REMOVABLE CARTRIDGE FOR A DOWNHOLE FLUID AND SOLID SEPARATION SYSTEM IN A WELL

BACKGROUND

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.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the disclosure may be better understood by referencing the accompanying drawings.

FIG. 1 is a perspective view in partial cross section of a multilateral well system that includes downhole fluid separation, according to some embodiments.

FIG. 2 is side view of an example downhole separation system (including a fluid separator, sediment separator(s), a computer/controller, and sediment injector(s)), according to some embodiments.

FIG. 3A is a sectional view of an elongated Y-block configured for use in a well.

FIG. 3B is a sectional view of a portion of the elongated Y-Block.

FIGS. 3C and 3D are sectional views of flow paths that may be utilized in connection with the elongated Y-block.

FIG. 4 is a sectional view of flow paths in the well.

FIG. 5 is a sectional view of flow paths in the well.

FIG. 6 is a close-up sectional view of the flow paths in the well.

FIG. 7 is a sectional view of the flow paths including profile devices and a deflector.

FIG. 8 is a cross sectional side view of a solids accumulator and solids mover of a hydrocyclone separator in the well.

FIG. 9 is a perspective view of a cartridge including an ESP.

FIGS. 10-11 include a flowchart of example operations for downhole fluid and solid separation, according to some implementations.

FIG. 12 describes operations for removing a device from a well.

FIG. 13 is a perspective view of an example of a Level 5 (mechanical) junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments.

FIG. 14 is a cross-sectional view of an example of a Level 5 junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments.

FIG. 15 is a cross-sectional view of an embodiment where the isolation sleeve can be shifted out of the way (or retrieved) and a deflection device installed to aid in deflecting one or more tools or devices out into a lateral bore, according to some embodiments.

FIG. 16 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS embodiments with a non-Level 5 junction, according to some embodiments.

FIG. 17 is a perspective view of a first example subsea DOWSS, according to some embodiments.

FIG. 18 is a perspective view of a second example subsea DOWSS, according to some embodiments.

FIG. 19 is a perspective view of types of offshore well that may benefit from example implementations, according to some embodiments.

FIG. 20 is a perspective view of an example subsea downhole oil water solids separation, according to some embodiments.

FIG. 21 is a perspective view of example locations in which example embodiments may be used.

DESCRIPTION

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 segments of a well. This also may include inserting and removing devices from the one or more segments of the multilateral well.

The segments of the well may include multiple flow paths. For example, a horizontal segment may include tubulars that divide a wellbore into two flow paths. A first flow path may include a plurality of electric submersible pump (ESP) configured to lift production fluids to the surface. A second flow path may convey fluids downstream into an injection well. Conventionally, a Y-block bifurcates a single flow path into two flow paths. Convention Y-blocks may not be configured to accommodate processes for inserting and/or extracting tools and other devices into and/or out of the plurality of flow paths. In some instances, convention Y-blocks do not create additional space needed for inserting/extracting devices in any of the plurality of flow paths.

Some implementations may enable operators to insert devices into and remove devices from any of the multiple flow paths in a well. For example, some implementations may include an extended Y-block configured to provide space in which devices can be inserted into and/or removed from one or more flow paths. The extended Y-block may be placed uphole of a flow path that includes two ESPs in tandem. Initially, the first ESP (closest to Y-block) may lift production fluid to the surface while the second ESP remains nonoperational. If the first ESP fails, operators may insert a tool into the extended Y-block and to remove the first ESP. After removing the first ESP, the second ESP may begin lifting production fluid to the surface. Hence, some implementations enable operators to remove tools from any flow path in a well.

Some implementations include a cartridge that includes one or more DOWS devices. The cartridge may be configured for insertion into and removal from one of a plurality of flow paths in the multilateral well. The cartridge may include one or more ESPs, oil-water separators, perturbation units, and/or any other devices that may be used in connection with a DOWS system.

In some implementations, the cartridge may be inserted using a tool configured to move through and between flow paths. The tool may interact with profiles that cause the tool to rotate, with deflectors that cause the tool to move between flow paths, and other devices that help the tool move to a desired location in a desired orientation. At the desired location, the tool may insert or remove the cartridge or perform other operations on the cartridge or devices disposed on the cartridge.

Example System

One or more extended Y-blocks, cartridges, and/or other devices described herein may be used in concert with any of the systems and components described herein (even if not shown).

FIG. 1 is a perspective view in partial cross section of a multilateral well system that includes downhole fluid separation, according to some embodiments. FIG. 1 depicts a multilateral well that includes a main bore 102 and a lateral bore 104. The main bore 102 may include an open hole horizontal well. The lateral bore 104 may be an open hole inclined well. Screens 105 may be positioned in the main bore 102 and the lateral bore 104. For example, one of the screens 105 may be positioned in the lateral bore 104 at the point where the formation fluid 118 enters the tubing to prevent the larger solids from even entering the tubing. In some implementations, the screens 105 may prevent larger solids from entering the formation (such as when the formation is being utilized to store non-production fluid). While described as being screens, alternatively or in addition, slotted liners, perforated tubing, etc. may be used to prevent the larger solids from entering the tubing.

In FIG. 1, a system 100 includes a separation system 124 that may include a combination of separators for both fluid and solids (such as sediment). The separation system 124 may include pumps and sediment injector(s). An example of the separation system 124 is depicted in FIG. 2 (which is further described below). A formation fluid 118 from the lateral bore may be drawn into the separation system 124. The separation system 124 may include a fluid separator to separate formation fluid 118. The fluid separator may separate the formation fluid 118 into production fluid (such as hydrocarbons (e.g., oil)) 114 and nonproduction fluid (such as water) 116. The production fluid 114 may be delivered uphole through a production tubing. The nonproduction fluid 116 may be delivered to the main bore 102 for injecting into the surrounding formation. Thus, example implementations may separate the nonproduction fluid downhole such that the nonproduction fluid may be directed back to the formation without any need to pump it back to the surface for separation and any transportation needed for storage.

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. 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 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 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 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 well) to deliver this sediment to the surface of the 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 well or to a different downhole location.

FIG. 2 is side view of an example downhole separation system (including a fluid separator, sediment separator(s), and sediment injector(s)), according to some embodiments. For example, FIG. 2 depicts a separation system 200 that may be an example of the separation system 124 depicted in FIG. 1. The separation system 200 includes a tubing that includes a fluid separator 296, separators 290A-290N, chemical injector(s) 291, a lower pump 292, an upper pump 293, sediment injector(s) 299, a separator 201, a computer 270, and a packer 288. Although shown separate from the other devices in FIG. 2, the computer 270 may be disposed at any suitable location among the devices. The computer 270 may be integrated in any of the devices. The computer may communicate with any of the devices described herein via wireless or wired communication networks. Also, while the separation system 200 is depicted in a given order, example implementations include a separation system with components that are reordered or changed.

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 This may decrease the velocity of the flow of the formation fluid 118—which allows the separation. The fluid separator 296 may comprise a perturbation device (not shown). The perturbation device may introduce turbulence into the fluid. The added turbulence may settle the flow into laminar flow. In particular, most or at least a majority of the production fluid 114 may separate into a flow channel the separator 201, while most or at least a majority of the nonproduction fluid with sediment 294 may separate into a separate lower flow channel of the separator 201. This allows most of the sediment to be captured in the lower portion of the tubing (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 sediment 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). For example, at least one of the sediment separators 290 may be a cyclonic separator—wherein larger (denser) particles in the rotating stream having 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.

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 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 sediment separators 290A-N and/or the sediment injector(s) 299 may comprise one or more components for the storage, transfer, accumulation, measurement, analysis, sensing, detecting, mixing, disposing, etc. and/or injecting, etc. sediments, solids, debris, basic sediments, emulsions, fluids, etc. or combinations thereof. The above one or more components may also be standalone components and/or assemblies or may be combined. The decision of when one or more of the processes should be performed may be based on different criteria. For example, pressure and/or production flow may be monitored at the surface of the 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. One or more processes may be monitored via sensors and analyzed, optimized, improved, and/or controlled by one or more computers/controllers such as computer 270.

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 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, the sediment injector(s) 299 may dispose of these sediments by injecting them into a tubing for delivery to the surface of the 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 being 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 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).

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.

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 injector 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.

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 well may be a target formation. In this implementation, the main bore passes through a target production formation and the lateral bore 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.

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 and the lateral bore, an existing watered out well may be re-entered, and a new lateral added to it. 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 tubing string for the delivery of fluids, sediment, etc. to the surface of the 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 flow tubing. Additionally, while depicting the separation being performed uphole relative to the junction between the main bore and the lateral well, 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, Viscous-based ICD's, etc., Inertial-based ICD's, AIDC's, etc., pumps, regulators, sensors, controllers, relays, transmitters, floats, etc.

Example Devices

All the example devices described herein (such as extended Y-blocks, cartridges, and other devices) 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, an extended Y-block, which may facilitate insertion or removal of devices in the well, may be used with devices such as a flow pipes, solids removers, coalescers, perturbation devices, and other devices.

FIG. 3A is a sectional view of an elongated Y-block configured for use in a well. The elongated Y-block 300 may a working space 302 that facilitates insertion and/or removal of tools in the well. The elongated Y-block 300 may include or otherwise be connected to a first flow path 312, second flow path 304, and third flow path 306. The first flow path 312 may fluidically connect the elongated Y-block 300 to components (such as tanks, containers, and other devices) at the surface. The second and third flow paths 304 and 306 may be fluidically connected to formations, wells, and/or devices downstream of the elongated Y-block 300.

As shown, the third flow path 306 may include an ESP motor and pump assembly 308 (“ESP 308”). However, any device(s) may be disposed in either of the second and/or third flow paths 304 and 306. In some implementations, operators may insert a tool into the working space 302 through the first flow path 312. The tool may pass through the working space 302 into the third flow path 306. The elongated Y-block 300 may include a profile and orienting device 314 configured to cause the tool to rotate into a position suitable to interface with the ESP 308. The tool may mate with a fishing neck 310 of the ESP 308. After mating with the fishing neck 310, the tool may pull the ESP 308 into the working area 302 and up to the surface via the first flow path 312.

In some implementations, ESP 308 may be configured so that one or more components of ESP 308 may be pulled and retrieved separately. In some examples, the motor for ESP 308 may be positioned on top of the pump of ESP 308. The motor for ESP 308 may be releasably connected to ESP 308's pump so that during the retrieving process the motor for ESP 308 may be retrieved by itself if the pulling force (tension) is too great for the wireline (or coiled tubing) being utilized to pull the entire ESP 308. After the ESP pump 308 has been retrieved, the remaining components of ESP 308 may be retrieved.

In some implementations, it may be desirable to use light intervention equipment (e.g., slickline, electric line, trailer-mounted coiled tubing units, etc.) instead of heavy intervention equipment (pulling rigs, workover rigs, drilling rigs, etc.). In these implementations, instead of utilizing heavier and/or longer DOWS assemblies/devices, DOWS assemblies and devices that may be installed in multiple runs. For one example, the ESP 308 may comprise components that may be installed in multiple runs. As an example, the inner and outer components of the pump (inner part may comprise the shaft and/or impellers parts while the outer part may comprise the housing, etc.). In another example, the motor, seals, sensors, and/or energy transfer mechanism, etc. may be run in one or more trips and then connected to the pump.

In some implementations, it may be desirable to have a downhole power cable for the Well System 100, and/or DOWS system's components (e.g., electric motors for the pumps), etc. to be run on the outside of tubing 106 or similar conduit. The power cable may comprise one or more of an electrical lines for power transmission, one or more electrical line(s) for at least one of data, sensor and control information transfer, one or more hydraulic line(s) for transmission at least one of power transmission and/or control signals to/from one or more downhole components, one or more fiber optic lines for transmission of data, sensor and/or control signals, one or more other energy transmission devices, a transformer, a transducer, and/or a combination thereof. FIG. 3B is a sectional view of a portion of the elongated Y-Block. In some implementations, the elongated Y-block 300 may be configured to comprise at least one Energy Transfer Device (ETD) 318 for the connection of the one or more downhole power cables extending from the surface or other uphole location (e.g., subsea wellhead, etc.). The elongated Y-block 300 may comprise at least one path approximately parallel to the working space 302. In some examples, the working space 302 may consist of an elongated profile in order to make room for a path for one or more downhole power cables 316 that may be connected to the ETD 318. In some examples, the downhole power cables 316 may be affixed to the elongated Y-Block near the uphole end near the proximity of the first flow path 312.

In some examples the ETD 318 may be affixed to the elongated Y-Block near the motor of ESP 308.

In some examples the ETD 318 via the elongated Y-block 300 may transfer energy from a downhole power cable to one or more downhole device(s) including, but not limited to, a DOWS system component, a system 124, an ESP such as 308 and/or another ESP such as 402, etc.

In some implementations, the ETD 318 may be referred to as a Wet Mate or a Wet Mateable connector. Wet mateable connectors are of a type that can be connected while downhole while exposed to wellbore fluids, etc.

In some implementations, the ETD 318 may transfer electrical energy via wireless energy transfer which is transmission of electrical energy without wires as a physical link. One or more wireless transfer technologies may be used including, but not limited to, inductive coupling, resonant inductive coupling, capacitive coupling, etc.

In some examples, the ETD 318 may transfer electrical energy via physical contact (electrical, mechanical, fluidic, optical, etc.). Electrical contacts may require sheaths and/or wipers to protect and/or clean the contact area prior to and/or during the connecting process and/or during/after the disconnection process. Electrical contacts may require insulators to protect the contacts from electrically arcing before, during and after the connecting process. Hydraulic contacts may require sleeves and/or seals to protect, seal, and/or clean the contact area prior to and/or during the connecting process and/or during/after the disconnection process. Fiber optic contacts may require sheaths and/or wipers to protect and/or clean the contact area prior to and/or during the connecting process and/or during/after the disconnection process. Fiber optic contacts may require resealable covers to protect the fiber optic ends (contacts) from debris, etc. before, during and after the connecting process. In some examples, the elongated Y-block 300 may have one or more ETDs for one or more electric motor/actuator, and/or one or more hydraulic motor/actuator, and/or one or more sensor of one or more types of sensors, including sensors/detectors to detect one or more of at least: a pressure change indication, a flow change indication, an electrical signal indication, a magnetic indication, an inductive indication, a conductive indication, a temperature change indication, a position change indication, a time change indication, an acoustic indication, a vibrational indication, a mechanical indication, a wireless signal indication, a light signal indication, a stress indication, a strain indication, a force indication, a gamma ray indication, a radioactive indication, an energy level indication, a mass property indication, a fluid property indication, and a gas property indication.

In some implementations, the elongated Y-block 300 may be configured to house one or more DOWS devices; each may be pulled in one or more ways. For example, the equipment may be pulled via a “trap door” that can be opened and closed via a coil tubing tool. When the door is open, the tool may be pulled out of its location and retrieved to the surface for repair/replacement.

In some implementations, the working space 302 is large enough to accommodate a device suitable to cause the tool to move upward into the second flow path 304. Hence, the tool may insert and/or remove devices from any of the flow paths 304 and 306.

FIGS. 3C and 3D are sectional views of flow paths that may be utilized in connection with the elongated Y-block. In some implementations, the elongated Y-block 300 may have one or more non-round flow paths (e.g., D-shaped flow paths). The separate flow paths may allow for 1) increased flow area, 2) greater separation area, 3) greater separation/oil-water contact interface prior to entering one or more separators or entering one or more pumps, or one or more ESPs/PCPs, etc. The D-shaped flow paths may include a water injection flow path, a water-cut flow path, and a water injection flow path.

FIG. 4 is a sectional view of flow paths in the well. More specifically, FIG. 4 shows a downhole segment of the flow paths 304 and 306. The flow path 306 includes the ESP 308 (“the first ESP 308”) and a second ESP motor and pump assembly 402 (“second ESP 402”). In some implementations, the first ESP 308 may propel fluids through the flow paths 304, 306, and 312, while the second ESP 402 may remain inoperative. If the first ESP 308 fails, it may be removed, and the second ESP 402 may be activated. In some implementations, both ESPs 308 and 402 may operate simultaneously, where the second ESP 402 pumps water to cool the first ESP 308 and to an injection zone in the well. The first ESP 308 may pump oil to the surface.

In some implementations, oil flowing uphole in the flow path 304 may pass through an oil inlet 408 and into the flow path 306. After passing through the oil inlet 408, the fluid may flow into the first ESP 308 and uphole to the flow path 312. A first plug 410 may block flow in the flow path 306, causing the oil to pass through the oil inlet 408 (as noted). As the fluid flows through the oil inlet 408, a second plug 406 may prohibit the fluid from flowing downhole toward the second ESP 402.

FIG. 5 is a sectional view of flow paths in the well. As shown, the flow path 306 includes the ESP 402. As shown, the flow path 304 may operate as an oil inlet line 510 through which oil moves uphole in the well. The flow path 306, or parts thereof, may operate as a water inlet line 512 through which water moves into the ESP 402. The ESP 402 may include a primary discharge port 504 configured to inject water into an injection zone (downhole-rightward in FIGS. 3-7) or other part of the well (downhole). Any suitable conduit may be used to fluidically connect to the primary discharge port 504 to the injection zone. One or more conduits suitable for conveying water or other fluids to the injection zone or other locations may be disposed in the annular space 516. In some examples, the one or more conduits may convey water or other fluids to one or more injection zone(s) or other location(s) located above (e.g., uphole) or both above and below the ESP 402. The ESP 402 also may include a secondary discharge port 508 configured to inject water into the injection zone or other part of the well. The ESP 402 also may be configured to circulate water or other fluid to the ESP 308 (disposed uphole in the flow path 304). Other devices 514, such as electrical conduits, hydraulic pumps, etc., may be disposed near the water inlet line 512 of the ESP 402 or in other suitable locations near the ESP 402. An additional ESP may be included to work in tandem with the ESP 402, etc., or to function as a backup to the ESP 402 when ESP 402 is shut down for maintenance, repairs, servicing, replacement of components, etc. Other additional devices such as ESP 308, devices 514, 290, 299, 293, 292, 291, 270, 296, etc. also may be included to act as backups or to distribute the duties to improve reliability and/or to increase the life one or more components, systems, and/or system 100, system 124, system 200, and/or other system disclosed below.

The elongated Y-block 300 may include or otherwise be connected to a first flow path 312, second flow path 304, and third flow path 306. The flow paths may include one or more inlet flow paths such as: second flow path 304 for fluids 510 and/or third flow path 306 for fluids 512 The flow paths may include one or more outlet flow paths such as: first flow path 312 for, at least, production fluid 114, primary discharge port 504 and other devices 514 for disposing nonproduction fluid 116.

The flow paths may include cross flow ports and profiles to receive plugs, such as: an oil inlet 408. Oil flowing uphole in the flow path 304 may pass through an oil inlet 408 and into the flow path 306. A first plug 410 may block flow in the flow path 306, causing the oil to pass through the oil inlet 408. A second plug 406 may prohibit the fluid from flowing downhole toward the second ESP 402.

As noted, there may be conduits for electrical (power and sensing) and other energy transmission lines. Other devices 514, such as electrical conduits, hydraulic pumps, etc., may be disposed near the water inlet line 512 of the ESP 402 or in other suitable locations near the ESP 402 (also see FIG. 21 and discussion thereof).

There may be a trap door. In some implementations, the elongated Y-block 300 may be configured to house one or more DOWS devices; each may be pulled in one or more ways. For example, the equipment may be pulled via a “trap door” that can be opened and closed via a coil tubing tool. When the door is open, the tool may be pulled out of its location and retrieved to the surface for repair/replacement.

FIG. 6 is a close-up sectional view of the flow paths in the well. As shown, the ESP 402 may reside in the flow path 306. The ESP 402 may include an emergency release valve 602.

In some implementations, a controller/computer 270 (downhole and/or at the surface of the well) may be communicatively coupled to the first ESP motor and/or pump 308, the second ESP motor and/or pump 402, one or more valves used to control the flow and/or pressure of one or more fluids in well system 100, sediment system 124 and/or one or more components thereof including, but not limited to solids accumulator (e.g., a component of sediment separator 290N and/or 806, etc., and/or the solids mover that is a component of sediment injector 299 and/or 804, etc., and other components (e.g., coalescers, perturbation devices, foils, flow diverters, actuators, speed controllers, flow sensors, pressure sensors, sensors, etc.) such that the computer 270 may initiate one or more sequences to adjust, diagnose, test, repair, maintain, etc. one or more of a first ESP motor and/or pump 308 and/or its components and/or related assemblies and sensors, the second ESP motor and/or pump 402 and/or its components and/or related assemblies and sensors, one or more valves used to control the flow and/or pressure of one or more fluids in well system 100, sediment system 124 and/or one or more components thereof, hydrocyclone 802, solids accumulator 806, and/or solids mover 804, coalescers, perturbation devices, foils, flow diverters and/or related assemblies and/or components.

In some implementations, the computer 270 is communicatively coupled to system 100, separation system 124, separation system 200, separator system 600, y-block 300, ESP 308, ESP 402, etc., and/or their related components and assemblies, and/or one or more components of the systems 100, 124, 200, 600, 800, 1208, 1802, 1820, 1832, 1908, 1912, 2006, 2008, 2020, 2026, 2028, 2024, 2022, etc., and other systems/components described within this document and related documents, etc.

For one example, the computer 270 may control one or more parameters of first ESP 308's motor and/or pump, the second ESP 402's motor and/or pump, the solids accumulator and/or the solids mover that is a component of sediment injector 299, the sediment separator(s) 290A-290N, etc. to increase the life of the ESP 308, ESP 402, separator system 124. In other words, the ESP 308, ESP 402, the solids mover that is a component of sediment injector 299, sediment separator 290A-290N, etc. their components, separation system 124, its components, and system 100 will operate longer and more efficiently by specifically having the computer 270 monitoring, controlling, diagnosing, and maintaining ESP 308, ESP 402, the solids mover that is a component of sediment injector 299 and/or solids accumulator that is a component of sediment injector 299.

Continuing with this example of ESP 308, the computer 270 may address one or more specific conditions or problems with ESP 308. For example, computer 270 may monitor the temperature of ESP 308. If the temperature is too high. The computer 270 may send a signal to ESP 308 to reduce the speed of the motor. Computer 270 will continue to monitor the temperature of ESP 308.

Continuing with the above example, if the temperature of ESP 308 is low, it may mean the sediment separating process can be increased.

On the other hand, if the temperature of ESP 308 is too high, the computer 270 can perform one or more activities similar to the following within a short amount of time (e.g., microseconds, milliseconds, seconds, minutes, etc.): 1) instantaneously detect the increase in temperature of ESP 308, 2) adjust the motor speed of ESP 308, 3) and then, check again the temperature and/or power consumption of ESP 308, 4) the computer 270 may quickly determine (e.g., in microseconds, milliseconds, seconds, minutes, etc.) if a positive (desirable/good) change in the temperature and/or electrical power demand of the ESP 308 has occurred. This determination may be made quickly to avoid damage or catastrophic failure to the ESP 308, or other components of the DOWs system and/or to another of the well's components. At this point, the computer 270 can determine whether to: change the ESP's (308) motor speed again, or maintain the ESP 308's motor speed, and input data into an AI/ML processor or algorithm and/or another device for data analysis and/or storage; perform data analysis, which may happen the fastest if performed by computer 270's on-chip or on-board processor and algorithm. Saving time may be critical to prevent equipment failure in fast-moving devices such as motor of ESP 308, the DOW's pump, etc.); and/or read output data/instructions from the AI/ML processor or algorithm and/or another device. The computer 270 also may perform another action based upon data analysis of computer 270, and/or one or more other inputs (e.g., computed analysis, human intervention, etc.), adjust one or more variables in the computer 270's instructional software, and/or adjust the code (instructions) in the computer 270's instructional software, etc. If a negative (undesirable/bad) change in the electrical power demand or temperature of the ESP 308 has occurred the computer 270 may quickly (e.g. in microseconds or milliseconds) determine whether to: change the ESP 308's motor speed again, or maintain current motor speed, or enter a diagnostic mode to determine reason(s) why electrical power demand, and/or the temperature, of the ESP 308 is at an undesirable level.

The computer 270 may include a diagnostic mode. The diagnostic mode may include: determining if one or more components are worn, damaged, or in a non-normal state, etc. by conducting one or more tests (e.g., run ESP 308 and/or other components such as the solids mover of 290A, etc.) The tests may include checking flowrate versus speed at various speeds, check for vibrations at various speeds, etc. The computer 270 may analyze tests results. This may be performed fastest if performed by computer 270's on-chip or on-board processor and/or algorithm.

The computer 270 may perform troubleshooting/maintenance testing which may include one or more of the following: a) Backflush solids mover of 290A and/or system to clear trapped debris or eliminate a gas lock, etc. Inject grease/lubricant in area(s) that may require lubrication for longer life, etc.) Inject sealant to repair gaskets, etc. c) Replace worn parts (e.g., motor bearings, motor, pump, auger blades, nozzles, bushings, liners, etc.) d) Change rating parameters of ESP 308 to reduce further wear, etc. Analyze troubleshooting and/or maintenance results via computer 270's on-chip/on-board processor and/or algorithm. e) Shut down auger/ESP 308's motor/system 124/etc. f) Transfer duties to a backup pump/motor/system (either temporarily or long term). g) Notify operator (supervisory computer, human, etc.) of condition(s) and actions taken. h) Perform other actions, analysis, function(s) to aid in returning the existing, or repaired, or replaced ESP 308/system to a better state (e.g., higher operating efficiency, increased processed sediments/solids, etc.) i) Input data into computer 270's onboard AI/ML/Processor device and algorithm and/or another device for data analysis and/or storage, j) Perform data analysis via computer 270's on-chip or on-board processor and/or algorithm. k) Read output data from computer 270 and/or another device. l) Perform another action based upon data analysis of computer 270, and/or one or more other inputs (e.g., computed analysis, human intervention, etc.), adjust one or more variables in the computer 270's instructional software, adjust the code (instructions) in the computer 270's instructional software, etc. m) Perform another activity/function via computer 270 with the update instructions/computer code. n) Exit computer 270's Diagnostic mode. o) Perform an emergency shutdown command by computer 270. p) Perform another action controlled by computer 270. q) Exit computer 270's Diagnostic mode. r) Return to monitoring mode.

The above example indicates how the computer 270 may increase the life of system 100, separation system 124, ESP 308, and/or one or more components of the systems 100, 124, ESP 308. Computer 270 is able to monitor, control, diagnose, maintain and repair, etc., said systems and component to prevent premature failure.

The above example also exemplifies how computer 270 may increase the efficiency of ESP 308, and/or systems 124, and/or 100 and their respective components. As noted, computer 270 may monitor, adjust, optimize the ESP, and/or the systems and the components to achieve one or more goals (e.g., maximize fluid production, reduce operating costs, increase life, etc.).

The computer/controller 270 may comprise devices, hardware, software, etc. including but not limited to: switches, power supplies, connectors, transmission lines, logic devices, software, hardware, artificial intelligence, machine learning, algorithms, and other devices known and not known in the current realm of controls, computers, material processing, energy industry, etc. FIGS. 2, 3-7, 8, 9, 13, 14-15, 16, 17, 18, 19, 20, and 21 provide examples of other processes and components that may be monitored, controlled and optimized by sensors and computer/controller 270.

FIG. 7 is a sectional view of the flow paths including profile devices and a deflector. As shown, the Y-block 300 may be used in concert with profile devices 702. The profile devices 702 may be configured to contact a tool moving through the Y-block 300 and to cause the tool to rotate. The profile devices 702 may be disposed in any suitable location on a surface inside the casing, tubular, or other device in the well.

As shown, the Y-block 300 may be utilized in connection with the flow paths 304 and 306. In some implementations, a deflector 704 may be placed in a flow path to cause the tool to move into another flow path. For example, as shown, the deflector 704 resides in the flow path 306. As the tool moves through the Y-block 300, it may hit the deflector 704 and move upward into the flow path 304. The profile devices 702 (also referred to as “profiles”) and the deflector 704 may be used to facilitate insertion or removal of a cartridge or other devices in the well. FIG. 8 is a cross sectional side view of a solids accumulator and solids mover of a hydrocyclone separator in the well. As shown, a separation system 800 (that may be representative of separation system 200 described in FIG. 2) may reside inside a casing 808. The separation system 800 that may include the flow paths 304 and 306, where a hydrocyclone 802 (or any other suitable cyclonic solid separator) and a solids accumulator 806 configured with a solids mover 804 may be positioned in the flow path 306. In some implementations, the solids accumulator 806 and/or the solids mover 804 may become damaged, worn, etc. and need to be repaired and/or replaced. For example, the solids accumulator 806 and/or the solids mover 804 may become worn due to the abrasiveness of the sediment passing through the components. Thus, the solids accumulator 806 and the solids mover 804 may be removed from the downhole oil-water-separator system 800 for repair, while the downhole oil-water-separator system 800 and corresponding components (such as the hydrocyclone 802) may remain in position in the well. An insertion and removal tool 812 (“tool 812”) may be coupled to the distal end of a deployment mechanism 814 (such as coiled tubing, wireline, jointed pipe, etc.). The tool 812 may be deployed in the well and into the flow path 304. The tool 812 may retrieve the solids accumulator 806 configured and the solids mover 804 from its initial position 803 in the flow path 306. The solids accumulator 806 configured and the solids mover 804 may then be transported to the surface via the tool 812. In some implementations, the separation system 800 may be configured with an access panel between the flow path 304 and the flow path 306 where the solids accumulator 806 may be transferred through when being replaced/installed. In some implementations, the tool 812 may be configured to open and/or shut the access panel.

In some implementations, a controller/computer 270 (downhole and/or at the surface of the well) may be communicatively coupled to the separation system 800, the one or more valves controlling flow from/to flow paths 304 and 306, the hydrocyclone 802 and the solids accumulator 806, the solids mover 804 and/or systems and components associated with the separation system 800 (e.g., coalescers, perturbation devices, foils, flow diverters, actuators, speed controllers, flow sensors, pressure sensors, sensors, motors, prime movers, power supplies, conduits, etc.) such that the computer 270 may initiate one or more sequences to adjust, diagnose, test, repair, maintain, etc. one or more of the aforementioned components, systems, or associated systems and components.

In some implementations, the computer 270 is communicatively coupled to separation system 800 and/or associated systems/components mentioned within this document and related documents, etc.

For one example, the computer 270 may sense one or more conditions via one or more sensors, and control one or more parameters of solids accumulator 806 in order to increase the life of the separation system 800, ESP 308, ESP 402, separator system 124, etc. In other words, the separation system 800, ESP 308, ESP 402, solids mover 800, its components, separation system 124, its components, and system 100 will operate longer and more efficiently by specifically having the computer 270 monitoring, controlling, diagnosing, and maintaining separation system 800, ESP 308, ESP 402, solids mover 800 and/or solids accumulator 806, etc.

Continuing with this example, the computer 270 may address one or more specific conditions or problems with solids accumulator 806. For example, computer 270 may monitor the height of solids in solids accumulator 806 and the power required to fill and/or empty solids accumulator 806. If the solids level is too high, the computer 270 may send a signal to one or more sediment separators 290, solids mover 804, and/or sediment injector(s) 299 (FIG. 2) to transfer and/or inject solids. These events may be performed in a similar fashion as described in Blocks 1102-1112.

Continuing with the above example, if the height of solids in solids accumulator 806 is low and the power required to fill/empty solids accumulator 806 via solids mover 804 is within a normal operating range, it may mean the sediment separating process can be increased.

On the other hand, if the height of solids in solids accumulator 806 is low and the power required to fill/empty solids accumulator 806 via solids mover 804 is too high, the computer 270 can perform one or more activities such as the following within a short amount of time (e.g., microseconds, milliseconds, seconds, minutes, etc.): instantaneously detect the increase in power consumption of solids mover 804, adjust the motor speed of solids mover 804, and then, check again the temperature and/or power consumption of solids mover 804.

The computer 270 may quickly determine (e.g., in microseconds, milliseconds, seconds, minutes, etc.) if a positive (desirable/good) change in the temperature and/or electrical power demand of the solids mover 804 has occurred. It is essential to decide quickly to avoid damage or catastrophic failure to the solids mover 804, or other components of the DOWs system and/or to another of the well's components.

At this point, the computer 270 can, for example, determine whether to: Change solids mover 804's motor speed again, or maintain the solids mover 804 speed, and, input data into an AI/ML processor or algorithm and/or another device for data analysis and/or storage, perform data analysis, which will happen the fastest if by performed by computer 270's on-chip or on-board processor and algorithm. Saving time may be critical to prevent equipment failure in highly loaded devices such as the solids mover 804, the DOW's pump, etc.), read output data/instructions from the AI/ML processor or algorithm and/or another device, perform another action based upon data analysis of computer 270, and/or one or more other inputs (e.g., computed analysis, human intervention, etc.), adjust one or more variables in the computer 270's instructional software, and/or adjust the code (instructions) in the computer 270's instructional software, etc.

If a negative (undesirable/bad) change in the electrical power demand or temperature of the solids mover 804 has occurred, the computer 270 may quickly (e.g. in microseconds, milliseconds, seconds or minutes) determine whether to: change the auger speed, or maintain current auger speed, or enter a diagnostic mode to determine reason(s) why electrical power demand, and/or the temperature, of the solids mover 804 is at an undesirable level.

The computer 270 may implement a diagnostic mode that may include determining if one or more components are worn, damaged, or in a non-normal state, etc. by conducting one or more tests (e.g. run solids mover 804 and/or other components (e.g., hydrocyclone 802, etc.) through a few tests (e.g. check torque versus speed at various speeds, check for vibrations at various speeds, etc.) The computer 270 may analyze test results. This may be performed fastest if performed by computer 270's on-chip or on-board processor and/or algorithm.

The computer 270 may perform troubleshooting/Maintenance tests which may include one or more of the following: a) Reverse solids mover 804 and/or system to clear trapped debris, etc. b) Inject grease/lubricant in area(s) that may require lubrication for longer life, etc. c) Change operating parameters of solids mover 804 to reduce further wear, etc. d) Analyze troubleshooting and/or maintenance results via computer 270's on-chip/on-board processor and/or algorithm, Shut down auger/solids mover 804/system 124/system 100, etc. e) Transfer duties to a backup auger/motor/system (either temporarily or long term). f) Detect certain parts that may need to be replaced. Signal operator, supervisor computer system, etc. to replace worn parts (e.g., augur, augur bearings, auger blades, nozzles, bushings, liners, etc.). g) Monitor all systems and parameters during replacement of worn parts with tool 812 as described above and below. h) Notify operator (supervisory computer, human, etc.) of condition(s) and actions taken. i) Perform other actions, analysis, function(s) to aid in returning the solids mover 804/system(s) online. j) Input data into computer 270's onboard AI/ML/Processor device and algorithm and/or another device for data analysis and/or storage. k) Perform data analysis via computer 270's on-chip or on-board processor and/or algorithm. l) Adjust parameters so new/repaired components of solids mover 804, solids mover 804 and/or system operate at an improved state (e.g., higher operating efficiency, increased processed sediments/solids, etc.). m) Utilize the computer's onboard AI/ML/Processor device(s) and/or algorithm(s) to adjust one or more variables or instructions (e.g., code) in the computer 270's instructional software in the computer's instructional software, memory, etc. n) Perform another activity/function via the computer 270 with the update instructions/computer code. o) Perform other actions, analysis, function(s) to aid in returning the solids mover 804/system(s) 800, 124, 100, etc. to a better state (e.g., higher operating efficiency, increased processed sediments/solids, etc.). p) Notify operator (supervisory computer, human, etc.) of condition(s) and actions taken. Input data into computer 270's onboard AI/ML/Processor device and algorithm and/or another device for data analysis and/or storage. q) Perform data analysis via computer 270's on-chip or on-board processor and/or algorithm. r) Adjust parameters of the components of solids mover 804, solids mover 804 and/or system(s) to operate at an improved state (e.g., higher operating efficiency, increased processed sediments/solids, less wear, increased life, etc.). s) Utilize computer 270's onboard AI/ML/Processor device(s) and/or algorithm(s) to adjust one or more program variables or instructions (e.g., code) in the computer 270's software, program(s), memory, etc. t) Perform another activity/function via the computer 270 with the update instructions/computer code. u) Exit the computer's Diagnostic mode. v) Perform an emergency shut down command from the computer 270. w) Perform another action controlled by the computer 270. x) Exit the computer's Diagnostic mode. y) Return to monitoring mode.

The above example indicates how the computer 270 may increase the life of system 100, separation system 124, separation system 800, solids mover 804, and/or one or more components of the systems 100, 124, separation system 800, solids mover 804. The computer 270 is able to monitor, control, diagnose, maintain, replace, and repair, etc., said systems and component to prevent premature failure.

The above example also indicates how the computer 270 may increase the efficiency of separation system 800, solids mover 804, and/or systems 124, and/or 100 and their respective components. As noted, computer 270 may monitor, adjust, optimize solids mover 804, and/or the systems and the components to achieve one or more goals (e.g., maximize fluid production, reduce operating costs, increase life, etc.).

The computer/controller 270 may comprise at least one of devices, hardware, software, etc. including but not limited to: switches, power supplies, connectors, transmission lines, logic devices, software, hardware, artificial intelligence, machine learning, algorithms, and other devices known and not known in the current realm of controls, computers, material processing, energy industry, etc.

The one or more computers/controllers 270 may comprise one or more of devices, components, hardware, software, artificial intelligence devices, artificial intelligence algorithms, machine learning devices, and/or machine learning algorithms, algorithms to increase the life of one or more components/systems of systems 100, 124, separation system 800, solids mover 804, etc. The computer 270 may monitor, control, diagnose, maintain, replace, and repair components and systems of system 100, etc., to improve the efficiency of one or more processes/objectives (higher fluid injection, lower power consumption, etc.). The computer 270 is capable of having its algorithm(s)/software/etc., updated/optimized via the above stated devices and/or algorithms which will also improve the efficiency of the systems and component related to System 100 and provide for a longer life.

FIG. 9 is a perspective view of a cartridge including an ESP. The cartridge 902 may be inserted into the working space 302 of the elongated Y-block 300 by the tool 812. The tool 812 may work in concert with profiles and/or diverters that direct the tool to a desired location (such as in the flow path 306). After insertion, the cartridge 902 may be removed using the tool 812. In some implementations, devices may be included in cartridges that are inserted into flow paths in the well. The cartridges may include any devices used in the DOWS system such as ESPs, components of a separation system (e.g., see FIGS. 2 and 9), perturbation units configured to settle turbulent flows into laminar flows, coalescers, perturbation devices, foils, flow diverters, or any other suitable device. In some implementations, the device itself (and not a cartridge) may be configured for insertion and removal according to the techniques described herein. For example, one or more ESPs may be suitable for insertion and removal from a flow path as described herein.

Example Operations

All the example devices (such as cartridges, Y-blocks, and other devices) 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, an extended Y-block, which may be used to facilitate insertion and/or removal of devices in the well, may be used with devices such as a flow pipes, solids removers, coalescers, perturbation devices, and other devices.

Example operations are now described. FIGS. 10-11 include a flowchart of example operations for downhole fluid and solid separation, according to some implementations.

At block 1002, production is initiated. For example, with reference to FIGS. 1-2, production may be initiated by the formation fluid 118 entering the main bore 102 and/or the lateral bore 104.

At block 1004, formation fluid is received into a downhole separation system. For example, with reference to FIGS. 1-2, the formation fluid 118 may be received into the separation system.

At block 1006, flow of formation fluid is separated into one or more flow paths. For example, with reference to FIGS. 1-2, the formation fluid 118 may flow into the fluid separator 296, wherein 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. Accordingly, if the formation fluid is at least partially segregated into oil-cut and water-cut, example implementations may take advantage of such a segregation to separate these fluids into two flow paths. Lower-density (oil-cut) fluids may flow through a top flow path. Higher-density (water-cut) may flow through a bottom flow path.

At block 1008, the flow rate decreases. For example, with reference to FIG. 2, 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 allows most of the sediment to be captured in the lower portion of the tubing 287 (below the separator 201). Accordingly, example implementations may reduce flow from a high-turbulent flow to a slower, less turbulent flow. Example implementations may provide more flow area (an increased pipe inner diameter, increased wellbore size, multilateral wellbore for settling ponds, distributing flow, etc.). Example implementations may also provide more time (start and stop flow, slow pumping action, etc.)

At block 1010, flow is modified to decrease turbulence. For example, example implementations may also stabilize 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 1012, flow is separated into one or more flow paths. For example, with reference to FIG. 2, the formation fluid 118 may be separated into one or more flow paths via the fluid separator 296. Such separation may be applicable to different flows (e.g., formation fluids, oil-cut, water-cut, gas, liquid, liquid-gas, slurries (solids-laden fluids, production fluids, fluids to be disposed, fluids to be injected, etc.).

At block 1014, gravitational separation is performed. For example, with reference to FIG. 2, the fluid separator 296 may comprise a gravity-based separation that includes the separator 201.

At block 1016, non-gravitational separation is performed. For example, with reference to FIG. 2, the formation fluid 118 may be separated using different types of non-gravitational operations.

At block 1018, stepped-sized separation is performed. For example, with reference to FIG. 2, the sediment separators 290A-290N may separate the sediment 294 from the nonproduction fluid 116. For example, the sediment separators 290A-290N may separate out the largest or densest solids first, then separate out the next largest or densest solids, etc. Example implementations may include allowing for settling and separation of solids to separate from fluid stream(s). Additionally, example implementations may allow time for the largest and/or densest solids to settle out from fluids. Example implementations may also allow lower flow rates to assist with the separation. Example implementations may use the sediment separators 290A-290N to allow the largest and/or densest solids to settle out, accumulate and be trapped. Example implementations may include allowing time for lighter fluids and gases to begin to segregate and separate from heavier fluids. Example implementations may include means, methods, and devices to subject one or more fluids to one or more force, acceleration, path (e.g., tortuous path, etc.), velocity, pressure, restriction (e.g., screen opening(s), screen size, nozzle, etc.), time, impulse, change in one or more of the above including step change, gradual change, etc. Example implementations may separate based on at least one of density, size, shape, surface tension, molecular makeup, other chemical, physical, molecular, electron properties, etc.

At block 1020, solids and lighter fluids are accumulated. For example, with reference to FIG. 2, the different sediment separators 290A-290N may accumulate the sediment.

Operations of the flowchart 1000 continue at transition point A, which continues at transition point A of FIG. 11. From transition point A of FIG. 11, operations continue at block 1102.

At block 1102, solids are separated and discharged into temporary holding tanks. For example, with reference to FIGS. 1-2, the different sediment separators 290A-290N may include temporary holding tanks for storing the separated out solids. Example implementations may include utilizing an auger, drag chain, an inclined plane, a jetting device, etc. to keep the solids or slurry from accumulating at the discharge end of the solid separation device which may cause the device to plug and become inoperable.

At block 1104, solids are transported for disposal. For example, with reference to FIG. 2, 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.

At block 1106, solids are transported to an injector. For example, with reference to FIGS. 1-2, the sediment may be transported to the sediment injectors 299.

At block 1108, solids may be mixed at the injector. For example, with reference to FIG. 2, the sediment 295 may be mixed at the sediment injector 299. For example, the sediment 295 may be mixed with fluid (such as production fluid, nonproduction fluid, etc.). In some implementations, one or more type of mixers may be used. For example, a mechanical mixer, a fluid-type mixer, etc. may be used to mix the sediment 295 with fluid. In some implementations, solids may be stored in or near the injector 299 so that mixing may progress smoothly or consistently at a defined rate. For example, the solids may be stored in an enclosed tank, gravity-fed tank, auger-fed tank, etc.

At block 1110, solids (or slurry) are injected. For example, with reference to FIGS. 1-2, 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 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).

At block 1112, solids-laden fluid is transported. For example, with reference to FIGS. 1-2, the sediment injector(s) 299 may dispose of these sediments by injecting them into a tubing for delivery to the surface of the 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 being 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.

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 1114, injection process is monitored and controlled. For example, with reference to FIGS. 1-2, controllers may be coupled to the sediment injectors 299 for monitoring and controlling the injection and disposal of the sediment (either to the surface of the wall or to a disposal location downhole).

Operations of the flowchart 1100 continue at transition point B, which continues at transition point B of FIG. 12. From transition point B of FIG. 10, operations return to operations at block 1004.

FIG. 12 describes operations for removing a device from a well. At block 1202, a tool is inserted into a working space of an extended Y-block residing in a horizontal wellbore, wherein the extended Y-block leads into a plurality of flow paths in the horizontal wellbore. At block 1204, the tool is guided into a first flow path of a plurality of flow paths. At block 1206, the tool interfaces with a device disposed in the first flow path. At block 1208, the tool is pulled through the working space and up to the surface.

Example Wells

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 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 embodiments, 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, FIG. 13 is a perspective view of an example of a Level 5 (mechanical) junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments. FIG. 13 depicts a system 1300 having a multilateral well that includes a main bore 1301, a lateral bore 1350, and a lateral bore 1351. Formation fluid 1302 from the surrounding subsurface formation enters the main bore 1301. The formation fluid 1302 is transported through the main bore 1301 uphole to a level 5 monolithic Y-block 1304 and into a DOWSS 1308.

The DOWSS 1308 may process the formation fluid 1302 to separate out nonproduction fluid 1306 from production fluid 1322. The DOWSS 1308 may also process the formation fluid 1302 to separate sediment from at least one of the nonproduction fluid 1306 or the production fluid 1322. The DOWSS 1308 may transport the nonproduction fluid 1306 into the lateral bore 1350 for disposal in a disposal zone 1320 for the nonproduction fluid 1306 in the subsurface formation around the lateral bore 1350. The DOWSS 1308 may also transport sediment 1325 into the lateral bore 1351 for disposal in a disposal zone 1324 for the sediment 1325 in the subsurface formation around the lateral bore 1351. The DOWSS 1308 may also transport the production fluid 1322 and sediment 1310 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.

FIG. 14 is a cross-sectional view of an example of a Level 5 junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments. In this embodiment, a main bore junction 1410 is used to provide a main bore 1402 for large tools to be passed through, or landed, in the y-block and/or main bore area of the junction 1410. A lateral bore 1404 is formed off the main bore 1402 at the junction 1410. In the example shown, an isolation sleeve 1470 may be landed in the junction. As shown, the isolation sleeve 1470 may provide pressure isolation between the formation fluids 1406 and the nonproduction fluids 1408. This main bore junction 1410 may be used with a variety of different Downhole Oil Water Separator Systems (DOWSS) and/or components including the DOWSS and/or its components disclosed within herein. The main bore junction 1410 may have a main bore leg inside diameter (ID) of 30% the outer diameter (OD) of the Junction's Y-Block. The main bore leg's ID may be 40% the OD of the Junction's Y-Block. The main bore leg's ID may be 50%, 53%, 55%, 60%, 67% or more of the Junction's Y-Block OD.

FIG. 15 is a cross-sectional view of an implementation where the isolation sleeve can be shifted out of the way (or retrieved) and a deflection device installed to aid in deflecting one or more tools or devices out into a lateral bore. FIG. 15 depicts a main bore 1502 and a lateral bore 1504 that is formed off the main bore 1502 at the junction 1510. An isolation sleeve 1570 may be shifted out of the way (or retrieved) to allow for a deflection device to be installed to aid in deflecting one or more tools or devices out into the lateral bore 1504. In some implementations, a tool may be inserted into the flow paths in the well to remove the isolation sleeve 1570. The process for removing the isolation sleeve 1570 may involve any one or more of the techniques and devices described herein.

FIG. 16 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS embodiments with a non-Level 5 junction, according to some embodiments. In this example, the multilateral well is producing from a lateral bore 1604 (instead of the main bore 1602) so the earthen junction is not over-pressure by fluid being injected in its surroundings. Formation fluid 1606 is being produced from a subsurface formation surrounding the lateral bore 1604. A DOWSS 1670 may receive the formation fluid 1606 and separate the formation fluid 1606 into a nonproduction fluid 1608, a sediment 1672, and a production fluid 1674. As shown, the nonproduction fluid 1608 may be disposed of downhole by being transported into the main bore 1602 for disposal in the surrounding subsurface formation. The sediment 1672 may be disposed of downhole and/or transported to the surface of the multilateral well. The production fluid 1674 may be transported to the surface of the multilateral well.

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 Subsea DOWSS (Downhole Oil Water Solids Separation)

Example implementations may include Subsea Oil Water Solids Separation (SOWSS). Example implementations may include perturbation of fluids, separation of fluids, 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.

FIG. 17 is a perspective view of a first example subsea DOWSS, according to some embodiments. FIG. 17 includes a subsea DOWSS 1700 that includes a subsea production well 1702 formed in a subsea surface 1704. The subsea production well 1702 may be formed through rock 1712 and a reservoir 1714. As described herein, production fluid (such as hydrocarbons 1715) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 1702.

In some implementations, this fluid transported to the surface of the subsea production well 1702 may be transported to a ship 1730 via a multiphase pump 1720 and risers 1722. The ship 1730 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1730 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 1730 may be transported down below to a subsea injection well 1734 via a water injection pump 1732. The water 1742 may be pumped downhole into the subsea injection well 1734. As shown, the water 1742 may be returned for storage in the reservoir 1714.

In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1702 may remain below (instead of being transported to the ship 1730). For example, after being transported to the surface, the fluid may be transported to a location 1705 at the subsea surface 1704 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1704 at a location 1708. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1704 at a location 1706. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 1704.

Accordingly, fluid from the subsea production well 1702 may be pumped to subsea surface 1704 for processing, temporary storage, transport, water injection to maintain reservoir pressure, water flood from the subsea injection well 1734 to push hydrocarbons to the subsea production well 1702 and/or disposal.

In some embodiments, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some embodiments, 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, FIG. 18 is a perspective view of a second example subsea DOWSS, according to some embodiments. Offshore drilling rigs (on occasion) inject used drilling mud into a disposal well. FIG. 16 includes a subsea DOWSS 1600 that includes a subsea disposal well 1634 used for injection of used drilling mud (solids (drill cuttings) 1642). The subsea DOWSS 1600 also includes a subsea production well 1602. As shown, the subsea disposal well 1634 and the subsea production well 1604 may be formed in a subsea surface 1604. The subsea disposal well 1634 and the subsea production well 1602 may be formed through rock 1612 and a reservoir 1614. As described herein, production fluid (such as hydrocarbons 1615) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 1602.

In some implementations, this fluid transported to the surface of the subsea production well 1602 may be transported to a ship 1630 via a multiphase pump 1616 and risers 1622. The ship 1630 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1630 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 1630 may be transported down below to the subsea injection well 1634 via a pump 1632. The solids (drill cuttings) 1642 may be pumped downhole into the subsea disposal well 1634 for storage in the reservoir 1614.

In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1602 may remain below (instead of being transported to the ship 1630). For example, after being transported to the surface, the fluid may be transported to a location 1605 at the subsea surface 1604 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1604 at a suitable location. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1604 at a suitable location. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 1634.

FIG. 19 is a perspective view of types of offshore well that may benefit from example implementations, according to some embodiments. The lifting cost of producing formation water from 3000 meters (m) is very costly. The cost of lifting solids in a high-velocity rate is extremely erosive and costly. Separating out the solids and then lifting them at a slower rate will decrease the amount erosion. FIG. 19 depicts a number of offshore wells at different depths. In particular, FIG. 19 depicts a fixed platform well 1902 (that may be used up to 200 m), a compliant piled tower well 1904 (that may be used between 200-500 m), a tension leg platform (TLP) well 1906 (that may be used between 300-1500 m), a semi floating production system (FPS) well 1908 (that may be used between 300-2000 m), a single point anchor reservoir (SPAR) platform well 1910 (that may be used between 300-2000 m), and a floating production systems-FPSO and subsea well 1912 (that may be used up to 3000 m).

FIG. 20 is a perspective view of an example subsea downhole oil water solids separation, according to some embodiments. FIG. 20 depicts a number of offshore rigs—an offshore rig 2002, an offshore rig 2004, and an offshore rig 2006. FIG. 20 also depicts a number of ships-a ship 2008, a ship 2010, a ship 2012, a ship 2014, a ship 2016, and a ship 2030. The offshore rigs 2002-2006 and the ships 2008-2018 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 2002-2006 and the ships 2008-2018 (e.g., Floating Production Storage and Offloading (FPSO)), may also include storage for the production fluid the nonproduction fluid, etc.

FIG. 20 also depicts a number of production wells-a production well 2020, a production well 2022, and a production well 2024. FIG. 20 also depicts a water disposal well 2026 and a solids disposal well 2028. The fluids/solids from the production wells 2020-2024 may be transported to any of the oil rigs 2002-2006, any of the ships (e.g., Floating Production Storage and Offloading (FPSO)) 2008-2018, any pipeline or another subsurface well. For example, the nonproduction fluid and the solids from the production wells 2020-2024 may be transported to the water disposal well 2026 and the solids disposal well 2028, respectively. Additionally, production fluid processing and separation, nonproduction fluid processing and/or solids processing may occur at one of more of the locations identified in FIG. 20.

FIG. 21 is a perspective view of example locations in which example embodiments may be used. FIG. 21 includes 11 example locations. A first example location includes a well 2102 where fluids may exit the well or are injected therein. A second example location includes an oil-cut processing unit 2104. For example, a flow diverter may divert oil-cut fluid to an oil-cut processing unit 2104. The oil-cut processing unit 2104 may include a flow diverter to remove more water from an oil-cut fluid. In some implementations, a flow diverter may divert solids, slurry, sludge, etc. to a processing unit 2106. Such solids, slurry, sludge, etc. may then be stored in a storage container or disposal well 2110. Flow diverter may be part of the storage container or disposal well 2110 to remove more oil from the slurry. The solids processing unit 2106 may include a flow diverter to remove more oil from the slurry.

FIG. 21 also depicts a number of offshore rigs—an offshore rig 2172, an offshore rig 2174, and an offshore rig 2176. FIG. 21 also depicts a number of ships (e.g., Floating Production Storage and Offloading (FPSO))—a ship 2178, a ship 2180, a ship 2182, a ship 2184, a ship 2186, and a ship 2188. The offshore rigs 2172-2176 and the ships 2178-2188 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 2172-2176 and the ships 2178-2188 may also include storage for the production fluid, the nonproduction fluid, solids, basic sediment, etc.

Another example location may include an oil storage and transfer unit 2108. Another example location may include a solids or slurry transfer line 2112. For example, a flow diverter may help mix, remix, stir, or agitate solids, basic sediments, etc. to keep them in suspension in the solids or transfer line 2112. Another example location may include a production fluids/oil-cut fluid/fluid transfer line 2114. 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 2114. Another example location may include a well 2116 with vertical, inclined, sloped, deviated, one or multiple laterals, tortuous paths, etc.

Another example location may include a multilateral well 2118, not shown, (that includes a lateral wellbore, junction, etc.). Another example location may include a horizontal well 2120. Another example location may include a main production transfer line 2122 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.

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.

The hardware and data processing apparatus used to implement the various illustrative logics, logical blocks, modules and circuits described in connection with the implementations disclosed herein may be implemented or performed with a general purpose single- or multi-chip processor, a digital signal processor (DSP), an application-specific integrated circuit (ASIC), a field-programmable gate array (FPGA) or other programmable logic device, discrete gate or transistor logic, discrete hardware components, or any combination thereof designed to perform the functions described herein. A general-purpose processor may be a microprocessor or any conventional processor, controller, microcontroller, or state machine. A processor also may be implemented as a combination of computing devices, e.g., a combination of a DSP and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a DSP core, or any other such configuration. In some implementations, particular processes and methods may be performed by circuitry that is specific to a given function.

In one or more implementations, the functions described may be implemented in hardware, digital electronic circuitry, computer software, firmware, including the structures disclosed in this specification and their structural equivalents thereof, or in any combination thereof. Implementations of the subject matter described in this specification also may be implemented as one or more computer programs, e.g., one or more modules of computer program instructions stored on a computer storage media for execution by, or to control the operation of, a computing device.

If implemented in software, the functions may be stored on or transmitted over as one or more instructions or code on a computer-readable medium. The processes of a method or algorithm disclosed herein may be implemented in a processor-executable instructions which may reside on a computer-readable medium. Computer-readable media includes both computer storage media and communication media including any medium that may be enabled to transfer a computer program from one place to another. Storage media may be any available media that may be accessed by a computer. By way of example, and not limitation, such computer-readable media may include RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other medium that may be used to store desired program code in the form of instructions or data structures and that may be accessed by a computer. Also, any connection may be properly termed a computer-readable medium. Disk and disc, as used herein, includes compact disc (CD), laser disc, optical disc, digital versatile disc (DVD), floppy disk, and Blu-Ray™ disc where disks usually reproduce data magnetically, while discs reproduce data optically with lasers. Combinations also may be included within the scope of computer-readable media. Additionally, the operations of a method or algorithm may reside as one or any combination or set of codes and instructions on a machine readable medium and computer-readable medium, which may be incorporated into a computer program product.

While operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. Further, the drawings may schematically depict one more example process in the form of a flow diagram. However, some operations may be omitted and/or other operations that are not depicted may be incorporated in the example processes that are schematically illustrated. For example, one or more additional operations may be performed before, after, simultaneously, or between any of the illustrated operations. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and the described program components and systems may generally be integrated together in a single software product or packaged into multiple software products. Additionally, other implementations are within the scope of the following claims. In some cases, the actions recited in the claims may be performed in a different order and still achieve desirable results.

Example Implementations

Some example implementations may be described by the following clauses.

Clause 1: A method for removing a device from a well system, the method comprising: inserting a tool into a working space of an elongated Y-block residing in a wellbore, wherein the elongated Y-block leads into the wellbore; guiding the tool into the well system; interfacing the tool with a cartridge including devices for separating fluids, the cartridge disposed in the well system; and pulling the tool and the cartridge through the working space and up to a surface device.

Clause 2: The method of clause 1, wherein the cartridge includes a first electric submersible pump (ESP) or parts thereof disposed in the well system.

Clause 3: The method of any one or more of clauses 1-2 further comprising: configuring, via the removal tool, a second ESP or parts thereof residing in the cartridge.

Clause 4: The method of any one or more of clauses 1-3, wherein the pulling the tool includes removing the first ESP via a fishing neck of the first ESP.

Clause 5: The method of any one or more of clauses 1-4, wherein the guiding includes pushing the tool into the well system, the diverter configured to cause the removal tool to move into the flow path.

Clause 6: The method of any one or more of clauses 1-5, wherein the guiding includes pushing the tool into a profile disposed in the elongated Y-block, the profile configured to rotate or land the tool at a particular depth and orientation.

Clause 7: The method of any one or more of clauses 1-6 further comprising: inserting the elongated Y-block into the wellbore.

Clause 8: The method of any one or more of clauses 1-7 further comprising: inserting a device for aiding in the separation fluids into the elongated Y-block.

Clause 9: The method of any one or more of clauses 1-8 further comprising: connecting an energy transfer conduit to the elongated Y-block and/or separation components.

Clause 10: The method of any one or more of clauses 1-9 further comprising: connecting the energy transfer device of the elongated Y-block to a device for aiding in the separation fluids.

Clause 11: A system comprising: a cartridge configured for insertion into a flow path in a well, wherein the cartridge includes one or more devices to separate fluids; and an elongated Y-block including a working space configured to enable a tool to remove the cartridge from the flow path.

Clause 12: The system of claim 11 further comprising: a tool configured to insert the cartridge into the flow path.

Clause 13: The system of any one or more of clauses 11-12 further comprising: a diverter configured to redirect the tool into the flow path.

Clause 14: The system of any one or more of clauses 11-13 further comprising: at least one profile disposed in the elongated Y-block and configured to rotate and land the tool at a particular depth and orientation.

Clause 15: The system of any one or more of clauses 11-14, wherein the tool is further configured to install the cartridge into the flow path through the elongated Y-block and to contact the profile to rotate the tool to an orientation at which the cartridge will be installed.

Clause 16: The system of any one or more of clauses 11-15, wherein the cartridge includes a component of an assembly to separate fluids.

Clause 17: The system of any one or more of claims 11-16, wherein the cartridge includes at least a component of an oil and water separator device.

Clause 18: The system of any one or more of clauses 11-17, wherein the cartridge includes a component of an energy transfer device.

Clause 19: The system of any one or more of clauses 11-18), wherein the ETD includes a component of a wireless ETD.

Clause 20: The system of any one or more of clauses 11-19, wherein the elongated Y-block includes a component of an ETD.

Clause 21: The system of any one or more of clauses 11-20, wherein the ETD includes a component of a wireless ETD.

Clause 22: The system of any one or more of clauses 11-21, wherein a computer may sense a one or more parameters of the one or more flow channels, pump, fluid separator, formation fluid, nonproduction fluid, production fluid, solid, sediment, container, emulsion, or a combination thereof, and perform one or more of monitoring, testing, controlling, troubleshooting, adjusting, diagnosing, analyzing, replacing, repairing, and/or maintaining a downhole separation system or component thereof.

Clause 23: The system of any one or more of clauses 11-22, wherein a computer may comprise at least an instruction from an Artificial Intelligence processor, an Artificial Intelligence algorithm, a Machine Learning processor, and/or a Machine Learning algorithm.

Clause 24: The system of any one or more of clauses 11-23, wherein at least one variable within the instruction code for the computer may be changed via the computer's Artificial Intelligence processor, the computer's Artificial Intelligence algorithm, the computer's Machine Learning processor, the computer's Machine Learning algorithm, and/or the computer's software.

Clause 25: An apparatus comprising: an elongated Y-block including a working space configured to enable a tool to insert and remove a cartridge from a flow path, the cartridge including devices configured to separate fluids.

Clause 26: The apparatus of clause 25 further comprising: a profile coupled with the elongated Y-block and configured to rotate the tool during insertion or removal of the cartridge.

Clause 27: The apparatus of any one or more of clauses 25-26 further comprising: a diverter configured to redirect the tool into the flow path.

Clause 28: The apparatus of any one or more of clauses 25-27, wherein the tool is configured to install the cartridge into the flow path through the elongated Y-block and to contact the profile to rotate the tool to an orientation at which the cartridge will be installed.

Clause 29: The apparatus of any one or more of clauses 25-28, wherein the cartridge includes an oil and water separator.

Clause 30: The apparatus of any one or more of clauses 25-29, wherein the cartridge includes at least one component of an ESP.

Clause 31: The apparatus of any one or more of clauses 25-30, wherein the cartridge includes a component of an energy transfer device (ETD).

Clause 32: The apparatus of any one or more of clauses 25-31, wherein the ETD includes a component of a wireless ETD.

Clause 33: The apparatus of any one or more of clauses 25-32, wherein the elongated Y-block includes a component of an Energy Transfer Device (ETD).

Clause 34: The apparatus of any one or more of clauses 25-33, wherein the ETD includes a component of a wireless ETD.

REMOVABLE CARTRIDGE FOR A DOWNHOLE FLUID AND SOLID SEPARATION SYSTEM IN A WELL

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Provisional Applications (1)