Retrievable, below junction, esp, and other devices

Abstract

A system comprises a downhole separator to be positioned in a main bore at an approximately horizontal location and configured to separate hydrocarbon bearing fluid from non-hydrocarbon bearing fluid. The system comprises a first pump to be positioned in the main bore uphole of the downhole separator and configured to receive the hydrocarbon bearing fluid and pump to surface. At least a portion of the first pump is removable from the main bore without removing the downhole separator using at least one light well intervention method. The system comprises a second pump to be positioned in the main bore uphole of the downhole separator and configured to receive the non-hydrocarbon bearing fluid and pump into at least one lateral bore. At least a portion of the second pump is removable from the main bore without removing the downhole separator, using at the least one light well intervention method.

Description

2025-INV-l 12834-WOOlRETRIEVABLE, BELOW JUNCTION, ESP, AND OTHER DEVICESBACKGROUND

[0001] 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.

[0002] 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.

[0003] 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 w ell that is drilled from a point in the original w ell. The lateral w ell 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,2025-INV-l 12834-WOOloperators 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

[0004] Implementations of the disclosure may be better understood by referencing the accompanying drawings.

[0005] FIG. 1 is a perspective view in partial cross section of a multilateral well system that includes downhole fluid separation, according to some implementations.

[0006] FIG. 2 is side view of an example downhole separation system, according to some implementations.

[0007] FIGS. 3A-3B are schematics of a downhole oil water separator (DOWS), according to some implementations.

[0008] FIG. 4 is a schematic of a DOWS system installed in a multilateral well with pumping systems positioned above the junction, according to some implementations.

[0009] FIG. 5 is a schematic of a DOWS system installed in a multilateral well with pumping systems positioned below' the junction, according to some implementations.

[0010] FIGS. 6-7 include a flowchart of example operations for downhole fluid and solid separation, according to some implementations.

[0011] FIG. 8 is a flowchart with operations for removing components of a DOWS system from a multilateral wellbore, according to some implementations.

[0012] FIG. 9 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 implementations.2025-INV-l 12834-WOOl

[0013] FIG. 10 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 implementations.

[0014] FIG. 11 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.

[0015] FIG. 12 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS implementations with anon-Level 5 junction, according to some implementations.

[0016] FIG. 13 is a perspective view of a first example subsea DOWSS, according to some implementations.

[0017] FIG. 14 is a perspective view of a second example subsea DOWSS, according to some implementations.

[0018] FIG. 15 is a perspective view of types of offshore well that may benefit from example implementations, according to some implementations.

[0019] FIG. 16 is a perspective view of an example subsea downhole oil water solids separation, according to some implementations.

[0020] FIG. 17 is a perspective view of example locations in which example implementations may be used, according to some implementations.DESCRIPTION

[0021] The description that follows includes example systems, methods, techniques, and program flow s that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to a multilateral w ell. Aspects of this disclosure can be applied to any suitable wellbore. For clarity, some well-known instruction instances, protocols, structures, and techniques have been omitted.

[0022] Unless otherwise specified, use of the terms "connect," "engage," "couple," "attach," or any other like term describing an interaction betw een elements is not meant to limit the interaction to a direct interaction between the elements and may also include an indirect interaction between the elements described. Unless otherwise specified, use of the terms "up,"2025-INV-l 12834-WOOl"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 w ell, regardless of the w ellbore 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.

[0023] As wells age, water production may increase. To decrease the lifting and production cost related to produced water, Dow nhole 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, such as a lateral of a multilateral well. To operate the well efficiently (i. e. , move as much fluid as possible), electric submersible pumps (ESPs) may be utilized. For example, ESPs may be positioned in a wellbore to pump fluid to the surface. In some implementations, the ESPs need to be properly sized such that the ESP does not inhibit production. For instance, the ESP size may be limited due to wellbore configurations such as the tubulars in the well. Thus, the DOWS system may be configured such that the largest ESP possible may be utilized to move the oil and water produced from the subsurface formation such that the ESP does not limit the production. As the well ages, the formation fluid rate and / or water cut may change. Accordingly, the ESPs may need to be changed to accommodate such changes. For example, as a reservoir is depleted (i.e., reservoir pressure decreases and / or fluid production decreases), the initial ESP may not be required due to pump constraints (e.g., the minimum pump rate of the ESP may be greater than the fluid flowing into the w ellbore from the reservoir), excess pow er consumption, etc.Accordingly, the initial pump may be removed from the wellbore and replaced with a properly sized pump to accommodate current and / or future wellbore pressures and production rates.

[0024] A multilateral w ell may include a main bore and one or more lateral bores w hich branch from the main bore at a junction. The multilateral well may include a multilateral system that, when operating with a DOWS, allows for fluid in the main bore and the lateral bores to be segregated. For instance, the DOWS may separate the formation fluid produced into the main bore into different phases (i.e., hydrocarbon bearing fluid (oil) and non-hydrocarbon bearing fluid(water)). Some implementations may enable operators to position the DOWS sy stem, or components thereof, in or near the production zone. For example, the DOWS system2025-INV-l 12834-WOOl(separators. ESPs, etc.) may be positioned in the production wellbore of a multilateral well at or near where the production fluid may enter the wellbore, such as in or uphole of a completed zone. Some implementations may enable operators to position the DOWS system, or components thereof, in horizontal and / or near-horizontal inclination. For example, the production wellbore of a multilateral well may be a horizontal wellbore. This is especially advantageous when using gravity -based separation systems that perform at an optimum level when they are installed in a near-horizontal position.

[0025] After separation, the water may flow, via a dedicated flow path (such as a tubular or an annular space), to the lateral well to be disposed of, and the oil may flow, via a dedicated flow path, to the surface via the main wellbore. In a multilateral well utilizing the DOWS system, component installation, repair, and / or maintenance may be time-intensive and costly. For example, production may need to be temporarily suspended to repair damaged components, replace components, etc. For instance, a sand separator may be worn, plugged, etc. and may need to be replaced, a component may need to be downsized to accommodate current production level, or the production zone may need to be cleaned and / or restimulated. Example implementations described herein include a DOWS pumping system that includes two or more ESPs configured to pump fluid phases separated by a DOWS. In some implementations, the DOWS pumping system may include any other suitable pumps to transport fluids. The DOWS pumping system may include a first ESP to pump water (e.g., to a lateral well in a multilateral well or to the surface through a dedicated conduit such as a tubing string, annulus, etc.), and a second ESP to pump oil to the surface. The multilateral system may be configured such that each of the ESPs respective size may be optimal for the well production while also allowing components of the DOWS pumping system or a DOWS to be installed and / or removed without having to remove multilateral system components. The ESPs of the DOWS pumping system may be positioned above the junction of the multilateral wellbore, below the junction of the multilateral wellbore, or any combination thereof. Some implementations may enable operators to install and / or retneve DOWS equipment, such as DOWS pumping system (e.g., the ESPs), fluid and / or solids separators, etc. that may be positioned above and / or below- the junction of a multilateral well. In some implementations, the DOWS pumping system (i.e., the ESPs), or components thereof, may be positioned proximate, or near, the DOWS equipment to keep the length of the pump intake line short. For example, the ESPs may be positioned 100 feet uphole of the DOWS equipment. The length of a pump intake line depends on the pump type and the desired How rate, but generally, it is recommended to keep the suction line as short as possible to minimize friction losses and ensure efficient operation.2025-INV-l 12834-WOOl

[0026] Some implementations may enable operators to retrieve and replace the DOWS pumping system or at least parts of the DOWS pumping system. DOWS Pumping system often uses Electrical Submersible Pumps (ESPs), as described above, which may be prone to fail. In some implementations, each of the ESPs may be positioned within a housing. The housing may at least partially encapsulate an ESP to deploy the ESP in the wellbore and also ensure the ESP is positioned properly in the wellbore. A tubular (such as a tubing string, casing string, liner, etc.) may include a profile at a depth configured to receive and orient the housing of the ESP such that the ESP may be positioned properly in the wellbore. For example, the ESP may need to be properly positioned such that a wet mate connector of the ESP may properly connect to a wet mate connector on the tubular string such that power can be supplied to the ESP via a power cable coupled with the tubular stnng. In some implementations, only a portion of an ESP may be pulled. For example, at least one of the pump stage, intake, seal, motor, etc. may be pulled, while the remaining components remain in the housing in the well.

[0027] Some implementations may enable operators to pull the DOWS Pumping system components and gain access to the DOWS system’s component for retrieval, replacement, performing maintenance, etc. For example, the ESPs may be removed from the wellbore such that components of the DOWS including, but not limited to, the fluid separators, sand separators, temporary sand storage containers, etc. may be retrieved. In some implementations, the one or more of the DOWS system’s components may be removed from the wellbore in order to gain access to the wellbore below the DOWS. This allows many different operations to be performed on the DOWS system and the production zone, completion equipment, sensors, etc. that are mounted in or below the DOWS system. For example, tools such as coiled tubing may be able to access the wellbore below the DOWS system to perform wellbore operations such as a cleanout operation.

[0028] Some implementations may enable operators to gain potential access to the upper lateral to perform different operations on the DOWS system and the upper injection / production zone, completion equipment including the multilateral (MLT) Multilateral Intersection Completion (MIC) junction, sensors, batteries, communication devices, wireless devices, etc. that are mounted in the lateral wellbore and / or in the main wellbore, its completion equipment (screens, valves, etc.), and the junction and its related components.

[0029] In many instances the w ells may be subsea w ells that have a subsea wellhead located 1 -km or more from the production platform. The oil is produced to the subsea floor and then pumped to the production platform or other location such as onshore. The subsea wellheads may2025-INV-l 12834-WOOlbe too far away to retrieve the pumps and DOWS from the production platform, so a Light Well Intervention (LW1) vessel (utilizing coiled tubing, wireline, tractor, etc.) may be used. Light Well Intervention may comprise the use of such techniques and systems such as Riserless Light Well Intervention (RLWI) which is a specialized system that enables well intervention operations without the need for a drilling riser, offering a cost-effective and efficient alternative to rig-based interventions, especially in subsea environments. Implementations described herein may ensure a “workover” may be performed on multilateral wells by pulling and replacing the pumps, their motors, and DOWS components.Example System

[0030] One or more ESPs. DOWS, and / or other devices described herein may be used in concert with any of the systems and components described herein (even if not shown).

[0031] FIG. 1 is a perspective view in partial cross section of a multilateral well system that includes downhole fluid separation, according to some implementations. FIG. 1 depicts a multilateral well 100 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.

[0032] In FIG. 1, a multilateral well 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). While the separation system 124 is depicted as above (uphole) the junction of the multilateral well, the separation system 124 may be positioned below (dow nhole) the junction in either main bore 102 or the lateral bore 104 (whichever the producing bore is, in this case, the lateral bore 104). 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 the2025-INV-l 12834-WOOlformation fluid 118 into production fluid 114 (such as hydrocarbons (e.g., oil)) and nonproduction fluid 116 (such as water). 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. In some implementations, ESPs may be positioned above the separation system 124 to pump the respective fluids to their respective intended destination (as depicted in FIGS. 4 and 5 below). For example, a first ESP may pump the water to the main bore 102 to injection into the surrounding formation, and the second ESP may pump the oil to the surface.

[0033] 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 into a subsurface formation. Therefore, the separation system 124 may also include sediment separator(s) to separate out sediment from the nonproduction fluid 116.

[0034] 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 the 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.

[0035] 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.

[0036] In some implementations, the separation system 124 may include gas injector(s) to receive gas separated out by the fluid separators. A gas separator may be integrated into separation system 124, or it may be a stand-alone separation system / device, or it may be a component of the ESP system. The gas injector(s) may inject the gas into the production tubing2025-INV-l 12834-WOOlto be delivered to the surface with the production fluid 114, a separate dedicated tubing string, or into the annulus of the production tubing delivering the production fluid 114.

[0037] FIG. 2 is side view of an example downhole separation system, according to some implementations. For example, FIG. 2 depicts a separation system 200 (i.e., a downhole oil water separator (DOWS)) 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 of at any suitable location among the devices. The computer 270 may be integrated in any of the devices. The computer 270 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. For example, the separators 290A-290N and sediment injector(s) 299 may be positioned in the upper flow channel with the production fluid 114, stream downstream of the fluid separator 296.

[0038] 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, w hich 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 How . In particular, most, or at least a majority of the production fluid 114 may separate into a flow7channel 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 may allow for most of the sediment to be captured in the low er portion of the tubing (below the separator 201).

[0039] 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 densities. Accordingly, even in the same tubing without the separator 201, most of the production fluid 114 w ould be above the nonproduction fluid 116 because of the differences in w eight between the two types of fluid.2025-INV-l 12834-WOOl

[0040] 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.

[0041] 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 inhibitors, 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.

[0042] In some implementations, these different collections of the sediment by the different sediment separators 290A-290N 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 290A-290N.2025-INV-l 12834-WOOl

[0043] Periodically, sediment may need to be emptied from the different sediment separators 290 A-N via the sediment injector(s) 299. The sediment separators 290 A-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, 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 (and / or from a computer / controller mounted downhole such as computer 270). 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 290A-N. One or more processes may be monitored via sensors and analyzed, optimized, improved, and / or controlled by one or more computers / controllers such as the computer 270.

[0044] In some implementations, sensors may be coupled to each of the tanks of the sediment separators 290A-N. 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 A-N.

[0045] 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.

[0046] Accordingly, if sediment is included with the production fluid 114 being delivered to the surface, the production fluid 114 may be delivered to surface equipment that provides for separation of the sediment. Alternatively, during the time when the sediment is not 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.

[0047] Alternatively, or in addition, the sediment injector(s) 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 some2025-INV-l 12834-WOOlimplementations, 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 of in a first dow nhole 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).

[0048] In some implementations, the separation system 200 may include a gas separator and / or a gas injector. The gas separator may be integrated into the separation system 200 (such as a part of the fluid separator 296, above the separator 201. and the intake of the separation system, etc.), or it may be a stand-alone separation system / device, or it may be a component of the ESP system. A gas injector may receive gas from the gas separator and inject it into a tubing for delivery to surface. For example, the gas may be injected into the production tubing or a separate tubing, annulus, etc. If the production tubing is used, gas may be included with the production fluid 114 that is being delivered to the surface. In such implementations, separation operations may be performed at the surface to separate out the gas from the production fluid 114.

[0049] 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 or adjusted via computergenerated signals. Alternatively, the w eir 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 and / or the oil separation side and plumbing of separator 201.

[0050] Accordingly, example implementations may detect the accumulation of solids in separation system 200. An operator (or other device) may be signaled that the solids should be removed. In response, an operational change in the separation system 200 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,2025-INV-l 12834-WOOlsolids 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 separation system 200 may be displaced. In some implementations, solids and other materials may be collected from separation system 200. The solids and other materials may be transported from the separation system 200. Fluids, chemicals, solvents, acids, liquids, abrasive media, solids, and other materials may be transported from the surface to the separation system 200. Likewise, components for processing and transporting oil, water, natural gas, and / or other fluids (e.g., oil emulsion) may benefit from computer controlled manipulation of the aforementioned processes and devices.

[0051] Items such as water, oil, emulsions, gases, 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 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, the 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.

[0052] 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 separation system 200 to enhance the longevity of the separation system 200. This may include applying and / or reapplying friction reducing coatings, replacing components - filters, stators, pumps, rotors, bearings, bearing assemblies, worn parts, eroded parts, electrical components, sensors, computers, controllers, logic devices, parts intended to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.

[0053] Also, the shutting down of the one or more separation system 200 processes (e.g., solid's removal) 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,2025-INV-l 12834-WOOletc. 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 intended to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.

[0054] An operational change in the separation system 200 equipment may be initiated to allow fluid separation again. This may include "turning on" or increase of separation system 200 related operations (e.g., increase or tum-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 separation system 200 equipment has been re-configured out of the solids-removal status and is ready to begin fluid separation operations. The separation system 200 may then return back to fluids separation mode. Additionally, there may be provided a continuous or occasional status check of the "health" of separation system 200 equipment.

[0055] It should be noted that the separation system 200 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 inclusive. Subsea trees, separation system 200 equipment, platform, land-base, jack up, drillship, Light Well Intervention (LWI) vessel, 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. Gas processing equipment and processes in the well and outside of the well may be inclusive.

[0056] 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.2025-INV-l 12834-WOOlcarbon 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.), cry ogenic 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 show n in detail to avoid confusion.

[0057] 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 provide 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. Other gravity -type and non-gravity separators may comprise vertical separators, horizontal tube separators, spherical separators, gravity oil separators, centrifugal separators, coalescing separators, hydrocyclone separators, centrifugal separators, helical separators, vortex separators, 2-phase separators. 3-phase separators, filter separators, and any combination of separators, etc.

[0058] 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 wdth orientation liner hanger connected to additional lower completion. 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.

[0059] 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 betw een 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 to2025-INV-l 12834-WOOlexample 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.

[0060] 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.

[0061] 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 gas 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.

[0062] The DOWS may include flow inlet devices, oil-separation devices, water-separation devices, gas separation 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, computers, sensors, controllers, relays, transmitters, floats, etc.2025-INV-l 12834-WOOl

[0063] The lifespan of an oil well ESP (Electric Submersible Pump) system can vary, but typically ranges from around 27 months to 5 years or more depending on factors like reservoir conditions and advancements in technology. In some instances, ESP lifespans may range from 13 months to 152 month. Factors that may affect the lifespan of an ESP may include, but are not limited to, reservoir conditions, ESP technology, and monitoring and maintenance. Reservoir conditions that may affect the ESP lifespan may include the types of fluid (water and oil), presence of gas, temperature, and the corrosiveness of the environment. ESP technology that may affect the ESP lifespan may include advances in abrasion resistance, gas handling, high-temperature tolerance, pump-stage thrust tolerance, and monitoring systems. Monitoring and maintenance that may affect the ESP lifespan may include regular monitoring and proactive maintenance to help identify potential problems early on. In some implementations, some ESPs have achieved over 9 years of continuous production. In some implementations, an ESP may be the first ty pe of artificial lift installed in a wellbore. Once production has been reduced to levels that may not be suitable for an ESP, alternate artificial lift methods may be installed (such as gas lift, rod pump, etc.).

[0064] FIGS. 3A-3B are schematics of a dow nhole oil water separator (DOWS), according to some implementations. FIG. 3A includes a cross section view 300 of the DOWS 301 depicted in FIG. 3B at cross-section line 304. The DOWS 301 may be similar to the separation system 200 described in FIG. 2. For example, the DOWS 301 may include a fluid separator 332 for separating the formation fluid 318 into oil 324 and water 320. For instance, the fluid separator 332 may be a gravity -based fluid separator, as shown in FIG. 3B. The oil 324 may flow into the flow path 322, via ports 334. and continue to flow uphole to other components (such as another ESP to pump the oil 324 to the surface. The water 320 may flow into the flow path 330, via ports 336, and into flow path 310. The flow- path 310 may be hydraulically coupled to the intake of the ESP 326 positioned in a housing 328. The ESP 326 may be configured to pump the water 320 to another downhole location, via flow path 316, such as to a lateral wellbore.

[0065] In some implementations, the DOWS 301 may include a flow path 310 to allow fluid and / or tools to pass through the DOWS 301 to perform operations below (i.e., downhole) the DOWS 301 such as repair components, cleanouts, stimulate the reservoir, etc. For example, the flow path 310 may allow tools such as coiled tubing, wireline, wireline tractor, etc. to pass though the DOWS 301 without the need to remove the DOWS 301, or all components of the DOWS 301, from the wellbore. Additionally, fluid, such as acid, may be pumped through the flow path to stimulate the subsurface formation via the perforations, screens, etc. downhole of2025-INV-l 12834-WOOlthe DOWS 301. The flow path 310 may be plugged during normal DOWS operations to allow proper flow diversion for fluid separation and transportation. For example, after separation, the water 320 may flow to the ESP 326 and the oil 324 may flow to a different ESP uphole, via respective flow paths 330 and 322. In some implementations, the flow path 310 may include an actuating valve or any other suitable component to divert flow and allow tools / fluid to pass through the DOWS 301. The DOWS 301 may include a retrieval neck 340 to allow the DOWS 301 to be pulled from the well using wireline, coiled tubing, jointed tubing, wireline tractor, etc.Example Pump System Configurations

[0066] All the example devices described herein (such as ESPs 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 show n in the drawings but are with the scope of this disclosure. For example, a first ESP may be positioned above a junction while a second ESP may be positioned below' the junction, the ESP responsible for handling water may be uphole or downhole of the ESP responsible for handling oil. etc. The dimensions described in FIGS. 4 and 5 are exemplary dimensions, and the components and / or tubulars described may have any suitable dimensions for positioning a DOWS and a DOWS pumping system in a wellbore.

[0067] FIG. 4 is a schematic of a DOWS system installed in a multilateral well with pumping systems positioned above the junction, according to some implementations. A multilateral w ell system 400 may include a DOWS 406, and a pumping system comprising a first ESP 402 and a second ESP 404. A DOWS 406 may be positioned below the junction 460 in the producing wellbore 452. The formation fluid 416 may be separated by the DOWS 406.Nonproduction fluid 414 (e.g., water) may flow to the second ESP 404 via an inner retrievable tubular 412. The second ESP 404 may be configured to pump the nonproduction fluid 414 into the lateral wellbore 450 and ultimately dispose of the water into the subsurface formation surrounding the lateral wellbore 450. Production fluid 420 (e.g., oil) may flow to the first ESP 402 via the annulus between the inner retrievable tubular 412, the liner 418, and the sub 410 to bypass the second ESP 404. The first ESP 402 may be configured to pump the production fluid 420 to the surface (via a production flow' path such as the tubular 408). In some implementations, the first ESP 402 and second ESP 404 may be positioned above the junction 460 of the multilateral well, as shown in FIG. 4. In some implementations, DOWS 406 may also2025-INV-l 12834-WOOlbe positioned above junction 460. As one example, if the formation fluid 416 is being produced from lateral wellbore 450, the nonproduction fluid 414 (water) is to be pumped down into the lower wellbore 452.

[0068] The DOWS 406 may comprise a system where one or more of the components may be housed within, and may be retrieved from a housing. The housing may be deployed on one string, such as liner 418 or tubular 408 (i.e., the Completion Deflector string, the Junction string, etc.). In some implementations, the DOWS 406 and / or the respective housing may have a maximum allowable diameter to optimize fluid and / or sediment separation. For example, if the internal diameter of the casing 480 may be 8.5 inches, and the outer diameter of the DOWS 406 housing may be 8.375 inches. One or more of the inner components of the DOWS 406 may be retrievable with the inner retrievable tubular 412, while the housing remains downhole. For example, the retrievable components may have an outer diameter of 4.685 inches in order to fit through the liner 418, having an internal diameter of 4.75 inches. In some implementations, one or more of the inner components may be retrieved via intervention methods such as wireline, slickline, downhole tractors, etc. before and / or after the inner retrievable tubular and associated inner components are retrieved from the DOWS 406 without retrieving the housing. For example, fluid and / or sediment separators (e.g., sediment separators 290A of FIG. 2) may be retrieved from the housing of the DOWS 406 without retrieving the housing.

[0069] Power and communications (electricity , hydraulic, light) lines may be communicatively coupled with the DOWS 406 via one or more wet connects (wet mates). The wet mate(s), or components(s) thereof, may be deployed with the housing (outer components) and / or the wet mate(s), or components(s) thereof. The power and communication lines may also be deployed with the inner retrievable components, such as with the inner retrievable tubular 412. The power and communication lines may be deployed inside the inner retrievable tubular, such as inner retrievable tubular 412 (or other tubular / conductor). in the wall of the tubular / conductor, or affixed to the outer wall of the tubular / conductor such as the inner retrievable tubular 412 or a combination thereof. The power and communication line(s) may comprise one or more of an ESP pow er cable, an insulated ACCC (Aluminum Conductor Composite Core), an ACSR (Aluminum Conductor Steel Reinforced), and / or another type of cord or rope capable of providing the power and data transmission needs of equipment located above and / or below the junction 460, liner 418, completion deflector, etc. The lines may comprise one or more wet mates, protectors against erosion from fluids flowing by the lines, protectors from downhole vibration, protectors from corrosion, anchors to support the weight of the line and prevent undesirable movement of the line(s), erosion resistant housing or coating,2025-INV-l 12834-WOOlvibration resistant materials, corrosion resistant materials, composite materials, metallic material, highly conductive materials, low-conductive materials (heat and electrical insulators), etc. The inner retrievable tubular 412 may have a releasable connection, a wet-mate connection, a sealable interface, a releasable anchor, a fishing neck, etc. to make it easily retrievable. In some implementations, the inner retrievable tubular 412 may include a tapered section with an upper outside diameter that is larger than the bore of the junction 460 and is positioned above the junction 460, and a lower outside diameter that is less than the bore of the junction 460 and positioned below the junction 460. The mating surface for the tapered surface may have the smallest inside diameter that is greater than the bore of the junction 460 so that it does limit the diameter of tools that are capable of passing through the bore of the junction 460.

[0070] The DOWS 406 may comprise of a hollow through-bore which may be plugged off (sealed) during one operation and may be opened up by actuating a valve, removing one or more plugs, etc. (as depicted in FIG. 3A). This may provide intervention tools such as coiled tubing and / or wireline access to the formation and / or equipment below the DOWS 406. This also may allow repairs or replacements to the semi-permanent items of the DOWS 406 (e.g., housing). Other semi-permanent items may also be repairer, replaced, etc. The formation may also be stimulated, flushed, acid injected, etc. when the hollow through-bore is opened up to improve the performance of the well.

[0071] In some implementations, the first ESP 402 and the second ESP 404 may be positioned above the junction 460 to take advantage of the larger wellbore. For example, the largest outside diameter of the retrievable portions of the first ESP 402 and the second ESP 404 and the retrievable portions of the DOWS 406 may be 80%, 90%, 95%, etc. of the inside diameter of the tubular 408. For instance, the tubular 408 may have an internal diameter of 5.795 inches. Accordingly, the first ESP 402 may have a diameter of approximately 4.636 inches, 5.216 inches, or 5.620 inches. The second ESP 404 may have an outer diameter that is less than the outer diameter of the first ESP 402 such that the second ESP 404 may be retrieved through the housing of the first ESP 402. The junction assembly positioned at the junction 460 may have a smaller inner diameter than the tubulars of the uphole of the junction 460. Thus, larger pumps (e.g., pumps capable of pumping 6,900-23,000 barrels per day (BPD)) may be positioned in the multilateral well above the junction 460 to accommodate high production rates. The first ESP 402 and the second ESP 404 may be positioned in respective housing that may be positioned in the tubular 408. For example, profiles (such as a seating profile) may be integrated into the tubular 408 at a specified depth. Accordingly, respective housings for the first ESP 402 and the second ESP 404 may be positioned in the respective profiles within the tubular 408.2025-INV-l 12834-WOOlSimilar to the DOWS 406, lines (power, communication, light, hydraulic, etc.) may be positioned internally and / or externally to the tubular 408, housings, etc. to communicatively couple the first ESP 402 and the second ESP 404 with the surface. The first ESP 402 and the second ESP 404 and / or respective housings may be configured with one or more wet mates to couple the ESPs with the lines.

[0072] In some implementations, at least a portion of the first ESP 402 and the second ESP 404 may be removed for repair, replacement, maintenance, etc. For example, the pumps, motor, seals, etc. or any combination thereof of the first ESP 402 may be removed while the housing of the first ESP 402 remains in position (such as in a profile integrated into the tubular 408). In some implementations, the entire first ESP 402 may be removed, with or without the housing, to remove at least a portion of the second ESP 404 (similar to the first ESP 402). In some implementations, the outer diameter of the second ESP 404 may be smaller than the internal diameter of the housing for the first ESP 402 to ensure it can run through the housing for the first ESP 402 without contacting or damaging the first ESP 402 housing components, such as wet mate connectors. For instance, the outer diameter of the second ESP 404 may have an outer diameter of 5.38 inches, while the outer diameter of the first ESP 402 is 4.62 inches. In some implementations, both the first ESP 402 and the second ESP 404 may be removed to access the DOWS 406, or components thereof. Intervention tools such as coiled tubing, wireline, wireline tractor, coiled tubing thruster, or tractor, etc. may access the DOWS 406 via the inner retrievable tubular 412. In some implementations, removable components of the DOWS 406 (such as separators, sediment movers, etc.) may be coupled with the inner retrievable tubular 412.Accordingly, the inner retrievable tubular 412 and removable components of the DOWS 406 may be removed from the wellbore after the first ESP 402 and the second ESP 404 to repair, replace, etc. the removable components of the DOWS 406 and / or address the permanent components of the DOWS 406 that does not come out with the inner retrievable tubular 412. Likewise, repairs, cleanups, stimulations, etc. may be performed on the wellbore and equipment located below DOWS 406.

[0073] FIG. 5 is a schematic of a DOWS system installed in a multilateral well with pumping sy stems positioned below the junction, according to some implementations. A multilateral well system 500 may include a DOWS 506. and a pumping system comprising a first ESP 504 and a second ESP 502. The DOWS 506 may be positioned below' the junction 560 in the producing wellbore 552. The formation fluid 516 may be separated by the DOWS 506. Nonproduction fluid 514 (e.g., water) may flow to a first ESP 504 from the DOWS 506 via a flow conduit. The first ESP 504 may be configured to pump the nonproduction fluid 514 into2025-INV-l 12834-WOOlthe lateral wellbore 550 and ultimately dispose of the water into the subsurface formation surrounding the lateral wellbore 550 via the annulus between the tubular 508 and the liner 518. Production fluid 510 (e.g., oil) may flow to a second ESP 502 via another conduit from the DOWS 506 that is separate from the conduit intended for the nonproduction fluid 514. The second ESP 502 may be configured to pump the production fluid 510 to the surface via the tubular 508. In some implementations, the DOWS 506 may be located in a mostly horizontal position of the producing wellbore 552 which may be necessary for some types of DOWS (i.e., gravity-based separation).

[0074] In some implementations, the first ESP 504 and the second ESP 502 may be positioned below the junction 560 to be as close to the DOWS 506 discharge as possible to optimize pump performance. For example, the pump intake of the first ESP 504 and / or the second ESP 502 may be shortened relative to if they were positioned above the junction 560 to minimize friction losses. Accordingly, the first ESP 504 and the second ESP 502 may be sized such that the first ESP 504 may be able to fit through the housing of the second ESP 502, and the first ESP 504 and the second ESP 502 may be sized such that the retrievable components of the DOWS 506 may fit through the respective housings of the first ESP 504 and the second ESP 502. In some implementations, the first ESP 504 and the second ESP 502 may have similar outer diameters to maximize pump efficiency. For example, the casing 580 may have an internal diameter of 8.5 inches. The outer diameter of the first ESP 504 may be 4.56 inches, the outer diameter of the second ESP 502 may be equal to or less than that of the first ESP 5040(e.g. 4.56 inches), the outer diameter of the DOWS 506 may be 8.375 inches to fit in the casing 580, but the retrievable components may have an outer diameter less than that of the first ESP 504 and the second ESP 502 (e.g., less than 4.56 inches).

[0075] The first ESP 504, the second ESP 502, and DOWS 506 may be configured to be removed similar to those in FIG. 4. For example, in some implementations, at least a portion of the first ESP 504 and the second ESP 502 may be removed for repair, replacement, maintenance, etc. The pumps, motor, etc. or any combination thereof of the second ESP 502 may be removed while a housing of the second ESP 502 remains in position. In some implementations, the entire second ESP 502 may be removed to remove at least a portion of the first ESP 504 (similar to the second ESP 404). In some implementations, both the first ESP 504 and the second ESP 502 (and the respective housings) may be removed to access the DOWS 506. In some embodiments it is preferrable to have the upper most ESP (i.e., the second ESP 502) to be slightly larger than the lower ESP (i.e., first ESP 504) so that the retrievable portions of the lower ESP will pass easily2025-INV-l 12834-WOOlthrough the bore of the larger housing for upper ESP. Intervention tools such as coiled tubing, wireline, etc. may access the DOWS 406 via the tubular 508.Example Operations

[0076] All the example devices (such as ESPs and other devices) described herein may operate in concert with one or more other devices such as fluid separators, coalescers, gas separators, 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.

[0077] Example operations are now described. FIGS. 6-7 include a flowchart of example operations for downhole fluid and solid separation, according to some implementations.

[0078] At block 602, 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.

[0079] At block 604, 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.

[0080] At block 606, 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 (watercut) may flow through a bottom flow path.

[0081] At block 608, the flow rate decreases. For example, with reference to Figure 2, the formation fluid 118 moves from a smaller to a larger diameter of the tubing 287. This may2025-INV-l 12834-WOOldecrease 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.)

[0082] At block 610, 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).

[0083] At block 612, flow is separated into one or more flow paths. For example, with reference to Figure 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.).

[0084] At block 614, gravitational separation is performed. For example, with reference to Figure 2, the fluid separator 296 may comprise a gravity-based separation that includes the separator 201.

[0085] At block 616, non-gravitational separation is performed. For example, with reference to Figure 2. the formation fluid 118 may be separated using different types of non-gravitational operations.

[0086] At block 618, stepped-sized separation is performed. For example, with reference to Figure 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. Example2025-INV-l 12834-WOOlimplementations 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.), velocity7, 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.

[0087] At block 620, solids and lighter fluids are accumulated. For example, with reference to Figure 2. the different sediment separators 290A-290N may accumulate the sediment.

[0088] Operations of the flowchart 600 continue at transition point A, which continues at transition point A of FIG. 7. From transition point A of FIG. 7, operations continue at block 802.

[0089] At block 702, 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 temporary7holding 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.

[0090] At block 704. solids are transported for disposal. For example, with reference to Figure 2, these different collections of the sediment by the different sediment separators 290A-290N 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 290A-290N.

[0091] At block 706, solids are transported to an injector. For example, with reference to FIGS. 1-2, the sediment may be transported to the sediment injector(s) 299.

[0092] At block 708, solids may be mixed at the injector. For example, with reference to Figure 2, the sediment 295 may be mixed at the sediment injector(s) 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 sediment injector(s) 299 so that mixing may2025-INV-l 12834-WOOlprogress 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.

[0093] At block 710, solids (or slurry) are injected. For example, with reference to FIGS. 1-2. the sediment injector(s) 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 of 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).

[0094] At block 712. 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.

[0095] In some implementations, the sediment injector(s) 299 may inject the solids or slurry into a string or tubular (e.g., a production tubing). The 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.2025-INV-l 12834-WOOl

[0096] At block 714. the injection process is monitored and controlled. For example, with reference to FIGS. 1-2, controllers may be coupled to the sediment injector(s) 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).

[0097] Operations of the flowchart 700 continue at transition point B. which continues at transition point B of Figure 6. From transition point B of Figure 6, operations return to operations at block 604.

[0098] FIG. 8 is a flowchart with operations for removing components of a DOWS system from a multilateral wellbore, according to some implementations. The flowchart 800 is described in reference to the multilateral well system 400 and 500 of FIGS. 4 and 5, respectively.Although flowchart 800 describes operations performed on a multilateral well, the operations may be performed on a single bore well. Additionally, one or more of the ESPs described in the flowchart 800 may be positioned above or below a junction of the multilateral well. For example, a first ESP and a second ESP may be positioned above the junction, the first ESP may be positioned above the junction and the second ESP may be positioned below the junction, or both the first ESP and the second ESP may be positioned below the junction.

[0099] At block 802, one or more components of a first ESP positioned in a first bore of a multilateral w ellbore may be removed. The components may be removed by any suitable intervention method such as wireline, coiled tubing, etc. Components may include pump stages, the pump intake, motor, etc. In some implementations, the entire ESP may be retrieved from the w ellbore. In some implementations, the housing of the ESP may remain in the w ellbore or be retrieved with the ESP. The components may be retrieved for repair, replacement, etc. For example, one or more of the stages may become worn / damaged. Accordingly, the stages may be replaced. In some implementations, the ESP components may be operating sufficiently, but need to be retrieved in order to access other components positioned downhole beneath the ESP.

[0100] At block 804, it may be determined if additional DOWS system components below the first ESP need to be removed. For instance, the second ESP and / or DOWS, both positioned below the first ESP, may require attention (repairs, replacement, etc.). Accordingly, operations of the now chart may proceed to block 806. Alternatively, if the first ESP was only requiring attention, then the no further intervention operations may be necessary. Accordingly, the one or more components of the first ESP may be positioned back in the multilateral wellbore (after2025-INV-l 12834-WOOlrepair / replacement / maintenance operations are complete for the second ESP), and the operations of the flowchart 800 are complete.

[0101] At block 806, one or more components of a second ESP positioned in a first bore of a multilateral wellbore may be removed. The second ESP may be positioned at a depth deeper than the first ESP. Similar to block 802, the components may be removed by any suitable intervention method such as wireline, coiled tubing, etc. Components may include pump stages, the pump intake, motor, etc. In some implementations, the entire ESP may be retrieved from the wellbore. In some implementations, the housing of the ESP may remain in the wellbore or be retrieved with the ESP. The components may be retrieved for repair, replacement, etc. For example, one or more of the stages may become wom / damaged. Accordingly, the stages may be replaced. In some implementations, the ESP components may be operating sufficiently, but need to be retrieved in order to access other components positioned downhole beneath the ESP.

[0102] At block 808, it may be determined if additional DOWS system components below the second ESP need to be removed. For instance, similar to block 804, the DOWS (positioned below the second ESP), the wellbore below the DOWS, the junction, or another bore of the multilateral wellbore, may require attention (repairs, replacement, maintenance, etc.).Accordingly, operations proceed to block 810. Alternatively, if the DOWS does not require attention, then the no further intervention operations may be necessary. Accordingly, the components of the first ESP may be positioned back in the multilateral wellbore (after repair / replacement / maintenance operations are complete for the second ESP), and the operations of the flowchart 800 are complete.

[0103] At block 810, a tubular positioned in the first bore or the multilateral wellbore may be removed, wherein one or more components of a DOWS system is coupled with the tubular and removed with the tubular. For example, the tubular may be similar to the inner retrievable tubular 412 of FIG. 4. The retrievable components of the DOWS may include fluid separators, sediment separators, chemical injectors, sensors, etc. In some implementations, one or more components may be retrieved from the DOWS if not retrievable with the aforementioned tubular. For instance, said components may be retrieved via wireline, slickline, coiled tubing, etc. In some implementations, retrieval of the tubular and DOWS components may open access to the wellbore below the DOWS for operations to be performed on the production zone, completion equipment, sensors positioned below the DOWS, or any other equipment below the DOWS. For example, with reference to FIG. 3B, the flow path 310 may be opened to allow access to the wellbore below the DOWS. In some implementations, wellbore operations performed on the2025-INV-l 12834-WOOlwellbore below the DOWS may be performed when access is opened such as formation stimulation, formation flush, acid injection, etc.

[0104] In some implementations, when the tubular is removed from the wellbore, access to a second bore (i. e. , a lateral bore where nonproduction fluid and / or sediment is to be disposed of) may be possible such that operations on second bore and surrounding formation, as well as corresponding equipment (such as the MLT MIC junction, sensors, batteries, communication devices, screens, valves, etc.) that are positioned in the second bore and the junction and its related components may be performed.Example Wells

[0105] 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.

[0106] 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 complexify 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.

[0107] 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 w ellbore and control of flow from the lateral impossible.2025-INV-l 12834-WOOl

[0108] 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.

[0109] 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.

[0110] 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.

[0111] 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.

[0112] 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 no2025-INV-l 12834-WOOljunction, 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.

[0113] 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 entirety to procure and install additional subsea infrastructure.

[0114] In implementations, a multilateral well is drilled and completed with a TAML Level 4 junction. The junction includes a pump and a fluid separator. The pump includes any pump capable of drawing in fluid through the pump intake, pressurizing it, and lifting it to the surface such as an electrical submersible pump, sucker-rod and pump jack, progressive cavity7pump, 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.2025-INV-l 12834-WOOl

[0115] 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.

[0116] 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.). In some implementations, a monolithic Y-block may be defined as functional unity, not necessarily physical singularity. Accordingly, the monolithic Y-block may be configured with one or more components.

[0117] To illustrate, FIG. 9 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 implementations. FIG. 9 depicts a system 900 having a multilateral well that includes a main bore 901, a lateral bore 950, and a lateral bore 951. Formation fluid 902 from the surrounding subsurface formation enters the main bore 901. The formation fluid 902 is transported through the main bore 901 uphole to a level 5 monolithic Y-block 904 and into a DOWSS 908.

[0118] The DOWSS 908 may process the formation fluid 902 to separate out nonproduction fluid 906 from production fluid 922. The DOWSS 908 may also process the formation fluid 902 to separate sediment from at least one of the nonproduction fluid 906 or the production fluid 922. The DOWSS 908 may transport the nonproduction fluid 906 into the lateral bore 950 for disposal in a disposal zone 920 for the nonproduction fluid 906 in the subsurface formation around the lateral bore 950. The DOWSS 908 may also transport sediment 925 into the lateral2025-INV-l 12834-WOOlbore 951 for disposal in a disposal zone 924 for the sediment 925 in the subsurface formation around the lateral bore 951. The DOWSS 908 may also transport the production fluid 922 and sediment 910 to a surface of the multilateral well. Accordingly, in this example, the sediment may be disposed dow nhole into a highly permeable zone downhole and / or may be transported to the surface of the multilateral well.

[0119] FIG. 10 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 implementations. In this embodiment, a main bore junction 1011 is used to provide a main bore 1002 for large tools to be passed through, or landed, in the y-block and / or main bore area of the junction 1011. A lateral bore 1004 is formed off the main bore 1002 at the junction 1010. In the example shown, an isolation sleeve 1070 may be landed in the junction. As shown, the isolation sleeve 1070 may provide pressure isolation between the formation fluids 1006 and the nonproduction fluids 1008. This main bore junction 1010 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 1010 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.

[0120] FIG. 11 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. 11 depicts a main bore 1102 and a lateral bore 1104 that is formed off the main bore 1102 at the junction 1110. An isolation sleeve 1170 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 1104. In some implementations, a tool may be inserted into the flow paths in the well to remove the isolation sleeve 1170. The process for removing the isolation sleeve 1170 may involve any one or more of the techniques and devices described herein.

[0121] FIG. 12 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS implementations with a non-Level 5 junction, according to some implementations. In this example, the multilateral well is producing from a lateral bore 1204 (instead of the main bore 1202) so the earthen junction is not over-pressure by fluid being injected in its surroundings. Formation fluid 1206 is being produced from a subsurface formation surrounding the lateral bore 1204. A DOWSS 1270 may receive the formation fluid 1206 and separate the2025-INV-l 12834-WOOlformation fluid 1206 into a nonproduction fluid 1208, a sediment 1272. and a production fluid 1274. As shown, the nonproduction fluid 1208 may be disposed of downhole by being transported into the main bore 1202 for disposal in the surrounding subsurface formation. The sediment 1272 may be disposed of downhole and / or transported to the surface of the multilateral well. The production fluid 1274 may be transported to the surface of the multilateral well.

[0122] 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 I 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 w ellbores.Example Subsea DOWSS (Downhole Oil Water Solids Separation)

[0123] 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 w ater, and oil maybe subsea - on the seafloor or in storage wells or in storage vessels embedded in the seafloor.

[0124] FIG. 13 is a perspective view of a first example subsea DOWSS, according to some implementations. FIG. 13 includes a subsea DOWSS 1300 that includes a subsea production well 1302 formed in a subsea surface 1304. The subsea production well 1302 may be formed through rock 1312 and a reservoir 1314. As described herein, production fluid (such as hydrocarbons 1315) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 1302.

[0125] In some implementations, this fluid transported to the surface of the subsea production well 1302 may be transported to a ship 1330 via a multiphase pump 1320 and risers 1322. The ship 1330 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1330 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 1330 may be transported down below to a subsea injection w ell 1334 via a water injection pump 1332. The water 1342 may be pumped downhole into the subsea injection well 1334. As shown, the water 1342 may be returned for storage in the reservoir 1314.2025-INV-l 12834-WOOl

[0126] In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1302 may remain below (instead of being transported to the ship 1330). For example, after being transported to the surface, the fluid may be transported to a location 1305 at the subsea surface 1304 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1304 at a location 1308. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1304 at a location 1306. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 1304.

[0127] Accordingly, fluid from the subsea production well 1302 may be pumped to subsea surface 1304 for processing, temporary storage, transport, waler injection to maintain reservoir pressure, water flood from the subsea injection well 1334 to push hydrocarbons to the subsea production well 1302 and / or disposal.

[0128] In some implementations, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some implementations, the solids, noncommercial fluids, a combination of both, etc. may be produced, separated, processed, stored, and then injected into the disposal well (or other designated well).

[0129] To illustrate, FIG. 14 is a perspective view' of a second example subsea DOWSS, according to some implementations. Offshore drilling rigs (on occasion) inject used drilling mud into a disposal well. FIG. 14 includes a subsea DOWSS 1400 that includes a subsea disposal w ell 1434 used for injection of used drilling mud (solids (drill cuttings) 1442). The subsea DOWSS 1400 also includes a subsea production well 1402. As show n, the subsea disposal well 1434 and the subsea production well 1402 may be formed in a subsea surface 1404. The subsea disposal well 1434 and the subsea production well 1402 may be formed through rock 1412 and a reservoir 1414. As described herein, production fluid (such as hydrocarbons 1415) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 1402.

[0130] In some implementations, this fluid transported to the surface of the subsea production w ell 1402 may be transported to a ship 1430 via a multiphase pump 1416 and risers 1422. The ship 1430 may include equipment to separate out nonproduction fluid (such as w ater) from the production fluid. The ship 1430 may also include storage for the production fluid. As shown, the solids (drill cuttings) separated out from the production fluid by equipment of the2025-INV-l 12834-WOOlship 1430 may be transported down below to the subsea disposal well 1434 via a pump 1432. The solids (dnll cuttings) 1442 may be pumped downhole into the subsea disposal well 1434 for storage in the reservoir 1414.

[0131] In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1402 may remain below (instead of being transported to the ship 1430). For example, after being transported to the surface, the fluid may be transported to a location 1405 at the subsea surface 1404 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1404 at a suitable location. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1404 at a suitable location. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 1434.

[0132] FIG. 15 is a perspective view of types of offshore well that may benefit from example implementations, according to some implementations. 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. 15 depicts a number of offshore wells at different depths. In particular, FIG. 15 depicts a fixed platform well 1502 (that may be used up to 200 m), a compliant piled tower well 1504 (that may be used betw een 200-500 m), a tension leg platform (TLP) well 1506 (that may be used between 300-1500 m), a semi floating production system (FPS) well 1508 (that may be used between 300-2000 m), a single point anchor reservoir (SPAR) platform well 1510 (that may be used between 300-2000 m). and a floating production systems - FPSO and subsea well 1512 (that may be used up to 3000 m).

[0133] FIG. 16 is a perspective view- of an example subsea dow-nhole oil water solids separation, according to some implementations. FIG. 16 depicts a number of offshore rigs - an offshore rig 1602, an offshore rig 1604, and an offshore rig 1606. Figure 16 also depicts a number of ships - a ship 1608, a ship 1610, a ship 1612, a ship 1614, a ship 1616, and a ship 1630. The offshore rigs 1602-1606 and the ships 1608-1618 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 1602-1606 and the ships 1608-1618 (e.g., Floating Production Storage and Offloading (FPSO)), may also include storage for the production fluid, the nonproduction fluid, etc.

[0134] Figure 16 also depicts a number of production wells - a production well 1620, a production well 1622, and a production well 1624. Figure 16 also depicts a water disposal well2025-INV-l 12834-WOOl1626 and a solids disposal well 1628. The fluids / solids from the production wells 1620-1624 may be transported to any of the oil rigs 1602-1606, any of the ships (e.g., Floating Production Storage and Offloading (FPSO)) 1608-1618, any pipeline or another subsurface well. For example, the nonproduction fluid and the solids from the production wells 1620-1624 may be transported to the water disposal well 1626 and the solids disposal well 1628. 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 Figure 16.

[0135] FIG. 17 is a perspective view of example locations in which example implementations may be used, according to some implementations. Figure 17 includes 11 example locations. A first example location includes a well 1702 where fluids may exit the well or are injected therein. A second example location includes an oil-cut processing unit 1704. For example, a flow diverter may divert oil-cut fluid to an oil-cut processing unit 1704. The oil-cut processing unit 1704 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 1706. Such solids, slurry, sludge, etc. may then be stored in a storage container or disposal well 1710. Flow diverter may be part of the storage container or disposal well 1710 to remove more oil from the slurry. The solids processing unit 1706 may include a flow diverter to remove more oil from the slurry.

[0136] Figure 17 also depicts a number of offshore rigs - an offshore rig 1772, an offshore rig 1774, and an offshore rig 1776. Figure 17 also depicts anumber of ships (e.g., Floating Production Storage and Offloading (FPSO)) - a ship 1778, a ship 1780. a ship 1782, a ship 1784, a ship 1786, and a ship 1788. The offshore rigs 1772-1776 and the ships 1778-1788 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 1772-1776 and the ships 1778-1788 may also include storage for the production fluid, the nonproduction fluid, solids, basic sediment, etc.

[0137] Another example location may include an oil storage and transfer unit 1708. Another example location may include a solids or slurry transfer line 1712. 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 slurry transfer line 1712. Another example location may include a production fluids / oil-cut fluid / fluid transfer line 1714. 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 1714. Another example location may include a well 1716 with vertical, inclined, sloped, deviated, one or multiple laterals, tortuous paths, etc.2025-INV-l 12834-WOOl

[0138] Another example location may include a multilateral well 1718, not shown, (that includes a lateral wellbore junction, etc.). Another example location may include a horizontal well 1720. Another example location may include a main production transfer line 1722 to another subsea pumping, gathering, and / or processing station or to land-based pumping, gathering, and / or processing facility.

[0139] 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.

[0140] 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.

[0141] 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 computer2025-INV-l 12834-WOOlprogram instructions stored on a computer storage media for execution by, or to control the operation of, a computing device.

[0142] 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.

[0143] 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.2025-INV-l 12834-WOOlExample Implementations

[0144] Implementation #1 : A system for a multilateral well having a main bore and at least one lateral bore, the system comprising: a downhole separator to be positioned in the main bore at a location that is approximately horizontal, wherein the downhole separator is configured to separate hydrocarbon bearing fluid from non-hydrocarbon bearing fluid; a first pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the first pump is fluidly coupled to receive the hydrocarbon bearing fluid and to pump the hydrocarbon bearing fluid to a surface of the main bore, wherein at least a portion of the first pump is removable from the main bore without removal of the downhole separator from the main bore and using at least one of a wireline, a slickline, or a coiled tubing; and a second pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the second pump is fluidly coupled to receive the non-hydrocarbon bearing fluid and to pump the non-hydrocarbon bearing fluid into the at least one lateral bore, and wherein at least a portion of the second pump is removable from the main bore without removal of the downhole separator from the main bore and using at least one of the wireline, the slickline, or the coiled tubing.

[0145] Implementation #2: The system of Implementation 1, w herein the first pump and the second pump are to be positioned in an approximately vertical section of the main bore that is approximately vertical from at least a position of the first pump and the second pump and up to the surface of the main bore.

[0146] Implementation #3: The system of Implementation 1 or 2, wherein the first pump and the second pump are to be positioned in a deviated section of the main bore that is approximately-deviated from at least a position of the first pump and the second pump and up to the surface of the main bore.

[0147] Implementation #4: The system of any one or more of Implementations 1-3, wherein a largest outside diameter of the first pump is at least 80% of a smallest inside diameter of a tubular the first pump resides in.

[0148] Implementation #5: The system of any one or more of Implementations 1-4, wherein a largest outside diameter of the first pump is at least 90% of a smallest inside diameter of a tubular the first pump resides in.2025-INV-l 12834-WOOl

[0149] Implementation #6: The system of any one or more of Implementations 1-5, wherein a largest outside diameter of the first pump is at least 95% of a smallest inside diameter of a tubular the first pump resides in.

[0150] Implementation #7: The system of any one or more of Implementations 1-6, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump and the second pump are positioned above the junction for the at least one lateral bore.

[0151] Implementation #8: The system of any one or more of Implementations 1-7, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump and the second pump are positioned below the junction for the at least one lateral bore.

[0152] Implementation #9: The system of any one or more of Implementations 1 -8, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump is positioned above the junction of the at least one lateral bore and the second pump is positioned below the junction of the at least one lateral bore.

[0153] Implementation #10: The system of any one or more of Implementations 1-9, wherein the second pump is positioned below the first pump, and wherein a diameter of components of the second pump is less than an inside diameter of a housing of the first pump.

[0154] Implementation #11 : The system of any one or more of Implementations 1-10, wherein one or more components of the first pump are removable from downhole without removal of the downhole separator from downhole, and wherein the one or more components are replaceable with similar or different components without removal of the downhole separator from the main bore.

[0155] Implementation #12: The system of any one or more of Implementations 1-11, wherein one or more components of the second pump is removable from downhole without removal of the downhole separator from downhole, and wherein the one or more components are replaceable w ith similar or different component w ithout removal of the downhole separator from the main bore.

[0156] Implementation #13: A method comprising: removing one or more components of a first ESP positioned in a first tubular w ithin a multilateral wellbore; removing one or more components of a second ESP positioned in the first tubular within the multilateral wellbore,2025-INV-l 12834-WOOlwherein the second ESP is below the first ESP; and removing one or more components of a downhole oil water separator, wherein the downhole oil water separator is positioned below the second ESP and in a first bore of the multilateral wellbore.

[0157] Implementation #14: The method of Implementation 13. wherein the one or more components of the downhole oil water separator are coupled to a second tubular, further comprising: removing the second tubular from the multilateral wellbore to remove the one or more components of the downhole oil water separator.

[0158] Implementation #15: The method of Implementation 13 or 14. wherein the one or more components of the first ESP, the one or more components of the second ESP, and the one or more components of the downhole oil water separator are removed by light well intervention methods including at least one of coiled tubing, wireline, slickline, or downhole tractors.

[0159] Implementation #16: The method of any one or more of Implementations 13-15, w herein the one or more components of the first ESP, the one or more components of the second ESP, and the one or more components of the downhole oil water separator are replaced by light well intervention methods including at least one of coiled tubing, wireline, slickline, or downhole tractors.

[0160] Implementation #17: An apparatus for a multilateral well having a main bore and at least one lateral bore comprising: a downhole separator to be positioned in the main bore at a location that is approximately horizontal, wherein the downhole separator is configured to separate hydrocarbon bearing fluid from non-hydrocarbon bearing fluid; and a pumping system to be positioned further uphole relative to the downhole separator and configured to receive the hydrocarbon bearing fluid and the non-hydrocarbon bearing fluid from the downhole separator, the pumping system including a first pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the first pump is fluidly coupled to receive the hydrocarbon bearing fluid and to pump the hydrocarbon bearing fluid to a surface of the main bore, wherein at least a portion of the first pump is removable from the main bore without removal of the downhole separator from the main bore and using at least one of a wireline, a slickline, or a coiled tubing; and a second pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the second pump is fluidly coupled to receive the non-hydrocarbon bearing fluid and to pump the non-hydrocarbon bearing fluid into the at least one lateral bore, and wherein at least a portion of the second pump is removable from the2025-INV-l 12834-WOOlmain bore without removal of the downhole separator from the main bore and using at least one of the wireline, the slickline, or the coiled tubing.

[0161] Implementation #18: The apparatus of Implementation 17, wherein ajunction between the main bore and the at least one lateral bore conforms to a TAML Level selected from Level 2 through Level 5.

[0162] Implementation #19: The apparatus of Implementation 18, wherein the junction provides hydraulic isolation between the main bore and the at least one lateral bore consistent with TAML Level 5 requirements.

[0163] Implementation #20: The apparatus of any one or more of Implementations 17-19, wherein ajunction between the main bore and the at least one lateral bore comprises a monolithic junction body formed from multiple parts that are mechanically and sealably joined together, and wherein one or more mechanical joints and one or more sealing joints of the monolithic junction body comprise at least one of w elds, sealing threads, metal-to-metal seals, or pressure-rated sealing interface.

[0164] 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” may 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.

[0165] 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.

Claims

2025-INV-l 12834-WOOlCLAIMS1. A system for a multilateral well having a main bore and at least one lateral bore, the system comprising:a downhole separator to be positioned in the main bore at a location that is approximately horizontal, wherein the downhole separator is configured to separate hydrocarbon bearing fluid from non-hydrocarbon bearing fluid; a first pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the first pump is fluidly coupled to receive the hydrocarbon bearing fluid and to pump the hydrocarbon bearing fluid to a surface of the main bore, wherein at least a portion of the first pump is removable from the main bore without removal of the downhole separator from the main bore and using at least one of a wireline, a slickline, or a coiled tubing; anda second pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the second pump is fluidly coupled to receive the non-hydrocarbon bearing fluid and to pump the non-hydrocarbon bearing fluid into the at least one lateral bore, and wherein at least a portion of the second pump is removable from the main bore without removal of the dow nhole separator from the main bore and using at least one of the wireline, the slickline, or the coiled tubing.

2. The system of claim 1, wherein the first pump and the second pump are to be positioned in an approximately vertical section of the main bore that is approximately vertical from at least a position of the first pump and the second pump and up to the surface of the main bore.

3. The system of claim 1, wherein the first pump and the second pump are to be positioned in a deviated section of the main bore that is approximately deviated from at least a position of the first pump and the second pump and up to the surface of the main bore.

4. The system of claim 1, wherein a largest outside diameter of the first pump is at least 80% of a smallest inside diameter of a tubular the first pump resides in.

5. The system of claim 1, wherein a largest outside diameter of the first pump is at least 90% of a smallest inside diameter of a tubular the first pump resides in.2025-INV-l 12834-WOOl6. The system of claim 1, wherein a largest outside diameter of the first pump is at least 95% of a smallest inside diameter of a tubular the first pump resides in.

7. The system of claim 1, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump and the second pump are positioned above the junction for the at least one lateral bore.

8. The system of claim 1, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump and the second pump are positioned below the junction for the at least one lateral bore.

9. The system of claim 1, wherein the downhole separator is positioned below a junction for the at least one lateral bore, and wherein the first pump is positioned above the junction of the at least one lateral bore and the second pump is positioned below the junction of the at least one lateral bore.

10. The system of claim 1, wherein the second pump is positioned below the first pump, and wherein a diameter of components of the second pump is less than an inside diameter of a housing of the first pump.

11. The system of claim 1, wherein one or more components of the first pump are removable from downhole without removal of the downhole separator from downhole, and wherein the one or more components are replaceable with similar or different components without removal of the downhole separator from the main bore.

12. The system of claim 1, wherein one or more components of the second pump is removable from downhole without removal of the downhole separator from downhole, and wherein the one or more components are replaceable with similar or different component without removal of the downhole separator from the main bore.

13. A method comprising:removing one or more components of a first ESP positioned in a first tubular within a multilateral wellbore;2025-INV-l 12834-WOOlremoving one or more components of a second ESP positioned in the first tubular within the multilateral wellbore, wherein the second ESP is below the first ESP; andremoving one or more components of a downhole oil water separator, wherein the downhole oil water separator is positioned below7the second ESP and in a first bore of the multilateral wellbore.

14. The method of claim 13, w herein the one or more components of the dow nhole oil w ater separator are coupled to a second tubular, further comprising:removing the second tubular from the multilateral wellbore to remove the one or more components of the downhole oil water separator.

15. The method of claim 13, wherein the one or more components of the first ESP, the one or more components of the second ESP, and the one or more components of the downhole oil water separator are removed by light well intervention methods including at least one of coiled tubing, wireline, slickline, or downhole tractors.

16. The method of claim 13, wherein the one or more components of the first ESP, the one or more components of the second ESP, and the one or more components of the downhole oil w ater separator are replaced by light well intervention methods including at least one of coiled tubing, wireline, slickline, or downhole tractors.

17. An apparatus for a multilateral well having a main bore and at least one lateral bore comprising:a downhole separator to be positioned in the main bore at a location that is approximately horizontal, wherein the downhole separator is configured to separate hydrocarbon bearing fluid from non-hydrocarbon bearing fluid; and a pumping system to be positioned further uphole relative to the downhole separator and configured to receive the hydrocarbon bearing fluid and the nonhydrocarbon bearing fluid from the downhole separator, the pumping system includinga first pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the first pump is fluidly coupled to receive the hydrocarbon bearing fluid and to pump the hydrocarbon bearing fluid to a surface of the main bore, wherein at least a portion of the first pump is removable from the main bore without removal2025-INV-l 12834-WOOlof the downhole separator from the main bore and using at least one of a wireline, a slickline, or a coiled tubing; anda second pump to be positioned in the main bore and further uphole relative to the downhole separator, wherein the second pump is fluidly coupled to receive the non-hydrocarbon bearing fluid and to pump the non-hydrocarbon bearing fluid into the at least one lateral bore, and wherein at least a portion of the second pump is removable from the main bore without removal of the downhole separator from the main bore and using at least one of the wireline, the slickline, or the coiled tubing.

18. The apparatus of claim 17, wherein a junction between the main bore and the at least one lateral bore conforms to a TAML Level selected from Level 2 through Level 5.

19. The apparatus of claim 18, w herein the junction provides hydraulic isolation between the main bore and the at least one lateral bore consistent with TAML Level 5 requirements.

20. The apparatus of claim 17, wherein a junction between the main bore and the at least one lateral bore comprises a monolithic junction body formed from multiple parts that are mechanically and sealably joined together, and wherein one or more mechanical joints and one or more sealing joints of the monolithic junction body comprise at least one of welds, sealing threads, metal-to-metal seals, or pressure-rated sealing interface.

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