Patent Application
20250101817
Oil and gas wells produce significant amounts of water in their lifetime. The percentage of water produced from these wells is called the water cut, the ratio of the water produced from the well compared to the volume of the total liquids produced. Most wells produce an ever-increasing water cut throughout their productive life. In many oil fields around the world the percentage of water recovered with oil has risen to be greater than the percentage of the oil. In fact, in many fields, the percentage of oil has decreased to be from about 20% in an excellent field to about 2% in a relatively poor field.
The end of a well's productive life is often determined by the water cut. A well is typically shut in when the value of the hydrocarbons produced is no longer sufficient to economically cover the operating costs of the well and the cost of disposing of the produced water. Indeed, disposing of the produced water is not environmentally and economically friendly as energy is used to power the pump to lift the produced water to the surface, to separate the produced water from the oil, to transport the separated water as it cannot be disposed on the surface in most cases. Thus, the separated water must be transported to a remote well site to be reinjected into a subterranean formation. Therefore, decreasing the water cut of a well increases the value of the produced fluids and directly decreases the disposal costs of the produced water.
One method of reducing the water cut of a well is to separate produced water from the hydrocarbons downhole, rather than at surface. Downhole separation increases the value of the fluids produced to the surface. Downhole separation also facilitates disposal of the separated water. The separated water can be reinjected into the same production zone or into a different zone. Another way to improve the productivity of a well is to increase the length of the intersection of the productive zone by the well completion. One way of increasing this intersection length is by using multilateral wells. A multilateral well is a conventional well that has a lateral well that is drilled from a point in the original well. The lateral well increases productivity by allowing additional intersection length along the productive zone without the cost and delay involved in redrilling the upper part of the well. While multilaterals enable multiple intersections within the same productive zone, multilaterals also enable fluid communication with different productive zones within a reservoir. In certain reservoirs, operators can leverage this approach to improve reservoir production by accessing numerous production zones or by increasing the contact area between a wellbore and a formation with minimal increase in drilling and completion costs. These techniques also reduce the environmental footprint of drilling rigs and subsequent production trees, particularly for land operations. Therefore, the use of multilateral well increases the potential production of a well and can also enable disposal of the produced water in a different zone.
Embodiments of the disclosure may be better understood by referencing the accompanying drawings.
As wells age, they may produce more water. To decrease the lifting and production cost related to produced water, Downhole Oil-Water Separation (DOWS) operations may be implemented to separate the water downhole and inject it into another portion of the well. This may include disposing of the separated produced water into one or more legs of a multilateral well.
Multilateral wells may include horizontal wells. Horizontal wells may deviate from 85 degrees to 95 degrees. As wells deviate from 90 degrees, their flow structure may become stratified with little or no mixing. For example, in an 85 degree horizontal well, fluid flow may include monophasic water flowing at the bottom and monophasic oil flowing at the top. The separate oil and water phases may flow at different velocities. Some implementations include a leveler configured to level segments of the horizontal well to 90 degrees. As fluids pass through a level segment of the horizontal well (90 degrees), the fluid phases may be less stratified and have more uniform flow.
The lever may be used to change an inclination of a tubular from a first inclination to a second inclination. The inclination change may facilitate various downhole operations such as fluid separation, sediment separation, and any other suitable downhole operation.
In some implementations, the leveler may include an actuator configured to move a tubular, tool, or other component in the well into a level position or into a position closer to 90 degrees. For example, the leveler may be placed under a component in the horizontal well (such as a tubular). The leveler's actuator may be used to move the component into an improved state of levelness (such as by moving a component from 87 degrees to 90 degrees).
The leveler may be part of a leveling system that includes sensors that determine when a component is in its optimal position (level or as close to level as possible). The leveler or any component of the leveling system may be electrically connected to and receive power from electrical cabling used for powering one or more electrical submersible pumps (ESPs) in the multilateral well system. Given that conditions in the multilateral well system may be dynamic, a component that was level may move to an unlevel position. The leveling system may include a controller that automatically levels components that become unlevel based on feedback from sensors. The sensors may determine and provide information indicating an orientation of component to the controller. The sensors may reside inside the component, such as inside a tubular, where the sensors may determine whether fluid phases have separated, thereby indicating the component may be unlevel.
Some implementations are in reference to a “multilateral well” and “multi-bore well.” Such terms may be used interchangeably. In other words, a multilateral well may be defined to include any type of well having more than one bore, wellbore, branch, lateral, etc. For example, a multilateral well may include a main bore with one or more laterals branching therefrom. In another example, a multilateral well may also include any type of multi-bore well configuration with such bores at any angles relative to each other. Additionally, while example implementations may be used in reference to a multilateral or multi-bore well, some implementations may also be used in a single bore well. Also, the terms Downhole Oil-Water Separation (DOWS) System and Downhole Oil-Water-Solids Separation (DOWSS) System herein may be used interchangeably. Moreover, the acronyms DOWS and DOWSS herein may be used interchangeably.
One or more levelers or other components described herein may be used in concert with any of the systems and components described herein (even if not shown).
In
The nonproduction fluid 116 may include sediment. In some implementations, the sediment may be separated out from the nonproduction fluid 116 prior to the nonproduction fluid 116 being injected back a subsurface formation. For example, a cyclonic solids separator may separate the sediment from the nonproduction fluid 116. Therefore, the separation system 124 may also include sediment separator(s) to separate out sediment from the nonproduction fluid 116.
In some implementations, the sediment that has been separated out may be stored downhole (at least temporarily). In some implementations, the sediment may be delivered to the surface of the multilateral well or another downhole location using a flow channel (such as a tubing string). Examples of another downhole location may include a cavern, a disposal wellbore, a thief zone, etc. This flow channel may be the production tubing string 106 used to deliver production fluid to a surface of the multilateral well. In some implementations, this flow channel may be a separate tubing string for delivery of the sediment and/or other fluids to the surface of the multilateral well or to a different downhole location.
In some implementations, the separation system 124 may include sediment injector(s) to receive the sediment separated out by the sediment separator(s). The sediment injector(s) may inject this sediment into the production tubing string 106 (used to deliver the production fluid to a surface of the multilateral well) to deliver this sediment to the surface of the multilateral well. Alternatively, or in addition, the sediment injector(s) may inject this sediment into a separate tubing string to deliver this sediment to the surface of the multilateral well or to a different downhole location.
The formation fluid 118 flows into the fluid separator 296. In this example, the fluid separator 296 comprises a gravity-based separation that includes the separator 201. As shown, the formation fluid 118 moves from a smaller to a larger diameter of the tubing 287. This may decrease the velocity of the flow of the formation fluid 118—which allows the separation. In particular, most, or at least a majority of the production fluid 114 may separate into a flow above the separator 201, while most or at least a majority of the nonproduction fluid with sediment 294 may separate into a separate flow below the separator 201. This may allow most of the sediment to be captured in the lower portion of the tubing 287 (below the separator 201).
While depicted as having the separator 201, in some implementations, there is no separator 201. Rather, the production fluid 114 and the nonproduction fluid with sediment 294 may naturally separate in a horizontal pipe because of their different density. Accordingly, even in a same tubing without the separator 201, most of the production fluid 114 would be above the nonproduction fluid 116 because of the differences in weight between the two types of fluid.
The nonproduction fluid with sediment 294 flows into the sediment separators 290A-290N, which may represent one to any number and type of separators. For example, the sediment separators 290A-290N may include cyclonic solids separators. In some implementations, each of the sediment separators 290A-290N may separate some of the sediment in the nonproduction fluid with sediment 294. For example, the first sediment separator 290 may be used to separate and collect the largest size (denser) sediment; the second sediment separator 290 may be used to separate and collect the next largest size sediment; the third sediment separator 290 may be used to separate and collect the next largest size sediment; etc. (as the flow moves from right to left through the different sediment separators 290A-290N). For example, at least one of the sediment separators 290 may be a hydrocyclone—wherein larger (denser) particles in the rotating stream have too much inertia to follow the tight curve of the stream. Such particles may thus strike the outside wall and fall to the bottom of the cyclone where they may be removed. In some implementations, each of the sediment separators 290 may store the sediment that was collected into an associated storage area or tank (i.e., a solids accumulator).
In some implementations, the separation system 200 and/or any one or more of the components within the separation system 200 may be oriented with respect to gravity. For example, components such as the fluid separator 296, separator 201, sediment separators 290A-N, etc. may be oriented with respect to gravity such that gravity may assist in separating the phases of the formation fluid 118, sediment 295 from the formation fluid 118, etc.
Additionally, the chemical injector(s) 291 may inject one or more chemicals into at least one of the formation fluid 118, the production fluid 114, the nonproduction fluid with sediment 294, the nonproduction fluid 116, or the sediment 295. While depicted such that chemicals are injected downhole, alternatively or in addition, chemicals may be injected from the surface of the multilateral well. Also, different chemicals may be injected for different purposes. For example, a flocculant or deflocculant may be injected to promote or not promote aggregation or settling of suspended particles in a liquid. Other examples of chemicals being injected may include paraffin, solvents, dispersants, etc. being added to the production fluid 114, a scavenger being added to the production fluid 114 to remove corrosive gases (H2S) therefrom, etc. In particular, crude oils often contain paraffins which precipitate and adhere to the liner, tubing, sucker rods and surface equipment as the temperature of the producing stream decreases in the normal course of flowing, gas lifting or pumping. Heavy paraffin deposits are undesirable because they reduce the effective size of the flow conduits and restrict the production rate from the well. Where severe paraffin deposition occurs, removal of the deposits by mechanical, thermal, or other means is required, resulting in costly down time, and increased operating costs.
In some implementations, these different collections of the sediment by the different sediment separators 290 may be injected into a same or different line or tubing for disposal. As shown, the sediment injector(s) 299 are coupled to receive the sediment collected by the different sediment separators 290.
Periodically, sediment may need to be emptied from the different sediment separators 290 via the sediment injector(s) 299. The decision of when may be based on different criteria. For example, pressure and/or production flow may be monitored at the surface of the multilateral well. If the pressure and/or production flow start to degrade, it may be an indication that sediment needs to be emptied from the sediment separators 290.
In some implementations, sensors may be coupled to each of the tanks of the sediment separators 290. A signal from a given sensor may indicate when the associated sediment separator 290 needs to be emptied. A controller (downhole or at the surface of the multilateral well) may be communicatively coupled to the sensors such that the controller may initiate a sequence to empty one or more of the tanks of the sediment separators 290.
In some implementations, each of the temporary storage tanks (i.e., solids accumulators) for the corresponding sediment separator 290 may be configured with a solid mover, such as an auger. When a sediment separator needs to be emptied, the solids mover may be activated to empty the solids from the solids accumulator.
In some implementations, the sediment injector(s) 299 may dispose of these sediments by injecting them into a tubing for delivery to the surface of the multilateral well. For example, the sediment may be delivered to the surface using the production tubing or a separate tubing. If the production tubing is used, the solids may be included with the production fluid that is being delivered to the surface. In such implementations, separation operations may be performed at the surface to separate out the solids from the production fluid 114.
Accordingly, if sediment is included with the production fluid 114 being delivered to the surface, the production fluid 114 may be delivered to surface equipment that provides for separation of the sediment. Alternatively, during the time when the sediment is not being included with the production fluid 114, the production fluid 114 may be delivered to different surface equipment that does not include such separation of sediment.
Alternatively, or in addition, the sediment injectors 299 may deliver the sediment to a different downhole location (such as a different lateral well, a thief zone (having a high porosity, high permeability downhole zone that may include a low pressure), etc.). In some implementations, sediment may be disposed to different locations depending on their size. For example, for sediment having a size greater than X, such solids may be delivered to the surface of the multilateral well for disposal. For sediment having a size less than X but greater than Y, such sediment may be disposed in a first downhole location (such as a thief zone). For the remaining sediment that have a size less than Y, such solids may be disposed in a second downhole location (such as a lateral well).
In some examples, the sediment (or solid) Y may be larger, or the same size as sediment X. As an example, if the first hole location is very permeable and may accept larger-size solids (or sediments), the larger size solids may be injected or disposed into the first downhole location and the smaller size solids may be either produced to the surface and/or injected or disposed into a second downhole location.
In some examples, X may range from 0.01 mm (10 microns) to larger than 8.00 mm (8000 microns). For example, X may range from medium silt to larger than medium gravel. In some examples, Y may be 0.01 mm (10 microns) or smaller. In some examples, X may range from 0.02 mm (20 microns) to 8.00 mm (8000 microns). For example, X may range from medium silt to larger than medium gravel.
In some examples, Y may be 0.02 mm (20 microns) or smaller. In some examples, Y may be.01 mm (10 microns) to 02 mm (20 microns). In some examples, X may range from 0.063 mm to 2.00 mm (63 microns to 2000 microns) (e.g., solids defined as sand per ISO 14688-1:2002). In some examples, Y may be 0.063 mm (63 microns) or smaller. In some examples, Y may be 0.02 mm (20 microns) to 0.063 mm (63 microns). In some examples, X may range from 0.075 mm to greater than 4.75 mm (75 to greater than 4750 microns). In some examples, Y be 0.075 mm (75 microns) or smaller.
In some examples, Y may be 0.02 mm (20 microns) to 0.075 mm (75 microns). In some examples, X may be greater than 4750 microns. In some examples, Y be 4.75 mm (4775 microns) or smaller. In some examples, Y may be 0.02 mm (20 microns) to 4.75 mm (4775 microns). In some examples, X may be greater than 0.6 mm (600 microns) (e.g., coarse sand and larger). In some examples, Y be 7.5 mm (75 microns) or smaller. In some examples, Y may be 0.02 mm (20 microns) to 7.5 mm (75 microns).
Accordingly, example implementations may detect the accumulation of solids in DOWS equipment. An operator (or other device) may be signaled that the solids should be removed. In response, an operational change in the DOWS equipment may be initiated to allow solids removal. For example, this may include shut down or reduction of DOWS-related operations (decrease or shut down pumps, switch valves that direct fluids to the surface and/or other location, etc.). Preparation of the solid's removal process may be initiated. For example, access sleeves and flushing ports may be opened, solids directional control equipment may be adjusted (e.g., change position), injection devices, sleeves, ports, valves, etc. may be closed, solids processing/removal equipment (from surface and/or downhole) may be deployed, etc. Additionally, flushing, dislodging, scrapping, chemically treating, fluidically treating, mechanically treating, etc. of downhole solids from one or more locations downhole may be enabled. Solids and related debris from the DOWS system (DOWSS) may be displaced. In some implementations, solids and other materials may be collected from the DOWSS. The solids and other materials may be transported from the DOWSS. Fluids, chemicals, solvents, acids, liquids, abrasive media, solids and other materials may be transported from the surface to the DOWSS.
Items such as water, chemicals and other items listed above may be transported in a controlled manner. For example, the transporting in a controlled manner may be based on speed, velocity, volumes, ratios, time-based (e.g., until a certain amount of time has passed), function-based (e.g., until a certain pressure-drop is experienced, until fluid has been circulated “bottoms up”, etc.). For example, the transporting in a controlled manner may be based on when Z number of tubing strings of fluid has been pumped or until X-amount (e.g., pounds, mass, volume, etc.) of debris has been recovered, collected, injected, disposed, transferred, etc. Tools, devices, flow, etc. may be moved, shifted, directed, etc. to improve the solids collecting, removal, retaining, and flushing process(es). For example, a direction of a jetting nozzle may be changed, one flushing port may be closed while opening another, etc. Tools, devices, components, strings, etc. may be repositioned from one location to another to continue the one-or-more above processes. Additionally, tools, devices, components, strings, etc. may be repositioned to dispose of solids in a preferred location.
One or more fluids, chemicals, solvents, acids, liquids, abrasive media, solids and other materials may be moved from the surface of the well to the DOWSS to enhance the longevity of the DOWSS. This may include applying and/or re-applying friction reducing coatings, replacing components-filters, stators, pumps, rotors, bearings, bearing assemblies, worn parts, eroded parts, electrical components, sensors, computers, controllers, logic devices, parts intend to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.
Also, the shutting down of the solid's removal process may be initiated. For example, access sleeves and flushing ports may be closed, solids directional control equipment may be adjusted. Injection devices, sleeves, ports, valves, etc. may be opened. Solids processing and removal equipment may be retrieved (from the surface and/or other location downhole. Used or worn devices from well may be retrieved. Such devices may include filters, stators, pumps, rotors, bearings, bearing assemblies, worn parts, eroded parts, electrical components, sensors, computers, controllers, logic devices, parts intend to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.
An operational change in the DOWS equipment may be initiated to allow fluid separation again. This may include “turning on” or increase of DOWSS-related operations (e.g., increase or turn-on pumps, switch valves that direct fluids to the surface and/or downhole, etc.). Also, the operator (or other device) may be signaled that the DOWSS equipment has been re-configured out of the solids-removal status and is ready to begin fluid separation operations. The DOWS may then return back to fluids separation mode. Additionally, there may be provided a continuous or occasional status check of the “health” of DOWS equipment.
It should be noted that the DOWS system and components noted may be inclusive of items from the wellhead to the toe of each wellbore and more. The cables and/or energy conduits that provide power to the one or more ESPs and/or other pumps and prime movers (downhole and on surface) may be inclusive. The surface components that transport the fluids and solids (everything) out of the well may be included. Subsea trees, subsea DOWS equipment, platform, land-base, jack up, drillship, etc. types of equipment may be inclusive. Data lines, data processing, sensors, in the well and outside of the well may be inclusive. Fluid processing equipment and processes in the well and outside of the well may be inclusive. Solids processing equipment and processes in the well and outside of the well may be inclusive.
Example implementations may be applied to other types of remote operations where the tools, operations, processes are separated from the operators by distances, barriers, adverse environments, etc. The ability to remotely test to determine or verify whether functions were performed successfully and then communicate or report the tests results to a locale inhabitable by humans (e.g. the earth's surface) makes example implementations suitable for use in other remote locations with harsh environments such as outer space (e.g., satellites, spacecrafts, etc.), aeronautics (aircrafts, drones), on-ground (swamps, marshes, power generation, hydrogen or other gas extraction and/or transportation, etc.), below ground (mines, caves, etc.), ocean (on surface and subsea), subterranean (mineral extraction, storage wells (carbon sequestration, carbon capture and storage (CCS), etc.)), and other energy recovery activities (geothermal, steam, etc.). The unhabitable environments may comprise corrosive fluids (hydrocarbons, H2S fluids, C02 fluids, acids, bases, gases, etc.), contaminants (sand, debris, paraffins, asphaltenes, etc.), high-temperature fluids (fluids from geothermal formations, injected fluids, etc.), cryogenic fluids, etc. Example implementations may be utilized in harsh conditions (e.g., corrosive environments or contaminated fluids), extreme pressures (e.g., >5,000-psi differential), extreme temperatures (e.g., >−20° F. or >300° F.), etc. In other instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail to avoid confusion.
Thus, in some implementations, the separators, pumps, and injectors may be installed at the junction between the main bore and the lateral bore. In other implementations, such devices may be installed below this junction or above this junction. Further, the main bore or one or more lateral bores may include one or more orientation devices which provides depth and orientation control. While example implementations include a given gravity-type separator, other types of separators may be used. For example, other gravity-type separators (e.g., fluid separators) and other non- gravity separators may be used.
Example implementations may include weir skimmers that function by allowing the oil floating on the surface of the water to flow over a weir. In some implementations, the weir skimmers may require the weir height to be manually adjusted. Alternatively, the weir skimmers may be such that the weir height is automatic or self-adjusting. While manually adjusted weir skimmer types may have a lower initial cost, the requirement for regular manual adjustment makes self-adjusting weir types more popular in most applications. Weir skimmers may collect water if operating when oil is no longer present. To overcome this limitation, the weir type skimmers may include an automatic water drain on the oil collection tank.
Some implementations are in reference to a “multilateral well.” A multilateral well may be defined to include any type of well that has more than one bore, wellbore, branch, lateral, etc. For example, a multilateral well may include a main bore with one or more laterals branching therefrom. In another example, a multilateral well may also include any type of multi-bore well configuration with such bores at any angles relative to each other.
In some implementations, the separation system 200 may be installed at the junction between the main bore and the lateral bore. In other implementations, such devices may be installed below this junction or above this junction. Further, the main bore or one or more lateral bores may include one or more orientation devices which provides depth and orientation control. While example implementations include a given gravity-type separator, other types of separators may be used. For example, other gravity-type separators (e.g., FluidSep) and other non-gravity separators may be used.
The multilateral junction may be placed above or inside the target formation. In some implementations, this configuration may be accomplished in a two-trip multilateral completion that includes a lower completion with orientation liner hanger connected to additional lower completion, and an upper completion that includes the fluid separator, an electrical submersible pump, and an upper packer. This simplifies the installation. This reduced complexity allows the fluid separator to be installed into existing wells, i.e., retrofitting existing wells. Further, the lateral bore 104 may be a target formation. In this implementation, the main bore 102 passes through a target production formation and the lateral bore 104 passes through a target injection formation which is a separate formation from the production formation. The existing wells do not require a tangent section at the junction for the placement of the fluid separator, significantly increasing the number of oil well candidates for installation of the fluid separator according to example implementations.
Example implementations may be used in non-horizontal applications (inclined wells, extended reach wells, slant hole wells, vertical wells, S-wells, or combination thereof, etc.). In some applications, such as inclined wells, a flow diverter may be used in conjunction with other devices. The other devices may be one or more destabilizers, a gravitational separator, a non-gravitational separator, a combination of both gravitational and non-gravitational, a coalescing device, a cleaning device, another flow diverting device, a leveling device, an inclination device to monitor, sense, adjust, change the inclination of one or more devices with respect to gravity and/or the inclination of the well, an orientation device to monitor, sense, adjust, change the orientation and/or azimuthal position of one or more devices, systems etc. One or more orientation devices (powered and non-powered) may be used. Example implementations may include cartridges.
The design of the installed completion equipment may be critical for the downhole fluid separator to function as intended. By installing the fluid separators, pumps, and sediment injector in the main bore at or near the junction between the main bore 102 and the lateral bore 104, an existing watered out well may be re-entered. This decreases the overall cost involved in installing the separators, pumps, and sediment injector according to example implementations as compared with installing it at the completion of the well at the beginning of the life of the well. It also decreases the risks associated with installing these devices according to example implementations in existing wells that may be poor producers and represent a smaller cost if the well is lost during the trial as compared with selecting a potential well before well completion is finished. Using these separators and injectors in a downhole setting combined with a multilateral junction may provide efficiency gains.
This includes converting poor performing wells, wherein the percentage of oil has decreased to about 2% for example, into a downhole water injector combined with a better producing well. Additional benefits include lower flow rate and pressure rating requirements, a lighter fluid column, and increased recovery. Example implementations may be particularly useful in low flow rate wells (in the 200 barrel per day range or less), which tend to be shallow, and relatively inexpensive to drill. Moderate flow rate wells, for example 500-5000 barrels of fluid per day, may also be potential candidates for incorporating example implementations. Finally, it will also be useful for most multilaterals with very high flow rate wells, up to 50,000 barrels of fluid per day, for example.
Example implementations reference a production tubing string 106 for the delivery of fluids, sediment, etc. to the surface of the multilateral well or other downhole location. However, example implementations may use any type of flow channel, conduit, etc. for such delivery. For example, the sediment flow channel may be the annular space around the production tubing string 106. Additionally, while depicting the separation being performed uphole relative to the junction between the main bore 102 and the lateral bore 104, example implementations may position the separation at any other location downhole. For instance, the separation may be performed at the junction, below the junction, etc.
The DOWSS may include flow inlet devices, oil-separation devices, water-separation devices, self-deprecation devices, flow outlet devices, flow outlet conduits (tubing, screens, y's, tees, splitters, etc.), fluid transport devices, fluid screening devices, formation support devices (liners, casings, screens, injection ports, and valves (including Outflow Control Devices (including automatic, chokes, restrictors, regulating, etc.). The outflow control devices may comprise one or more features similar to inflow control devices such Inflow Control Devices (ICD's), Automatic Inflow Control Devices (AICD's), Gravity-based ICD's, AIDC's, etc., Viscous-based ICD's, AIDC's, etc., Inertial-based ICD's, AIDC's, etc., pumps, regulators, sensors, controllers, relays, transmitters, floats, etc.
Examples implementations may include an injecting-while-producing system—wherein one pump may be used to force fluid into one formation and a second pump may be used to produce fluid from a second zone. This single-bore water-flood solution maintains downhole pressure to reduce cycling and recover more oil in struggling wells. The injecting-while-producing system may inject from an upper zone and produce from the lower with the aid of isolation packers, or it can inject in the bottom zone and produce from a zone higher in the well.
All the example inclination devices (also referred to as “levelers”) described herein may operate in concert with one or more other devices such as fluid separators, coalescers, perturbation devices, and others. Some novel combinations may not be explicitly shown in the drawings but are with the scope of this disclosure. For example, a leveler, which may inhibit phase separation of formation fluid or achieve other aspects of fluid flow, may be used with devices such as a flow pipes, solids removers, coalescers, perturbation devices, and other devices.
The leveler 406 may reside in the component 404 and be positioned to exert force on the tubular 408. By exerting force on the tubular 408, the leveler 406 may improve the levelness of the tubular 408 or otherwise alter its position with respect to a vertical position. As shown, the leveler 406 may hold the tubular 408 and a level position (90° from the vertical position) or at a non-level position (e.g., (92° from the vertical position) Some embodiments may enable oil to accumulate as shown in the 91-degree aspects of
As the leveler 406 changes the inclination of the tubular 408, fluid flow through the tubular may exhibit different properties. For example, if the leveler 406 moves the tubular 408 into a level orientation (such as) 90°, oil and water phases may behave like those described with reference to
In some implementations, the leveler 406 includes a hydraulic pump configured to drive the actuator 410 along its range of motion. In some implementations, the leveler 406 may include an electric motor configured to drive the actuator along its range of motion. Some implementations may include any other suitable device for driving the actuator 410 along its full range of motion.
The leveling system 700 may include a first support member 702 and a second support member 704. The first support member 702 may have an outer surface with cylindrical shape configured to mate with the second tubular 704. The first support member 702 may enable the first tubular 706 to rotate inside the second tubular 708 (such as with bearings or bushings). The second support member 704 may fit inside an interface member 714. The second support member 704 may remain in a fixed position relative to the interface member 714.
The interface member 714 may include teeth 716 that interface with a tool or other mechanism that may apply a turning force to rotate the first tubular 706 inside the second tubular 708. For example, a tool may engage with the teeth 716 and turn the interface member counterclockwise, thereby rotating the first tubular 706. Rotating the first tubular 706 may change the levelness of the first tubular 706.
The first and second tubulars (706 and 708) may have uniform thickness. The first support member 702 may have nonuniform thickness. For example, beginning at a first point on the outer surface of the first support member 702, the first support 702 member may have a thickness of 10 mm. Thickness may uniformly increase to a second point on the outer surface at which the thickness is 30 mm. Moving around the outer surface back to the first point, the thickness may uniformly decrease back to 10 mm. The first support member 702 may include one or more bearings that interface with the second tubular 708 and enables the first tubular 706 to rotate around an axis 718 spanning between ends of the first tubular 706. The second support member 704 also may have nonuniform thickness. The support members 702 and 704 may have whatever thickness profiles may be needed to extend the range of orientation of the leveling system 700. That is, the support members 702 and 704 may have any thickness profile suitable for maximizing the adjustability and levelness of the first tubular 706.
By having nonuniform thickness, the first support member 702 may hold the first tubular closer to a lower surface of the second tubular 708 than to an upper surface of the second tubular 708 (at some positions of the interface member 714). That is, a distance 712 between the first tubular 706 and the lower inner surface of the second tubular 708 may be less than the distance 710 between the first tubular 706 and the upper inner surface of the second tubular 708. Although this principle is shown with respect to upper and lower surfaces of the second tubular 708, it applies to any part of the inner surface of the second tubular 708. Given the properties of the support members (702 and 704), applying a rotational force to the interface member 714 may alter the levelness of the first tubular 706. For example, rotating the interface member 714 by 90 degrees may change the levelness of the first tubular by one or more degrees.
All the example levelers described herein may operate in concert with one or more other devices such as fluid separators, coalescers, perturbation devices, and others. Some novel combinations may not be explicitly shown in the drawings but are with the scope of this disclosure. For example, a leveler, which may inhibit phase separation of formation fluid or achieve other aspects of fluid flow, may be used with devices such as a flow pipes, solids removers, coalescers, perturbation devices, and other devices.
Example operations are now described.
At block 1202, production is initiated. For example, with reference to
At block 1204, formation fluid is received into a downhole separation system. For example, with reference to
At block 1206, flow of formation fluid is separated into one or more flow paths. For example, with reference to
At block 1208, the flow rate is decreased. For example, with reference to
At block 1210, flow is modified to decrease turbulence. For example, example implementations may also destabilize turbulence and reduce flow from a turbulent flow to a laminar flow (or transitional flow) by one or means (including those mentioned above).
At block 1212, flow is separated into one or more flow paths. For example, with reference to
At block 1214, gravitational separation is performed. For example, with reference to
At block 1216, non-gravitational separation is performed. For example, with reference to
At block 1218, stepped-sized separation is performed. For example, with reference to
At block 1220, solids and lighter fluids are accumulated. For example, with reference to
Operations of the flowchart 1700 continue at transition point A, which continues at transition point A of
At block 1302, solids are separated and discharged into temporary holding tanks. For example, with reference to
At block 1304, solids are transported for disposal. For example, with reference to
At block 1306, solids are transported to an injector. For example, with reference to
At block 1308, solids may be mixed at the injector. For example, with reference to
At block 1310, solids (or slurry) are injected. For example, with reference to
At block 1312, solids-laden fluid is transported. For example, with reference to
In some implementations, the sediment injectors 299 may inject the solids or slurry into a string or tubular (e.g., a production tubing). Timing of the injection may be coordinated with production of production fluid. For example, a pump may switch between pumping (in the production tubing) production fluid to the solid-laden fluid. Example implementations may include communications to the surface regarding the switching, the volume of the solids, fluids, slurry to be pumped, how much has been pumped, how much remains to be pumped, etc. Additionally, some implementations may enable communication from the surface to downhole to control and override the switching.
At block 1314, injection process is monitored and controlled. For example, with reference to
Operations of the flowchart 1300 continue at transition point B, which continues at transition point B of
All the example levelers described herein may operate in concert with one or more other devices such as fluid separators, coalescers, perturbation devices, and others. Some novel combinations may not be explicitly shown in the drawings but are with the scope of this disclosure. For example, a leveler, which may inhibit phase separation of formation fluid or achieve other aspects of fluid flow, may be used with devices such as a flow pipes, solids removers, coalescers, perturbation devices, and other devices.
Example implementations may be performed in different Technology Advancement of Multilaterals (TAML) Level wells. In particular, multilateral wells are characterized according to definitions established in 1997 during a Technology Advancement of Multilaterals (TAML) Forum held in Aberdeen. These standards classify junctions as TAML Level 1, 2, 3, 4, 5, or 6 based on mechanical complexity, connectivity, and hydraulic isolation. The ascending order of these levels reflects the increasing mechanical and pressure capability of the junction. Consequently, cost, complexity, and risk also generally increase at the higher TAML levels. However, other considerations of the well design also influence the overall complexity of the well-for example, a TAML Level 2 well with an advanced intelligent completion can be more complex and costly than a TAML Level 5 well with a simpler completion system.
In a TAML 1 well, the main bore, lateral, and junction are uncased. This basic lateral is designed to enhance reservoir drainage from consolidated formations. It has the advantage of low drilling and completion costs, but the open hole junction makes reentry into the lateral wellbore and control of flow from the lateral impossible.
Wells that have cased and cemented main bores and open hole laterals are designated TAML Level 2. A cemented main bore significantly reduces the risk of wellbore collapse and provides isolation between laterals. By placing sliding sleeves and packers in the main bore, operators can produce the bores singly or in commingle production.
Placing a liner in the lateral and mechanically connecting it to the cased and cemented main bore results in a TAML Level 3 well. A liner is a string of casing that does not extend to the surface but is anchored or suspended inside a previously run casing string. This TAML Level 3 well includes a lateral that is cased but not cemented at the junction. It is a relatively low-cost option that includes reentry capabilities and a lateral that is better supported than that of Levels 1 and 2. Using sliding sleeves and packer plugs, operators can produce the bores singly or in commingle production. A TAML Level 3 junction does not provide hydraulic isolation, and its use is restricted to consolidated formations.
TAML Level 4 junctions are applicable in both consolidated and unconsolidated formations because both the lateral and the main bore are cased and cemented at the junction. The junction provides full bore access to the lateral, and mechanical support is supplied by the tubulars and cement. However, because the cement can only withstand limited differential pressure, the junction does not provide hydraulic isolation.
TAML Level 5 wells do provide hydraulic isolation at the junction because pressure integrity is provided by the completion, which includes production tubing connecting a packer in the main wellbore above the junction and a packer in the lateral wellbore. Because hydraulic isolation and support are provided by the completion hardware, the junction may be a TAML Level 2, 3, or 4 before the Level 5 completion is installed. TAML Level 6 wells also provide hydraulic isolation at the junction. A well at this level differs from a TAML Level 5 well in that pressure integrity is provided by the main wellbore casing and a cemented or uncemented liner in the lateral. The cost and complexity of creating a single-metal-element dual-bore casing junction downhole has prevented TAML Level 6 wells from being developed. As of today, the category exists as a result of early experiments. Because multilateral wells that have higher TAML designations are generally more complex, they are more costly, and their configurations are more flexible. As they do with multilateral geometry, engineers choose a TAML level junction based primarily on reservoir characteristics, costs, and function.
The ability to reenter the lateral for well intervention operations is another multilateral well design consideration. Because it is a directionally drilled section that has no junction, the lower lateral is almost always easily accessed using standard intervention methods. Operators must make an economics-based decision during the well planning stage to include junctions that allow lateral access after pulling the upper completion, through-tubing access, junctions that can be adopted to allow access after installation or junctions through which no access is possible to main bore, lateral, or both. If the well includes more than one lateral, a selective through-tubing access system would need to be considered. The decision to deploy lateral junctions that allow full bore or restricted access is a function of the overall well design. Engineers usually opt for full bore access if a packer is to be placed below the junction or if an artificial lift system must be located near the lower lateral. In addition, based on their knowledge of the reservoir, operators may require full bore access to perform perforating, stimulation, logging, water shutoff, gravel packing, cleanout, and other remedial operations. Full bore access can be adapted to all TAML level junctions but must be specified before installation; some commercially available junctions allow no access or only restricted access to either the lateral or the main bore and cannot be adapted after installation.
The decision to use a multilateral well system and what type to use are the result of cost benefit analyses. In general, the less-complex junctions present operators with lower risks and costs. But risk mitigation and cost savings must be balanced against individual well and field development expectations. In low-value reservoirs, a simple open hole lateral that has no reentry capability may increase ultimate reserve recovery or accelerate production while having little impact on overall drilling and completion costs. In high-value deepwater plays, installing a hydraulically sealed TAML Level 5 or 6 junction can drive total well costs into millions of dollars and still be a good investment because it may save drilling another well with a complex and tortuous trajectory, preserve a well slot on an existing production platform, or eliminate the need entirely to procure and install additional subsea infrastructure.
In implementations, a multilateral well is drilled and completed with a TAML Level 4 junction. The junction includes a pump and a fluid separator. The pump includes any pump capable of drawing in fluid through the pump intake, pressurizing it, and lifting it to the surface such as an electrical submersible pump, sucker-rod and pump jack, progressive cavity pump, gas lift and intermittent gas lift, reciprocating and jet hydraulic pumping systems, etc. The fluid separator and the pump can be above, at, or below the junction. The upper completion includes a retrievable electrical submersible pump packer while the lower completion has an orientation liner hanger or other orientation device.
While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. Many variations, modifications, additions, and improvements are possible. Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.
In some implementations, a mechanical junction (not to be confused with the earthen junction of 2 earthen wellbores) may comprise a junction with a monolithic Y-Block. In some implementations, a monolithic Y-Block may provide for more robust connections to the other components of a junction assembly (i.e., main bore leg, lateral leg, tank, etc.).
To illustrate,
The DOWSS 1508 may process the formation fluid 1502 to separate out nonproduction fluid 1506 from production fluid 1522. The DOWSS 1508 may also process the formation fluid 1502 to separate sediment from at least one of the nonproduction fluid 1506 or the production fluid 1522. The DOWSS 1508 may transport the nonproduction fluid 1506 into the lateral bore 1550 for disposal in a disposal zone 1520 for the nonproduction fluid 1506 in the subsurface formation around the lateral bore 1550. The DOWSS 1508 may also transport sediment 1525 into the lateral bore 1551 for disposal in a disposal zone 1524 for the sediment 1525 in the subsurface formation around the lateral bore 1551. The DOWSS 1508 may also transport the production fluid 1522 and sediment 1525 to a surface of the multilateral well. Accordingly, in this example, the sediment may be disposed downhole into a highly permeable zone downhole and/or may be transported to the surface of the multilateral well.
To help illustrate,
The above examples of junctions are provided as nonlimiting examples—as other type of junctions may be used. The placement of the DOWSS, the DOWSS components, the tubing/fluid paths are also non-limiting examples—as other placements, components, paths may be used. The terms “downhole” and “below” may or may not be considered equivalent depending on the type of wellbore. For example, “downhole” and “below” may be considered the same for vertical wellbores. However, “downhole” and “below” may be considered different for horizontal wellbores.
Example implementations may include Subsea Oil Water Solids Separation (SOWSS). Example implementations may include disposal of solids, storage of water, and oil maybe subsea—on the seafloor or in storage wells or in storage vessels embedded in the seafloor.
In some implementations, this fluid transported to the surface of the subsea production well 2002 may be transported to a ship 2030 via a multiphase pump 2020 and risers 2022. The ship 2030 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 2030 may also include storage for the production fluid. As shown, the nonproduction fluid (such as water) separated out from the production fluid by equipment of the ship 2030 may be transported down below to a subsea injection well 2034 via a water injection pump 2032. The water 2042 may be pumped downhole into the subsea injection well 2034. As shown, the water 2042 may be returned for storage in the reservoir 2014.
In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 2002 may remain below (instead of being transported to the ship 2030). For example, after being transported to the surface, the fluid may be transported to a location 2005 at the subsea surface 2004 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 2004 at a location 2008. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 2004 at a location 2006. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 2004.
Accordingly, fluid from the subsea production well 2002 may be pumped to subsea surface 2004 for processing, temporary storage, transport, water injection to maintain reservoir pressure, water flood from the subsea injection well 2034 to push hydrocarbons to the subsea production well 2002 and/or disposal.
In some implementations, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some implementations, the solids, non-commercial fluids, a combination of both, etc. may be produced, separated, processed, stored, and then injected into the disposal well (or other designated well).
To illustrate,
In some implementations, this fluid transported to the surface of the subsea production well 2102 may be transported to a ship 2130 via a multiphase pump 2120 and risers 2122. The ship 2130 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 2130 may also include storage for the production fluid. As shown, the solids (drill cuttings) separated out from the production fluid by equipment of the ship 2130 may be transported down below to the subsea disposal well 2134 via a pump 2132. The solids (drill cuttings) 2142 may be pumped downhole into the subsea disposal well 2134 for storage in the reservoir 2114.
In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 2102 may remain below (instead of being transported to the ship 2130). For example, after being transported to the surface, the fluid may be transported to a location 2105 at the subsea surface 2104 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 2104 at a location 2108. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 2104 at a location 2106. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 2134.
Another example location may include an oil storage and transfer unit 2408. Another example location may include a solids or slurry transfer line 2412. For example, a flow diverter may help mix, remix, stir, or agitate solids to keep them in suspension in the solids or slurry transfer line 2412. Another example location may include a production fluids/oil-cut fluid/fluid transfer line 2414. For example, a flow diverter may help mix, remix, stir, or agitate solids and the fluids to keep them flowing properly in the production fluids/oil-cut fluid/fluid transfer line 2414. Another example location may include a well 2416 with vertical, inclined, sloped, deviated, tortuous paths.
Another example location may include a multilateral well 2418 (that includes a lateral wellbore, junction, etc. Another example location may include a horizontal well 2420. Another example location may include a main production transfer line 2422 to another subsea pumping, gathering, and/or processing station or to land-based pumping, gathering, and/or processing facility.
Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” or other like terms shall be construed as generally toward the bottom, terminal end of the well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. In some instances, a part near the end of the well can be horizontal or even slightly directed upwards. Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.
Unless otherwise specified, the phrase cyclonic solids separator, hydrocyclone, hydrocyclone system, desander, desilter, centrifuge, helical separator, or other separating devices that use gravity or artificial gravity shall be construed as a device positioned downhole to separate sediment from a fluid.
It should be noted that the DOWS system and components noted above may be inclusive of all items from the wellhead to the toe of each wellbore. The cables/energy conduits that provide power to the one or more ESPs and/or other pumps and prime movers (downhole and on surface) are inclusive. The surface components that transport the fluids and solids out of the well are included. Subsea trees, subsea DOWS equipment, platform, land-base, jack up, drillship, etc. types of equipment are inclusive. All data lines, data processing, sensors, in the well and outside of the well are inclusive. All fluid processing equipment and processes in the well and outside of the well are inclusive. All solids processing equipment and processes in the well and outside of the well are inclusive. All decision-making, monitoring, and control of process(es) including human, computer, software, logical hardware and/or software, on-rig, remotely, in the cloud, on the edge, downhole, AI-related, Deep Learning, Neural Network, Machine Learning, Fuzzy Logic, etc. may be inclusive.
In addition to hydrocyclones and helical separators, other types of separators may be used with example implementations.
For example, one or more centrifuges may be added to the system, integrated into one or more devices of the systems, and/or the concept of a centrifuge may be utilized. A key difference between a centrifuge and a hydrocyclone is that hydrocyclones may function as passive separator packages capable of applying modest amounts of centrifugal force, whereas centrifuges are dynamic separators that are generally able to apply much more centrifugal force than hydrocyclones.
In some implementations, clarifiers may be used. Clarifiers are settling tanks built with mechanical means for continuous removal of solids being deposited by sedimentation. A clarifier is generally used to remove solid particulates or suspended solids from liquid for clarification and/or thickening. In some implementations, one or more clarifiers may be positioned in one or more laterals. The laterals may provide a large area for the clarifiers to function. In some implementations, a clarifier may be located subsea. In some implementations, a clarifier may be located in a shallow well drilled into the sea floor. The clarifier may be located near the well or a distance from the well. For example, it may be beneficial for the clarifier to be located near a water injection or water disposal plant and facility located one km or more from the production well.
Various implementations of a clarifier may be used including inclined plate clarifiers which may provide a large effective settling area for a small footprint. The inlet stream is stilled upon entry into the clarifier. Solid particles begin to settle on the plates and begin to accumulate in collection hoppers at the bottom of the clarifier unit. The sludge is drawn off at the bottom of these hoppers and the clarified liquid exits the unit at the top by weir.
It should be understood that the word “solids” also implies concentrated impurities and may be known as sludge, while the particles that float to the surface of the liquid are called scum.
Conveyor belts may be used for removal and transport of accumulated solids. Scrapers may be used for removal and transport of accumulated solids. Coalescing plates may be used for removing oil droplets from flowing water and/or removing solid particles from a fluid. Baffles may be used to reduce water inlet and outlet velocities to minimize turbulence and promote effective settling throughout available tank volume. Weirs (such as overflow weirs) may be used to uniformly distribute flow from liquid leaving the tank over a wide area of the surface to minimize resuspension of settling particles.
Tube or plate settlers are commonly used in rectangular clarifiers to increase the settling capacity by reducing the vertical distance a suspended particle must travel. Tube settlers are available in many different designs such as parallel plates, chevron shaped, diamond, octagon or triangle shape, and circular shape. High efficiency tube settlers may use a stack of parallel tubes, rectangles or flat corrugated plates separated by a few inches (several centimeters) and sloping upwards in the direction of flow. This structure creates a large number of narrow parallel flow pathways encouraging uniform laminar flow as modeled by Stokes' law. These structures may work in two ways. First, they provide an exceptionally large surface area onto which particles may fall and become stabilized. Second, because flow is temporarily accelerated between the plates and then immediately slows down, this helps to aggregate very fine particles that can settle as the flow exits the plates.
Structures inclined between approximately 45° and 60° may allow gravity drainage of accumulated solids, but shallower angles of inclination may typically require periodic draining and cleaning. Tube settlers may allow the use of a smaller clarifier and may enable finer particles to be separated with residence times less than 10 minutes. Typically, such structures are used for difficult-to-treat waters, especially those containing colloidal materials.
Tube settlers may capture the fine particles allowing the larger particles to travel to the bottom of the clarifier in a more uniform way. The fine particles then build up into a larger mass which then slides down the tube channels. The reduction in solids present in the outflow allows a reduction in the clarifier footprint when designing. Tubes made of PVC plastic may be a minor cost in clarifier design improvements and may lead to an increase of operating rate, such as up to 2 to 4 times.
Another advantage of separating solids upstream (further downhole) is to prevent erosional wear on other DOWS-related equipment (other separators, pumps (ESP, PCP, etc.).
Example implementations may also be used in other operations requiring the separation of fluids, solids, gases, minerals, metals, etc. In particular any operations where the work is in an uninhabitable environment and/or remote location where separation, transportation, disposal and/or processing of one or more materials is required.
For example, example implementations may be used in lithium solution mining, borate mining, etc. For example, after dissolving an ore, a saturated borate solution may be pumped into a large settling tank. Borates float on top of the liquor while rock and clay settle to the bottom.
The separation of abrasive particles may accelerate abrasion in cyclones and other separator equipment. For example, the coarse discharge of a hydrocyclone typically will experience more rapid wear than other parts of the cyclone. The use of certain materials (stainless steel, ceramics, tungsten carbide, etc.) may reduce corrosive reactions from occurring. Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed. As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.
Example implementations are now described by the following clauses.
Clause 1: A downhole oil-water separation (DOWS) system configured to be disposed downhole in a well, the DOWS system comprising: a tubular configured to be placed in a horizontal well of the well and to convey reservoir fluid in the DOWS; and a leveler configured to move the tubular from a first inclination to a second inclination.
Clause 2: The DOWS system of clause 1, wherein the leveler further includes: an actuator configured to move the tubular from the first inclination to the second inclination.
Clause 3: The DOWS system of any one or more of clauses 1-2, wherein the leveler further includes: a hydraulic pump configured to drive the actuator.
Clause 4: The DOWS system of any one or more of clauses 1-3, wherein the actuator includes an electrical motor configured to receive power from a conductor assembly that provides power to an electrical submersible pump (ESP).
Clause 5: The DOWS system of any one or more of clauses 1-4, wherein one or more sensors configured to indicate levelness of the tubular; a controller configured to activate the leveler based on an indication of levelness of the tubular.
Clause 6: The DOWS system of any one or more of clauses 1-5 further including: a fluid separator configured for placement in or adjacent to the leveled tubular and configured to separate the reservoir fluid into production fluid and nonproduction fluid.
Clause 7: An apparatus comprising: a first tubular configured for use in a downhole oil-water separation (DOWS) system and for placement in a segment of a well; first and second support members configured to hold the first tubular at a preferred inclination in the well, wherein the first support member is configured to hold a first end of the first tubular at the preferred inclination inside a second tubular, and the second support member is configured to hold a second end of the first tubular at the preferred inclination inside the second tubular.
Clause 8: The apparatus of clause 7, wherein the first end of the first tubular is closer to an upper inner surface of the second tubular than to a lower inner surface of the second tubular.
Clause 9: The apparatus of any one or more of clauses 7-8, wherein the second end of the first tubular is closer to a lower inner surface of the second tubular than to an upper inner surface of the second tubular.
Clause 10: The apparatus of any one or more of clauses 7-9, wherein the first end is held at a first distance from a bottom surface of the second tubular and the second end at a second distance from the bottom surface of the second tubular.
Clause 11: The apparatus of any one or more of clauses 7-10, wherein the first and second support members include material configured to compress in response to force and expand in absence of force.
Clause 12: The apparatus of any one or more of clauses 7-11, wherein the first and second support members are configured to adjust levelness of the tubular by up to 10 degrees.
Clause 13: The apparatus of any one or more of clauses 7-12, wherein a component may include one or more devices such as a thread, a seal or other apparati at its upper end (left end) and/or lower end (right end) to hydraulically seal and/or mechanically attach it to another tubular or device.
Clause 14: The apparatus of any one or more of clauses 7-13, wherein the leveler may include an actuator that may articulate such that as the actuator articulates, the leveler may be in a nonlevel position.
Clause 15: The apparatus of any one or more of clauses 7-14, wherein the leveler includes a hydraulic pump configured to drive the actuator along its range of motion and wherein the leveler has sensors and uses a controller.
Clause 16: A method comprising: positioning a tubular in a downhole oil-water separation (DOWS) system in a well, wherein the tubular is configured to convey production fluid in the DOWS system; and improving, using a leveling device, an inclination of the tubular.
Clause 17: The method of clause 16, wherein the leveling device includes: an actuator configured to increase the levelness of the tubular by moving the tubular from a nonlevel position to another inclined/level position.
Clause 18: The method of any one or more of clauses 16-17, wherein the leveling device further includes: a hydraulic pump configured to drive the actuator.
Clause 19: The method of any one or more of clauses 16-18, wherein the actuator includes an electrical motor, the method further comprising: receiving power from a conductor that provides power to an electrical submersible pump of the DOWS system; and operating the electrical motor to drive the actuator to increase the levelness of the tubular.
Clause 20: The method of any one or more of clauses 16-18, wherein the improving occurs automatically based on one or input from one more sensors configured to indicate levelness of the tubular, and operations of a controller configured to activate the leveler based on an indication of levelness of the tubular.
Clause 21: The method of any one or more of clauses 16-20 further including: removing a portion of a casing in the well.
Clause 22: The method of any one or more of clauses 16-21, wherein the leveling device includes a positionable tubular configured to contact a casing.
| Number | Date | Country | |
|---|---|---|---|
| 63585881 | Sep 2023 | US |
