TECHNIQUES FOR IMPROVED OIL RECOVERY

Abstract

An improved oil recovery module may include a floating platform, one or more improved oil recovery pods disposed on the floating platform, and one or more injection assemblies fluidly connected to the one or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads.

Description

BACKGROUND

Initial oil production from a subsurface reservoir is typically motivated by natural reservoir energy in the form of formation pressure followed by the expansion of dissolved gas, active aquifer flow, or some combination of these and/or other drivers as oil is gradually extracted. After some amount of production, however, natural reservoir energy falls to the point at which it is no longer able to overcome the hydrostatic pressure and frictional losses within both the production well and the flow lines that connect it to a production facility. Some fraction of the Original Oil in Place (OOIP) consequently remains unrecovered, or trapped, in the reservoir.

As oil production knowledge and technology have advanced, artificial means of Improved Oil Recovery (IOR) have been developed. So called secondary recovery typically refers to techniques that contribute energy to the reservoir such that oil is displaced towards production wells. Examples include water and gas injection. So called tertiary recovery, often referred to as an Enhanced Oil Recovery (EOR) subset of IOR, typically refers to techniques that alter the physical properties of oil and/or the injected medium in order to improve fluid flow through the reservoir formation. Examples include miscible gas (e.g., carbon dioxide, nitrogen, LPG), chemical treatment (e.g., polymers, alkali surfactants) microbiological (MEOR), and thermal (e.g., steam, hot water) injection.

Despite the advancement of IOR technology and experience, it remains difficult to predict the optimum application throughout the production life of a given reservoir and the resulting improvement in oil recovery at the initial planning stage. Justification of offshore IOR application is further challenged by the expense of the required facilities and the support thereof. Field operators may be hesitant to incorporate this capability into offshore production facilities and may consequently accept a limited Recovery Factor (RF) relative to the OOIP. There is a need to both improve the RF and develop “stranded assets” (i.e., reservoirs that are not economical to develop with traditional methods) by providing IOR systems with greater flexibility and applicability that may allow field operators to apply such systems with more certainty of success to multiple reservoirs sequentially or in parallel and amortize their cost accordingly.

SUMMARY OF THE DISCLOSURE

In one aspect, this disclosure relates to an improved oil recovery module including a floating platform, one or more improved oil recovery pods disposed on the floating platform, and one or more injection assemblies fluidly connected to the one or more improved oil recovery pods and configured to he fluidly connected to one or more injection wellheads.

In another aspect, this disclosure relates to an offshore oil production system including an oil production facility and one or more improved oil recovery modules. An improved oil recovery may include one or more improved oil recovery pods disposed on the floating platform, and one or more injection assemblies fluidly connected to the one or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads.

In another aspect, this disclosure relates to a method of offshore oil recovery using an improved oil recovery module. An improved oil recovery may include one or more improved oil recovery pods disposed on the floating platform, and one or more injection assemblies fluidly connected to the one or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads. The method may include locating an improved oil recovery module proximate a subsea oil field, connecting the one or more injection assemblies to one or more injection wellheads of the subsea oil field, and performing an oil recovery method using the improved oil recovery module.

Other aspects and advantages will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic of an improved oil recovery module in accordance with the present disclosure.

FIG. 2 is a schematic of a subsea field in accordance with the present disclosure.

FIG. 3 is a schematic of an improved oil recovery module in accordance with the present disclosure.

FIG. 4 is a schematic of an improved oil recovery module in accordance with the present disclosure.

FIGS. 5a-5b are schematics of subsea fields in accordance with the present disclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the claimed subject matter, However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.

In one aspect, the present disclosure relates to an improved oil recovery (IOR) module for offshore oil production. FIG. 1 illustrates an IOR module 100. The IOR module 100 includes a floating platform 102, one or more IOR pods 108a-108d, and an injection assembly 120. The IOR module may further include a connection assembly 104. The connection assembly 104 may connect the IOR pods 108a-108d to an injection wellhead 106 of a subsea oil field (not shown). The floating platform 102 may be a semi-submersible, a mono-hull, or any other type of floating structure known in the art.

The IOR module 100 may include one or more IOR pods 108a-108d, The IOR pods 108a-108d may be disposed on the floating platform 102. Each IOR pod 108a-108d may include equipment necessary to perform one or more IOR methods. The IOR methods may include water injection, steam injection, vapor injection, gas injection, water alternating gas (WAG) injection, chemically treated water injection, or any other IOR method known in the art.

Water injection, for example, may include filtering and treating seawater, then injecting the water into a wellhead. Water injection may further comprise heating the water. Steam injection, for example, may include filtering and treating seawater, then converting the seawater to steam, and injecting it into a wellhead. Gas injection, for example, may include injecting a gas which has previously been removed from a well back into an injection wellhead. Gas injection may alternatively or additionally include injecting a miscible gas from another source into a wellhead. WAG injection may include injecting water and gas into a wellhead in an alternating pattern. WAG injection may be performed by a single IOR pod, or it may be performed by a first IOR pod which performs water injection and a second IOR pod which performs gas injection. In some embodiment, WAG injection may be performed by two IOR modules 100 that alternate, using the same connection assembly 104 to serve the same injection wellhead 106. Chemically treated water injection, for example, may include filtering and treating seawater, chemically treating the water, and injecting the water into a wellhead. The chemicals for chemically treated water injection may be stored on board the floating platform 102.

The floating platform 102 may be designed such that a desired combination of IOR pods 108a-108d may be disposed on the floating platform 102. The IOR pods 108a-108d may be removably attached to the floating platform 102, such that IOR pods 108a-108d may be exchanged prior to or between uses of a floating platform 102, allowing a single floating platform 102 to be configured to have different combinations of IOR pods 108a-108d for different operations. IOR pods 108a-108d may be lifted onto and off of the floating platform 102 using a crane, or any other suitable equipment known in the art. The floating platform 102 may comprise a means to lock the IOR pods 108a-108d in position after the desired IOR pods 108a-108d have been disposed on the floating platform 102. In one or more embodiments, the IOR pods 108a-108d may be permanently attached to the floating platform 102.

The IOR module 100 may include one or more storage tanks 110a, 110b which may contain chemicals or other materials necessary to perform an IOR method performed by one of the IOR pods 108a-108d. The storage tanks 110a, 110b may be disposed on the floating platform 102. In some embodiments, the storage tanks 110a, 110b may be an integral part of the floating platform 102. The storage tanks 110a, 110b may each be connected to one or more appropriate IOR pods 108a-108d.

The IOR module 100 may include one or more seawater intake assemblies 112. A seawater intake assembly 112 may include a sweater intake module 114, a hose 116, and a hose reel 118. The seawater intake module 114 may or may not include one or more filters. The hose 116 may he connected to the IOR pods 108a-108d, such that the hose 116 may deliver seawater to the IOR pods 108a-108d for use in IOR processes, The hose reel 118 may be disposed on the floating platform 102 and may allow the seawater intake module 114 to be raised or lowered to a desired depth. The seawater intake assembly 112 may he capable of taking in seawater at a variable flow rate based on the requirements of the IOR processes being performed at a particular time.

The IOR pods 108a-108d may be connected in a single or multi-phase manner to an injection wellhead 106. Each of the IOR pods 108a-108d may be connectable to or connected to the injection wellhead 106. In some embodiments, the TOR pods 108a-108d may be connectable to or connected to two or more injection wellheads 106. Each of the one or more IOR pods 108a-108d may be connectable or connected to each injection wellhead 106.

The IOR module may include an injection assembly 120. The injection assembly 120 may be disposed on the floating platform 102. The injection assembly 120 may be fluidly connectable or connected to the IOR pods 108a-108d. The injection assembly 120 may be configured to be fluidly connected to one or more injection wellheads 106.

The injection assembly 120 may comprise one or more inlets and one or more outlets. The outlet of the injection assembly 120 may be fluidly connected to one or more injection wellheads 106. Each inlet of the connection assembly 120 may be connected to an IOR pod 108a-108d, The injection assembly 120 may comprise one or more valves such that the injection assembly 120 may be configured to place each of the IOR pods 108a-108d in fluid communication with the outlet of the injection assembly 120, while the other IOR pods 108a-108d are prevented from fluidly communicating with the outlet of the injection assembly 120. In other embodiments, the IOR pods may be connectable to the injection assembly 120 in a plug-and-play manner, such that the IOR pods are only fluidly connected to the injection assembly when their use is desired.

In some embodiments, the injection assembly 120 may comprise a single inlet and a single outlet. The injection assembly 120 may be capable of being configured such that each of the IOR pods 108a-108d is connected to the inlet of the injection assembly. The injection assembly 120 may be movable, such as along a length of the vessel, such that the inlet of the injection assembly 120 is connected to the desired IOR pod 108a-108d. Alternatively, piping, flexible piping, or other connections may be provided to operatively connect the IOR pods to the injection assembly.

IOR pods 108a-108d performing different IOR methods may output fluids having varied densities, phases, and flow rates. Therefore, the injection assembly 120 may include the necessary equipment to provide the flexibility to allow the flow of fluids having such varied properties. For example, inlet lines may be provided with multiple control valves having varied trim sizes so as to operate over a range of flow rates as needed. Similarly, pumps, compressors, and other equipment may be provided so as to accommodate the varied outputs from the IOR pods. The injection assembly 120 may control or modify a pressure, flow rate, or other pressure of a fluid which flows through the injection assembly 120. Alternatively, the pods may be provided with the appropriate equipment to regulate their output, the injection assembly simply facilitating the connection to the injection wellhead(s).

An IOR pod 108a-108d in fluid communication with the injection assembly 120 may flow a liquid, a vapor, or a gas through the injection assembly 120 and a connection assembly 104, described below, and thence into the injection wellhead 106. The IOR pod 108a-108d may control a flow rate, pressure, or other property of the fluid which is injected.

The outlet of the injection assembly 120 may be fluidly connected to one or more injection wellheads 106. In some embodiments, the outlet of the injection assembly 120 may be connected to the injection wellheads 106 via a connection assembly 104. The connection assembly 104 will now be described, with reference to FIG. 1, beginning at a proximal end which may attach to the injection assembly 120 and ending at a distal end which may attach to injection wellhead 106.

The connection assembly 104 may include an upper jumper 122. The proximal end of the upper jumper 122 may connected to the outlet of the injection assembly 120.

The connection assembly 104 may include an upper riser assembly 124. The upper riser assembly 124 may be attached to a distal end of the upper jumper 122. The upper riser assembly 124 may include a buoyancy can or other buoyancy means, and may be capable of supporting a riser 126 at a desired depth. The upper riser assembly 124 may be made buoyant by any means known in the art.

The connection assembly 104 may include a riser 126. A proximal end of the riser 126 may be connected to the upper riser assembly 124.

The connection assembly 104 may include a lower riser assembly 128. The lower riser assembly 128 may be connected to a distal end of the riser 126. The lower riser assembly 128 may be tethered to the seafloor by an anchor system 130. The anchor system 130 may maintain the lower riser assembly 128 and the riser 126 in a desired position.

The connection assembly 104 may include a lower jumper 132. A proximal end of the lower jumper 132 may be connected to the lower riser assembly 130. A distal end of the lower jumper 132 may be connected to the injection wellhead 106.

The IOR module 180 may include a means (not shown) for maintaining the floating platform 102 in a desired position. The means may be a mooring system with anchor lines that connect the floating platform 102 to anchors on the seafloor. The means may be an active dynamic positioning system. The dynamic positioning system may comprise a computer and one or more sensors, such as position reference sensors, motion sensors, wind sensors, and gyroscopes. The computer may command action of components of the floating platform 102 necessary to maintain the floating platform in the desired position, based on the position readings made by the one or more sensors.

As illustrated in FIG. 2, an injection wellhead 206 may be part of a subsea oil field 250. The injection wellhead 206 may be disposed on a proximal end of an injection well 252. The injection well may he constructed for the sole purpose of injection or be converted from a former production well. The subsea oil field 250 may also include a production well 254 and a production wellhead 256. When fluid is injected into the injection well 252 through the injection wellhead 206, the fluid may enter the substrate 258. The fluid may flow through the substrate 258 towards the production well 254. The fluid may push or carry any oil remaining in the substrate 258 towards the production well 254. The oil and the injected fluid may flow upwards through the production well 254 and may be accessed at the production wellhead 256. A production riser (not shown) may be attached to the production wellhead 256 to allow the oil to be brought to sea level.

FIG. 1 illustrates an embodiment of the connection assembly 104 which connects the injection pods 108a-108d to a single injection wellhead 106. However, in some embodiments, a connection assembly 104 may connect the injection pods 108a-108d of an IOR module 100 to more than one injection wellheads 106.

FIG. 3 illustrates an embodiment of a connection assembly 304, in which the connection assembly 304 connects three IOR pods 308a-308c to four injection wellheads 306. Similar to the embodiment shown in FIG. 1, the IOR pods 308a-308c are each connectable or connected to an inlet of a single injection assembly 320. An outlet of the injection assembly 320 is connected to the connection assembly 304, 100361 The connection assembly 304 may include an upper jumper 322, an upper riser assembly 324, and a riser 326, connected in sequence. The upper jumper 322, upper riser assembly 324, and riser 326 may have the same features as the elements described above, with reference to FIG. 1.

The connection assembly 304 may include a lower riser assembly 328 and one or more lower jumpers 332. The lower riser assembly 328 may be or may include a distribution manifold. The lower riser assembly 328 may be tethered to the seafloor by an anchor system (not shown). The anchor system may maintain the lower riser assembly 328 and the riser 326 in a desired position. The one or more lower jumpers 332 may be connected to the lower riser assembly 328. For example, FIG. 3 illustrates an embodiment in which four lower jumpers 332 are connected to the lower riser assembly 328. The lower riser assembly 328 may include a mechanism to maintain a desired flow rate and pressure of fluid in each of the one or more lower jumpers 332. In some embodiments, the lower riser assembly 328 may include a mechanism to maintain desired flow rates and pressures of fluid in each of the one or more lower jumpers 332 that are not equal. Each of the one or more lower jumpers 332 may be connected to an injection wellhead 306. The injection wellheads 306 may be part of a single subsea oil field (not shown).

In some embodiments, a connection assembly 304, such as the one shown in FIG.

3, may connect a single injection assembly 320 to any number of injection wellheads 306.

FIG. 4 illustrates an embodiment of a connection assembly 404, in which the connection assembly 404 connects three IOR pods 408a-408c to two injection wellheads 406.

An IOR module may include more than one injection assembly 420. Each of the IOR pods 408a-408c may be connectable or connected to an inlet of each injection assembly 420. For example, in the embodiment shown in FIG. 4 each of three IOR pods 408a-408c is connectable or connected to an inlet of two injection assemblies 420. The injection assemblies 420 may have some or all of the same properties described above with reference to the injection assembly 120 of FIG. 1. The multiple injection assemblies 420 may be controlled by a single control system. The control system may command the connection assemblies 420 such that a single IOR pod 408a-408c is in fluid communication with the outlets of all of the injection assemblies 420. The control system may command the injection assemblies 420 such that a fluid flows out of the outlet of each injection assembly 420 at a desired pressure and flow rate. The control system may command the injection assemblies 420 such that a fluid flows out of the outlet of each injection assembly 420 at different desired pressures and flow rates.

The connection assembly 404 may include more than one flow path, such that each flow path fluidly connects an outlet of an injection assembly 420 to an injection wellhead 406. Each flow path may include an upper jumper 422, an upper riser assembly 424, a riser 426, a lower riser assembly 428, and a lower jumper 432. The upper jumper 422, upper riser assembly 424, riser 426, lower riser assembly 428, and lower jumper 432 may have properties such as those described above with reference to FIG. 1. The components of multiple flow paths may or may not be identical. The components of different flow paths may have different lengths to accommodate injection wellheads 406 at different distances from the floating platform (not shown). The injection wellheads 406 may be part of a single subsea oil field (not shown).

In some embodiments, a connection assembly 404, such as the one shown in FIG. 4, may include any number of flow paths, each flow path connecting an injection assembly 420 to an injection wellhead 406. It may also be envisioned that the embodiments illustrated in FIGS. 3 and 4 may be combined, such that an IOR module may include more than one injection assembly, and at least one of the injection assemblies may be connected to a lower riser assembly which is a distribution manifold.

In some embodiments, the connection assembly may take any form that connects one or more injection assemblies to one or more injection wellheads without departing from the scope of the disclosure.

An IOR module in accordance with the present disclosure may not include equipment for oil and/or gas production. The equipment included in the IOR module may be limited to injection equipment. In this way, the IOR module may differ from equipment currently used to perform subsea IOR methods. Currently used equipment may comprise floating platforms that include both production and injection equipment. Thus, using traditional equipment, production and injection equipment may have to be brought to a subsea oil field together, and all of the equipment may have to remain at the subsea oil field until all desired IOR and production operations have been completed.

During operations at a subsea oil field, time spent performing IOR methods may comprise a small portion of the total time spent performing operations at the subsea oil field. Therefore, using traditional equipment, IOR equipment may sit idle on a floating platform for a significant portion of the time spent performing operations at a subsea oil field.

The IOR module of the present disclosure may allow IOR equipment to be brought to a subsea oil field when it is desired to perform an IOR method and taken away from the subsea oil field when the IOR method is complete or during an intermittent cessation of injection operations. The IOR module may be taken to a second subsea oil field while other operations are performed at the first subsea oil field. In this way, the IOR module may reduce the time that IOR equipment must be left idle, and may increase the productivity of the IOR equipment.

Using an IOR module in conjunction with a floating platform including production equipment may allow the weight, size, and/or cost of the floating platform including production equipment to be reduced. The floating platform including. production equipment may be able to be assembled without injection equipment.

More than one IOR modules may be used together as a system. The multiple IOR modules may be located proximate a single subsea oil field. The subsea oil field may include injection wellheads and production wellheads as described above. The IOR modules may each comprise a floating platform, one or more IOR pods, and one or more injection assemblies. The IOR modules may each further comprise a connection assembly. The floating platforms may be arranged such that the every injection wellhead of the subsea oil field may be connected to the injection assembly(ies) of an IOR module. In some embodiments, the floating platforms may be arranged such that a desired subset of the injection wellheads of the subsea oil field may be connected to the injection assembly(s) of an IOR module. The injection wellheads may be connected to the injection assemblies via the connection assemblies.

The multiple IOR modules of the system may or may not have the same configuration. For example, any combination of the IOR modules in accordance with the embodiments shown in FIGS. 1, 3, and 4 may be part of a single system. Further, a system may include IOR modules having a combination of the features of the embodiments shown in FIGS. 1, 3, and 4 may he part of a system.

A system of IOR modules may be configured for a particular injection operation at a particular subsea oil field. The number of IOR modules and the configuration of each IOR module may he informed by properties of the subsea oil field, such as the total size of the field, as well as temperatures, pressures, and other properties of the subsea formation and the oil produced.

IOR module may be configured for a particular injection operation at a particular subsea oil field. The IOR module may be used alone or as part of a system of IOR modules. The type of IOR pods included in the IOR module and the configuration of the connection assembly may be informed by properties of the subsea oil field, such as the spacing between the injection wellheads, and the amount of oil remaining in the substrate of the subsea oil field.

In another aspect, the present disclosure relates to an offshore oil production system. The offshore oil production system may include one or more IOR modules, as described above, and an oil production facility. In some embodiments, the offshore oil production system may include other facilities which may be used to perform wellbore operations.

The production facility may be used for production of one or more subsea wells, and may include at least a production platform and a production riser. The production platform may be located at sea level and the production riser may connect the production platform to one or more subsea production wellheads. Each of the production wellheads may be connected to a subsea wellbore. Each of the one or more injection wellheads may be connected to an IOR, module as described above.

The IOR module(s) may have the capability to send communications to the oil production facility and to receive communications from the oil production facility. Likewise, the oil production facility may have the capability to send communications to the IOR module(s) and to receive communications from the IOR module(s). If the system includes other facilities, the other facilities may have the capability to communicate with the TOR module(s) and the oil production facility. Communications made between the IOR module(s) and the oil production facility may be used to adjust the operation of the IOR module(s) and/or the oil production facility. The adjustments may enhance the production of oil.

The IOR module(s) and the oil production facility may include sensors which measure or sense information about their operations. The IOR module(s) and the oil production facility may communicate some or all of the information gathered by the sensors to each other. For example, the IOR module(s) and the oil production facility may measure the position of the floating platform and the oil production platform, respectively. The IOR module(s) may measure the flow rate, volume, or pressure of a material being injected into the injection wellhead. The oil production facility may measure a flow rate, volume, or pressure of oil produced from the production riser. The IOR module(s) and the oil production facility may measure vibrations in the connection assembly and the production riser, respectively. Measurements made by the TOR. module(s) and the oil production facility may be displayed to a human operator on either facility, or may be used to directly command operations of the IOR module(s) and/or the production facility.

As described above, injection wells and production wells may he part of a subsea oil field. FIGS. 5a-5b illustrate potential embodiments of a subsea oil field, in which injection wells are represented by triangles and production wells are represented by circles. With reference to FIG. 5a, two IOR modules 500 are each connected to two injection wellheads 506. Fluid may be injected from the IOR modules 500 into the injection wellheads 506. The fluid may flow through an injection well (not shown) and then into a substrate of the subsea field. The injection fluid may push or carry oil in the substrate towards a production well (not shown) disposed below a production wellhead 556, as shown by the arrows. The production wellhead 556 may be connected to a production facility 570 and the oil may be brought to sea level at the production facility 570.

With reference to FIG. 5b, a subsea oil field may contain multiple production wells and multiple injection wells. An injection wellhead 506 (shown as a triangle) may be disposed at a proximal end of each injection well, at the level of the seafloor, and a production wellhead 556 (shown as a circle) may be disposed at a proximal end of each production well, at the level of the seafloor. The production wellheads 556 may be connected by a network of subsea pipes (not shown) which may be connected to a production facility (not shown) by a single production riser (not shown).

Multiple IOR modules (not shown) may be located proximate the subsea oil field. Each IOR module may be connected to one or more injection wellheads 506. The number of IOR modules brought to the subsea oil field and the locations in which the IOR modules are located may depend on the number and spacing of injection wellheads 506 in the subsea oil field. The IOR modules may be located such that every injection wellhead 506, or a desired subset of the injection wellheads 506, may be connected to an IOR module.

FIG. 5b illustrates a subsea oil field having wells arranged in a 5-spot pattern.

Wells in a subsea oil field may be arranged in any configuration without departing from the scope of this disclosure. For example, wells may be arranged in a 7-spot pattern, a 9-spot pattern, or a 4-spot pattern. Wells may be arranged based on properties of the substrate, properties of the oil to be produced, production goals, or other considerations. An IOR module or a system of IOR modules may be designed to accommodate any arrangement of wells within a subsea oil field without departing from the scope of the disclosure.

In another aspect, the present disclosure relates to a method of offshore oil recovery. The method may be performed using the IOR module or the oil production system described above.

An operator may determine that IOR methods are needed at a subsea oil field. An operator may have access to a fleet of floating platforms, a variety of connection assemblies, and a variety of IOR pods. An IOR module or a system of IOR modules may be assembled based on the needs or predicted needs of the subsea oil field. The needs may be predicted based on production data. Considerations in assembling the IOR module or system may include the number and spacing of injection wellheads at the subsea oil field, which may be used to determine the configuration of connection assemblies included in an IOR module and the length of the upper jumpers, risers, and lower jumpers included in the IOR module and/or the number of IOR modules included in a system. The type and amount of oil remaining in a substrate of the subsea oil field may inform the type of IOR pods included in an IOR module. Properties of the subsea oil field may also be used to determine the size of the floating platforms, the injection risers, or any other components, if different sizes of components are available. The type of communication used by a production facility at the subsea oil field may inform the type of communication the IOR module or system is assembled to include.

In some embodiments, the operator may further determine particular types of IOR methods that are needed. This information may be used to determine what types of IOR pods to include in an IOR module. In some embodiments, an IOR module may be assembled to include a pre-determined set of IOR pods, which may include all available types of IOR pods or a subset thereof.

An IOR module or a system of IOR modules may be moved to a desired location proximate the subsea oil field. Each IOR module of a system may be moved to a different desired position. The desired position may be proximate the injection wellhead(s) to which it is desired to connect the IOR module. The components of the connection assembly of an IOR module may be disposed on the floating platform of the IOR module for transport to the desired location. The connection assembly may then be assembled between the floating platform and the injection wellheads. The connection assemblies may be tested.

IOR methods may then he performed using the IOR. pods of the IOR module. An operator may configure the injection assembly(s) such that an IOR pod which performs the desired IOR method is in communication with the injection wellheads via the connection assembly. The IOR pod may inject a desired material into the injection wellheads. The injection may cause oil to be produced at a production facility at the same subsea oil field. The IOR module may communicate with the production facility. An operator may determine if and when the IOR method being performed should be changed. The operator may then configure the injection assembly(s) such that an IOR pod which was previously used is not in communication with the injection wellheads via the connection assembly. The operator may then configure the injection assembly(s) such that an IOR pod which performs the new desired IOR method is in communication with the injection wellheads via the connection assembly. These steps may be used to change the IOR method being performed as many times as desired.

After one or more IOR methods are performed, an operator may determine whether or not another IOR method should be performed. An operator may determine that an IOR method is not currently desired, but will likely be desired after other wellbore operations are performed at the subsea oil field. The floating platforms may be disconnected from the connection assemblies. The connection assemblies may be left connected to the injection wellheads. The floating platforms may be removed from the subsea oil field. The floating platforms may be moved to another subsea oil field, where they may be used, or the floating platforms may be moved to a location for storage, maintenance, resupply, crew change, or testing.

After one or more wellbore operations have been performed, an operator may determine an IOR method should be performed. The floating platforms may be moved back to the subsea oil field. The floating platforms may or may not be the same floating platforms that were previously located at the subsea oil field. The floating platforms may be connected to the connection assemblies. One or more wellbore methods may be performed as described above. These steps may be used to alternate between performing IOR methods and other wellbore methods as many times as desired.

After all desired IOR methods have been performed, the floating platform may he disconnected from the connection assembly and the connection assembly may be disconnected from the injection wellhead. The connection assembly may be disassembled if necessary. The IOR module or system of IOR modules may be removed from the subsea oil field. The IOR module or system of IOR modules may be moved to another subsea oil field, where it may be used, or the IOR module or system of IOR modules may be moved to a location for storage, maintenance, or testing.

As described in the method above, various floating platforms may he brought to and removed from a subsea oil field over the course of a wellbore operation. An IOR module in accordance with the present disclosure may be understood to include the floating platforms and connection assemblies present at a subsea oil field at a single point in time, the floating platforms and connection assemblies present at a subsea oil field over the course of a wellbore operation, or a fleet of floating platforms and connection assemblies which may he deployed to different subsea oil fields.

The IOR module, the system of IOR modules, the oil production system, and the method of oil recovery disclosed herein may present several advantages over currently used equipment, systems, and methods. The present disclosure provides modular equipment capable of performing IOR methods on an as-needed basis. The IOR module disclosed herein is separate from any oil production facility, or any other equipment that may be present at a subsea oil field. Thus, the IOR module may be brought to a subsea oil field when IOR methods are needed, and removed from the site when they are not. This presents at least two advantages. First, the IOR module may be used at different subsea oil fields in an alternating fashion (i.e. the IOR module may be moved from one subsea oil field to another, as needed), thus preventing idle time for the IOR equipment and improving efficiency. Second, IOR equipment is not located on an oil production platform, or any other floating component which may be located at a subsea oil field from the commencement of operations at that site, to the conclusion of all operations at that site. This may allow other equipment to be included on the more permanent floating structures, or may reduce the weight and cost of the more permanent floating structures. Third, the IOR module can be tailored to the specific requirements of a subsea oil field, including requirements that may only become apparent after initial production from the oil field. The present disclosure also provides the ability to configure IOR modules and systems for specific subsea oil fields, such that an operator may “mix and match” floating platforms, connection assemblies, IOR pods, and communication equipment when designing an IOR module for a particular subsea oil field. The IOR module may be disassembled and its components may be reassembled to produce a new IOR module having a different configuration for a different subsea oil field. This increases the flexibility that an operator has and prevents unneeded equipment from being deployed to a subsea oil field. The present disclosure may reduce the costs of performing IOR methods at subsea oil subsea oil fields.

While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.

Claims

1. An improved oil recovery module comprising:

a floating platform;

two or more improved oil recovery pods disposed on the floating platform; and

one or more injection assemblies each of the one or more injection assemblies fluidly connected to two or more of the improved oil recovery pods and configured to he fluidly connected to one or more injection wellheads,

wherein each of the one or more injection assemblies comprises one or more inlets and an outlet, and wherein the one or more injection assemblies are each configured such that one or more improved oil recovery pods may he fluidly connected to the outlet.

2. (canceled)

3. The improved oil recovery module of claim 1, wherein each of the one or more improved oil recovery pod comprises: water injection equipment, steam injection equipment, vapor injection equipment, gas injection equipment, water alternating gas injection equipment, or chemically treated water injection equipment.

4. The improved oil recovery module of claim 1, wherein the one or more improved oil recovery pods are individually removable from the floating platform.

5. The improved oil recovery module of claim 1, further comprising a connection assembly configured to fluidly connect the injection assembly to one or more injection wellheads.

6. The improved oil recovery module of claim 1, wherein the improved oil recovery module does not comprise equipment for receiving produced reservoir fluids.

7. A system comprising two or more improved oil recovery modules of claim 1.

8. An offshore oil production system comprising:

an oil production facility; and

one or more improved oil recovery modules wherein a module comprises: a floating platform; one or more improved oil recovery pods disposed on the floating platform; and one or more injection assemblies connected to the one or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads; and

one or more connection assemblies, configured to connect the one or more injection. assemblies to the one or more injection wellheads, each of the one or more connection assemblies comprising: an upper jumper, having a proximal end connected to one of the one or more connection assemblies; one or more risers, each riser having an upper end connected to a distal end of the upper jumper; and one or more lower jumpers, each lower jumper having a proximal end connected to a lower end of one of the one or more risers.

9. The offshore oil recovery of claim 8, further comprising equipment which facilitates communication between the oil production facility and the improved oil recovery module.

10. The offshore oil production system of claim 8, further comprising sensors disposed on the improved oil recovery module or the oil production facility to measure a property of the improved oil recovery method performed by the improved oil recovery module.

11. The offshore oil production system of claim 10, wherein an operation of the oil production facility or the improved oil recovery module is controlled based on a measurement of the property of the improved oil recovery method.

12. A method of offshore oil recovery comprising:

locating an improved oil recovery module proximate a subsea oil field;

wherein the improved oil recovery module comprises: a floating platform; two or more improved oil recovery pods disposed on the floating platform, the two or more improved oil recovery pods comprising two or more of a water injection pod, a steam injection pod, a vapor injection pod, a gas injection pod, a water alternating gas injection pod, or a chemically treated water injection pod; and one or more injection assemblies fluidly connected to the two or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads;

connecting the one or more injection assemblies to one or more injection wellheads of the subsea oil field; and

performing an oil recovery method using the improved oil recovery module,

wherein the oil recovery method comprises pushing oil through a formation of the oil field towards a production wellhead.

13. The method of claim 12, further connecting the one or more injection assemblies to the one or more injection wellheads via a connection assembly.

14. The method of claim 12, further comprising disconnecting the injection assembly from the connection assembly, performing a wellbore operation, and reconnecting the injection assembly to the connection assembly.

15. The method of claim 12, wherein the one or more injection assemblies each comprises one or more inlets and an outlet, and wherein the one or more injection assemblies may each be configured such that a single improved oil recovery pod is fluidly connected to the outlet.

16. The method of claim 15, further comprising:

configuring the injection assembly such that a first improved oil recovery pod may fluidly communicate with the outlet;

performing an improved oil recovery method using the first improved oil recovery pod;

configuring the injection assembly such that the first improved oil recovery pod may not fluidly communicate with the injection wellhead;

configuring the injection assembly such that a second improved oil recovery pod, different from the first improved oil recovery pod, may fluidly communicate with the injection wellhead; and

performing an improved oil recovery method using the second improved oil recovery pod.

17. The method of claim 12, further comprising assembling the improved oil recovery module disposing the one or more improved oil recovery pods on the floating platform.

18. The method of claim 12, further comprising:

locating a second improved oil recovery module proximate a subsea oil field;

wherein the second improved oil recovery module comprises:

a floating platform;

one or more improved oil recovery pods disposed on the floating, platform; and

one or more injection assemblies fluidly connected to the one or more improved oil recovery pods and configured to be fluidly connected to one or more injection wellheads

connecting the one or more injection assemblies to one or more injection wellheads of the subsea oil field; and

performing an oil recovery method using the second improved oil recovery module.

19. The offshore oil production system of claim 8, wherein each of the one or more connection assemblies further comprise:

a buoyant upper riser assembly connected between the upper jumper and the one or more risers;

one or more lower riser assemblies connected between the one or more risers and the one or more lower jumpers; and

one or more anchors connected to the one or more lower riser assemblies.

20. The offshore oil production system of claim 8, wherein the connection assembly is configured to connect at least one of the one or more injection assemblies to more than one injection wellhead.

21. The method of claim 12, further comprising:

locating the improved oil recovery module proximate a second subsea oil field;

connecting the one or more injection assemblies to one or more injection wellheads of the second subsea oil field; and

performing an oil recovery method at the second subsea oil field using the improved oil recovery module.

22. The method of claim 21, wherein the oil recovery method at the second subsea oil field uses a different improved oil recovery pod than the improved oil recovery pod used in the oil recovery method at the subsea oil field.