OIL RECOVERY METHOD INTEGRATED WITH THE CAPTURE, UTILIZATION AND STORAGE OF CO2 THROUGH A CAVERN IN SALINE ROCK

Abstract

The present invention finds its field of application among the advanced oil recovery methods, which must occur simultaneously and integrated with the capture, utilization, and storage of CO2 through a cavern built in offshore saline rock. More particularly the invention refers to offshore oil wells where there is an evaporitic rock layer next to it and, suitable for constructing a cavern in the saline rock, for its use as a CO2 and brine control volume in the water-gas alternating injection process in the reservoir.

Claims

1- OIL RECOVERY METHOD INTEGRATED WITH THE CAPTURE, UTILIZATION AND STORAGE OF CO2 THROUGH A CAVERN IN SALINE ROCK, characterized by comprising the following steps: 1—constructing an access well to generate the cavern in saline rock; 2—installing two concentric tubular columns in the well; 3—circulating water through the concentric strings to dissolve the salt; 4—vertically moving the concentric strings of injection and withdrawing the water; 5—evaluating the cavern geometry; 6—instrumenting the cavern in saline rock and the marine floor; 7—performing a cavern hydrostatic integrity test; 8—installing a pipe in the position next to the top of the cavern in saline rock for the CO2 inlet and outlet; 9—installing a pipe in the position next to the bottom of the cavern in saline rock for brine inlet and outlet; 10—carrying out cycles of replacement of brine by CO2 until the cavern is completely filled with CO2 saline rock; 11—abandoning the well

2- METHOD, according to claim 1, characterized in that the cavern in saline rock is generated with the same equipment used in the WAG-type oil recovery method, which originally inject water into the reservoir.

3- METHOD, according to claim 2, characterized in that the cavern in saline rock is generated during the period in which CO2 is injected into the reservoir by the WAG-type oil recovery method.

4- METHOD, according to claim 3, characterized in that the period of water injection for the construction of the cavern in saline rock is from 2 to 24 months.

5- METHOD, according to claims 2 to 4, characterized in that the generation of the cavern in saline rock occurs simultaneously with the WAG-type oil recovery method.

6- METHOD, according to claim 1, characterized in that the water circulation step to dissolve the salt is carried out by an autonomous subsea pumping system or by the SPU.

7- METHOD, according to claim 6, characterized by the system of autonomous pumping or by the SPU to make the direct or reverse circulation of water inside the cavern in saline rock.

8- METHOD, according to claim 1, characterized in that the evaluation of the cavern geometry in saline rock is carried out by sonar inside and/or outside the cavern in saline rock.

9- METHOD, according to claims 1 and 8, characterized in that the evaluation of the cavern geometry in saline rock is used to assess the need to return to step 2 and proceed with the sequence up to step 11.

10- METHOD, according to claim 1, characterized in that the two pipes, at the top and at the base of the cavern in saline rock, are for the fluids and gases entry and exit in the cavern.

11- METHOD, according to claim 10, characterized in that the two pipes comprise rigid or flexible tubes, wherein one is positioned between 1 and 10 m from the top of the cavern in saline rock, for the entry and exit of CO2, and the other is between 1 and 10 m from the bottom of the saline rock cavern, for the brine entry and exit.

12- METHOD, according to claim 11, characterized in that the two pipes have a smaller diameter in relation to the last casing settled in the access well to the saline rock cavern, in the range of 10 to 50% smaller.

13- METHOD, according to claim 12, characterized in that the two pipes are operated alternately or simultaneously substituting the brine in the saline rock cavern for CO2 discontinuously or in steps.

14- METHOD, according to claim 13, characterized in that the replacement of brine in the saline rock cavern by CO2 occurs simultaneously with the WAG-type oil recovery method.

15- METHOD, according to claim 14, characterized in that the WAG-type oil recovery method occurs simultaneously with the capture, utilization and storage of CO2 (CCUS) in the cavern in saline rock.

16- METHOD, according to claims 1, 10 to 14 characterized in that the brine emptying or CO2 filling periods in the cavern in saline rock range from 2 to 24 months.

17- METHOD, according to claim 1, characterized in that the well is abandoned with cement plugs after the total filling of the cavern in saline rock by CO2.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0058] The present invention will be described in more detail below, with reference to the attached figures which, in a schematic and not limiting of the inventive scope, represent examples of its realization. The drawings show:

[0059] FIG. 1 schematically illustrates a cavern offshore in saline rock at the beginning of the process of replacing the brine in the cavern with CO2, in which the brine is injected into a well by the WAG process (water injection period) and the CO2 comes from a SPU;

[0060] FIG. 2 schematically illustrates a variation of FIG. 1, in which the CO2 to be stored in the cave additionally comes from an underwater separation process;

[0061] FIG. 3 schematically illustrates the variation of water and CO2 inside a saline rock cavern over the time, from the construction of the cavern, up to its abandonment, passing through several WAG cycles;

[0062] FIG. 4 schematically illustrates a variation of FIG. 1, in which the CO2 or H2O, coming from the processes of a stationary floating unit, can be drained into the saline rock cavern to then be used in the WAG process;

[0063] FIG. 5 schematically illustrates a variation of FIG. 3, in which H2O coming from the processes of a stationary floating unit can be drained into the saline rock cavern and, as this volume of water and CO2 vary within a rock cavern saline over the time, from the construction of the cavern, up to its abandonment, passing through several WAG cycles;

[0064] The invention is described by means of the following reference numerals: [0065] 01—Oil reservoir; [0066] 02—Producing well; [0067] 03—Hydrocarbon flow from the well to the Stationary Production Unit (SPU); [0068] 04—SPU; [0069] 05—Flare; [0070] 06—Injector well; [0071] 07—Injection of water (brine) and/or processed gases into the injector well; [0072] 08—Evaporitic rock; [0073] 09—Cavern access well in saline rock (CRS); [0074] 10—CRS; [0075] 11—Injection of water (brine) or gases into the CRS from the separation processes at the SPU; [0076] 12—CO2 at the top of the CRS; [0077] 13—Water (brine) at the bottom of the CRS; [0078] 14—submarine raw water injection system; [0079] 15—Injection of water (brine) or gases into the injector well from the CRS; [0080] 16—Piping positioned next to the top of the CRS for CO2 inlet/outlet; [0081] 17—Piping positioned next to the bottom/base of the CRS for brine inlet/outlet; [0082] 18—Subsea oil-gas-water separation equipment [0083] 19—Oil drained to the SPU; [0084] 20—Gas and water drained to the CRS; [0085] 21—Abandonment of the CRS because it was full of CO2.

DETAILED DESCRIPTION OF THE INVENTION

[0086] The present invention relates to a method of constructing caverns in saline rocks for the capture, utilization and storage of CO2 simultaneously and integrated to the advanced recovery process of the WAG type, which substantially reduces the construction cost of said caverns and increases CCUS.

[0087] The hydrocarbon and other fluids produced in a reservoir (1) through a producing well (2) are drained (3) to a Stationary Production Unit (SPU) (4) to be processed through physical and/or chemical processes to separate the produced fluid into oil, gas and water (FIG. 1). The excess of gases produced, such as methane, ethane, butane, CO2, etc) is released/burned in the flare (05) to reduce the risk of explosions in the SPU, but it generates greenhouse gases. And, the water, after being treated and in accordance with current legislation, can be discarded.

[0088] Upon constructing an injector well (06) taking into account the type of oil recovery to be carried out, the gases and or even the water separated from the processed oil can be injected (07) into the injector well (06). However, the produced gases or water are not injected simultaneously into the injector well (06), either one is injected, or another is injected, or only one of them is injected. Therefore, at a certain time the gases are released into the flare (05), while the water is injected into the reservoir (01) through the injector well (06) or the water is discarded, while the gases are injected into the reservoir (01) through the injector well (06). As a result, even so, it generates greenhouse gases when gases are not being injected into the reservoir.

[0089] Below follows a detailed description of a preferred embodiment of the present invention, by way of example and in no way limiting. Nevertheless, it will be clear to a person skilled in the art, from the reading of this description, possible additional embodiments of the present invention further comprised by the essential and optional features below.

[0090] The method for oil recovery integrated with the capture, utilization and storage of CO2 through a saline rock cavern is characterized by having the following steps: [0091] 1. constructing an access well to generate the CRS; [0092] 2. installing two concentric tubular columns in the well; [0093] 3. circulating water through the concentric strings to dissolve the salt; [0094] 4. vertically moving the concentric strings of injection and withdrawing the water; [0095] 5. evaluating the cavern geometry, if it is not as designed, return to step 2; [0096] 6. instrumenting the CRS and the marine floor; [0097] 7. performing a cavern hydrostatic integrity test; [0098] 8. installing piping in the position next to the top of the CRS for the CO2 inlet and outlet; [0099] 9. installing a pipeline in the position next to the bottom/base of the CRS for brine inlet and outlet; [0100] 10. carrying out cycles of replacement of brine by CO2 until the total filling of the cavern in CO2 saline rock occurs; 11. Abandoning the well.

[0101] In said method (FIG. 1), object of the present invention, with the presence of an evaporitic rock layer (08) close to the reservoir (01), an access well (09) for construction the saline rock in cavern (CRS) must be executed. After the last casing shoe is settled inside the salt layer, the salt layer is drilled to the predicted depth for the base of the CRS (not shown), after that, CO2 is injected into the access well, so that this gas protects the last casing shoe cemented in the access well against the dissolution of the water to be injected. Because CO2 is lighter, it will be at the top (12) of the CRS, while water will be at the bottom (13).

[0102] Thus, the construction of the CRS (10) begins by the leaching method from the injection into the access well (09) of water (with 0 at 300,000 ppm of NaCl) (11) coming from the reservoir (01), after passing by the separation processes at the SPU (04), instead of being discarded at the sea. The CRS can also be built by injecting seawater pumped directly from the SPU or by a submarine raw water injection system (SRWI) (14), with an energy source coming from the SPU.

[0103] The CRS can be generated with the same equipment (pumps, filters, separators, pipelines, etc.) used in the WAG-type oil recovery method, which originally inject water into the reservoir. With this, equipment costs for construction the CRS (around 40% of CAPEX) can be attenuated/reduced, due to the sharing of the same equipment with the WAG process.

[0104] And the CRS can be generated during the period in which CO2 is injected into the reservoir by the WAG-type oil recovery method. Therefore, both processes can occur simultaneously.

[0105] The water injection period for the construction of the CRS can be between 2 and 24 months, depending on the dimensions of the CRS, the flow rate and the temperature of the injection water, and the injection method can be direct or reverse circulation, such as the release of the CRS brine to the bottom of the sea.

[0106] During the period of the CRS construction in the injector well (06), the gases (07) from the SPU processes must be being injected.

[0107] Step 5 of the method establishes that the CRS geometry must be performed by sonar inside and/or outside the cavern. The result of this sonar assessment will enable decision making to move on to the final step 11 (abandonment of the well) or start the sequence of steps again from step 2 of the method.

[0108] At the end of the CRS construction, the injection of water (15) begins in the injector well (06), which can be the brine found in the CRS (13), thus promoting the beginning of the replacement process of the brine in the CRS. Specifically, this process will occur discontinuously or in steps, to be illustrated below. Meanwhile, gases (11), preferably CO2, from the SPU processes are injected into the CRS. At the end of the water injection period into the reservoir through the injector well (06), which can last from 2 to 24 months, depending on the characteristics of the reservoir, it is completed the first cycle of the WAG recovery method, which is integrated with CRS.

[0109] It is worth mentioning that inside the CRS there must be two pipes (16 and 17) (rigid or flexible), mentioned in step 8, one positioned next to the top of the CRS (16) for CO2 inlet/outlet, and another next to the bottom of the CRS (17), for brine inlet/outlet (FIG. 1).

[0110] The two pipes (16 and 17) must have a smaller diameter in relation to the last casing settled in the access well to the saline rock cavern, in the range of 10 to 50% smaller and must be operated alternately or simultaneously, replacing the brine in the CRS by CO2 discontinuously or in steps.

[0111] Therefore, the replacement of the brine in the CRS by CO2 must occur simultaneously with the WAG-type oil recovery method. And the WAG-type oil recovery method occurs concurrently with CO2 Capture, Utilization and Storage (CCUS) in the CRS.

[0112] And the brine emptying or CO2 filling periods in the CRS are from 2 to 24 months.

[0113] Alternatively (FIG. 2), in the case of the presence of underwater separation equipment (oil-gas-water) (18), the oil is drained (19) to the SPU (4) and the gases, preferably CO2, and the water, are drained (20) to the CRS.

[0114] In order to present the construction processes of the CRS and the step-by-step replacement of the brine in the CRS by the CO2 of the present invention, FIG. 3 outlines the volumes of brine and CO2 present in the CRS over the time, which, depending on the dimensions of the CRS and reservoir characteristics for the WAG process, the time for each step can range from 2 to 24 months.

[0115] The time interval A-B represents the construction period of the CRS, so the volume of brine present in the CRS (dashed line) increases until reaching the final volume of the CRS, while the volume of CO2 in the CRS (solid line) remains almost zero (there is only the volume that protects the roof of the CRS against the dilution of the casing shoe base), because during this period CO2 is being injected into the reservoir.

[0116] Once the construction of the CRS is completed (time B), the injection of CO2 into the reservoir through the injector well can be interrupted and the injection of water (brine) from the CRS into the reservoir through the injector well can be started.

[0117] The time interval B-C represents the brine injection period in the injector well, so the volume of brine present in the CRS decreases (dashed line), while the volume of CO2 in the CRS increases (solid line). This happens because all the CO2 leaving the SPU process plant, which would conventionally be discarded in the environment, can now be drained to the CRS and, thus, facilitating the exit of the brine from the CRS (piston effect) to the injector well and yet promoting the Dewatering process in the CRS. In the case of a subsea CO2/hydrocarbon separator is present, the CO2 from a hydrocarbon producing well can be directly drained to the CRS without going through the SPU. It is worth mentioning that at time C the first WAG cycle in the reservoir is completed.

[0118] The time interval C-D represents the CO2 injection period in the injector well, so the volume of brine present in the CRS remains constant (dashed line), while the volume of CO2 in the CRS increases, but at a lower rate (lower slope of the straight), since part of the CO2 (generated in the SPU or coming from the well) goes to the injector well and part remains in the CRS (continuous line).

[0119] The advanced oil recovery process using the WAG method, integrated with CO2 storage through a CRS, occurs cyclically until time “Z” (FIG. 3). Therefore, time interval D-E is the repetition of time interval B-C and time interval E-F is the repetition of the time interval C-D. Such time intervals are repeated cyclically until the CRS is full of CO2 (21), time “Z”, from then on, the CRS is abandoned through the execution of cement plugs for permanent abandonment of the access well to the CRS, thus completing the storage of CO2 in a CRS.

[0120] That is, while the volume of brine in the CRS decreases with time or cycles, the volume of CO2 grows, thus enabling the advanced recovery of oil by the EOR-WAG process (brine-CO2) simultaneously and integrated with the capture, utilization and storage of CO2 through the offshore CRS.

[0121] The time “Z” (FIG. 3) that it will take for the CRS to be filled with CO2 depends on the flow rates (brine and CO2) used in the WAG process, the number and time of each WAG cycle, as well as the dimensions of the CRS and its maximum allowable pressure. If production in the oil field continues in the same way, a new CRS is built to operate under the same conditions described above.

[0122] It is worth mentioning that in the case of an offshore CRS, given the intrinsic characteristics of the saline rock, the CO2 stored in the CRS can be in a liquid state, which allows a significant volume to be stored in relation to it in the gaseous state.

[0123] It is worth mentioning that it is also possible to drain the water (11) from the SPU (04) hydrocarbon separation processes to the CRS (10), as shown in FIG. 4, which shows the CRS (10) in a time when about half of the geometric volume of the CRS has CO2 (12) and the other half has brine (13).

[0124] This condition is interesting in a hydrocarbon production condition (03) with a high amount of Basic Sediment and Water (BSW). Thus, instead of the brine volume in the CRS remaining constant during the CO2 injection period (sections C-D, E-F, dashed line, in FIG. 3) it has a slight increase, greater slope of the straight, (sections C-D, E-F, line dashed, in FIG. 5).

[0125] The description that has been made so far of the present method should be considered only as a possible embodiment, and any particular features should be understood as something that has been described to facilitate understanding. Thus, such features cannot be considered as limiting of the invention, which is limited only to the scope of the accompanying claims.