DOWNHOLE OIL-WATER-SOLIDS SEPARATION
A technique facilitates separating fluids and solids and handling the separated solids downhole. A separator system is provided with a separator having a well fluid inlet, an oil stream passage, a water stream passage, and a solids passage. The separator operates to separate well fluid into substantially oil, water, and solids components and those components are directed to the corresponding passages. A flow restrictor may be used in cooperation with the separator to facilitate separation of the well fluid components.
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The present document is based on and claims priority to U.S. Provisional Application Ser. No. 61/359,875, filed Jun. 30, 2010 and incorporated by reference herein.
BACKGROUNDOil well production can involve pumping a well fluid as part oil and part water, i.e. an oil/water mixture. As an oil well becomes depleted of oil, a greater percentage of water is present and subsequently produced to the surface. The “produced” water can sometimes account for more than 80% of total produced well fluid volume, thus creating significant operational issues. For example, the produced water may require treatment and/or reinjection into a subterranean reservoir to dispose of the water and to help maintain reservoir pressure. Treating and disposing of produced water can be expensive.
One way to address these issues is through employment of a downhole device to separate oil and water and to re-inject the separated water, thereby minimizing production of unwanted water to the surface. Reducing water produced to the surface can allow for a reduction of required power, a reduction of hydraulic losses, and a simplification of surface equipment. Furthermore, many of the costs associated with water treatment are reduced or eliminated.
However, successfully separating oil and water downhole and then re-injecting water is a relatively involved and sensitive process with many variables and factors that affect the efficiency and feasibility of such an operation. For example, the oil/water ratio can vary from well to well and can change significantly over the life of the well. The required injection pressure also can change over the life of the well. For example, the required injection pressure for the separated water tends to increase over time.
Additional issues arise when the well fluid includes solids, such as sand and other particulates which are sometimes mixed in with the well fluid. The solids tend to be heavier than the oil and separate out with the water. However, the presence of solids in the water stream can create complications downhole, such as clogging. In some applications, the solids separate from the reinjected water stream and tend to clog the reinjection locations. The ratio of solids in the well fluid/water also can change over time which creates greater difficulties in handling the solids downhole.
SUMMARYIn general, aspects of downhole oil-water-solids separation provide a system and method for separating fluids and solids and for handling the separated solids downhole. The technique utilizes a separator system having a separator with a well fluid inlet, an oil stream outlet passage, a water stream outlet passage, and a solids outlet passage. The separator operates to separate well fluid into substantially oil, water, and solids components and those components are directed to the corresponding passages. A flow restrictor may be used in cooperation with the separator to facilitate separation of the well fluid components.
Certain embodiments of downhole oil-water-solids separation will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
In the specification and appended claims: the terms “up” and “down”, “upper” and “lower”, “upwardly” and “downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationships as appropriate.
Embodiments described herein generally relate to artificial lift systems, e.g. artificial lift systems in connection with hydrocarbon wells. The embodiments comprise systems and methods for separating well fluid components, such as oil, water and solids. For example, an embodiment relates to downhole oil/water/solids separation and to managing back pressure to manipulate the well fluid component separation. One way of controlling separation of oil and water, for example, is by regulating back pressure applied to the oil stream and/or the water stream. The back pressure can be controlled by regulating a flow restriction to cause desired throttling of the oil stream and/or water stream exiting a well fluid component separator. In addition to well fluid component separation, embodiments described herein relate to equipment designed to provide a desired throttling, i.e. back pressure, applied to the outlet streams. The magnitude of throttling can range from completely closed (no flow) to wide open (full flow) depending on the oil/water/solids content of the well fluid.
Controlling back pressure and related flow can be highly dependent on the injection zone orientation relative to the producing zone (injection zone uphole or downhole of the producing zone). Some of the differences between these two orientations relate to injecting uphole where the device can throttle and vent to a tubing annulus in a single operation, and injecting downhole where the device may need to throttle the flow “in-line”, i.e. receive the injection flow from tubing, throttle the flow, and then return the flow to another tubing routed toward the injection zone. In some applications, the diameter of a throttle passage/opening of a flow restrictor can range from about 0.125 inches to 1.0 inches.
Referring generally to
In the example illustrated, the well system 20 is placed downhole in a hydrocarbon well, such as inside a well casing 36. When placed at a desired location downhole, the submersible motor 26 may be powered to drive both the submersible pump 28 and the separator 34. During operation of this embodiment, well fluid is drawn into pump 28 through vent 30 and pumped into the separator 34. The separator 34 accelerates and drives the well fluid mixture in a circular path, thereby utilizing centrifugal forces to locate the more dense materials, e.g. water and solids, to a more distant radial position and the less dense fluids, e.g. oil, to a position closer to the center of rotation. In this example, an oil stream and a water stream exit the separator 34 and travel separately along different paths to a redirector 38 which redirects the water stream and injects it into the surrounding formation while directing the oil stream uphole through, for example, a tubing 40 to a surface collection location. The separator 34 may be designed to separate oil, water and solids (see
References to water streams, oil streams, and/or solids streams output from the separator 34 refers to streams that have a substantial concentration of water, oil, and solids, respectively. In other words, the respective streams may contain portions of the other well fluid components and may not be pure in the sense that they contain solely water, oil, or solids. Depending on the specific application, the well system 20 may comprise various other components, such as packers 42 and 44.
Referring generally to
The flow restrictor 60 may be selected from a number of different types of flow restrictors, an example of which has an orifice member 62 with a flow through orifice or passage 64. The size of the orifice 64 may vary and the configuration of flow restrictor 60 and orifice member 62 enables adjustment of the back pressure in water stream 58. For example, the flow restrictor 60 may be a removable flow restrictor to enable interchanging with other flow restrictors 60 having a different throttling capability, e.g. a different throttle member 62 with a flow through orifice 64 having a different size, thus enabling adjustment of the back pressure. In other embodiments, the orifice member 62 is removable and may be interchanged with other orifice members 62 having orifices 64 of different sizes. The flow restrictor 60 and/or orifice member 62 may be interchanged with the aid of a tool 66 that can be lowered downhole to place and/or remove the flow restrictor 60 or orifice member 62. By way of example, the tool used to interchange the device may comprise a tool run on a wireline, slickline, coiled tubing, or another suitable conveyance 68. In some applications, slickline can be the most economical conveyance for changing the throttling. In the example illustrated in
In some applications, the flow restrictor 60 comprises an orifice member 62 having a variable size throttle orifice 64 so that replacement of the flow restrictor 60 is not required to vary the size of orifice 64. By way of example, the size of the orifice can be adjusted mechanically at the surface or by tool 66 lowered via conveyance 68, e.g. wireline, slick line, coiled tubing. In other applications, the orifice member 62 may have an adjustable orifice 64 which is adjustable via hydraulic pressure directed downhole through a hydraulic line or by an electric motor controlled by electric signals sent from the surface or from a downhole controller.
As further illustrated in
Referring again to
Well system 20 also may be configured to enable injection of stimulation treatments downhole. In the embodiment illustrated in
Referring generally to
With additional reference to
In the embodiment illustrated, the flow restriction orifice 64 of orifice member 62 has a narrower diameter than the diameter of upper inner chamber 94 or lower inner chamber 96, however the diameter of the orifice 64 could be essentially the same as the diameter of either the upper chamber 94 or the lower chamber 96. Additionally, one or more passages 98 are located in the flow restrictor body 92 and hydraulically connect the upper chamber 94 with a region external to the flow restrictor 60. Another passage 100 is located on a downhole end of the flow restrictor 60 and provides a flow path which enables communication with the bottom of orifice member 62 through lower inner chamber 96.
When the flow restrictor 60 is positioned within flow restrictor pocket 86, the passages 98 allow fluid to pass from the water passage 88, through the passages 98, and into the upper inner chamber 94. The fluid then flows through the restrictor orifice 64 of orifice member 62, and into the lower inner chamber 96. From the lower inner chamber 96, the fluid, e.g. water, flows through passage 100 and out of flow restrictor 60 for re-injection into a desired zone, e.g. injection zone 76. A plurality of seals 102, e.g. O-ring seals, may be mounted about body 92 to form a seal with the interior surface of flow restrictor pocket 96. In a variety of applications, the flow restrictor 60 may be removable. Additionally or alternatively, the orifice member 62 can be constructed as interchangeable or adjustable to enable adjustment with respect to the size of flow passage 64. It should be noted that the flow restrictor 60 can have many internal configurations that enable the desired restriction/throttling of fluid flow to facilitate separation of well fluid components.
When removable, the flow restrictor 60 may comprise an attachment member 104 designed to facilitate engagement with tool 66 for placement and retrieval with respect to the flow restrictor pocket 86. As noted earlier, the tool 66 can be connected to a variety of conveyances 68, e.g. wireline, slick line, or coiled tubing.
In many applications, the separation techniques applied and the flow restrictor selected depend on parameters/characteristics related to the well fluid, e.g. well fluid content. For example, the content of the well fluid can be useful in determining the appropriate techniques for separating, producing, and re-injecting the various well fluid components. In some applications, a sensor 106 can be located downhole to determine selected parameters of the well fluid, such as the oil/water/solids ratio in the well fluid, as illustrated in
Referring again to
Referring generally to
The embodiment of separator 34 illustrated in
As discussed above with respect to separator 34, separation of the oil component, water component, and solids component can be achieved by rotating, dynamic separators, e.g. cyclone or centrifugal separators, operating according to the principle of density separation using the forces created from rotation. When the well fluid is rotated, the heavier phase/component is separated to the outer radius of rotation. For example, the heavier solids may be separated to a radially outer region, while the lighter water is separated to an intermediate region, and the lighter oil is separated to a region closer to the core of rotation. This radially centric oil component (possibly with some remaining water and/or solids) is discharged as the production stream.
Referring again to the embodiment illustrated in
In operation, a well fluid mixture is driven into the separator chamber 46, e.g. a cyclone/centrifugal chamber, of the separator 34 by submersible pump 28 or another suitable pump of pumping system 24. The well fluid flows into separator portion 46 of separator 34 through a well fluid inlet 116. Within separator portion 46, the components of the well fluid are separated into the oil, water, and solids components which primarily comprise oil, water, and solids, respectively. Streams of primarily oil, water, and solids are then split into component streams by divider 48, and the respective component streams are routed through the corresponding oil passage 50, water passage 52 and solids passage 112. The well fluid components may be directed through a corresponding oil stream outlet 118, water stream outlet 120 and solids outlet 122 of divider 48 to appropriate flow paths downstream. The water passage 52 is radially outward relative to oil passage 50, and the solids passage 112 is radially outward relative to water passage 52. By way of example, the oil passage 50, water passage 52, and solids passage 112 may be in the form of concentric conduits which route the respective well fluid components to desired locations downstream. For example, the component streams may be routed to an appropriate redirector 38 and/or through appropriate flow restrictors 60.
As described with respect to the various well system embodiments above, the separation of well fluid components, e.g. the separation of oil, water, and solids components, can be improved by manipulating the back pressure on the various well fluid component streams. In many applications, the desired back pressure can be accomplished by providing removable flow restrictors, removable orifice members, and/or adjustable orifices placed in the oil/solid stream and/or the water stream. However, the back pressure can be created with a variety of devices and with respect to various combinations of the well fluid component streams to achieve desired production results. The flow restrictor, for example, can be placed in the oil/solid stream, the oil component stream, the water component stream, and/or the solids component stream.
Although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this invention. Accordingly, such modifications are intended to be included within the scope of this invention as defined in the claims.
Claims
1. A downhole device, comprising:
- a separator system, having: a separator comprising a well fluid inlet, an oil stream passage, a water stream passage, and a solids passage; and a removable flow restrictor located in at least one of the water stream passage, the oil stream passage, or the solids passage to facilitate separation of well fluid components.
2. The downhole device of claim 1, wherein the removable flow restrictor has a fixed throttle orifice member having a flow passage, the size of the flow passage being changed by interchanging flow restrictors.
3. The downhole device of claim 1, wherein the removable flow restrictor has a removable throttle orifice member having a flow passage, the size of the flow passage being changed by interchanging removable throttle orifice members.
4. The downhole device of claim 1, further comprising a pumping system having a submersible pump, wherein the water stream passage opens up into a wellbore at a point farther downhole than the submersible pump.
5. The downhole device of claim 1, wherein the removable flow restrictor is removable by a downhole tool relayed downhole by a conveyance.
6. The downhole device of claim 1, wherein the separator is a cyclone separator.
7. The downhole device of claim 1, wherein the separator is a centrifugal separator.
8. The downhole device of claim 1, wherein the separator system further comprises a sensor that senses a parameter of flowing fluid.
9. The downhole device of claim 8, wherein the sensor is located downstream from the well fluid inlet.
10. The downhole device of claim 8, wherein the sensor is located inside the separator.
11. The downhole device of claim 8, wherein the sensor is located upstream from the separator.
12. The downhole device of claim 1, wherein the removable flow restrictor has a throttle member with a selectively variable orifice.
13. A method of separating fluids and solids downhole, comprising:
- placing a separation system downhole, the separation system comprising a separator having a well fluid inlet, an oil stream outlet passage, a water stream outlet passage, and a solids outlet passage, the separator system further comprising a flow restrictor pocket located in the oil stream outlet passage or the water stream outlet passage;
- determining a parameter of a downhole well fluid;
- selecting a degree of flow restriction based on the determination and selecting a corresponding flow restrictor; and
- placing the selected flow restrictor in the flow restrictor pocket.
14. The method of claim 13, further comprising varying the flow restriction by removing the flow restrictor from the separator while the separator is downhole and then placing a different flow restrictor having a different throttle into the separator while the separator remains downhole.
15. The method of claim 13, wherein determining comprises determining with a sensor located downhole within the separator system.
16. The method of claim 15, further comprising locating the sensor inside the flow restrictor.
17. A method of preparing a downhole fluids and solids separation system, comprising:
- constructing a separator with a separation portion in communication with a fluid inlet, the separation portion also being in communication with a divider having an oil stream passage, a water stream passage positioned radially outward from the oil stream passage, and a solids passage positioned radially outward from the water stream passage; and
- positioning a flow restrictor in cooperation with the separator to enable selective manipulation of the separation of water and oil.
18. The method of claim 17, further comprising deploying the separator downhole into a wellbore; and separating oil, water, and solids for discharge through the oil stream passage, the water stream passage, and the solids passage, respectively.
19. The method of claim 18, further comprising using a downhole pumping system to pump the separated oil to a surface location.
20. The method of claim 19, further comprising reinjecting the separated solids back into the separated oil above the downhole pumping system; and delivering the separated solids to a surface location.
Type: Application
Filed: Jun 14, 2011
Publication Date: Jan 12, 2012
Applicant: SCHLUMBERGER TECHNOLOGY CORPORATION (SUGAR LAND, TX)
Inventors: Ryan Cox (Moscow), Steven Dornak (Damon, TX)
Application Number: 13/159,996
International Classification: E21B 43/00 (20060101); E21B 34/00 (20060101);