METHOD FOR CONTROLLING THE MIGRATION OF FORMATION FINES

Abstract

A method for limiting and/or preventing the migration of fines in a geological formation, in particular a subterranean formation, the method including bringing the formation into contact with one or more copolymers including at most 40 mol % of repeating units derived from a cationic monomer.

Claims

1-15. (canceled)

16. A method for averting and/or delaying and/or limiting and/or preventing the migration of fines in a geological formation, said method comprising bringing the formation into contact with one or more copolymers comprising: at most 40 mol % of monomeric units derived from one or more cationic monomers of formula (Ia) and/or (Ib)
CH.sub.2═C(R.sub.4)—C(═O)—Y—(CH.sub.2).sub.m—N.sup.+(R.sub.1)(R.sub.2)(R.sub.3), X.sup.−   (Ia)
[CH.sub.2═CH—CH.sub.2].sub.n—N.sup.+(R.sub.1)(R.sub.2)(R.sub.3).sub.(2−n), X.sup.−  (Ib) in which R.sub.4 represents a hydrogen atom or a methyl radical, R.sub.1, R.sub.2 and R.sub.3, which may be identical or different, represent an ethyl radical or a methyl radical, m represents an integer between 1 and 4, n represents 1 or 2, Y represents NH or O, and X.sup.− represents an anion chosen from bromide or chloride ions, at least 60 mol % of monomeric units derived from one or more neutral monomers of formula (II)
CH.sub.2═C(R.sub.5)—C(═O)—N(R.sub.6)(R.sub.7)   (II) in which R.sub.5 represents a hydrogen atom or a methyl radical, R.sub.6 and R.sub.7 represent, independently of one another, a hydrogen atom or an alkyl radical comprising from 1 to 4 carbon atoms, which is optionally substituted with a hydroxyl group, wherein the sum of the repeating units derived from the cationic monomer of formula (Ia) and/or (Ib) and the repeating units derived from the neutral monomer of formula (II) represents at least 95 mol % of the total sum of the repeating units of the copolymer, and the copolymer does not comprise organosilane units.

17. The method according to claim 16, wherein the copolymer comprises at most 30 mol % of monomeric units derived from one or more cationic monomers of formula (Ia) and/or (Ib).

18. The method d according to claim 17, wherein the copolymer comprises at most 20 mol % of monomeric units derived from one or more cationic monomers of formula (Ia) and/or (Ib).

19. The method according to claim 16, wherein in the formula (Ia) and/or formula (Ib) R.sub.1═R.sub.2═R.sub.3═CH.sub.3.

20. The method according to claim 16, wherein the cationic monomers of formulae (Ia) and (Ib) are chosen from diallyldialkylammonium and allyltrialkylammonium salts; acidified or quaternized salts of dialkylaminoalkyl acrylates, or quaternized salts of dialkylaminoalkylmethacrylates, and acidified or quaternized salts of dialkylaminoalkylacrylamides or of dialkylaminoalkylmethacrylamides.

21. The method according to claim 20, wherein the cationic monomers of formulae (Ia) and (Ib) are chosen from diallyldimethylammonium chloride (DADMAC), (2-(Acryloyloxy)ethyl)trimethylammonium chloride (ADAMEMC), (2-(Methacryloyloxy)ethyl)trimethylammonium chloride (MADAMEMC), (3-methacrylamidopropyl)trimethylammonium chloride (MAPTAC) and (3-acrylamidopropyl)trimethylammonium chloride (APTAC).

22. The method according to claim 16, wherein in formula (Ia), Y represents NH.

23. The method according to claim 16, wherein the monomer of formula (II) is chosen from acrylamide, methacrylamide, N,N-dimethylacrylamide, N-methylmethacrylamide, N-ethylmethacrylamide, N-propylmethacrylamide, N-isopropylmethacrylamide, N-(2-hydroxyethyl)methacrylamide, N-methylacrylamide, N-ethylacrylamide, N-propylacrylamide or N-(2-hydroxyethyl)acrylamide, and N[2-hydroxy-1,1-bis(hydroxymethyl)ethyl]propenamide.

24. The method according to claim 23, wherein the monomer of formula (II) is chosen from acrylamide; N,N-dimethylacrylamide; N-[2-hydroxy-1,1 bis(hydroxymethyl)ethyl]propenamide; and 2-hydroxyethylacrylamide.

25. The method according to claim 16, wherein the copolymer has an average molar mass ranging from 3×106 g.Math.mol.sup.−1 to 12×106 g.Math.mol.sup.−1.

26. The method according to claim 16, wherein the sum of the repeating units derived from the cationic monomer of formula (Ia) and/or (Ib) and the repeating units derived from the neutral monomer of formula (II) represents from 98% to 100% of the total sum of the repeating units of the copolymer.

27. The method according to claim 16, wherein the formation is a subterranean formation.

28. The method according to claim 27, wherein the subterranean formation is in contact with an oil-producing and/or gas-producing well.

29. The method according to claim 16, wherein the formation is a subterranean formation in contact with a water table.

30. The method according to claim 16, wherein the copolymer(s) are in a carrier fluid.

31. The method according to claim 30, wherein the carrier fluid is water.

32. The method according to claim 31, wherein the carrier fluid comprises from 500 to 5000 ppm of copolymer comprising: at most 40 mol % of monomeric units derived from one or more cationic monomers of formula (Ia) and/or (Ib)
CH.sub.2═C(R.sub.4)—C(═O)—Y—(CH.sub.2)—N(R.sub.1)(R.sub.2)(R.sub.3), X.sup.−  (Ia)
[CH.sub.2═CH—CH.sub.2].sub.n—N.sup.+(R.sub.1)(R.sub.2)(R.sub.3).sub.(2−n), X.sup.−  (Ib) in which R.sub.4 represents a hydrogen atom or a methyl radical, R.sub.1, R.sub.2 and R.sub.3, which may be identical or different, represent the ethyl radical or a methyl radical, m represents an integer between 1 and 4, n represents 1 or 2, Y represents NH or O, and X.sup.− represents an anion chosen from bromide or chloride ions, at least 60 mol % of monomeric units derived from one or more neutral monomers of formula (II)
CH.sub.2═C(R.sub.5)—C(═O)—N(R.sub.6)(R.sub.7)   (II) in which R.sub.5 represents a hydrogen atom or the methyl radical, R.sub.6 and R.sub.7 represent, independently of one another, the hydrogen atom or an alkyl radical comprising from 1 to 4 carbon atoms, which is optionally substituted with the hydroxyl group, wherein the sum of the repeating units derived from the cationic monomer of formula (Ia) and/or (Ib) and the repeating units derived from the neutral monomer of formula (II) represents at least 95 mol % of the total sum of the repeating units of the copolymer, and the copolymer does not comprise organosilane units.

33. The method according to claim 30 wherein the carrier fluid does not include any acidic compounds.

34. The method according to claim 16, which also comprises a step of pre-treating the formation before the bringing into contact with the copolymer(s).

Description

DESCRIPTION OF THE FIGURES

[0196] FIG. 1 represents the principle of the treatment of a formation according to the method of the invention; a) represents the non-treated rock of the formation (1) comprising fines (2) and grains of sand (3), b) represents the same non-treated rock (1) in which migration of the fines (2) and of the grains of sand (3) is observed during the hydrocarbon extraction, the arrows represent the direction of extraction of the hydrocarbon and of movement of the grains and particles, and c) represents the same portion of rock (1) in which a copolymer according to the invention has been adsorbed to form a film (4) so as to prevent the fines (2) and the grains of sand (3) from migrating.

[0197] FIG. 2 represents a scheme of the experimental device for measuring the residual permeability to water.

[0198] FIG. 3 represents the change in the residual permeability to water of a sandstone core sample not treated using the method of the invention (core sample C1). The x-axis represents the volume in ml of brine injected through the core sample. The y-axis represents the percentage of residual permeability to water % K.

[0199] FIG. 4 represents the change in the residual permeability to water of a sandstone core sample treated using the method according to the invention (core sample C2). The x-axis represents the volume in ml of brine injected through the core sample. The y-axis represents the percentage of residual permeability to water % K.

[0200] FIG. 5 represents the change in the residual permeability to water of a sandstone core sample treated using a comparative polyacrylamide polymer (core sample C3). The x-axis represents the volume in ml of brine injected through the core sample. The y-axis represents the percentage of residual permeability to water % K.

EXPERIMENTAL SECTION

[0201] The following examples illustrate the invention without limiting the scope thereof.

[0202] The following examples are presented in two parts. The first part describes the laboratory procedure used to design a treatment. This procedure consists in using sandstone core samples comprising fine particles that can migrate under the effect of a change in salinity. The second part describes the results obtained in a formation in a natural environment.

I—Laboratory Tests

1—Materials

[0203] Sandstone: The tests are carried out on samples in the form of cylindrical core samples from a block of sandstone from Vosges. The core samples have the dimensions 3.81 cm×5.08 cm, have a porosity of 25% and have an absolute permeability of 2 to 3 Darcy. The sandstone core samples have the following mineralogical composition: [0204] Quartz=82%, [0205] Feldspar (90% Orthoclase+10% Albite)=12.5%, [0206] Clays=4.5%, [0207] Hematite=1%.

[0208] Brines: Two solutions S1 and S2 are prepared by mixing pure NaCl with deionized water in a ratio of 100 g/l and 5 g/l respectively.

[0209] Monomers: acrylamide (CAS N° 79-06-1) and acryloyloxyethyl trimethylammonium chloride (ADAMEMC) (CAS N° 4499-01-0) were purchased from Merk Sigma Aldrich.

2—Preparation and Characterization of the Copolymers

[0210] Polymer 1 (according to the invention): it is a copolymer comprising 5 mol % of repeating units derived from ADAMEMC and 95 mol % of monomer units derived from acrylamide. The copolymer has an average molar mass of 6×106 g.Math.mol.sup.−1 as determined by the method described in Rodriguez, Laurent et al., Monitoring Thermal and Mechanical Stability of Enhanced Oil Recovery (EOR) Acrylamide Based Polymers (PAM) Through Intrinsic Viscosity (IV) Determination Using a New Capillary Rheology Technique, January 2016, DOI 10.2118/179827-MS.

[0211] Polymer P2 (comparative): it is a polyacrylamide: a non-ionic polymer comprising 100 mol % of acrylamide units and of molar mass 6×106 g.Math.mol.sup.−1.

3—Experimental Protocol

3.1—Determination of the Pore Volume Vp of the Core Samples

[0212] The mass of the sandstone core samples mc is determined beforehand by weighing. The core sample is then placed in a desiccator while maintaining the vacuum. Once the vacuum has been established, the core sample is saturated with brine S1 containing 100 g/l of NaCl, the mass and the density ρ of which are known.

[0213] The saturated core sample is then weighed, its new mass is ms. The difference in mass Δm=ms−mc after imbibition of the brine corresponds to the amount of brine present in the pore volume.

The pore volume is calculated according to the following equation:

[00001]$\mathrm{Vp}=\frac{\Delta m}{\rho }$

[0214] The pore volume of the sandstone core samples studied is 20 ml.

3.2—Measurement of the Residual Permeability to Water

[0215] The residual permeability to water K.sub.w of the sandstone core sample represents its capacity to allow water to flow via its pores. The experimental assembly for measuring the residual permeability to water is represented in FIG. 2.

[0216] First of all, various solutions are injected into the core samples. These solutions are described in the table below.

TABLE-US-00001 TABLE 1 C2 (according to Core sample C1(comparative) invention) C3 (comparative) Injection S1 containing S1 containing S1 containing solution 100 g/l de NaCl 100 g/l of NaCl + 100 g/l of NaCl + 5 Vp* of polymer 5 Vp* of polymer P1 at 500 ppm in P2 at 500 ppm in the solution S1 the solution S1 *Vp corresponds to the pore volume determined in Section 2.1.

[0217] Solutions with different salinities are subsequently injected through the core sample. The various following injection sequences are carried out. [0218] 1—injection of solution S1 containing 100 g/l of NaCl, [0219] 2—injection of solution S2 at 5 g/l of NaCl, [0220] 3—injection of solution S1 at 100 g/l of NaCl.

[0221] The flow rate for injecting the solutions is constant throughout the tests and is set at 10 cm.sup.3/h.

[0222] The pressure differential AP through each core sample is measured throughout the injection sequences by virtue of a pre-calibrated differential pressure sensor.

[0223] The percentage of residual permeability to water % K.sub.w is calculated according to the following equation:

[00002]$\%\mathrm{Kw}=100*\frac{\Delta P1}{\Delta Px}$

wherein [0224] ΔP1: pressure differential at the plateau during the core-sample imbibition phase, [0225] ΔPx: pressure differential at the plateau during an injection sequence x (x=1, 2 or 3).

4—Experimental Results

[0226] The results of the measurements of residual permeability to water on the three core samples C1, C2 and C3 are given in FIGS. 3, 4 and 5.

[0227] Curve (1) (in light grey) in the three FIGS. 3, 4 and 5 corresponds to the first injection sequence, that is to say the injection of brine containing 100 g/l of NaCl. The percentage of permeability to water % K.sub.w in this case is equal to 100%. It is the reference. During the second sequence of injecting brine containing 5 g/l of NaCl, curve (2) (in dark grey), a considerable drop in the permeability is obtained. This is explained by the activation of the clays contained in the core sample which can swell and propagate. This results in damage to the core sample. The particles can migrate, accumulate and block the pores of the core sample.

[0228] During the third injection of brine containing 100 g/l of NaCl, curve (3) (in black), the percentage of residual permeability to water remains low in the case of the non-treated core sample (C1). % K.sub.w is about 40%. This injection shows the irreversible consequences of the injection of brine containing 5 g/l of NaCl. The result is similar for the core sample C3 into which was injected the non-ionic polymer outside the invention with a % K.sub.w of about 60%.

[0229] On the other hand, in the case of the core sample C2 treated with the copolymer of the invention, the percentage of residual permeability to water returns to the initial level of 100%. This result demonstrates the effectiveness of the treatment with the copolymer of the invention on the migration of the particles within the sandstone core sample.

[0230] These examples therefore clearly demonstrate the effectiveness of the injection of the copolymer according to the invention for limiting and/or averting and/or preventing the migration of fine particles.

[0231] 5—Effect of the Copolymer Composition on the Wettability of the Core Samples

[0232] Experiments were conducted to assess the changes in relative permeability to water and to oil at end points after injection of copolymers of different compositions, in particular copolymers according to the invention (Polymer P1) and organosilane-containing copolymers according to the prior art.

[0233] The tests were carried out on Bentheimer sandstone samples in the form of cylindrical core and having an absolute permeability of 1.8 Darcy.

[0234] The procedure consists first in determining the relative permeability to water (Krw) at residual oil saturation (Sor) and the relative permeability to oil (Kro) at irreducible water saturation (Swi) of the core. Then, the different copolymers are injected in solution to determine the set of relative permeabilities in the same flow conditions. The following steps are performed: [0235] Mounting the core in a Hassler cell in an oven set at 25° C., [0236] Saturation of the core with a 2% KCl brine and measurement of absolute permeability k, [0237] performing two cycles of oil/brine injection with measurements of end points Kro at Swi and Krw at Sor, [0238] Injection of the polymer solution (5 Pore Volume) at 500 ppm in 2% KCl brine at residual oil saturation, [0239] Shut in for 48 hours, [0240] Water injection and measurement of relative permeability to water at Sor, [0241] Oil injection and measurement of relative permeability to oil at Swi.

[0242] The obtained results are summarized in Table 2:

TABLE-US-00002 TABLE 2 Polymer Polymer comprising comprising 13 mol % of 20 mol % of Polymer P1 organosilane organosilane Relative Initial (according to functions functions permeabilities value the invention) (comparative) (comparative) Krw (%) 0.15 0.10 0.52 0.53 Kro (%) 0.89 0.90 0.48 0.47

[0243] Results show that relative permeability to oil has not been affected after the injection of the copolymer according to the invention and has strongly decreased for copolymers comprising organosilane units of 13 mol % and 20 mol %. On the other hand, water permeability has strongly increased after injection of copolymers comprising organosilane units, and has decreased after the injection of the polymer according to the invention. These results show that after injecting copolymers comprising organosilane units, the core becomes oil wet, which induces a loss in oil permeability and a gain in water permeability. This will lead to a drop in well performances. This adverse effect does not occur with the polymer according to the invention, which keeps the core water wet.

II—Field Tests

[0244] 2 gas-producing wells in different reservoir rocks were treated with the copolymer P1 of the invention. The reservoir rocks consist of clay-loam sandstone rich in fines having the following characteristics: [0245] permeability=10-70 mD, [0246] porosity=15-20%, [0247] total perforation height=5to 50 m, [0248] temperature=40-50° C., [0249] salinity=30 000-40 000 TDS (Total Dissolved Salt).

[0250] Before treatment, it was observed that the production of sand in these wells occurs in two steps. At the beginning, the sand essentially consists of fines of which the grain size is less than 50 μm. At a subsequent stage, the distribution of the sand grains broadens with a considerable fraction of large particles having a diameter of 100-150 μm or more. Such behaviour reveals a degradation of the rock surrounding the gas-producing well throughout the extraction operation.

[0251] Before the treatment with the copolymer of the invention, two batches of brine containing 1% of KCl were injected into the wells in order to verify the injectivity. All the injections were carried out in “bullhead” mode. The term “bullhead” refers to the process of forced pumping of fluids throughout the open interval in a formation without needing to isolate the zone into which the fluid will penetrate. The pressure at the bottom of the well was continually measured by a logging unit.

[0252] The polymer solutions were prepared by solubilizing the copolymer P1 at a concentration of between 1000 and 4000 ppm in freshwater comprising 1% of KCl. These solutions are stored at the surface in 10 m.sup.3 tanks equipped with blade mixers and pumped in the well by a triplex pumping unit.

[0253] The solutions are injected into the wells while maintaining a flow of approximately 10 m.sup.3/h. The pressure at the bottom of the well is maintained below 12 000 kPa.

[0254] The injection of the polymer solutions is followed by a continuous injection of nitrogen, and the gas extraction is recommenced shortly afterwards.

[0255] The comparison of the data obtained before and after the treatment is summarised in the following table:

TABLE-US-00003 TABLE 3 Before treatment Volume of After treatment Presence polymer Presence Gas of sand solution Gas of sand production and of injected production and of Wells (kSm.sup.3/day) fines (m.sup.3) (kSm.sup.3/day) fines 1 26 Yes 51 55 No 2 18 Yes 55 49 No

[0256] These results clearly show that the production of sand and fines is halted after the treatment with the polymer of the invention and the gas production yield is considerably improved.