• 专利附录
  • 专利说明
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    • 专利摘要:
    The present disclosure relates to a method of limiting an annular pressure buildup, comprising providing or using a foamed process fluid, comprising: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed treatment fluid into an annulus (24) of a wellbore (12). The present disclosure also relates to a foamed process fluid combining the aforementioned components.
    公开号:FR3040391A1
    申请号:FR1657264
    申请日:2016-07-28
    公开日:2017-03-03
    发明作者:Chase R Gamwell；Samuel L Lewis；Thomas S Sodhi
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    CONTEXT
    A natural resource such as oil or gas in an underground formation can be recovered by drilling a well in the formation. The underground formation is usually isolated from other formations according to a known technique such as well cementing. In particular, a wellbore is typically drilled into the subterranean formation while a drilling fluid is circulated through the wellbore. Once the drilling is complete, a drill string, e.g. a casing is introduced into the wellbore. The primary cementing is then generally carried out, whereby a slurry of cement is pumped down through the pipe string and into the annulus between the pipe string and the walls of the wellbore to allow the suspension to flow. cement to harden in an impermeable column of cement thus sealing the annular space. Secondary cementing operations can be carried out after the primary cementing operation. An example of a secondary cementation operation is to compress the cementation, whereby a cement slurry is forcibly moved under pressure to areas of integrity lost in the annulus to seal these areas.
    After cementing operations, oil or gas production can begin. Oil and gas are produced at the surface after flowing through the wellbore. When oil and gas pass through the wellbore, heat can escape from these fluids through the casing and into the annulus, typically resulting in the expansion of any fluid in the annulus. This expansion can cause a build-up of pressure in the annulus, called annular pressure increase. The annular pressure increase typically occurs when the annular volume is fixed. For example, the annular space may be closed (eg trapped). The annular space is trapped to isolate fluids in the annular space from areas outside thereof. Trapping of an annular space typically occurs towards the end of the cementing operations, once well completion fluids such as spacing fluids and cements are in place. The annulus is usually trapped by closing a valve, which activates a seal and similar elements. Trapping presents operational problems. For example, the build-up of ring pressure can damage the wellbore to the point of damaging the cement sheath, casing, tubing and other equipment.
    A number of techniques have been used to combat ring pressure build-up, including the use of synthetic foam encased in casing, the introduction of nitrified spacing fluids over cement into space annular, the placement of rupture discs in an outer casing, the design of deficiencies in primary cementing operations, such as the design of the top of the cement column in an annular space to be short of the previous casing shoe, the use of hollow spheres, among others. However, these methods have their disadvantages. For example, syntactic foam may cause flow restrictions during primary casing cementation in the wellbore. In addition, the syntactic foam may become detached from the casing and / or degrade during the installation of the casing. Disadvantages of placement of nitrified spacing fluids include logistical difficulties (eg, limited space for accompanying surface equipment), pressure limitations on the wellbore, and typical high expense associated with it. Other disadvantages associated with the placement of nitrified spacer fluids include loss of returns when circulating the nitrified spacer fluid in place and in situations where geographical conditions create difficulties in providing the proper equipment to pump the nitrified spacer fluid into place. nitrified spacing fluid. Other disadvantages include such compression of the casing string by the disc failure disks, that it becomes impossible to continue operations of the wellbore. Other disadvantages include design failure, which may not occur due to the non-displacement of the wellbore fluids as expected and the build-up of cement to a casing shoe and the entrapment of the cement. In addition, the problems inherent in hollow spheres include the failure of the spheres prior to their placement in the annulus and their inability to withstand repeated pressure / temperature variations,
    PRESENTATION
    According to one or more embodiments of the present disclosure, a foamed treatment fluid suitable for limiting an annular pressure buildup comprises: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-carbon-containing polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form the foamed process fluid.
    According to one or more embodiments of the present disclosure, a method of limiting an annular pressure buildup comprises: providing or using a foamed process fluid, which comprises: an aqueous base fluid ; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed treatment fluid into an annulus of a wellbore.
    According to one or more embodiments of the present disclosure, a method of limiting an annular pressure buildup comprises: preparing a foamed process fluid by combining an aqueous base fluid with: a water soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and enough gas to form a foam; and introducing the foamed treatment fluid into an annulus of a wellbore.
    According to one or more embodiment (s) of the present disclosure, the method further comprises using a mixer for combining the components and a pump for introducing the foamed treatment fluid into the annulus of the well. drilling.
    According to one or more embodiments of the present disclosure, the water-soluble carbonyl-containing polymer comprises at least one of the following: an acrylamide-based polymer, an oxidized polysaccharide, and combinations thereof.
    According to one or more embodiments of the present disclosure, the organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups is selected from the group consisting of: polyalkylene imine; a polyalkylene polyamine, a polyfunctional aliphatic amine, an arylalkylamine, a heteroarylalkylamine and combinations thereof.
    According to one or more embodiment (s) of the present disclosure, the foamed treatment fluid contains no ionic crosslinking agent.
    According to one or more embodiment (s) of the present disclosure, the foamed treatment fluid further comprises a gelling agent.
    According to one or more embodiment (s) of the present disclosure, the gelling agent is a biopolymer.
    According to one or more embodiments of the present disclosure, the foam surfactant contains at least one of an amphoteric surfactant, a cationic surfactant, an anionic surfactant, and combinations thereof.
    According to one or more embodiment (s) of the present disclosure, the foam surfactant contains at least one compound from the group consisting of betaines, sultaines and imidazolinium, sodium lauryl sulphate (SLS), polyfoxyclenylene alcohols fatty acids), polyoxyethylene sorbitol esters, alkanolamides, sulfosuccinates, phospholipids, glycolipids, laurylsodium sulphoacetates, alcohol ether sulphates and combinations thereof.
    According to one or more embodiments of the present disclosure, the foam surfactant is present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid.
    According to one or more embodiment (s) of the present disclosure, the quality of the foam is between 5% of the gas volume to about 99% of the gas volume.
    According to one or more embodiment (s) of the present disclosure, the gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination of these.
    According to one or more embodiments of the present disclosure, the method further comprises using the process fluid to move a drilling fluid from the annulus of the wellbore; and introducing a cement composition into the annulus of the wellbore, the process fluid separating the cement composition from the drilling fluid.
    BRIEF DESCRIPTION OF THE DRAWINGS
    The following figures are presented to illustrate certain aspects of the present disclosure, and should not be considered as exclusive embodiments. The disclosed object is capable of significant modifications, alterations and equivalents in form and function, as will be apparent to a person skilled in the art and who benefits from this disclosure.
    Figure 1 is a photograph of an embodiment of the foamed crosslinked polymer system of the disclosure.
    Fig. 2 shows an embodiment of placing the foamed treatment fluids in an annulus of a wellbore.
    Figure 3 illustrates an embodiment of a system for producing and delivering foamed process fluids of the embodiments described herein in the annulus of a wellbore.
    Figure 4 is a graph showing pressure fluctuations over time of heated water in an ultrasonic cement analyzer ("UCA").
    Fig. 5 is a graph of time pressure fluctuations of the liquid variant of an unfoamed process fluid which is heated according to the disclosure.
    Fig. 6 is a graph showing the pressure fluctuations over time of the gelled variant of an unfoamed process fluid that is heated according to the disclosure.
    Figure 7 is a graph of time pressure fluctuations of the liquid variant of a foamed process fluid that is heated according to the disclosure.
    Fig. 8 is a graph showing the pressure fluctuations over time of the gelled variant of a foamed process fluid that is heated according to the disclosure.
    Figures 9A and 9B are photographs of the foamed and gelled material after testing in the UCA.
    DETAILED DESCRIPTION
    This disclosure describes a foaming process of a two-part crosslinked polymer system that can be used to limit annular pressure buildup ("APB"). The disclosed system may, once foamed, be compressed (and change shape) as needed to limit the increase in APB pressure and other potential downhole variations to temperatures that may exceed 400 ° F (about 204 ° C). VS).
    The described polymer system consists of several parts. The base is a linear or modified carbonyl-containing polymer and the crosslinking agent is an agent that contains an amine group capable of cross-linking the carbonyl-containing polymer. These two compounds are mixed to form a gel. When a foam surfactant is added, the gel can foam according to varying qualities. One embodiment of the final product, as seen in Figure 1, is a low density solid foam that is flexible but resilient.
    The materials used in the state of the art have several disadvantages. As higher temperature production fluids up to about 400 ° F (about 204 ° C) pass through the production piping, they can significantly increase the temperature of the annular fluid. Most of the fluids of the prior art are unable to fully limit the build-up of pressure at these very high temperatures. In addition, while the temperature increases by about 140 ° F (about 60 ° C), stabilizers, such as sodium bicarbonate, may be required. Many of the compounds of the present disclosure may limit the increase in APB to temperatures that may exceed 400 ° F (about 204 ° C).
    Secondly, the crosslinking agents used in the state of the art are typically based on chromium. These crosslinking agents are less desirable because some species containing chromium can be toxic. The compounds of the present disclosure utilize an ionic crosslinking agent.
    Some embodiments of the APB limitation include: providing or using a foamed treatment fluid, comprising: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed treatment fluid into an annulus of a wellbore. In some embodiments, the water-soluble carbonyl-containing polymer comprises at least one of the following: an acrylamide-based polymer, an oxidized polysaccharide, and combinations thereof. In one embodiment, the organic crosslinking agent that contains an amine group capable of cross-linking the water-soluble carbonyl-containing polymer is selected from the group consisting of: polyalkyleneimine; polyethylene imine, polyalkylene polyamine, polyfunctional aliphatic amine, arylalkylamine, heteroarylalkylamine and combinations thereof. In some embodiments, the foamed process fluid does not contain any ionic crosslinking agent. In some embodiments, the foamed process fluid further comprises a gelling agent. This gelling agent may be a biopolymer. In many embodiments, the foam surfactant contains at least one amphoteric surfactant, one cationic surfactant, one anionic surfactant, and combinations thereof. The foam surfactant contains at least one compound from the group consisting of betaines, sultaines and imidazolinium, sodium lauryl sulphate ("SLS"), poly (oxyethylene of fatty alcohols), polyoxyethylene sorbitol esters, alkanolamides, sulfosuccinates, phospholipids, glycolipid, laurylsodium sulfoacetate, alcohol ether sulfates, and combinations thereof. The foam surfactant may be present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid. The quality of the foam can range from 5% of the gas volume to about 99% of the gas volume. In some embodiments, the gas may be selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination thereof. The method may further include using the process fluid to move a drilling fluid from the annulus of the wellbore; and introducing a cement composition into the annulus of the wellbore, the process fluid separating the cement composition from the drilling fluid.
    In some embodiments, a method of limiting the annular pressure buildup comprises: combining an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and enough gas to form a foam; and introducing the foamed treatment fluid into an annulus of a wellbore. In some embodiments, the method includes a mixer for combining the components and a pump for introducing the foamed process fluid into the annulus of the wellbore.
    In one embodiment, a foamed treatment fluid for limiting the annular pressure buildup comprises: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foamed process fluid. In some embodiments, the water-soluble carbonyl-containing polymer comprises at least one of the following: an acrylamide-based polymer, an oxidized polysaccharide, and combinations thereof. In one embodiment, the organic crosslinking agent that contains an amine group capable of cross-linking the water-soluble carbonyl-containing polymer is selected from the group consisting of: polyalkyleneimine; polyethyleneimine, polyalkylenepolyamine, polyfunctional aliphatic amine, arylalkylamine, heteroarylalkylamine and combinations thereof. In some embodiments, the foamed process fluid does not contain any ionic crosslinking agent. In some embodiments, the foamed process fluid further comprises a gelling agent. This gelling agent may be a biopolymer. In many embodiments, the foam surfactant contains at least one amphoteric surfactant, one cationic surfactant, one anionic surfactant, and combinations thereof. The foam surfactant may contain at least one compound from the group consisting of betaines, sultaines and imidazolinium, SLS, poly (oxyethylene fatty alcohols), polyoxyethylene sorbitol esters, alkanolamides, sulfosuccinates, phospholipids, glycolipid, laurylsodium sulfoacetate, alcohol ether sulfates, and combinations thereof. The foam surfactant may be present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid. The quality of the foam can range from 5% of the gas volume to about 99% of the gas volume. In some embodiments, the gas may be selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination thereof.
    Aqueous base fluids
    The aqueous base fluid of the present embodiments can generally be from any source, provided that the fluids do not contain components that may affect the stability and / or performance of the process fluids of the present invention.
    In various embodiments, the aqueous base fluid may comprise fresh water, salt water, sea water, brine or an aqueous solution of a salt. In some embodiments, the aqueous base fluid may contain a monovalent brine or a divalent brine. Suitable monovalent brines may include, for example, sodium chloride brines, sodium bromide brines, potassium chloride brines, potassium bromide brines, and the like. Suitable divalent brines may include, for example, magnesium chloride brines, calcium chloride brines, calcium brines and the like.
    In some embodiments, the aqueous base fluid is present in the foamed process fluids at a concentration of about 20% to about 99% by volume of the fluid system.
    Water-soluble polymer
    The foamed treatment fluids of the disclosure include a water-soluble polymer containing carbonyl groups. Generally, the water-soluble carbonyl-containing polymer should react, under appropriate conditions (eg, time, temperature, choice of particular organic crosslinking agent, etc.) with the organic crosslinking agent to form a crosslinked gel. . The carbonyl groups may be contained in the groups dependent on the water-soluble polymer or contained in the backbone of the polymer. Examples of suitable carbonyl groups may include, but are not limited to, ester, aldehyde, ketone, anhydride, amide and carboxylic acid groups. Suitable water-soluble polymers containing carbonyl groups include, but are not limited to, saturated or unsaturated acrylamide-based polymers. Examples include, but are not limited to, polyacrylamide, acrylamide copolymers, polyvinyl pyrrolidone, 2-acrylamido-2-methylpropane sulfonic acid / acrylamide copolymers, sulfonated styrene / maleic anhydride copolymers, terpolymers of vinylpyrrolidone / 2-acrylamido-2-methylpropanesulphonic acid / acylamide, terpolymers of acrylamide / t-butyl acrylate / N-vinylpyrrolidone, terpolymers of acrylamide / t-butyl acrylate / 2-acrylamido-2-methylpropane acid sulfonic acid, terpolymers of 2-acrylamido-2-methylpropanesulphonic acid / N, N-dimethylacrylamide / acrylamide, tetrapolymers of acrylamide / t-butyl acrylate / N-vinylpyrrolidone / 2-acrylamido-2-methylpropanesulphonic acid, copolymers acrylamide / t-butyl acrylate and mixtures thereof and derivatives thereof. Those skilled in the art will recognize from this disclosure that other suitable water-soluble polymers containing carbonyl groups may also be used in the present invention.
    In some embodiments, the carbonyl-containing polymer comprises oxidized starch. Examples of suitable starches include, but are not limited to, corn starch, potato starch, waxy maize and dextrinized starch, and mixtures thereof. A large number of oxidants can be used to oxidize the starch. Examples of suitable oxidants used in the present invention include but are not limited to sodium hypochlorite, sodium periodate, hydrogen peroxide and peracetic acid, and mixtures thereof. Those skilled in the art benefiting from this disclosure will appreciate that related oxidized polysaccharides, other than oxidized starch, can be used to cross-link with the organic crosslinking agent, including oxidized cellulose, oxidized agarose, oxidized cellulose partially acetylated and oxidized gums and mixtures thereof. Other compounds that can be employed include dialdehyde starch (DAS) and dialdehyde cellulose, and mixtures thereof. In some embodiments, the oxidized polysaccharides contain at least one ketone, aldehyde, or anhydride functional groups upon oxidation. In some embodiments, the oxidized polysaccharides may be used in combination with any of the aforementioned water-soluble polymers. Generally, increasing the fraction of hindered or less reactive monomers in the water-soluble polymer containing carbonyl groups, the temperature at which the gelation takes place may increase and / or the pumping time at a given temperature may increase. One skilled in the art benefiting from this disclosure will recognize a suitable water-soluble polymer containing carbonyl groups based on, among other factors, the temperature of the formation and the desired pumping time.
    The water-soluble polymers containing carbonyl groups should be present in the water-soluble crosslinkable compositions of the present invention in an amount sufficient to provide the desired pumping time prior to freezing and the desired crosslinking reaction.
    In some embodiments, the water-soluble carbonyl-containing polymers may be present in the range of about 0.5% to about 20% by weight of the composition. In some embodiments, the water-soluble carbonyl-containing polymer may be present in an amount of from about 0.6% to about 12% by weight of the composition.
    Organic crosslinking agents
    One component of the foamed treatment fluids of the disclosure comprises an organic crosslinking agent. Suitable organic crosslinking agents should be capable of crosslinking with the water-soluble polymers containing carbonyl groups. Under the appropriate conditions (eg, time, temperature) the organic crosslinking agent should react with the water soluble polymer to give a crosslinked gel.
    Suitable organic crosslinking agents may contain amine groups capable of undergoing a crosslinking reaction with the water-soluble polymers containing the carbonyl groups. Examples of suitable organic crosslinking agents include, but are not limited to, polyalkyleneimines (eg, polyethyleneimine), polyalkylenepolyamines, polyfunctional aliphatic amines, arylalkylamines, heteroarylalkylamines, and mixtures thereof. In some embodiments, the organic crosslinking agent contains polyethyleneimine ("PEI"). The organic crosslinking agent should be part of the crosslinkable polymer compositions of the present invention in an amount sufficient to provide the desired crosslinking reaction. In some embodiments, the organic crosslinking agent may be present in an amount of from about 0.05% to about 15% by weight of the composition. In some embodiments, the organic crosslinking agent may be present in the range of about 0.5% to about 5% by weight of the composition.
    Foam surfactants
    In one embodiment, the present disclosure utilizes foam surfactants to improve the quality of the stabilizing foams and to add some stability to the foams. In some embodiments, the foam surfactants are selected from an amphoteric surfactant, a cationic surfactant, an anionic surfactant, and combinations thereof.
    Useful foamed surfactants include betaines, sultaines and rimidazolinium such as cocamidopropyl betaine, and sodium lauraminopropionate, lauryl sodium sulfate (SLS) and other fatty alcohol ether sulfates including SLES, poly (oxyethylene fatty alcohols) and polyoxyethylene sorbitol esters and alkanolamides, sulfosuccinates (eg, disodium laureth sulfosuccinate), phospholipids, glycolipid, laurylsodium sulfoacetate and combinations thereof. In some embodiments, the combinations of surfactants, i.e. co-surfactants cooperate to produce a useful foam surfactant.
    In exemplary embodiments, the foam surfactant is present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid.
    Gas
    In some embodiments, the gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination thereof. In some embodiments, the quality of the foamed fracturing fluid may be between a lower limit of about 5%, 10%, 25%, 40%, 50%, 60% or 70% by volume of gas up to an upper limit of approximately 99%, 90%, 80%, 75%, 60% or 50% by volume of gas, the quality of the foamed fracturing fluid ranging from any lower limit to any upper limit and encompassing any subset between the upper and lower limits.
    Gelling agents
    The foamed treatment fluids may comprise a gelling agent. A "base gel" is a fluid that contains a viscosity-increasing agent, such as a guar, but excludes, for example, the fluids commonly referred to as "cross-linked gels" and "Surfactant gels".
    In the water-based fluid, a number of gelling agents may be used, such as hydratable polymers containing at least one functional group such as hydroxyl, carboxyl, sulfate, sulfonate, amino or amide groups. Suitable gelling agents typically include natural polymers, synthetic polymers or a combination thereof. A number of gelling agents may be used in connection with the methods and compositions of the present invention, including but not limited to hydratable polymers which contain at least one functional group such as hydroxyl, cis-hydroxyl , carboxylic acids, carboxylic acid derivatives, sulphate, sulphonate, phosphate, phosphonate, amino or amide. In certain exemplary embodiments, the gelling agents may be polymers comprising polysaccharides and their derivatives which contain at least one of these monosaccharide units: galactose, mannose, glucose, xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate. Examples of suitable polymers include, but are not limited to, xanthan, guar, guar derivatives (such as hydroxypropyl guar, carboxymethyl guar, and carboxymethylhydroxypropyl guar) and cellulose derivatives (such as hydroxyethyl cellulose and cellulose). carboxylmethyl hydroxyethyl). In addition, synthetic polymers and copolymers which contain the aforementioned functional groups can be used. Examples of such synthetic polymers include but are not limited to polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol and polyvinylpyrrolidone.
    The aqueous base fluid may comprise aqueous linear gels, aqueous linear polysaccharide gels, aqueous linear guar gels, groundwater, water, brine, viscoelastic surfactant solution and combinations thereof. .
    Other adjuvants
    In addition to the aforementioned materials, it may be desirable in some embodiments that other components be present in the process fluid. These additional components may include, but are not limited to, particulate matter, proppants, fibrous materials, bridging agents, weighting agents, gravel, corrosion inhibitors, catalysts, stabilizing agents, clay, biocides, bactericides, friction reducing agents, gases, surfactants, solubilizers, salts, scale inhibitors, foaming agents, anti-foaming agents, bleaching agents, iron regulation and the like.
    Methods of use
    Process fluid embodiments may be used in various wellbore maintenance operations. The treatment fluid may for example be a spacer fluid, a drilling fluid, a completion fluid such as a cement composition or a locating fluid. According to the present embodiments, the process fluid may be placed in a wellbore annulus. In general, an operator can circulate at least one additional fluid (e.g., a cement composition) onsite in the subsurface annulus after embodiments of the process fluids. At least a portion of the embodiments of the process fluids can then be trapped in the annulus of the wellbore. In some embodiments, at least a portion of the process fluid may be trapped at a certain time after a cement composition is circulated in a desired portion in the annulus to meet the operator's expectations. .
    An exemplary method includes a method of maintaining a wellbore comprising the steps of: using a process fluid that contains a foamed and crosslinked polymer; and introducing the process fluid into an annulus of the wellbore. Other process steps may include at least one of the following steps: using the process fluid to move a drilling fluid from the annulus of the wellbore; introducing a cement composition into the annulus of the wellbore, the process fluid separating the cement composition from the drilling fluid; allowing the cement composition to harden in the annulus of the wellbore; or allowing at least a portion of the process fluid to be trapped in the annulus of the wellbore. In some exemplary embodiments, the process fluid may be trapped in the annulus of the wellbore, for example, after placement of the process fluid in the annulus of the wellbore. In other embodiments, the process fluid may be a drilling fluid that is circulated in an annulus of a wellbore while drilling the well. At least a portion of the process fluid may be left in the hole of the well after completion of the drilling operations.
    The process fluids of the present invention may be prepared by any method suitable for a given application. For example, certain components of the process fluid of the present invention may be provided as a premixed powder or as a powder dispersion in a liquid, and then combined with the aqueous base fluid at a later stage. Once these components are combined, the foaming agent can be injected into the liquid stream. After this procedure, a gas, such as nitrogen, may be injected to foam the treatment fluid. In addition, other adjuvants may be added prior to introduction into the wellbore. Specialists benefiting from this disclosure may determine other suitable methods for the preparation of the process fluids of the present invention.
    Drilling well and training
    Basically, an area is a rock interval along a borehole that is differentiated from surrounding rocks over a hydrocarbon content or other elements such as perforations or other fluid communication with the well. drilling, gaps or fractures. Treatment usually involves introducing a treatment fluid into a well. In this context, a treatment fluid is a fluid used in a treatment. Unless the context otherwise requires, lexical processing in the term "process fluid" does not necessarily imply a particular action or treatment by the fluid. If the treatment fluid is to be used in a relatively small volume, for example less than about 200 barrels (about 31,798 liters), it is sometimes referred to in the art as a plug or pill. In this context, a treatment zone corresponds to a rock interval along a wellbore in which a process fluid is directed to flow from the wellbore. In this context, moreover, in a treatment area means in and through the wellhead and moreover, through the wellbore and into the treatment area.
    In this context, an underground formation may include introduction at least into and / or through a wellbore into the subterranean formation. According to various known techniques, equipment, tools or well fluids can be directed from a wellhead to any desired portion of the wellbore. In addition, a well fluid can be directed from a portion of the wellbore into the rock matrix of a zone.
    In various embodiments, systems are described for delivering process fluids described herein at the bottom of a wellbore. In various embodiments, the systems may include a pump fluidly coupled to a tubular portion, the tubular portion containing the process fluids, and any additional adjuvant described herein.
    Embodiments of the process fluids may be placed in a wellbore annulus in any convenient manner. The annulus of the wellbore must be an annular space between a pipe string (eg casing, piping, etc.) and an underground formation and / or between a pipe string and a larger pipe in the pipe. wellbore. For example, the treatment fluids may be placed in the annulus of wellbore directly from the surface. Alternatively, the process fluids may be introduced into a wellbore through the casing and circulated to the target in an annulus of wellbore between the casing and the subterranean formation or between the casing and a large conduit. Figure 2 illustrates the placement of the process fluid in a wellbore 12 according to exemplary embodiments. As can be seen, the wellbore 12 can be drilled in the subterranean formation 14. While the wellbore 12 is illustrated extending generally vertically in the subterranean formation 14, exemplary embodiments are also applicable to drilling wells which extend at an angle through the subterranean formation 14, such as horizontal and inclined wellbores. The wellbore 32 contains walls 16. As can be seen, a surface casing 18 has been introduced into the wellbore 12. The surface casing 18 can be cemented to the walls 16 of the wellbore 12 by a sheath. In the illustrated embodiment, at least one additional train of pipes, appearing here as the casing 22, may be in the wellbore 12. As illustrated, there is an annular space 24 of wellbore between tubing 22 and walls 16 of wellbore 12 and / or surface tubing 18. Embodiments of process fluids may be prepared according to a number of methods, as will be apparent to those skilled in the art. The treatment fluid can then be pumped down the casing 22, as shown in FIG. 4 by the directional arrows 26. The treatment fluid can flow to the bottom of the casing 22 and around the casing 22 in an annular space 24 wells.
    The pump may be a high pressure pump in some embodiments. In this context, the term "high pressure pump" will mean a pump that is capable of delivering fluid to the bottom at a pressure of about 1000 psi (or about 6895 kPa) or higher. A high pressure pump may be used when introducing the treatment fluid into a subterranean formation at or below a fracture gradient of the subterranean formation, but may also be used in cases where fracturing occurs. is not desired. In some embodiments, the high pressure pump may be able to fluidly transport particulate matter, such as proppant particles, into the subterranean formation. Suitable high pressure pumps will be known to a specialist and may include but not limited to floating piston pumps and positive displacement pumps.
    In other embodiments, the pump may be a low pressure pump. In this context, the term "low pressure pump" refers to a pump operating at a pressure of about 1000 psi (or about 6895 kPa) or less. In some embodiments, a low pressure pump may be fluidly coupled to a high pressure pump that is fluidly coupled to the tubular portion. That is, in these embodiments, the low pressure pump may be adapted to transport the process fluid to a high pressure pump. In these embodiments, the low pressure pump can "adjust" the pressure of the process fluid before it reaches the high pressure pump.
    In some embodiments, the systems described herein may further include a mixing tank that is upstream of the pump and wherein the process fluid is formulated. In various embodiments, the pump (e.g., a low pressure pump, a high pressure pump, or a combination thereof) can carry the treatment fluid from the mixing tank or other fluid source. treatment towards the tubular part. In other embodiments, the process fluid may be formulated off-site and transported to an operating site, in which case the process fluid may be introduced into the tubular portion by the pump directly from its container. shipping (eg a truck, wagon, barge or the like) or from a transport pipe. In either case, the process fluid can be drawn into the pump, raised to an appropriate pressure, and then introduced into the tubular portion for supply to the bottom of the hole.
    Figure 3 shows an illustrative diagram of a system capable of producing process fluids of the embodiments described herein at the bottom of a wellbore, according to at least one embodiment. Note that while Figure 3 illustrates, in general, a terrestrial system, it must be recognized that similar systems can be exploited in underwater sites as well. As shown in FIG. 3, the system 1 may comprise a mixing tank 10, in which a process fluid of the embodiments described herein can be formulated. The treatment fluid can be conducted through line 2 to the wellhead 4, where the treatment fluid enters the tubular portion 6, the tubular portion 6 extending from the wellhead 4 to the formation S. After ejection of the tubular portion 6, the treatment fluid can enter the underground formation 8. The pump 9 can be designed to raise the pressure of the treatment fluid to a desired degree before its introduction into the part It should be recognized that the system 1 is purely symbolic, and that various other components may be present which have not necessarily been described in FIG. 3, for the sake of clarity. Non-limiting components that may be present may include, but are not limited to, feed nozzles, valves, condensers, adapters, seals, gauges, sensors, compressors, gauges, sensors pressure sensors, flow meters, flow sensors, temperature probes, and the like.
    Although not shown in FIG. 3, the process fluid may, in some embodiments, flow back to the wellhead 4 and exit the subsurface formation 8. In some embodiments, the process fluid that has flowed back to at the wellhead 4 can then be recovered and recirculated to the underground formation 8.
    It must also be admitted that the treatment fluids described may also directly or indirectly affect the various equipment and downhole tools that may come into contact with the treatment fluids during operation. Such equipment and tools may include, but are not limited to, wellbore casing, wellbore liner, completion train, insertion trains, drill string, coiled tubing, smooth cable , a cable line, a drill pipe, drill collars, mud motors, downhole motors and / or pumps, motors and / or surface mounted pumps, centering devices, turbol scrapers, floats (eg shoes, collars, valves, etc.), logging tools and related telemetry equipment, actuators (eg electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production ducts, plugs, screens, filters, flow control devices (eg, influx control devices, self-contained impulse control devices, devices of the regulation of the escapement etc.), couplings (eg. an electrohydraulic wet coupling, dry coupling, inductive coupler, etc.), control lines (eg electrical, fiber optic, hydraulic, etc.), monitoring lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, gaskets, cement plugs, temporary plugs and other wellbore insulation, or components, and the like. Any of these components may be part of the systems generally described above and described in Figure 3.
    Now that the invention has been generally described, the following examples are given as particular embodiments and to demonstrate its implementation and its advantages. The following examples are for illustrative purposes only and are not intended to limit the following disclosure or claims in any way.
    EXAMPLES
    Experimental procedure:
    The foams described in Table 1 were tested for their effectiveness in limiting ΓΑΡΒ by a comparative test with water and with its unfoamed liquid counterpart. Each of the materials is poured into a UCA and pressurized before heating to 282 ° F (ie about 139 ° C). The unfoamed base suspension is prepared before foaming, and foamed according to the procedure of ΓΑΡΙ RP 10B-4 (July 2004), Section 7.
    Table 1
    Final foam density = 6.60 pounds / gal (about 0.79 kg / L)
    Foam quality = 24.04% in gas
    The HZ-30 ™ compliant material is a high molecular weight polyacrylamide used in production improvement. SA-1015 ™ suspending agent is an additive to prevent solids from settling and to regulate the free fluid present in cement suspensions. The crosslinking agent HZ-20 ™ allows organic crosslinking. Foaming agent 1026 ™ foaming agent / stabilizer is a mixture of a foam stabilizer and a primary foaming agent. All are available from Halliburton Energy Services, Inc., Houston, Texas.
    As seen in Figure 4, after placing in a UCA and heating, the water quickly starts to build up pressure, reaching the upper operating limit of 1UCA and requiring the release of pressure. Two heating cycles are demonstrated.
    Then an unfoamed variant of the process fluid is mixed and heated in the UCA to 282 ° F (about 139 ° C). As shown in FIG. 5, while it takes longer for the unfoamed fluid to reach the upper pressure limit of 1UCA used, the continuous accumulation of pressure once the temperature is reached requires the release of pressure from the cell. This test is carried out on the liquid variant of the non-foamed treatment fluid mixture. This material is tested a second time after it has had time to harden. In its gelled form, matter behaves similarly, though not exactly, as its liquid counterpart. If we look closely at the graph in Figure 6, we can see that the slope of the pressure curves increases a little. Here too, when one reaches the temperature, the UCA cell is ventilated to prevent the additional accumulation of pressure
    The foamed variant of the foamed treatment fluid forms a behavior other than water and the liquid variant of the treatment fluid (see FIG. 7). Once foamed and heated in the UCA cell, the liquid mixture does not quite reach the upper pressure limit of 1UCA. This may indicate a level of pressure limitation during the heating phase of the test. Here too, when we reach the temperature, the matter seems to limit some of the pressure that overcomes it. During the second cycle, however, the pressure is slightly higher than previously. This may indicate compression of the foam in the UCA cell.
    Once the liquid foam mixture has been allowed to cure, the heating cycles are started a second time (see Figure 8). Here again, when the temperature is reached, the foam is able to adapt to the pressure carried on it. While there is no decrease as important as that of the liquid foamed counterpart, the solid foam still allows to prevent the accumulation of pressure, under the effect of the temperature, to culminate rapidly as in the case of water and the variant of the liquid treatment fluid.
    One skilled in the art can conclude from the derivative that the total pressure accumulated when heated to 282 ° F (about 139 ° C) is attenuated and compensated for the foamed material.
    After the test, the UCA cell is opened and the foamed material is removed. As seen in Figure 9A, the foam appears intact. When completely removed from the cell, the foam shown in Figure 9B, although discolored by heating, still has a satisfactory shape.
    Embodiments described herein include: A: A method of limiting an annular pressure buildup, comprising providing or using a foamed process fluid, comprising: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed treatment fluid into an annulus of a wellbore. B: A method of limiting an annular pressure buildup comprising combining an aqueous base fluid with a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the combined foamed treatment fluid into an annulus wellbore space. C: A foamed treating fluid suitable for limiting an annular pressure buildup, comprising: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foamed process fluid.
    Each of Embodiments A, B and C may have one or more of the following additional elements, in any combination: Element 1: The water-soluble polymer containing carbonyl groups comprises at least one of the following compounds: acrylamide, an oxidized polysaccharide and combinations thereof. Element 2: The organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble carbonyl-containing polymer is selected from the group consisting of: polyalkyleneimine; a polyalkylene polyamine, a polyfunctional aliphatic amine, an arylalkylamine, a heteroarylalkylamine and combinations thereof. Element 3: The foamed treatment fluid contains no ionic crosslinking agent. Element 4: The foamed treatment fluid further comprises a gelling agent. Element 5: The gelling agent is a biopolymer. Element 6: The foam surfactant contains at least one of an amphoteric surfactant, a cationic surfactant, an anionic surfactant and combinations thereof. Element 7: the foam surfactant contains at least one compound from the group consisting of betaines, sultaines and imidazolinium, sodium lauryl sulphate (SLS), poly (oxyethylene) fatty alcohols, polyoxyethylene sorbitol esters, d alkanolamides, sulfosuccinates, phospholipids, glycolipid, laurylsodium sulfoacetate, alcohol ether sulfates and combinations thereof. Element 8: The foam surfactant is present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid. Element 9: The quality of the foam is between 5% of the gas volume to about 99% of the gas volume. Element 10: The gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination thereof. Element 11: further understanding the use of the process fluid for moving a drilling fluid from the annulus of the wellbore; and introducing a cement composition into the annulus of the wellbore, the process fluid separating the cement composition from the drilling fluid. Element 12: Further understanding the use of a mixer for combining the components and a pump for introducing the foamed treatment fluid into the annulus of the wellbore.
    Although the particular preferred embodiments of the present invention have been illustrated and described, those skilled in the art will be able to make modifications to them without departing from the teachings of the invention. The embodiments described here are only exemplary, and are not intended to be limiting. Variations and modifications of the invention described herein are possible and form part of the invention. The use of the term "possibly" with respect to any element of a claim is intended to mean that the element in question is required, or otherwise, not required. When two alternatives are mentioned in a claim, these two alternatives must be understood as falling within the scope of the claim.
    Many other modifications, equivalents and variations will be apparent to those skilled in the art once the aforementioned disclosure has been fully understood. It is intended that the following claims be interpreted to encompass all such modifications, equivalents or variations where applicable.
    权利要求:
    Claims (15)
    [1" id="c-fr-0001]
    A method of limiting an annular pressure buildup, characterized in that said method comprises: providing or using a foamed process fluid, which comprises: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed process fluid into an annulus (24) of a wellbore (12).
    [2" id="c-fr-0002]
    A method of limiting an annular pressure build-up characterized in that said method comprises: preparing a foamed process fluid by combining an aqueous base fluid with a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form a foam; and introducing the foamed process fluid into an annulus (24) of a wellbore (12).
    [3" id="c-fr-0003]
    The method of claim 2, further comprising using a mixer for combining the components and a pump for introducing the foamed treatment fluid into the annulus (24) of the wellbore (12). ).
    [4" id="c-fr-0004]
    The process according to any one of claims 1 to 3, wherein the water-soluble carbonyl-containing polymer comprises at least one of the following compounds: an acrylamide-based polymer, an oxidized polysaccharide, and combinations thereof.
    [5" id="c-fr-0005]
    The process according to any of claims 1 to 4, wherein the organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble carbonyl-containing polymer is selected from the group consisting of: polyalkylene imine; a polyalkylene polyamine, a polyfunctional aliphatic amine, an arylalkylamine, a heteroarylalkylamine and combinations thereof.
    [6" id="c-fr-0006]
    The method of any one of claims 1 to 5, wherein the foamed process fluid does not contain any ionic crosslinking agent.
    [7" id="c-fr-0007]
    The method of any one of claims 1 to 6, wherein the foamed process fluid further comprises a gelling agent.
    [8" id="c-fr-0008]
    The method of claim 7, wherein the gelling agent is a biopolymer.
    [9" id="c-fr-0009]
    The process according to any one of claims 1 to 8, wherein the foam surfactant contains at least one of an amphoteric surfactant, a cationic surfactant, an anionic surfactant and combinations thereof.
    [10" id="c-fr-0010]
    The process according to claim 9, wherein the foam surfactant contains at least one compound from the group consisting of betaines, sultaines and imidazolinium, sodium lauryl sulphate (SLS), poly (oxyethylene of fatty alcohols), polyoxyethylene sorbitol esters, alkanolamides, sulfosuccinates, phospholipids, glycolipid, laurylsodium sulphoacetate, alcohol alcohol sulphates and combinations thereof.
    [11" id="c-fr-0011]
    The method of any of claims 3 to 10, wherein the foam surfactant is present in the foamed process fluid at a concentration of about 0.005% to about 5% by weight of the aqueous base fluid.
    [12" id="c-fr-0012]
    The method of any one of claims 1 to 11, wherein the quality of the foam is from 5% of the gas volume to about 99% of the gas volume.
    [13" id="c-fr-0013]
    The process according to any one of claims 1 to 12, wherein the gas is selected from the group consisting of nitrogen, carbon dioxide, air, methane, helium, argon and any combination of these.
    [14" id="c-fr-0014]
    The method of any one of claims 1 to 13, further comprising using the process fluid to move a drilling fluid from the annulus (24) of the wellbore (12); and introducing a cement composition into the annulus (24) of the wellbore (12), the process fluid separating the cement composition from the drilling fluid.
    [15" id="c-fr-0015]
    A foamed treatment fluid suitable for limiting an annular pressure build-up, characterized in that the foamed process fluid comprises: an aqueous base fluid; a water-soluble polymer containing carbonyl groups; an organic crosslinking agent which contains an amine group capable of cross-linking the water-soluble polymer containing carbonyl groups; a foam surfactant; and sufficient gas to form the foamed process fluid.
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    同族专利:
    公开号 | 公开日
    US20180291251A1|2018-10-11|
    GB201800258D0|2018-02-21|
    FR3040391B1|2019-09-13|
    US10899956B2|2021-01-26|
    GB2557041A|2018-06-13|
    MX2018000850A|2018-05-04|
    WO2017039616A1|2017-03-09|
    AU2015408176A1|2018-02-01|
    NO20180119A1|2018-01-25|
    GB2557041B|2022-02-23|
    GB2557041A8|2018-06-27|
    CA2993274A1|2017-03-09|
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    法律状态:
    2017-07-26| PLFP| Fee payment|Year of fee payment: 2 |
    2018-07-18| PLFP| Fee payment|Year of fee payment: 3 |
    2018-11-30| PLSC| Publication of the preliminary search report|Effective date: 20181130 |
    2019-07-30| PLFP| Fee payment|Year of fee payment: 4 |
    2021-04-09| ST| Notification of lapse|Effective date: 20210305 |
    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2015/047738|WO2017039616A1|2015-08-31|2015-08-31|Use of crosslinked polymer system for mitigation of annular pressure buildup|
    USWOUS2015047738|2015-08-31|
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