Combined thermochemical and chelating agents useful for well cleanup

Abstract

A well cleanup process involves removing an impermeable filter cake from a formation face with thermochemical and chelating agents to allow formation fluids to flow from a reservoir to a wellbore. The method may be used with oil and water-based drilling fluids with varied weighting agents, e.g., bentonite, calcium carbonate, or barite. Such thermochemical agents may involve two salts, e.g., NO.sub.2.sup.− and NH.sub.4.sup.+, which, when mixed together, can generate pressure and heat, in addition to hot H.sub.2O and/or N.sub.2. For example, the thermochemical agents may comprise Na.sup.+, K.sup.+, Li.sup.+, Cs.sup.+, Mg.sup.2+, Ca.sup.2+, and/or Ba.sup.2+ with NO.sub.2.sup.− and NH.sub.4.sup.+ with F.sup.−, Cl.sup.−, Br.sup.−, I.sup.−, CO.sub.3.sup.2−, NO.sub.3.sup.−, ClO.sub.4.sup.−, and/or .sup.−OH. The thermochemical agents in combination with a chelator such as EDTA can removed the filter cake after 6 hours with a removal efficiency of 89 wt % for the barite filter cake in water based drilling fluid, exploiting the generation of a pressure pulse and heat which may disturb the filter cake and/or enhance barite dissolution and polymer degradation.

Claims

1. A method of removing a filter cake mass from a wellbore wall in a subterranean formation, the method comprising: introducing into a wellbore an aqueous composition and contacting the aqueous composition with a wellbore face coated with the filter cake mass; and allowing the aqueous composition to reach a temperature in the wellbore sufficient to initiate an exothermic chemical reaction of at least two components present in the aqueous composition and sufficient to raise a temperature, cause a pressure surge, or both raise a temperature and cause a pressure surge at the wellbore face to disrupt the filter cake mass from the wellbore face, wherein the aqueous composition comprises, at a pH of no less than 10: a first combination comprising a hydrated sulfate salt and a polyacrylamide, wherein the hydrated sulfate salt is an alkaline metal sulfate salt or an alkaline earth metal sulfate with saturated hydration; and at least 20 wt. % ethylenediamine tetraacetic acid, based on total aqueous composition weight.

2. The method of claim 1, wherein the hydrated sulfate salt comprises at least one selected from the group consisting of Na.sup.+ and Mg.sup.2+.

3. The method of claim 1, wherein the hydrated sulfate salt comprises at least 95 wt. % Na.sub.2SO.sub.4.10H.sub.2O, relative to total sulfate salt weight.

4. The method of claim 1, wherein the hydrated sulfate salt comprises at least 95 wt. % MgSO.sub.4.7H.sub.2O, relative to total sulfate salt weight.

5. The method of claim 1, wherein the aqueous composition comprises the ethylenediamine tetraacetic acid in a range of from 22.5 to 30 wt. % of the total aqueous composition weight.

6. The method of claim 1, wherein the temperature in the wellbore is in a range of from 50 to 150° C., prior to the introducing.

7. The method of claim 1, wherein the aqueous composition comprises at least 65 wt. % of barite.

8. The method of claim 1, which achieves the removal of at least 85 wt. % of the filter cake mass within 6 hours.

9. The method of claim 1, wherein at least 95% of the removal of the filter cake mass achievable by the method is within 6 hours after the introducing starts.

10. The method of claim 1, wherein the ethylenediamine tetraacetic acid has a potassium counterion.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) A more complete appreciation of the invention and many of the attendant advantages thereof will be readily obtained as the same becomes better understood by reference to the following detailed description when considered in connection with the accompanying drawings, wherein:

(2) FIG. 1 shows a representation of the exemplary high pressure, high temperature (HPHT) filtration set-up used in testing as described herein;

(3) FIG. 2 shows a plot of the time to reach the maximum reaction temperature as a function of reservoir temperature using two exemplary injection formulations;

(4) FIG. 3A shows an oil-based barite filter cake before removal by an exemplary combined thermochemical-EDTA solution;

(5) FIG. 3B shows oil-based barite filter cake after removal by an exemplary combined thermochemical-EDTA solution;

(6) FIG. 4A shows a water-based barite filter cake before removal by combined thermochemical/EDTA solution;

(7) FIG. 4B shows a water-based barite filter cake after removal by combined thermochemical/EDTA solution;

(8) FIG. 5 shows a chart presenting barite solubility as a function of temperature in 25 wt. % EDTA at pH 14;

(9) FIG. 6 shows a chart of the effect of temperature on the 25 wt. % EDTA diffusion coefficient;

(10) FIG. 7 shows a plot of the effect of average barite particle size on barite solubility in 25 wt. % EDTA at pH 14 at 210° C. for 6 hours; and

(11) FIG. 8 shows a chart of the effect of soaking time on the barite filter cake removal efficiency (water based drilling fluid) in an exemplary formulation combining thermochemical agents and 25 wt. % EDTA solution at pH 14.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

(12) Aspects of the invention provide wellbore filter cake removal compositions which may comprise, in an aqueous solution at a pH of at least 10, 10.5, 11, 11.5, 12, 12.5, 13, 13.5, or 14; 1 to 75 g of an ammonium salt per 100 mL composition; 1 to 75 g of nitrite salt per 100 mL composition; and at least 20 g ethylenediamine tetraacetic acid per 100 mL composition. The mass of ammonium and/or nitrite salt may independently be, e.g., at least 1, 2, 2.5, 3, 4, 5, 7.5, 10, 12.5, 15, 17.5, 20, 22.5, 25, 27.5, 30, 33, 35, 37.5, 40, 42.5, or 45 g and/or up to 75, 70, 65, 60, 55, 50, 45, 40, 35, 30, 27.5, 25, 22.5, 20, 17.5, or 15 g, per 100 mL of composition. The mass of ethylenediamine tetraacetic acid per 100 mL of composition may be, for example, at least 20, 21, 22, 22.5, 23, 24, 25, 26, 27, 27.5, 28, 29, 30, or 32 g and/or up to 35, 34, 33, 32.5, 32, 31, 30, 29, 28, 27.5, 27, 26, 25, 24, 23, 22.5, 22, 21, or 20 g. The nitrite salt and the ammonium salt may be in a molar ratio in a range of from 1.175 to 1 to 1 to 1.175, e.g., at least 1.175:1, 1.15:1, 1.125:1, 1.1:1, 1.075:1, 1.05:1, 1.025:1, 1:1, 0.975:1, 0.95:1, 0.925:1, or 0.9:1 and/or up to 1:1.175, 1:1.17, 1:1.165, 1:1.16, 1:1.155, 1:1.15, 1:1.125, 1:1.1, 1:1.075, 1:1.05, 1:1.025, 1:1, or 1:0.975. The ammonium salt may be an ammonium halide, e.g., fluoride, chloride, bromide, and/or iodide, and/or the nitrite salt may be an alkali metal salt, e.g., lithium, sodium, potassium, cesium, magnesium, calcium, strontium, and/or barium. The ethylenediamine tetraacetic acid may comprise a potassium counterion per molecule, e.g., at least 1, 1.1, 1.2, 1.25, 1.5, 1.75, 2, 2.25, 2.5, 2.75, 3, 3.25, 3.5, 3.75, or 4 potassium counterions per molecule.

(13) Aspects of the invention provide methods of removal of filter cake mass from a wellbore wall in a subterranean formation using any permutation of the inventive composition(s) described herein. Such methods may comprise: introducing into a wellbore an aqueous composition onto a wellbore face coated with the filter cake mass; allowing the aqueous composition to reach a temperature in the wellbore sufficient to initiate an exothermic chemical reaction, e.g., at least 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100° C. and/or up to 150, 145, 140, 135, 130, 125, 120, 115, 110, 105, 100, 95, 90, or 85° C., of the components of the aqueous composition and thereby cause a temperature (e.g., at least 10, 25, 35, 50, 65, 75, 80, 85, 90, 95, 100, 105, 110, 125, or 150° C. up to 200, 175, 150, 125, 110, 100, 90, 80, or 75° C.) and/or pressure (e.g., at least 10, 25, 50, 75, 100, 125, 150, 200, 250, 350, 500, 650, 750, or 1000 psi and/or up to 10000, 7500, 5000, 3500, 2500, 2000, 1500, 1000, 900, 750, 650, 500, 450, 400, 350, 300, or 250 psi) surge at the wellbore face to disrupt the filter cake from the well bore face. The aqueous composition may comprise, at a pH of no less than 10, 10.33, 10.67, 11, 11.33, 11.67, 12, 12.33, 12.67, 13, 13.33, 13.67, or 14 (or any pH described herein): a first combination comprising a hydrated sulfate salt (e.g., mono, di, tri, tetra, penta, hexa, hepta, octa, nona, deca, undeca, dodecahydrate, or more) and guar or a polyacrylamide or a second combination comprising a nitrite salt and an ammonium salt; and at least 20, 20.5, 21, 21.5, 22, 22.5, 23, 23.5, 24, 24.5, 25, 25.5, 26, 26.5, 27, 27.5, 28, 28.5, 29, 29.5, or 30 wt. % (or any range or percent described herein) ethylenediamine tetraacetic acid, based on total aqueous composition weight.

(14) In the second combination the ammonium salt and the nitrite salt may each be at a concentration in a range of from 0.5 to 15 M, particularly 1 to 5 M, e.g., at least 0.5, 0.75, 1, 1.25, 1.5, 1.75, 2, 2.25, 2.5, 2.75, 3, 3.5, 4, 4.5, or 5 M and/or up to 15, 12.5, 12, 11, 10, 9, 8, 7.5, 7, 6.5, 6, 5.5, 5, 4.75, 4.5, 4.25, 4, 3.75, or 3.5 M. The ammonium salt may be an ammonium halide, or otherwise comprise a non-reactive anion. The nitrite salt may be an alkaline metal or alkaline earth metal nitrite. The nitrite salt may comprise Na.sup.+, K.sup.+, Li.sup.+, Cs.sup.+, Mg.sup.2+, Ca.sup.2+, and/or Ba.sup.2+ in the nitrite salt. The ammonium salt may comprise F.sup.−, Cl.sup.−, Br.sup.−, I.sup.−, CO.sub.3.sup.2−, NO.sub.3.sup.−, ClO.sub.4.sup.−, HSO.sub.4.sup.−, SO.sub.4.sup.2−, H.sub.2PO.sub.4.sup.−, HPO.sub.4.sup.2−, PO.sub.4.sup.3−, and/or .sup.−OH in the ammonium salt. At least 95 wt. % of the nitrite salt may be sodium nitrite, relative to the total nitrite salt weight. At least 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % of the ammonium salt may be ammonium chloride, relative to the total ammonium salt weight. A molar ratio of the ammonium salt to the nitrite salt may be in a range of from 1.175 to 1 to 1.175 to 1.

(15) The first combination may be preferably used in some applications and may comprise: the polyacrylamide (e.g., with Mn of at least 10, 15, 20, 25, 30, 35, 40, 45, or 50 kDa and/or up to 100, 85, 75, 65, 55, 50, 45, 40, 35, 30, 25, or 20 kDa); and an alkaline metal or alkaline earth metal sulfate with saturated or at least 50, 60, 70, 75, 80, 85, or 90% saturated hydration sphere (e.g., mono, di, tri, tetra, penta, hexa, hepta, octa, nona, deca, undeca, dodecahydrate, or more). The hydrated sulfate salt may comprise Na.sup.+ and/or Mg.sup.2+ as the cation. The hydrated sulfate salt may be a combination of 2, 3, 4, 5, or 6 different hydrated sulfate salts. The hydrated sulfate salt may comprise at least 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % Na.sub.2SO.sub.4.10H.sub.2O, relative to total sulfate salt weight. The hydrated sulfate salt may comprise at least 95, 96, 97, 97.5, 98, 99, 99.1, 99.5, or 99.9 wt. % MgSO.sub.4.7H.sub.2O, relative to total sulfate salt weight.

(16) The ethylenediamine tetraacetic acid may be in a range of from 22.5 to 30 wt. %, e.g., at least 22.5, 22.75, 23, 23.25, 23.5, 23.75, 24, 24.25, 24.5, 24.75, 25, 25.25, 25.5, 25.75, 26, 26.25, 26.5, 26.75, 27, 27.25, 27.5, 27.75, or 28 wt. % and/or up to 30, 29.75, 29.5, 29.25, 29, 28.75, 28.5, 28.25, 28, 27.75, 27.5, 27.25, 27, 26.75, 26.5, 26.25, 26, 25.75, 25.5, 25.25, or 25 wt. % (or any percent described herein), of the total aqueous composition weight. Each ethylenediamine tetraacetic acid molecule may comprise a potassium counterion, e.g., on average, 1, 1.1, 1.15, 1.2, 1.25, 1.33, 1.5, 1.67, 1.75, 1.85, 2, 2.2, 2.4, 2.5, 2.6, 2.8, 3, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, or 4 K.sup.+ counterions per molecule EDTA (or any average amount described herein).

(17) The temperature in the wellbore may be in a range of from 50 to 150° C., such as at least 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 100° C. and/or up to 150, 145, 140, 135, 130, 125, 120, 115, 110, 105, 100, or 95° C. (or any temperature described herein) prior to the introducing, i.e., before the thermochemical agent(s) release heat and/or pressure.

(18) The wellbore may comprise a drilling fluid comprising at least 65, 67, 70, 72.5, 75, 77.5, or 80 wt. % and/or up to 95, 92.5, 90, 87.5, 85, 82.5, 80, 77.5, or 75 wt %, relative to all drilling fluid solids, of barite. Inventive methods may achieve the removal of at least 85, 86, 87, 88, 89, 90, 91, or 92 wt. % of the filter cake mass within 6 hours. Inventive methods may be ones in which at least 95, 95.5, 96, 96.5, 97, 97.5, 98, 98.5, 99, or 99.5% of the removal of the filter cake mass achievable by the method is within 6 hours.

(19) Inventive materials do not require formation into pellets, spheres, cylinders, or the like, and/or require no pressurized treatment before reaction, e.g., no more than 4.5, 4, 2, 1, 0.75, 0.5, 0.25, 0.15, 0.102 MPa.

(20) Inventive formulations may avoid foaming/blowing agent(s) and/or foam stabilizer(s) entirely, or contain no more than 5, 4, 3, 2.5, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulation weight, of such foaming agent(s) and/or stabilizer(s), individually or in combination, such as hydroxypropyl silicone (HPG), hydroxypropyl tannin, hydroxypropyl guar, xanthan gum (XG), hydroxyethyl cellulose (HEC), sodium dodecyl sulfate (AS), and/or betaine (AC), including ethoxylated alcohols, polysaccharides, ethoxylated fatty amines, amine oxides, glucosides, sulfonates, and/or quaternary ammonium salts. Inventive formulations may exclude acidic catalysts, or may comprise no more than 15, 10, 7.5, 5, 4, 3, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to the total formulation weight, of acid catalysts, such as hydrochloric acid, hydroxyacetic acid, lactic acid, hydrofluoric acid, adipic acid, succinic acid, phosphoric acid, glutaric acid, 3-hydroxypropionic acid, carbonic acid, erythorbic acid, citric acid, salicylic acid, glycolic acid, acetic acid, propionic acid, formic acid, methanesulfonic acid, trifluoroacetic acid, trifluoromethanesulfonic acid, and/or tartaric acid. Inventive formulations may exclude N-acetic acid amino acids, or may comprise no more than 5, 4, 3, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to the total formulation weight, of such N-acetic acid amino acids, e.g., glutamic acid N,N-diacetic acid, aspartic acid N,N-diacetic acid, methylglycine acid N,N-diacetic acid, and/or N-hydroxyethyl ethylenediamine-N,N′,N′-tri acetic acid, and/or other chelating agents, such as citric acid, nitrilotriacetic acid (NTA), diethylene triamine pentaacetic acid (DTPA), propylene diamine tetraacetic acid (PDTA), ethylene diamine-N,N′-di(hydroxyphenyl) acetic acid (EDDHA), ethylene diamine-N,N′-di-(hydroxy-methyl phenyl) acetic acid (EDDHMA), sodium ethylenediamine-N,N-disuccinic acid (EDDS), ethanol diglycine (EDG), ethylene glycol-bis(β-aminoethyl ether)-N,N,N′,N′-tetraacetic acid (EGTA), 2-hydroxyethyliminodiacetic acid (HEIDA), trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA), ethylenediaminediacetic acid (EDDA), methylglycinediacetic acid (MGDA), glucoheptonic acid, gluconic acid, glutamic diacetic acid, sodium citrate, and/or phosphonic acid.

(21) Inventive formulations may exclude mutual solvents, i.e., chemical additives soluble in oil, water, acids, and/or other well treatment fluids, e.g., lower alcohols (methanol, ethanol, 1-propanol, 2-propanol, etc.), glycols (ethylene glycol, propylene glycol, diethylene glycol, dipropylene glycol, polyethylene glycol, polypropylene glycol, polyethylene glycol-polyethylene glycol block copolymers, etc.), glycol ethers (2-methoxyethanol, diethylene glycol mono methyl ether, etc.), C2 to C2 esters, and C2 to C10 ketones, such as methyl ethyl ketone, methanol, or may contain no more than 5, 4, 3, 2.5, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulation weight, of these, individually or in combination. Inventive formulations can avoid oxidizing agents, such as peroxides, hypochlorites, hypobromites, peracids, persulfates, and/or persulfonic acids, or may comprise no more than 5, 4, 3, 2.5, 2, 1, 0.5, 0.1, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulation weight, of these, individually or in combination.

(22) Inventive formulations may substantially exclude polymers, particularly polyionomers, or may comprise no more than 5, 4, 3, 2.5, 2, 1, 0.75, 0.5, 0.25, 0.1, 0.05, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulation weight, of such polymer(s), such as a hydrophobically modified polymer, acrylamido-tert-butyl sulfonate, hydrolyzed polyacrylamide, etc., individually or in combination.

(23) Inventive formulations may exclude metallic catalysts and/or metal-containing catalysts, particularly transition metal (containing) catalysts, e.g., Y, Zr, Ti, V, Nb, Ta, Cr, Mo, W, Mn, Re, Fe, Ru, Os, Co, Rh, Ir, Ni, Pd, Pt, Cu, Ag, Au, Zn, Cd, In, Sn, Sb, Pb, and/or Bi, or may comprise no more than 25, 15, 10, 7.5, 5, 4, 3, 2.5, 2, 1, 0.75, 0.5, 0.25, 0.1, 0.05, 0.01, 0.001, 0.0001, or 0.00001 wt. %, relative to total formulation weight, of these, individually or in combination.

(24) Relevant ammonium species may include, for example, ammonium acetate (NH.sub.4C.sub.2H.sub.3O.sub.2), ammonium azide (NH.sub.4N.sub.3), ammonium benzoate (NH.sub.4C.sub.7H.sub.5O.sub.2), ammonium bicarbonate (NH.sub.4HCO.sub.3), ammonium bromide (NH.sub.4Br), ammonium carbonate ((NH.sub.4).sub.2CO.sub.3), ammonium chlorate (NH.sub.4ClO.sub.3), ammonium chloride (NH.sub.4Cl), ammonium chromate ((NH.sub.4).sub.2CrO.sub.4), ammonium dichromate ((NH.sub.4).sub.2Cr.sub.2O.sub.7), ammonium dihydrogen arsenate (NH.sub.4H.sub.2AsO.sub.4), ammonium dihydrogen phosphate (NH.sub.4H.sub.2PO.sub.4), ammonium fluoride (NH.sub.4F), ammonium fluorosilicate ((NH.sub.4).sub.2SiF.sub.6), ammonium formate (NH.sub.4HCO.sub.2), ammonium hydrogen phosphate ((NH.sub.4).sub.2HPO.sub.4), ammonium hydrogen sulfate (NH.sub.4HSO.sub.4), ammonium iodate (NH.sub.4IO.sub.3), ammonium iodide (NH.sub.4I), ammonium nitrate (NH.sub.4NO.sub.3), ammonium oxalate ((NH.sub.4).sub.2C.sub.2O.sub.4), ammonium perchlorate (NH.sub.4ClO.sub.4), ammonium perrhenate (NH.sub.4ReO.sub.4), ammonium phosphate ((NH.sub.4).sub.3PO.sub.4), ammonium selenate ((NH.sub.4).sub.2SeO.sub.4), ammonium sulfate ((NH.sub.4).sub.2SO.sub.4), ammonium aluminum sulfate (NH.sub.4Al(SO.sub.4).sub.2 or NH.sub.4Al(SO.sub.4).sub.2.12H.sub.2O), ammonium sulfite ((NH.sub.4).sub.2SO.sub.3), ammonium tartrate ((NH.sub.4).sub.2C.sub.4H.sub.4O.sub.6), ammonium thiocyanate (NH.sub.4SCN), ammonium thiosulfate ((NH.sub.4).sub.2S.sub.2O.sub.3), etc.

(25) Relevant nitrite species may include, for example, barium nitrite (Ba(NO.sub.2).sub.2), calcium nitrite (Ca(NO.sub.2).sub.2 or Ca(NO.sub.2).sub.2.4H.sub.2O), lithium nitrite (LiNO.sub.2), potassium nitrite (KNO.sub.2), sodium nitrite (NaNO.sub.2), ammonium nitrite (NH.sub.4NO.sub.2), magnesium nitrite (Mg(NO.sub.2).sub.2), strontium nitrite (Sr(NO.sub.2).sub.2), zinc nitrite (Zn(NO.sub.2).sub.2), silver nitrite (AgNO.sub.2), etc.

(26) The thermochemical agents may comprise Na.sup.+, K.sup.+, Li.sup.+, Cs.sup.+, Mg.sup.2+, Ca.sup.2+, and/or Ba.sup.2+ with NO.sub.2.sup.− and NH.sub.4.sup.+ with F.sup.−, Cl.sup.−, Br.sup.−, I.sup.−, CO.sub.3.sup.2−, NO.sub.3.sup.−, N.sub.3.sup.−, ClO.sub.4.sup.−, and/or .sup.−OH.

(27) As described herein, a filter cake (also referred to as a cake, mudcake, or wall cake) means the residue deposited on a permeable medium when a slurry, such as a drilling fluid, is forced against the medium under a pressure. The filter cake is a layer formed by solid particles in drilling mud against porous zones due to differential pressure between hydrostatic pressure and formation pressure. The filtrate is the liquid that passes through the medium, leaving the cake on the medium. Drilling muds are usually tested to determine the filtration rate and filter-cake properties. Filter cake properties, including cake thickness, toughness, slickness, and permeability, are important because the filter cake that forms on permeable zones in the wellbore can cause plugging, i.e., stuck pipe, and other drilling problems. Reduced oil and gas production can result from reservoir damage when a poor filter cake allows deep filtrate invasion. A degree of filter cake buildup is desirable to isolate formations from drilling fluids, however. In open hole completions in high-angle or horizontal holes, the formation of an external filter cake is preferable to a cake that forms partly inside the formation, which inside formations have higher potential for formation damage.

(28) For the drilling operation, it may be preferable to have a filter cake that is impermeable and thin. Practically, the filter cake from API or HTHP fluid loss test should be less than or equal to 1/16 inch. If the drilling fluid is in poor shape, resulting in a thick filter cake in the wellbore, blocked pipe, stuck pipe and/or high torque/drag may occur. Thick filter cakes increase the contact area between drilling string or any kind of tubular. Drilling into permeable zones that are severely overbalanced risk the drill stem getting differentially stuck across these zones. Beyond the drilling string get stuck, the logging tool may also become stuck across permeable sands. If the drilling fluid/mud has a thick filter cake across the wall of the wellbore under dynamic conditions including drilling, working pipe, etc., torque will increase. A thick wall filter cake will also result in high drag while tripping out of the hole.

(29) Aspects of the invention comprise using thermochemical reactions to remove the water-based and/or oil-based drilling fluid filter cake and designing the process to improve the removal efficiency in well cleanup in long horizontal wells.

(30) Aspects of the invention include the removal of barite oil- and water-based filter cakes using a combined solution of thermochemical/EDTA chelating agent solution in one single stage. Aspects of the invention comprise use of 1:1 molar ratio of a thermochemical agent with 25 wt % EDTA chelating agent at pH 14 to yield 89% removal efficiency in barite water base filter cake and 83% removal efficiency in barite oil base filter cake in 6 hours. Aspects of the invention provide generating one or more pressure pulses, e.g., with one or more thermochemical reactions, optionally combined with temperature, to improve removal efficiency relative to unheated and/or thermochemical reaction-free conditions. Aspects of the invention include formulations allowing safe handling and/or minimizing corrosion risk, via localization of the reaction, the high pressure, and temperature (only) at the formation face.

EXAMPLES

(31) Materials: Typical field formulations were used for the oil and water-based drilling fluids to form the filter cake, Tables 1 and 2 below list the composition of these fluids, wherein XC Polymer is a xanthan gum derivative of molecular weight 1016.8 g/mol, the chemical formula C.sub.36H.sub.58O.sub.29P.sub.2, the IUPAC name 6-[6-[6-(acetyloxymethyl)-2-[3-[3,4-dihydroxy-6-(hydroxymethyl)-5-phosphanyloxyoxan-2-yl]oxy-5-hydroxy-2-(hydroxymethyl)-6-(phosphanylmethyl)oxan-4-yl]oxy-4,5-dihydroxyoxan-3-yl]oxy-2-carboxy-4,5-dihydroxyoxan-3-yl]oxy-7,8-dihydroxy-2-methyl-4,4a,6,7,8,8a-hexahydropyrano[3,2-d][1,3]dioxine-2-carboxylic acid, used as an emulsion stabilizing and gelling agent.

(32) TABLE-US-00001 TABLE 1 Drilling fluid formulation of the water-based drilling fluid. Additive Amount Unit Water 0.691 bbl Bentonite 4 lb XC Polymer 0.5 lb KOH 0.5 lb KCl 20.0 lb NaCl 66 lb Barite 352 lb CaCO.sub.3 medium 5.0 lb

(33) TABLE-US-00002 TABLE 2 Drilling fluid formulation of oil-based drilling fluid. Name Amount Unit Water 12.28 bbl Oil 24 bbl Calcite 11 lb Barite 42.2 lb KOH 0.05 lb Polymer 0.07 lb Viscosifier 5 lb Emulsifier 5.4 lb

(34) Indiana limestone core samples of 2.0-inch diameter and 2.0-inch length were used as filter media to form the filter cake. A high pressure, high temperature (HPHT) coreflooding set-up was used to form the filter cake, and the same set-up was used to remove the filter cake or the drilling fluid residue. FIG. 1 shows the coreflooding set-up used in the Examples. The polymer is preferably a cellulosic, lignocellulose and/or aminated cellulosic, lignocellulose having quaternary amine groups. The emulsifier is, for example, Witcomul to 3158 that reduces the interfacial tension between oil and water.

(35) Two sets of thermochemical fluids, in addition to ethylenediaminetetraacetic acid (EDTA) chelating agent at pH of 14, preferably only the EDTA fluid is at a pH of 14, were used to remove the water and oil-based barite filter cake. The concentration of EDTA used in all experiments was 25 wt. % potassium salt of EDTA, i.e., K.sub.4EDTA, because such a potassium salt can have higher dissolving power than the sodium salt. The filter cake for both oil and water-based drilling fluids was formed using the HPHT filtration equipment shown in FIG. 1. The same equipment was used to remove the filter cake.

(36) Methodology: After the generation of the filter cake for two different drilling fluids (oil-based and water-based), the HPHT temperature cell was used to remove the drilling fluid residues (filter cake). The first set of thermochemical agents was magnesium sulfate, MgSO.sub.4, in addition to a polymer, polyacrylamide or guar (the polyacrylamide has a molecular weight around 100,000 g/mol and a melting point around 250° C. The first set was mixed in a 300 mL water solution and placed in the HPHT cell above the rock sample covered by the drilling fluid residue. The cell was then heated to 100° C. at 500 psi pressure (nitrogen gas was used to apply the pressure). EDTA chelating agent at pH 14 was added to the thermochemical agent to a final EDTA concentration of 25 wt. %. The mixture was reacted, and the pressure and temperature inside the cell were monitored over time.

(37) The second set of thermochemical agent included ammonium chloride, NH.sub.4Cl, and sodium nitrite, NaNO.sub.2, salts. The salts were prepared in one to one (1:1) molar ratio and mixed with EDTA chelating agent at pH of 14. The final concentration of EDTA chelating agent was 25 wt. % in the approx. 1M solution. Similar to the previous set, the reaction was triggered by heating the HPHT cell to 100° C. (the reaction can be triggered by a temperature as low as 50° C. but this will take longer time, i.e., at least one hour). Pressure and temperature profiles inside the cell were monitored over time. In this experiment, different molar concentrations of thermochemicals were used, e.g., 1 mol/L, 2 mol/L, 3 mol/L.

(38) In-situ heat and pressure pulse can be generated by different methods. For example, heat and pressure can be generated by magnesium sulfate heptahydrate, MgSO.sub.4.7H.sub.2O, and/or a combined solution of ammonium chloride (or other ammonium salts) and sodium nitrite (or other nitrite) salts. The magnesium sulfate has complications related to handling and storing in addition to the possibility of scale formation downhole. The ammonium-with-nitrite method is comparatively safe and easy to handle.

(39) The ammonium-with-nitrite method can be used for different types of filter cakes and drilling fluid residues, insofar as the proper type of dissolver/solubilizer is selected in addition to the thermochemical agent(s). For example, in the case of calcium carbonate drilling fluid residue, chelating agents including Na.sub.4EDTA, Na.sub.4GLDA, and/or Na.sub.3HEDTA, may be preferred to dissolve the calcium carbonate.

(40) In the case that the downhole temperature is insufficient to trigger the reaction (or dehydration in the case of MgSO.sub.4.7H.sub.2O), a second mechanism may be used in which an external buffer is used to trigger the reaction. Such external buffer may be a low pH chelating agent, such as HEDTA or GLDA. In the case of MgSO.sub.4.7H.sub.2O, the initiation of the thermochemical activity requires a temperature of at least 100° C., then magnesium sulfate will dehydrate, releasing hot water or steam.

(41) Referring now to the drawings, wherein like reference numerals designate identical or corresponding parts throughout the several views.

(42) FIG. 1 shows the coreflooding set-up used in the Examples. The arrangement includes at least one inlet for compressed air, fed into a walled space, optionally through a valve including a pressure gage and/or further measurement interfaces. The compressed air is fed into a walled space or chamber, which may have a heating jacket integrated into its wall and/or penetrating into the space. The walled space may contain the removal formation upon a filter cake layer upon a filter medium or filter media, resting upon a base.

(43) Effect of Initial Temperature on the Reaction Time

(44) The chemical reaction of the exemplary thermochemical agents used in the Examples can be described by Equation 1 as follows:
NH.sub.4Cl+NaNO.sub.2.fwdarw.NaCl+2H.sub.2O+N.sub.2+ΔH  Eq. 1,
wherein ΔH is the generated heat. The reaction in Eq. 1 requires heat to start, and the reaction time is a function of the initial temperature. The reaction (e.g., ratio of NH.sub.4Cl to NaNO.sub.2) in Eq. 1, at one to one (1:1) molar ratio, generated an additional temperature of 90° C. and at two to two (2:2) molar ratio, i.e., twice the concentration, relative to EDTA, generated and additional temperature of 115° C. Different initial temperatures were used from 50 to 100° C., with these temperatures representing the downhole reservoir temperatures.

(45) FIG. 2 shows the effect of reservoir temperature on the reaction time. As shown in FIG. 2, the duration of the reaction reaching the maximum temperature is a function of the initial reservoir or wellbore temperature at the time of reaction. The maximum generated temperature generally adds to the initial wellbore temperature. For example, in the case of a 1:1 molar ratio of thermochemical agents the relative to EDTA concentration may be 20-25 wt. %, the cell temperature reached 190° C. when the starting temperature was 100° C. The generated pressure in all cases reached 1500 psi and started to decline to 500 psi during the experiment, attributable to drilling fluid residue removal. The duration of the experiment was changed from 6 to 24 hours, and the drilling fluid residue removal efficiency was determined as a function of removal time. The removal efficiency was calculated by taking the disc weight before and after the removal process, and this difference was divided by the original disk weight (including the drilling fluid residue).

(46) Possible Mechanisms of Drilling Fluid Residue Removal by Thermochemicals and EDTA

(47) The experiments on the drilling fluid residue removal (filter cake) in both oil and water-based drilling fluids were conducted at an initial temperature of 100° C. and an initial pressure of 500 psi for different soaking times. Two different thermochemical molar concentrations relative to EDTA were tested, i.e., 1:1 and 2:2 molar ratios. The first set of experiments were conducted using the water-based drilling fluid.

(48) FIGS. 3A, 3B, 4A, and 4B show photos for oil-based barite filter cakes (FIGS. 3A and 3B) and water-based barite filter cakes (FIGS. 4A and 4B) that were formed and removed using the HPHT flooding equipment. FIG. 3A to 4B show the results of using the exemplary 2:2 molar ratio thermochemical formulation combined with 25 wt % EDTA chelating agent. The removal efficiency reached 83% in the oil-based filter cake (FIG. 3B). The removal efficiency reached 89% in the water based filter cake (FIG. 4B).

(49) The 2:2 molar ratio thermochemical reaction resulted in a final temperature of 210° C. after 10 minutes of reaction, and this thermal load needed 6 hours to dissipate to the cell temperature of 100° C. The reaction resulted in a final pressure of 1500 psi, which declined to 500 psi after 6 hours. The experimental time was 6 hours.

(50) The resulting temperature from the 2:2 molar ratio thermochemical reaction caused some hydrolysis of the polymer covering the filter cake. In addition, the pressure disturbed the filter cake and removed the polymer form the surface. This process of polymer removal resulted in direct contact between the EDTA and barite. The resulting pressure pulse, i.e., 1500 psi, disturbed the filter cake as well as the polymer that covers the filter cake. This disturbance may have increased the surface area exposed for reaction with both the thermochemical agents and the EDTA chelating agent. The increase in temperature from 100 to 210° C. due to the thermochemical reaction resulted in higher barite solubility.

(51) FIG. 5 shows the barite solubility as a function of temperature in 25 wt. % EDTA in water the final solution after adding thermochemical reactants at pH of 14. Increases in temperature correspondingly increased EDTA diffusion into the filter cake surface, and enhanced the dissolving power. In addition, increasing the temperature increased the reaction rate, allowing the filter cake to be removed in less time compared to low temperatures.

(52) The increase in the barite solubility, i.e., dissolution rate, with increasing temperature may be explained by the reaction kinetics of the 25 wt. % K.sub.4EDTA solution with barite. Experiments on this reaction were conducted for barite discs using rotating disk apparatus, and more detail about the reaction kinetics of barite with chelating agents is described in Energy and Fuels 2018, 32, 9813-9821, and SPE Drilling & Completion 2019, 34(1), SPE-187122-PA (16-26), each of which is incorporated by reference herein in its entirety. The relationship between the dissolution rate of barite and the EDTA diffusion coefficient are shown below in Equation 2:

(53) $\begin{array}{cc}{R}_d=\frac{0.60248{\left(\frac{{\mu }_f}{{\rho }_f{D}_e}\right)}^{-\frac{2}{3}}{C}_b\sqrt{\frac{\mu }{\rho }}}{1+0.2980{\left(\frac{{\mu }_f}{{\rho }_f{D}_e}\right)}^{-\frac{1}{3}}+0.1451{\left(\frac{{\mu }_f}{{\rho }_f{D}_e}\right)}^{-\frac{2}{3}}}{\omega }^{\frac{1}{2}},& \mathrm{Eq}.2\end{array}$
wherein Rd is the reaction rate in mole/cm.sup.2.Math.s, μ.sub.f is the viscosity of the 25 wt. % K.sub.4EDTA in g/(s.Math.cm), p is the density of K.sub.4EDTA in g/cm.sup.3, D.sub.e is the diffusion coefficient in cm.sup.2/s, C.sub.b is the molar concentration of K.sub.4EDTA (0.75 M in this case), and co is the disk rotational speed in Hz or s.sup.−1. The effect of the generated temperature using thermochemical agents on the 25 wt. % K.sub.4EDTA diffusion coefficient was investigated at three different temperatures, i.e., 100, 125, and 150° C.

(54) FIG. 6 shows the diffusion coefficient at the temperatures 100, 125, and 150° C. The diffusion coefficient increased significantly with temperature which, in turn, was observed to increase the dissolution rate of barite filter cake.

(55) The effect of a pressure pulse on the disturbance of the filter cake was studied by testing the filter cake solubility at 210° C. with and without thermochemical fluids at 1500 psi. All other parameters were held constant as if the thermochemical reaction were to proceed except for the pressure pulse. A second experiment was performed for comparison to the above experiment. The thermochemical-free experiment was conducted after the formation of the water-based barite filter cake using the HPHT cell. EDTA chelating agent at 25 wt. % concentration in water and pH of 14 was used at a temperature of 210° C. and a pressure of 1500 psi. This experiment was compared to the initial experiment that was conducted using the combined thermochemical-EDTA chelating agent solution. The filter cake removal efficiency for the second, thermochemical-free experiment was 75%, compared to 89% for the first case (using the thermochemical agents). These results support the conclusion that the pressure pulse generated by the thermochemical reaction disturbed the filter cake integrity and exposed more surface area for the reaction.

(56) FIG. 7 shows the effect of barite surface area on the reaction with 25 wt. % EDTA chelating agent at 100° C. The average particle size of the industrial barite that is typically used in drilling fluid preparation is 40 microns. Barite particle size has an effect on the barite solubility in 25 wt % EDTA chelating agent. The set of solubility experiments plotted in FIG. 7 were conducted at 210° C. for 6 hours using 25 wt. % EDTA at pH 14. Lower barite particle size yielded the highest solubility as shown in FIG. 7. A maximum barite solubility was obtained for a 40-micron size and the lowest solubility was for the largest particle size of 200-micron. Smaller particle sizes resulted in larger surface areas as is described by Equation 3, below:

(57) $\begin{array}{cc}SSA=\underset{I=1}{\overset{n}{.Math.}}\frac{6}{d_i\rho }\left(\frac{w_{i}F}{100}\right),& \mathrm{Eq}.3\end{array}$
wherein SSA is the specific surface area in m.sup.2/kg, w.sub.i is the weight percentage in size fraction i, F is the surface shape factor (between 1.1 and 1.15), d.sub.i is the geometric mean size of particle size fraction i in cm, p is the apparent density of the particle in kg/m.sup.3, and n is the number of size fractions.

(58) The reaction rate of EDTA chelating with barite is affected by the surface area exposed to the reaction, which is likewise influenced by the particle surface area, which can be described by Equation 4, below:
R.sub.m=r.sub.mS.sub.m  Eq. 4,
wherein R.sub.m is the reaction rate of the mineral, r.sub.m is the specific reaction rate constant for the mineral, and S.sub.m is the mineral surface area. Equation 4 indicates that the reaction and solubility of barite mineral is a function of the surface area exposed for reaction.

(59) FIG. 8 shows the effect of exposure time on the filter cake removal. The removal efficiency in the experiments did not show significant change after 6 hours of reaction. This may be attributed to the fact that, after 6 hours, the 25 wt. % EDTA solution may have become saturated with barite thereby retarding further reaction with and/or solubilization of the existing barite in solution. As shown in FIG. 8, a substantially complete dissolution for the filter cake removal of barite weighted water-based drilling fluids using a combined thermochemical/EDTA treatment can be achieved by 6 hours.

(60) The diffusion coefficient of EDTA chelating agent is a function of the barium concentration in solution. After 6 hours, the barium concentration reached 15,000 ppm. This high concentration, i.e., 15,000 ppm or 1.5%, retarded the reaction of EDTA and resulted in minor changes in the barite solubility at higher soaking times. The EDTA diffusion to the barite surface was indicated to be inversely proportional to the barite concentration in solution.

(61) Numerous modifications and variations of the present invention are possible in light of the above teachings. It is therefore to be understood that within the scope of the appended claims, the invention may be practiced otherwise than as specifically described herein.