Technical field

The present invention relates to the field of enhanced oil recovery (EOR), and more specifically to an installation for enhanced oil recovery. The invention also relates to a method for EOR.

Technical background

Hydrocarbons (such as crude oil) are extracted from a subterranean formation (or reservoir) by means of one or more production wells drilled in the reservoir. Before production begins, the formation, which is a porous medium, is saturated with hydrocarbons. The initial recovery of hydrocarbons is generally carried out by techniques of “primary recovery”, in which only the natural forces present in the reservoir are relied upon. In this primary recovery, only part of the hydrocarbons is ejected from the pores by the pressure of the formation. Typically, once the natural forces are exhausted and primary recovery is completed, there is still a large volume of hydrocarbons left in the reservoir. This phenomenon has led to the development of EOR techniques.

EOR projects often involve use of Water Alternating Gas (WAG) injection, a cyclic procedure of alternating the injection of water and gas, to improve the sweep efficiency of the recovery process. Water and gas are delivered at high pressures, the topside pressure of water being higher (for example, 19 MPaG) than that of gas (for example, 12 MPaG). Both water and gas injection lines therefore cannot be connected at the same time, as when switching from water injection to gas injection, gas can run back into the water injection system. To overcome this problem, a complex injection line is installed on each injection well to ensure that the fluids can crossflow, comprising at least one block and bleed valve system. An example of such a system is provided in FIG. 1 and FIG. 2. The system is often located below deck, with every switchover involving its removal and replacement, which also leads to a number of operational and safety challenges. For a wellhead area with a number of injection wells, the overall number of valves, control systems, and sometimes even whole platforms that are replaced result in costly and time consuming setup, operation and maintenance. Document WO 2015/197422 A2 provides a WAG apparatus and associated method for operation, the apparatus being located or locatable in a wellbore that extends from a surface to a subsurface location, the apparatus comprising at least one first channel configured to convey a liquid downhole from the surface; at least one second channel configured to convey a gas downhole from the surface; and wherein the apparatus comprises one or more downhole valve systems for switching the downhole apparatus between alternatingly providing the liquid at the downhole location and gas at the downhole location.

Document US 2018 087361 A1 provides a method of treating a subsurface formation with low permeability to increase total oil production from the formation. The method may include providing a first fluid into two or more fractures emanating from a first wellbore. The first fluid may be provided at a pressure below a fracture pressure of the formation. The first fluid may increase a pressure in zones substantially surrounding a first fracture and a second fracture emanating from the first wellbore. A zone having a lower pressure may be located between these zones. Additional fractures may be formed from a second wellbore in the formation with at least one of the additional fractures emanating from the second wellbore and propagating into the lower pressure zone. Hydrocarbons may be produced from the second wellbore. A second fluid may be provided into the first wellbore before and/or after producing the hydrocarbons from the second wellbore.

Document EP 2 990 595 A2 provides various embodiments of computer- implemented methods, computing systems, and program products for analyzing a flood operation on a hydrocarbon reservoir.

Within this context, there is still a need to provide an installation for enhanced oil recovery in a simplified and cost-effective manner.

Summary of the invention

It is therefore the object of this invention to provide an installation for enhanced oil recovery, the installation comprising: a gas line connected to a source of gas, a liquid line connected to a source of liquid, a topside switchover system comprising a plurality of valves and having a gas inlet and a liquid inlet, the gas line being connected to the gas inlet and the liquid line being connected to the liquid inlet, at least one manifold connected to an outlet of the topside switchover system, said manifold being connected to a plurality of injection lines, each injection line being connected to an inlet of a respective injection well, wherein the topside switchover system can be configured such that liquid or gas is injected into each injection well.

According to some embodiments, the topside switchover system is the only switchover system of the installation.

According to some embodiments, the installation comprises a single manifold, so that only liquid or only gas is fed to all of the injection wells.

According to some embodiments, the topside switchover system comprises only one block and bleed valve system.

According to some embodiments, the at least one manifold comprises a first manifold connected to a first group of injection lines feeding a first group of injection wells, and a second manifold connected to a second group of injection lines feeding a second group of injection wells different from the first group of injection wells.

According to some embodiments, the topside switchover system comprises a block and bleed valve system connected to the gas line and another block and bleed valve system connected to the liquid line; wherein each of these two block and bleed valve systems is connected to the first manifold and to the second manifold.

According to some embodiments, the topside switchover system has a first configuration wherein liquid is provided to the first group of injection lines via the first manifold, and gas is provided to the second group of injection lines via the second manifold; and a second configuration wherein gas is provided to the first group of injection lines via the first manifold, and liquid is provided to the second group of injection lines via the second manifold.

According to some embodiments, the injection wells are arranged as one or more rows in a subterranean formation, and the injection wells of the first group alternate with the injection wells of the second group within each row.

According to some embodiments, the first group of injection wells are arranged as a first row and the second group of injection wells are arranged as a second row distinct from the first row, in a subterranean formation.

According to some embodiments, the topside switchover system comprises at least one spool to connect the gas line to an outlet of the topside switchover system, and/or at least one spool to connect the liquid line to an outlet of the topside switchover system.

According to some embodiments, the topside switchover system comprises a gas security system configured to perform a nitrogen purge along the gas line. According to some embodiments, the installation comprises one or more additive lines configured for feeding one or more additives from one or more additive reservoirs to the liquid line.

According to some embodiments, the source of gas is a source of CO2 and/or the source of liquid is a source of water.

According to some embodiments, the gas line and the liquid line are at a pressure lying from 10 MPa to 40 MPa.

According to some embodiments, the gas line is at a first pressure and the liquid line is at a second pressure, the first pressure being higher than the second pressure.

According to some embodiments, the installation further comprises a liquid derivation line connected to the liquid line and equipped with a pump configured to raise the pressure of the liquid from the second pressure to approximately the first pressure.

Another object of the invention is a method for enhanced oil recovery using an installation according to any of the previously described embodiments, the method comprising: injecting gas and/or liquid to the injection wells via the at least one manifold.

According to some embodiments, the method is a method of WAG injection.

According to some embodiments, only gas is simultaneously injected into all injection wells, or only liquid is simultaneously injected into all injection wells.

According to some embodiments, liquid is injected into some of the injection wells, while gas is simultaneously injected into the other injection wells.

According to some embodiments, the method comprises a step of switching from liquid injection to gas injection into at least some of the injection wells, said step comprising: closing the liquid inlet, optionally, draining liquid from at least part of the installation, disconnecting the liquid inlet from the outlet and connecting the gas inlet to the outlet, opening the gas inlet.

According to some embodiments, the method comprises a step of switching from gas injection to liquid injection into at least some of the injection wells, said step comprising: closing the gas inlet, disconnecting the gas inlet from the outlet and connecting the liquid inlet to the outlet, opening the liquid inlet.

According to some embodiments, after the step of switching from gas injection to liquid injection, the method comprises a transitory step of injecting liquid into injection wells at a first pressure, followed by a step of injecting liquid into injection wells at a second pressure lower than the first pressure.

According to some embodiments, disconnecting one of the gas inlet and liquid inlet from the outlet and connecting the other of the gas inlet and liquid inlet to the outlet is carried out by removing a spool and installing another spool.

The present invention makes it possible to address the need mentioned above. In particular, the invention provides an installation for EOR which is simplified and cost-effective.

This is achieved by providing a gas line connected to a source of gas, a liquid line connected to a source of liquid, a topside switchover system comprising a plurality of valves and having a gas inlet and a liquid inlet, the gas line being connected to the gas inlet and the liquid line being connected to the liquid inlet, at least one manifold connected to an outlet of the topside switchover system, said manifold being connected to a plurality of injection lines, each injection line being connected to an inlet of a respective injection well, wherein the topside switchover system can be configured such that liquid or gas is injected into each injection well.

Given that the switchover system is a topside system and that the manifold is connected to a plurality of injection lines, the number of valve systems per group of injection wells is significantly reduced. In other words, instead of applying a separate valve system to each individual well, one valve system can be applied to an entire selection of wells, for example, all the wellheads of a platform (whole wellhead platform (WHP) switchover).

Advantageously and according to some embodiments, the installation may alternatively comprise a first manifold connected to a first group of injection lines feeding a first group of injection wells, and a second manifold connected to a second group of injection lines feeding a second group of injection wells different from the first group of injection wells, enabling a whole pattern switchover where one group of injection lines may receive water while the other group of injection lines receives gas, the different groups therefore receiving different desired treatments simultaneously. Brief description of the drawings

Non-limiting examples will now be described in reference to the accompanying drawings, where:

FIG. 1 shows an illustration of a typical system for surface WAG switchover according to the prior art.

FIG. 2 shows a schematic illustration of a typical system for surface WAG switchover according to the prior art.

FIG. 3 shows a schematic illustration of the installation according to an embodiment.

FIG. 4 shows a schematic illustration of the installation according to an embodiment.

FIG. 5 shows a schematic illustration of the installation according to an embodiment.

FIG. 6 shows a hydrocarbon foot map for a model of a group of wells.

FIG. 7 shows gas injection rate and gas production rate as a function of time according to a number of embodiments.

FIG. 8 shows gas injection total and oil production total as a function of time according to a number of embodiments.

FIG. 9 shows CO2 injection rate and gas production rate as a function of time according to a number of embodiments.

FIG. 10 shows CO2 injection total and oil production total as a function of time according to a number of embodiments.

In each of FIG 7-10, the top part of the graph shows a projected gas injection rate (Y-axis, in Mscf/day) depending on the date (X-axis); and the bottom part of the graph shows a projected gas production rate (Y-axis, in Mscf/day) depending on the date (X-axis). FIG 9 and FIG 10 provide examples for injected CO2 specifically.

Detailed description

The invention will now be described in more detail without limitation in the following description.

The installation of the present invention comprises a gas line connected to a source of gas, a liquid line connected to a source of liquid, a topside switchover system comprising a plurality of valves and having a gas inlet and a liquid inlet, the gas line being connected to the gas inlet and the liquid line being connected to the liquid inlet, at least one manifold connected to an outlet of the topside switchover system, said manifold being connected to a plurality of injection lines, each injection line being connected to an inlet of a respective injection well, wherein the topside switchover system can be configured such that liquid or gas is injected into each injection well.

The term “topside" means above water for an off-shore installation and above ground for an on-shore installation.

The term “manifold" refers to a pipe or chamber branching into several openings.

The term “injection welf’ refers to an injection well of a reservoir of a subterranean formation or subterranean reservoir containing, for example, hydrocarbons. The well may be of a length lying from 1 km to 10 km, such as, for example, from 1 km to 5 km; or from 5 km to 10 km; or from 3 km to 7 km. The well may of a width lying, for example, from 50 m to 550 m, for example from 50 m to 150 m; or from 150 m to 250 m; or from 250 m to 350 m; or from 350 m to 450 m; or from 450 m to 550 m. The wells are arranged so that liquid or gas provided into the injection well causes hydrocarbons to migrate towards nearby production wells for hydrocarbon extraction. Depending on the case, it may take a number of years for hydrocarbons to migrate from injection well to production well, for example, from 1 to 50 years, or from 20 to 40 years, such as for example 30 years.

Making reference by way of illustration to FIG. 3, the injection wells may be arranged as one or more rows 231 , 232 in a subterranean formation. The term “row" refers to the positioning of the wells in a subterranean reservoir, meaning that more than two injection wells are substantially aligned in a horizontal direction across an area of the subterranean reservoir.

In particular, the injection wells may comprise a proximal portion which is substantially vertical and a distal portion which is substantially horizontal within the reservoir. FIG. 3 schematically shows the distal portions of the wells, in an example, when viewed from the top. The distal portions of the injection wells may be substantially parallel and arranged in or more rows 231 , 232. The respective distalmost points of the injection wells within a row may be substantially aligned.

Other wells such as, for example, production wells and/or different injection wells and/or inactive wells may also be present between the injection wells. The proximity of the wells belonging to each row may vary from 90 m to 600 m. The proximity of the injection and production wells belonging to each row may, for example, vary from 150 m to 300 m. For instance, production wells may be disposed in the rows of injection wells. Preferably, injection wells 201 , 202, 203, 204, 205, 206, 207, 208, 209 and production wells 221 , 222, 223, 224, 225, 226, 227, 228, 229 alternate within each row 231 , 232, as illustrated in the example displayed in FIG. 3. The topside switchover system may be the only switchover system of the installation. In particular, most preferably, individual switchover systems allowing switching between liquid and gas feeding on each injection well are not present in the installation.

Liquid or gas may be injected to the injection wells via the at least one manifold. The method of injection may be one of WAG injection.

The installation may also comprise at least one spool to connect the gas line to an outlet of the topside switchover system, and/or at least one spool to connect the liquid line to an outlet of the topside switchover system. The topside switchover system may comprise a gas security system configured to perform a nitrogen purge along the gas line. The security system may at each switchover flush the manifold with nitrogen before it is opened for injection so as to minimize the release of hydrocarbons into the atmosphere. The installation may comprise one or more additive lines configured for feeding one or more additives from one or more additive reservoirs to the liquid line. Such additives may, for example, include biocide and/or glycol (such as, for example, tri-ethylene glycol (TEG)). The source of gas may be, for example, a source of CO2. Additionally or alternatively, the source of gas may be a methane source of gas, or a mix of methane and heavier gases. The source of liquid may be, for example, a source of water. The gas line and the liquid line may be at a pressure, for example, lying from 10 MPa to 40 MPa. The gas line may be at a first pressure and the liquid line may be at a second pressure, the first pressure being higher than the second pressure, for example, the liquid may be at a pressure lying from 10 MPa to 20 MPa, such as 15 MPa and the gas may be at a pressure lying from 15 MPa to 40 MPa, such as 25 MPa.

All injection lines, whether injecting liquid or gas, may for example be equipped with individual valves on each well to optionally stop injection into any particular well.

According to some embodiments, the method of injection may comprise a step of switching from liquid injection to gas injection for at least some of the injection wells, or vice versa.

The step of switching from liquid injection to gas injection may involve closing the liquid inlet. Optionally, the step may involve draining liquid from at least part of the installation. Upon closing the liquid inlet and/or draining the liquid, the step may involve disconnecting the liquid inlet from the outlet before connecting the gas inlet to the outlet. This may, for example, be carried out by removing a spool and installing another spool. The step may then include opening the gas inlet. The step of switching from gas injection to liquid injection may involve closing the gas inlet. The step may involve disconnecting the gas inlet from the outlet before connecting the liquid inlet to the outlet. This may, for example, be carried out by removing a spool and installing another spool. The step may then include opening the liquid inlet.

In the case of switching from gas injection to liquid injection, once the step of switching has been completed, the method may comprise a transitory step of injecting liquid into injection wells at a first pressure, followed by a step of injecting liquid into injection wells at a second pressure lower than the first pressure. To this end, the installation may further comprise a liquid derivation line connected to the liquid line and equipped with a pump configured to raise the pressure of the liquid from the second pressure to the first pressure for the transitory step. The first pressure in this transitory step may be approximately equal to the above first pressure of the gas line. The transitory step may act as a security step to fill the injection wells with liquid and hence prevent gas from flowing back in the system and subsequently cause a large gas release.

Whole Pattern Switchover

Referring to FIG. 4, the installation of the present invention may be suitable for performing a whole pattern switchover. A method of use of the installation may involve injecting liquid into some injection wells while simultaneously injecting gas into other injection wells. A gas line 301 is connected to a gas source while a liquid line 302 is connected to a liquid source. A first manifold 305 and a second manifold 306 are connected to an outlet of the topside switchover system at one end. The topside switchover system may comprise only one block and bleed valve system 304. Each of the gas and liquid lines 301 , 302 may be connected to a block and bleed valve system (for example, a double block and bleed valve system) or another arrangement of valves of the topside switchover system 303 via a gas inlet and a liquid inlet, each of the block and bleed valve systems 304 or arrangement of valves being connected to the first manifold and to the second manifold. This enables gas to be bled from the installation and ensures isolation between the high pressure gas and a water injection manifold.

In a first configuration of the installation, the method may for example include injecting gas from the gas source to the first manifold 305, from the first manifold 305 to a first group of injection lines 307 connected to the first manifold 305 and feeding a first group of injection wells 308 at the other end of the first group of injection lines 307, while simultaneously injecting liquid from the liquid source to the second manifold 306, from the second manifold 306 to a second group of injection lines 309 connected to the second manifold and feeding a second group of injection wells 310 (being different to the first group of injection wells 308) at the other end of the injection lines.

In a second configuration, the method may comprise injecting liquid to the first manifold 305, from the first manifold 305 to the first group of injection lines 307 feeding the first group of injection wells 308 while gas is simultaneously being injected from the second manifold 306 to the second group of injection lines 309 feeding the second group of injection wells 310.

The installation may switch from the first configuration to the second configuration or vice versa by acting on the topside switchover system 303.

Preferably, the injection wells 308, 310 may be arranged as one or more rows in a subterranean formation, as described above.

The rows may comprise the first group 308 and the second group 310 of injection wells. The first group 308 / second group 310 of injection wells may comprise 4 to 20 wells per group, for example 12 to 16 wells per group The first group of injection wells 308 and the second group of injection wells 310 may be arranged within each row to form different patterns. The pattern formed in each row may vary from row to row.

The injection wells of the first group and second group may alternate within each row.

The first group of injection wells 308 may, for example, consist of every second injection well in a row, the second group of injection wells 310 comprising the remaining wells.

Alternatively, the first group of injection wells 308 may, for example, repeat for every third injection well in a row, the two injection wells in between each third injection well being injection wells of the second group of injection wells 310. Alternatively, the first group of injection wells 308 may, for example, repeat for every fourth injection well in a row, the three injection wells in between each fourth injection well being injection wells of the second group of injection wells 310. The first group pf injection wells 308 may, for example, repeat for every n ^th injection well in a row, the remaining injection wells between each n ^th injection well being injection wells of the second group of injection wells 310. Additionally and/or alternatively, the second group pf injection wells 310 may, for example, repeat for every n ^th injection well in a row, the remaining injection wells between each n ^th injection well being injection wells of the first group of injection wells 308.

Additionally and/or alternatively, the first group of injection wells 308 may, for example, consist of a pattern comprising at least two consecutive injection wells followed by at least one injection well from the second group of injection wells 310. Additionally and/or alternatively, the second group of injection wells 310 may, for example, consist of at least two consecutive injection wells followed by at least one injection well from the first group of injection wells 308.

Alternatively, the first group of injection wells 308 may be arranged as a first row and the second group of injection wells 310 may be arranged as a second row distinct from the first row, in a subterranean formation. Additionally and/or alternatively, the first group of injection wells 308 may, for example, be arranged in a first set of multiple rows and the second group of injection wells 310 may be arranged in a second set of multiple rows distinct from the first set, in a subterranean formation.

Making reference to FIG. 3 for example, the injections well 201 , 203, 205, etc. may thus belong to the first group 308 within row 231 , while the injection wells 202, 204, etc. may belong to the second group 310 within row 231 - or vice versa (different group at each successive injection well); or the injection wells 201 , 202 may belong to the first group 308 within row 231 , while the injection wells 203, 204, may belong to the second group 310 within row 231 , etc. - or vice versa (different group every two successive injection wells). Alternatively, all injections wells 201 , 202, 203, 204, 205 in the same row 231 may belong to the first group 308 while all injections wells 206, 207, 208, 209 in the next row 232 may belong to the first group 310 - or vice versa.

Whole Wellhead Platform Switchover

Referring to FIG. 5, the installation of the present invention may comprise a single manifold 411 connected to all injection wells 413, so that only liquid or only gas is fed to all of the injection wells 413. For gas injection, a gas line 401 is connected to a gas source. Meanwhile for liquid injection, a liquid line 402 is connected to a liquid source. Each line may be connected to a block and bleed valve system 404 (for example a double block and bleed valve system) or another arrangement of valves of the topside switchover system 403 via a gas inlet and a liquid inlet. In a first configuration, the manifold 411 , connected to an outlet of the topside switchover system at one end, simultaneously injects liquid to a group of injection wells 413 via all displayed injection lines 412. In a second configuration, the manifold 411 simultaneously injects gas to the group of injection wells 413 via all displayed injection lines. The installation may switch from the first configuration to the second configuration or vice versa by acting on the topside switchover system 403. Experimental Results

FIG. 6 shows a hydrocarbon foot map of a compositional dynamic simulation model representing tight carbonate rock with a thin undersaturated medium heavy crude oil. In this example, the area is developed with long horizontal wells drilled in two patterns, alternating between injection wells (e.g. INJ 1 ) and production wells (e.g. PROD 1 ). A standard WAG process involves development via alternating injection wells with gas and water injection and then providing individual well treatment for optimization purposes. A comparison was made between this approach and embodiments of the present invention including whole pattern switchover and whole wellhead platform switchover.

For each of FIG. 7 to 10, plot lines 701 , 711 , 801 , 811 , 901 , 911 , 1101 , 1111 represent simulated injection wells running according to an example of whole wellhead platform switchover, i.e. all injection wells running on either gas or water at the same time. Plot lines 702, 712, 802, 812, 902, 912, 1102, 1112 represent simulated injection wells running according to an example of whole pattern switchover (i.e. some injection wells running on water while other injection wells simultaneously run on gas), with all injection wells to the left of FIG. 6 running with gas injection, and all injection wells to the right of FIG. 6 running with liquid injection. Plot lines 703, 713, 803, 813, 903, 913, 1103, 1113 represent simulated injection wells running according to another example of whole pattern switchover, with every second injection well running on gas injection, and remaining wells simultaneously running on water injection. This particular embodiment uses the invention to form a pattern that is one of standard WAG implementation. Plot lines 704, 714, 804, 814, 904, 914, 1104, 1114 represent a waterflood case with no gas injection. Switching from gas to liquid may occur, for example, between every 3 to 12 months, such as every 6 months.

FIG. 7 shows a top graph displaying gas injection rate (Mscf/day) over time and a bottom graph displaying gas production rate (Mscf/day) over time. It can be seen that despite varying gas injection patterns, all gas production patterns 711 , 712 and 713 show a general trend in increased production rate for increased injection rate over time.

FIG. 8 shows a top graph displaying gas injection total (Mscf) over time and a bottom graph displaying total oil production (stb) over time. The cumulative oil potential for the same amount of gas injection using different patterns, such as those of plots 801 and 802, remains the same as that obtained by using the invention to implement a standard WAG pattern 803.

FIG. 9 and FIG. 10 refer to examples of embodiments wherein the simulated model was tested for carbon capture storage (CCS) purposes for EOR. In these figures, the injected fluid is CO2. In FIG. 9 it can be seen that for each pattern 901 , 902, 903 tested, results for gas production rate remain uniform. The same observation can be made regarding FIG. 10 for total oil production.

In such an example, after injection, CO2 may propagate into the production wells. In such a scenario, the produced gas may be reinjected into the reservoir to avoid contamination with other infrastructure.