OA17443A - Alkyl polyglycoside derivative as biodegradable foaming surfactant for cement. - Google Patents

Abstract

A cement composition : (a) a hydraulic cement; (b) water; and (c) an alkyl polyglycoside derivative, wherein the alkyl polyglycoside derivative is selected from the group consisting of : sulfonates, betaines, an inorganic salt of any of the foregoing, and any combination of any of the foregoing. A method comprising the steps of : (A) forming the cement composition; and (B) introducing the cement composition into the well. Preferably, the cement composition is foamed.

Description

ALKYL POLYGLYCOSIDE DERIVATIVE

AS BIODEGRADABLE FOAMING SURFACTANT FOR CEMENT

CROSS-REFERENCE TO RELATED APPLICATIONS [0001] This Application claims priority from U.S. Non-Provisional Patent Application No.l 3/786,113, filed March 05, 2013, entitled “Alkyl Polyglycoside Dérivative as Biodégradable Foaming Surfactant for Cernent,” 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 cernent compositions and methods of cementing a well. The cernent compositions include a foaming surfactant.

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 20 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, completion, and intervention. Well services are designed to faciiitate or enhance the production of désirable fluids 25 such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.

[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 5 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 allow fluid communication between the zone and the wellbore. The cemented casing also enables 10 subséquent or remédiai séparation or isolation of one or more production zones of the wellbore by using downhole tools, such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cernent in the perforations. Hydraulic cernent compositions can also be 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 15 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 20 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 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 25 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.

[0008] It is important to maintain a cernent in a pumpable slurry state until it is placed in a desired portion of the well. For this purpose, a set retarder can be used in a cernent slurry, which retards the setting process and provides adéquate pumping time to place the cernent slurry.

Altematively or in addition, a set intensifier can be used, which accelerates the setting process.

The retarder or intensifier can be used to help control the thîckening time or setting of a cernent composition.

Foamed Cernent Slurries [0009] Light-weight cernent slurry is often used in cementing of oil wells to prevent the 10 exertion of excess hydrostatic pressure on the subterranean formation, which otherwise could fracture the formation. Low-density materials such as hallow beads are used to design lightweight cernent slurries.

[0010] However, foamed cernent compositions hâve unique features of high compressibility and thermal însulation properties as compared to non-foamed cernent 15 compositions. Foamed cernent contains gas maintained under sufficient pressure so as to prevent gas migration in the fluid during the transition of the cernent slurry into a set solid mass. Also, the set foamed cernent has ductile property, which is désirable for sustaining the stress.

[0011] Normally, foamed cements hâve been prepared using a gas and a foaming surfactant. Even though there are many foaming surfactants known in the literature, they hâve 20 limitations such as réduction in compressive strength, gélation with mixing fluids (i.e., increase in slurry viscosity), incompatibility with co-additives, and poor environmental compliance. Therefore, there is a need for new surfactant that performs better over the existing materials.

Inorganic Salts in Cernent Slurries [0012] Cernent slurries 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 foaming surfactant be compatible for use in a cernent slurry formed with seawater or having other inorganic salts dissolved in the water. Not ali foaming surfactants are compatible for use with dissolved salts.

Fluid-Loss Control [0013] Fluids used in drilling, completion, or servicing of a wellbore can be lost to the subterranean formation while circulating the fluids in the wellbore. In particular, the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, lost 5 circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth. The extent of fluid losses to the formation may range from minor (for example less than 10 bbl/hr) referred to as seepage loss to severe (for example, greater than 500 bbl/hr) referred to as complété loss. As a resuit, the service provided by such fluid is more difficult to achieve. For example, a drilling fluid may be 10 lost to the formation, resulting in the circulation of the fluid in the wellbore being too low to allow for further drilling of the wellbore. Also, a secondary cernent or sealant composition may be lost to the formation as it is being placed in the wellbore, thereby rendering the secondary operation ineffective in maintainîng isolation of the formation.

[0014] The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. Ail else being equal, the higher the concentration of the appropriately sized particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks 20 into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or pénétrâtes only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filtercake. Depending on the nature of a fluid phase and the filtercake, such a filtercake may help block the further loss of a fluid phase (referred to as 25 a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium. Accordingly, a fluid-loss control material is sometimes referred to as a filtration control agent.

SUMMARY OFTHE INVENTION [0015] A cernent composition is provided, the composition comprising:

(a) a hydraulic cernent;

(b) water; and (c) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of: sulfonates, betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing.

[0016] Preferably, the cernent composition additionally comprises a gas, whereby the cernent composition is foamed.

[0017] A method of cementing a portion of a well is provided, the method comprising the steps of: (A) forming a cernent composition according to the invention; and (B) introducing the cernent composition into the well.

[0018] 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 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.

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODE

Définitions and Usages

General Interprétation [0019] The words or terms used herein hâve their plain, ordinary meaning in the field of this disclosure, except to the extent explieitiy and clearly defined in this disclosure or unless the spécifie context otherwise requires a different meaning.

[0020] 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.

[0021] 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.

[0022] The indefinite articles “a” or “an” mean one or more than one of the component, 20 part, or step that the article introduces.

[0023] 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.

[0024] It should be understood that algebraic variables or other scîentific symbols used herein are selected arbitrarily or according to convention. Other algebraic variables can be used.

[0025] The control or controlling of a condition includes any one or more of 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 [0026] In the context of production from a well, “oil” and “gas” are understood to refer to crude oil and natural gas, respectively. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.

[0027] A “subterranean formation” is a body of rock that has sufficiently distinctive 10 characteristics and is sufficiently continuous for geologists to describe, map, and name it.

[0028] A subterranean formation having a sufficient porosity and permeability to store and transmit fluîds is sometimes referred to as a “réservoir.” [0029] A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas réservoirs are typically located in the range of a few 15 hundred feet (shallow réservoirs) to a few tens of thousands of feet (ultra-deep réservoirs) below the surface of the land or seabed.

Well Servicing and Well Fluîds [0030] To produce oil or gas from a réservoir, a wellbore is drilled into a subterranean 20 formation, which may be the réservoir or adjacent to the réservoir.

[0031] Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of désirable fluîds such as oil or gas from or through a subterranean formation. A well service usually involves 25 introducing a well fluid into a well.

Well Terms [0032] 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.

[0033] A “well site” is the geographîcal location of a wellhead of a well. It may include 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.

[0034] 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 10 wellbore wall, that is, the rock surface or wall that bounds the drilled hole. A wellbore can hâve 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.

[0035] 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 fluîds can be directed from the wellhead into any desired portion of the wellbore.

[0036] As used herein, the word “tubular” means any kind of structural body in the general form of a tube. Examples of tubulars include, but are not limited to, a drill pipe, a casing, 20 a tubing string, a line pipe, and a transportation pipe. Tubulars can also be used to transport fluids such as oil, gas, water, liquefied methane, coolants, and heated fluids into or out of a 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.

[0037] 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 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-limiting 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 tubing string and the borehole of the wellbore is an annulus. In a cased hole, the space between 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 5 and the inside cylindrical portion of the casing. An annulus can be a space through whîch a fluid can flow or it can be fîlled 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 which a fluid can flow.

[0038] As used herein, a “well fluid” broadly refers to any fluid adapted to be 10 introduced into a well for any purpose. A well fluid can be, for example, a drilling fluid, a cernent 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 sometimes referred to as a wash, dump, slug, or pill.

[0039] A “portion” of a well, tubular, or pipeline refers to any downhole portion of the 15 well or any portion of the length of a pipeline or any portion of a tubular, as the case may be.

[0040] A “zone” refers to an înterval 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, or fractures. A zone of a wellbore that pénétrâtes a hydrocarbon-bearing zone that is capable of 20 producing hydrocarbon is referred to as a “production zone.” A “treatment zone” refers 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.

[0041] Fluid loss refers to the undesirable leakage of a fluid phase of any type of well 25 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.

[0042] Generally, the greater the depth of the formation, the higher the static température and pressure of the formation. Initial ly, the static pressure equals the initial pressure

in the formation before production. After production begins, the static pressure approaches the average réservoir pressure.

[0043] Deviated wells are wellbores inclined at various angles to the vertical. Complex wells include inclined wellbores in high-temperature or high-pressure downhole conditions.

[0044] 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 viscosity for at least a specifïed 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 10 shear conditions of the pumping.

[0045] 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 15 during treatment. The design température for a well fluid is sometimes referred to as the bottom 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.

Substances, Chemicals, and Dérivatives [0046] A substance can be a pure chemical or a mixture of two or more different chemicals.

[0047] 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 25 the combination of polymers having two monomeric units, but includes any combination of monomeric units, e.g., terpolymers, tetrapolymers, etc.

[0048] 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 chemicai process preferably includes at most

Π 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 polymeric material may be partial or complété,

Physical States and Phases [0049] As used herein, “phase” is used to refer to a substance having a chemical composition and physical state that is distînguishable from an adjacent phase of a substance having a different chemical composition or a different physical state.

[0050] 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 I atmosphère (Standard Laboratory Conditions) without applied shear.

Fluids [0051] 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.

[0052] 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 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 sizes of the solid particles of a mass of a particulate are too large to be appreciably affected by the range of Intermolecular Forces.) [0053] 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 5 Conditions. For example, a well fluid can be in the form of a slurry or suspension (larger solid particles 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).

Cernent and Cernent Compositions [0054] In the most general sense of the word, a “cernent” is a binder, that is, a substance that sets and can bind other materials together. As used herein, “cernent” refers to an inorganic cernent that, when mixed with water, will begin to set and harden into a concrète material.

[0055] As used herein, the term “set” means the process of becoming gelled to a gel state, solid, or hard by curing.

[0056] As used herein, a “cernent composition” is a material including at least one inorganic cernent. A cernent composition can also include additives. Some cernent compositions can include water or be mixed with water. Depending on the type of cernent, the chemical 20 proportions, when a cernent composition is mixed with water it can begin setting to form a phase solid material.

[0057] A cernent can be characterized as non-hydraulic or hydraulic.

[0058] Non-hydraulic cements (e.g., gypsum plaster, Sorei cements) must be kept dry in order to retain their strength. A non-hydraulic cernent produces hydrates that are not résistant 25 to water. If the proportion of water to a non-hydraulic cernent is too high, the cernent composition will not set into a hardened material.

[0059] Hydraulic cements (e.g., Portland cernent) harden because of hydration, chemical reactions that occur independently of the mixture’s water content; they can harden even underwater or when constantly exposed to wet weather. The chemical reaction that results when

the dry cernent powder is mîxed with water produces hydrates that hâve extremely low solubility in water. The cernent composition sets by a hydration process, and it passes through a gel phase to solid phase.

[0060] More particularly, Portland cernent is formed from a clinker such as a clinker 5 according to the European Standard EN 197-1: “Portland cernent clinker is a hydrauiic material which shall consîst of at least two-thirds by mass of calcium silicates (3 CaOSi02 and 2 CaO-SiCh), the remainder consisting of aluminum- and iron-containing clinker phases and other compounds. The ratio of CaO to S1O2 shall not be less than 2.0. The magnésium oxide content (MgO) shall not exceed 5.0% by mass.” The American Society of Testing Materials (“ASTM”) 10 standard “C 150” defines Portland cernent as “hydrauiic cernent (cernent that not only hardens by reacting with water but also forms a water-resistant product) produced by pulverizing clinkers consisting essentially of hydrauiic calcium silicates, usually containing one or more of the forms of calcium sulfate as an inter ground addition.” In addition, Portland cements typically hâve a ratio of CaO to S1O2 of less than 4.0.

[0061] The American Society for Testing and Materials (ASTM) has established a set of standards for a Portland cernent to meet to be considered an ASTM cernent. These standards include Types I, II, ΠΙ, IV, and V.

[0062] The American Petroleum Institute (API) has established a set of standards that a

Portland cernent must meet to be considered an API cernent. The standards include Classes A, B, 20 C, D, E, F, G, H, I, and J.

[0063] As used herein, a “light-weight” cernent slurry refers to a cernent slurry having a density less than 15 ppg (1020 kg/m³), and typically in the range of about 8.5 ppg (1020 kg/m³) to about 15 ppg (1800 kg/m³).

[0064] As used herein, “high compressibility” regarding a cernent slurry means higher 25 compressibility than for an otherwise similar cernent slurry composition without any foaming.

[0065] As used herein, good thermal insulation means higher than thermal insulating property than for an otherwise similar cernent slurry composition without any foaming.

Cernent Additives [0066] Cernent compositions can contaîn other additives, including but not limited to resins, latex, stabilizers, silica, microspheres, aqueous superabsorbers, viscosifying agents, suspending agents, dispersing agents, salts, accélérants, retardants, high-density materials, low5 density materials, fluid loss control agents, elastomers, vitrified shale, gas migration control additives, formation conditioning agents, or other additives or modifying agents, or combinations thereof.

[0067] Of course, the additives should be compatible with the cernent slurry and its function. Physical or chemical interaction of an additive with other components or additives (co10 additives) can lead to their deactivatîon or poor performance of the cernent slurry. Two additives are incompatible if undesîrable physical or chemical interactions occur when mixed in a cernent slurry.

Cementing and Other Uses for Cernent Compositions [0068] During well completion, it is common to introduce a cernent composition into an annulus in the wellbore. For example, in a cased hole, the cernent composition is placed into and allowed to set in the annulus between the wellbore and the casing in order to stabilize and secure the casing in the wellbore. After setting, the set cernent composition should bave a low permeability. Consequentiy, oil or gas can be produced in a controlled manner by directing the 20 flow of oil or gas through the casing and into the wellhead.

[0069] Cernent compositions can also be used, for example, in well-plugging operations or gravel-packing operations. Cernent compositions can also be used to control fluid loss or migration in zones.

[0070] During placement of a cernent composition, it is necessary for the cernent composition to remain pumpable during introduction into the subterranean formation or the well and until the cernent composition is situated in the portion of the subterranean formation or the well to be cemented. After the cernent composition has reached the portion of the well to be cemented, the cernent composition ultimately sets. A cernent composition that thickens too quickly while being pumped can damage pumping equipment or block tubing or pipes, and a

cernent composition that sets too slowly can cost time and money while waiting for the cernent composition to set.

Pumping Time and Thickening Time [0071] As used herein, the “pumping time” is the total time required for pumping a hydraulic cementing composition into a desired portion or zone of the well in a cementing operation plus a safety factor.

[0072] As used herein, the “thickening time” is how long it takes for a cernent composition to become unpumpable at a specified température and specified pressure. The 10 pumpability of a cernent composition is related to the consistency of the composition. The consistency of a cernent composition is measured in Bearden units of consistency (Bc), a dimensionless unit with no direct conversion factor to the more common units of viscosity. As used herein, a setting fluid is considered to be “pumpable” so long as the fluid has an apparent viscosity less than 30,000 mPa*s (cP) (independent of any gel characteristic) or a consistency of 15 less than 70 Bc. A setting fluid becomes “unpumpable when the consistency of the composition reaches at least 70 Bc.

[0073] As used herein, the consistency of a cernent composition is measured according to ANSI/API Recommended Practice 10B-2 as follows. The cernent composition is mixed and then placed in the test cell of a High-Temperature, High-Pressure (HTHP) consistometer, such as 20 a FANN™ Model 275 or a CHANDLER™ Model 8240. The cernent composition is tested in the HTHP consistometer at the specified température and pressure. Consistency measurements are taken continuously until the consistency of the cernent composition exceeds 70 Bc.

[0074] Of course, the thickening time should be greater than the pumping time for a cementing operation.

Setting and Compressive Strength [0075] Depending on the composition and the conditions, it can take just a few minutes up to 72 hours or longer for some cernent compositions to initially set. A cernent composition sample that is at least initially set is suitable for destructive compressive strength testing.

[0076] Compressive strength is defined as the capacity of a material to withstand axially directed pushing forces. The compressive strength a setting composition attains is a function of both curing time and température, among other things.

[0077] The compressive strength of a cernent composition can be used to indicate whether the cernent composition has set. As used herein, a cernent composition is considered “initially set” when the cernent composition has developed a compressive strength of 50 psi using the non-destructive compressive strength method. As used herein, the “initial setting time” is the différence in time between when the cernent is mixed with water and when the cernent composition is initially set. Some cernent compositions can continue to develop a compressive 10 strength greater than 50 psi over the course of several days. The compressive strength of certain kinds of cernent compositions can reach over 10,000 psi.

[0078] Compressive strength is typically measured at a specified time after the cernent composition has been mixed and at a specified température and pressure conditions. If not otherwise stated, the setting and the initial setting time is determîned at a température of 212 °F 15 and an atmospheric pressure of 3,000 psi. Compressive strength can also be measured at a spécifie time and température after the cernent composition has been mixed, for example, in the range of about 24 to about 72 hours at a design température and pressure, for example, a température of 212 °F and 3,000 psi. According to ANSI/API Recommended Practice 10B-2, compressive strength can be measured by either a destructive method or non-destructive method.

[0079] The destructive method mechanically tests the strength of cernent composition samples at various points in time by crushïng the samples in a compression-testing machine. The destructive method is performed as follows. The cernent composition is mixed and then cured. The cured cernent composition sample is placed in a compressive strength testing device, such as a Super L Universal testing machine model 602, available from Tinius Olsen, Horsham in 25 Pennsylvania, USA. According to the destructive method, the compressive strength is calculated as the force required to break the sample divided by the smallest cross-sectional area in contact with the load-bearing plates of the compression device. The actual compressive strength is reported în units of pressure, such as pound-force per square inch (psi) or megapascals (MPa).

[0080] The non-destructive method continually measures a correlated compressive strength of a cernent composition sample throughout the test period by utilizing a non-destructive sonie device such as an Ultrasonic Cernent Analyzer (UCA) available from Fann Instruments in Houston, TX. As used herein, the “compressive strength” of a cernent composition is measured 5 utilizing an Ultrasonic Cernent Analyzer as follows. The cernent composition is mixed. The cernent composition is placed in an Ultrasonic Cernent Analyzer, in which the cernent composition is heated to the specified température and pressurized to the specified pressure. The UCA continually measures the transit time of the acoustic signal through the sample. The UCA device contains preset algorithms that correlate transit time through the sample to compressive 10 strength. The UCA reports the compressive strength of the cernent composition in units of pressure, such as psi or megapascals (MPa).

Cernent Testing Conditions [0081] As used herein, if any test (e.g., thickening time, compressive strength, or 15 permeability) requires the step of mixing the setting composition, cernent composition, or the like, then the mixing step is performed according to ANSVAPI Recommended Practice 10B-2 as follows. Any of the ingrédients that are a dry particulate substance are pre-blended. The liquid is added to a mixing container and the container is then placed on a mixer base. For example, the mixer can be a Lightning Mixer. The motor of the base is then turned on and maintained at about 20 4,000 révolutions per minute (rpm). The pre-blended dry ingrédients are added to the container at a uniform rate in not more than 15 seconds (s). After ail the dry ingrédients hâve been added to the liquid ingrédients in the container, a cover is then placed on the container, and the composition is mixed at 12,000 rpm (+/- 500 rpm) for 35 s (+/- 1 s). It is to be understood that the composition is mixed under Standard Laboratory Conditions (about 77 °F and about 1 25 atmosphère pressure).

[0082] It is also to be understood that if any test (e.g., thickening time or compressive strength or permeability) spécifiés the test be performed at a specified température and possibly a specified pressure, then the température and pressure of the cernent composition is ramped up to the specified température and pressure after being mixed at ambient température and pressure.

For example, the cernent composition can be mixed at 77 °F and then placed into the testing apparatus and the température of the cernent composition can be ramped up to the specified température. As used herein, the rate of ramping up the température is in the range of about 3 °F/min to about 5 °F/min. After the cernent composition is ramped up to the specified température and possibly pressure, the cernent composition is maintained at that température and pressure for the duration of the testing.

[0083] As used herein, if any test (e.g., compressive strength or permeability) requires the step of “curing the cernent composition” or the like, then the curing step is performed according to ANSI/API Recommended Practice 10B-2 as follows. After the cernent composition has been mixed, it is poured into a curing mold. The curing mold is placed into a pressurized curing chamber and the curing chamber is maintained at a température of 212 °F and a pressure of 3000 psi. The cernent composition is allowed to cure for the length of time necessary for the composition to set. After the composition has set, the curing mold is placed into a water cooling bath until the cernent composition sample is tested.

Cernent Retarders [0084] As used herein, a “retarder” is a chemical agent used to increase the thickening time of a cernent composition. The need for retarding the thickening time of a cernent composition tends to increase with depth of the zone to be cemented due to the greater time required to complété the cementing operation and the effect of increased température on the settîng of the cernent. A longer thickening time at the design température allows for a longer pumping time that may be required.

Foamed Fluîds [0085] A foamed fluid is fluid having a liquid extemal phase that includes a dispersion of undissolved gas bubbles that foam the liquid, usually with the aid of a chemical (a foaming agent) in the liquid phase to achieve stability.

[0086] Any suitable gas may be used for foaming, including nitrogen, carbon dioxide, air, or methane. A foamed treatment fluid may be désirable to, among other things, reduce the

amount of fluid that is required in a water sensitive subterranean formation, to reduce fluid loss in the formation, or to provide enhanced proppant suspension. In examples of such embodiments, the gas may be présent in the range of from about 5% to about 98% by volume of the treatment fluid, and more preferably in the range of from about 20% to about 80% by volume of the treatment fluid. The amount of gas to incorporate in the fluid may be affected by many factors including the viscosity of the fluid and the bottom hole températures and pressures involved in a particular application. One of ordinary skill in the art, with the benefit of this disclosure, will recognize how much gas, if any, to incorporate into a foamed treatment fluid.

Surfactants [0087] 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.

[0088] 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.

[0089] A surfactant package can include one or more different chemical surfactants.

Biodegradability [0090] Biodégradable means the process by which complex molécules are broken down by micro-organisms to produce simpler compounds. Biodégradation can be either aérobic (with 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.

[0091] 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 substance is first tested for ready biodegradability, and only if the substance does not pass at least one of the ready biodegradabilîty tests then the substance is tested for inhérent bîodegradability.

[0092] In accordance wîth Organisation for Economie Co-operation and Development (“OECD”) guidelines, the following six tests permit the screening of chemicals for ready 5 biodegradabilîty. As used herein, a substance showing more than 60% biodegradabilîty in 28 days according to any one of the six ready biodegradabilîty tests is considered a pass level for classifying it as “readily biodégradable,” and it may be assumed that the substance will undergo rapid and ultîmate dégradation in the environment. The six ready biodegradabilîty tests are: (1) 301A: DOC Die-Away; (2) 301B: CO₂ Evolution (Modified Sturm Test); (3) 301C: MITI (I) 10 (Ministry of International Trade and Industry, Japan); (4) 301D: Closed Bottle; (5) 301E:

Modified OECD Screening; and (6) 301F: Manometric Respirometry. The six ready biodegradabilîty tests are described below:

[0093] For the 301A test, a measured volume of inoculated minerai medium, containing mg to 40 mg dissolved organic carbon per liter (DOC/1) from the substance as the nominal 15 sole source of organic carbon, is aerated in the dark or diffuse light at 22 ± 2 °C. Dégradation is foliowed 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 biodégradation may also be calculated from supplémentai chemical analysis for parent 20 compound made at the beginning and end of incubation.

[0094] For the 30IB test, a measured volume of inoculated minerai medium, containing 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 in the dark or in diffuse light. Dégradation is foliowed over 28 days by determining the carbon 25 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 supplémentai DOC analysis made at the beginning and end of incubation.

[0095] For the 30IC 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.

[0096] 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 substance, corrected for uptake by the blank inoculum run in parallel, is expressed as a percentage of ThOD or, less satisfactorily COD.

[0097] 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. 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.

[0098] 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 doser) for up to 28 days. The consumption of oxygen is determined either by measuring the quantity of oxygen (produced eiectrolytically) required to maintain constant gas volume in the respirometer flask or 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 beginning and end of incubation, and ultimate biodégradation by DOC analysis.

[0099] 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 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 three tests are: (1) 302A: 1981 Modîfied SC AS Test; (2) 302B: 1992 Zahn-Wellens Test; and (3) 302C: 1981 Modîfied MITI 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:

[0100] 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 supernatant 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 supernatant liquor. This value is compared with that found for the liquor obtained from a control tube dosed with settled sewage only.

[0101] For the 3O2B 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 °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 5 time. The percentage biodégradation is plotted against time to give the biodégradation curve.

[0102] 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 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 10 supplémentai chemical analysis, such as measurement of the dissolved organic carbon concentration, concentration of residual chemicals, etc.

[0103] AS4351 is an Australian Standard in regards to the biodegradability of a 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 15 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 30IE.

General Measurement Terms [0104] Unless otherwise specified or unless the context otherwise clearly requires, any ratio or percentage means by weight.

[0105] 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 viscosity-increasing agent, dissolved sait, suspended particulate, or 25 other materials or additives that may be présent in the water.

[0106] If there is any différence between U.S. or Impérial units, U.S. units are intended.

[0107] As used herein, a “sack” (“sk”) is an amount that weighs 94 pounds (94 lb/sk) [0108] As used herein, the conversion between gallon per sack (gal/sk) and percent by weight of cernent (% bwoc) is 1 gal/sk = 3.96% bwoc.

[0109] The conversion between pound per gallon (lb/gal or ppg) and kilogram per cubic meter (kg/m³) is: 1 lb/gal = (0.453592 kg/lb) x (gal/0.003785 m³) = 120 kg/m³.

General Approach [0110] Foamed cernent contains gas which maintains sufficient pressure so as to prevent the fluid/gas migration during the transition of cernent fluid into the set solid mass.

[0111] Cernent slurry in an annulus loses its overbalance as a resuit of gélation and simultaneous volume réduction caused by the cernent hydration processes. If the pore pressure of the gelled cernent drops below réservoir pressure before the cernent has started to harden, gas 10 influx will occur. One method of combating the above pressure loss Is to include gas in the cernent. Compressed gas in the foam cernent maintains pressure and ensures that there is no gas migration through the cernent column.

[0112] Initial testing with a sulfonate dérivative of an alkyl polyglycoside (“APG”) provided very good results as a foaming surfactant for a cernent slurry, as described in more 15 detail below. The tested APG dérivative was decyl polyglucoside hydroxypropylsulfonate sodium sait (“DPG HPS”).

[0113] Based on this initial success using DPG HPS, a person of knowledge and expérience in the field would be able extrapolate to similar chemicals that would be likely to work according to the principles of this invention.

[0114] A cernent composition is provided, the composition comprising: (a) a hydraulic cernent; (b) water; and (c) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of: sulfonates, betaines, an inorganic sait of any of the foregoîng, and any combination of any of the foregoing.

[0115] Preferably, the cernent composition additionally comprises a gas, whereby the 25 cernent composition is foamed,

[0116] A method of cementing a portion of a well is provided, the method comprising the steps of: (A) forming a cernent composition according the invention; and (B) introducing the cernent composition into the well.

[0117] 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:

[0118] 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.

[0119] 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.

[0120] For any type of alkyl polyglycoside, independently of the other parameters, preferably m is in the range of 2 to 20.

[0121] 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.

[0122] 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.

[0123] The alkyl polyglycoside (APG) dérivative is selected from the group consisting of: functionalized sulfonates, functionalized betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing. 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, alkaline earth métal, and ammonium salts.

Most preferably, the inorganic sait is an alkali métal sait.

[0124] Most preferably, the alkyl polyglycoside (APG) dérivative is selected from the group consisting of:

(a) Decyl polyglucoside hydroxypropylsulfonate sodium sait;

(b) Lauryl polyglucoside hydroxypropylsulfonate sodium sait;

(c) Coco polyglucoside hydroxypropylsulfonate sodium sait;

(d) Lauryl polyglucoside sulfosuccinate disodium sait;

(e) Decyl polyglucoside sulfosuccinate disodium sait;

(f) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait;

(g) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (h) any combination of thereof.

[0125] In an embodiment, the APG dérivative is or comprises decyl polyglucoside hydroxypropylsulfonate sodium sait.

[0126] In a cernent slurry, the APG dérivative is preferably in a concentration in the range of 0.1 %bwoc to 0.5 %bwoc.

[0127] The APG dérivatives can be used as foaming surfactants for light-weight cernent compositions. The foaming surfactants are very effective. In addition, the foaming surfactants are compatible with tap water, seawater, NaCl, CaCh, and commonly-used fluid-loss control additives (such as a copolymer of acrylamide and 2-acrylamido-2-methyIpropanesulfonic acid). The foaming 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 foaming surfactants are biodégradable and non-toxic. After setting, a foamed cernent slurry according to the invention has sufficiently uniform density and good compressive strength.

[0128] While various gases can be utilized for foaming the treatment fluids, nitrogen, carbon dioxide, and mixtures thereof are preferred. In examples of such embodiments, the gas may be présent in a treatment fluid in an amount in the range of from about 5% to about 98% by volume of the treatment fluid, and more preferably in the range of from about 20% to about 80%.

The amount of gas to incorporate into the fluid may be affected by factors including the viscosity of the fluid and wellhead pressures involved in a particular application.

Methods of Cementing [0129] According to another embodiment of the invention, a method of cementing is provided, the method including the steps of: (A) forming a cementing composition according to the invention; and (B) introducing the cementing composition into the well.

[0130] A cernent slurry can be prepared at the job site, prepared at a plant or facility prior to use, or certain components of the cernent slurry can be pre-mixed prior to use and then 10 transported to the job site. Certain components of the cernent slurry can be provided as a dry mix” to be combined with fluid or other components prior to or during introducing the cernent slurry into the well.

[0131] In certain embodiments, the préparation of a cernent slurry can be done at the job site in a method characterized as being performed “on the fly.” The term “on-the-fly” is used 15 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 ongoing treatment. Such mixing can also be described as “real-time” mixing.

[0132] Often the step of delivering a cernent slurry into a well is within a relatively 20 short period after forming the slurry, e.g., less within 30 minutes to one hour. More preferably, the step of delivering the cernent slurry is immediately after the step of forming, which is “on the fly.” [0133] It should be understood that the step of delivering a cernent slurry into a well can advantageously include the use of one or more fluid pumps.

[0134] Preferably, the step of introducing a cernent slurry is at a rate and pressure below the fracture pressure of the treatment zone.

[0135] After the step of introducing a cernent slurry and directing it to a desired treatment zone in a well, sufficient time should be allowed for the cernent slurry to thicken, and preferably, sufficient time should be allowed for the cernent slurry to set. This times should be

under the design conditions în the zone of the well. Preferably, the step of flowing back is within hours of the step of introducîng. More preferably, the step of flowing back is within 24 hours of the step of introducîng.

[0136] Preferably, after any such well treatment, a step of producing hydrocarbon from the subterranean formation is the désirable objective.

Examples [0137] To facîlitate 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.

Table L

Name:	Decyl polyglucoside hydroxypropylsulfonate sodium sait (“DPG HPS”)
Activity:	40.0% (aqueous solution)
pH (10% aqueous solution):	7.0
Flash Point:	> 200 °F (93 °C)
Storage Température:	50 °F to 100 °F (10 °C to 38 °C)
Spécifie gravity at 25 °C:	1,10

[0138] Regarding biodegradability, DPG HPS reportedly achieved 80% to 82% biodegradability and exceeded the 70% biodegradability requirement for ready biodegradability of a single organic substance or natural product when tested according to AS4351 Part 2.

[0139] Regarding toxicological effects, this product îs reported as being non-irritating, causing no visible skin reaction, and having an acute toxicity (Rat): Oral ingestion, greater than 2g/kg, LD50, where ail animais survived without any sign of toxicity.

Testing Procedures [0140] The foaming surfactant was tested in a Class G cernent slurry. The effect of tap water, seawater, NaCl, CaCl₂, and a commonly-used fluid-loss control agent was investigated. In

a typical experiment, the cernent was suspended in water to form slurry. The fluid-loss control agent used in the si unies was copolymer of acrylamide and 2--acry lamido-2methylpropanesulfonic acid. A calculated amount of the cernent slurry was transferred to a foam can and then the foaming surfactant was added. A foam can is laboratory-scale mixing jar 5 wherein the cernent slurry and the foaming surfactant are mîxed together to obtain foamed cernent slurry, which has a capacity of 1,170 ml.

[0141] The base density of the cernent slurry was measured before foaming of the slurry. The foaming was done for 20 seconds. The density of the foamed slurry was measured. The densities were measured using an atmospheric mud balance (a balance used to measure the 10 density of the cernent slurry at atmospheric pressure).

[0142] The foamed slurry was cured at 140 °F (60 °C) for 24 hours at atmospheric pressure in a water bath. The cured cernent slurry was tested for density variation (sédimentation test). The cernent slurry was cured in the form of cylinder (dimensions: about 1 inch diameter and about 6 inch length). The cured cylindrical samples were sliced into three portions of equal 15 length. The densities were measured for the top, middle, and bottom portions of the cured sample. The stability of the foamed cernent slurry through setting can be determined by measuring the variation in density. The allowed variation in density is up to about 0.5 ppg (60 kg/m³) between the top, middle, and bottom portions of the cured sample.

[0143] In addition, the crush strength of each cured sample was measured.

[0144] The cernent slurry compositions and results are given in Table 2.

Table 2. Slurry Compositions, Densifies, and Crush Strengths

Slurry No.	“Control”	1	2	3	4	5	6
Base density lb/gal (kg/m3)	15.8 (1900)	15.5 (1860)	15.8 (1900)	15.5 (1860)	15.8 (1900)	16.0 (1920)	16.6 (1990)
Class G Cernent base %	100	100	100	100	100	100	100
“DPG HPS” foaming surfactant gal/sk (%bwoc)	-	0.087 (0.34)	0.063 (0.25)	0.087 (0.34)	0.063 (0.25)	0.063 (0.25)	0.063 (0.25)
Fluid-loss control agent (% bwoc)	-	-	-	0.6	-	-	-
CaCb (% bwoc)	-	-	-	-	2.0	-	-
NaCI (% w/w of water)	-	-	-	-	-	-	18
Water (% bwoc)	45.10	47.6	44.6	47.6	44.65	45.10* seawater	40.51
Foam Can (g)	-	1675.25	1675.11	1675.28	1675.15	1675.13	1675.26
Foamed Density lb/gal (kg/m3)	-	11.3 (1360)	11.2 (1340)	13.0 (1560)	11.8 (1420)	11.8 (1420)	12.3 (1480)
Cured at 140 °F (60 °C) for 24 hours
Top Density lb/gal (kg/m3)	-	10.16 (1220)	10.45 (1254)	12.68 (1522)	11.60 (1392)	11.35 (1362)	11.88 (1426)
Middle Density lb/gal (kg/m3)	-	10.23 (1227)	10.39 (1247)	12.89 (1547)	11.81 (1417)	11.44 (1373)	11.95 (1434)
Bottom Density lb/gal (kg/m3)	-	10.24 ¢12.29)	10.59 (1271)	12.97 (1556)	11.57 (1388)	11.50 (1380)	11.98 (1438)
Crush Strength psi (Mpa)	-	1045 (7.21)	1189 (8.20)	1021 (7.04)	2060 (14.2)	1977 (13.6)	902 (6.22)

[0145] In addition, Slurry No. 4 was tested after curing at 72 °F (22 °C) for 24 hours.

For this test, the top, middle, and bottom densities were 12.12 lb/gal (1454 kg/m³), 12.09 5 (1451 kg/m³), and 12.12 lb/gal (1454 kg/m³), respectively, and the crush strength was 330 psi (2.3 MPa).

[0146] Thickening time of cernent slurries was also tested with the use of an HPHT consistometer. In order to compare the results to a conventional cernent slurries, a cernent slurry

without any foaming surfactant (“Control” in Table 2), a cernent slurry comprising a conventîonal alkyl polyglucoside foaming surfactant (TERRADRIL S 853 B™ commercially available from Baroid), and a cernent slurry including “DPG HPS” as the foaming surfactant was tested (Slurry No. 2 in Table 2).

[0147] These slurries were tested at 140 °F (60 °C) and 240 °F (116 °C). The results shown in Table 3 demonstrate that the “DPG HPS” as a foaming surfactant did not significantly retard thickening time, whereas the conventîonal foaming agent did retard the thickening times.

Table 3. Thickening Times

Slurry No.	Foaming Surfactant and Concentration	Thickening time at 140 °F (60 °C) (HR:MM)
Control	none	1:15
Conventîonal	Conventîonal Foaming Surfactant “TERRADIRIL S 853 B” at 0.041 gal/sk (0.252 %bwoc)	4:56
2	“DPG HPS Foaming Surfactant at 0.063 gal/sk (0.252 %bwoc)	1:28

[0148] The APG dérivative performs well as a foaming surfactant for cernent in a variety of different type of slurries, e.g., cernent with tap water, seawater, or containing NaCl or CaCh; it is biodégradable; it is non-toxic; and do not reduce the compressive strength to set cernent. Moreover, the material is compatible with fluid-loss control additives such as a 15 copolymer of acrylamide and 2-acrylamido-2-methylpropanesulfonic acid, which is a significant advantage. This material can be used anywhere in the world including the “North Sea région.”

Conclusion [0149] Therefore, the présent invention is well adapted to attain the ends and advantages mentioned as well as those that are inhérent thereîn.

[0150] 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 10 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, 15 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 20 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.

[0151] 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 25 skilled in the art having the benefit 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.

[0152] 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 efficiency and benefits that can be obtained from the invention.

[0153] The invention illustrât!vely disclosed herein suitably may be practiced in the absence of any element or step that is not specifically disclosed or claimed.

[0154] Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.

Claims (20)

1. A cernent composition comprising:

(a) a hydraulic cernent;

(b) water; and (c) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of: sulfonates, betaines, an inorganic sait of any of the foregoing, and any combination of any of the foregoing.

2. The cernent composition according to claim 1, wherein the aikyl 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.

3. The cernent composition according to claim 2, wherein n is in the range of 8 to

24.

4. The cernent composition according to claim 2, wherein m is in the range of 2 to

20.

5. The cernent composition according to claim 1, wherein the sulfonate is selected from the group consisting of hydroxyalkylsulfonates.

6. The cernent composition according to claim 5, wherein the alkyi of the hydroxylalkylsulfonate is selected from the group consisting of short-chain alkyi groups having in the range of 1 to 6 carbons.

7. The cernent composition according to claim 1, wherein the inorganic sait of the alkyi polyglycoside dérivative is selected from the group consisting of alkali métal, alkaline earth métal, and ammonium salts.

8. The cernent composition according to claim 1, wherein the alkyi polyglycoside dérivative is selected from the group consisting of:

(a) Decyl polyglucoside hydroxypropylsulfonate sodium sait;

(b) Lauryl polyglucoside hydroxypropylsulfonate sodium sait;

(c) Coco polyglucoside hydroxypropylsulfonate sodium sait;

(d) Lauryl polyglucoside sulfosuccinate disodium sait;

(e) Decyl polyglucoside sulfosuccinate disodium sait;

(f) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait;

(g) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (h) any combination of thereof.

9. The cernent composition according to claim I, wherein the alkyi polyglycoside dérivative comprises: decyl polyglucoside hydroxypropylsulfonate sodium sait.

10. The cernent composition according to any one of claims 1-9, additionally comprising a gas, whereby the cernent composition is foamed.

11. A method of cementing a portion of a well, the method comprising the steps of:

(A) forming a cernent composition comprising:

(a) a hydraulic cernent;

(b) water; and (c) an alkyl polyglycoside dérivative, wherein the alkyl polyglycoside dérivative is selected from the group consisting of: sulfonates, betaines, an inorganic sait of any of the foregoîng, and any combination of any of the foregoing; and (B) introducing the cernent composition into the well.

12. The method according to claim 1, wherein the alkyl polyglycoside is an alkyl polyglucoside having a chemical structure:

OH

OH wherein n for the alkyl is 8 or greater; and wherein m for the polyglucoside is 2 or greater.

13. The method according to claim 12, wherein n is in the range of 8 to 24.

14. The method according to claim 12, wherein m is in the range of 2 to 20.

15. The method according to claim 11, wherein the sulfonate is selected from the group consisting of hydroxyalkyl sulfonates.

16. The method according to claim 15, wherein the alkyl of the hydroxylalkylsulfonate is selected from the group consisting of short-chain alkyl groups having in the range of 1 to 6 carbons.

17. The method according to claim II, 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. The method according to claim 11, wherein the alkyl polyglycoside dérivative is selected from the group consisting of:

(a) Decyl polyglucoside hydroxypropylsulfonate sodium sait;

(b) Lauryl polyglucoside hydroxypropylsulfonate sodium sait;

(c) Coco polyglucoside hydroxypropylsulfonate sodium sait;

(d) Lauryl polyglucoside sulfosuccinate disodïum sait;

(e) Decyl polyglucoside sulfosuccinate disodium sait;

(f) Lauryl polyglucoside bis-hydroxyethylglycinate sodium sait;

(g) Coco polyglucoside bis-hydroxyethylglycinate sodium sait; and (h) any combination of thereof.

19. The method according to claim 11, wherein the alkyl polyglycoside dérivative comprises: decyl polyglucoside hydroxypropylsulfonate sodium sait.

20. The method according to any one of claims 11-19, additionally comprising a gas, whereby the cernent composition is foamed.