Water-based well treatment fluid for treating an underground formation, process for manufacturing a water-based well treatment fluid, method for inhibiting the swelling and / or migration of underground clay materials encountered during the drilling of an underground formation, and method for extracting oil from an underground formation.
Patent Information
- Application Number
- BR112021025646
- Authority / Receiving Office
- BR · BR
- Patent Type
- Patents
- Current Assignee / Owner
- Publication Date
- 2026-09-01
Abstract
Description
Water-based well treatment fluid for treating an underground formation, process for manufacturing a water-based well treatment fluid, method for inhibiting the swelling and / or migration of underground clay materials encountered during the drilling of an underground formation, and method for extracting oil from an underground formation. CROSS-REFERENCE ON RELATED REQUEST
[001] This application claims priority of the Patent Application U.S. Provisional Order No. 62 / 863,326 filed June 24, 2019. DECLARATION CONCERNING RESEARCH OR DEVELOPMENT SPONSORED BY THE FEDERAL GOVERNMENT
[002] Not applicable. FIELD
[003] The present invention generally relates to water-based well treatment fluids and their use. More specifically, the present invention relates to a mixture of a free primary amine and a second amine as a clay stabilizing agent in water-based well treatment fluids and methods of using the same. FUNDAMENTALS
[004] Hydrocarbon production from underground formations is frequently affected by the presence of clays and other fragments that can migrate and obstruct or restrict the flow of hydrocarbon product. Migration of fragments within an underground formation is often the result of clay swelling, salt dissolution, and / or disturbance of fragments by the introduction of fluids foreign to the formation. Typically, these foreign fluids (e.g., drilling fluid, fracturing fluid, or stabilizing fluid) are introduced into the Petition 870250103741, dated 12 / 11 / 2025, p. 11 / 20 / 26 training with the purpose of completing and / or addressing training to stimulate hydrocarbon production through, for example, drilling, fracturing, acidification or well stabilization.
[005] Attempts to mitigate the detrimental effects caused by the introduction of foreign fluid and the swelling and migration of formation components have included the addition of one or more of several shale hydration inhibitors and / or stabilizing agents to these foreign fluids. They work on the principle of replacing a cationic species in the clay network with a sodium ion. The cationic species is usually selected so that its hydration radius is smaller than that of the sodium ion. It is believed that the molecules of shale hydration inhibitors and stabilizing agents compete with water molecules for reactive sites. Thus, the possibility of swelling and migration is minimized upon contact with the formation. As a result, the probability of formation disintegration is decreased and swelling is inhibited.
[006] Potassium chloride has been widely used as a shale inhibitor / clay stabilizer. In stimulation methods, potassium chloride has often been used as a pre-discharge and / or added to aqueous stimulation methods in order to convert clay into a less swollen form. Although these salts decrease the reduction in formation permeability, they are often detrimental to the performance of other foreign fluid constituents. For example, high concentrations of these salts are typically required for clay stabilization (typically 6%). These salts additionally produce high levels of chloride which are environmentally unacceptable. Other known shale hydration inhibitors / clay stabilizing agents that have been used include, for example: document WO 98 / 55733 describing the use of at least Petition 870210117669, dated 12 / 17 / 2021, page 12 / 42 / 26 an organic amine selected from a primary diamine with a chain length of less than 8 carbon atoms and a primary alkylamine with a chain length of less than 4 carbon atoms; document WO 05 / 058986 which teaches the use of an amine salt of an imide of a maleic anhydride polymer; WO 06 / 013595, a document describing carboxymethylcellulose adducts and an organic amine as solid shale inhibitors; The document WO 06 / 013597 teaches the use of 0.2 to 5% by weight of 1,2-diaminocyclohexane to inhibit the swelling of clay; WO 06 / 136031, a document that teaches the use of amine salts with different molecular weights so that they can transport to micropores, mesopores, and macropores during formation and effect cation exchange within them; WO 10 / 040223, a document describing the use of bis-surfactant diamine compounds to reduce clay swelling during drilling; U.S. Patent No. 4,719,021 which teaches how to incorporate a polyvalent metal / guanidine complex into a drilling fluid to stabilize colloidal clay; U.S. Patent Nos. 6,831,043 and 6,857,485 which teach the use of polyether amines as shale hydration inhibiting agents; U.S. Patent No. 7,192,907 describes quaternary compounds as shale encapsulating agents to inhibit, at least partially, swelling and assist in the action of conventional shale inhibitors; U.S. Patent No. 7,514,392 which teaches the use of bis-cyclohexylamine derivatives as shale hydration inhibitors; U.S. Patent No. 7,939,473 describes monoquaternary hydroxyalkylalkylamines or poly(trihydroxyalkylalkyl)amines. Petition 870210117669, dated 12 / 17 / 2021, page 13 / 42 / 26 quaternary amines) as additives to reduce clay swelling in wells; U.S. Patent No. 8,026,198 which teaches the use of propylamine derivatives, hydrogenated poly(propyleneimine) dendrimers and polyamine twin dendrimers as shale hydration inhibitors; U.S. Patent No. 9,574,126 which teaches the use of glycol ether amines as clay shale inhibitors; US Patent No. 9,719,007 describes an aqueous composition comprising a clay inhibitor consisting of a compound of the formula R1-NH-R-(OR)x-NH-R1 where R is ethyl or propyl and R1 is a C1-C6 alkyl group and weighting material; US Patent Published Application No. 2016 / 0208158 describing a water-based drilling fluid containing 45 to 95% by weight of triethylenetetramine and 5 to 50% by weight of aminoethylpiperazine; and US Patent Published Application No. US 2017 / 0145282 describing a clay stabilizer having the formula Y-R1-(O-R2)xY, where R1 and R2 are substituted or unsubstituted C1-C20 hydrocarbylene groups and at least one Y must be a substituted amino group, a substituted or unsubstituted ammonium group, a substituted or unsubstituted amine oxide group, or a nitro group.
[007] There is a continuing need for the development of improved shale hydration inhibitors / clay stabilizing agents that pose little threat to the environment, substantially eliminating all chlorides, and that are at least as effective as the most effective shale hydration inhibitors / clay stabilizing agents of the prior art. SUMMARY
[008] The present description provides a water-based well treatment fluid that is capable of being used in a downhole fluid that is Petition 870210117669, dated 12 / 17 / 2021, p. 14 / 42 / 26 introduced into an underground formation containing underground clay materials, such underground materials having a tendency to exhibit swelling and / or migration upon exposure to water. Water-based well treatment fluid generally contains a continuous aqueous phase, a clay stabilizing agent that includes less than 20% by weight of a free primary amine and a second amine.
[009] According to another embodiment, a method is provided for inhibiting the swelling and / or migration of underground clay materials encountered during the drilling of an underground formation. The method includes circulating the water-based well treatment fluid of the present invention into the underground formation.
[0010] In yet another embodiment, a method is provided for extracting oil from an underground formation containing oil, including the steps of providing, through a first borehole, a pressurized water-based well treatment fluid of the present invention and recovering oil from the underground formation through a second borehole.
[0011] In yet another embodiment, a system is provided comprising an underground formation and the water-based well treatment fluid of the present invention. DETAILED DESCRIPTION
[0012] The present invention is generally directed to a water-based well treatment fluid for use in treating an underground formation comprising: (i) a continuous aqueous phase; and (ii) a clay stabilizing agent comprising (a) less than 20% by weight, based on the total weight of the clay stabilizing agent, of a free primary amine and (b) a second amine. It has been surprisingly found that this particular mixture of amines provides clay / shale inhibitor performances that are remarkably better than predicted from a weighted average. Petition 870210117669, dated 12 / 17 / 2021, p. 15 / 42 / 26 regarding the performance of individual amines.
[0013] The following terms will have the following meanings: The term “comprising” and derivatives thereof are not intended to exclude the presence of any additional component, step, or procedure, regardless of whether it is described herein. For the avoidance of doubt, all compositions claimed herein through the use of the term “comprising” may include any additive, adjuvant, or additional compound, unless stated otherwise. In contrast, the term “essentially consisting of,” if it appears herein, excludes from the scope of any subsequent quotation any other component, step, or procedure, except those not essential to operability, and the term “consisting of,” if used, excludes any component, step, or procedure not specifically outlined or listed. The term “or,” unless stated otherwise, refers to the listed members individually as well as in any combination.
[0014] The term “free primary amine” means a compound in which the carbon atom(s) adjacent to the nitrogen of the primary amine group(s) has only hydrogen atoms bonded to it.
[0015] The articles “a” and “an” are used herein to refer to one or more than one (i.e., at least one) of the grammatical objects of the article. For example, “a free primary amine” means a free primary amine or more than one free primary amine. The phrases “in an embodiment,” “according to an embodiment,” and the like generally mean that the specific feature, structure, or characteristic following the phrase is included in at least one embodiment of the present invention, and may be included in more than one embodiment of the present description. Considerably, such phrases do not necessarily refer to the same aspect. If the descriptive report mentions a component or feature that “should,” “may,” or “could” be included in or have a feature, that Petition 870210117669, dated 12 / 17 / 2021, page 16 / 42 / 26: a particular component or feature does not need to be included or have the characteristic.
[0016] The term “around” as used herein may allow for a degree of variability in a value or range, for example, it may be within 10%, 5%, or 1% of a mentioned value or a mentioned limit of a range.
[0017] Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly cited as the limits of the range, but also to include all individual numerical values or subranges encompassed within that range as if each numerical value and subrange were explicitly cited. For example, a range, such as from 1 to 6, should be considered to have specifically described subranges, such as from 1 to 3, from 2 to 4, from 3 to 6, etc., as well as individual numbers within that range, for example, 1, 2, 3, 4, 5, and 6. This applies regardless of the range width.
[0018] The terms “preferred” and “preferably” refer to embodiments that may provide certain benefits under certain circumstances. However, other aspects may also be preferred under the same or other circumstances. Furthermore, the mention of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of this description.
[0019] The term “substantially free” refers to a composition in which a particular compound or fraction is present in an amount that has no material effect on the composition. In some embodiments, “substantially free” may refer to a composition in which the particular compound or fraction is present in the composition in an amount less than 2% by weight, or less than 1% by weight, or less than 0.5% by weight, or less than 0.1% by weight, or less than 0.05% by weight, or Petition 870210117669, dated 12 / 17 / 2021, p. 17 / 42 / 26 even less than 0.01% by weight based on the total weight of the composition, or that no quantity of that particular compound or fraction is present in the respective composition.
[0020] When substituent groups are specified by their conventional chemical formula, written from left to right, they equally encompass chemically identical substituents that would result from writing the structure from left to right, for example, -CH2O- is equivalent to -OCH2-.
[0021] The term “aliphatic” or “aliphatic group”, as used herein, denotes a hydrocarbon moiety that is linear (i.e., unbranched) or cyclic (including fused, bridged, and fused spiro polycyclic) and may be fully saturated or may contain one or more unsaturation units but is not aromatic.
[0022] The term “continuous aqueous phase”, as used herein, refers to a liquid medium composed largely, but not necessarily exclusively, of water, such as at least 50% by weight of water, or at least 60% by weight of water, or at least 70% by weight of water, or at least 80% by weight of water, or at least 90% by weight of water, or at least 95% by weight of water. Other components may be present, such as salts, cosolvents, buffers, etc.
[0023] The phrase “subterranean formation” encompasses areas below exposed earth and areas below earth covered by water, such as an ocean or freshwater. The term “subterranean clay materials” includes sand and / or clays that swell, disperse, disintegrate, or break apart, thus demonstrating an increase in apparent volume, in the presence of foreign aqueous well treatment fluids, such as drilling fluids, stimulation fluids, cuttings conditioning fluids, etc. The term also includes those sand and / or clays that disperse, disintegrate, or break apart without actual swelling. For example, clays that, in the presence Petition 870210117669, dated 12 / 17 / 2021, p. 18 / 42 / 26 of foreign aqueous well treatment fluids, expand and may rupture when they become unconsolidated, thus producing particles that migrate into a borehole, should also be included by the term.
[0024] The term “optional” or “optionally” means that the event or circumstance subsequently described must or must not happen, and that the description includes examples in which the said event or circumstance happens and examples in which it does not happen.
[0025] According to various embodiments, the clay stabilizing agent of the present invention may comprise, consist essentially of, or consist of a synergistic mixture of amines that can be used in water-based well treatment fluids. In particular, the amine mixture performs significantly better than that predicted from a weighted average of the performances of the individual amines.
[0026] Furthermore, water-based well treatment fluid containing the clay stabilizer is capable of substantially reducing or eliminating damage to an underground formation caused by swelling and / or migrating underground clay materials. The presence of the clay stabilizer eliminates or reduces the tendency of underground clay materials to swell and / or disintegrate / migrate after contact with the water-based well treatment fluid. This inhibition and / or migration can be temporary or substantially permanent, depending on the amount of water-based well treatment fluid used to treat the underground formation. Thus, another advantage of using the described clay stabilizer is evidenced by its ability to provide permanent clay stabilization.Temporary clay stabilizers are materials that protect the underground formation only during formation treatment with water-based well treatment fluid. The migration of natural fluids over the underground formation over time displaces external cations, thus reverting the clay back to its natural form. Petition 870210117669, dated 12 / 17 / 2021, p. 19 / 42 / 26 swelling. On the contrary, permanent clay stabilizers minimize this swelling when clays are exposed to natural fluids over time, without the need for continuous addition of water-based well treatment fluid.
[0027] In addition to inhibiting swelling and / or migration, the clay stabilizing agents described in this document also achieve other benefits. For example, clay stabilizing agents can be thermally stable, toxicologically safer, and have better handling properties. Therefore, clay stabilizing agents can be widely used in onshore drilling operations as well as in offshore drilling operations.
[0028] Thus, according to one embodiment, a water-based well treatment fluid is supplied for the treatment of an underground formation comprising: (A) a continuous aqueous phase and (B) a clay stabilizing agent that includes: (a) from about 0.001% by weight to about 20% by weight, based on the total weight of the clay stabilizing agent, of a free primary amine selected from: (i) a compound having a formula R1-(CH2)m-(A)x-(CH2)n-(B)y-(CH2)p-R2 where R1 and R2 are independently -NH2 or methyl with the condition that at least one of R1 or R2 is -NH2; A and B are independently chosen from a group of ethylene oxide, propylene oxide and butylene oxide; m, n and p are independently an integer ranging from 0 to 10 with the condition that m + n + p is at least 1; x and y are independently an integer from 0 to 5 with the condition that x + y is at least 1; (ii) a compound with a molecular weight less than 600 g / mol and a formula: R3-(NH2)a Petition 870210117669, dated 12 / 17 / 2021, p. 20 / 42 11 / 26 where R3 is an aliphatic group having at least 4 to 30 carbon atoms and a is 2 or 3; and (iii) a mixture thereof; and (b) a second amine selected from: (i) an alkanolamine; (ii) a polyalkylenamine selected from a polyethyleneamine, a polypropyleneamine and a mixture thereof; (iii) a compound having the formula R4-(CH2)d-NH2 where R4 is a piperazine group or a morpholine group and d is an integer from 0 to 10; (iv) a compound with the formula H R2 H2N-CH-CH2—O—CH—CH—NH2ch3 where h is an integer from about 2 to about 7; and (v) a mixture thereof. In a particular embodiment, the composition is substantially free of a quaternary amine.
[0029] Water-based well treatment fluid can be any fluid capable of delivering the clay stabilizing agent in an underground formation. Thus, in one embodiment, water-based well treatment fluid is a drilling fluid, a boring fluid, a stimulation fluid, a fracturing fluid, an acidification fluid, a correction fluid, a well rework fluid, or a cuttings conditioning fluid.
[0030] The continuous aqueous phase may be any water-based fluid phase that is compatible with the water-based well treatment fluid formulation and that is also compatible with the clay stabilizing agents described herein. In one embodiment, the continuous aqueous phase is selected from fresh water, seawater, brine, a mixture of water and a water-soluble organic compound, and mixtures thereof. The amount of the continuous aqueous phase must be sufficient to form a fluid. Petition 870210117669, dated 12 / 17 / 2021, p. 21 / 42 / 26 regarding water-based well treatment. In one embodiment, the amount of continuous aqueous phase can vary from nearly 100% of the water-based well treatment fluid by volume to less than 30% of the water-based well treatment fluid by volume. In another embodiment, the amount of continuous aqueous phase is from about 95% by volume to about 30% by volume of the water-based well treatment fluid. In yet another embodiment, the amount of continuous aqueous phase is from about 90% by volume to about 40% by volume of the water-based well treatment fluid.
[0031] As discussed above, water-based well treatment fluid also includes a clay stabilizing agent that is a mixture of a free primary amine and a secondary amine. In one embodiment, the free primary amine is the compound that has the formula R1-(CH2)m-(A)x-(CH2)n-(B)y-(CH2)p-R2 where R1 is methyl; R2 is -NH2; A and B are ethylene oxide or propylene oxide; m, n, and p are independently integers from 0 to 10 with the condition that m + n + p is at least 1; x and y are independently integers from 0 to 5, with the condition that x + y is at least 1. In another embodiment, R1 is methyl; R2 is -NH2; A and B are ethylene oxide; m, n, and p are independently integers from 0 to 5 with the condition that m + n + p is at least 1; x and y are independently integers from 0 to 3, with the condition that x + y is at least 1. In yet another embodiment, R1 is methyl; R2 is -NH2; A and B are ethylene oxide; m, nep are independently 0 or 1 with the condition that m + n + p is at least 1; x and y are independently 0 or 1 with the condition that x + y is at least 1.
[0032] In another embodiment, the free primary amine is the compound that has the formula R1-(CH2)m-(A)x-(CH2)n-(B)y-(CH2)p-R2 where R1 is -NH2; R2 is -NH2; A and B are ethylene oxide or Petition 870210117669, dated 12 / 17 / 2021, p. 22 / 42 / 26 propylene oxide; m, nep are independently integers from 0 to 10 with the condition that m + n + p is at least 1; x and y are independently integers from 0 to 5, with the condition that x + y is at least 1. In another embodiment, R1 is -NH2; R2 is -NH2; A and B are ethylene oxide; m, nep are independently integers from 0 to 5 with the condition that m + n + p is at least 1; x and y are independently integers from 0 to 3, with the condition that x + y is at least 1. In yet another embodiment, R1 is -NH2; R2 is -NH2; A and B are ethylene oxide; m, nep are independently 0 or 1 with the condition that m + n + p is at least 1; x and y are independently 0 or 1 with the condition that x + y is at least 1.
[0033] According to another embodiment, the free primary amine is the compound that has the formula R3-(NH2)a where R3 is an aliphatic group that has from 4 to 20 carbon atoms.Examples include, but are not limited to, 1,4-diaminobutane, 1,5-diaminopentane, 1,6-diaminohexane, 1,7-diaminoheptane, 1,8-diaminooctane, 1,9-diaminononane, 1,10-diaminodecane, 1,12-diaminododecane, 2,2,4-trimethylhexamethylenediamine, 2,4,4-trimethylhexamethylenediamine, tetramethylenediamine, 1,2,3-triaminopropane, triaminohexane, triaminononane, triaminododecane, 1,8-diamino-4-aminomethyloctane, 1,3,6-triaminohexane, 1,6,11-triaminoundecane, 3-aminomethyl-1,6-diaminohexane, diaminocyclobutane, isophoronediamine, 1,2-diaminocyclohexane, 1,3-diaminocyclohexane, 1,4-diaminocyclohexane, 1,3-bis(aminomethyl)cyclohexane, 1,4-bis(aminomethyl)cyclohexane, 4,4'-methylenebis(cyclohexylamine), 2,5-bis(aminomethyl)bicyclo[2,2,1]heptane, 2,6-bis(aminomethyl)bicyclo[2,2,1]heptane, hydrogenated 2,4-tolylenediamine, hydrogenated 2,6-tolylenediamine, triaminocyclohexane and mixtures thereof.
[0034] According to another embodiment, the second amine is an alkanolamine. The alkanolamine may be a monoalkanolamine, which in Petition 870210117669, dated 12 / 17 / 2021, page 23 / 42 / 26 some embodiments contain from 2 to 20 carbon atoms, including ethanolamine, propanolamine, butanolamine, pentanolamine, hexanolamine, heptanolamine, octanolamine, nonanolamine, decanolamine, undecanolamine, dodecanolamine, tridecanolamine, tetradecanolamine, pentadecanolamine, hexadecanolamine, heptadecanolamine, octadecanolamine, nonadecanolamine, eicosanolamine and in other embodiments these alkanolamines may have one or both amino hydrogens substituted by an alkyl group, the alkyl group containing from 1 to 20 carbon atoms. Such substituted alkanolamines include N-methylethanolamine, N-ethylethanolamine, N-propylethanolamine, N-butylethanolamine, N-pentylethanolamine, N-hexylethanolamine, N-heptylethanolamine, N-octylethanolamine, N-nonylethanolamine, N-decylethanolamine, N-undecylethanolamine, Ndodecylethanolamine, N-tridecyl-ethanolamine, N-tetradecyl-ethanolamine.Npentadecyl-ethanolamine, N-hexadecyl-ethanolamine, N-heptadecyl-ethanolamine, N-octadecyl-ethanolamine, N-nonadecyl-ethanolamine, N-eicosyl-ethanolamine, N,N-dimethylethanolamine, N,N-diethyl-ethanolamine, N,N-dipropyl-ethanolamine, N,N-dibutylethanolamine, N,N-dipentylethanolamine, N,N-dihexyylethanolamine, N,N-diheptylethanolamine, N,N-dioctylethanolamine, N,Ndinonylethanolamine, N,N-didecylethanolamine, N,N-diundecylethanolamine, N,N-didodecylethanolamine, N,N-ditridecyl-ethanolamine, N,Nditetradecylethanolamine, N,N-dipentadecylethanolamine, N,Ndihexadecylethanolamine, N,N-diheptadecylethanolamine, N,N-dioctadecylethanolamine, N,N-dinonadecylethanolamine and N,N-dieicosylethanolamine. It is understood that the substitution may also include cycloalquil, such as cyclohexil.
[0035] In another embodiment, the second amine is an alkanolamine containing at least two hydroxyl groups and one amine group or an alkanolamine containing at least one hydroxyl group and two amine groups. The embodiment in which the alkanolamine contains at least two groups Petition 870210117669, dated 12 / 17 / 2021, page 24 / 42 / 26 hydroxyl and an amine group includes dialkylamines, such as N-aliphatic dialkylamines.
[0036] In one embodiment, N-aliphatic-dialkanolamine is an N-alkyl-diethanolamine with up to 20 carbon atoms. Illustrative compounds include, but are not limited to, N-methyl-diethanolamine, N-ethyldiethanolamine, N-propyl-diethanolamine, N-nonyl-diethanolamine, N-decyldiethanolamine, N-undecyl-diethanolamine, N-dodecyl-diethanolamine, N-tridecyldiethanolamine, N-tetradecyl-diethanolamine, N-pentadecyl-diethanolamine, N-hexadecyl-diethanolamine, and N-dodecyl-diethanol-N-tricosyl-diethanolamine.
[0037] In some cases, N-alkenyl-diethanolamines can be used. Illustrative N-alkenyl-diethanolamines include, but are not limited to, N-hexenyl-diethanolamine, N-heptenyl-diethanolamine, N-octenyldiethanolamine, N-undecenyl-diethanolamine, N-dodecenyl-diethanolamine, N-tridecenyl-diethanolamine, N-tetradecenyl-diethanolamine, N-pentadecenyldiethanolamine, N-hexadecenyl-diethanolamine, N-heptadecenyl-diethanolamine, N-octadecenyl-diethanolamine, N-nonadecenyl-diethanolamine and N-eicosenyldiethanolamine.
[0038] In embodiments wherein the alkanolamine contains at least one hydroxyl group and two amine groups, the alkanolamine may be an aminoalkyl alkanolamine. The aminoalkyl alkanolamine may have from about four to about 20 carbon atoms. Illustrative compounds include, but are not limited to, aminoethylethanolamine, aminoethylpropanolamine, aminoethylbutanolamine, aminoethylpentanolamine, aminoethylhexanolamine, aminopropylethanolamine, aminopropylpropanolamine, aminopropylbutanolamine, aminopropylpentanolamine, aminopropylhexanolamine, aminobutylethanolamine, aminobutylpropanolamine, aminobutylbutanolamine, aminobutylpentanolamine, aminobutylhexanolamine, aminopentylethanolamine, aminopentylpropanolamine, aminopentylbutanolamine, aminopentylpentanolamine, Petition 870210117669, dated 12 / 17 / 2021, page 25 / 42 16 / 26 aminopentylhexanolamine, aminohexylethanolamine, aminohexylpropanolamine, aminohexylbutanolamine, aminohexylpentanolamine and aminohexylhexanolamine.
[0039] In another embodiment, the second amine is a polyalkylenamine selected from a polyethylenediamine, a polypropylenediamine, and a mixture thereof. Examples of polyethylenediamine include, but are not limited to, ethylenediamine (EDA), diethylenetriamine (DETA), triethylenediamine (TEDA), triethylenetetramine (TETA), tetraethylenepentamine (TEPA), pentaethylenehexamine, mixtures of ethylenediamine, such as mixtures of ethylenediamine oligomers having an average molecular weight of about 250 to 500, and other mixtures thereof. Polypropylenediamine includes, but is not limited to, propylenediamine, dipropylenetriamine, tripropylenetriamine, and other higher polypropylenediamines.
[0040] In some embodiments, the molecular weight or average molecular weight of the polyalkylenamine is from about 50 to about 1,000 or from about 100 to about 500, or from about 200 to about 500.
[0041] According to another embodiment, the second amine is the compound that has the formula R4-(CH2)d-NH2 where R4 is a piperazine group or a morpholine group and ed is an integer from 0 to about 10 or from 1 to about 8 or from 1 to about 6 or from 1 to about 4 or from 1 to about 3.
[0042] In yet another form, the second amine is the compound that has the formula H2N-CH-CH2—O—CH—CH—NH CH3< -A where h is an integer from about 2.5 to about 6.5. Examples of these compounds include JEFF AMINE® D230 and D240. Petition 870210117669, dated 12 / 17 / 2021, p. 26 / 42 / 26
[0043] In one particular embodiment, the clay stabilizing agent includes: (a) from about 0.01% by weight to about 17.5% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 82.5% by weight, based on the total weight of the clay stabilizing agent, of the second amine. In another particular embodiment, the clay stabilizing agent includes: (a) from about 0.1% by weight to about 15% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 85% by weight, based on the total weight of the clay stabilizing agent, of the second amine. In yet another particular embodiment, the clay stabilizing agent comprises: (a) from about 0.5% by weight to about 12.5% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 87.5% by weight, based on the total weight of the clay stabilizing agent, of the second amine.In another particular embodiment, the clay stabilizing agent includes: (a) about 1% by weight to about 10% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 90% by weight, based on the total weight of the clay stabilizing agent, of the second amine. In another particular embodiment, the clay stabilizing agent includes: (a) about 1.5% by weight to about 7.5% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 92.5% by weight, based on the total weight of the clay stabilizing agent, of the second amine. In yet another particular embodiment, the clay stabilizing agent comprises: (a) from about 2% by weight to about 5% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least about 95% by weight, based on the total weight of the clay stabilizing agent, of the second amine.
[0044] Generally, the clay stabilizing agent may be present in water-based well treatment fluid in an amount Petition 870210117669, dated 12 / 17 / 2021, p. 27 / 42 / 26 sufficient to reduce either or both surface hydration-based swelling and / or osmotic-based swelling of underground clay materials. The exact amount of clay stabilizing agent present in a given water-based well treatment fluid can be determined by a trial-and-error method to test the combination of the water-based well treatment fluid and the clay formation encountered. In one embodiment, the amount of clay stabilizing agent of the present invention used in water-based well treatment fluids ranges from about 1 to about 9.07 kg per barrel (20 pounds per barrel (lbs / bbl or ppb)) of water-based well treatment fluid.In another embodiment, the amount of clay stabilizer present in the water-based well treatment fluid varies from about 2 to about 8.16 kg per barrel (18 ppb) of water-based well treatment fluid. In yet another embodiment, the water-based well treatment fluid may include from about 0.001% by weight to about 10% by weight, based on the total weight of the water-based well treatment fluid, of the clay stabilizer. In another embodiment, the water-based well treatment fluid may include from about 0.1% by weight to about 8% by weight, or from about 0.5% by weight to about 6% by weight, or from about 1% by weight to about 4% by weight, based on the total weight of the water-based well treatment fluid, of the clay stabilizer.
[0045] In another embodiment, the water-based well treatment fluid may include a weighting material. The weighting material may increase the density of the fluid in order to prevent rebound and eruption. Suitable weighting materials include any type of weighting material that is in solid form, in particulate form, suspended in solution, or dissolved in the continuous aqueous phase. In one embodiment, the weighting material is barium sulfate, barite, hematite, iron oxide, calcium carbonate, magnesium carbonate, an organic salt, a salt Petition 870210117669, dated 12 / 17 / 2021, p. 28 / 42 / 26 inorganic or mixtures thereof. The amount of weighting material present in water-based well treatment fluid is an effective amount to prevent rebound and eruption, the amount of which changes according to the nature of the formation under treatment operations. In a particular embodiment, the weighting material is included in the water-based well treatment fluid at a level below 362.87 kg per barrel (800 ppb), for example, from about 2.26 kg per barrel (5 ppb) to about 340.19 kg per barrel (750 ppb) or from about 4.53 kg per barrel (10 ppb) to about 317.51 kg per barrel (700 ppb) of water-based well treatment fluid.
[0046] In addition, an acid or base may be added to the water-based well treatment fluid of the present invention for handling or pH adjustment purposes. Any suitable acid or base may be used. In one embodiment, the acid or base must not form a salt that is not soluble. In some embodiments, the water-based well treatment fluid may be neutralized to a pH of approximately pH 9 to 11. Examples of acids or bases include, but are not limited to, glacial acetic acid and sodium hydroxide.
[0047] The water-based well treatment fluid of the present invention may further comprise an additive, such as gelling materials, diluents, and fluid loss control agents. Typical gelling materials include, but are not limited to, bentonite, sepiolite clay, attapulgite clay, high molecular weight anionic polymer, and biopolymers. Typical diluents include, but are not limited to, lignosulfonates, modified lignosulfonates, polyphosphates, tannins, and low molecular weight polyacrylates. Diluents are added to a drilling fluid to reduce flow resistance, control gelation tendencies, reduce filtration and filter cake thickness, neutralize the effects of salts, minimize the effects of water on drilled formations, emulsify oil in water, and stabilize the Petition 870210117669, dated 12 / 17 / 2021, page 29 / 42 / 26 mud properties at elevated temperatures. Suitable fluid control agents include, but are not limited to, synthetic organic polymers, biopolymers, and mixtures thereof. Fluid control agents may also comprise modified lignite, polymers, and modified starches and celluloses. Ideally, additives should be selected to have low toxicity and be compatible with common drilling fluid additives such as polyanionic carboxymethylcellulose (PAC or CMC), polyacrylates, partially hydrolyzed polyacrylamides (PHPA), lignosulfonates, xanthan gum, and mixtures thereof.
[0048] The water-based well treatment fluids of the present invention may additionally contain an additional additive, such as an encapsulating agent. Encapsulating agents help improve chip removal with less dispersion of chips in the drilling fluids. Encapsulating agents may be anionic, cationic, or non-ionic in nature. Other additives may also be added to the water-based well treatment fluids of the present invention, including products such as lubricants, penetration rate enhancers, structuring agents, antifoaming agents, corrosion inhibitors, loss circulation products, and other similar products known to those skilled in the art.
[0049] The clay stabilizing agent of the present invention and the optional weighting material and optional additives can be mixed with the continuous aqueous phase to form the water-based well treatment fluid. Thus, in another embodiment, a method is provided for manufacturing a water-based well treatment fluid including the step of mixing a clay stabilizing agent according to the present invention, optionally a weighting material and other optional additives with a continuous aqueous phase.
[0050] In another embodiment, a method is provided for inhibiting the swelling and / or migration of underground clay materials. Petition 870210117669, dated 12 / 17 / 2021, page 30 / 42 / 26 found during the drilling of an underground formation. The method includes circulating a water-based well treatment fluid containing a continuous aqueous phase and the clay stabilizing agent of the present invention into the underground formation. In yet another embodiment, a method is provided for stabilizing an underground formation that includes the steps of bringing the underground formation into contact with the water-based well treatment fluid of the present invention. The underground formation can be brought into contact, for example, by providing the water-based well treatment fluid described in this document to the underground formation before, during, or after hydraulic fracturing or drilling.
[0051] Underground clay materials that can be effectively treated with water-based well treatment fluid can be of varying shapes, such as tiny, plate-like particles, tubes, and / or fibers with an extremely large surface area. Examples include clay minerals from the montmorillonite (smectite) group such as montmorillonite, saponite, nontronite, hectorite, and sauconite; the kaolin group such as kaolinite, nacrite, dickite, and halloysite; the hydrosmic group such as hydrobiotite, glauconite, illite, and brahmalite; the chlorite group such as chlorite and chamosite; clay minerals not belonging to the above group such as vermiculite, attapulgite, and sepiolite; and varieties of mixed layers of such minerals and clay groups. Other mineral components may be associated with the clay.
[0052] In another embodiment, the materials and method for inhibiting the swelling and / or migration of underground clay materials and stabilizing the underground formation may be provided as a kit that includes a sufficient quantity of the clay stabilizing agent of the present invention, optional weighting material and optional additives for mixing on site with the continuous aqueous phase.
[0053] The result of stabilizing the underground formation with the Petition 870210117669, dated 12 / 17 / 2021, page 31 / 42 / 26: The water-based well treatment fluid described herein is that particulate groundwater clay material loosened from the underground formation by the hydrocarbon product removal process has reduced swelling, reduced underground migration, does not reduce hydrocarbon product flow, and / or does not contaminate the hydrocarbon product. Without the water-based well treatment fluid, groundwater clay materials can swell and / or migrate to inhibit or contaminate hydrocarbon production. The stabilization effect can be measured by comparing wells with and without the water-based well treatment fluid or by comparing the flow rate of fluids (e.g., oil, water, or natural gas) through samples from the underground formation with and without the water-based well treatment fluid.
[0054] Underground formations can be stabilized by bringing them into contact with water-based well treatment fluid. In one embodiment, the swelling of underground clay materials and / or the migration of fragments can be reduced by bringing the underground formation into contact with a water-based well treatment fluid comprising a continuous aqueous phase, the clay stabilizing agent of the present invention, the optional weighting material, and the optional additives.
[0055] In another embodiment, a previously hydraulically fractured underground formation can be re-stabilized by placing the hydraulically fractured underground formation in contact with the water-based well treatment fluid of the present invention. The hydraulically fractured underground formation can be, for example, one from which hydrocarbons were extracted. Preferably, the hydraulically fractured underground formation is a mineral-content formation that is predominantly clay, shale, sand, and / or a mixture thereof.
[0056] In yet another modality, the well treatment fluid to Petition 870210117669, dated 12 / 17 / 2021, p. 32 / 42 / 26: Water-based well treatment fluid can be used in a method for flushing a borehole during drilling. The method involves applying water-based well treatment fluid to a drill head while drilling into an underground formation.
[0057] In yet another embodiment, a method is provided for extracting oil from an oil-containing underground formation by providing, through a first borehole, a pressurized water-based well treatment fluid of the present invention and recovering oil from the underground formation through a second borehole. Preferably, the underground formation has been previously hydraulically fractured and the oil previously extracted.
[0058] In yet another embodiment, a system that includes the water-based well treatment fluid of the present invention and an underground formation is provided.
[0059] The present invention will now be better described with reference to the following non-limiting examples. EXAMPLES
[0060] Examples 1 to 4. Preparation / testing of water-based well treatment fluids.
[0061] Buffered solutions were prepared from sodium carbonate and sodium bicarbonate with pH values of 9, 10, and 11. Each solution contained 0.4% by weight of sodium carboxymethylcellulose and a sodium concentration of 0.232 M. 10.5 grams of 100% active clay stabilizing agent were diluted with 340 grams of each buffered solution, followed by readjustment to a pH of 9, 10, or 11 using glacial acetic acid or 50% aqueous NaOH. Solution weights were adjusted to 350 g to produce 3% by weight solutions. Virgin shale rocks were obtained in Russia, broken and sieved to a diameter of 4.75 to 6.7 mm (longest dimension) and dried at 95° to 110°C for 3 hours before the Petition 870210117669, dated 12 / 17 / 2021, page 33 / 42 / 26 use. These shale rocks were weighed and added to 400 ml stainless steel pressure vessels. Water-based well treatment fluids were added and the vessels were purged with air pressurizing to 0.689 MPa (100 psig) with nitrogen and evacuated to atmospheric pressure three successive times. The vessels, containing nitrogen at atmospheric pressure, were transferred to a rotary furnace set to 90°C and left to rotate for 16 hours. The vessels were then immersed in baths containing tap water at room temperature and allowed to cool for 1 hour and 30 minutes before opening. The contents were filtered through a 20 mesh screen and the remaining solids were washed with 5% by weight KCl before drying between 95° and 110°C for 3 hours.The dried shale pieces obtained were sieved through successive 8 and 20 mesh sieves, and the weights obtained were recorded as percentages of the initial weight of shale used in each experiment. The clay stabilizing agents used are identified in Table 1 below. TABLE 1 - COMPOSITIONS OF CLAY STABILIZING AGENTS. Description Free Primary Amine A A1 Hexamethylenediamine A2 SURFONIC® MW-781 Amine (Butoxypropylamine) Secondary Amine B B1 Aminoethylethanolamine B2 JEFFAMINE® E-100 Amine (Polyethylene amine) B3 Mixture of secondary amines1 B4 Mixture of secondary amines2 1The mixture includes ethylenediamines, ethanolamines, amines and alcohols with morpholine function and water.2The mixture includes JEFFAMINE® D230 and D400 amines
[0062] Water-based well treatment fluids, examples 1 to 4, were prepared by mixing 20 parts A1 with 80 parts B1-4 individually, respectively. The measured performance of each, e.g., measured, was compared to the expected performance based on simple linear combinations of the performances of each component, e.g., calculated, (e.g., comparison of the calculated, e.g., calculated 1, with the measured, e.g., measured 1, values for which the first Petition 870210117669, dated 12 / 17 / 2021, pp. 34 / 42 / 26 were determined as linear combinations of the values of components A and B. Percentage by weight of surviving shale of sizes 20 and 8 mesh after tests with pH 9, 10 and 11). The results are presented in Table 2 below. TABLE 2 - PERFORMANCE OF TREATMENT FLUIDS WATER-BASED WELL pH 9 pH 10 pH 11 20 mesh (%) 8 mesh (%) 20 mesh (%) 8 mesh (%) 20 mesh (%) 8 mesh (%) Ex. l = 0.2 Al + 0.8 Bl A1 46.99 12.13 59.90 20.28 67.59 42.71 B1 10.87 6.51 6.97 3.35 8.21 3.20 Calculated Ex. 1 18.09 7.63 17.56 6.73 20.09 11.10 Measured Ex. 1 65.28 31.67 62.97 25.40 42.50 10.90 Ex. 2 = 0.2 Al + 0.8 B2 A1 46.99 12.13 59.90 20.28 67.59 42.71 B2 71.36 25.70 73.36 31.43 28.11 13.01 Calculated Ex. 2 66.49 22.99 70.67 29.20 36.01 18.95 Measured Ex. 2 73.75 38.90 70.09 34.15 60.38 35.58 Ex. 3 = 0.2 Al + 0.8 B3 A1 46.99 12.13 59.90 20.28 67.59 42.71 B3 62.85 36.61 45.32 29.40 12.56 8.14 Calculated Ex. 3 59.67 31.71 48.23 27.58 23.57 15.05 Measured Ex. 3 50.57 26.46 70.43 39.96 45.70 17.72 Ex. 4 = 0.2 Al + 0.8 B4 A1 46.99 12.13 59.90 20.28 67.59 42.71 B4 67.62 28.88 83.09 44.92 16.52 10.66 Calculated Ex. 4 63.49 25.53 78.45 39.99 26.73 17.07 Measured Ex. 4 76.43 35.69 71.14 37.02 49.27 26.54
[0063] From the results above, it can be seen that potential synergies, defined in this document as cases for which the measured values are at least 5% greater than the calculated values, were identified for all Ex. fluids for at least two of the three pH values for which data were obtained. EXAMPLES 5 TO 7 - PREPARATION / TESTING OF WATER-BASED WELL TREATMENT FLUIDS
[0064] In another series of experiments similar to those above, water-based well treatment fluids, examples 5 to 7, were prepared by mixing 5% by weight, 10% by weight and 20% by weight of A2 in B2 and tested. The results are presented in Table 3. TABLE 3 - PERFORMANCE OF TREATMENT FLUIDS Petition 870210117669, dated 12 / 17 / 2021, pages 35 / 42 / 26 WATER-BASED WELL pH 9 pH 10 pH 11 20 mesh (%) 8 mesh (%) 20 mesh (%) 8 mesh (%) 20 mesh (%) 8 mesh (%) A2 80.90 51.23 85.89 71.67 18.10 12.55 B2 71.36 25.70 73.36 31.43 28.11 13.01 Ex. 5 = 0.2 A1 + 0.8 B2 Calculated ex. 5 73.27 30.81 75.87 39.48 26.11 12.92 Measured ex. 5 79.42 42.09 86.70 66.89 13.89 6.27 Ex. 6 = 0.1 A1 + 0.8 B2 Calculated ex. 6 72.31 28.25 74.61 35.45 27.11 12.96 Measured ex. 6 83.44 47.22 89.24 62.96 13.76 7.36 Ex. 7 = 0.05 A1 + 0.95 B2 Calculated ex. 7 71.84 26.98 73.99 33.44 27.61 12.99 Measured example 7 87.89 50.93 90.11 63.90 23.34 11.87
[0065] Again, potential synergies were identified for all exemplary fluids with pH 9 and 10. Notably, the performance of Example 7, which contains only 5% by weight of the free primary amine, is as good as Example 5, which contains 20% by weight of the free primary amine, within experimental error.
[0066] Although the manufacture and use of various embodiments of the present invention have been described in detail above, it should be recognized that the present invention provides many applicable inventive concepts that can be incorporated into a wide variety of specific contexts. The specific embodiments discussed herein are merely illustrative of specific ways to make and use the invention and do not delimit the scope of the invention.
Claims
1. Water-based well treatment fluid for the treatment of an underground formation, characterized in that it comprises: (A) a continuous aqueous phase and (B) a clay stabilizing agent comprising: (a) from 0.001% by weight to 20% by weight, based on the total weight of the clay stabilizing agent, of a free primary amine, wherein the free primary amine is butoxypropylamine; and (b) a second amine which is a mixture of polyethyleneamines, wherein the average molecular weight of the polyethyleneamine is from 200 to 500.
2. Water-based well treatment fluid according to claim 1, characterized in that the continuous aqueous phase is selected from fresh water.
3. Water-based well treatment fluid according to claim 1, characterized in that it further comprises a weighting material.
4. Water-based well treatment fluid according to claim 1, characterized in that the clay stabilizing agent includes: (a) from 0.01% by weight to 17.5% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least 82.5% by weight, based on the total weight of the clay stabilizing agent, of the second amine.
5. Water-based well treatment fluid according to claim 1, characterized in that the clay stabilizing agent includes: (a) 1% by weight to 10% by weight, based on the total weight of the clay stabilizing agent, of the free primary amine and (b) at least 90% by weight, based on the total weight of the clay stabilizing agent, of the secondary amine. Petition 870260043043, dated 07 / 05 / 2026, p. 11 / 14 2 / 2 6. Process for manufacturing a water-based well treatment fluid comprising a mixture of a clay stabilizing agent, characterized in that it comprises: (a) 0.001% by weight to 20% by weight, based on the total weight of the clay stabilizing agent, of a free primary amine, wherein the free primary amine is butoxypropylamine; and (b) a second amine which is a mixture of polyethyleneamines in a continuous aqueous phase, wherein the average molecular weight of the polyethyleneamine is 200 to 500.
7. Method for inhibiting the swelling and / or migration of underground clay materials encountered during the drilling of an underground formation, characterized in that it comprises circulating water-based well treatment fluid in the underground formation as defined in claim 1.
8. A method for extracting oil from an underground formation containing oil, characterized in that it comprises providing, through a first borehole, a pressurized water-based well treatment fluid, as defined in claim 1, and recovering oil from the underground formation through a second borehole.