Method for enhanced oil recovery in a subterranean carbonate formation

Abstract

This invention concerns a method for enhanced oil recovery in a subterranean carbonate formation by injecting an aqueous composition comprising at least one water-soluble polymer containing acrylamidopropyltrimethylammonium chloride (APTAC).

Claims

1. Method for enhanced oil recovery in a subterranean carbonate formation comprising injecting an aqueous composition comprising at least one water-soluble polymer, wherein the water-soluble polymer is an amphoteric polymer containing acrylamidopropyltrimethylammonium chloride and at least one anionic monomer.

2. Method according to claim 1, wherein the number of acrylamidopropyltrimethylammonium chloride units in the water-soluble polymer is between 20 and 99.9 mol % relative to the total number of moles of monomer units of the water-soluble polymer.

3. Method according to claim 1, wherein the number of anionic monomer units in the water-soluble polymer is between 0.1 and 70 mol % relative to the total number of moles of monomer units of the water-soluble polymer.

4. Method according to claim 1, wherein the water-soluble polymer is an amphoteric polymer of acrylamidopropyltrimethylammonium chloride and of at least one anionic monomer, wherein the anionic monomer is selected the list consisting of acrylic acid, methacrylic acid, itaconic acid, crotonic acid, maleic acid, fumaric acid, sulphonated monomers, phosphonated monomers, 2-acrylamido-2-methylpropanesulphonic acid, vinylsulphonic acid, vinylphosphonic acid, allylsulphonic acid and allylphosphonic acid, wherein the anionic monomer is not in salt form or partially or totally in salt form.

5. Method according to claim 1, wherein the water-soluble polymer further contains at least one non-ionic and/or zwitterionic monomer.

6. Method according to claim 1, wherein the water-soluble polymer is an amphoteric polymer of acrylamidopropyltrimethylammonium chloride and 2-acrylamido-2-methylpropanesulphonic acid and/or one of its salts.

7. Method according to claim 1, wherein the water-soluble polymer does not contain cationic monomers other than acrylamidopropyltrimethylammonium chloride.

8. Method according to claim 1, wherein the weight-average molecular weight of the water-soluble polymer is between 1 and 15 million g/mol.

9. Method according to claim 1, wherein the aqueous composition comprises between 50 and 50 000 ppm of water-soluble polymer.

10. Method according to claim 1, wherein the subterranean carbonate formation contains at least 20% carbonates.

11. Method according to claim 1, wherein the method comprises the following steps: preparing an aqueous composition comprising at least one water-soluble polymer, injecting the aqueous composition into a subterranean carbonate formation, sweeping the subterranean carbonate formation by means of the injected aqueous composition, recovering a mixture of water and oil and/or gas.

12. Method according to claim 1, wherein the method is a Surfactant Polymer, Alkaline Polymer, or Alkaline Surfactant Polymer method of enhanced oil recovery comprising injecting surfactants and/or alkaline agents.

13. Injection fluid for use in a method for enhanced oil recovery in a subterranean carbonate formation comprising a water-soluble polymer according to claim 1.

Description

EXAMPLES

Example 1: Obtaining Polymers

[0066]

TABLE-US-00001 ATBS NVP AM DADMAC EO APTAC Polymer 1 100 (comparative) Polymer 2 35 35 30 (comparative) Polymer 3 70 30 (comparative) Polymer 4 100 (comparative) Polymer 5 100 (comparative) Polymer 6 33 67 (invention) Polymer 7 50 50 (invention) Polymer 8 67 33 (invention) Polymer 9 50 50 (comparative) Polymer 10 50 50 (comparative)

[0067] Polymers are prepared by gel polymerisation. Powders are obtained for each of the polymers, the monomer composition of which is shown in table 1.

[0068] Table 1—Monomer Composition of Polymers by Mole Percent

[0069] ATBS: 2-Acrylamido 2-methylpropanesulphonic acid

[0070] NVP: N-Vinyl Pyrrolidone

[0071] AM: Acrylamide

[0072] DADMAC: Dimethyldiallylammonium chloride

[0073] APTAC: Acrylamidopropyltrimethylammonium chloride

Example 2: Evaluation of Polymer Properties

[0074] The polymers are subjected to various tests to evaluate their injectability into the subterranean formation (filter ratio), their ability to contribute to the viscosity of the injection fluid, including in high-salinity and high-temperature conditions (Brookfield viscosity), and their efficacy in a carbonate field (adsorption).

[0075] ‘Filter ratio’ (FR) refers to a test that determines the performance of a polymer solution in conditions approaching the permeability of the deposit, and consists of measuring the time taken by a given volume/concentration of solution to pass through a filter. Generally, the FR compares the filterability of the polymer solution for two consecutive equivalent volumes, indicating the tendency of the solution to clog the filter. Lower FR values indicate better performance.

[0076] The test used to determine FR consists of measuring the time taken by a given volume of solution with 1000 ppm active polymer to flow through a filter. The solution is contained in a pressurised cell at a pressure of 2 bar, and the filter is 47 mm in diameter, with a pore size of 1.2 μm.

[0077] The time required to obtain 100 ml (t100 ml), 200 ml (t200 ml), and 300 ml (t300 ml) of filtrate are thus measured, defining an FR expressed as:

FR=(t300ml−t200ml)/(t200ml−t100ml)

[0078] The time measurements are exact to 0.1 s.

[0079] The FR thus represents the ability of the polymer solution to clog the filter with two consecutive equivalent volumes.

[0080] The 25° C. viscosity measurement is carried out using a Brookfield viscosimeter with UL module at 6 RPM (7.34 s.sup.−1) at 25° C. on a solution containing 5 g/l polymer, with the polymer dissolved in water. The viscosity measurement is carried out in anaerobic conditions in a glove box.

[0081] The brine viscosity measurement is carried out in the same conditions, except that the measurement temperature is 70° C., and the polymer is processed in a brine containing 10 g/l NaCl and 1 g/l CaCl.sub.2. The viscosity measurement is carried out in anaerobic conditions in a glove box.

[0082] The viscosity results are expressed in cps. The greater the viscosity, the better the oil sweeping performance in the subterranean formation.

[0083] Thermal stability corresponds to the percentage of viscosity conserved at 25° C., after 6 months of storage of a 4.5 g/l polymer solution in a brine containing 75.984 g/l NaCl, 22.42 g/l CaCl.sub.2, 2H.sub.2O, and 13.475 g/l MgCl.sub.2, 6H.sub.2O, at a temperature of 100 or 120° C. The viscosity measurements are carried out in the same conditions as the 25° C. viscosity measurements described supra. The greater the percentage, the better the sweeping performance in these temperature conditions.

[0084] Adsorption in a carbonate environment is measured by the method described infra. The test consists of injecting a 1000 ppm polymer into a carbonate rock core and determine the amount of polymer adsorbed to the surface of the carbonate rock compared to the proportion of polymer that passed through the core. More specifically, two injections of the polymer solution under evaluation are carried out in a core of the carbonate rock in question.

[0085] The carbonate rock on which the tests are conducted is an Estaillades carbonate rock, a well-known reference having the following characteristics: permeability: 120 mD, porosity (porous volume): 30.7%, and having the following composition: [0086] Quartz: 0.3 mass %; [0087] Calcite: 99.4 mass %; [0088] Apatites: 0.2 mass %; [0089] Barite: 0.1 mass %;

[0090] First of all, the carbonate rock core, 2.5 cm in diameter and 15 cm in length, is saturated under vacuum with the same brine as described above, previously filtered and deoxygenated and then placed in an injection cell in a porous medium, itself connected to the testing device.

[0091] Then, a first injection of the polymer solution is made at a constant flow rate of 5 ml/h. The volume of this injected is set at 5× the porous volume of the rock in question.

[0092] Then, a volume of brine corresponding to 25× the porous volume of the rock in question is injected at a constant flow rate of 5 ml/h to displace the non-adsorbed polymer out of the rock.

[0093] Lastly, a second injection of the polymer solution is made at a constant flow rate of 5 ml/h. The volume of this front is set at 5× the porous volume of the rock in question.

[0094] Upon each injection of the polymer solution, the effluents from the core are collected in the form of 4 ml fraction. For each effluent fraction collected, the concentration of the polymer solution is determined in order to establish the breakthrough curves of the polymer solution for each injection.

[0095] The difference in breakthrough volume at 50% of the concentration injected between the two polymer injections is then used to determine the quantity of polymer adsorbed in μg polymer/g rock.

[0096] The adsorption is then expressed in μg/g, and a low value is advantageous, because it shows the greatest tendency of the polymer to be adsorbed and thus immobilised by the carbonate rock. A lower adsorption thus allows more polymers to participate in the sweeping of the formation and, de facto, to increase the oil recovery performance in a carbonate field.

[0097] The results are shown in table 2 below.

TABLE-US-00002 TABLE 2 Polymer performance Viscos- Brine Thermal Thermal ity at viscos- stability stability Adsorp- 25  ity at 100° at 120  tion in FR (cps) (cps) C. in % in % μg/g Polymer 1 1.5 20 12 100 80 90 (comparative) Polymer 2 1.8 17 8 100 80 80 (comparative) Polymer 3 2.6 5 2 30 0 100 (comparative) Polymer 4 3.0 7 4 90 75 120 (comparative) Polymer 5 1.5 16 8 50 20 30 (comparative) Polymer 6 1.3 17 9 80 65 20 (invention) Polymer 7 1.4 18 10 85 75 40 (invention) Polymer 8 1.4 19 10 90 80 60 (invention) Polymer 9 1.6 9 6 90 80 115 (comparative) Polymer 10 2.2 8 5 85 75 125 (comparative)

[0098] These results show that the water-soluble polymers according to the invention 6, 7, and 8 are the only ones that simultaneously offer good performance in carbonate rock and good sweeping properties, including in high-salinity conditions, whilst maintaining good stability at 100 and 120° C.

[0099] Indeed, carbonate fields are often high-temperature fields. The temperature resistance of the polymers is thus taken into account for these specific cases. Although polymers 1 and 2 (comparative) (and 9 and 10, to a lesser extent) offer excellent temperature resistance, the results show that they are not very effective in carbonate fields.

[0100] The examples according to the invention, on the other hand, offer better performance in carbonate fields without excessive compromises in terms of temperature resistance. The performance of polymer 5 in the carbonate field is very good, but has less thermal stability than polymers 6, 7, and 8. Thus, it would be suited to a carbonate field with a lower temperature.