Patent Application
20250101846
Oil and gas wells produce significant amounts of water in their lifetime. The percentage of water produced from these wells is called the water cut, the ratio of the water produced from the well compared to the volume of the total liquids produced. Most wells produce an ever-increasing water cut throughout their productive life. In many oil fields around the world the percentage of water recovered with oil has risen to be greater than the percentage of the oil. In fact, in many fields, the percentage of oil has decreased to be from about 20% in an excellent field to about 2% in a relatively poor field.
The end of a well's productive life is often determined by the water cut. A well is typically shut in when the value of the hydrocarbons produced is no longer sufficient to economically cover the operating costs of the well and the cost of disposing of the produced water. Indeed, disposing of the produced water is not environmentally and economically friendly as energy is used to power the pump to lift the produced water to the surface, to separate the produced water from the oil, to transport the separated water as it cannot be disposed on the surface in most cases. Thus, the separated water must be transported to a remote well site to be reinjected into a subterranean formation. Therefore, decreasing the water cut of a well increases the value of the produced fluids and directly decreases the disposal costs of the produced water.
One method of reducing the water cut of a well is to separate produced water from the hydrocarbons downhole, rather than at surface. Downhole separation increases the value of the fluids produced to the surface. Downhole separation also facilitates disposal of the separated water. The separated water can be reinjected into the same production zone or into a different zone. Another way to improve the productivity of a well is to increase the length of the intersection of the productive zone by the well completion. One way of increasing this intersection length is by using multilateral wells. A multilateral well is a conventional well that has a lateral well that is drilled from a point in the original well. The lateral well increases productivity by allowing additional intersection length along the productive zone without the cost and delay involved in redrilling the upper part of the well. While multilaterals enable multiple intersections within the same productive zone, multilaterals also enable fluid communication with different productive zones within a reservoir. In certain reservoirs, operators can leverage this approach to improve reservoir production by accessing numerous production zones or by increasing the contact area between a wellbore and a formation with minimal increase in drilling and completion costs. These techniques also reduce the environmental footprint of drilling rigs and subsequent production trees, particularly for land operations. Therefore, the use of multilateral well increases the potential production of a well and can also enable disposal of the produced water in a different zone.
Implementations of the disclosure may be better understood by referencing the accompanying drawings.
The description that follows includes example systems, methods, techniques, and program flows that embody aspects of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. In some instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description.
Some implementations are in reference to a “multilateral well” and “multi-bore well.” Such terms may be used interchangeably. In other words, a multilateral well may be defined to include any type of well having more than one bore, wellbore, branch, lateral, etc. For example, a multilateral well may include a main bore with one or more laterals branching therefrom. In another example, a multilateral well may also include any type of multi-bore well configuration with such bores at any angles relative to each other. Additionally, while example implementations may be used in reference to a multilateral or multi-bore well, some implementations may also be used in a single bore well. Also, the terms Downhole Oil-Water Separation (DOWS) System and Downhole Oil-Water-Solids Separation (DOWSS) System herein may be used interchangeably. Moreover, the acronyms DOWS and DOWSS herein may be used interchangeably.
Example implementations may include a wellbore system that includes downhole fluid and sediment separators. For example, the system may be part of a multilateral well completion design that includes a fluid separator and sediment separator(s) that may be near or at the junction between the main bore and a lateral bore. A fluid separator may provide separation of different types of fluids. For example, the fluid separator may separate a formation fluid (received from the formation surrounding the main bore) into production fluid and nonproduction fluid. For instance, the fluid separator may include an oil/water separator and a gas/oil/water separator, etc. In some implementations, the system may include a pump (such as an electrical submersible pump (ESP)) to pump the nonproduction fluid (such as water) into the main bore or lateral bore so that the nonproduction fluid is injected into the subsurface formation surrounding a lateral bore. For example, the formation fluid may be received from the lateral bore, and the nonproduction fluid may be injected into the main bore. Alternatively, the formation fluid may be received from the main bore, and the nonproduction fluid may be injected into the lateral bore.
Example implementations may also include downhole operations to separate out of sediment (or other types of solids) from the fluid(s), formation fluid(s), production fluid(s), and/or nonproduction fluid(s), or any combination thereof. In some implementations, the sediment that has been separated out may be stored downhole (at least temporarily). In some implementations, the sediment may be delivered to the surface of the multilateral well or another downhole location using a flow channel (such as a tubing string). Examples of another downhole location may include a cavern, a disposal wellbore, a thief zone, etc. This flow channel may be the production tubing string used to deliver production fluid to a surface of the multilateral well. In some implementations, this flow channel may be a separate tubing string for delivery of the sediment and/or fluids to the surface of the multilateral well and/or to a different downhole location.
In some implementations, a sediment injector may receive the sediment separated out by the sediment separator(s). The sediment injector may inject this sediment into the production tubing string (used to deliver the production fluid to a surface of the multilateral well) to deliver this sediment to the surface of the multilateral well. Alternatively, or in addition, the sediment injector(s) may inject this sediment into a separate tubing string to deliver this sediment to the surface of the multilateral well or to a different downhole location (such as another lateral wellbore, a storage tank, etc.).
A controller (e.g., computer) may be coupled to control the sediment injector to control the timing of the injection of sediment into a tubing string (such as the production tubing string). In some implementations, the sediment injector may be configured to regulate flow of fluids for lifting or carrying the sediment to its destination (e.g., the surface of the multilateral well). For example, the sediment injector may increase the flow rate as the volume or weight of the sediment being delivered increases.
In some implementations, the sediment injector or other device may regulate chemicals being injected into the sediment and/or the slurry or fluid used to lift or carry the sediment to its destination. For instance, a surface device may regulate chemicals being injected into the sediment and/or slurry or fluid used to lift or carry the sediment to the surface of the multilateral well. In some implementations, the chemical being injected may include a surfactant or other chemicals to increase viscosity of the fluid so that the sediment may be held in suspension. In some implementations, the chemicals may be trickled into the casing-tubing annulus. A device floating on the annulus fluid column may collect and deliver the chemicals downhole to the correct location, which may dramatically reduce plumbing cost.
Additionally, some implementations may include delivery of the nonproduction fluid to the surface of the multilateral well to sample the nonproduction fluid including the amount of sediment therein. This delivery may be via a tubing that is separate from the production tubing.
Thus, in some implementations, the separators, pumps, and injector may be installed at the junction between the main bore and the lateral bore. In other implementations, such devices may be installed below this junction or above this junction. Further, the main bore or one or more lateral bores may include one or more orientation devices which provides depth and/or orientation control. While example implementations include a given gravity-type separator, other types of separators may be used. For example, other gravity-type separators and other non-gravity separators may be used.
The multilateral junction may be placed above or inside the target formation (e.g., a depth interval of interest (such as hydrocarbon-bearing rock, rock capable of storing fluids/solids, etc.) in the subsurface of the Earth). In some implementations, this configuration may be accomplished in a multi-trip multilateral completion that includes a lower completion and an upper completion that may comprise the fluid separator, a pump (such as an electrical submersible pump, rod pump, Rotaflex, etc.), and an upper packer. This simplifies the installation. This reduced complexity allows the fluid separator to be installed into existing wells, i.e., retrofitting existing wells. Further, the lateral well may be a target formation. In this implementation, the main bore passes into a target production formation and the lateral bore passes into a target injection formation which may be a separate formation from the production formation. The existing wells do not require a tangent section at the junction for the placement of the fluid separator, significantly increasing the number of oil well candidates for installation of the fluid separator according to example implementations.
The design of the installed completion equipment may be critical for the downhole fluid separator to function as intended. By installing the fluid separators, pumps, and sediment injector(s) in the main bore at or near the junction between the main bore and the lateral bore, an existing watered out well may be re-entered and a DOWS/DOWSS may be installed. This decreases the overall cost involved in installing the separators, pumps, and sediment injector according to example implementations as compared with installing it at the completion of the well at the beginning of the life of the well. It also may decrease the risks associated with installing these devices, according to example implementations, in existing wells that may be poor producers. The installation in existing, poor producing wells may represent a smaller cost if the well is lost during the trial as compared with selecting a potential well before well completion is finished. Using these separators and injectors in a downhole setting combined with a multilateral junction may provide efficiency gains.
This includes converting poor performing wells, wherein the percentage of oil has decreased to about 2% for example, into a downhole water injector combined with a better producing well. Additional benefits include lower flow rate and pressure rating requirements, a lighter fluid column, and increased recovery. Example implementations may be particularly useful in low flow rate wells (for example, 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 500-2000 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 20,000 barrels of fluid per day, for example.
Example implementations reference a tubing string for the delivery of fluids, sediment, etc. to the surface of the multilateral well (or non-multilateral well wellbore) or other downhole location. However, example implementations may use any type of flow channel, conduit, etc. for such delivery. For example, one or more D-shaped tubes, called D-Tubes may be used. For instance, two D Tubes may be used to optimize the use of the inner diameter of a casing to maximize flow area. In some implementations, the sediment flow channel may be the annular space around the production flow tubing. Additionally, while depicting the separation being performed uphole relative to the junction between the main bore and the lateral well, example implementations may position the separation at any other location downhole. For instance, the separation may be performed at the junction, below the junction, etc.
In
The nonproduction fluid 116 may include sediment. In some implementations, the sediment may be separated out from the nonproduction fluid 116 prior to the nonproduction fluid 116 being injected back into a subsurface formation. Therefore, the separation system 124 may also include sediment separator(s) to separate out sediment from the nonproduction fluid 116.
In some implementations, the sediment that has been separated out may be stored downhole (at least temporarily). In some implementations, the sediment may be delivered to the surface of the multilateral well or another downhole location using a flow channel (such as a tubing string). Examples of another downhole location may include a cavern, a disposal wellbore, a thief zone, etc. This flow channel may be the production tubing string 106 used to deliver production fluid to a surface of the multilateral well. In some implementations, this flow channel may be a separate tubing string for delivery of the sediment and/or other fluids to the surface of the multilateral well or to a different downhole location. In some implementations, the sediment and/or other fluids may be injection at a different location, wellbore, storage device, etc. on the sea floor.
In some implementations, the separation system 124 may include sediment injector(s) to receive the sediment separated out by the sediment separator(s). The sediment injector(s) may inject this sediment into the production tubing string 106 (used to deliver the production fluid to a surface of the multilateral well) to deliver this sediment to the surface of the multilateral well. Alternatively or in addition, the sediment injector(s) may inject this sediment into a separate tubing string to deliver this sediment to the surface of the multilateral well or to a different location.
The formation fluid 118 flows into the fluid separator 296. In this example, the fluid separator 296 comprises a gravity-based separation that includes the separator 201. As shown, the formation fluid 118 moves from a smaller to a larger diameter of the tubing 287. The tubing 287 is shown as one continuous tubing for ease of clarification. However, in some implementations, the tubing 287 may comprise one or more devices with different configurations. For example, with reference to
This may decrease the velocity of the flow of the formation fluid 118—which allows the separation. In particular, most or at least a majority of the production fluid 114 may separate into a flow above the separator 201, while most or at least a majority of the nonproduction fluid with sediment 294 may separate into a separate flow below the separator 201. This allows most of the sediment to be captured in the lower portion of the tubing 287 (below the separator 201).
While depicted as having the separator 201, in some implementations, there is no separator 201. Rather, the production fluid 114 and the nonproduction fluid with sediment 294 may naturally separate in a horizontal pipe because of their different density. Accordingly, even in a same tubing without the separator 201, most of the production fluid 114 would be above the nonproduction fluid 116 because of the differences in weight (density) between the two types of fluid.
The nonproduction fluid with sediment 294 flows into the sediment separators 290A-290N, which may represent one to any number and type of sediment separators. In some implementations, each of the sediment separators 290A-290N may separate some of the sediment in the nonproduction fluid with sediment 294. For example, the first sediment separator 290 may be used to separate and collect the largest size (denser) sediment; the second sediment separator 290 may be used to separate and collect the next largest size sediment; the third sediment separator 290 may be used to separate and collect the next largest size sediment; etc. (as the flow moves from right to left through the different sediment separators). For example, at least one of the sediment separators 290 may be a cyclonic separator—wherein larger (denser) particles in the rotating stream having too much inertia to follow the tight curve of the stream. Such particles may thus strike the outside wall and fall to the bottom of the cyclone where they may be removed. In some implementations, each of the sediment separators 290 may store the sediment that was collected into an associated storage area or tank.
In some implementations, sensors may be coupled to each of the sediment separators 290A-290N. A signal from a given sensor may indicate when the associated sediment separator 290 is functioning optimally. A controller/computer 270 (downhole and/or at the surface of the well) may be communicatively coupled to the sediment separators 290A-290N sensors and other components (e.g., actuators, speed controllers, etc.) such that the computer 270 may initiate one or more sequences to adjust, diagnose, test, repair, maintain, etc. one or more of the sediment separators 290, components of 290, or related assemblies and/or components.
In some implementations, computer 270 is communicatively coupled to system 100, separation system 124, separation system 200, and/or one or more components of the systems 100, 124, 200, etc.
For one example, computer 270 may control one or more parameters of sediment separator 290N in order to increase the life of the solids and fluid separator system. In other words, the sediment separator 290N, its components, separation system 200, its components, and system 100 will operate longer and more efficiently by specifically having the computer 270 monitoring, controlling, diagnosing, and maintaining sediment separator 290N.
Continuing with this example of 290N, computer 270 may address one or more specific conditions or problems with sediment separator 290N. For example, computer 270 may monitor the moisture content of sediment separator 290N's solids/sediment discharge. If the moisture content of the discharge of solids is too dry it could mean the centrifuge forces may be too high. The computer 270 may send a signal to sediment separator 290N to reduce the speed of the pump. Computer 270 will continue to monitor the moisture content of the discharged solids.
Continuing with the above example, if the solids discharge becomes too wet (meaning some of the fluid is escaping with the solids), it may mean the centrifuge force is too low and/or a liner inside the sediment separator 290N is worn.
In this case of the sediment being too wet, the computer 270 can perform one or more of the following within a short amount of time (e.g., microseconds, milliseconds, seconds, etc.):
The above example exemplifies how computer 270 may increase the life of system 100, separation system 124, separation system 200, and/or one or more components of the systems 100, 124, 200. Computer 270 is able to monitor, control, diagnose, maintain and repair, etc., said systems and component to prevent premature failure.
The above example also exemplifies how computer 270 may increase the efficiency of systems 200, 124, and/or 100 and their respective components. As noted, computer 270 may monitor, adjust, optimize the systems and components to achieve one or more goals (e.g., maximize fluid production, reduce operating costs, increase life, etc.).
The computer/controller 270 may comprise devices, hardware, software, etc. including but not limited to: switches, power supplies, connectors, transmission lines, logic devices, software, hardware, artificial intelligence, machine learning, algorithms, and other devices known and not known in the current realm of controls, computers, material processing, energy industry, etc.
Additionally, the chemical injector(s) 291 may inject one or more chemicals into at least one of the formation fluid 118, the production fluid 114, the nonproduction fluid with sediment 294, the nonproduction fluid 116, or the sediment 295. While depicted such that chemicals are injected downhole, alternatively or in addition, chemicals may be injected from the surface of the multilateral well. Also, different chemicals may be injected for different purposes. For example, a flocculant or deflocculant may be injected to promote or not promote aggregation or settling of suspended particles in a liquid. Other examples of chemicals being injected may include paraffin, solvents, dispersants, etc. being added to the production fluid 114, a scavenger being added to the production fluid 114 to protect components from corrosive gases (H2S, CO2, etc.) 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. One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said chemical injector(s) 291 and components thereof to prevent premature failure and increase efficiencies as described within.
In some implementations, these different collections of the sediment by the different sediment separators 290 may be injected into a same or different line or tubing for disposal. As shown, the sediment injector(s) 299 are coupled to receive the sediment collected by the different sediment separators 290.
Periodically, sediment may need to be emptied from the different sediment separators 290 via the sediment injector(s) 299. The decision of when may be based on different criteria. For example, pressure and/or production flow may be monitored at the surface of the multilateral well. If the pressure and/or production flow start to degrade, it may be an indication that sediment needs to be emptied from the sediment separators 290.
In some implementations, sensors may be coupled to each of the tanks of the sediment separators 290. A signal from a given sensor may indicate when the associated sediment separator 290 needs to be emptied. A controller (downhole and/or at the surface of the multilateral well) may be communicatively coupled to the sensors such that the controller may initiate a sequence to empty one or more of the tanks of the sediment separators 290. One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said sediment separators 290, sediment injector(s) 299 and components thereof to prevent premature failure and increase efficiencies as described within.
In some implementations, the sediment injector(s) 299 may dispose of these sediments by injecting them into a tubing for delivery to the surface of the multilateral well. For example, the sediment may be delivered to the surface using the production tubing or a separate tubing. If the production tubing is used, the solids may be included with the production fluid that is being delivered to the surface. In some implementations, the production of solids with the production fluid may be timed or controlled so that the production fluid with solids may be diverted into special containers and/or processing equipment to remove the solids from the production fluid before the production fluid is funneled into the “regular” production flow. Such implementations may cut down the erosion of the normal production lines/devices caused by the intermittent solids production. In such implementations, separation operations may be performed at the surface to separate out the solids from the production fluid 114.
Accordingly, if sediment is being included with the production fluid 114 being delivered to the surface, the production fluid 114 may be delivered to surface equipment that provides for separation of the sediment. Alternatively, during the time when the sediment is not being included with the production fluid 114, the production fluid 114 may be delivered to different surface equipment that does not include such separation of sediment.
Alternatively or in addition, the sediment injectors 299 may deliver the sediment to a different downhole location (such as a different lateral well, a thief zone (having a high porosity, high permeability downhole zone that may include a low pressure), etc.). In some implementations, sediment may be disposed to different locations depending on their size. For example, for sediment having a size greater than X, such solids may be delivered to the surface of the multilateral well for disposal. For sediment having a size less than X but greater than Y, such sediment may be disposed in a first downhole location (such as a thief zone). For the remaining sediment that have a size less than Y, such solids may be disposed in a second downhole location (such as a lateral well). One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said sediment injectors 299 and components thereof to prevent premature failure and increase efficiencies as described within.
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 adjusted. In some implementations, the weir skimmers may be such that the weir height is automatic or self-adjusting. While manually adjusted weir skimmer types may have a lower initial cost, the requirement for regular manual adjustment makes self-adjusting weir types more popular in most applications. Weir skimmers may collect water if operating when oil is no longer present. To overcome this limitation, the weir type skimmers may include an automatic water drain on the oil collection tank. One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said weir skimmers and components thereof to prevent premature failure and increase efficiencies as described within.
In some implementations, the separation system 200 and/or any one or more of the components within the separation system 200 may be oriented with respect to gravity. For example, components such as the fluid separator 296, separator 201, sediment separators 290A-N, etc. may be oriented with respect to gravity such that gravity may assist in separating the phases of the formation fluid 118, sediment 295 from the formation fluid 118, etc. One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said orienting devices and components thereof to prevent premature failure and increase efficiencies as described within.
Example separators are now described in
In some implementations, any one of the aforementioned components may be removed from the a fluid and sediment separator system 400 for cleaning, repair, replacement, etc. For example, the separator 402 may be removed from the fluid and sediment separator system 400 (i.e., transported to surface) to be cleaned and then returned back to position in the fluid and sediment separator system 400.
When the sediment has been separated from the nonproduction fluid (or formation fluid), the sediment may be transported to a solids container that may be configured with an auger 408. An auger 408 (or any other suitable mechanism, such as the conveyor belt 306 of
The formation fluid 702 may enter the hydrocyclone 700 via an inlet 704. The inlet 704 may be tangential to the body of the hydrocyclone 700. The configuration of the hydrocyclone 700 and the position of the inlet 704 may cause the formation fluid 702 to flow in a helical path through separator towards the distal end 720. A reducing section 706 (i.e., where the internal diameter decreases) may result in the acceleration of the flow of the formation fluid 702 in a helical path. This may result in lighter phases 712 (less dense, such as hydrocarbons) of fluid migrating towards the central axis of the hydrocyclone 700 and being discharged through the distal end 722. The heavier phases 710 (more dense, such as water) may migrate towards the inner wall of the hydrocyclone 700 and be discharged through the distal end 720. In some implementations, sediments in the formation fluid 702 may migrate towards the inner wall with the heavier phases 710 and be discharged out the distal end 720. In some implementations, a backpressure device 708 may be positioned proximate the distal end 720 to control the pressure in the hydrocyclone 700. One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said fluid and hydrocyclone 700 and components (e.g., backpressure device 708, etc.) thereof to prevent premature failure and increase efficiencies as described within.
In some implementations, the fluids discharged out the distal end 720 may provide an indication of the health of the equipment. If the discharge is too dry it could mean the centrifuge forces may be too high. If the discharge was too wet (meaning some of the fluid was escaping with the sediment), it could mean the centrifuge force may be too low and/or a liner inside the reducing section 706 was worn. By monitoring the pressure, flow, wetness of discharge out of the distal end 720, composition of fluids and/or sediment discharged out of the distal ends 720, 722 and/or the formation fluid 702, the backpressure device 708 may be adjusted accordingly. The formation fluid 702 may be increased or decreased by changing the pump speed or efficiency. The life of the equipment could be extended by monitoring and controlling said processes.
In some implementations, the hydrocyclone 700 may be communicatively coupled to a processor (such as the processor of the computer 270) configured to control the hydrocyclone 700. The processor may control parameters such as the pump speed or efficiency, the backpressure device 708, etc. to optimize the hydrocyclone 700 as described above for maximizing profit, maximizing the life of the solids and fluid separator system, maximizing oil recovery, etc. In some implementations, the processor may be configured with a learning machine (such as a neural network), or any other suitable model, to adjust operating parameters for maximum system efficiency.
In some implementations, more than one hydrocyclone 800 may be positioned in series and/or in parallel. When in series, each subsequent hydrocyclone 800 may separate out sediment smaller than the previous hydrocyclone 800 in the sequence. In some implementations, there may be diminishing returns on separating out the sediment. Thus, in some implementations, one or more of the hydrocyclones 800 in a series may be configured to separate out production fluid (oil) from nonproduction fluid (water). One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said fluid and hydrocyclone 800 and components (e.g., backpressure device 816, flow tube 814, etc.) thereof to prevent premature failure and increase efficiencies as described within.
At block 1002, production mode may begin to allow formation fluid to enter a downhole separation system. In implementations with a multi-bore wellbore, the formation fluid may be produced into a main wellbore and/or a lateral wellbore of a multilateral wellbore from the surrounding subsurface formation. The well may be a newly drilled well. In some implementations, a lateral may be drilled from an existing well (either single bore or multi-bore) to form a new multilateral well. The formation fluid may comprise one or more of the following combinations: 1) oil and water being immiscible, 2) gas being miscible with water (typically in small quantities), 3) gas is miscible with oil (typically in large quantities), etc. For example, at a given pressure and temperature, oil and water may absorb a given amount of gas until the oil and water are saturated with gas. Above this gas saturation concentration limit, gas cannot mix further and stays as a separate gas phase. So for a given pressure and temperature, there can be up to three phases: 1) oil with gas in solution (traditionally called oil), 2) water with a small quantity of gas in solution (traditionally called water), and 3) free gas—gas. In some implementations, the formation fluid may include sediment such as sand, silt, etc. A downhole separation system may be positioned in a well (such as separation system 200 of
Operations may then proceed to blocks 1004-1006 and/or blocks 1008-1010. In some implementations, the operations of blocks 1004-1006 and blocks 1008-1010 may be performed in parallel, series, or in combination thereof.
At block 1004, phases of the formation fluid may be separated via the downhole separation system. For example, the downhole separation system may be configured with separators (such as separators described in
In some implementations the formation fluid may be semi-segregated into oil-cut and water-cut when the formation fluid enters the downhole separation system. Accordingly, the downhole separation system may be configured to take advantage of the natural separation and separate the two phases into separate flow paths. For instance, the lower-density fluid (oil-cut, gas-cut, etc.) may flow to an upper flow path (relative to depth) and the higher-density fluid (water-cut) may flow to a lower path in the downhole separation system.
In some implementations, the downhole separation system may be configured to reduce the velocity of the fluid as it flows through the downhole separation system. For example, the flow may be reduced from a high-turbulent flow to a slower, less turbulent flow (e.g., laminar flow). This may be accomplished by providing more flow area in the downhole separation system such as increasing the diameter of the flow path, increasing the wellbore size, multilateral wellbore for settling ponds/distributing flow, etc. Moreover, more time may be provided to reduce the turbulent flow such as starting and stopping flow through the downhole separation system, slowing pumping action, pausing and then restarting the flow, etc. In some implementations, the downhole separation system may be configured with one or more devices configured to stabilize turbulent flow.
In some implementations, flow velocity may be reduced by distributing the flow of the fluid into one or more flow paths. For example, the formation fluid, oil-cut fluid, water-cut fluid, gas, solid-laden slurries, etc. may flow into the one or more flow paths to reduce the velocity of the fluid for further separation (such as by increasing the cross-sectional area of the flow paths). The multiple flow paths may include one or more components configured to separate the fluids and sediments. For example, each of the flow paths may include one or more gravitational separation devices, non-gravitational separation devices, solids separation devices, accumulation and removal devices, transport devices for solids, etc.
In some implementations, the downhole separator system may be configured to allow the less dense fluid (hydrocarbons) to rise in an upward direction (i.e., opposite gravitational force) and accumulate and be channeled. For example, the downhole separator may be configured to allow time for the less dense fluids to begin to separate from the heavier fluids and/or allow the velocity of the fluid to be reduced, as described above. Moreover, the downhole separator system may be configured with one or more components to allow the less dense fluid to separate out, coalesce, accumulate, be channeled, etc. such as a gas separator, gas buster, etc. Additionally, or alternatively, the downhole separator system may be configured with one or more components configured to subject one or more fluids to one or more force, acceleration, path (i.e., tortuous path), velocity, pressure, restriction (i.e., screen opening(s), screen size, nozzle, etc.) time, impulse, etc. Moreover, the one or more fluids may be subject to a change in one or more of the aforementioned such as a step change, gradual change, etc.
At block 1006, the phases may be distributed into one or more flow channels. Once separated, the phases may be distributed to respective flow channels to be transferred to another location. For example, less dense fluids (i.e., production fluids such as hydrocarbons) may be transferred/injected/flowed to a production tubing to flow to the surface, to an inlet of a pump (such as an electric submersible pump) to be pumped to surface, to another device, etc. More dense fluids (i.e., non-production fluids such as water) may be transferred/injected/flow to a nonproduction fluid line to flow to the surface, to another bore (lateral and/or main bore) to be injected into the formation, etc. Moreover, the nonproduction fluid may be transferred to a pump (such as an electric submersible pump) to be pumped to a nonproduction fluid line, another bore, etc. In some implementations, the nonproduction fluid may be disposed on the sea floor, into a zone within the main wellbore (aka standard water disposal well), etc.
At block 1008, sediment may be separated from the fluid stream, via the downhole separator system. For example, the downhole separation system may be configured with separators (such as separators described in
In some implementations, the downhole separator system may be configured to allow time for the larger and/or more dense sediment to be separated from the fluid. Moreover, the downhole separator system may be configured to reduce the velocity of the fluid to allow the sediment to settle out of the fluid (such as by reducing the flow to laminar flow). Additionally, or alternatively, the downhole separator system may be configured with one or more devices such as a sluice box that may allow the larger and/or more dense sediment to settle out, accumulate, and be trapped. Moreover, the downhole separator system may be configured to subject one or more fluids to one or more force, acceleration, path (i.e., tortuous path), velocity, pressure, restriction (i.e., screen opening(s), screen size, nozzle, etc.) time, impulse, etc. to separate the sediment from the fluid. Moreover, the one or more fluids may be subject to a change in one or more of the aforementioned such as a step change, gradual change, etc. to separate the sediment from the fluid. Any suitable device including a sediment separator, cyclonic separator, screen cleaners, coalescers, desanders, desilters, centrifuges, desalters, etc. or a combination thereof may be utilized to separate the sediment from the fluid.
At block 1010, the sediment may accumulate in a temporary storage tank. Once separated, the sediment may accumulate in a temporary storage tank within the downhole separator system and/or proximate the discharge of the sediment separator for temporary accumulation of the sediment separated from the fluid. The sediment may be temporarily stored in the storage tank for later disposal (as described in
At block 1102, the sediment may be transported to a sediment injector. For example, the solids may be transported to the sediment injector 299 of
In some implementations, to transport the sediment, fluid such as formation fluid, production fluid, nonproduction fluid, etc. may be mixed with the sediment to generate a solid-laden slurry. Once the temporary storage tank is full, a fluid may be mixed with the solids to generate a solid-laden slurry. The solid-laden slurry may be viscous enough to suspend and transport the solids without settling out, but also thin enough such that the slurry may be pumped to the sediment injector. In some implementations, one or more chemicals may be added to the solid-laden slurry, to the sediment prior to introducing a fluid (aka pre-treating the solids/sediment), and/or prior to introducing the fluid to the sediment (aka pre-treating the fluid) to assist in suspension and transportation of the sediment.
In some implementations, the sediment may be transported to the sediment injector by a combination and hydraulic and mechanical devices such as a jetting nozzle device and a conveyor type device.
In some implementations, one or more sensors may detect when the temporary storage tank is full, and the processor of the computer 270 may initiate operations to transport the sediments to the sediment injector. For example, the process of the computer 270 may instruct the downhole separator system to divert flow of fluid (e.g., nonproduction fluid) to the temporary storage tank to generate a solid-laden slurry to then be pumped to the sediment injector. Alternatively, the processor of the computer 270 may instruct a mechanical device to transport the sediment to the sediment injector. Moreover, the processor of the computer 270 may detect, via one or more sensors, and/or control chemicals injected into the solids, fluid, and/or solid-laden slurry.
At block 1104, the sediment may be mixed with a fluid in the sediment injector. Fluids such as formation fluid, production fluid, nonproduction fluid, or any combination thereof may be diverted to the sediment injector to mix with the sediment. sediment may be mixed with fluids with mixers such as a mechanical mixer, fluid-type mixer, etc. or any combination thereof. In some implementations, the processor of the computer 270 may instruct the mixing of the sediment and the fluid. For example, the processor of the computer 270 may instruct the sediment to be mixed when one or more sensors detects when the temporary storage tank is full.
At block 1106, the sediment may be injected to a destination location, via the sediment injector. The destination location may include a final destination (such as disposed on surface, injected into a formation, etc.) or another temporary location (such as another section in a wellbore, a temporary location in the formation, etc.) The sediment injector may inject the solid-laden slurry to a flow channel such as the tubing for production fluid and/or nonproduction fluid to transport the solids to the surface with the production fluid and/or nonproduction fluid. In some implementations, the timing of the injection may be coordinated with the production of the production fluid in the tubing. For example, a pump may switch from pumping the production fluid to the surface from the downhole separator system to the solid-laden slurry to transport the fluid to surface. The processor of the computer 270 may be notified of the valve position. Moreover, the processor of the computer 270 may alter the valve position such that the solid-laden slurry may be pumped into the production tubing and transported to the surface. Injection of the sediment to the production tubing may be based on the sediment status such as the volume of solids, volume of fluids, slurry volume to be pumped, slurry volume that has been pumped, etc. In some implementations, processes may be altered (either manually or automatically) to transport the solid-laden slurry to the tubing. For example, if a standard process injects the solid-laden slurry to the tubing on a specified time interval, the process may be altered if there is an indication that the discharge of a sediment separator may be plugged, the temporary storage tank is full, etc.
In some implementations, the sediment may be injected to a flow channel to be injected into a lateral of the multilateral wellbore. For example, the methods described above may be utilized to inject the sediment into a flow channel to further inject the solid slurry into the subsurface formation surrounding a bore (lateral bore or main bore) of the multilateral wellbore. Other locations may include a cavern, thief zone, etc.
At block 1108, the downhole separation system may return to production mode. Fluid may be diverted from the sediment injector and back to the respective flow paths within the downhole separation system. For example, one or more pumps, may proceed to pump fluid (production fluid, nonproduction fluid) to surface and/or nonproduction fluid to be disposed in one or more bores. Additionally, sediment may continue to be separated from the formation fluid and stored in a temporary storage tank.
Example operations are now described.
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said systems and components related to the operations for downhole fluid and solid separation as shown in flowchart 1200-1300 in order to prevent premature failure and increase efficiencies as described within.
At block 1202, production is initiated. For example, with reference to
At block 1204, formation fluid is received into a downhole separation system. For example, with reference to
At block 1206, flow of formation fluid is separated into one or more flow paths. For example, with reference to
At block 1208, the flow rate is decreased. For example, with reference to
At block 1210, flow is modified to decrease turbulence. For example, example implementations may also destabilize turbulence and reduce flow from a turbulent flow to a laminar flow (or transitional flow) by one or means (including those mentioned above).
At block 1212, flow is separated into one or more flow paths. For example, with reference to
At block 1214, gravitational separation is performed. For example, with reference to
At block 1216, non-gravitational separation is performed. For example, with reference to
At block 1218, stepped-sized separation is performed. For example, with reference to
At block 1220, solids and lighter fluids are accumulated. For example, with reference to
Operations of the flowchart 1200 continue at transition point A, which continues at transition point A of
At block 1302, solids are separated and discharged into temporary holding tanks. For example, with reference to
At block 1304, solids are transported for disposal. For example, with reference to
At block 1306, solids are transported to an injector. For example, with reference to
At block 1308, solids may be mixed at the injector. For example, with reference to
At block 1310, solids (or slurry) are injected. For example, with reference to
At block 1312, solids-laden fluid is transported. For example, with reference to
In some implementations, the sediment injectors 299 may inject the solids or slurry into a string or tubular (e.g., a production tubing). Timing of the injection may be coordinated with production of production fluid. For example, a pump may switch between pumping (in the production tubing) production fluid to the solid-laden fluid. Example implementations may include communications to the surface regarding the switching, the volume of the solids, fluids, slurry to be pumped, how much has been pumped, how much remains to be pumped, etc. Additionally, some implementations may enable communication from the surface to downhole to control and override the switching.
At block 1314, injection process is monitored and controlled. For example, with reference to
Operations of the flowchart 1300 continue at transition point B, which continues at transition point B of
Example implementations may be performed in different Technology Advancement of Multilaterals (TAML) Level wells. In particular, multilateral wells are characterized according to definitions established in 1997 during a Technology Advancement of Multilaterals (TAML) Forum held in Aberdeen. These standards classify junctions as TAML Level 1, 2, 3, 4, 5, or 6 based on mechanical complexity, connectivity, and hydraulic isolation. The ascending order of these levels reflects increasing mechanical and pressure capability of the junction. Consequently, cost, complexity, and risk also generally increase at the higher TAML levels. However, other considerations of the well design also influence the overall complexity of the well—for example, a TAML Level 2 well with an advanced intelligent completion can be more complex and costly than a TAML Level 5 well with a simpler completion system.
In a TAML 1 well, the main bore, lateral, and junction are uncased. This basic lateral is designed to enhance reservoir drainage from consolidated formations. It has the advantage of low drilling and completion costs, but the open hole junction makes reentry into the lateral wellbore and control of flow from the lateral impossible.
Wells that have cased and cemented main bores and open hole laterals are designated TAML Level 2. A cemented main bore significantly reduces the risk of wellbore collapse and provides isolation between laterals. By placing sliding sleeves and packers in the main bore, operators can produce the bores singly or in commingle production.
Placing a liner in the lateral and mechanically connecting it to the cased and cemented main bore results in a TAML Level 3 well. A liner is a string of casing that does not extend to the surface but is anchored or suspended inside a previously run casing string. This TAML Level 3 well includes a lateral that is cased but not cemented at the junction. It is a relatively low-cost option that includes reentry capabilities and a lateral that is better supported than that of Levels 1 and 2. Using sliding sleeves and packer plugs, operators can produce the bores singly or in commingle production. A TAML Level 3 junction does not provide hydraulic isolation, and its use is restricted to consolidated formations.
TAML Level 4 junctions are applicable in both consolidated and unconsolidated formations because both the lateral and the main bore are cased and cemented at the junction. The junction provides full bore access to the lateral, and mechanical support is supplied by the tubulars and cement. However, because the cement can only withstand limited differential pressure, the junction does not provide hydraulic isolation.
TAML Level 5 wells do provide hydraulic isolation at the junction because pressure integrity is provided by the completion, which includes production tubing connecting a packer in the main wellbore above the junction and a packer in the lateral wellbore. Because hydraulic isolation and support are provided by the completion hardware, the junction may be a TAML Level 2, 3, or 4 before the Level 5 completion is installed. TAML Level 6 wells also provide hydraulic isolation at the junction. A well at this level differs from a TAML Level 5 well in that pressure integrity is provided by the main wellbore casing and a cemented or uncemented liner in the lateral. The cost and complexity of creating a single-metal-element dual-bore casing junction downhole has prevented TAML Level 6 wells from being developed. As of today, the category exists as a result of early experiments. Because multilateral wells that have higher TAML designations are generally more complex, they are more costly, and their configurations are more flexible. As they do with multilateral geometry, engineers choose a TAML level junction based primarily on reservoir characteristics, costs, and function.
The ability to reenter the lateral for well intervention operations is another multilateral well design consideration. Because it is a directionally drilled section that has no junction, the lower lateral is almost always easily accessed using standard intervention methods. Operators must make an economics-based decision during the well planning stage to include junctions that allow lateral access after pulling the upper completion, through-tubing access, junctions that can be adopted to allow access after installation or junctions through which no access is possible to main bore, lateral, or both. If the well includes more than one lateral, a selective through-tubing access system would need to be considered. The decision to deploy lateral junctions that allow full bore or restricted access is a function of the overall well design. Engineers usually opt for full bore access if a packer is to be placed below the junction or if an artificial lift system must be located near the lower lateral. In addition, based on their knowledge of the reservoir, operators may require full bore access to perform perforating, stimulation, logging, water shutoff, gravel packing, cleanout, and other remedial operations. Full bore access can be adapted to all TAML level junctions but must be specified before installation; some commercially available junctions allow no access or only restricted access to either the lateral or the main bore and cannot be adapted after installation.
The decision to use a multilateral well system and what type to use are the result of cost benefit analyses. In general, the less-complex junctions present operators with lower risks and costs. But risk mitigation and cost savings must be balanced against individual well and field development expectations. In low-value reservoirs, a simple open hole lateral that has no reentry capability may increase ultimate reserve recovery or accelerate production while having little impact on overall drilling and completion costs. In high-value deepwater plays, installing a hydraulically sealed TAML Level 5 or 6 junction can drive total well costs into millions of dollars and still be a good investment because it may save drilling another well with a complex and tortuous trajectory, preserve a well slot on an existing production platform, or eliminate the need entirely to procure and install additional subsea infrastructure.
In implementations, a multilateral well is drilled and completed with a TAML Level 4 junction. The junction includes a pump and a fluid separator. The pump includes any pump capable of drawing in fluid through the pump intake, pressurizing it, and lifting it to the surface such as an electrical submersible pump, sucker-rod and pump jack, progressive cavity pump, gas lift and intermittent gas lift, reciprocating and jet hydraulic pumping systems, etc. The fluid separator and the pump can be above, at, or below the junction. The upper completion includes a retrievable electrical submersible pump packer while the lower completion has an orientation liner hanger or other orientation device.
While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. Many variations, modifications, additions, and improvements are possible. Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.
In some implementations, a mechanical junction (not to be confused with the earthen junction of 2 earthen wellbores) may comprise a junction with a monolithic Y-Block. In some implementations, a monolithic Y-Block may provide for more robust connections to the other components of a junction assembly (i.e. main bore leg, lateral leg, tank, etc.).
To illustrate,
The DOWSS 1408 may process the formation fluid 1402 to separate out nonproduction fluid 1406 from production fluid 1422. The DOWSS 1408 may also process the formation fluid 1402 to separate sediment from at least one of the nonproduction fluid 1406 or the production fluid 1422. The DOWSS 1408 may transport the nonproduction fluid 1406 into the lateral bore 1450 for disposal in a disposal zone 1420 for the nonproduction fluid 1406 in the subsurface formation around the lateral bore 1450. The DOWSS 1408 may also transport sediment 1425 into the lateral bore 1451 for disposal in a disposal zone 1424 for the sediment 1425 in the subsurface formation around the lateral bore 1451. The DOWSS 1408 may also transport the production fluid 1422 and sediment 1410 to a surface of the multilateral well. Accordingly, in this example, the sediment may be disposed downhole into a highly permeable zone downhole and/or may be transported to the surface of the multilateral well or to a subsea or seafloor location.
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said systems and components related to system 1400, such as DOWSS 1408, in order to prevent premature failure and increase efficiencies as described within.
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said Level 5 junction assembly for use with a downhole oil, water and solids separator system and components related to system shown in
To help illustrate,
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said DOWSS system and components related to systems shown in
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said service tools and components related to systems shown in
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., the isolation sleeve, deflection device and related tools described above and some shown in
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., the non-Level 5 junction, its components, and related tools in order to prevent premature failures and increase efficiencies as described within.
The above examples of junctions are provided as nonlimiting examples—as other type of junctions may be used. The placement of the DOWSS, the DOWSS components, the tubing/fluid paths are also non-limiting examples—as other placements, components, paths may be used. The terms “downhole” and “below” may or may not be considered equivalent depending on the type of wellbore. For example, “downhole” and “below” may be considered the same for vertical wellbores. However, “downhole” and “below” may be considered different for horizontal wellbores.
Example implementations may include Subsea Oil Water Solids Separation (SOWSS). Example implementations may include disposal of solids, storage of water, and oil maybe subsea—on the seafloor or in storage wells or in storage vessels embedded in or sitting on the seafloor (or combination of both).
In some implementations, this fluid transported to the surface of the subsea production well 1902 may be transported to a ship 1930 via a multiphase pump 1918 and risers 1922. The ship 1930 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1930 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 1930 may be transported down below to a subsea injection well 1934 via a water injection pump 1932. The water 1942 may be pumped downhole into the subsea injection well 1934. As shown, the water 1942 may be returned for storage in the reservoir 1914. Water injected into an oil reservoir may be done to either pressurize the reservoir to encourage the fluid to flow to the low pressure area (near the well 1902).
In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1902 may remain below (instead of being transported to the ship 1930). For example, after being transported to the surface, the fluid may be transported to a location 1905 at the subsea surface 1904 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1904 at a location 1908. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1904 at a location 1906. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 1904.
Accordingly, fluid from the subsea production well 1902 may be pumped to subsea surface 1904 for processing, temporary storage, transport, water injection to maintain reservoir pressure, water flood from the subsea injection well 1934 to push hydrocarbons to the subsea production well 1902 and/or disposal.
In some implementations, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some implementations, the solids, non-commercial fluids, a combination of both, etc. may be produced, separated, processed, stored and then injected into the disposal well (or other designated well).
To illustrate,
In some implementations, this fluid transported to the surface of the subsea production well 2002 may be transported to a ship 2030 via a multiphase pump 2018 and risers 2022. The ship 2030 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 2030 may also include storage for the production fluid. As shown, the solids (drill cuttings) separated out from the production fluid by equipment of the ship 2030 may be transported down below to the subsea disposal well 2034 via a pump 2032. The solids (drill cuttings) 2042 may be pumped downhole into the subsea disposal well 2034 for storage in the reservoir 2014.
In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 2002 may remain below (instead of being transported to the ship 2030). For example, after being transported to the surface, the fluid may be transported to a location 2005 at the subsea surface 2004 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 2004 at a location 2008. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 2004 at a location 2006. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 2034.
Another example location may include an oil storage and transfer unit 2308. Another example location may include a solids or slurry transfer line 2312. For example, a flow diverter may help mix, remix, stir, or agitate solids to keep them in suspension in the solids or transfer line 2312. Another example location may include a production fluids/oil-cut fluid/fluid transfer line 2314. 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 2314. Another example location may include a well 2316 with vertical, inclined, sloped, deviated, tortuous paths.
Another example location may include a multilateral well 2318 (that includes a lateral wellbore, junction, etc.). Another example location may include a horizontal well 2320. Another example location may include a main production transfer line 2322 to another subsea pumping, gathering, and/or processing station or to land-based pumping, gathering, and/or processing facility.
One or more computers, such as computer 270, and sensors may monitor, control, diagnose, maintain, and repair, etc., said Subsea DOWSS (Downhole Oil Water Solids Separation) systems and components to prevent premature failure and increase efficiencies as described within.
The computer 2400 also includes a processor 2411 and a controller 2424 which may perform the operations described herein. For example, the processor 2411 may determine when a temporary storage tank is full of solids, one or more discharge areas are plugged with solids, the flow rate through a separation system, etc. The controller 2423 may perform an operation based on the measurements within the separation system such as transporting solids to a sediment injector to dispose of the solids into a lateral of the multilateral wellbore. The processor 2411 and the controller 2423 can be in communication. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 2401. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 2401, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in
Example implementations are now described.
Implementation #1: A well system comprising: a sediment separator to be positioned downhole in a well, wherein the sediment separator is configured to receive a formation fluid from a subsurface formation surrounding the well, the sediment separator configured to separate out sediment from the formation fluid, wherein the sediment is disposed or stored at surface of the well or a different downhole location in the well; and a fluid separator to be positioned downhole in the well, the fluid separator configured to receive the formation fluid from the sediment separator, wherein the fluid separator is configured to separate the formation fluid into production fluid and nonproduction fluid.
Implementation #2: The well system of Implementation #1, wherein the sediment is to be temporarily stored in one or more solids containers downhole after being separated from the formation fluid.
Implementation #3: The well system of Implementation #1, further comprising: a sediment injector configured to inject the sediment into a flow channel for delivery of the sediment to a destination location that comprises at least one of the surface of the well or the different downhole location in the well.
Implementation #4: The well system of Implementation #1, wherein the well is a multi-bore well configured with a first bore and a second bore.
Implementation #5: The well system of Implementation #4, wherein the formation fluid is received from the subsurface formation surrounding the first bore, and wherein the sediment, the nonproduction fluid, or any combination thereof is disposed of into the subsurface formation surrounding the second bore.
Implementation #6: The well system of Implementation #1, further comprising: a production flow channel configured to deliver the production fluid to the surface of the well.
Implementation #7: The well system of Implementation #6, wherein a sediment injector is configured to inject the sediment into the production flow channel for delivery of the sediment to the surface of the well while the production fluid channel continues to deliver the production fluid to the surface of the well.
Implementation #8: The well system of Implementation #7, wherein one or more chemicals are added to the production fluid to carry the sediment to the surface.
Implementation #9: The well system of Implementation #8, wherein the one or more chemicals include one or more chemicals to increase a viscosity of the production fluid.
Implementation #10: The well system of Implementation #1 further comprising: a production flow channel configured to deliver the nonproduction fluid to the surface of the well, wherein a sediment injector is configured to inject the sediment into the nonproduction fluid for delivery of the sediment to the surface of the well with nonproduction fluid.
Implementation #11: The well system of Implementation #1, wherein the nonproduction fluid includes water.
Implementation #12: The well system of Implementation #1, wherein the production fluid includes hydrocarbons.
Implementation #13: The well system of Implementation #1, wherein the sediment separator is configured to receive the formation fluid directly from the subsurface formation, a well bore, or one or more devices that transport a fluid.
Implementation #14: The well system of Implementation #1, wherein the sediment separator is positioned in a flow path of the nonproduction fluid downstream of the fluid separator and configured to separate the sediment from the nonproduction fluid, and wherein the sediment separator is positioned in a flow path of the production fluid downstream of the fluid separator and configured to separate the sediment from the production fluid.
Implementation #15: The well system of Implementation #1, wherein one or more sediment separator components may be removed from the sediment separator for cleaning, repair, or replacement, and wherein one or more fluid separator components may be removed from the fluid separator for cleaning, repair, or replacement.
Implementation #16: The well system of Implementation #1, wherein one or more parameters of an inlet of the sediment separator may depend on fluid properties, sediment properties, or any combination thereof, and wherein the one or more parameters of the inlet of the fluid separator may depend on the fluid properties, the sediment properties, or any combination thereof, and wherein the one or more parameters includes shape, orientation, or any combination thereof.
Implementation #17: The well system of Implementation #1, wherein the sediment separator includes a hydrocyclone configured with a backpressure device configured to control a pressure in the hydrocyclone, and wherein the fluid separator includes the hydrocyclone configured with the backpressure device configured to control the pressure in the hydrocyclone.
Implementation #18: The well system of Implementation #1, wherein the sediment separator is configured with one or more transportation systems to prevent sediment from accumulating at a discharge end of the sediment separation.
Implementation #19: The well system of Implementation #9, wherein at least one of a sediment separator, a fluid separator, a sediment injector, or a chemical injector, is configured with one or more sensors.
Implementation #20: The well system of Implementation #19, wherein a component is configured with one or more computers.
Implementation #21: The well system of Implementation #20, wherein the computer may sense a one or more parameter of a component and perform one or more of monitoring, testing, controlling, troubleshooting to, in order to extend the life or prevent failure by at least one of adjusting, diagnosing, analyzing, repairing, or maintaining a separator, a sediment injector, and/or a chemical injector and/or component thereof.
Implementation #22: The well system of Implementation #21, wherein a computer comprises at least an instruction from an Artificial Intelligence processor, an Artificial Intelligence algorithm, a Machine Learning processor, and/or a Machine Learning algorithm.
Implementation #23: A method comprising: receiving, from a subsurface formation into which a well is formed, formation fluid into a downhole separation system positioned in the well; separating, via the downhole separation system, sediment from the formation fluid, wherein the sediment is disposed or stored at surface of the well or a different downhole location in the well; and separating, via the downhole separation system, the formation fluid into production fluid and nonproduction fluid.
Implementation #24: The method of Implementation #23, wherein the well is a multi-bore well configured with a first bore and a second bore.
Implementation #25: The method of Implementation #24 further comprising: receiving, from the subsurface formation surrounding the first bore of the well, the formation fluid; distributing the nonproduction fluid into one or more flow channels configured to deliver the nonproduction fluid to at least one of a surface of the multi-bore well or to the subsurface formation surrounding the second bore of the multi-bore well; and distributing the production fluid into one or more flow channels configured to deliver the production fluid to surface of the multi-bore well.
Implementation #26: The method of Implementation #23 further comprising: separating, via a sediment separator, the sediment from the formation fluid, the production fluid, the nonproduction fluid, or any combination thereof; and temporarily storing the sediment in one or more solids containers that are located downhole in the well.
Implementation #27: The method of Implementation #26 further comprising: transporting the sediment from the one or more solids containers to a sediment injector, wherein the sediment is mixed with the production fluid, the nonproduction fluid, or any combination thereof to generate a solid-laden slurry; and injecting the solid-laden slurry to a destination location.
Implementation #28: The method of Implementation #27 further comprising: detecting, via one or more sensors, a volume of the sediment in the one or more solids containers; diverting flow of the production fluid, the nonproduction fluid, or any combination thereof to the one or more solids containers to generate the solid-laden slurry; and transporting the solid-laden slurry to the sediment injector based on the volume of the sediment in the one or more solids containers.
Implementation #29: The method of Implementation #28, wherein a timing of the injection of the solid-laden slurry is coordinated with the production of the production fluid in a tubing.
Implementation #30: The method of Implementation #28, wherein the destination location includes surface, a cavern in the subsurface formation, another location in the well, or any combination thereof.
Implementation #31: The method of Implementation #28, wherein a computer is configured to sense a one or more parameter of the one or more flow channels, solids containers, sediment injector, formation fluid, nonproduction fluid, production fluid, solid-laden slurry or a component thereof, and perform one or more of monitoring, testing, controlling, troubleshooting, adjusting, diagnosing, analyzing, repairing, and/or maintaining a downhole separation system or component thereof.
Implementation #32: A downhole separation system positioned in a well formed in a subsurface formation comprising: a sediment separator configured to be positioned downhole in the well and configured to receive a formation fluid from the subsurface formation, the sediment separator configured to separate out sediment from the formation fluid; a fluid separator configured to be positioned downhole in the well and configured to receive the formation fluid from the sediment separator, wherein the fluid separator is configured to separate the formation fluid into production fluid and nonproduction fluid; and a sediment injector configured to be positioned downhole in the well and configured to inject the sediment to a destination location.
Implementation #33: The downhole separation system of Implementation #32, wherein the well is a multi-bore well configured with at least a first bore and a second bore.
Implementation #34: The downhole separation system of Implementation #33, wherein the fluid separator is configured to receive the formation fluid from the subsurface formation surrounding a first bore, wherein the nonproduction fluid is distributed into one or more flow channels configured to deliver the nonproduction fluid to at least one of a surface of the well or to a second bore of the well, and wherein the production fluid is distributed into one or more flow channels configured to deliver the production fluid to surface of the well.
Implementation #35: The downhole separation system of Implementation #34, wherein a chemical is added to at least one of the sediment, the production fluid, or the nonproduction fluid to aid in carrying the sediment to the destination location.
Implementation #36: The downhole separation system of Implementation #32, wherein the sediment separator and the fluid separator are oriented with respect to gravity.
Implementation #37: The downhole separation system of Implementation #32, wherein the nonproduction fluid is transported to surface, and wherein the nonproduction fluid is disposed into a location beneath the surface, and separate from the well, for storage.
Implementation #38: The downhole separations system of Implementation #32, wherein the production fluid is transported to surface, and wherein the nonproduction fluid is disposed into a location beneath the surface, and separate from the well, for storage.
Implementation #39: The downhole separation system of Implementation #35, wherein a computer may sense a one or more parameter of the one or more flow channels, sediment injector, fluid separator, formation fluid, nonproduction fluid, production fluid, or a component thereof, and perform one or more of monitoring, testing, controlling, troubleshooting, adjusting, diagnosing, analyzing, repairing, and/or maintaining a downhole separation system or component thereof.
Implementation #40: The downhole separation system of Implementation #39, wherein a computer may comprise at least an instruction from an Artificial Intelligence processor, an Artificial Intelligence algorithm, a Machine Learning processor, and/or a Machine Learning algorithm.
| Number | Date | Country | |
|---|---|---|---|
| 63585080 | Sep 2023 | US |
