from the wellbore; and disposing of at least one of the wellbore fluid or drilled cuttings by one of disposed of mix-bury-cover, land-spreading, pump-off, or land-spraying.
circulating a wellbore fluid into a wellbore, the wellbore fluid comprising:
an aqueous base fluid;
a natural amine having at least one amine group and at least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier, wherein the natural amine and the biopolymer viscosifier are present in an amount such that at least 75% of the original concentration of each of the natural amine and the biopolymer results in a 50% decrease in light output of Vibrio fischeri upon exposure to the natural amine and the biopolymer viscosifier or the greatest percentage of effect in light output of Vibrio fischeri is a reduction that is less than a 50% decrease in light output, or the natural amine or biopolymer trigger hormesis;
collecting the wellbore fluid and drilled cuttings from the wellbore; and disposing of at least one of the wellbore fluid or drilled cuttings by one of disposed of mix-bury-cover, land-spreading, pump-off, or land-spraying.
15. The method of claim 14, wherein the at least one amine group is a primary, secondary, or tertiary amine.
16. The method of claim 14, wherein the natural amine comprises at least two amine groups.
17. The method of claim 14, wherein the oleophilic backbone comprises a linear or branched alkyl, a cyclic alkyl, or a heterocyclic aromatic group.
18. The method of claim 14, wherein the natural amine comprises at least one amino acid or at least one naturally occurring species based on an amino acid.
19. The method of claim 14, wherein natural amine comprises one or more of pantothenic acid, folic acid, biotin, niacin, L-arginine, L-lysine, asparagine, glutamine, histadine, aspartic acid, glutamic acid, or beta-alanine.
20. The method of claim 14, wherein the natural amine has a molecular weight of less than 500.
21. The method of claim 20, wherein the natural amine has a molecular weight of less than 250.
22. The method of claim 14, wherein at least one of the natural amine and the biopolymer viscosifier have an EC50 value of at least 90%.
23. The method of claim 14, wherein at least one of the natural amine and the biopolymer viscosifier cause hormesis in Vibrio fischeri.
24. The method of claim 14, wherein the aqueous base fluid is selected to have an electrical conductivity of no more than 10,000 µS/cm.
25
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US201161444380P | 2011-02-18 | 2011-02-18 | |
| US61/444,380 | 2011-02-18 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2768162A1 true CA2768162A1 (en) | 2012-08-18 |
Family
ID=46671147
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2768162 Abandoned CA2768162A1 (en) | 2011-02-18 | 2012-02-15 | Non-toxic, shale inhibitive water-based wellbore fluid |
Country Status (1)
| Country | Link |
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| CA (1) | CA2768162A1 (en) |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2014026003A1 (en) * | 2012-08-09 | 2014-02-13 | Baker Hughes Incorporated | Well treatment fluids containing an ylide or a vitamin b and methods of using the same |
| WO2015073197A1 (en) * | 2013-11-13 | 2015-05-21 | Baker Hughes Incorporated | Method of treating produced or flowback water with nucleophilic agent to deactivate breaker |
| WO2022191862A1 (en) * | 2021-03-11 | 2022-09-15 | Saudi Arabian Oil Company | Drilling fluids and methods of making and using thereof |
-
2012
- 2012-02-15 CA CA 2768162 patent/CA2768162A1/en not_active Abandoned
Cited By (7)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2014026003A1 (en) * | 2012-08-09 | 2014-02-13 | Baker Hughes Incorporated | Well treatment fluids containing an ylide or a vitamin b and methods of using the same |
| US9090814B2 (en) | 2012-08-09 | 2015-07-28 | Baker Hughes Incorporated | Well treatment fluids containing an ylide or a vitamin B and methods of using the same |
| WO2015073197A1 (en) * | 2013-11-13 | 2015-05-21 | Baker Hughes Incorporated | Method of treating produced or flowback water with nucleophilic agent to deactivate breaker |
| US9822594B2 (en) | 2013-11-13 | 2017-11-21 | Baker Hughes, A Ge Company, Llc | Method of treating produced or flowback water with nucleophilic agent to deactivate breaker |
| RU2681326C1 (en) * | 2013-11-13 | 2019-03-06 | Бейкер Хьюз Инкорпорейтед | Method of treating produced or flowback water with nucleophilic agent to deactivate breaker |
| WO2022191862A1 (en) * | 2021-03-11 | 2022-09-15 | Saudi Arabian Oil Company | Drilling fluids and methods of making and using thereof |
| US11807801B2 (en) | 2021-03-11 | 2023-11-07 | Saudi Arabian Oil Company | Drilling fluids and methods of making and using thereof |
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