OA17442A - Alkyl polyglycoside derivative as biodegradable spacer surfactant. - Google Patents

Abstract

A spacer fluid comprising : (a) water; and (b) an alkyl polyglycoside derivative, wherein the alkyl polyglycoside derivative is selected from the group consisting of sorbitan fatty acids; functionalized sulfonates, functionalized betaines, an inorganic salt of any of the foregoing, and any combination of any of the foregoing. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agent. A method of displacing an oil-based drilling mud from a portion of a well comprising the steps of : (A) forming the spacer fluid; and (B) introducing the spacer fluid into the well.

Description

Abrégé :

A spacer fluid comprising : (a) water; and (b) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of sorbitan fatty acids; functionalized sulfonates, functionalized betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agent. A method of displacing an oil-based drilling mud from a portion of a well comprising the steps of : (A) forming the spacer fluid; and (B) introducing the spacer fluid into the well.

Fig. 1

O.A.P.I. - B.P. 887, YAOUNDE (Cameroun) - Tel. (237) 222 20 57 00- Fax: (237) 222 20 57 27- Site web: http:/www.oapi.int - Email: oapi@oapi.int

DEMANDE DE BREVET D’INVENTION

PCT/US2014/011802 DU 16/01/2014

Nom du Déposant(s): HALLIBURTON ENERGY SERVICES, INC.

Titre d’invention:

ALKYL POLYGLYCOSIDE DERIVATIVE AS BIODEGRADABLE SPACER SURFACTANT

Noms d’inventeur(s):

1. MUTHUSAMY, Ramesh

2. DESHPANDE, Abhimanyu Pramod

3. PATIL, Rahul Chandrakant

4. PATIL, Sandip Prbhakar

Mandataire : SCP AKKUM, AKKUM & Associâtes

(12) INTERNATIONAL APPLICATION PUBUSHED UNDER THE PATENT COOPERATION TREATY (PCT)

(19) World Intellectual Property Organization International Bureau (43) International Publication Date 12 September 2014 (12.09.2014)

WIPOIPCT lllIHHlIIIMIIIIIii (10) International Publication Number

WO 2014/137494 Al (51) Interna tien» 1 Patent Classification:

C09K 8/40 (2006.01) E21B 43/22 (2006.01) (21) International Application Number:

PCT/US2014/011802 (22) International Filing Date:

January 2014 (16.01.2014) (25) Filing Language: English (26) Publication Language: English (30) Priority Data:

13/786,227 5 March 2013 (05.03.2013) US (71) Applicant: HALLIBURTON ENERGY SERVICES, INC. [US/USJ; 10200 Bellaire Boulevard, Houston, Texas 77072 (US).

% (72) Inventons·. MUTHUSAMY, Ramcsh; Gururamkrishna Housing Society, Pashan, Pune 411021 (IN). DESHPANDE, Abhimanyu Pramad; Dnyanesh Soc., Pune 411058 (ΓΝ)· PAT1L, Rahul Chandrakant; Tara Residency, Pune 411038 (IN). PATIL, Sandlp Prbhakar, E/4, Gokulnagari, Pimple Gurav, Pune 411027 (IN).

(74) Agent: ALBANESI, Todd E.; Booth Albanesi Schroeder LLC, 1601 Ehn Street, Suite 1950, Dallas, Texas 75201 (US).

(81) Designated States (unless otherwise indicated, for every kind of national protection available): AE, AG, AL, AM, AO, AT, AU, AZ, BA, BB, BG, BH, BN, BR, BW, BY, BZ, CA, CH, CL, CN, CO, CR, CU, CZ, DE, DK, DM, DO, DZ, EC, EE, EG, ES, FI, GB, GD, GE, GH, GM, GT, HN, HR, HU, ID, LL, IN, IR, IS, JP, KE, KG, KN, KP, KR,

KZ, LA, LC, LK, LR, LS, LT, LU, LY, MA, MD, ME,

MG, MK, MN, MW, MX, MY, MZ, NA, NG, NI, NO, NZ, OM, PA, PE, PG, PH, PL, PT, QA, RO, RS, RU, RW, SA, SC, SD, SE, SG, SK, SL, SM, ST, SV, SY, TH, TJ, TM, TN, TR, TT, TZ, UA, UG, US, UZ, VC, VN, ZA, ZM, ZW.

(84) Designated States (unless otherwise indicated, for every kind of régional protection available): ARIPO (BW, GII, GM, KE, LR, LS, MW, MZ, NA, RW. SD, SL, SZ, TZ, UG, ZM, ZW), Eurasian (AM, AZ, BY, KG, KZ, RU, TJ, TM), Européen (AL, AT, BE, BG, CH, CY, CZ, DE, DK, EE, ES, FL FR, GB. GR, HR, HU, IE, IS, ΓΓ, LT, LU, LV, MC, MK, MT, NL, NO, PL, PT, RO, RS, SE, SI, SK, SM, TR), OAPI (BF, BJ, CF, CG, CL CM, GA, GN, GQ, GW, KM, ML, MR, NE, SN, TD, TG).

Published:

— with international search report (Art. 21(3)) (54) Title: ALKYL POLYGLYCOSIDE DERIVATIVE AS BIODEGRADABLE SPACER SURFACTANT

WO 2014/137494 Al (57) Abstract: A spaccr fluid comprising: (a) water; and (b) an alkyl polyglycoside dérivative, wherein the alkyl polyglycosidc dérivative is selected from the group consisting of sorbitan fatty acids; fimctionalized sulfonates, fimctionalized betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoiug. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agpnt. A method of displacing an oil-based driliing mûri from a portion of a well comprising the steps of: (Λ) forming the spacer fluid; and (B) introducing the spacer fluid into the well.

ALKYL POLYGLYCOSIDE DERIVATIVE AS BIODEGRADABLE SPACER SURFACTANT

CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This Application claims priority from U.S. Non-Provisional Patent Application

No. 13/786,227, filed March 05, 2013, entitled “Alkyl Polyglycoside Dérivative as

Biodégradable Spacer Surfactant,” which is hereby incorporated by reference in its entirety.

TECHNICAL FIELD [0002] The inventions are in the field of producing crude oil or natural gas from subterranean formations. More specifically, the inventions generally relate to spacer fluids and methods of displacing an oil-based drilling mud from a well.

BACKGROUND

Oil & Gas Wells [0003] To produce oil or gas from a réservoir, a well is drilled into a subterranean formation, which may be the réservoir or adjacent to the réservoir. Typically, a wellbore of a well must be drilled hundreds or thousands of feet into the earth to reach a hydrocarbon-bearing formation.

[0004] Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completîon, and intervention. Well services are designed to facilitate or enhance the production of désirable fluids such as oil or gas from or through a subterraneaii formation. A well service usually involves introducing a well fluid into a well.

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[0005] Drilling is the process of drilling the wellbore. After a portion of the wellbore is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.

[0006] Cementing is a common well operation. For example, hydraulic cernent compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cernent stabilizes the pipe in the wellbore and prevents undesirable migration of fluids along the annulus between the wellbore and the outside of the casing or liner from one zone along the wellbore to the next. Where the wellbore pénétrâtes into 10 a hydrocarbon-bearing zone of a subterranean formation, the casing can Iater be perforated to allow fluid communication between the zone and the wellbore. The cemented casing also enables subséquent or remédiai séparation or isolation of one or more production zones of the wellbore by using downhole tools, such as packers or piugs, or by using other techniques, such as forming sand plugs or placing cernent in the perforations. Hydraulic cernent compositions can also be 15 utilized in intervention operations, such as in plugging highly permeable zones, or fractures in zones, that may be producing too much water, plugging cracks or holes in pipe strings, and the like.

Cementing and Hydraulic Cernent Compositions [0007] In a cementing operation, a hydraulic cernent, water, and any other components are mixed to form a hydraulic cernent composition in fluid form. The hydraulic cernent composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cernent composition is pumped into the annular space between the exterior surfaces of a pipe string and 25 the borehole (that is, the wall of the wellbore). The hydraulic cernent composition should be a fluid for a sufficient time before setting to allow for pumping the composition into the wellbore and for placement in a desired downhole location in the well. The cernent composition is allowed time to set in the annular space, thereby forming an annular sheath of hardened, substantially imperméable cernent. The hardened cernent supports and positions the pipe string in the wellbore

and fills the annular space between the exterior surfaces of the pipe string and the borehole of the wellbore.

Spacer Fluids [0008] Effective and complété removal of the drillîng mud is required for a successful cernent job. Spacer fluids are used to displace the drillîng fluid from the well before cementing operation. The drillîng fluid can be either water-based or oil-based system.

₍ [0009] In the case of oil-based fluids, it is important to displace them completely from well, otherwise they will contaminate ±e cernent slurry, which can eventually lead to issues such 10 as incompatîbility, poor bonding as well as suppression of compressive strength development.

The presence oil layer over the casing may affect the bonding between the casîng and cernent and lead to formation of micro channels.

[0010] A surfactant is used in a spacer to enhance the compatibility between the spacer and oil-based drillîng fluid. A surfactant also helps to change the interface between the mud and 15 spacer from an oil-extemal émulsion to a water-extemal. In the past, a surfactant package comprising DSS-A (oil soluble), DSS-B (water soluble), and SEM-8 (water soluble) has been used extensively. It is désirable to use fewer surfactants in order to minimize the costs and associated expenses, such as transportation. In addition, there is a need for an environment friendly, salt-tolerant surfactant composition for spacer fluids.

Inorganic Salts in Spacer Fluids [0011] Spacer fluids are often formed with water, seawater, or, for various reasons, inorganic salts such as NaCl or CaCl₂ may be added. It is important that a surfactant for a spacer fluid be compatible for use with seawater or having other inorganic salts dissolved in the water. 25 Not ail surfactants are compatible for use with dissolved salts.

SUMMARY OF THE INVENTION [0012] A spacer fluid is provided, the fluid comprising:

(a) water; and (b) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of sorbitan fatty acids , functionalized sulfonates, functionalized betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agent.

[0013] A method of displacing an oil-based drilling mud from a portion of a well is 10 provided, the method comprising the steps of: (A) forming a spacer fluid according to the invention; and (B) introducing the spacer fluid into the well.

[0014] These and other aspects of the invention will be apparent to one skilled in the art upon reading the following detailed description. While the invention is susceptible to various modifications and alternative forms, spécifie embodiments thereof will be described in detail and 15 shown by way of example. It should be understood, however, that it is not intended to limit the invention to the particular forms disclosed, but, on the contrary, the invention is to cover ail modifications and alternatives falling within the spirit and scope of the invention as expressed in the appended claims.

BRIEF DESCRIPTION OF THE DRAWING [0015] The accompanying drawing is incorporated into the spécification to help illustrate examples according to the presently most-preferred embodiment of the invention.

[0016] Figure 1 is a représentative chemical structure of a sorbitan oleate polyglucoside, which is an example of the class of polyglycoside dérivatives for use in a spacer 25 fluid according to the invention.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODE

Définitions and Usages

General Interprétation [0017] The words or terms used herein hâve their plain, ordinary meaning in the field of this disclosure, except to the extent explicitly and clearly defîned in this disclosure or unless the spécifie context otherwise requires a different meaning.

[0018] If there is any conflict in the usages of a word or term in this disclosure and one 10 or more patent(s) or other documents that may be incorporated by reference, the définitions that are consistent with this spécification should be adopted.

[0019] The words “comprising,” “containing,” “including,” “having,” and ail grammatical variations thereof are intended to hâve an open, non-limiting meaning. For example, a composition comprising a component does not exclude it from having additional components, 15 an apparatus comprising a part does not exclude it from having additional parts, and a method having a step does not exclude it having additional steps. When such terms are used, the *

compositions, apparatuses, and methods that “consist essentially of ’ or “consist of ’ the specified components, parts, and steps are specifically included and disclosed.

[0020] The indefinite articles “a” or “an” mean one or more than one of the component, 20 part, or step that the article introduces.

[0021] Whenever a numerical range of degree or measurement with a lower limit and an upper limit is disclosed, any number and any range falling within the range is also intended to be specifically disclosed. For example, every range of values (in the form “from a to b,” or “from about a to about b, or “from about a to b,” “from approximately a to b,” and any similar 25 expressions, where “a” and “b” represent numerical values of degree or measurement) is to be understood to set forth every number and range encompassed within the broader range of values.

[0022] It should be understood that algebraic variables and other scientific symbols used herein are selected arbitrarily or according to convention. Other algebraic variables can be used.

^v [0023] Terms such as “first,” “second,” “third,” etc. are assigned arbitrarily and are merely intended to differentiate between two or more components, parts, or steps that are otherwise similar or corresponding in nature, structure, function, or action. For example, the words “first” and “second” serve no other purpose and are not part of the name or description of the following name or descriptive terms. The mere use of the term “first” does not require that there be any “second” similar or corresponding component, part, or step. Similarly, the mere use of the word “second” does not require that there by any “first” or “third” similar or corresponding component, part, or step. Further, it is to be understood that the mere use of the term “first” does not require that the element or step be the very first in any sequence, but merely I0 that it is at least one of the éléments or steps. Similarly, the mere use of the terms “first” and “second” does not necessarily require any sequence. Accordingly, the mere use of such terms does not exclude intervening éléments or steps between the “first” and “second” éléments or steps, etc.

[0024] The control or controlling of a condition includes any one or more of 15 maintaining, applying, or varying of the condition. For example, controlling the température of a substance can include heating, cooling, or thermally insulating the substance.

Oil and Gas Réservoirs [0025] In the context of production from a well, “oil” and “gas” are understood to refer 20 to crude oil and natural gas, respectively. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.

[0026] A “subterranean formation” is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it.

[0027] A subterranean formation having a sufficient porosity and permeabilîty to store 25 and transmit fluids is sometimes referred to as a “réservoir.” [0028] A subterranean formation containing oil or gas may be located under Iand or under the seabed off shore. Oil and gas réservoirs are typically located in the range of a few hundred feet (shallow réservoirs) to a few tens of thousands of feet (ultra-deep réservoirs) below the surface of the Iand or seabed.

Well Servîcing and Well Fluids [0029] To produce oil or gas from a réservoir, a wellbore is drilled into a subterranean formation, which may be the réservoir or adjacent to the réservoir.

[0030] Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completîon, and intervention. Well services are designed to facilitate or enhance the production of désirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.

[0031] Drilling is the process of drilling the wellbore. After a portion of the wellbore is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.

[0032] Cementing is a common well operation. For example, hydraulic cernent 15 compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cernent stabilizes the pipe in the wellbore and prevents undesirable migration of fluids along the annulus between the wellbore and the outside of the casing or liner from one zone along the wellbore to the next. Where the wellbore pénétrâtes into a hydrocarbon-bearing zone of a subterranean formation, the casing can later be perforated to 20 allow fluid communication between the zone and the wellbore. The cemented casing also enables subséquent or remédiai séparation or isolation of one or more production zones of the wellbore by using downhoie tools, such as packers or plugs, or by using other techniques, such as forming sand plugs or placîng cernent in the perforations. Hydraulic cernent compositions can also be utilized in intervention operations, such as in plugging highly permeable zones, or fractures in 25 zones, that may be producing too much water, plugging cracks or holes in pipe strings, and the like.

[0033] Completîon is the process of making a well ready for production or injection. This princîpally involves preparing a zone of the wellbore to the required spécifications, running

in the production tubing and associated downhole equipment, as well as perforating and stimulating as required, [0034] Intervention is any operation carried out on a well during or at the end of its productive life that alters the state of the well or well geometry, provides well diagnostics, or 5 manages the production of the well.

[0035] Workover can broadly refer to any kind of well intervention that involves invasive techniques, such as wireline, coiled tubing, or snubbing. More specifically, however, workover usually refers to a process of pulling and replacing a completion.

Well Terms [0036] A “well” includes a wellhead and at least one wellbore from the wellhead penetrating the earth. The “wellhead” is the surface termination of a wellbore, which surface may be on land or on a seabed.

[0037] A “well site” is the geographical location of a wellhead of a well. It may include 15 related facilities, such as a tank battery, separators, compressor stations, heating or other equipment, and fluid pits. If offshore, a well site can include a platform.

[0038] The “wellbore” refers to the drilled hole, including any cased or uncased portions of the well or any other tubulars in the well. The “borehole” usually refers to the inside wellbore wall, that is, the rock surface or wall that bounds the drilled hole. A wellbore can hâve 20 portions that are vertical, horizontal, or anything in between, and it can hâve portions that are straight, curved, or branched. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.

[0039] A wellbore can be used as a production or injection wellbore. A production 25 wellbore is used to produce hydrocarbons from the réservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.

[0040] As used herein, introducing “into a well” means introducing at least into and through the wellhead. According to various techniques known in the art, tubulars, equipment, tools, or well fluids can be directed from the wellhead into any desired portion of the wellbore.

[0041] As used herein, the word “tubular” means any kind of structural body in the general form of a tube. Examples of tabulais include, but are not limited to, a drill pipe, a casing, a tabing string, a line pipe, and a transportation pipe. Tubulars can also be used to transport fluids such as oil, gas, water, liquefied mcthane, coolants, and heated fluids into or out of a 5 subterranean formation. For example, a tubular can be placed underground to transport produced hydrocarbons or water from a subterranean formation to another location. Tubulars can be of any suitable body material, but in the oilfield they are most commonly of steel.

[0042] As used herein, the term “annulus” means the space between two generally cylindrical objects, one inside the other. The objects can be concentric or eccentric. Without 10 limitation, one of the objects can be a tubular and the other object can be an enclosed conduit.

The enclosed conduit can be a wellbore or borehole or it can be another tubular. The following are some non-Iimiting examples illustrating some situations in which an annulus can exist. Referring to an oil, gas, or water well, in an open hole well, the space between the outside of a tabing string and the borehole of the wellbore is an annulus. In a cased hole, the space between 15 the outside of the casing and the borehole is an annulus. In addition, in a cased hole there may be an annulus between the outside cylindrical portion of a tubular such as a production tubing string and the inside cylindrical portion of the casing. An annulus can be a space through which a fluid can flow or it can be filled with a material or object that blocks fluid flow, such as a packing element. Unless otherwise clear from the context, as used herein an “annulus” is a space through 20 which a fluid can flow.

[0043] As used herein, a “well fluid” broadly refers to any fluid adapted to be introduced into a well for any purpose. A well fluid can be, for example, a drilling fluid, a setting composition, a treatment fluid, or a spacer fluid. If a well fluid is to be used in a relatively small volume, for example less than about 200 barrels (about 8,400 US gallons or about 32 m³), it is 25 sometimes referred to as a wash, dump, slug, orpill.

[0044] Drilling fluids, also known as drilling muds or simply “muds,” are typically classified according to their base fluid, that is, the nature of the continuous phase. A water-based mud (“WBM”) has a water phase as the continuous phase. The water can be brine. A brine-based drilling fluid is a water-based mud in which the aqueous component is brine. In some cases, oil

may be emulsified in a water-based drilling mud. An oil-based mud (“OBM”) has an oil phase as the continuous phase. In some cases, a water phase is emulsified in the oil-based mud.

[0045] As used herein, the word “treatment” refers to any treatment for changing a condition of a portion of a pipeline, a wellbore, or a subterranean formation adjacent a wellbore;

however, the word “treatment” does not necessarily imply any particular treatment purpose. A treatment usually involves introducing a well fluid for the treatment, in which case it may be referred to as a treatment fluid, into a well. As used herein, a “treatment fluid” is a well fluid used in a treatment. The word “treatment” in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid.

[0046] As used herein, the ternis spacer fluid, wash fluid, and inverter fluid can be used interchangeably. A spacer fluid is a fluid used to physically separate one special-purpose fluid from another. It may be undesirable for one special-purpose fluid to mix with another used in the well, so a spacer fluid compatible with each is used between the two. A spacer fluid is usually used when changing between well fluids used in a well.

[0047] For example, a spacer fluid is used to change from a drilling fluid during drilling to cementing composition during cementing operations in the well. In case of an oil-based drilling fluid, it should be kept separate from a water-based cementing fluid. In changing to the latter fluid, a chemically treated water-based spacer fluid is usually used to separate the drilling fluid from the water-based cementing fluid.

[0048] A spacer fluid specially designed to separate a spécial purpose oil-extemal fluid from a spécial purpose water-extemal fluid may be termed as an inverter fluid. Inverter fluids may be so designed that the diffused contaminated layer between both the spécial purpose fluids has progressive variation in properties like solids carrying capability, electrical conductivity, rheology, and chemical potential. In other words, inverter fluids may be ideally designed to be fully compatible physically and chemically with either or both of the spécial purpose fluids under the simulated conditions of pressure, température and shear. Compatibility may be warranted by rheological investigations or visual observations at ail intermediate compositions. Unwanted flocculation, coagulation, or excessive thinning of the admixture compared to the original fluids is typically considered to be a signature for incompatibility.

[0049] Volumes of spacer fluid that are consumed in channel lengths due to contamination process are not sufficient to clean wellbore surfaces or change wettability. These volumes should be considered sacrificial and the amount of pure uncontaminated spacer is estimated from surface wettability techniques.

[0050] A “portion” of a well, tubular, or pipeline refers to any downhole portion of the well or any portion of the length of a pipeline or any portion of a tubular, as the case may be.

[0051] A “zone” refers to an interval of rock along a wellbore that is differentiated from uphole and downhole zones based on hydrocarbon content or other features, such as permeability, composition, perforations or other fluid communication with the wellbore, faults, 10 or fractures. A zone of a wellbore that pénétrâtes a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a “production zone.” A “treatment zone” refera to an interval of rock along a wellbore into which a well fluid is directed to flow from the wellbore. As used herein, “into a treatment zone” means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.

[0052] As used herein, a “downhole” fluid (or gel) is an in-situ fluid in a well, which may be the same as a well fluid at the time it is introduced, or a well fluid mixed with another fluid downhole, or a fluid in which chemical reactions are occurring or hâve occurred in-situ downhole.

[0053] Fluid loss refers to the undesirable leakage of a fluid phase of any type of well 20 fluid into the permeable matrix of a zone, which zone may or may not be a treatment zone. Fluidloss control refers to treatments designed to reduce such undesirable leakage.

[0054] Generally, the greater the depth of the formation, the higher the static température and pressure of the formation. Initially, the static pressure equals the initial pressure in the formation before production. After production begins, the static pressure approaches the 25 average réservoir pressure.

[0055] Deviated wells are wellbores inclined at various angles to the vertical. Complex wells include inclined wellbores in high-temperature or high-pressure downhole conditions.

[0056] A “design” refers to the estimate or measure of one or more parameters planned or expected for a particular fluid or stage of a well service or treatment. For example, a fluid can

be designed to hâve components that provide a minimum density or viscosîty for at least a specified time under expected downhole conditions. A well service may include design parameters such as fluid volume to be pumped, required pumping time for a treatment, or the shear conditions of the pumping.

[0057] The term “design température” refers to an estimate or measurement of the actual température at the downhole environment during the time of a treatment. For example, the design température for a well treatment takes into account not only the bottom hole static température (“BHST”), but also the effect of the température of the well fluid on the BHST during treatment. The design température for a well fluid is sometimes referred to as the bottom 10 hole circulation température (“BHCT”). Because well fluids may be considerably cooler than BHST, the différence between the two températures can be quite large. Ultimately, if left undisturbed, a subterranean formation will retum to the BHST.

[0058] Two fluids are incompatible if undesîrable physical or chemical interactions occur when the fluids are mixed. Incompatibility is characterized by undesîrable changes in 15 apparent viscosity and shear stresses. When apparent viscosîty of the mixed fluids is greater than apparent viscosity of each individual fluid, they are said to be incompatible at the tested shear rate.

Substances, Chemicals, and Dérivatives [0059] A substance can be a pure chemical or a mixture of two or more different chemicals.

[0060] As used herein, a “polymer” or “polymeric material” includes polymers, copolymers, terpolymers, etc. In addition, the term “copolymer” as used herein is not limited to the combination of polymers having two monomeric units, but includes any combination of 25 monomeric units, e.g., terpolymers, tetrapolymers, etc.

[0061] As used herein, “modified” or “dérivative” means a chemical compound formed by a chemical process from a parent compound, wherein the chemical backbone skeleton of the parent compound is retained in the dérivative. The chemical process preferably includes at most a few chemical reaction steps, and more preferably only one or two chemical reaction steps. As

used herein, a “chemical reaction step” is a chemical reaction between two chemical reactant species to produce at least one chemically different species from the reactants (regardless of the number of transient chemical species that may be formed during the reaction). An example of a chemical step is a substitution reaction. Substitution on the reactive sites of a poiymeric material 5 may be partial or complété.

Physical States and Phases [0062] As used herein, “phase” is used to refer to a substance having a chemical composition and physical state that is distinguishable from an adjacent phase of a substance 10 having a different chemical composition or a different physical state.

[0063] As used herein, if not other otherwise specifically stated, the physical state or phase of a substance (or mixture of substances) and other physical properties are determined at a température of 77 °F (25 °C) and a pressure of 1 atmosphère (Standard Laboratory Conditions) without applied shear.

Particles and Particulates [0064] As used herein, a “particle” refers to a body having a finite mass and suffîcient cohésion such that it can be considered as an entity but having relatively small dimensions. A particle can be of any size ranging from molecular scale to macroscopie, depending on context.

[0065] A particle can be in any physical state. For example, a particle of a substance in a solid state can be as small as a few molécules on the scale of nanometers up to a large particle on the scale of a few millimeters, such as large grains of sand. Similarly, a particle of a substance in a liquid state can be as small as a few molécules on the scale of nanometers up to a large drop on the scale of a few millimeters. A particle of a substance in a gas state is a single atom or molécule that is separated from other atoms or molécules such that întermolecular attractions hâve relatively little effect on their respective motions.

[0066] As used herein, particulate or particulate material refers to matter in the physical form of distinct particles in a solid or liquid state (which means such an association of a few atoms or molécules). As used herein, a particulate is a grouping of particles having similar

chemical composition and particle size ranges anywhere in the range of about 0.5 micrometer (500 nm), e.g., microscopie clay particles, to about 3 millimeters, e.g., large grains of sand.

[0067] A partîculate can be of solid or liquid particles. As used herein, however, unless the context otherwise requires, partîculate refers to a solid partîculate. Of course, a solid 5 partîculate is a partîculate of particles that are in the solid physical state, that is, the constituent atoms, ions, or molécules are suffïciently restricted in their relative movement to resuit in a fixed shape for each of the particles.

Dispersions [0068] A dispersion is a system in which particles of a substance of one chemical composition and physical state are dispersed in another substance of a different chemical composition or physical state. In addition, phases can be nested. If a substance has more than one phase, the most extemal phase is referred to as the continuous phase of the substance as a whole, regardless of the number of different internai phases or nested phases.

[0069] A dispersion can be classifïed in different ways, including, for example, based on the size of the dispersed particles, the uniformity or lack of uniformity of the dispersion, and, if a fluid, by whether or not précipitation occurs.

Classification of Dispersions: Heterogeneous and Homogeneous [0070] A dispersion is considered to be heterogeneous if the dispersed particles are not dissolved and are greater than about 1 nanometer in size. (For reference, the diameter of a molécule of toluène is about 1 nm and a molécule of water is about 0.3 nm).

[0071] Heterogeneous dispersions can hâve gas, liquid, or solid as an extemal phase. For example, in a case where the dispersed-phase particles are liquid in an extemal phase that is 25 another liquid, this kind of heterogeneous dispersion is more particulariy referred to as an émulsion. A solid dispersed phase in a continuous liquid phase is referred to as a sol, suspension, or slurry, partly depending on the size of the dispersed solid partîculate.

[0072] A dispersion is considered to be homogeneous if the dispersed particles are dissolved in solution or the particles are less than about 1 nanometer in size. Even if not

dissolved, a dispersion is considered to be homogeneous if the dispersed particles are less than about 1 nanometer in size.

Classification of Heterogeneous Dispersions: Suspensions and Colloids [0073] Heterogeneous dispersions can be further classifïed based on the dispersed particle size.

[0074] A heterogeneous dispersion is a “suspension” where the dispersed particles are larger than about 50 micrometers. Such particles can be seen with a microscope, or if larger than about 50 micrometers (0.05 mm), with the unaided human eye. The dispersed particles of a 10 suspension in a liquid extemal phase may eventually separate on standing, e.g., settle in cases where the particles hâve a higher density than the liquid phase. Suspensions having a liquid extemal phase are essentially unstable from a thermodynamic point of view; however, they can be kinetically stable over a long period depending on température and other conditions.

[0075] A heterogeneous dispersion is a “colloid” where the dispersed particles range up 15 to about 50 micrometer (50,000 nanometers) in size. The dispersed particles of a colloid are so small that they settle extremely slowly, if ever. In some cases, a colloid can be considered as a homogeneous mixture. This is because the distinction between “dissolved” and “particulate” matter can be sometimes a matter of theoretical approach, which affects whether or not it is considered homogeneous or heterogeneous.

Classification of Homogeneous Dispersions: Solutions [0076] A solution is a spécial type of homogeneous mixture. A solution is considered homogeneous: (a) because the ratio of soluté to solvent is the same throughout the solution; and (b) because soluté will never settle out of solution, even under powerful centrifugation, which is 25 due to intermolecular attraction between the solvent and the soluté. An aqueous solution, for example, saltwater, is a homogenous solution in which water is the solvent and sait is the soluté.

[0077] One may also refer to the solvated state, in which a soluté ion or molécule is complexed by solvent molécules. A chemical that is dissolved in solution is in a solvated state. The solvated state is distinct from dissolution and solubility. Dissolution is a kinetic process, and

is quantîfied by its rate. Solubility quantifies the concentration of the soluté at which there is dynamic equilibrium between the rate of dissolution and the rate of précipitation of the soluté. Dissolution and solubility can be dépendent on température and pressure, and may be dépendent on other factors, such as salinity or pH of an aqueous phase.

Hydratability or Solubility [0078] As referred to herein, “hydratable” means capable of being hydrated by contacting the hydratable agent with water. Regarding a hydratable agent that includes a polymer, this means, among other things, to associate sites on the polymer with water molécules 10 and to unravel and extend the polymer chain in the water.

[0079] A substance is considered to be “soluble” in a liquid if at least 10 grams of the substance can be hydrated or dissolved in one liter of the liquid (which is at least 83 ppt) when tested at 77 °F and 1 atmosphère pressure for 2 hours, considered to be “insoluble” if less than 1 gram per liter (which is less than 8.3 ppt), and considered to be sparingly soluble” for 15 intermediate solubility values.

[0080] As will be appreciated by a person of skill in the art, the hydratability, dispersibility, or solubility of a substance in water can be dépendent on the salinity, pH, or other substances in the water. Accordingly, the salinity, pH, and addîtive sélection of the water can be modified to facilitate the hydratability, dispersibility, or solubility of a substance în aqueous 20 solution. To the extent not specified, the hydratability, dispersibility, or solubility of a substance in water is determined in deionized water, at neutral pH, and without any other additives.

[0081] As used herein, the term “polar” means having a dielectric constant greater than 30. The term “relatively polar” means having a dielectric constant greater than about 2 and less than about 30. “Non-polar” means having a dielectric constant less than 2.

Fluids [0082] A fluid can be a single phase or a dispersion. In general, a fluid is an amorphous substance that is or has a continuous phase of particles that are smaller than about 1 micrometer that tends to flow and to conform to the outline of its container.

[0083] Examples of fluids are gases and liquids. A gas (in the sense of a physical state) refers to an amorphous substance that has a high tendency to disperse (at the molecular level) and a relatively high compressibility. A liquid refers to an amorphous substance that has little tendency to disperse (at the molecular level) and relatively high incompressibility. The tendency 5 to disperse is related to Intermolecular Forces (also known as van der Waal’s Forces). (A continuous mass of a particulate, e.g., a powder or sand, can tend to flow as a fluid depending on many factors such as particle size distribution, particle shape distribution, the proportion and nature of any wetting liquid or other surface coating on the particles, and many other variables. Nevertheless, as used herein, a fluid does not refer to a continuous mass of particulate as the 10 sizes of the solid particles of a mass of a particulate are too large to be appreciably affected by the range of Intermolecular Forces.) [0084] Every fluid inherently has at least a continuous phase. A fluid can hâve more than one phase. The continuous phase of a well fluid is a liquid under Standard Laboratory Conditions. For example, a well fluid can be in the form of a suspension (larger solid particles 15 dispersed in a liquid phase), a sol (smaller solid particles dispersed in a liquid phase), an émulsion (liquid particles dispersed in another liquid phase), or a foam (a gas phase dispersed in a liquid phase).

[0085] The continuous phase of a fluid characterizes its relative permittivity. Permittivity is a measure of the ability of a material to be polarized by an electric field. The 20 dielectric constant of a material is the ratio of its permittivity to the permittivity of vacuum. The dielectric constant is therefore also known as the relative permittivity of the material.

[0086] As used herein, a “water-based” fluid means that water or an aqueous solution is the dominant material of the continuous phase, that is, greater than 50% by weight, of the continuous phase of the fluid based on the combined weight of water and any other solvents in 25 the phase (that is, excluding the weight of any dissolved solids).

[0087] In contrast, an “oil-based” fluid means that oil is the dominant material by weight of the continuous phase of the fluid. In this context, the oil of an oil-based fluid can be any oil.

[0088] In the context of a well fluid, ou is understood to refer to an oil liquid, whereas gas is understood to refer to a physical state of a substance, in contrast to a liquid. In this context, an oil is any substance that is liquid under Standard Laboratory Conditions, is hydrophobie, and soluble in organic solvents. Oils hâve a high carbon and hydrogen content and are non-polar substances. This general définition includes classes such as petrochemical oils, vegetable oils, and many organic solvents. Ail oils can be traced back to organic sources.

Apparent Viscosity of a Fluid [0089] Viscosity is a measure of the résistance of a fluid to flow. In everyday terms, viscosity is “thickness” or “internai friction.” Thus, pure water is “thin,” having a relatively low viscosity whereas honey is “thick,” having a relatively higher viscosity. Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). More precisely, viscosity is defîned as the ratio of shear stress to shear rate.

[0090] A fluid moving along solid boundary will incur a shear stress on that boundary. The no-slip condition dictâtes that the speed of the fluid at the boundary (relative to the boundary) is zéro, but at some distance from the boundary the flow speed must equal that of the fluid. The région between these two points is aptly named the boundary layer. For ail Newtonian fluids in laminar flow, the shear stress is proportional to the strain rate in the fluid where the viscosity is the constant of proportionality. However for non-Newtonian fluids, this is no longer the case as for these fluids the viscosity is not constant. The shear stress is imparted onto the boundary as a resuit of this loss of velocity.

[0091] A Newtonian fluid (named after Isaac Newton) is a fluid for which stress versus strain rate curve is linear and passes through the origin. The constant of proportionality is known as the viscosity. Examples of Newtonian fluids include water and most gases. Newton’s law of viscosity is an approximation that holds for some substances but not others.

[0092] Non-Newtonian fluids exhibit a more complîcated relationship between shear stress and velocity gradient (i.e., shear rate) than simple linearity. Thus, there exist a number of forms of non-Newtonian fluids. Shear thickening fluids hâve an apparent viscosity that increases wîth increasing the rate of shear. Shear thinning fluids hâve a viscosity that decreases with

increasing rate of shear. Thixotropic fluids become less viscous over time at a constant shear rate. Rheopectic fluids become more viscous over time at a constant shear rate. A Bingham plastic is a material that behaves as a solid at low stresses but flows as a viscous fluid at high yield stresses.

[0093] Most well fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. As used herein, a reference to viscosity is actually a reference to an apparent viscosity. Apparent viscosity is commonly expressed in units of mPa*s or centipoise (cP), which are équivalent.

[0094] Like other physical properties, the viscosity of a Newtonian fluid or the apparent viscosity of a non-Newtonian fluid may be highly dépendent on the physical conditions, primarily température and pressure.

Viscosity and Gel Measurements [0095] There are numerous ways of measuring and modeling viscous properties, and new developments continue to be made. The methods dépend on the type of fluid for which viscosity is being measured. A typical method for quality assurance or quality control (QA/QC) purposes uses a couette device, such as a FANN™ Model 35 or Model 50 viscometer or a CHANDLER™ 5550 HPHT viscometer. Such a viscometer measures viscosity as a function of 20 time, température, and shear rate. The viscosity-measuring instrument can be calibrated using standard viscosity silicone oils or other standard viscosity fluids.

[0096] Due to the geometry of most common viscosity-measuring devices, however, solid particulate, especially if larger than silt (larger than 74 micron), would interfère with the measurement on some types of measuring devices. Therefore, the viscosity of a fluid containing 25 such solid particulate is usually inferred and estimated by measuring the viscosity of a test fluid that is similar to the fracturing fluid without any proppant or gravel that would otherwise be included. However, as suspended particles (which can be solid, gel, liquid, or gaseous bubbles) usually affect the viscosity of a fluid, the actual viscosity of a suspension is usually somewhat different from that of the continuons phase.

[0097] Unless otherwise specified, the apparent viscosity of a fluid (cxcluding any suspended solid particulate larger than silt) is measured with a FANN™ Model 35 type viscometer using an RI rotor, B1 bob, and Fl torsion spring at a shear rate of 40 1/s, and at a température of 77 °F (25 °C) and a pressure of 1 atmosphère.

[0098] A substance is considered to be a fluid if it has an apparent viscosity less than

5,000 mPa*s (5,000 cP) (independent of any gel characteristic). For reference, the viscosity of pure water is about 1 mPa*s (1 cP).

General Measurement Terms [0099] Unless otherwise specified or unless the context otherwise clearly requires, any ratio or percentage means by weight.

[0100] Unless otherwise specified or unless the context otherwise clearly requires, the phrase “by weight of the water” means the weight of the water of an aqueous phase of the fluid without the weight of any viscosîty-increasing agent, dissolved sait, suspended particulate, or 15 other materials or additives that may be présent in the water.

[0101] As used herein, “%wt/vol” means the mass-volume percentage, sometimes referred to as weight-volume percentage or percent weight per volume and often abbreviated as % m/v or % w/v, which describes the mass of the soluté in g per 100 mL of the liquid. Massvolume percentage is often used for solutions made from a solid soluté dissolved in a liquid. For 20 example, a 40% w/v sugar solution contains 40 g of sugar per 100 mL of liquid.

[0102] If there is any différence between U.S. or Impérial units, U.S. units are intended.

[0103] Unless otherwise specified, mesh sizes are in U.S. Standard Mesh.

[0104] The micrometer (pm) may sometimes be referred to herein as a micron.

[0105] The conversion between pound per gallon (Ib/gal or ppg) and kilogram per cubic 25 meter (kg/m³) is: 1 lb/gal = (0.4536 kg/lb) x (gal/0.003785 m³) = 120 kg/m³.

Emulsions [0106] An émulsion is a fluid including a dispersion of immiscible liquid particles in an external liquid phase. In addition, the proportion of the external and internai phases is above the

solubilïty of either in the other. A chemical can be included to reduce the interfacial tension between the two inuniscible liquids to help with stability against coalescing of the internai liquid phase, in which case the chemical may be referred to as a surfactant or more particularly as an emulsifier or emulsifying agent.

[0107] In the context of an émulsion, a “water phase” refers to a phase of water or an aqueous solution and an “oil phase” refers to a phase of any non-polar, organic liquid that is inuniscible with water, usually an oil.

[0108] An émulsion can be an oil-in-water (o/w) type or water-in-oil (w/o) type. A water-in-oil émulsion is sometimes referred to as an invert émulsion.

[0109] A stable émulsion is an émulsion that will not cream, flocculate, or coalesce under certain conditions, including time and température. As used herein, the term “cream” means at least some of the droplets of a dispersed phase converge towards the surface or bottom of the émulsion (depending on the relative densities of the liquids making up the continuous and dispersed phases). The converged droplets maintain a discrète droplet form. As used herein, the 15 term “flocculate” means at least some of the droplets of a dispersed phase combine to form small aggregates in the émulsion. As used herein, the term “coalesce” means at least some of the droplets of a dispersed phase combine to form larger drops in the émulsion.

Surfactants [0110] Surfactants are compounds that lower the surface tension of a liquid, the interfacial tension between two liquids, or that between a liquid and a solid, or that between a liquid and a gas. Surfactants may act as détergents, wetting agents, emulsifiers, foaming agents, and dispersants.

[0111] Surfactants are usually organic compounds that are amphiphilic, meaning they contain both hydrophobie groups (“tails”) and hydrophilic groups (“heads”). Therefore, a surfactant contains both a water-insoluble (or oil soluble) portion and a water-soluble portion.

[0112] A surfactant package can include one or more different chemical surfactants.

[0113] In a water phase, surfactants form aggregates, such as micelles, where the hydrophobie tails form the core of the aggregate and the hydrophilic heads are in contact with the

surrounding liquid. The aggregates can be formed in various shapes such as spherical or cylindrical micelles or bilayers. The shape of the aggregation dépends upon various factors such as the chemical structure of the surfactant (e.g., the balance of the sizes of the hydrophobie tail and hydrophilic head), the concentration of the surfactant, nature of counter ions, ionic sait concentration, co-surfactants, solubilized components (if any), pH, and température.

[0114] As used herein, the term mîcelle includes any structure that minimizes the contact between the lyophobic (“solvent-repelling”) portion of a surfactant molécule and the solvent, for example, by aggregating the surfactant molécules into structures such as sphères, cylinders, or sheets, wherein the lyophobic portions are on the interior of the aggregate structure and the lyophilic (“solvent-attracting”) portions are on the exterior of the structure. Micelles can function, among other purposes, to stabilize émulsions, break émulsions, stabilize foam, change the wettability of a surface, or solubilize certain materials.

Emulsifiers [0115] As used herein, an “emulsifier” refers to a type of surfactant that helps prevent the droplets of the dispersed phase of an émulsion from flocculating or coalescing in the émulsion. As used herein, an emulsifier refers to a chemical or mixture of chemicals that helps prevent the droplets of the dispersed phase of an émulsion from flocculating or coalescing in the émulsion. As used herein, an “emulsifier” or “emulsifying agent” does not mean or include a hydrophobie particulate.

[0116] An emulsifier can be or include a cationic, a zwitterionic, or a nonionic emulsifier.

[0117] The hydrophilic-lipophilic balance (“HLB”) of a surfactant is a measure of the degree to which it is hydrophilic or lipophilie, determined by calculating values for the different régions of the molécule, as described by Griffin in 1949 and 1954. Other methods hâve been suggested, notably in 1957 by Davies.

[0118] In general, Grifïïn’s method for non-ionic surfactants as described in 1954 works as follows:

HLB = 20*Mh/M where Mh is the molecular mass of the hydrophilic portion of the molécule, and M is the molecular mass of the whole molécule, giving a resuit on a scale of 0 to 20. An HLB value of 0 5 corresponds to a completely lipidphilic/hydrophobic molécule, and a value of 20 corresponds to a completely hydrophilic/lypidphobic molécule. Griffîn WC: “Classification of Surface-Active Agents by ‘HLB,’” Journal of the Society of Cosmetic Chemists 1 (1949): 311. Griffin WC: “Calculation of HLB Values of Non-Ionic Surfactants,” Journal of the Society of Cosmetic Chemists 5 (1954): 249.

[0119] The HLB (Griffin) value can be used to predict the surfactant properties of a molécule, where a value less than 10 indicates that the surfactant molécule is lipid soluble (and water insoluble), whereas a value greater than 10 indicates that the surfactant molécule is water soluble (and lipid insoluble).

[0120] In addition, the HLB (Griffin) value can be used to predict the uses of the 15 molécule, where: a value from 4 to 8 indicates an anti-foaming agent, a value from 7 to 11 indicates a W/O (water in oil) emulsifîer, a value from 12 to 16 indicates O/W (oil in water) emulsifîer, a value from 11 to 14 indicates a wetting agent, a value from 12 to 15 indicates a detergent, and a value of 16 to 20 indicates a solubiliser or hydrotrope.

[0121] An emulsifîer can be or include a cationic, a zwitterionic, or a nonionic 20 emulsifîer. A emulsifîer package can include one or more different chemical emulsifîers.

[0122] An emulsifîer or emulsifîer package is preferably in a concentration of at least 1% by weight of the water of the émulsion. More preferably, the emulsifîer is in a concentration in the range of 1 % to 10% by weight of the water.

Emulsifier [0123] As used herein, an emulsifîer refers to a substance that helps prevent the droplets of the dispersed phase of an émulsion from flocculating or coalescing in the émulsion.

[0124] An emulsifier can be or include a cationic, a zwitterionic, or a nonionic emulsifier. A emulsifier package can include one or more different chemical emulsifîers.

[0125] The emulsifier is preferably in a concentration of at least 1% by weight of the water of the émulsion. More preferably, the emulsifier is in a concentration in the range of 1% to 10% by weight of the water.

[0126] The émulsion can also include other additives. For example, the émulsion can contain a freezing-point depressant. More preferably, the freezing point depressant is for the water of the continuons phase. Preferably, the freezing-point depressant is selected from the group consisting of water soluble ionic salts, alcohols, glycols, urea, and any combination thereof in any proportion.

[0127] The émulsion can also contain water-soluble salt(s) at a high-ionic strength for 10 other purposes, for example, to increase the density of the continuons phase of the émulsion. Preferably, the water-soluble sait is selected from the group consisting of: an alkali métal halide, alkaline earth métal halide, alkali métal formate, and any combination thereof.

[0128] Preferably, an émulsion should be stable under one or more of certain conditions commonly encountered in the storage and use of such an émulsion composition for a well 15 treatment operation.

Biodegradability [0129] Biodégradable means the process by which complex molécules are broken down by micro-organisms to produce simpler compounds. Biodégradation can be either aérobic (with 20 oxygen) or anaérobie (without oxygen). The potential for biodégradation is commonly measured on well fluids or their components to ensure that they do not persist in the environment. A variety of tests exist to assess biodégradation.

[0130] As used herein, a substance is considered “biodégradable” if the substance passes a ready biodegradability test or an inhérent biodegradability test. It is preferred that a 25 substance is first tested for ready biodegradability, and only if the substance does not pass at least one of the ready biodegradability tests then the substance is tested for inhérent biodegradability, [0131] In accordance with Organisation for Economie Co-operation and Development (“OECD”) guidelines, the following six tests permit the screening of chemicals for ready

biodegradability. As used herein, a substance showing more than 60% biodegradability in 28 days according to any one of the six ready biodegradability tests is considered a pass level for classifying it as “readily biodégradable,” and it may be assumed that the substance will undergo rapid and ultimate dégradation in the environment. The six ready biodegradability tests are:

(1) 301A: DOC Die-Away; (2) 301B: CO2 Evolution (Modified Sturm Test); (3) 301C: ΜΓΠ (I) (Mînistry of International Trade and Industry, Japan); (4) 30ID: Closed Bottle; (5) 301E: Modified OECD Screening; and (6) 301F: Manometric Respirometry. The six ready biodegradability tests are described below.

[0132] For the 301A test, a measured volume of inoculated minerai medium, containing 10 10 mg to 40 mg dissolved organic carbon per liter (DOC/1) from the substance as the nominal sole source of organic carbon, is aerated in the dark or diffuse light at 22 ± 2 °C. Dégradation is followed by DOC analysis at frequent intervals over a 28-day period. The degree of biodégradation is calculated by expressing the concentration of DOC removed (corrected for that in the blank inoculum control) as a percentage of the concentration initially présent. Primary 15 biodégradation may also be calculated from supplémentai chemical analysis for parent compound made at the beginning and end of incubation.

[0133] For the 30IB test, a measured volume of inoculated minerai medium, containing 10 mg to 20 mg DOC or total organic carbon per liter from the substance as the nominal sole source of organic carbon is aerated by the passage of carbon dioxide-free air at a controlled rate 20 in the dark or in diffuse light. Dégradation is followed over 28 days by determining the carbon dioxide produced. The CO₂ is trapped in barium or sodium hydroxide and is measured by titration of the residual hydroxide or as inorganic carbon. The amount of carbon dioxide produced from the test substance (corrected for that derived from the blank inoculum) is expressed as a percentage of ThCO2. The degree of biodégradation may also be calculated from 25 supplémentai DOC analysis made at the beginning and end of incubation.

[0134] For the 301C test, the oxygen uptake by a stirred solution, or suspension, of the substance in a minerai medium, inoculated with specially grown, unadapted micro-organisms, is measured automatically over a period of 28 days in a darkened, enclosed respirometer at 25 +/- 1 °C. Evolved carbon dioxide is absorbed by soda lime. Biodégradation is expressed as the

percentage oxygen uptake (corrected for blank uptake) of the theoretical uptake (ThOD). The percentage primary biodégradation is also calculated from supplémentai spécifie chemical analysis made at the beginning and end of incubation, and optionally ultimate biodégradation by DOC analysis.

[0135] For the 301D test, a solution of the substance in minerai medium, usually at 2-5 milligrams per liter (mg/1), is inoculated with a relatively small number of micro-organisms from a mixed population and kept in completely full, closed bottles in the dark at constant température. Dégradation is followed by analysis of dissolved oxygen over a 28 day period. The amount of oxygen taken up by the microbial population during biodégradation of the test 10 substance, corrected for uptake by the blank inoculum run in parallel, is expressed as a percentage of ThOD or, less satisfactorily COD.

[0136] For the 301E test, a measured volume of minerai medium containing 10 to 40 mg DOC/1 of the substance as the nominal sole source of organic carbon is inoculated with 0.5 ml effluent per liter of medium. The mixture is aerated in the dark or diffused light at 22 + 2 °C. 15 Dégradation is followed by DOC analysis at frequent intervals over a 28 day period. The degree of biodégradation is calculated by expressing the concentration of DOC removed (corrected for that in the blank inoculums control) as a percentage of the concentration initially présent. Primary biodégradation may also be calculated from supplémentai chemical analysis for the parent compound made at the beginning and end of incubation.

[0137] For the 301F test, a measured volume of inoculated minerai medium, containing

100 mg of the substance per liter giving at least 50 to 100 mg ThOD/1 as the nominal sole source of organic carbon, is stirred in a closed flask at a constant température (+ 1°C or closer) for up to 28 days. The consumption of oxygen is determined either by measuring the quantity of oxygen (produced electrolytically) required to maintain constant gas volume in the respirometer flask or 25 from the change in volume or pressure (or a combination of the two) in the apparatus. Evolved carbon dioxide is absorbed in a solution of potassium hydroxide or another suitable absorbent. The amount of oxygen taken up by the microbial population during biodégradation of the test substance (corrected for uptake by blank inoculum, run in parallel) is expressed as a percentage of ThOD or, less satisfactorily, COD. Optionally, primary biodégradation may also be calculated

from supplémentai spécifie chemical analysis made at the begjnning and end of incubation, and ultimate biodégradation by DOC analysis.

[0138] In accordance with OECD guidelines, the following three tests permit the testing of chemicals for inhérent biodegradability. As used herein, a substance with a biodégradation or 5 biodégradation rate of >20% is regarded as “inherently primary biodégradable.” A substance with a biodégradation or biodégradation rate of >70% is regarded as “inherently ultimate biodégradable.” As used herein, a substance passes the inhérent biodegradability test if the substance is either regarded as inherently primary biodégradable or inherently ultimate biodégradable when tested according to any one of three inhérent biodegradability tests. The 10 three tests are: (1) 302A: 1981 Modified SCAS Test; (2) 302B: 1992 Zahn-Wellens Test; and (3) 302C: 1981 Modified ΜΓΓΙ Test. Inhérent biodegradability refers to tests which allow prolonged exposure of the test compound to microorganisms, a more favorable test compound to biomass ratio, and chemical or other conditions which favor biodégradation. The three inhérent biodegradability tests are described below:

[0139] For the 302A test, activated sludge from a sewage treatment plant is placed in an aération (SCAS) unit. The substance and settled domestic sewage are added, and the mixture is aerated for 23 hours. The aération is then stopped, the sludge allowed to settle and the supematant liquor is removed. The sludge remaining in the aération chamber is then mixed with a further aliquot of the substance and sewage and the cycle is repeated. Biodégradation is established by détermination of the dissolved organic carbon content of the supematant liquor. This value is compared with that found for the liquor obtained from a control tube dosed with settled sewage only.

[0140] For the 302B test, a mixture containing the substance, minerai nutrients, and a relatively large amount of activated sludge in aqueous medium is agitated and aerated at 20 °C to 25 25 °C in the dark or in diffuse light for up to 28 days. A blank control, containing activated sludge and minerai nutrients but no substance, is run in parallel. The biodégradation process is monitored by détermination of DOC (or COD) in filtered samples taken at daily or other time intervals. The ratio of eliminated DOC (or COD), corrected for the blank, after each time

interval, to the initial DOC value is expressed as the percentage biodégradation at the sampling time. The percentage biodégradation is plotted against time to give the biodégradation curve.

[0141] For the 302C test, an automated closed-system oxygen consumption measuring apparatus (BOD-meter) is used. The substance to be tested is inoculated in the testing vessels 5 with micro-organisms. During the test period, the biochemical oxygen demand is measured continuously by means of a BOD-meter. Biodegradability is calculated on the basis of BOD and supplémentai chemical analysis, such as measurement of the dissolved organic carbon concentration, concentration of residual chemicals, etc.

[0142] AS4351 is an Australian Standard in regards to the biodegradability of a 10 product. Its purpose is to ensure that products are biodégradable and eco-friendly by requiring that products be tested by certified testing laboratories that at least 70% of the total ingrédients used to make the product can readily biodegrade in 28 days. This standard is technically équivalent to ISO 7827-1994 and is based on OECD “Ready Biodegradability” tests 301A to 301E.

General Approach [0143] The general structure of a sorbitan oleate polyglucoside is shown in Figure 1 and below:

where each R is an alkyl group having 8 to 24 carbons, wherein the R groups can be the same or different, where the range of n is 2 to 20 (for the glucose units) and where the range of m is 1 to 10 (for the sorbitan oleate units).

[0144] A Sorbitan Oleate Decylpolyglucoside (SOD) is a sorbitan oleate polyglucoside 25 wherein both R groups are decyl chains (C10). SODs are available with various HT .B values,

depending on the value of m for the sorbitan units. Two of these (herein designated “SOD-1” and “SOD-2”) hâve been successfully tested in water-based spacer fluids, including in spacer fluids having an 18% sait solution. The results are discussed in detail below.

_____________________Material Information______________

Name	Sorbitan Oleate Decylpolyglucoside
Concentration (%wt)	70.00 (in aqueous solution)
PH	7.0
HLB	5 (SOD-1), 12 (SOD-2)
Physical form	Liquid

[0145] This material has been tested for biodegradabîlity according to OECD 301 D. It undergo dégradation >80% in 16 days. For oil field application, the requirement is at least 60% 10 dégradation in 30 days. Since it is readily dégradés, it can be considered environment friendly.

[0146] This class of SOD surfactants are expected to be environment friendly, biodégradable, as they are derived from sugar sources. Such an SOD surfactant can be part of an effective surfactant package for a spacer fluid. Since the green chemicals are gaining much attention in the oil field industry, the new surfactant is commercially désirable. Applications 15 include wells having a sait zone that need treatment with a spacer fluid to displace an oil-based mud.

[0147] Based on the successful testing with SOD-1 and SOD-2 as disclosed below, a person of skill in the art can extrapolate to certain types of alkyl polyglycoside dérivatives that would be expected to hâve similar surfactant properties and be suitable for use according to the 20 principles of this invention.

[0148] Alkyl polyglycosides (“APGs”) are a class of non-ionic surfactants. When derived from glucose, alkyl polyglycosides are more specifically known as alkyl polyglucosides. Alkyl polyglucosides hâve the following general chemical structure, where m and n are variables:

[0149] The chemical structure of alkyl polyglycosides derived from other sugar molécules is similar, except for the différence in the type of sugar molécule on which the polyglycoside is based.

[0150] Preferably, independently of the other parameters for the alkyl polyglycoside, the alkyl polyglycoside (APG) is derived from glucose, such that it is an alkyl polyglucoside.

[0151] For any type of alkyl polyglycoside, independently of the other parameters, preferably m is in the range of 2 to 20.

[0152] For any type of alkyl polyglycoside, independently of the other parameters, preferably n for the alkyl group is in the range of 8 to 24.

[0153] More preferably, the alkyl polyglycoside (APG) is an alkyl polyglucoside wherein preferably m is in the range of 2 to 20 and preferably n for the alkyl is in the range of 8 to 24.

[0154] More generally, the surfactant is an alkyl polyglycoside (APG) dérivative selected from the group consisting of: sorbitan fatty acids ; functionalized sulfonates, functionalized betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing. Preferably, the sorbitan fatty acid functionality is selected from the group consisting of sorbitan oleate, sorbiant laurate, sorbitan stéarate, and sorbitan palmitate, Preferably, the sulfonate functionality is selected from the group consisting of hydroxyalkylsulfonates. More preferably, the alkyl group of the hydroxylalkylsulfonate functionality is selected from the group consisting of short-chain alkyl groups having in the range of 1 to 6 carbons. Preferably, an inorganic sait of the foregoing is selected from the group consisting of alkali métal, alkalîne earth métal, and ammonium salts. Most preferably, the inorganic sait is an alkali métal sait.

[0155] Most preferably, the surfactant is selected from the group consisting of:

(a) Sorbitan oleate decylpolyglucoside;

(b) Sorbitan laurate decylpolyglucoside;

(c) Sorbitan stéarate decylpolyglucoside;

(d) Sorbitan palmitate decylpolyglucoside;

(e) Decyl polyglucoside hydroxypropylsulfonate sodium sait (f) Lauryl polyglucoside hydroxypropylsulfonate sodium sait (g) Coco polyglucoside hydroxypropylsulfonate sodium sait;

(h) Lauryl polyglucoside sulfosuccinate disodium sait;

(i) Decyl polyglucoside sulfosuccinate disodium sait;

(j) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait (k) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (l) any combination of thereof.

[0156] In an embodiment, the APG dérivative comprises a sorbitan oleate decylpolyglucoside.

[0157] In a spacer fluid, the APG dérivative is preferably in a concentration in the range of 1 %wt active/vol to 10 %wt active/vol water.

[0158] These surfactants can be used for spacer fluids that are adapted for displacing an oil-based mud from a well. The surfactants are very effective for this purpose. In addition, the surfactants are compatible with tap water, seawater, and high concentrations of dissolved inorganic sait (e.g., 18% NaCl). The surfactants can be provided in an aqueous solution and can be diluted with water as may be desired or required under local operating régulations. More importantly, the surfactants are biodégradable and non-toxic.

Well Fluid Additives [0159] A well fluid can contain additives that are commonly used in oil field applications, as known to those skilled in the art. These include, but are not necessarily limited to, brines, inorganic water-soluble salts, sait substitutes (such as trimethyl ammonium chloride), 5 pH control additives, oxygen scavengers, alcohols, scale inhibitors, corrosion inhibitors, hydrate inhibitors, fluid-loss control additives, clay stabilizers, sulfïde scavengers, fibers, nanoparticles, bactéricides, and combinations thereof.

[0160] Of course, additives should be selected for not interfering with the purpose of the well fluid.

Method of Treating a Well with the Well Fluid [0161] According to another embodiment of the invention, a method of treating a well, is provided, the method including the steps of: forming a treatment fluid according to the invention; and introducing the treatment fluid into the well.

[0162] A well fluid can be prepared at the job site, prepared at a plant or facility prior to use, or certain components of the well fluid can be pre-mixed prior to use and then transported to the job site. Certain components of the well fluid may be provided as a “dry mix” to be combined with fluid or other components prior to or during introducing the well fluid into the well.

[0163] In certain embodîments, the préparation of a well fluid can be done at the job site in a method characterized as being performed “on the fly.” The term “on-the-fly” is used herein to include methods of combining two or more components wherein a flowing stream of one element is continuously introduced into flowing stream of another component so that the streams are combined and mixed while continuing to flow as a single stream as part of the on25 going treatment. Such mixing can also be described as “real-time” mixing.

[0164] Often the step of delivering a well fluid into a well is within a relatively short period after forming the well fluid, e.g., less within 30 minutes to one hour. More preferably, the step of delivering the well fluid is immediately after the step of forming the well fluid, which is “on the fly.”

[0165] It should be understood that the step of delîvering a well fluid into a well can advantageously include the use of one or more fluid pumps.

[0166] Preferably, the step of introducing the well fluid (spacer fluid) is after a step of drillîng the portion of the well with an oil-based mud.

[0167] Preferably, the step of introducing is at a rate and pressure below the fracture pressure of the treatment zone.

[0168] After the step of introducing a spacer fluid according to the invention, the method preferably includes the step of circulating the fluid in the well to wash out an oil-based mud.

[0169] After the step of introducing the spacer fluid, the method can include a step of cementing in the portion of the well.

[0170] Preferably, after any such well treatment, a step of producing hydrocarbon from the subterranean formation is the désirable objective.

Examples [0171] To facilitate a better understanding of the présent invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the entire scope of the invention.

Materials [0172] The performance of SODs was tested using a synthetic oil-based mud (OBM) obtained from a field operation. The major components include but are not necessarily limited to a synthetic base oil, water, barite, and a viscosifîer. The same OBM composition of 10.7 ppg (1280 kg/m³) was used in ail testing.

[0173] The performance of the SODs was tested in comparison to conventional surfactants for use in spacer fluids, which are designated herein “AES,” “DSS-A,” and “DSS-B”. These surfactants are known to provide good rheological compatibility between water and an OBM. However, such conventional surfactants are not biodégradable.

[0174] The AES is a water-soluble alkylether sulfate. AES acts to help with rheological compatibility between a spacer fluid and an oil-based mud. In addition, it acts as a degreaser, which helps promote cernent bonding by displacing an oil-based mud and helping to remove oil from a métal surface of a tubular in a well. In some cases, the AES is the only surfactant required 5 in a spacer fluid to wash away an OBM and achieve a water-wet condition. Of course, it can be combined with other surfactants. Testing including the AES is not included herein, however, the AES is known to be a useful surfactant in a spacer fluid.

[0175] The DSS-A and the DSS-B are of an ethoxylated nonylphenol. Ethoxylation is an industrial process in which ethylene oxide is added to alcohols and phénols to give 10 surfactants. The ethoxylation process is attributed to Schôller and Wittwer at I.G. Farben industries. Carbon chain length is usually in the range of about 8 to 18 and the ethoxylated chain is usually 3 to 12 ethylene oxides, although longer ethoxylated chains are available. They feature both a lipophilie tails and a relatively polar head group ((OC^ILiUOH). DSS-A has a shorter ethylene oxide chain length compared to DSS-B, which gives them differing in HT .B values 15 (Griffîn scale). DSS-A is an oil-soluble surfactant. DSS-B is a water-soluble surfactant.

[0176] Weighting agents are commonly used in well fluids, including in spacer fluids. As used herein a weighting agent has an intrinsic density or spécifie gravity greater than 2.7. Preferably, the weighting agent has a spécifie gravity in the range of 2.7 to 8.0. Weighting agents are sometimes referred to herein as “high-gravity solids” or “HGS”. Preferably, a weighting 20 agent is insoluble in both a water phase and insoluble in an oil phase.

[0177] In some cases, a spacer fluid can include a particulate weighting agent. Any suitable particulate weighting agent can be employed according to the invention. For example, barite is a minerai consisting essentially of barium sulfate (BaSO₄). Barite is insoluble in water or oil and has a true density in the range of about 4.0 to 4.5 g/cm. It can be formed into a 25 particulate useful as a weighting agent in drilling fluids or other well fluids. Other examples of weighting agents include, for example, particulate weighting material such as barite, hématite, iron oxide, manganèse tetroxide, galena, magnetite, lilmenite, siderite, celesite, or any combination thereof. If included, the particulate weighting agent preferably has a particle size distribution anywhere in the range of 0.1 to 500 micrometers.

[0178] In some cases, a spacer fluid can include a particulate. For example, such a particulate can be a mixture of amorphous silica (60-100%) and crystalline silica (0-1%). In another example, such a particulate can be a mixture of crystalline silica 0-5% ad bentonite (60100%).

Wettability Testing Procedure [0179] Wettability testing was done to test whether total phase inversion occurs upon mixing a spacer fluid and the OBM. An Apparent Wettability meter test (SSST) was used to measure Hogan readings, as described in “Water-Wetting Capability Testing” recently added to 10 API Recommended Practice IOB-2/1 0 10426-2. The apparent-wettability apparatus measures both the surface-acting and electrical properties of the fluid being tested. The apparatus' circuitry and Eurotherm controller test the electrical activity in the fluid and on the electrode surfaces, and provide a continuous reading to reflect the apparent wettability of the fluid measured in the dimensionless unit of Hogans (Hn). The experimental procedure is summarized as follows:

1. The spacer fluid was conditioned to a test température for 30 minutes with constant high-shear stirring.

2. Wettability measurement equipment was calibrated using a spacer for 125 Hogan.

3. After calibration, the mixing jar was washed thoroughly with water.

4. Equal quantities of the OBM and the spacer fluid were added to the mixing jar.

5. The surfactant(s) to be tested were taken in syringes and slowly added into the fluid mixture until the meter reading showed 150 Hogan under the mixing conditions (300-600 rpm at the test température).

6. A fresh spacer fluid was prepared using the surfactants quantity as determined in step 5.

7. 200 ml of the OBM was added into the mixing jar, To (his spacer fluid comprising the tested surfactant(s) was added and meter reading was monitored until it reaches 150 Hogans.

Compatibility Testing Procedure [0180] Compatibility testing between the spacer fluid and the OBM was also performed. The experimental procedure is summarized as follows:

1. The spacer fluid

2. The OBM was conditioned at the test température for 30 minutes.

3. The spacer fluid and the OBM were mixed in various proportions.

4. Rheology was measured at the test température using a FANN™ Model 35 viscometer, as described above.

'Wettability and Compatibility of a Spacer Fluid with SOD-2 (2.9 %wt/vol) at 80 °F [0181] In this example, DSS-B in a spacer fluid was replaced wîth SOD-2. The wettability and compatibility results are given below.

Table 1. Composition of Spacer Fluid - 12 ppg (1440 kg/m³)

Material	Amount
Water	168.8 g
Mixture of amorphous silica and crystalline silica	17.8 g
Barite	100.9 g
DSS-A	3 ml
SOD-2	7 ml (about 2.9 %wt active/vol water)

Table 2. Wettability Analysis

Spacer (ml)	Hogans
134	2
140	50
142	100
146	120
150	150

Table 3. Compatibility of Spacer Fluid with OBM at 80 °F

Ratio Spacer FluidOBM (v:v)	Viscometer Readings
3	6	30	60	100	200	300	600
100:00	11	14	20	25	26	35	43	64
90:10	15	18	25	29	32	41	49	66
75:25	16	19	26	31	34	42	46	66
50:50	14	16	21	26	29	38	44	67
25:75	11	15	29	42	60	110	124	242
10:90	13	16	26	39	52	86	118	196
00:100	13	16	25	38	48	76	99	157

Wettabïliiy and Compatibility of Spacer Fluid with SOD-2 (2.3 %wt/vol) at 140 °F [0182] In this example, the DSS-B in a spacer fluid was replaced with SOD-2, but at a lower concentration than in the above example and at 140 °F. The wettabîlity and compatibility results are given below.

Table 4. Composil	tîon of Spacer Fluid -12 ppg (1440 kg/ni3
Material	Amount
Water	168.8 g
Mixture of amorphous silica and crystalline silica	17.8 g
Barite	100.9 g
DSS-A	3 ml
SOD-2	5.5 ml (about 2.3 %wt active/vol water)

Table 5. Wettability Analysis

Spacer (ml)	Hogans
200	20
210	50
215	75
220	150

Table 6. Compatibility of Spacer Fluid with QBM at 14(

Ratio Spacer Huid.OBM (v:v)	Viscometer Readings
3	6	30	60	100	200	300	600
100:00	9	11	17	22	27	36	42	58
90:10	7	9	14	16	18	24	30	46
75:25	8	10	14	18	20	24	26	39
50:50	7	9	11	13	15	19	27	38
25:75	16	18	32	42	54	78	94	145
10:90	14	17	26	34	44	66	90	122
00:100	16	18	25	31	42	63	81	113

W'ettability of Spacer Fluid Containing 18% Sait with SOD-2 at 80 T [0183] In this example, DSS-B in a spacer fluid containing 18% sait was replaced with

SOD-2. The wettability results are given below.

Table 7.

,620 of Spacer Fluid -13.5

Material	Amount
Water	160 g
Crystalline silica 05%; Bentonite (60100%)	12.56 g
36% NaCl solution	171 ml
B an te	270 g
DSS-A	4 ml
SOD-2	6 ml (about 2.6 %wt active/vol water)

i³)

Table 8.

Spacer (ml)	Hogans
160	80
170	120
180	150

Wettability of Spacer Fluid Containing 18% Sait with SOD-1 and SOD-2 at 80 °F [0184] In this example, DS S-A and DSS-B in a spacer fluid containing 18% sait were replaced with SOD-1 and SOD-2, respectively. The wettability and compatibility results are given below.

Table 9. Composition of Spacer Fluid -13.5 ppg (1,620 kg/m³)

Material	Amount
Water	160 g
Mixture of amorphous silica (60-100%) and Crystalline silica (0-1%)	12.56 g
36% NaCl solution	171ml
Barite	270 g
SOD-1	6 ml
SOD-2	6 ml

Table 10. Wel	ttability Analysis
Spacer (ml)	Hogans
150	40
160	130
170	150

Results Discussion [0185] The combination of two surfactants, DSS-A and SOD-2 performs well in a spacer fluid made from tab water as well as in a spacer fluid containing 18% NaCl sait. Such a 15 material can replace a less environmentally friendly surfactant such as DSS-B.

[0186] In addition, DSS-A can be replaced with SOD-1.

[0187] The disclosed class of alkyl polyglycoside dérivatives as surfactants (as exemplified by SOD-1 and SOD-2 above) are shown to be effective in a spacer fluid to achieve good compatibility with an oil-based drilling fluid at about room température (80 °F) as well as 20 at a higher température of 140 °F. It was observed that viscosities of the mixtures of such a spacer fluid and a typical oil-based mud were low (i.e., pumpable) and did not show gélation (abrupt increase in viscosity) at any particular proportions. It can be seen that, on addition of a

spacer fluid with the surfactant gives a sharp increase in Hogan reading measured in an Apparent Wettability test. Thus, it can be concluded that this class of alkyl polyglycoside dérivatives inverts an émulsion of an oil-based mud effectively without creating unstable émulsion phases (that is, without creating émulsion phases that readily separate into different fluid layers).

[0188] Further, this class of alkyl polyglycoside dérivatives is effective in a spacer fluid without need of an AES surfactant to achieve the desired fluid compatibility with an oil-based mud.

[0189] In addition, class of alkyl polyglycoside dérivatives is shown to be effective in spacer fluids containing high concentration of salts (e.g., 18% NaCI) without any incompatibility and still giving good wetting characteristics.

Conclusion [0190] Therefore, the présent invention is well adapted to attain the ends and advantages mentioned as well as those that are inhérent therein.

[0191] The exemplary fluids disclosed herein may directly or indirectly affect one or more components or pièces of equipment associated with the préparation, delivery, recapture, recycling, reuse, or disposai of the disclosed fluids. For example, the disclosed fluids may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, fluid separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used generate, store, monitor, regulate, or recondition the exemplary fluids. The disclosed fluids may also directly or indirectly affect any transport or delivery equipment used to convey the fluids to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, or pipes used to fluidically move the fluids from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the fluids into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids, and any sensors (i.e., pressure and température), gauges, or combinations thereof, and the like. The disclosed fluids may also directly or indirectly affect the various downhole equipment and tools that may corne into contact with the chemicals/fluids such as, but not limited to, drill string, coiled tubing, drill pipe, drill collars, mud motors, downhole motors or pumps, floats,

MWD/LWD tools and related telemetry equipment, drill bits (including roller cône, PDC, natural diamond, hole openers, reamers, and coring bits), sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore isolation devices or components, and the like.

[0192] The particular embodiments disclosed above are illustrative only, as the présent invention may be modified and practiced in different but équivalent manners apparent to those skilled in the art having the benefît of the teachings herein. It is, therefore, évident that the particular illustrative embodiments disclosed above may be altered or modified and ail such variations are considered within the scope and spirit of the présent invention.

[0193] The various éléments or steps according to the disclosed éléments or steps can be combined advantageously or practiced together in various combinations or sub-combinations of éléments or sequences of steps to increase the effîciency and benefits that can be obtained from the invention.

[0194] The invention illustratively disclosed herein suitably may be practiced in the 15 absence of any element or step that is not specifically disclosed or claimed.

[0195] Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.

Claims (21)

1. What is claimed is:

   1. A spacer fluid comprising:

   (a) water;

   (b) a solid particulate; and (c) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of sorbitan fatty acids, sulfonates, betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing.

   10
2. 2. The spacer fluid according to claim 1, wherein the alkyl polyglycoside is an alkyl polyglucoside having a chemical structure:

   fT.

   wherein n for the alkyl is 8 or greater; and

   15 wherein m for the polyglucoside is 2 or greater.
3. 3. The spacer fluid according to claim 2, wherein n is in the range of 8 to 24.
4. 4. The spacer fluid according to claim 2, wherein m is in the range of 2 to 20.
5. 5. The spacer fluid according to claim 1, wherein the sulfonate is selected from the group consisting of hydroxyalkylsulfonates.
6. 6. The spacer fluid according to claim 5, wherein the alkyl group of the

   25 hydroxylalkylsulfonate is selected from the group consisting of short-chain alkyl groups having in the range of 1 to 6 carbons.
7. 7. The spacer fluid according to claim 1, wherein the inorganic sait of the alkyl polyglycoside dérivative is selected from the group consisting of alkali métal, alkaline earth métal, and ammonium salts.
8. 8. The spacer fluid according to claim 1, wherein the alkyl polyglycoside dérivative is selected from the group consisting of:

   (a) Sorbitan oleate decylpolyglucoside;

   (b) Sorbitan laurate decylpolyglucoside;

   (c) Sorbitan stéarate decylpolyglucoside;

   (d) Sorbitan palmitate decylpolyglucoside;

   (e) Decyl polyglucoside hydroxypropylsulfonate sodium sait (f) Lauryl polyglucoside hydroxypropylsulfonate sodium sait (g) Coco polyglucoside hydroxypropylsulfonate sodium sait;

   (h) Lauryl polyglucoside sulfosuccinate disodium sait;

   (i) Decyl polyglucoside sulfosuccinate disodium sait;

   (j) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait (k) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (l) any combination of thereof.
9. 9. The spacer fluid according to claim 1, wherein the alkyl polyglycoside dérivative comprises: a sorbitan oleate decylpolyglucoside.
10. 10. The spacer fluid according to claim 1, wherein the solid particulate comprises a weighting agent.
11. 11. A method of displacing an oil-based driiling mud from a portion of a well, the method comprising the steps of:

    (A) forming a spacer fluid comprising:

    (a) water; and (b) an alkyl polyglycoside derivative, wherein the alkyl polyglycoside derivative is selected from the group consisting of sorbitan fatty acids, sulfonates, betaines, an înorganic sait of any of the foregoing, and any combination of any of the foregoing; and (B) introducing the spacer fluid into the well.
12. 12. The spacer fluid according to claim 11, wherein the alkyl polyglycoside is an alkyl polyglucoside having a chemical structure:

    wherein n for the alkyl is 8 or greater; and wherein m for the polyglucoside is 2 or greater.
13. 13. The method according to claim 12, wherein n is in the range of 8 to 24,
14. 14. The method according to claim 12, wherein m is in the range of 2 to 20.
15. 15. The method according to claim 11, wherein the sulfonate is selected from the group consisting of hydroxyalkylsulfonates.
16. 16. The method according to claim 15, wherein the alkyl group of the hydroxylalkylsulfonate is selected from the group consisting of short-chain alkyl groups having in the range of 1 to 6 carbons.
17. 17. The method according to claim 11, wherein the inorganic sait of the alkyl polyglycoside dérivative is selected from the group consisting of alkali métal, alkaline earth métal, and ammonium salts.
18. 18. The method according to claim 11, wherein the alkyl polyglycoside dérivative is selected from the group consisting of·.

    (a) Sorbitan oleate decylpolyglucoside;

    (b) Sorbitan laurate decylpolyglucoside;

    (c) Sorbitan stéarate decylpolyglucoside;

    (d) Sorbitan palmitate decylpolyglucoside;

    (e) Decyl polyglucoside hydroxypropylsulfonate sodium sait (f) Lauryl polyglucoside hydroxypropylsulfonate sodium sait (g) Coco polyglucoside hydroxypropylsulfonate sodium sait;

    (h) Lauryl polyglucoside sulfosuccinate dîsodium sait;

    (i) Decyl polyglucoside sulfosuccinate disodium sait;

    (j) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait (k) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (l) any combination of thereof.
19. 19. The method according to claim 11, wherein the alkyl polyglycoside dérivative comprises: a sorbitan oleate decylpolyglucoside.
20. 20. The method according to claim 11, wherein the spacer fluid additionally comprises a solid partîculate.
21. 21. The method according to claim 20, wherein the solid partîculate comprises a weighting agent.