DOWNHOLE PROCESSING AND DISPOSAL OF PRODUCED SOLIDS FROM A WELL

Abstract

A well system comprises a subsea system to be positioned on a floor of a subsea at or near a current well that is formed in a subsurface formation below the floor of the subsea. The subsea system comprises at least one solids reduction device to receive solids that were part of the subsurface formation from downhole at a surface of the current well, wherein the at least one solids reduction device is configured to reduce a size of at least a portion of the solids.

Description

BACKGROUND

Oil and gas wells produce significant amounts of water in their lifetime. The percentage of water produced from these wells is called the water cut, the ratio of the water produced from the well compared to the volume of the total liquids produced. Most wells produce an ever-increasing water cut throughout their productive life. In many oil fields around the world the percentage of water recovered with oil has risen to be greater than the percentage of the oil. In fact, in many fields, the percentage of oil has decreased to be from about 20% in an excellent field to about 2% in a relatively poor field.

The end of a well's productive life is often determined by the water cut. A well is typically shut in when the value of the hydrocarbons produced is no longer sufficient to economically cover the operating costs of the well and the cost of disposing of the produced water. Indeed, disposing of the produced water is not environmentally and economically friendly as energy is used to power the pump to lift the produced water to the surface, to separate the produced water from the oil, to transport the separated water as it cannot be disposed on the surface in most cases. Thus, the separated water must be transported to a remote well site to be reinjected into a subterranean formation. Therefore, decreasing the water cut of a well increases the value of the produced fluids and directly decreases the disposal costs of the produced water.

One method of reducing the water cut of a well is to separate produced water from the hydrocarbons downhole, rather than at surface. Downhole separation increases the value of the fluids produced to the surface. Downhole separation also facilitates disposal of the separated water. The separated water can be reinjected into the same production zone or into a different zone. Another way to improve the productivity of a well is to increase the length of the intersection of the productive zone by the well completion. One way of increasing this intersection length is by using multilateral wells. A multilateral well is a conventional well that has a lateral well that is drilled from a point in the original well. The lateral well increases productivity by allowing additional intersection length along the productive zone without the cost and delay involved in redrilling the upper part of the well. While multilaterals enable multiple intersections within the same productive zone, multilaterals also enable fluid communication with different productive zones within a reservoir. In certain reservoirs, operators can leverage this approach to improve reservoir production by accessing numerous production zones or by increasing the contact area between a wellbore and a formation with minimal increase in drilling and completion costs. These techniques also reduce the environmental footprint of drilling rigs and subsequent production trees, particularly for land operations. Therefore, the use of multilateral well increases the potential production of a well and can also enable disposal of the produced water in a different zone.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is a perspective view of a subsea system on a subsea floor that is to process, reduce and dispose of solids at the subsea floor, according to some embodiments.

FIG. 2 is a perspective view in partial cross sectional of a multilateral well system, according to some embodiments.

FIG. 3 is side view of an example downhole separation system, according to some embodiments.

FIG. 4 is a flowchart of example operations for downhole fluid and solid separation, according to some embodiments.

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

FIG. 6 is a cross-sectional view of an example of a Level 5 junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments.

FIG. 7 is a cross-sectional view of an embodiment where the isolation sleeve can be shifted out of the way (or retrieved) and a deflection device installed to aid in deflecting one or more tools or devices out into a lateral bore, according to some embodiments.

FIG. 8 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS embodiments with a non-Level 5 junction, according to some embodiments.

FIG. 9 is a perspective view of a first example subsea DOWSS, according to some embodiments.

FIG. 10 is a perspective view of a second example subsea DOWSS, according to some embodiments.

FIG. 11 is a perspective view of types of offshore well that may benefit from example implementations, according to some embodiments.

FIG. 12 is a perspective view of an example subsea downhole oil water solids separation, according to some embodiments.

FIG. 13 is a perspective view of example locations in which example embodiments may be used.

DESCRIPTION

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. Additionally, relative terms such as down or up within a well or wellbore may be changed and still be within example implementations.

Example implementations may include a subsea system that is positioned on a floor of a sea. This subsea system may process, reduce, and dispose of solids brought from downhole to a surface of a current well. In some implementations, the current well may be a “multilateral well” or “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.

In some implementations, the subsea system may be used in conjunction with a Downhole Oil-Water Separation (DOWS) System and Downhole Oil-Water-Solids Separation (DOWSS) System. As used herein, DOWS and DOWSS may be used interchangeably. Moreover, the acronyms DOWS and DOWSS herein may be used interchangeably. For example, the current well may include a DOWSS for downhole separation in the current well. Solids from this downhole separation may be transported to a current well on the floor of a subsea. The subsea system may be positioned at or near the current well and may process and dispose of the solids (output from the DOWSS) brought to a current well on a floor of a subsea (as further described below).

In some implementations, the subsea system may include at least one solids reduction device. For example, the at least one solids reduction device may include at least one rock crusher. For instance, the at least one solids reduction device may include a primary crusher and a secondary crusher for reducing the size of the solids brought to the surface of the current well. The subsea system may also include a number of different transport mechanisms for transporting the solids for processing and disposal of the solids. For example, the subsea system may include a number of conveyors to transport the solids to different devices of the subsea system.

An output from the primary crusher may be placed into a hopper (which may serve as an accumulator). The solids from the hopper may serve as an input to the secondary crusher. Such a configuration with a hopper may ensure that the secondary crusher may have solids to process during its operation.

In some implementations, the output from the secondary crusher may be added to the output from the hopper. A conveyor may feed these outputs into a screening. The screening device may be configured such that solids that are too large are input into the secondary crusher for further reduction of these solids. Otherwise, the screening device may output those solids that are not too large to a different conveyor for further processing. Accordingly, the subsea system may be configured to reduce a size of solids until such solids have a size that is below a maximum size threshold. In some implementations, the maximum size threshold may be 5 millimeters (mm), 6 mm, 10 mm, 25 mm, 20 micrometers (μm), 25-μm, etc.

In some implementations, the subsea system may include one or more grinders. For example, a grinder may be positioned to receive the output from the screening device to further reduce the size of the solids. In some implementations, operations of the subsea system (such as the crushing, grinding, etc.) may develop a foam. For example, operations that introduce water as part of the reduction of the solids may result in the introduction of foam. Accordingly, the subsea system may include one or more floatation devices to skim off the foam. Other devices may be used to skim off the foam. For example, in some implementations, a centrifuge device may be used. In some implementations, the floatation device may be positioned after at least one of the crushers or the grinder.

Certain parts or devices of the subsea system may wear and/or break over time—thereby potentially introducing metal into the solids. Some implementations may include a device to remove this metal from the solids. For example, in some implementations, the subsea system may include a magnetic separation device to remove this unwanted metal. Such a magnetic separation device may be positioned before any of the devices in the subsea system. For example, a magnetic separation device may be positioned before the solids are input into one or more of the solids reduction devices, the grinder, the solids separation device, etc. In some implementations, the subsea system may include hydrometallurgy to extract metals from the solids.

In some situations, the solids brought from a current well may include material (e.g., clay) that is used to plug off a subsurface formation. In some implementations, such material needs to be removed from the solids (especially if such solids are transported back down the current well or a different well). Examples of solids that may be too small may include material (such as bentonite) that is introduced into the drilling mud during drilling to seal off the well. For example, such material may be introduced into the drilling mud to prevent or limit water from leaking into the wellbore. In some implementations, the subsea system may include a filtration device to remove these types of solids. In particular, the filtration device may remove solids having a size that is below a minimum size threshold. In some implementations, the minimum size threshold may be 0.1 millimeters (mm), 0.05 mm, 0.01 mm, 0.001, 0.5 micrometers (μm), 20 μm, etc.

Therefore, some implementations may process solids at the floor of the subsea such that solids have a size that is within a range (between a minimum size threshold and a maximum size threshold (see description about regarding reduction of the solids). Such solids that are within this defined range may be disposed of back down into the current well or a different well formed in a subsurface formation below a floor of the subsea. For example, assume the current well is a multi-lateral well and that the solids are brought to the surface of the current well from a first bore of the multi-lateral well. While not shown in FIG. 1, the current well may include other equipment. For example, a wellhead, a Christmas tree, and production-control equipment may be located on the floor of the sea. In some implementations, solids that are returned back down into the current well may be disposed of in a second bore of the multi-lateral well. This defined range of the solids transported back downhole into the current well or a different well may vary. For example, the range may be 0.1-6 millimeters (mm), 0.05-10 mm, 0.01-5 mm, 0.001-6 mm, 0.001-6 mm, 0.5- to 50-μm, 20-μm-25-mm, etc.

In some implementations, those solids that are separated out by the subsea system may be disposed of on the subsea floor. For example, those solids, whose size does not fall in the defined size range to be transported downhole back in the current well and/or in a different well formed in the subsea floor, may be disposed onto the subsea floor. Alternatively or in addition, those solids may instead be disposed by being transported to the surface of the water. For example, those solids may be transported to a ship at the surface of the water. Additionally, there may be a number of approaches to processing the solids brought to the surface of the current well at the floor of a subsea. In some implementations, these solids may be stored in a location on the floor of the subsea for transport to the surface of the water. For example, a tank storing these solids may be transported to the surface of the water. This tank may be replaced by an empty tank for storage of the solids at the subsea floor.

In some implementations, the devices and components of the subsea system may be enclosed such that they are not exposed to the surrounding water. Some implementations may include a digital twin or model to enable simulation of the subsea system. Such implementations may provide a diagnosis and/or solution to a problem occurring during operation of the subsea system. In some implementations, operations of the subsea system may be automated. For example, the subsea system may include intelligent automation (including performing operations, diagnosing and solving problems that may occur during operations, etc. independent of manual intervention). The subsea system may include deep or machine learning to provide proper operation of the equipment, devices, etc. In some implementations, the term “formation fluid” may include unaltered (non-processed) formation fluids, fluids that may have been partially processed fluids (downhole or on the seafloor), etc.

Example Subsea System

FIG. 1 is a perspective view of a subsea system on a subsea floor that is to process, reduce and dispose of solids at the subsea floor, according to some embodiments. FIG. 1 depicts a subsea system 100 that is positioned below a surface 150 of the water and on or near a subsea floor 126. In FIG. 1, a current well 102 and a different well 103 are both formed in a subsurface formation below the subsea floor 126. The current well 102 may be a multi-lateral well, a single bore well, etc., from which solids are received by the subsea system 100. In some implementations, the different well 103 may be a disposal well into which solids that have been processed by the subsea system 100 are disposed. Also, as shown in FIG. 1, a ship 152 may be positioned at the surface 150 of the water. The ship 152 may be used to assist in the operations of the subsea system 100. For example, the ship 152 may retrieve and store solids that have been processed by the subsea system 100.

The subsea system 100 includes a number of transport devices for transporting solids to a different devices and/or locations. These transport devices are described as conveyors but may be any other type of device for transporting of solids.

The subsea system 100 may include one or more solids reduction devices to reduce a size and a quantity of the solids. In this example, the subsea system 100 includes a primary crusher 106 that is to receive solids from the current well 102 via a conveyor 104. The primary crusher 106 may perform a first reduction of the size of the solids received. The output from the primary crusher 106 is then input into a hopper 110 via a conveyor 108.

The output from the hopper 110 is coupled to an input of a screening device 120 via a conveyor 118. The screening device 120 may be configured such that solids that are too large are input into a secondary crusher 114 (via a conveyor 121) for further reduction of these solids. Otherwise, the screening device 120 may output those solids that are not too large to an input of a grinder 124 via a conveyor 122. The grinder 124 may further reduce a size of the solids. In some implementations, the subsea system 100 may include additional grinders. For example, a grinder may be positioned at the output of the primary crusher 106, and a grinder may be positioned at the output of the secondary crusher 114. Accordingly, the subsea system 100 may be configured to reduce a size of solids until such solids have a size that is below a maximum size threshold. The output of the secondary crusher 114 may be fed onto a conveyor 116 which is then added with the solids on the conveyor 118 (to be input into the screening device 120).

In some implementations, operations of the subsea system (such as the crushing, grinding, etc.) may develop a foam. For example, operations that introduce water as part of the reduction of the solids may result in the introduction of foam. Accordingly, the subsea system 100 may include one or more floatation devices to skim off the foam. In FIG. 1, the output from the grinder 124 is coupled to an input of a floatation device 159 via a conveyor 170. In some implementations, the subsea system 100 may include additional floatation devices. For example, a floatation device may be positioned at the output of the primary crusher 106, and a floatation device may be positioned at the output of the secondary crusher 114.

The output of the floatation device 159 may be coupled to an input of a magnetic separation device 151 via a conveyor 172. In particular, certain parts or devices of the subsea system 100 may wear and/or break over time-thereby potentially introducing metal into the solids. Accordingly, some implementations may include the magnetic separation device 151 to remove this metal from the solids. While FIG. 1 depicts one magnetic separation device 151, in some implementations, such a magnetic separation device may be positioned before any of the devices in the subsea system 100. For example, a magnetic separation device may be positioned before the solids are input into one or more of the solids reduction devices, the grinder, the solids separation device, etc. In some implementations, the subsea system may include hydrometallurgy to extract metallurgy from the solids.

The output of the magnetic separation device 151 may be coupled to an input of a filtration device 161 via a conveyor 172. In particular, in some situations, the solids brought from a current well may include material (e.g., clay) that is used to plug off a subsurface formation during drilling and completion operations. In some implementations, such material needs to be removed from the solids (especially if such solids are transported back down the current well or a different well). Examples of solids that may be too small may include material (such as bentonite, illite, kaolinite, montmorillonite, glauconite, etc.) that is introduced into the drilling mud during drilling to seal off the well. For example, such material may be introduced into the drilling mud to prevent or limit water from leaking into the wellbore. The filtration device 161 may remove these types of solids. In particular, the filtration device 161 may remove solids having a size that is below a minimum size threshold.

The output of the filtration device 161 may be output to a conveyor 127. In some implementations, the output of the filtration device 161 may include solids having a size that is within a range (between a minimum size threshold and a maximum size threshold. These solids may be disposed of in one or more locations. For examples, such solids that are within this defined range may be disposed of back down into the current well 102 or the different well 102.

In some implementations, the current well 102 is a multi-lateral well such that the solids may be brought to the surface of the current well 102 from a first bore of the multi-lateral well. In some implementations, solids that are returned back down into the current well 102 may be disposed of in a second bore of the multi-lateral well. This defined range of the solids transported back downhole into the current well 102 or the different well 103 may vary. For example, the range may be 0.1-6 millimeters (mm), 0.05-10 mm, 0.01-5 mm, 0.001-6 mm, 0.001-6 mm, 0.5- to 50-μm, 20-μm-25-mm, etc.

In some implementations, those solids that are separated out by the subsea system 100 may be disposed of on the subsea floor 126. For example, those solids, whose size does not fall in the defined size range to be transported downhole back in the current well and/or in a different well formed in the subsea floor, may be disposed onto the subsea floor. Alternatively or in addition, those solids may instead be disposed by being transported to the surface of the water. For example, those solids may be transported to a ship 152 at the surface of the water. Additionally, there may be a number of approaches to processing the solids brought to the surface of the current well at the floor of a subsea. In some implementations, these solids may be stored in a location on the floor of the subsea for transport to the surface of the water. For example, a tank storing these solids may be transported to the surface of the water. This tank may be replaced by an empty tank for storage of the solids at the subsea floor. In some implementations, the devices and components of the subsea system 100 may be enclosed such that they are not exposed to the surrounding water.

In some implementations, water from the formation may be used to pump the solids downhole. For example, the subsea system may receive solids and water from downhole and may separate the water. This separated out water from the formation may be used to pump the reduced solids back down into the current well or the different well.

Example DOWS Systems

Example implementations of processing and reduction of solids on a subsea floor (as described above in reference to FIG. 1) may be performed in conjunction with a number of different well configurations. For example, these subsea floor operations may be performed with a multilateral well (as is now described). In particular, mature oilfields typically begin “watering out” in the later stages of their lives. The cost of producing the water is expensive. By separating the water from the oil downhole and then leaving the water downhole, lifting/production costs may be lowered. Solids may also be produced from the well and must be processed and disposed of as well. By processing, separating and/or disposing of the solids at a location other than the surface of the well, costs may be decreased, the downhole system may not be clogged, there is less wear and damage to component of the downhole system, etc.

To decrease the lifting and production cost related to produced water, Downhole Oil Water Solids Separation (DOWSS) operations may be implemented to separate the water and solids downhole and inject them into one or more portions of the well. This may include disposing of the separated produced water and/or solids into one or more legs of a multilateral well. One challenge of such configuration is dealing with the solids in these situations-solids may need to be reduced in size.

Downhole Oil Water Separation (DOWS) and/or Downhole Oil Water Solids Separation (DOWSS) operations may need to process and dispose of basic sediment, formation fines, etc. (hereinafter solids). In some implementations, DOWS operations and DOWSS operations may be the same or different operations. Example implementations may process and dispose of formation solids downhole to reduce the lifting cost of the solids (and water) to surface of the wellbore. These solids may be disposed at one or more downhole locations in this multilateral well (such as injection zone, a lateral well of this multilateral well, etc.). In some implementations, at least a portion of these formation solids may be transported to the surface of the multilateral well for disposal. For example, these formation solids transported to the surface may be disposed in a subsea storage vessel, another wellbore, etc.

As part of processing the solids downhole, some implementations may reduce the size of formation solids so they may be re-injected downhole without plugging injection zone(s) and/or the equipment within the multilateral well. Example implementations may reduce the size of formation solids using various devices (such as a grinder, hammermill, etc.). In some implementations, the formation solids may be separated out according to their properties (such as size), via different types of devices (such as screens). In some implementations, there may be multiple reduction devices downhole to reduce the formation solids (either serially and/or in parallel). For example, a first reduction device may reduce the formation solids having a size greater than A, a second reduction device may reduce the formation solids having a size less than A but greater than B, a third reduction device may reduce the formation solids having a size less than B but greater than C, etc. In some implementations, the reduction device(s) may be part of a closed loop such that the formation solids may continue to be reduced by the reduction device(s) until the size of the formation solids is below a size threshold. In some implementations, the size threshold is based on a criteria that comprises at least one of a permeability or porosity of an injection zone within a subsurface formation downhole in the multilateral well where the solids are to be injected, the average size of the cuttings being produced from this multilateral well and/or from this type of subsurface formation into which the multilateral well is being formed, etc.

In some implementations, a portion of the produced solids may be sent to surface while a different portion of the produced solids may be reinjected downhole. For example, a defined percentage (e.g., 10%) of the largest solids may be sent to the surface, while the remaining 90% are processed and reinjected downhole.

Thus, example implementations may adjust the composition (make-up) of the solids-laden fluids to be injected into another zone downhole. Example implementations may also adjust the composition (make-up) of the fluids to be produced at the surface of the well (e.g. produced fluids). The devices used for separation and/or reduction of the downhole solids may be located downhole and/or at a surface of a well. For example, these devices may be located on a subsea floor for offshore drilling, between the wellhead and the surface location, etc. In some implementations, the one or more fluids, solid-laden fluids, solids, or other fluid(s) may be treated chemically to enhance one or more properties (such as solids suspension, solids dispersion, lubricity, etc.).

Thus, example implementations may include separating out the formation solids from the fluids downhole and reducing the size of the formation solids downhole via a downhole reduction device (such as a grinder). Example implementations may include measuring the size of the formation solids and sorting these solids according to one or more criteria (such as size). Small-sized solids may be mixed and injected. However, larger-sized solids may be further processed (e.g., reduced in size) and/or transported to the surface of the well or other local location for storage, disposal, longer-term storage, etc.

After any reduction, these formation solids may be prepared, mixed, and injected into another downhole location (such as a lateral wellbore, thief zone, zone with certain permeability and/or porosity characteristics, etc.). Some implementations may allow for the formation solids (unprocessed, processed, reprocessed, etc.) to be stored in a downhole location temporarily. The formation solids may be gathered from the downhole system and/or temporary storage. These gathered formation solids may be transported for injection at a downhole location (cavern, disposal wellbore, thief zone, etc.) and/or uphole to a surface of the well via a production tubing.

In some implementations, an injector or other device may regulate the flow of fluids used for lifting/carrying the solids (unprocessed or ground or processed or combination thereof). For example, the injector or other device may increase the flow rate of the flow to the surface of the well to ensure that the solids being transported to the surface may be swept uphole.

In some implementations, an injector or other device may regulate chemicals being injected into the solids and/or lifting slurry, fluid, etc. For example, chemicals from the surface may be conveyed to one or more devices. The chemicals may be surfactants or other chemicals to increase the viscosity of the fluid so the solids 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 the fluid. Such implementations may dramatically reduce the plumbing cost.

While described in reference to a multilateral well, example implementations may be used in any other types of wells. Additionally, while described in reference to a DOWSS system, example implementations may be used in other types of downhole systems. For example, some wells may not necessarily produce water such that a fluid separator is not needed.

FIG. 2 is a perspective view in partial cross sectional of a multilateral well system, according to some embodiments. FIG. 2 depicts a multilateral well that includes a main bore 202 and a lateral bore 204. The main bore 202 may include an open hole horizontal well. The lateral bore 204 may be an open hole inclined well. Screens 205 may be positioned in the main bore 202 and the lateral bore 204. For example, one of the screens 205 may be positioned in the lateral bore 204 at the point where the formation fluid 218 enters the tubing to prevent the larger solids from even entering the tubing. While described as being screens, alternatively or in addition, slotted liners, perforated tubing, etc. may be used to prevent the larger solids from entering the tubing. On the other hand, one or more portions of either wellbore may be left as an open hole. In some implementations, a wellbore portion may have no tubulars installed.

In FIG. 2, a system 200 includes a separation system 224 that may include a combination of separators for both fluid and solids (such as sediment). The separation system 224 may include pumps and solid injector(s). An example of the separation system 224 is depicted in FIG. 3 (which is further described below). A formation fluid 218 from the lateral bore may be drawn into the separation system 224. The separation system 224 may include a fluid separator to separate formation fluid 218. The fluid separator may separate the formation fluid 218 into production fluid (such as hydrocarbons (e.g., oil, gas and/or a combination of oil and gas)) 214 and nonproduction fluid (such as water) 216. The production fluid 214 may be delivered uphole through a production tubing 206. The nonproduction fluid 216 may be delivered to the main bore 202 for injecting into the surrounding formation. Thus, example implementations may separate the nonproduction fluid downhole such that the nonproduction fluid may be directed back to the formation without any need to pump it back to the surface for separation and any transportation needed for storage.

The production fluid 214 and/or the nonproduction fluid 216 may include solids. In some implementations, the solids may be separated out from the production fluid 214 and/or the nonproduction fluid 216. For example, the solids may be separated from the nonproduction fluid 216 prior to the nonproduction fluid 216 being injected back a subsurface formation. Therefore, the separation system 224 may also include solid separator(s) to separate out solids from the nonproduction fluid 216.

In some implementations, the solids that have been separated out may be stored downhole (at least temporarily). In some implementations, the solids 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 206 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 flow channel may be an annulus between two tubulars (e.g. the annulus between the production casing string and tubing string 206, or the annulus between the intermediate casing string and the production casing string, etc.). In some implementations, the flow channel may be an open wellbore or a partially cased (lined) wellbore.

In some implementations, the separation system 224 may include reduction device(s) to reduce the size of the solids (as further described below). In some implementations, the separation system 224 may include solid injector(s) to receive the solids after separation and any reduction. The solid injector(s) may inject these into a downhole location (such as an injection zone). Alternatively or in addition, the solid injector(s) may inject these solids into the production tubing string 206 (used to deliver the production fluid to a surface of the multilateral well) to deliver these solids to the surface of the multilateral well.

FIG. 3 is side view of an example downhole separation system, according to some embodiments. For example, FIG. 3 depicts a separation system 300 that may be an example of the separation system 224 depicted in FIG. 2. The separation system 300 includes a tubing 387 that includes fluid separator(s) 396, solid separator(s) 304, chemical injector(s) 391, a pump 393, reduction device(s) 390, and solid injector(s) 399. Each of these components of the separation system 300 may represent one or more of the given component. For example, there may be one or more of a fluid separator, a solid separator, a chemical injector, a pump, a reduction device, and a solid injector. While the separation system 300 is depicted in a given order, example implementations include a separation system with components that are reordered or changed. For example, the solid separator 304 may be before the fluid separator so that the formation fluid 218 is processed to perform solid separation prior to fluid separation. One example for separating out the solids first is that such a system may reduce the amount of solids grinding equipment. For instance, if fluids are separated into production and nonproduction fluid prior to solid separation, then there may be two flow streams with solids that need to be separated therefrom. In some implementations, the separation system 300 may include more or less components. For example, the system 300 may not necessarily include fluid separation.

The formation fluid 218 flows into the fluid separator 396. In this example, the fluid separator 396 comprises a gravity-based separation. As shown, the formation fluid 218 moves from a smaller to a larger diameter of the tubing 387. This may decrease the velocity of the flow of the formation fluid 218—which allows the separation. In particular, most or at least a majority of the production fluid 214 may separate into a flow above a separator, while most or at least a majority of the nonproduction fluid with solid 394 may separate into a separate flow below a separator. This allows most of the solid to be captured in the lower portion of the tubing 387.

While described as having a separator, in some implementations, there is no separator. Rather, the production fluid 214 and the nonproduction fluid with solid 394 may naturally separate in a horizontal pipe because of their different density. Accordingly, even in a same tubing without a separator, most of the production fluid 214 would be above the nonproduction fluid 216 because of the differences in weight between the two types of fluid.

The nonproduction fluid with solid 394 flows into the solid separator 304, which may represent one to any number and type of solid separators. In some implementations, each of the solid separators 304 may separate some of the solid in the nonproduction fluid with solid 394. For example, the first solid separator 304 may be used to separate and collect the largest size (denser) solid; the second solid separator 304 may be used to separate and collect the next largest size solid; the third solid separator 304 may be used to separate and collect the next largest size solid; etc. (as the flow moves from right to left through the different solid separators). For example, at least one of the solid separators 304 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 solid separators 304 may store the solid that was collected into an associated storage area or tank.

Additionally, the chemical injector(s) 391 may inject one or more chemicals into at least one of the formation fluid 218, the production fluid 214, the nonproduction fluid with solid 394, the nonproduction fluid 216, or the solids 395. 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 remover, solvents, dispersants, etc. being added to the production fluid 214, a scavenger being added to the production fluid 214 to remove corrosive gases (H₂S) therefrom, etc. In particular, crude oils often contain paraffins which precipitate and adhere to the liner, tubing, sucker rods and surface equipment as the temperature of the producing stream decreases in the normal course of flowing, gas lifting or pumping. Heavy paraffin deposits are undesirable because they reduce the effective size of the flow conduits and restrict the production rate from the well. Where severe paraffin deposition occurs, removal of the deposits by mechanical, thermal or other means is required, resulting in costly down time and increased operating costs.

In some implementations, these different collections of the solid by the different solid separators 304 may be injected into a same or different line or tubing for disposal. As shown, the reduction device(s) 390 are coupled to receive the solids collected by the different solid separators 304.

Periodically, solids may need to be emptied from the different solid separators 304. 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 solid needs to be emptied from the solid separators 304.

In some implementations, sensors may be coupled to each of the tanks of the solid separators 304. A signal from a given sensor may indicate when the associated solid separator 304 needs to be emptied. A controller (downhole or at the surface of the multilateral well) may be communicatively coupled to the sensors such that the controller may initiate a sequence to empty one or more of the tanks of the solid separators 304.

As shown, the solid separators 304 may separate the solids 395 from the nonproduction fluid 216 (such as water). In some implementations, at least a portion of the solids 395 may be input into the reduction devices 390, while the remaining solids 395 may bypass the reduction devices 390 and be input into the solid injectors 399.

For example, some implementations may include measuring the size of the formation solids and sorting these solids according to one or more criteria (such as size). Small-sized solids may be input into the solid injectors 399 (bypassing the reduction devices 390). However, larger-sized solids may be input into the reduction devices 290 for further processing (e.g., reduced in size).

In some implementations, the solids 395 may be transported to the reduction devices 390 with some nonproduction fluid 216. For example, the solids 395 may be discharged in a slurry that includes the solids 395 and some nonproduction fluid 216. In some implementations, the percentage of the nonproduction fluid 216 that is included should be enough to suspend and carry the solids 395 to the reduction device(s) 390.

In some implementations, the percentage and flow rate of the nonproductive fluid 216 to be included with the solids 395 may be adjusted to flush and clean the system. For example, the percentage of the nonproductive fluid 216 may be 3%, 10%, 30%, 50%, 75%, 85%, 90% 95%, 97% or higher. The flow rate may be a function of one or more of the following: viscosity of the nonproductive fluid 216, size of the solids 395, amount of solids 395 that exceed the size threshold, amount of solids 395 that do not exceed the size threshold, density of 395, chemical makeup of the nonproductive fluid 216, etc.

The reduction devices 390 may be any type of device that can reduce a size of the solids. For example, the reduction devices 390 may be at least one of a grinder, a hammermill, etc. If there is more than one reduction device 390, the solids may be processed by the reduction devices 390 serially and/or in parallel. For example, a first reduction device 390 may reduce the formation solids having a size greater than A, a second reduction device 390 may reduce the formation solids having a size less than A but greater than B, a third reduction device 390 may reduce the formation solids having a size less than B but greater than C, etc. As shown, in some implementations, the reduction device(s) 390 may be part of a closed loop such that the formation solids may continue to be reduced by the reduction device 390 until the size of the formation solids is below a size threshold.

Accordingly, the reduction devices 390 may reduce the size of the solids 395 and then separate the solids 395 in to at least two categories: (1) solids that are larger than the size threshold or criteria and (2) solids that are less than or equal to the size threshold or criteria. As shown, the solids 395 that are larger than the size threshold or criteria may be recirculated back through the reduction devices 390 to be re-crushed. Some of the nonproduction fluid 216 may be used to transport these solids 395. The solids 395 that are less than or smaller than the size threshold or criteria may be transported to the solid injector(s) 399. Some of the nonproduction fluid 216 may be used to transport these solids to the solid injector(s) 399.

In some implementations, additional nonproduction fluid 215 may be needed to process and inject the correctly sized solids 395A back into the nonproduction fluid 216. This mixture of the nonproduction fluid 216 with the correctly sized solids 395A is shown by mixture 384. In some implementations, the flow of the additional nonproduction fluid 215 may be turned off and on such that the sized solids are injected only after enough have been collected. Likewise the flow of the additional nonproduction fluid 215 may be increased or decreased to flush and clean the system.

The solid injectors 399 may then mix and inject the right sized solids with the nonproduction fluid 216 at a downhole location (such as a lateral wellbore, thief zone, zone with certain permeability and/or porosity characteristics, etc.). Some implementations may allow for the formation solids (unprocessed, processed, reprocessed, etc.) to be stored in a downhole location temporarily. The formation solids may be gathered from the downhole system and/or temporary storage. These gathered formation solids may be transported for injection at a downhole location (cavern, disposal wellbore, thief zone, etc.) and/or uphole to a surface of the well via a production tubing (shown by solids 395B).

Accordingly, the solid injector(s) 399 may dispose of these solids by injecting them into a tubing for delivery to the surface of the multilateral well. For example, the solid 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 214.

Accordingly, if solids are being included with the production fluid 214 being delivered to the surface, the production fluid 214 may be delivered to surface equipment that provides for separation of the solid. Alternatively, during the time when the solids are not being included with the production fluid 214, the production fluid 214 may be delivered to different surface equipment that does not include such separation of solids.

Alternatively or in addition, the solid injectors 399 may deliver the solid 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, solids may be disposed to different locations depending on their size. For example, for solids having a size greater than X, such solids may be delivered to the surface of the multilateral well for disposal. For solid having a size less than X but greater than Y, such solid may be disposed in a first downhole location (such as a thief zone). For the remaining solid that have a size less than Y, such solids may be disposed in a second downhole location (such as a lateral well).

Example DOWSS Operations

FIG. 4 is a flowchart of example operations for downhole fluid and solid separation, according to some embodiments. FIG. 4 includes a flowchart 400 that is described in reference to FIGS. 2-3. While described in reference to a given number of operations in a given order, operations of the flowchart 400 may have more or less operations and/or in a different order. For example, injections of chemicals at blocks 404, 408, and 412 may be optionally operations such that no or one or more injections of such chemicals may be performed. Additionally, separation of the solids at block 410 may be performed before separation of the fluid at block 406. Operations of the flowchart 400 start at block 402.

At block 402, formation fluid is received downhole into a DOWSS or DOWS system (in a multilateral well). For example, with reference to FIG. 3, the system 300 receives the formation fluid 218.

At block 404, the formation fluid is injected with a chemical to assist with separation. For example, with reference to FIG. 3, the chemical injector 391 may be fluidly coupled with the formation fluid 218 before such fluid is input into the fluid separator(s) 396, such that the chemical injector 391 may inject a chemical into the formation fluid 218.

At block 406, the formation fluid is separated into production fluid and nonproduction fluid. For example, with reference to FIG. 3, the fluid separator(s) 396 separates the formation fluid 218 into the production fluid 214 (e.g., hydrocarbons) and the nonproduction fluid (with solids) 394 (e.g., water and solids).

At block 408, the nonproduction fluid is injected with a chemical to assist with separation. For example, with reference to FIG. 3, the chemical injector 391 may be fluidly coupled with the nonproduction fluid (with the solids) 394 before such fluid is input into the solid separator(s) 304, such that the chemical injector 391 may inject a chemical into the nonproduction fluid (with the solids) 394.

At block 410, solids are separated from the nonproduction fluid. For example, with reference to FIG. 3, the solid separator(s) separate the solids 395 from the nonproduction fluid 216.

At block 412, the separated out solids are injected with a chemical to assist with separation. For example, with reference to FIG. 3, the chemical injector 391 may be fluidly coupled with the solids 395 before such solids are input into the reduction device(s) 390, such that the chemical injector 391 may inject a chemical into the solids 395.

At block 414, a determination is made of whether the separated out solids are less than or greater than a size threshold. For example, with reference to FIG. 3, the reduction device(s) 390 may make this determination. In some implementations, this determination may be made using screens which may sort the solids according to their sizes. Those solids which pass through given size screens may be defined as less than the size threshold. Whereas those solids which do not pass through may be defined as greater than the size threshold. In some implementations, the size threshold is based on a criteria that comprises at least one of a permeability or porosity of an injection zone within a subsurface formation downhole in the multilateral well where the solids are to be injected, the average size of the cuttings being produced from this multilateral well and/or from this type of subsurface formation into which the multilateral well is being formed, etc. For those separated out solids greater than the size threshold, operations of the flowchart 400 continue at block 416. For those separated out solids less than the size threshold, operations of the flowchart 400 continue at block 418.

At block 416, the separated solids greater than the size threshold are reduced, using a downhole reduction device. For example, with reference to FIG. 3, the reduction device(s) 390 may perform this operation. For instance, the reduction device(s) may be grinders, hammermills, etc. In some implementations, there may be multiple reduction devices 390 to reduce the formation solids (either serially and/or in parallel). For example, a first reduction device may reduce the formation solids having a size greater than A, a second reduction device may reduce the formation solids having a size less than A but greater than B, a third reduction device may reduce the formation solids having a size less than B but greater than C, etc. In some implementations, the reduction device(s) may be part of a closed loop such that the formation solids may continue to be reduced by the reduction device(s) until the size of the formation solids is below a size threshold. Operations of the flowchart 400 return to block 414 to again determine whether these solids have now been reduced to be below the size threshold. Thus, the solids may continue in this closed loop until their size is below the size threshold.

In some implementations, at least some of the solids may not be reduced. Such reduction may not be performed because of the hardness of these solids. For example, in some producing zones, there may be extremely hard solids such as feldspar. Instead of creating excessive wear and tear on the grinding and processing equipment, it may be better just to dispose of these hard solids than to decrease the operating life of the equipment. In the event that the solids are not reduced in size, the remaining “large” solids may be disposed of in at one of three ways. First, the “large” solids may be injected into a channel (flow path) to surface-such as the production tubing. Second, the “large” solids may be injected into the injection zone with the other solids. Third, the “large” solids may be injected into another lateral or “disposal” zone. The “disposal” zone may have characteristics different than the “reinjection” zone. For example the “reinjection” zone may be in the same zone as the production fluids with the goal of assisting the pushing the hydrocarbons towards the production well (similar to how a water flood well works). While on the other hand, the “disposal” zone may be another zone away from the production zone; it may contain little or no hydrocarbons but have a high porosity/high permeability to accept the “large” solids.

At block 418, the separated solids less than the size threshold are injected or disposed. For example, with reference to FIG. 3, the solid injector(s) 399 inject or dispose of these separated solids. For instance, the solid injector(s) 399 may inject or dispose of these separated solids at a downhole location (cavern, disposal wellbore, thief zone, etc.) and/or uphole to a surface of the well via a production tubing. In some implementations, an injector or other device may regulate the flow of fluids used for lifting/carrying the solids (unprocessed or ground or processed or combination thereof). For example, the injector or other device may increase the flow rate of the flow to the surface of the well to ensure that the solids being transported to the surface may be swept uphole.

Example Multilateral Wells

Example implementations may be performed in different Technology Advancement of Multilaterals (TAML) Level wells. In particular, multilateral wells are characterized according to definitions established in 1997 during a Technology Advancement of Multilaterals (TAML) Forum held in Aberdeen. These standards classify junctions as TAML Level 1, 2, 3, 4, 5, or 6 based on mechanical complexity, connectivity, and hydraulic isolation. The ascending order of these levels reflects increasing mechanical and pressure capability of the junction. Consequently, cost, complexity, and risk also generally increase at the higher TAML levels. However, other considerations of the well design also influence the overall complexity of the well—for example, a TAML Level 2 well with an advanced intelligent completion can be more complex and costly than a TAML Level 5 well with a simpler completion system.

In a TAML 1 well, the main bore, lateral, and junction are uncased. This basic lateral is designed to enhance reservoir drainage from consolidated formations. It has the advantage of low drilling and completion costs, but the open hole junction makes reentry into the lateral wellbore and control of flow from the lateral impossible.

Wells that have cased and cemented main bores and open hole laterals are designated TAML Level 2. A cemented main bore significantly reduces the risk of wellbore collapse and provides isolation between laterals. By placing sliding sleeves and packers in the main bore, operators can produce the bores singly or in commingle production.

Placing a liner in the lateral and mechanically connecting it to the cased and cemented main bore results in a TAML Level 3 well. A liner is a string of casing that does not extend to the surface but is anchored or suspended inside a previously run casing string. This TAML Level 3 well includes a lateral that is cased but not cemented at the junction. It is a relatively low-cost option that includes reentry capabilities and a lateral that is better supported than that of Levels 1 and 2. Using sliding sleeves and packer plugs, operators can produce the bores singly or in commingle production. A TAML Level 3 junction does not provide hydraulic isolation, and its use is restricted to consolidated formations.

TAML Level 4 junctions are applicable in both consolidated and unconsolidated formations because both the lateral and the main bore are cased and cemented at the junction. The junction provides full bore access to the lateral, and mechanical support is supplied by the tubulars and cement. However, because the cement can only withstand limited differential pressure, the junction does not provide hydraulic isolation.

TAML Level 5 wells do provide hydraulic isolation at the junction because pressure integrity is provided by the completion, which includes production tubing connecting a packer in the main wellbore above the junction and a packer in the lateral wellbore. Because hydraulic isolation and support are provided by the completion hardware, the junction may be a TAML Level 2, 3, or 4 before the Level 5 completion is installed. TAML Level 6 wells also provide hydraulic isolation at the junction. A well at this level differs from a TAML Level 5 well in that pressure integrity is provided by the main wellbore casing and a cemented or uncemented liner in the lateral. The cost and complexity of creating a single-metal-element dual-bore casing junction downhole has prevented TAML Level 6 wells from being developed. As of today, the category exists as a result of early experiments. Because multilateral wells that have higher TAML designations are generally more complex, they are more costly, and their configurations are more flexible. As they do with multilateral geometry, engineers choose a TAML level junction based primarily on reservoir characteristics, costs, and function.

The ability to reenter the lateral for well intervention operations is another multilateral well design consideration. Because it is a directionally drilled section that has no junction, the lower lateral is almost always easily accessed using standard intervention methods. Operators must make an economics-based decision during the well planning stage to include junctions that allow lateral access after pulling the upper completion, through-tubing access, junctions that can be adopted to allow access after installation or junctions through which no access is possible to main bore, lateral, or both. If the well includes more than one lateral, a selective through-tubing access system would need to be considered. The decision to deploy lateral junctions that allow full bore or restricted access is a function of the overall well design. Engineers usually opt for full bore access if a packer is to be placed below the junction or if an artificial lift system must be located near the lower lateral. In addition, based on their knowledge of the reservoir, operators may require full bore access to perform perforating, stimulation, logging, water shutoff, gravel packing, cleanout, and other remedial operations. Full bore access can be adapted to all TAML level junctions but must be specified before installation; some commercially available junctions allow no access or only restricted access to either the lateral or the main bore and cannot be adapted after installation.

The decision to use a multilateral well system and what type to use are the result of cost benefit analyses. In general, the less-complex junctions present operators with lower risks and costs. But risk mitigation and cost savings must be balanced against individual well and field development expectations. In low-value reservoirs, a simple open hole lateral that has no reentry capability may increase ultimate reserve recovery or accelerate production while having little impact on overall drilling and completion costs. In high-value deepwater plays, installing a hydraulically sealed TAML Level 5 or 6 junction can drive total well costs into millions of dollars and still be a good investment because it may save drilling another well with a complex and tortuous trajectory, preserve a well slot on an existing production platform, or eliminate the need entirely to procure and install additional subsea infrastructure.

In embodiments, a multilateral well is drilled and completed with a TAML Level 4 junction. The junction includes a pump and a fluid separator. The pump includes any pump capable of drawing in fluid through the pump intake, pressurizing it, and lifting it to the surface such as an electrical submersible pump, sucker-rod and pump jack, progressive cavity pump, gas lift and intermittent gas lift, reciprocating and jet hydraulic pumping systems, etc. The fluid separator and the pump can be above, at, or below the junction. The upper completion includes a retrievable electrical submersible pump packer while the lower completion has an orientation liner hanger or other orientation device.

While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. Many variations, modifications, additions, and improvements are possible. Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.

In some implementations, a mechanical junction (not to be confused with the earthen junction of 2 earthen wellbores) may comprise a junction with a monolithic Y-Block. In some implementations, a monolithic Y-Block may provide for more robust connections to the other components of a junction assembly (i.e. main bore leg, lateral leg, tank, etc.).

To illustrate, FIG. 5 is a perspective view of an example of a Level 5 (mechanical) junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments. FIG. 5 depicts a system 500 having a multilateral well that includes a main bore 501, a lateral bore 550, and a lateral bore 551. Formation fluid 502 from the surrounding subsurface formation enters the main bore 501. The formation fluid 502 is transported through the main bore 501 uphole to a level 5 monolithic Y-block 504 and into a DOWSS 508.

The DOWSS 508 may process the formation fluid 502 to separate out nonproduction fluid 506 from production fluid 522. The DOWSS 508 may also process the formation fluid 502 to separate sediment from at least one of the nonproduction fluid 506 or the production fluid 522. The DOWSS 508 may transport the nonproduction fluid 506 into the lateral bore 550 for disposal in a disposal zone 520 for the nonproduction fluid 506 in the subsurface formation around the lateral bore 550. The DOWSS 508 may also transport sediment 525 into the lateral bore 551 for disposal in a disposal zone 524 for the sediment 525 in the subsurface formation around the lateral bore 551. The DOWSS 508 may also transport the production fluid 522 and sediment 510 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.

FIG. 6 is a cross-sectional view of an example of a Level 5 junction assembly for use with a downhole oil, water and solids separator system, according to some embodiments. In this embodiment, a main bore junction 610 is used to provide a main bore 602 for large tools to be passed through, or landed, in the y-block and/or main bore area of the junction 610. A lateral bore 604 is formed off the main bore 602 at the junction 610. In the example shown, an isolation sleeve 670 may be landed in the junction. As shown, the isolation sleeve 670 may provide pressure isolation between the formation fluids 606 and the nonproduction fluids 608. This main bore junction 610 may be used with a variety of different Downhole Oil Water Separator Systems (DOWSS) and/or components including the DOWSS and/or its components (and/or with a DOWS system and/or components of the DOWS) disclosed within herein. The main bore junction 610 may have a main bore leg inside diameter (ID) of 30% the outer diameter (OD) of the Junction's Y-Block. The main bore leg's ID may be 40% the OD of the Junction's Y-Block. The main bore leg's ID may be 50%, 53%, 55%, 60%, 67% or more of the Junction's Y-Block OD.

FIG. 7 is a cross-sectional view of an embodiment where the isolation sleeve can be shifted out of the way (or retrieved) and a deflection device installed to aid in deflecting one or more tools or devices out into a lateral bore, according to some embodiments. FIG. 7 depicts a main bore 702 and a lateral bore 704 that is formed off the main bore 702 at the junction 710. An isolation sleeve 770 may be shifted out of the way (or retrieved) to allow for a deflection device to be installed to aid in deflecting one or more tools or devices out into the lateral bore 704.

FIG. 8 is a cross-sectional view of a multilateral tool embodiment of one or more DOWSS embodiments with a non-Level 5 junction, according to some embodiments. In this example, the multilateral well is producing from a lateral bore 804 (instead of the main bore 802) so the earthen junction isn't over-pressure by fluid being injected in its surroundings. Formation fluid 806 is being produced from a subsurface formation surrounding the lateral bore 804. A tubular 892 in the main bore may include a port 891 to enable the flow of the formation fluid 806 to flow into the main bore. A DOWSS 870 may receive the formation fluid 806 and separate the formation fluid 806 into a nonproduction fluid 808, a sediment 872, and a production fluid 874. As shown, the nonproduction fluid 808 may be disposed of downhole by being transported into the main bore 802 for disposal in the surrounding subsurface formation. The sediment 872 may be disposed of downhole and/or transported to the surface of the multilateral well. The production fluid 874 may be transported to the surface of the multilateral well.

The above examples of junctions are provided as nonlimiting examples—as other type of junctions may be used. The placement of the DOWSS, the DOWSS components, the tubing/fluid paths are also non-limiting examples—as other placements, components, paths may be used. The terms “downhole” and “below” may or may not be considered equivalent depending on the type of wellbore. For example, “downhole” and “below” may be considered the same for vertical wellbores. However, “downhole” and “below” may be considered different for horizontal wellbores.

Example Subsea DOWSS (Downhole Oil Water Solids Separation)

Example implementations may include Subsea Oil Water Solids Separation (SOWSS). Example implementations may include 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).

FIG. 9 is a perspective view of a first example subsea DOWSS, according to some embodiments. FIG. 9 includes a subsea DOWSS 900 that includes a subsea production well 902 formed in a subsea surface 904. The subsea production well 902 may be formed through rock 912 and a reservoir 914. As described herein, production fluid (such as hydrocarbons 915) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 902.

In some implementations, this fluid transported to the surface of the subsea production well 902 may be transported to a ship 930 via a multiphase pump 920 and risers 922. The ship 930 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 930 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 930 may be transported down below to a subsea injection well 934 via a water injection pump 932. The water 942 may be pumped downhole into the subsea injection well 934. As shown, the water 942 may be returned for storage in the reservoir 914. 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 902).

In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 902 may remain below (instead of being transported to the ship 930). For example, after being transported to the surface, the fluid may be transported to a location 905 at the subsea surface 904 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 904 at a location 908. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 904 at a location 906. In some implementations (even though not shown), sediment (solids) separated out from this fluid may be stored at or under the subsea surface 904.

Accordingly, fluid from the subsea production well 902 may be pumped to subsea surface 904 for processing, temporary storage, transport, water injection to maintain reservoir pressure, water flood from the subsea injection well 934 to push hydrocarbons to the subsea production well 902 and/or disposal.

In some embodiments, the solids may be flowed to the sea floor and then injected into a disposal well (or other designated well). In some embodiments, the solids, non-commercial fluids, a combination of both, etc. may be produced, separated, processed, stored and then injected into the disposal well (or other designated well).

To illustrate, FIG. 10 is a perspective view of a second example subsea DOWSS, according to some embodiments. Offshore drilling rigs (on occasion) inject used drilling mud into a disposal well. FIG. 10 includes a subsea DOWSS 1000 that includes a subsea disposal well 1034 used for injection of used drilling mud (solids (drill cuttings) 1042). The subsea DOWSS 1000 also includes a subsea production well 1002. As shown, the subsea disposal well 1034 and the subsea production well 1004 may be formed in a subsea surface 1004. The subsea disposal well 1034 and the subsea production well 1002 may be formed through rock 1012 and a reservoir 1014. As described herein, production fluid (such as hydrocarbons 1015) and possibly nonproduction fluid, sediment, etc. may be transported from downhole to a surface of the subsea production well 1002.

In some implementations, this fluid transported to the surface of the subsea production well 1002 may be transported to a ship 1030 via a multiphase pump 1020 and risers 1022. The ship 1030 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The ship 1030 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 1030 may be transported down below to the subsea injection well 1034 via a pump 1032. The solids (drill cuttings) 1042 may be pumped downhole into the subsea disposal well 1034 for storage in the reservoir 1014.

In some implementations, at least some of the fluid transmitted to the surface of the subsea production well 1002 may remain below (instead of being transported to the ship 1030). For example, after being transported to the surface, the fluid may be transported to a location 1005 at the subsea surface 1004 for processing, separating, pumping, etc. Then, the nonproduction fluid (separated out from this fluid) may be stored below the subsea surface 1004 at a location 1008. Additionally, the production fluid (separated out from this fluid) may be stored below the subsea surface 1004 at a location 1006. The solids (drill cuttings) separated out from this fluid may be stored downhole in the subsea disposal well 1034.

FIG. 11 is a perspective view of types of offshore well that may benefit from example implementations, according to some embodiments. The lifting cost of producing formation water from 3000 meters (m) is very costly. The cost of lifting solids in a high-velocity rate is extremely erosive and costly. Separating out the solids and then lifting them at a slower rate will decrease the amount erosion. FIG. 11 depicts a number of offshore wells at different depths. In particular, FIG. 11 depicts a fixed platform well 1102 (that may be used up to 200 m), a compliant piled tower well 1104 (that may be used between 200-500 m), a tension leg platform (TLP) well 1106 (that may be used between 300-1500 m), a semi floating production system (FPS) well 1108 (that may be used between 300-2000 m), a single point anchor reservoir (SPAR) platform well 1110 (that may be used between 300-2000 m), and a floating production systems-(Floating Production Storage and Offloading) (FPSO) and subsea well 1112 (that may be used up to 3000 m).

FIG. 12 is a perspective view of an example subsea downhole oil water solids separation, according to some embodiments. FIG. 12 depicts a number of offshore rigs—an offshore rig 1202, an offshore rig 1204, and an offshore rig 1206. FIG. 12 also depicts a number of ships—a ship 1208, a ship 1210, a ship 1212, a ship 1214, a ship 1216, and a ship 1218. The offshore rigs 1202-1206 and the ships 1208-1218 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 1202-1206 and the ships 1208-1218 may also include storage for the production fluid, the nonproduction fluid, etc.

FIG. 12 also depicts a number of production wells-a production well 1220, a production well 1222, and a production well 1224. FIG. 12 also depicts a water disposal well 1226 and a solids disposal well 1228. The fluids/solids from the production wells 1220-1224 may be transported to any of the oil rigs 1202-1206, any of the ships 1208-1218 or another subsurface well. For example, the nonproduction fluid and the solids from the production wells 1220-1224 may be transported to the water disposal well 1226 and the solids disposal well 1228, respectively. Additionally, production fluid processing and separation, nonproduction fluid processing and/or solids processing may occur at one of more of the locations identified in FIG. 12.

FIG. 13 is a perspective view of example locations in which example embodiments may be used. FIG. 13 includes 11 example locations. A first example location includes a well 1302 where fluids may exit the well or are injected therein. A second example location includes an oil-cut processing unit 1304. For example, a flow diverter may divert oil-cut fluid to an oil-cut processing unit 1304. The oil-cut processing unit 1304 may include a flow diverter to remove more water from an oil-cut fluid. In some implementations, a flow diverter may divert solids, slurry, sludge, etc. to a processing unit 1306. Such solids, slurry, sludge, etc. may then be stored in a storage container or disposal well 1310. Flow diverter may be part of the storage container or disposal well 1310 to remove more oil from the slurry. The solids processing unit 1306 may include a flow diverter to remove more oil from the slurry.

FIG. 13 also depicts a number of offshore rigs—an offshore rig 1372, an offshore rig 1374, and an offshore rig 1376. FIG. 13 also depicts a number of ships—a ship 1378, a ship 1380, a ship 1382, a ship 1384, a ship 1386, and a ship 1388. The offshore rigs 1372-1376 and the ships 1378-1388 may include equipment to separate out nonproduction fluid (such as water) from the production fluid. The offshore rigs 1372-1376 and the ships 1378-1388 may also include storage for the production fluid, the nonproduction fluid, etc.

Another example location may include an oil storage and transfer unit 1308. Another example location may include a solids or slurry transfer line 1312. For example, a flow diverter may help mix, remix, stir, or agitate solids to keep them in suspension in the solids or transfer line 1312. Another example location may include a production fluids/oil-cut fluid/fluid transfer line 1314. 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 1314. Another example location may include a well 1316 with vertical, inclined, sloped, deviated, tortuous paths.

Another example location may include a multilateral well 1318 (that includes a lateral wellbore, junction, etc.). Another example location may include a horizontal well 1320. Another example location may include a main production transfer line 1322 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

Example implementations are now described.

Implementation #1: A well system comprising: a subsea system to be positioned on a floor of a subsea at or near a current well that is formed in a subsurface formation below the floor of the subsea, the subsea system comprising: at least one solids reduction device to receive solids that were part of the subsurface formation from downhole at a surface of the current well, wherein the at least one solids reduction device is configured to reduce a size of at least a portion of the solids.

Implementation #2: The well system of Implementation #1, wherein the at least one solids reduction device comprises a primary solids crusher and a secondary solids crusher.

Implementation #3: The well system of Implementation #2, further comprising a screener to be positioned to screen the solids from an output from the primary solids crusher and the secondary solids crusher, such that solids greater than a size threshold are returned to the secondary solids crusher to be reduced in size.

Implementation #4: The well system of according to any one of Implementations #1-2, further comprising: a first transport device configured to transport a first subset of the solids downhole in the current well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

Implementation #5: The well system of any one of Implementations #1-4, wherein the current well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the current well are returned to a second bore of the multi-lateral well.

Implementation #6: The well system of any one of Implementations #1-5, further comprising: a second transport device configured to transport a second subset of the solids that are outside the size range, to at least one of a location on the floor of the subsea, or a location above a surface of the subsea.

Implementation #7: The well system of any one of Implementations #1-6, wherein the minimum size threshold is approximately 0.001 millimeters and the maximum size threshold is approximately 6 millimeters.

Implementation #8: The well system of any one of Implementations #1-7, further comprising: a magnetic separation device to be positioned to remove at least a portion of magnetic material from the solids prior to the at least one solids reduction device receiving the solids.

Implementation #9: The well system of any one of Implementations #1-8, wherein the at least one solids reduction device is enclosed such that the at least one solids reduction device is isolated from exposure to water of the subsea.

Implementation #10: A well system comprising: a downhole system to be positioned downhole in a well that is formed in a subsurface formation below a floor of a subsea, the downhole system comprising, a solid separator configured to receive formation fluid that comprises solids, wherein the solid separator is configured to separate out at least a portion of the solids from the formation fluid, prior to transporting at least a portion of the formation fluid to a surface of the well; and a subsea system to be positioned on the floor of the subsea at or near the well, the subsea system comprising: at least one solids reduction device to receive the solids from downhole at a surface of the well, wherein the at least one solids reduction device is configured to reduce a size of at least a portion of the solids.

Implementation #11: The well system of Implementation #10, wherein the at least one solids reduction device comprises a primary solids crusher and a secondary solids crusher, wherein the well system further comprises a screener to be positioned to screen the solids from an output from the primary solids crusher and the secondary solids crusher, such that solids greater than a size threshold are returned to the secondary solids crusher to be reduced in size.

Implementation #12: The well system of any one of Implementations #10-11, further comprising: a first transport device configured to transport a first subset of the solids downhole in the well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

Implementation #13: The well system of any one of Implementations #10-12, wherein the well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the well are returned to a second bore of the multi-lateral well.

Implementation #14: The well system of any one of Implementations #10-13, further comprising: a second transport device configured to transport a second subset of solids, that comprise solids separated out and the solids that are reduced in size and that are outside the size range, to at least one of a location on the floor of the subsea, or a location above a surface of the subsea.

Implementation #15: The well system of any one of Implementations #10-14, wherein the minimum size threshold is approximately 0.001 millimeters and the maximum size threshold is approximately 6 millimeters.

Implementation #16: A method comprising: receiving, by a subsea system positioned on a floor of a subsea at or near a current well that is formed in a subsurface formation below the floor of the subsea, solids from downhole of the current well; and reducing, by at least one solids reduction device that is part of the subsea system, a size of at least a portion of the solids.

Implementation #17: The method of Implementation #16, wherein the reducing comprises: reducing, by a primary crusher of the at least one solids reduction device, the size of the at least the portion of the solids; and reducing, by a secondary crusher of the at least one solids reduction device, the size of the at least the portion of the solids reduced by the primary crusher.

Implementation #18: The method of any one of Implementations #16-17, wherein the reducing comprises: screening output from the primary crusher and the secondary crusher, such that solids greater than a size threshold are returned to the secondary crusher to be reduced in size.

Implementation #19: The method of any one of Implementations #16-18, further comprising: transporting a first subset of the solids downhole in the current well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of the solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

Implementation #20: The method of any one of Implementations #16-19, wherein the current well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the current well are returned to a second bore of the multi-lateral well.

Claims

1. A well system comprising:

a subsea system to be positioned on a floor of a subsea at or near a current well that is formed in a subsurface formation below the floor of the subsea, the subsea system comprising: at least one solids reduction device to receive solids that were part of the subsurface formation from downhole at a surface of the current well, wherein the at least one solids reduction device is configured to reduce a size of at least a portion of the solids.

2. The well system of claim 1, wherein the at least one solids reduction device comprises a primary solids crusher and a secondary solids crusher.

3. The well system of claim 2, further comprising a screener to be positioned to screen the solids from an output from the primary solids crusher and the secondary solids crusher, such that solids greater than a size threshold are returned to the secondary solids crusher to be reduced in size.

4. The well system of claim 1, further comprising:

a first transport device configured to transport a first subset of the solids downhole in the current well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

5. The well system of claim 4, wherein the current well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the current well are returned to a second bore of the multi-lateral well.

6. The well system of claim 4, further comprising:

a second transport device configured to transport a second subset of the solids that are outside the size range, to at least one of a location on the floor of the subsea, or a location above a surface of the subsea.

7. The well system of claim 4, wherein the minimum size threshold is approximately 0.001 millimeters and the maximum size threshold is approximately 6 millimeters.

8. The well system of claim 1, further comprising:

a magnetic separation device to be positioned to remove at least a portion of magnetic material from the solids prior to the at least one solids reduction device receiving the solids.

9. The well system of claim 1, wherein the at least one solids reduction device is enclosed such that the at least one solids reduction device is isolated from exposure to water of the subsea.

10. A well system comprising:

a downhole system to be positioned downhole in a well that is formed in a subsurface formation below a floor of a subsea, the downhole system comprising, a solid separator configured to receive formation fluid that comprises solids, wherein the solid separator is configured to separate out at least a portion of the solids from the formation fluid, prior to transporting at least a portion of the formation fluid to a surface of the well; and

a subsea system to be positioned on the floor of the subsea at or near the well, the subsea system comprising: at least one solids reduction device to receive the solids from downhole at a surface of the well, wherein the at least one solids reduction device is configured to reduce a size of at least a portion of the solids.

11. The well system of claim 10,

wherein the at least one solids reduction device comprises a primary solids crusher and a secondary solids crusher,

wherein the well system further comprises a screener to be positioned to screen the solids from an output from the primary solids crusher and the secondary solids crusher, such that solids greater than a size threshold are returned to the secondary solids crusher to be reduced in size.

12. The well system of claim 10, further comprising:

a first transport device configured to transport a first subset of the solids downhole in the well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

13. The well system of claim 12, wherein the well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the well are returned to a second bore of the multi-lateral well.

14. The well system of claim 12, further comprising:

a second transport device configured to transport a second subset of solids, that comprise solids separated out and the solids that are reduced in size and that are outside the size range, to at least one of a location on the floor of the subsea, or a location above a surface of the subsea.

15. The well system of claim 12, wherein the minimum size threshold is approximately 0.001 millimeters and the maximum size threshold is approximately 6 millimeters.

16. A method comprising:

receiving, by a subsea system positioned on a floor of a subsea at or near a current well that is formed in a subsurface formation below the floor of the subsea, solids from downhole of the current well; and

reducing, by at least one solids reduction device that is part of the subsea system, a size of at least a portion of the solids.

17. The method of claim 16, wherein the reducing comprises:

reducing, by a primary crusher of the at least one solids reduction device, the size of the at least the portion of the solids; and

reducing, by a secondary crusher of the at least one solids reduction device, the size of the at least the portion of the solids reduced by the primary crusher.

18. The method of claim 17, wherein the reducing comprises:

screening output from the primary crusher and the secondary crusher, such that solids greater than a size threshold are returned to the secondary crusher to be reduced in size.

19. The method of claim 16, further comprising:

transporting a first subset of the solids downhole in the current well or a different well that is formed in the subsurface formation below the floor of the subsea, wherein the first subset of the solids comprise the solids having a size that is within a size range defined by a minimum size threshold and a maximum size threshold.

20. The method of claim 19,

wherein the current well is a multi-lateral well, wherein the solids received by the at least one solids reduction device are from a formation surrounding a first bore of the multi-lateral well and the solids transported back downhole in the current well are returned to a second bore of the multi-lateral well.