Patent Application
20250109675
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.
As wells age, they may produce more water. To decrease the lifting and production cost related to produced water, Downhole Oil-Water Separation (DOWS) operations may be implemented to separate the water downhole and inject it into another portion of the well. This may include disposing of the separated produced water into one or more legs of a multilateral well.
Many oil-water separation systems may rely on the difference in density of the fluids to be separated. Many of the systems may rely on gravitational effects to allow the fluids to separate. Laminar flow may be required to allow gravitation to separate the fluids. However, to achieve a laminar flow in a downhole oil-water mixture, the fluid may need a Reynolds Number of less than 2,000 which may require fluid to flow at less than 200 BFPD in pipes having a diameter of 7.532″.
Example implementations may create a device and/or system to produce laminar flow at higher flow rates. For example, in a downhole pipe with an inside diameter of 7.532″, some implementations may achieve laminar flow at flow rates of 500 BFPD or higher. Example implementations may include one or more rotors that stir or otherwise perturb a turbulent flow of fluid that includes oil and water. Introducing perturbation in a turbulent flow may lead to a complete collapse of turbulence—allowing the flow to fully relaminarize. Once relaminarization is achieved, the flow may remain laminar provided that the pipe is straight and smooth. Hence, after passing through the rotors and proceeding downstream, turbulence in the fluid may reduce and the flow may become laminar. In laminar flow, the fluid may enter a fluid separation device that may separate the oil and water. Because the fluid reaches the fluid separation device in laminar flow, the fluid separation device may utilize gravity to separate water and oil.
Example implementations may relate to downhole oil/water separation (DOWS) systems. Some implementations may be part of a multilateral well completion design that may include a perturbation device, a fluid separator, and other components (such as a sediment separator) near or at the junction between a main bore and a lateral bore. The 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 on the main bore) into production fluid and nonproduction fluid. For instance, the fluid separator may include components for separating oil and water. The fluid separator also may include components for separating gas, oil, and water. 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 the 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.
In
The nonproduction fluid 116 may include sediment. In some implementations, the sediment may be separated out from the nonproduction fluid 116 prior to the nonproduction fluid 116 being injected back a subsurface formation. Therefore, the separation system 124 may also include sediment separator(s) to separate out sediment from the nonproduction fluid 116. The separation system also may include devices to separate out sediment, solids, fluids, and/or gases from the formation fluid.
In some implementations, the sediment that has been separated out may be stored downhole (at least temporarily). In some implementations, the sediment may be delivered to the surface of the multilateral well or another downhole location using a flow channel (such as a tubing string). Examples of another downhole location may include a cavern, a disposal wellbore, a thief zone, etc. This flow channel may be the production tubing string 106 used to deliver production fluid to a surface of the multilateral well. In some implementations, this flow channel may be a separate tubing string for delivery of the sediment and/or other fluids to the surface of the multilateral well or to a different downhole location.
In some implementations, the separation system 124 may include sediment injector(s) to receive the sediment separated out by the sediment separator(s). The sediment injector(s) may inject this sediment into the production tubing string 106 (used to deliver the production fluid to a surface of the multilateral well) to deliver this sediment to the surface of the multilateral well. Alternatively or in addition, the sediment injector(s) may inject this sediment into a separate tubing string to deliver this sediment to the surface of the multilateral well or to a different downhole location.
The formation fluid 118 flows into the fluid separator 296. In this example, the fluid separator 296 comprises a gravity-based separation that includes the separator 201. As shown, the formation fluid 118 moves from a smaller to a larger diameter of the tubing. 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 (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 mostly horizontal pipe because of their differences in densities, viscosities, velocities, inclination of pipe, and/or differences in one or more other characteristics, properties, compositions, constitutions, natural influencers, influences resulting from the nature or design of the system, etc. 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 densities between the two types of fluid.
The nonproduction fluid with sediment 294 flows into the sediment separators 290A-290N, which may represent one to any number and type of sediment separators. In some implementations, each of the sediment separators 290A-290N may separate some of the sediment in the nonproduction fluid with sediment 294. For example, the first sediment separator 290 may be used to separate and collect the largest size (denser) sediment; the second sediment separator 290 may be used to separate and collect the next largest size sediment; the third sediment separator 290 may be used to separate and collect the next largest size sediment; etc. (as the flow moves from right to left through the different sediment separators). For example, at least one of the sediment separators 290 may be a cyclonic separator—wherein larger (denser) particles in the rotating stream having too much inertia to follow the tight curve of the stream. Such particles may thus strike the outside wall and fall to the bottom of the cyclone where they may be removed. In some implementations, each of the sediment separators 290 may store the sediment that was collected into an associated storage area or tank.
Additionally, the chemical injector(s) 291 may inject one or more chemicals into at least one of the formation fluid 118, the production fluid 114, the nonproduction fluid with sediment 294, the nonproduction fluid 116, or the sediment 295. While depicted such that chemicals are injected downhole, alternatively or in addition, chemicals may be injected from the surface of the 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, wax, 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.), etc. In particular, crude oils often contain paraffins which precipitate and adhere to the liner, tubing, sucker rods and surface equipment as the temperature of the producing stream decreases in the normal course of flowing, gas lifting or pumping. Heavy paraffin deposits are undesirable because they reduce the effective size of the flow conduits and restrict the production rate from the well. Where severe paraffin deposition occurs, removal of the deposits by mechanical, thermal or other means is required, resulting in costly down time and increased operating costs.
In some implementations, these different collections of the sediment by the different sediment separators 290 may be injected into a same or different line or tubing for disposal. As shown, the sediment injector(s) 299 are coupled to receive the sediment collected by the different sediment separators 290.
Periodically, sediment may need to be emptied from the different sediment separators 290 via the sediment injector(s) 299. The decision of when may be based on different criteria. For example, pressure and/or production flow may be monitored at the surface of the multilateral well. If the pressure and/or production flow start to degrade, it may be an indication that sediment needs to be emptied from the sediment separators 290.
In some implementations, sensors may be coupled to each of the tanks of the sediment separators 290. In some embodiments, there may be more tanks than separators, less tanks than separators (one tank for more than one separator). In some embodiments the tanks may be as simple as sections of the casing, a tubular, and/or a flow path for the formation fluid 118, nonproduction fluid 116, production fluid 114, or other fluid(s). In some embodiments, the tanks may comprise one or more features of one or more fluid transporting channel or device (such as the tube between sediment separator 290A and lower pump 292). The sensors also may be located at other places such pump inlets, pump discharges, separator inlets/outlets, fluid conduits/connectors/features. 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 well) may be communicatively coupled to the sensors such that the controller may initiate a sequence to empty one or more of the tanks of the sediment separators 290.
In some implementations, the sediment injector(s) 299 may dispose of these sediments by injecting them into a tubing for delivery to the surface of the multilateral well. For example, the sediment may be delivered to the surface using the production tubing or a separate tubing. If the production tubing is used, the solids may be included with the production fluid that is being delivered to the surface. In such implementations, separation operations may be performed at the surface to separate out the solids from the production fluid 114 or the non-production fluid 116. If the production tubing is used, the solids may be mixed with non-production fluid 116 and then delivered to the surface.
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. If sediment is included with the non-production fluid 116 being delivered to the surface, the non-production fluid 116 may be delivered to surface equipment that provides for separation of the 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.). Sediment may include any solids, particles, conglomerates such as fine silt, clay, paraffin, asphaltenes. resins, silt, gums, salt crystals, scale, and others. In some implementations, sediment may be disposed to different locations depending on their size. For example, for sediment having a size greater than X, such solids may be delivered to the surface of the multilateral well for disposal. For sediment having a size less than X but greater than Y, such sediment may be disposed in a first downhole location (such as a thief zone). For the remaining sediment that have a size less than Y, such solids may be disposed in a second downhole location (such as a lateral well). In some implementations, the sediment may be ground or otherwise reduced to a smaller size for disposal at a downhole location.
Some implementations may include weir skimmers that function by allowing the oil floating on the surface of the water to flow over a weir. In some implementations, the weir skimmers may require the weir height to be manually adjusted. Alternatively, the weir skimmers may be such that the weir height is automatic or self-adjusting. While manually adjusted weir skimmer types may have a lower initial cost, the requirement for regular manual adjustment makes self-adjusting weir types more popular in most applications. Weir skimmers may collect water if operating when oil is no longer present. To overcome this limitation, the weir type skimmers may include an automatic water drain on the oil collection tank.
Accordingly, example implementations may detect the accumulation of solids in DOWS equipment. An operator (or other device) may be signaled that the solids should be removed. In response, an operational change in the DOWS equipment may be initiated to allow solids removal. For example, this may include shut down or reduction of DOWS-related operations (decrease or shut down pumps, switch valves that direct fluids to the surface and/or other location, etc.). Preparation of the solid's removal process may be initiated. For example, access sleeves and flushing ports may be opened, solids directional control equipment may be adjusted (e.g., change position), injection devices, sleeves, ports, valves, etc. may be closed, solids processing/removal equipment (from surface and/or downhole) may be deployed, etc. Additionally, flushing, dislodging, scrapping, chemically treating, fluidically treating, mechanically treating, etc. of downhole solids from one or more locations downhole may be enabled. Solids and related debris from the DOWS system (DOWSS) may be displaced. In some implementations, solids and other materials may be collected from the DOWSS. The solids and other materials may be transported from the DOWSS. Fluids, chemicals, solvents, acids, liquids, abrasive media, solids and other materials may be transported from the surface to the DOWSS.
Items such as water, chemicals and other items listed above may be transported in a controlled manner. For example, the transporting in a controlled manner may be based on speed, velocity, volumes, ratios, time-based (e.g., until a certain amount of time has passed), function-based (e.g., until a certain pressure-drop is experienced, until fluid has been circulated “bottoms up”, etc.). For example, the transporting in a controlled manner may be based on when Z number of tubing strings of fluid has been pumped or until X-amount (e.g., pounds, mass, volume, etc.) of debris has been recovered, collected, injected, disposed, transferred, etc. Tools, devices, flow, etc. may be moved, shifted, directed, etc. to improve the solids collecting, removal, retaining, and flushing process(es). For example, a direction of a jetting nozzle may be changed, one flushing port may be closed while opening another, etc. Tools, devices, components, strings, etc. may be repositioned from one location to another to continue the one-or-more above processes. Additionally, tools, devices, components, strings, etc. may be repositioned to dispose of solids in a preferred location.
One or more fluids, chemicals, solvents, acids, liquids, abrasive media, solids and other materials may be moved from the surface of the well to the DOWSS to enhance the longevity of the DOWSS. This may include applying and/or re-applying friction reducing coatings, replacing components—filters, stators, pumps, rotors, bearings, bearing assemblies, worn parts, eroded parts, electrical components, sensors, computers, controllers, logic devices, parts intend to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.
Also, the shutting down of the solid's removal process may be initiated. For example, access sleeves and flushing ports may be closed, solids directional control equipment may be adjusted. Injection devices, sleeves, ports, valves, etc. may be opened. Solids processing and removal equipment may be retrieved (from the surface and/or other location downhole. Used or worn devices from well may be retrieved. Such devices may include filters, stators, pumps, rotors, bearings, bearing assemblies, worn parts, eroded parts, electrical components, sensors, computers, controllers, logic devices, parts intend to be consumed including wear pads, erosion pads, corrosion pads, filters, screens, etc.
An operational change in the DOWS equipment may be initiated to allow fluid separation again. This may include “turning on” or increase of DOWSS-related operations (e.g., increase or turn-on pumps, switch valves that direct fluids to the surface and/or downhole, etc.). Also, the operator (or other device) may be signaled that the DOWSS equipment has been re-configured out of the solids-removal status and is ready to begin fluid separation operations. The DOWS may then return back to fluids separation mode. Additionally, there may be provided a continuous or occasional status check of the “health” of DOWS equipment.
It should be noted that the DOWS system and components noted may be inclusive of items from the wellhead to the toe of each wellbore and more. The cables and/or energy conduits that provide power to the one or more ESPs and/or other pumps and prime movers (downhole and on surface) may be inclusive. The surface components that transport the fluids and solids (everything) out of the well may be included. Subsea trees, subsea DOWS equipment, platform, land-base, jack up, drillship, etc. types of equipment may be inclusive. Data lines, data processing, sensors, in the well and outside of the well may be inclusive. Fluid processing equipment and processes in the well and outside of the well may be inclusive. Solids processing equipment and processes in the well and outside of the well may be inclusive.
Example implementations may be applied to other types of remote operations where the tools, operations, processes are separated from the operators by distances, barriers, adverse environments, etc. The ability to remotely test to determine or verify whether functions were performed successfully and then communicate or report the tests results to a locale inhabitable by humans (e.g. the earth's surface) makes example implementations suitable for use in other remote locations with harsh environments such as outer space (e.g., satellites, spacecrafts, etc.), aeronautics (aircrafts, drones), on-ground (swamps, marshes, power generation, hydrogen or other gas extraction and/or transportation, etc.), below ground (mines, caves, etc.), ocean (on surface and subsea), subterranean (mineral extraction, storage wells (carbon sequestration, carbon capture and storage (CCS), etc.)), and other energy recovery activities (geothermal, steam, etc.). The unhabitable environments may comprise corrosive fluids (hydrocarbons, H2S fluids, CO2 fluids, acids, bases, gases, etc.), contaminants (sand, debris, paraffins, asphaltenes, etc.), high-temperature fluids (fluids from geothermal formations, injected fluids, etc.), cryogenic fluids, etc. Example implementations may be utilized in harsh conditions (e.g., corrosive environments or contaminated fluids), extreme pressures (e.g., >5,000-psi differential), extreme temperatures (e.g., >−20° F. or >300° F.), etc. In other instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail to avoid confusion.
Thus, in some implementations, the separators, pumps, and injector may be installed at the junction between the main bore and the lateral bore. In other implementations, such devices may be installed below this junction or above this junction. Further, the main bore or one or more lateral bores may include one or more devices which provide 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 (e.g., fluid separators) and other non-gravity separators may be used.
The multilateral junction may be placed above, below, or inside the target formation. In some implementations, this configuration may be accomplished in a two-trip multilateral completion that includes a lower completion and an upper completion that includes the fluid separator, a pump (such as an electrical submersible pump), and an upper packer. This simplifies the installation. This reduced complexity allows the fluid separator to be installed into existing wells, i.e., retrofitting existing wells. Further, the lateral well may be a target formation. In this implementation, the main bore passes through a target production formation and the lateral bore passes through a target injection formation which is a separate formation from the production formation. The existing wells do not require a tangent section at the junction for the placement of the fluid separator, significantly increasing the number of oil well candidates for installation of the fluid separator according to example implementations.
The design of the installed completion equipment may be critical for the downhole fluid separator to function as intended. By installing the fluid separators, pumps, and sediment injector(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 decreases 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 (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 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.
The DOWSS may include flow inlet devices, oil-separation devices, water-separation devices, perturbation devices, flow outlet devices, flow outlet conduits (tubing, screens, y's, tees, splitters, etc.), fluid transport devices, fluid screening devices, formation support devices (liners, casings, screens, injection ports, and valves (including Outflow Control Devices (including automatic, chokes, restrictors, regulating, etc.). The outflow control devices may comprise one or more features similar to inflow control devices such Inflow Control Devices (ICD's), Automatic Inflow Control Devices (AICD's), Gravity-based ICD's, AIDC's, etc., Viscous-based ICD's, AIDC's, etc., Inertial-based ICD's, pumps, regulators, sensors, controllers, relays, transmitters, floats, etc.
All the example perturbation devices described herein may operate in concert with one or more fluid separators. However, the fluid separators may not be shown in the drawings. For example, fluid with turbulent flow may flow through one or more perturbation devices that cause the turbulent flow to settle into laminar flow. In laminar flow, the fluid may flow into one or more fluid separators that separate the fluid into production fluid, nonproduction fluid, sediment, or any other suitable number and type of fluids. The fluid, in laminar flow, also may flow into other devices such as a solids catcher and remover, a coalescer, and other devices.
Fluid may flow from right to left through the tool 304. For example, fluid may flow through the perturbation device 302 and on through the solids catcher and remover 306 and coalescer 308. Before reaching the perturbation device 302, the fluid may have turbulent flow. The perturbation device 302 may introduce turbulence into the fluid. The added turbulence may settle the flow into laminar flow.
In some implementations, the perturbation device 302 is positioned approximately 130 diameters away from the solids catcher and remover 306. In some implementations, a diameter refers to the inner diameter of the tool 304 (such as approximately 7.532 inches). In some implementations, the perturbation device 302 may be positioned at any suitable distance away from the solids catcher and remover 306.
The perturbation device 302 may include four rotors (only three may be seen in the side view). However, in other implementations, the perturbation device 400 may include any suitable number of rotors. The rotors 402 may include a single blade rotating about an axis. Each rotor 402 may be mounted on a cylindrical element through which fluid may flow. In some implementations, the rotors 402 are powered via a power cable that connects power from the surface to the perturbation device 400. In other implementations, the rotors 402 may be powered by a generator disposed in a wellbore of the multilateral well system.
In some implementations, the perturbator includes one or more protrusions helically disposed about a rotor 402. The protrusions may change position and shape with respect to the fluid and flow changes. These protrusions may be shaped similar to VIV strakes, possibly longer and more limber. In some implementations, the protrusions may be disposed on a fixed device that does not rotate. The protrusions may reside downstream from the flow. The VIV strakes may facilitate VIV suppression. The strakes may modify flow, tripping the production of Karman vortices so that they act less coherently.
The perturbation device 302 also may include one or more cylindrical elements 508 mounted on each support member 506. A rotor 504 may be mounted on each of the cylindrical elements 508. The rotor 504 may include four blades. Alternatively, the rotor 504 may include a unitary blade that includes four tines. However, in other embodiments, the rotor 504 may include any suitable number of blades or tines. In some instances, one or more perturbation devices 302 may serve more than one purpose such as changing flow parameters (e.g., acting as a perturbation device to change flow from turbulent to laminar) and/or to act as a coalescing device. Also, perturbation devices 302 that perform more than one function may have one or more functions controllable/changeable due to the change of one or more sensed parameters. In some implementations, the perturbation device 302 (or one or more of its components) may be designed to move out of the flow path so cleaning tools, maintenance tools, coiled tubing, etc. may pass by the device. For example, the rotor 504, cylindrical elements 508, and support members 506 may fold outwards against the inner diameter (ID) wall of the tool 304 when a different tool/device needs to pass by the perturbation device 302. One or more parts of perturbation device 302 may be locked in the retracted position until the other tool is pulled back above perturbation device 302. One or more components of perturbation device 302 may be articulated open and/or closed by an actuator, motor, hydraulic powered unit, hinge, latching device, etc. The articulation may occur with the aid of one or more sensors, controllers, signals, and/or other components.
As shown, the upstream segment 702 may be separated from the perturbation segment 704 by a distance of 20 times the inner diameter of the tubular 700. The downstream segment 706 may be separated by 130 times the inner diameter of the tubular 700.
As fluid flows from the upstream segment 702 to the perturbation device 302, the fluid may exhibit turbulent flow. As the fluid flows through the perturbation device 302, the perturbation device 302 may introduce additional turbulence into the fluid. For example, the perturbation device 302 may include rotors that disrupt and/or change the energy state of the fluid, thereby introducing additional turbulence into the fluid. As the fluid flows through the downstream segment 706, the fluid may settle into laminar flow. In some implementations, the fluid settles into laminar flow in a distance of approximately 130 times the inner diameter of the tubular 700. In a laminar flow, the fluid may flow into a fluid separator (not shown in
The turbine-driven electrical generator 802 may produce electrical power as fluid flows across the rotor 804, thereby causing it to spin. The turbine-driven electrical generator 802 may be electrically connected to the perturbation device 302 via the conductor 810. The turbine-driven electrical generator 802 may provide power by which the perturbation device 302 introduces turbulence into fluid flowing through the tool 304. After the turbulence is introduced, the fluid may settle into a laminar flow.
Example operations are now described.
At block 1102, production is initiated. For example, with reference to
At block 1104, formation fluid is received into a downhole separation system. For example, with reference to
At block 1106, flow of formation fluid is separated into one or more flow paths. For example, with reference to
At block 1108, the flow rate is decreased. For example, with reference to
At block 1110, 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 more means (including those mentioned above). For example, with reference to
At block 1112, flow is separated into one or more flow paths. For example, with reference to
At block 1114, gravitational separation is performed. For example, with reference to
At block 1116, non-gravitational separation is performed. For example, with reference to
At block 1118, stepped-sized separation is performed. For example, with reference to
At block 1120, solids and lighter fluids are accumulated. For example, with reference to
Operations of the flowchart 1100 continue at transition point A, which continues at transition point A of
At block 1202, solids are separated and discharged into temporary holding tanks. For example, with reference to
At block 1204, solids are transported for disposal. For example, with reference to
At block 1206, solids are transported to an injector. For example, with reference to
At block 1208, solids may be mixed at the injector. For example, with reference to
At block 1210, solids (or slurry) are injected. For example, with reference to
At block 1212, 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 1214, injection process is monitored and controlled. For example, with reference to
In some implementations, output flow of one, or both, of the productive fluid and/or non-productive fluids may be adjusted. This may occur by adjusting the upper pump 293 and/or adjusting the lower pump 292. The upper pump 293 and/or the lower pump 292 may be a variable pump where the flow is variable via a swash-plate type of pump. The upper pump 293 may be a variable speed pump where the speed of the motor that is driving it can be sped up and slowed down to control the flow (and/or pressure) of the system.
The separators 290A-N may have their own motors or hydraulic pumps driven from a hydraulic pump that is driven by one or more of the pumps 293 and 292. There are different types of motors that could be used downhole—such as: brushed or brushless, single-phase, two-phase, or three-phase, axial or radial flux, and may be air-cooled or liquid-cooled. The different types of motors may include permanent magnet synchronous motor (PMSM), a switched reluctance motor, or an induction (asynchronous) motor. They may also use neodymium magnets and be outrunners (the stator is surrounded by the rotor), inrunners (the rotor is surrounded by the stator), or axial (the rotor and stator are flat and parallel). The motors may include one or more Brushless DC electric motors (BLDC). In the BLDC motor, a controller may adjust the phase and amplitude of the current pulses that control the speed and torque of the BLDC motor. Any of these motors may be sealed within air-filled or oil-filled cavities, or these motors may use a flooded design that allows water to come into contact with the motor, providing extra cooling and lubrication.
Operations of the flowchart 1200 continue at transition point B, which continues at transition point B of
At block 1304, a fluid separator configured to be positioned in the borehole separating, the formation fluid having the laminar flow into production fluid and nonproduction fluid.
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 1597 during a Technology Advancement of Multilaterals (TAML) Forum held in Aberdeen. These standards classify junctions as TAML Level 1, 2, 3, 4, 5, or 6 based on mechanical complexity, connectivity, and hydraulic isolation. The ascending order of these levels reflects increasing mechanical and pressure capability of the junction. Consequently, cost, complexity, and risk also generally increase at the higher TAML levels. However, other considerations of the well design also influence the overall complexity of the well—for example, a TAML Level 2 well with an advanced intelligent completion can be more complex and costly than a TAML Level 5 well with a simpler completion system.
In a TAML 1 well, the main bore, lateral, and junction are uncased. This basic lateral is designed to enhance reservoir drainage from consolidated formations. It has the advantage of low drilling and completion costs, but the open hole junction makes reentry into the lateral wellbore and control of flow from the lateral impossible.
Wells that have cased and cemented main bores and open hole laterals are designated TAML Level 2. A cemented main bore significantly reduces the risk of wellbore collapse and provides isolation between laterals. By placing sliding sleeves and packers in the main bore, operators can produce the bores singly or in commingle production.
Placing a liner in the lateral and mechanically connecting it to the cased and cemented main bore results in a TAML Level 3 well. A liner is a string of casing that does not extend to the surface but is anchored or suspended inside a previously run casing string. This TAML Level 3 well includes a lateral that is cased but not cemented at the junction. It is a relatively low-cost option that includes reentry capabilities and a lateral that is better supported than that of Levels 1 and 2. Using sliding sleeves and packer plugs, operators can produce the bores singly or in commingle production. A TAML Level 3 junction does not provide hydraulic isolation, and its use is restricted to consolidated formations.
TAML Level 4 junctions are applicable in both consolidated and unconsolidated formations because both the lateral and the main bore are cased and cemented at the junction. The junction provides full bore access to the lateral, and mechanical support is supplied by the tubulars and cement. However, because the cement can only withstand limited differential pressure, the junction does not provide hydraulic isolation.
TAML Level 5 wells do provide hydraulic isolation at the junction because pressure integrity is provided by the completion, which includes production tubing connecting a packer in the main wellbore above the junction and a packer in the lateral wellbore. Because hydraulic isolation and support are provided by the completion hardware, the junction may be a TAML Level 2, 3, or 4 before the Level 5 completion is installed. TAML Level 6 wells also provide hydraulic isolation at the junction. A well at this level differs from a TAML Level 5 well in that pressure integrity is provided by the main wellbore casing and a cemented or uncemented liner in the lateral. The cost and complexity of creating a single-metal-element dual-bore casing junction downhole has prevented TAML Level 6 wells from being developed. As of today, the category exists as a result of early experiments. Because multilateral wells that have higher TAML designations are generally more complex, they are more costly, and their configurations are more flexible. As they do with multilateral geometry, engineers choose a TAML level junction based primarily on reservoir characteristics, costs, and function.
The ability to reenter the lateral for well intervention operations is another multilateral well design consideration. Because it is a directionally drilled section that has no junction, the lower lateral is almost always easily accessed using standard intervention methods. Operators must make an economics-based decision during the well planning stage to include junctions that allow lateral access after pulling the upper completion, through-tubing access, junctions that can be adopted to allow access after installation or junctions through which no access is possible to main bore, lateral, or both. If the well includes more than one lateral, a selective through-tubing access system would need to be considered. The decision to deploy lateral junctions that allow full bore or restricted access is a function of the overall well design. Engineers usually opt for full bore access if a packer is to be placed below the junction or if an artificial lift system must be located near the lower lateral. In addition, based on their knowledge of the reservoir, operators may require full bore access to perform perforating, stimulation, logging, water shutoff, gravel packing, cleanout, and other remedial operations. Full bore access can be adapted to all TAML level junctions but must be specified before installation; some commercially available junctions allow no access or only restricted access to either the lateral or the main bore and cannot be adapted after installation.
The decision to use a multilateral well system and what type to use are the result of cost benefit analyses. In general, the less-complex junctions present operators with lower risks and costs. But risk mitigation and cost savings must be balanced against individual well and field development expectations. In low-value reservoirs, a simple open hole lateral that has no reentry capability may increase ultimate reserve recovery or accelerate production while having little impact on overall drilling and completion costs. In high-value deepwater plays, installing a hydraulically sealed TAML Level 5 or 6 junction can drive total well costs into millions of dollars and still be a good investment because it may save drilling another well with a complex and tortuous trajectory, preserve a well slot on an existing production platform, or eliminate the need entirely to procure and install additional subsea infrastructure.
In embodiments, a multilateral well is drilled and completed with a TAML Level 4 junction. The junction includes a pump and a fluid separator. The pump includes any pump capable of drawing in fluid through the pump intake, pressurizing it, and lifting it to the surface such as an electrical submersible pump, sucker-rod and pump jack, progressive cavity pump, gas lift and intermittent gas lift, reciprocating and jet hydraulic pumping systems, etc. The fluid separator and the pump can be above, at, or below the junction. The upper completion includes a retrievable electrical submersible pump packer while the lower completion has an orientation liner hanger or other orientation device.
While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. Many variations, modifications, additions, and improvements are possible. Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.
In some implementations, a mechanical junction (not to be confused with the earthen junction of 2 earthen wellbores) may comprise a junction with a monolithic Y-Block. In some implementations, a monolithic Y-Block may provide for more robust connections to the other components of a junction assembly (i.e., main bore leg, lateral leg, tank, etc.).
To illustrate,
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 1510 to a surface of the multilateral well. Accordingly, in this example, the sediment may be disposed downhole into a highly permeable zone downhole and/or may be transported to the surface of the multilateral well.
To help illustrate,
The above examples of junctions are provided as nonlimiting examples—as other type of junctions may be used. The placement of the DOWSS, the DOWSS components, the tubing/fluid paths are also non-limiting examples—as other placements, components, paths may be used. The terms “downhole” and “below” may or may not be considered equivalent depending on the type of wellbore. For example, “downhole” and “below” may be considered the same for vertical wellbores. However, “downhole” and “below” may be considered different for horizontal wellbores.
Example implementations may include Subsea Oil Water Solids Separation (SOWSS). Example implementations may include perturbation of fluids, separation of fluids, disposal of solids, storage of water, and oil maybe subsea—on the seafloor or in storage wells or in storage vessels embedded in the seafloor.
In some implementations, this fluid transported to the surface of the subsea production well 1802 may be transported to a ship 1830 via a multiphase pump 1820 and risers 1822. The ship 1830 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1830 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 1830 may be transported down below to a subsea injection well 1834 via a water injection pump 1832. The water 1842 may be pumped downhole into the subsea injection well 1834. As shown, the water 1842 may be returned for storage in the reservoir 1814.
In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1802 may remain below (instead of being transported to the ship 1830). For example, after being transported to the surface, the fluid may be transported to a location 1805 at the subsea surface 1804 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1804 at a location 1808. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1804 at a location 1806. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 1804.
Accordingly, fluid from the subsea production well 1802 may be pumped to subsea surface 1804 for processing, temporary storage, transport, water injection to maintain reservoir pressure, water flood from the subsea injection well 1834 to push hydrocarbons to the subsea production well 1802 and/or disposal.
In some embodiments, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some embodiments, the solids, non-commercial fluids, a combination of both, etc. may be produced, separated, processed, stored and then injected into the disposal well (or other designated well).
To illustrate,
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 1920 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 solids (drill cuttings) separated out from the production fluid by equipment of the ship 1930 may be transported down below to the subsea injection well 1934 via a pump 1932. The solids (drill cuttings) 1942 may be pumped downhole into the subsea disposal well 1934 for storage in the reservoir 1914.
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. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 1934.
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.
Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed. As used herein, the term “or” is inclusive unless otherwise explicitly noted. Thus, the phrase “at least one of A, B, or C” is satisfied by any element from the set {A, B, C} or any combination thereof, including multiples of any element.
Example implementations include those described by the following clauses.
| Number | Date | Country | |
|---|---|---|---|
| 63586118 | Sep 2023 | US |
