Patent Application
20250067158
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 re-drilling 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.
These drawings illustrate certain aspects of some examples of the present disclosure and should not be used to limit or define the disclosure.
The present disclosure relates to the field of downhole fluid separator. More specifically, systems are described of multilateral well completion design to install fluid separator on the upper completion and inside a lateral well and methods of use thereof. A fluid separator includes an oil/water separator and a gas/oil/water separator, for example. Fluid separators that are installed downhole in multilateral oil wells can require that they are placed in long tangent sections within a wellbore, above the multilateral junction. However, the cost associated with the planification and implementation of a novel multilateral well is significant. In fact, the cost to design and install a downhole fluid separator with a tangent section may be as high as the cost of the entire multilateral well without the separator. In addition, the placement of the fluid separator above the multilateral junction requires installing it right from the onset when completing the new well to minimize the risk of losing the well. In embodiments, the fluid separator may be installed inside or below the junction between the main bore and the lateral well. Further, the fluid separator may be installed in a horizontal or in a vertical configuration thanks to the gravity generated artificially according to embodiments of the present disclosure. Indeed, one or multiple artificial gravity generators can be installed in a single tubing allowing the fluid separator to be installed in vertical wells, horizontal wells, and any inclined wells in between. The artificial gravity generator includes at least one turbine, an inlet nozzle, and a couple of outlets. The spinning of the turbine can generate gravity and help in the separation of oil from water. The artificial gravity generator includes a flow system, wherein a device is configured to rotate, wherein the fluid pathway is configured to differentiate fluids including oil and water based on their properties including density, a flow system, wherein the gravitational acceleration is amplified due to the centripetal acceleration of the fluid, an inlet nozzle to take in fluid, an outlet nozzle to dispose of unwanted fluid including water, and an input nozzle to input oil and other preferred fluids into the production string. A pump, such as an electrical submersible pump, can be used to create a pressure difference across the annulus and the tubing helping the separation of the oil into the tubing and water into the micro annulus or annulus into the lateral. One way check valve may be used at the beginning of the lateral well to prevent water from flowing back from the lateral well into the production tubing. Float switching based on first generation fluidic diode used in autonomous interval control device, autonomous inflow control device, and/or shrouded inflow control device can also be incorporated to allow better fluid separation.
In embodiments, the fluid separator can be placed in the main bore at the junction between the main bore and the lateral well with a pump such as an electrical submersible pump disposed above the fluid separator. The multilateral junction may be placed above or inside the target formation. This configuration can be accomplished in a two-trip multilateral completion consisting of a lower completion with orientation liner hanger connected to additional lower completion, and an upper completion consisting of the fluid separator, an electrical submersible pump, and an upper packer. This simplifies the installation. This reduced complexity allows the fluid separator according to embodiments of the present disclosure to be installed into existing wells, i.e., retrofitting existing wells. Further, the lateral well can be a target formation. The existing wells do not require a tangent section at the junction for the placement of the fluid separator, significantly increasing the number of oil well candidates for installation of the fluid separator according to embodiments of the present disclosure.
The design of the installed completion equipment is critical for the downhole fluid separator to function as intended. Current well designs place the downhole fluid separator above the multilateral junction. By installing the fluid separator in the main bore at the junction between the main bore and the lateral well with a pump such as an electrical submersible pump disposed above the fluid separator according to embodiments of the present disclosure, an existing watered out well can be re-entered, and a new lateral added to it. Alternatively, the fluid separator may be placed below or above the junction the junction between the main bore and the lateral well. Further, the candidate wells can be a vertical wells, a horizontal wells, or any deviated wells in between. This decreases the overall cost involved in installing the fluid separator according to embodiments of the present disclosure as compared with installing it at the completion of the well at the beginning of the life of the well. It also decreases the risks associated with installing downhole fluid separator according to embodiments of the present disclosure as existing wells that are already poor producers can be selected as candidates and represent a smaller cost if the well is lost during the trial as compared with selecting a potential well before well completion is finished. Using a fluid separator in a downhole setting combined with a multilateral junction provides efficiency gains. This includes converting poor performing wells, wherein the percentage of oil has decreased to about 2% for example, into a downhole water injector combined with a better producing well. Additional benefits include lower flow rate and pressure rating requirements, a lighter fluid column, and increased recovery. The fluid separator according to embodiments of the present disclosure may be particularly useful in low flow rate wells (in the 200 barrel per day range or less), which tend to be shallow, and relatively inexpensive to drill. Moderate flow rate wells, for example 500-5000 barrels of fluid per day, can also be potential candidates for the downhole fluid separator according to embodiments of the present disclosure. Finally, it will also be useful for most multilaterals with very high flow rate wells, up to 50,000 barrels of fluid per day, for example.
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. 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.
An orienting liner hanger 110 may be disposed in the main bore 102 of a multilateral well 100 in a position downhole from the junction 108. As illustrated, the orienting liner hanger 110 is secured to a portion of main bore casing 112 extending downhole from the junction 108. Further, the orienting liner hanger 110 may be sealed against the main bore casing 112 such that the orienting liner hanger 110 may fluidly isolate the junction 108 from a production portion 114 of the main bore 102. In particular, as set forth in greater detail below, the orienting liner hanger 110 may fluidly isolate a lower annulus end 116 of a separator annulus 118 from the production portion 114 of the main bore 102.
The orienting liner hanger 110 may also be configured to support a lower completion 120. The lower completion 120 may be secured to a downhole end of the orienting liner hanger 110. As illustrated, the lower completion 120 may extend into and through the production portion 114 of the main bore 102, which may produce formation fluid 122. The formation fluid 122 may include a combination of oil and water. Alternatively, the formation fluid 122 may include a combination of oil, gas, and water. The lower completion 120 may assist with directing and controlling flow of the formation fluid 122 from the production portion 114 of the main bore 102 toward the junction 108 of the multilateral well 100. Specifically, the lower completion 120 may direct to the formation fluid 122 to flow to a fluid separator assembly 124 disposed within a least a portion of the junction 108.
Moreover, the lower completion 120 may include a lower production tubing 126 and a plurality of production packers 128 disposed about the lower production tubing 126. The production packers 128 may be configured to isolate various production zones 130 (e.g., a first production zone 132, a second production zone 134, a third production zone 136, etc.) in the production portion 114 of the main bore 102. Further, the lower completion 120 may include at least one screen 138 disposed in each production zone (e.g., between adjacent packers of the plurality of production packers 128). The at least one screen 138 is configured to filter and/or clean formation fluid 122 flowing into the lower production tubing 126. Indeed, formation fluid 122 is configured to enter the lower production tubing 126 via the at least one screen 138 and flow uphole toward the fluid separator assembly 124. The fluid separator assembly 124 is configured to receive formation fluid 122 flowing uphole from the lower completion 120.
As set forth in greater detail below, the fluid separator assembly 124 may include an assembly housing 140, as well as a fluid separator 142 (e.g., a fluid separator system) and a pump 144 housed within the assembly housing 140. The fluid separator assembly 124 may also include an inlet feature configured to seal against an inner surface of the orienting liner hanger 110. In particular, the inlet feature may include an inlet tubular 146 configured to extend outward from an axially downhole end 148 of the fluid separator assembly 124. The inlet feature may also include at least one seal 150 disposed about the inlet tubular 146. The inlet tubular 146 may be configured to extend into a portion of the orienting liner hanger 110 to form a seal between the inlet feature and the inner surface of the orienting liner hanger 110. For example, with the inlet tubular 146 extended into the orienting liner hanger 110, the at least one seal 150 may compress between a radially outer surface of the inlet tubular 146 the inner surface of the orienting liner hanger 110 to form the seal.
The inlet feature may be configured to fluidly connect the lower production tubing 126 with a fluid inlet 152 of the fluid separator 142 such that the formation fluid 122 may flow from the lower completion 120 into the fluid separator 142. The inlet feature may also be configured to isolate the flow of formation fluid 122 from the lower completion 120 to the fluid separator assembly 124 from a separator annulus 118, which may improve performance of the fluid separator assembly 124.
As set forth above, the formation fluid 122 may include a combination of oil and water. After receiving the formation fluid 122 from the lower completion 120, the fluid separator assembly 124 is configured to at least partially separate the formation fluid 122 into formation oil 154 and formation water 156. Indeed, as set forth in greater detail below, the fluid separator 142 of the fluid separator assembly 124 is configured to at least partially separate the formation fluid 122 into the formation oil 154 and the formation water 156. However, in some cases, the oil and the water may not completely separate. As such, the term formation oil 154 may refer to a combination of oil and water having at least 70% oil. Further, the term formation water 156 may refer to a combination of water and oil having at least 70% water. Moreover, as set forth in greater detail below, the fluid separator assembly 124 is configured to output the formation oil 154 to an upper production tubing 158 and output the formation water 156 into the lateral bore 104 of the multilateral well 100.
As illustrated, the fluid separator assembly 124 may be disposed at least partially within the junction 108 of the multilateral well 100 and uphole from the orienting liner hanger 110. As illustrated, an upper separator end 160 of the fluid separator assembly 124 may extend uphole from an upper junction end 162 of the junction 108, and the axially downhole end 148 of the fluid separator assembly 124 may extend downhole from a lower junction end 164 of the junction 108. However, the fluid separator assembly 124 may alternatively be disposed entirely within the junction 108. Further, the fluid separator assembly 124 may be oriented vertically within the multilateral well 100. For example, as illustrated, the fluid separator assembly 124 may be extend through the vertical portion 106 of the main bore 102 and/or the junction 108, such that the fluid separator assembly 124 is oriented vertically within the multilateral well 100. Having the fluid separator assembly 124 oriented vertically within the main bore 102 and/or the junction 108 may include orienting an assembly housing 140 of the fluid separator assembly 124 such that the assembly housing 140 is substantially parallel to the main bore 102 of the multilateral well 100.
Moreover, an upper completion packer 166 may be secured within the main bore 102 in a position uphole from the fluid separator assembly 124. As illustrated, the upper production tubing 158 extends from the fluid separator assembly 124 at least to the upper completion packer 166. The upper completion packer 166 may include an upper pump (not shown) to drive the formation oil 154 output from the fluid separator 142 in the uphole direction through the upper production tubing 158 and the upper completion packer 166 toward the surface.
Additionally, the upper completion packer 166 is configured to seal the separator annulus 118 from the surface. As illustrated, the separator annulus 118 may be formed in the main bore 102 between the main bore casing 112 and radially outer surfaces of the fluid separator assembly 124 and the upper production tubing 158. Alternatively, the separator annulus 118 may be formed between a wellbore wall 168 of the main bore 102 and the radially outer surfaces of the fluid separator assembly 124 and the upper production tubing 158 for multilateral wells 100 without main bore casing 112. Moreover, the upper completion packer 166 is configured to seal an upper annulus end 170 of the separator annulus 118 and, as set forth above, the orienting liner hanger 110 is configured to seal the lower annulus end 116 of the separator annulus 118. Indeed, formation water 156 output into the separator annulus 118, via the fluid separator assembly 124, may be scaled from flowing downhole into the production portion 114 of the main bore 102, uphole toward the surface, or back into the fluid separator assembly 124. As such, the formation water 156 flowing into the separator annulus 118, via the fluid separator assembly 124 may be directed to flow into the lateral bore 104, which is in fluid communication with the separator annulus 118, such that the formation water 156 may flow back into a subterranean formation 172. Directing the formation water 156 back into the subterranean formation 172 via the lateral bore 104 may eliminate the need to pump the formation water 156 to the surface for transportation and storage, which may improve efficiency and reduce the cost of completion operations.
Referring to
As set forth in greater detail below, the fluid separator 142 of the fluid separator assembly 124 is configured to generate artificial gravity such that the fluid separator assembly 124 may operate in both vertical portions 106 (shown in
Further, the fluid separator 142 may be positioned within the assembly housing 140. In particular, the fluid separator 142 may include a separator housing 212 positioned within the assembly housing 140. As illustrated, the radially inner surface of the assembly housing 140 may form a top portion 214, a bottom portion 216, and side portions of the separator housing 212. Alternatively, the top portion 214, bottom portion 216, and side portions of the separator housing 212 may be separate from the assembly housing 140. Moreover, the separator housing 212 may further include an axially uphole separator wall 218 and an axially downhole separator wall 220 each configured to seal respective ends of the separator housing 212. As illustrated, the lower end wall 204 of the assembly housing may form the axially downhole separator wall 220. Alternatively, the axially downhole separator wall 220 may be separate from the lower end wall 204 such that the separator housing 212 may be axially offset from the lower end wall 204 of the assembly housing 140.
Moreover, as illustrated, the fluid separator 142 may include a turbine chamber 222 formed within the separator housing 212. The separator housing 212 may be configured to enclose a turbine chamber 222 such that the formation fluid 122 may only enter the separator housing 212 via the fluid inlet 152. Indeed, as set forth above, the fluid inlet 152 is configured to receive formation fluid 122 and direct the formation fluid 122 into the turbine chamber 222. In particular, the fluid inlet 152 is configured to fluidly connect the turbine chamber 222 with the lower production tubing 126 such that fluid flowing uphole from the lower completion 120 (shown in
The fluid separator 142 also includes a turbine 224 disposed within the turbine chamber 222. During operation, the turbine 224 is configured to rotate above a threshold speed needed to generate artificial gravity for the formation fluid disposed in the turbine chamber 222. That is, the turbine 224 may be configured to rotate above the threshold speed to exert a centrifugal force on the fluid (e.g., formation fluid 122, formation oil 154, formation water 156) in the turbine chamber 222. The centrifugal force may be configured to separate fluids of different densities. As such, the centrifugal force in the turbine chamber may function as artificial gravity to separate the formation fluid 122 into the formation oil 154 and the formation water 156 based on density. As illustrated, the centrifugal force may drive the formation water 156 in a radially outward direction, with respect to a central axis 226 of the turbine 224. In particular, the centrifugal force may drive the formation water 156 outward toward a water outlet 228 formed in the separator housing 212.
As illustrated, the water outlet 228 may be formed in the axially uphole separator wall 218. However, the water outlet 228 may be formed in any suitable portion of the separator housing 212. Moreover, the water outlet 228 is configured to receive the formation water 156 separated from the formation fluid 122 in the turbine chamber 222 and direct the formation water 156 out of the separator housing 212. In particular, the water outlet 228 is configured to output the formation water 156 toward the pump 144.
The pump 144 may include an electrical submersible pump positioned within the assembly housing 140. However, the pump 144 may include any suitable type of pump. As illustrated, the pump 144 may be disposed within the assembly housing 140 in a position uphole from the fluid separator 142. Alternatively, the pump 144 may be disposed downhole from the fluid separator 142. Moreover, the pump 144 may be fluidly coupled to the water outlet 228 of the fluid separator 142 via at least one intermediate water line 230 extending through the assembly housing 140. The pump 144 is configured to receive the formation water 156 via the at least one intermediate water line 230 and drive the formation water 156 toward an exterior of the assembly housing 140. That is, the pump 144 may be configured to output the formation water 156, via a pump outlet 232, into a water outlet line 234. The water outlet line 234 is configured to fluidly couple the pump outlet 232 with the housing water outlet 210 formed in the assembly housing 140. Further, the housing water outlet 210 may be positioned within the separator annulus 118 or lateral bore 104 of the multilateral well 100. As such, the formation water 156 output from the pump 144 may flow through the water outlet line 234 and into the separator annulus 118 or the lateral bore 104 via the housing water outlet 210.
The fluid separator assembly 124 may further include a one-way check valve 236 disposed within the water outlet line 234. The one-way check valve 236 is configured to prevent the formation water 156 from flowing back into the fluid separator assembly 124 from the separator annulus 118 and/or the lateral bore 104. Specifically, the one-way check valve 236 is configured to block fluid from flowing through the water outlet line 234 in the direction from the housing water outlet 210 toward the pump 144. As illustrated, the one-way check valve 236 may include a ball check valve. However, the one-way check valve 236 may include any suitable type of one-way check valve 236 for blocking fluid from flowing through the water outlet line 234 in the direction from the housing water outlet 210 toward the pump 144. For example, the one-way check valve 236 may alternatively include a diaphragm check valve, a swing check valve, a lift check valve, etc.
Moreover, the fluid separator 142 may include an oil outlet 238 extending through the separator housing 212. As set forth in greater detail below, the oil outlet 238 is configured to direct the formation oil 154, separated from the formation fluid 122 via the centrifugal force, out of the turbine chamber 222 and toward the upper production tubing 158 secured to an uphole end 240 of the assembly housing 140. As illustrated, the turbine 224 of the fluid separator 142 may include a base portion 242 and a bladed portion 244. A radially outer surface 246 of the base portion 242 may have a cylindrical shape, and the bladed portion 244 may include a plurality of blades secured to the radially outer surface 246 of the base portion 242. Further, the base portion 242 may include a hollow central portion 248. The oil outlet 238 may be disposed within the hollow central portion 248 of the base portion 242 of the turbine 224. As illustrated, the base portion 242 may include a rotor shaft 270 secured within the turbine chamber 222 and configured to rotate. Further, the hollow central portion 248 may extend through the rotor shaft 270.
A lower axial end 250 of the turbine 224 may be axially offset from a bottom surface 252 of the turbine chamber 222 to form a lower flow path 254 in the turbine chamber 222. At least a portion of the formation oil 154 separated from the formation fluid 122 may flow from a radially outer edge 256 of the turbine 224 toward the oil outlet 238 via the lower flow path 254. Further, an upper axial end 258 of the turbine 224 may be axially offset from a top surface 260 of the turbine chamber 222 and/or a top flow wall 266 to form an upper flow path 262 for the formation oil 154 to flow across the turbine 224 to the oil outlet 238. Similarly, at least a portion of the formation oil 154 separated from the formation fluid 122 may flow from the radially outer edge 256 of the turbine 224 toward the oil outlet 238 via the upper flow path 262.
Moreover, the fluid separator assembly 124 may include at least one oil outlet line 264 extending from the oil outlet 238 toward the housing oil outlet 208. As illustrated, the housing oil outlet 208 is in direct fluid communication with the upper production tubing 158. The formation oil 154 output from the turbine chamber 222, via the oil outlet 238, may flow through the at least one oil outlet line 264 and exit the assembly housing 140, via the housing oil outlet 208, to flow uphole through the upper production tubing 158 toward the surface.
Moreover, the fluid inlet 152 may be offset from the base portion 242 of the turbine 224. As illustrated, the fluid inlet 152 may be aligned with the bladed portion 244 of the turbine 224 such that the formation fluid 122 flowing into the turbine chamber 222 may flow directly into the bladed portion 244 of the turbine 224. Further, the fluid inlet 152 may include an inlet nozzle 306 configured to accelerate the flow rate of the formation fluid 122 passing through the fluid inlet 152 and flowing into the bladed portion 244. The accelerated formation fluid 122 may exert a force on the bladed portion 244 to drive rotation of the turbine 224 within the turbine chamber 222. The fluid separator assembly 124 may utilize the pump 144 (shown in
As set forth above, the turbine 224 is configured to rotate above a threshold speed needed to generate artificial gravity for the formation fluid 122 disposed in the turbine chamber 222. That is, the turbine 224 may be configured to rotate above the threshold speed to exert a centrifugal force on the formation fluid 122 in the turbine chamber 222. The centrifugal force may be configured to separate fluids of different densities. As such, the centrifugal force in the turbine chamber 222 may function as artificial gravity to separate the formation fluid 122 into the formation oil 154 and the formation water 156 based on density. As illustrated, the centrifugal force may drive the formation water 156 in a radially outward direction 308, with respect to the turbine axis 302 (e.g., the central axis 226 of the turbine 224). In particular, the centrifugal force may drive the formation water 156 outward toward a water outlet 228 formed in the separator housing 212. As illustrated, the water outlet 228 may be positioned in the turbine chamber 222 such that the turbine 224 is positioned between the inlet nozzle 306 and the water outlet 228 with respect to the central axis 304 of the assembly housing 140. Having the water outlet 228 positioned opposite the inlet nozzle 306 may allow for increased separation as a travel distance in turbine chamber 222 may be greater than having the water outlet 228 positioned adjacent the inlet nozzle 306.
As illustrated, the fluid separator assembly 124 may include a second pump 400 (e.g., a second electrical submersible pump) positioned within the assembly housing 140. The second pump 400 may be fluidly coupled to the oil outlet 238 via an intermediate oil line 402. As such, the second pump 400 may be configured to receive the formation oil 154 from the fluid separator 142 via the intermediate oil line 402. Further, the second pump 400 may be configured to drive the formation oil 154 toward the upper production tubing 158. In particular, the second pump 400 may be fluidly coupled to the housing oil outlet 208 via the oil outlet line 264. The second pump 400 may drive the formation oil 154 to flow through the oil outlet line 264 and exit the assembly housing 140, via the housing oil outlet 208, to flow uphole through the upper production tubing 158 toward the surface. Having the second pump 400 may increase the flow rate of the formation oil 154 flowing toward the surface, which may increase production efficiency.
As illustrated, the first fluid separator 500 may include a first fluid inlet 504 configured to receive the formation fluid 122 directly from the lower production tubing 126. The first fluid separator 500 is configured to at least partially separate the formation fluid 122 into the formation oil 154 and the formation water 156. However, as set forth above, the oil and the water may not completely. For example, the first fluid separator 500 may separate the formation fluid 122 into formation water 156 having a combination of 75% water and 25% oil and formation oil 154 having a combination of 25% water and 75% oil.
As illustrated, a first water outlet 506 may be fluidly coupled to the pump 144 such that the formation water 156 output from the first fluid separator 500 may be driven by the pump 144 and output into the separator annulus 118 and/or lateral bore 104 via the housing water outlet 210. Further, a first oil outlet 508 of the first fluid separator 500 may be fluidly connected to a second fluid inlet 510 of the second fluid separator 502 such that the formation oil 154 output via the first fluid separator 500 may be input into the second fluid separator 502. As such, water remaining in the formation oil 154 may be further separated from the formation oil 154. For example, the formation oil 154 output from the second fluid separator 502 may have a combination of 15% water and 85% oil. Accordingly, having multiple fluid separators 142 in series may improve separation in the fluid separator assembly 124. Moreover, the formation oil 154 may be output from the second fluid separator 502 to the upper production tubing 158. The formation water 156 output from the second fluid separator 502 may be directed to the pump 144 and output from the assembly housing 140 into the separator annulus 118 and/or the lateral bore 104. Alternatively, the fluid separator assembly 124 may include an additional pump configured to receive the formation water 156 from the second fluid separator 502 and output the formation water 156 from the assembly housing 140.
Alternatively, the first water outlet 506 of the first fluid separator 500 may be fluidly coupled to the second fluid inlet 510 of the second fluid separator 502 such that the second fluid separator 502 may further separate the oil from the formation water 156, which may increase an amount of oil output to the surface via the fluid separator assembly 124.
In particular, the first fluid separator 500 may include the first fluid inlet 504 and the second fluid separator 502 may include a second fluid inlet 510. Both the first fluid inlet 504 and the second fluid inlet 510 may be coupled directly to the lower production tubing 126 such that a portion of the formation fluid 122 flowing through the lower production tubing 126 is directed into the first fluid separator 500 and a remaining portion of the formation fluid 122 flowing through the lower production tubing 126 is directed into the second fluid separator 502. Further, the first fluid separator 500 may include the first oil outlet 508 coupled to the upper production tubing 158 via the oil outlet line 264, and the second fluid separator 502 may include a second oil outlet 600 coupled to the upper production tubing 158 via the oil outlet line 264. Moreover, as illustrated, the first water outlet 506 of the first fluid separator 500 may be fluidly coupled to a first pump 602 and a second water outlet 604 of the second fluid separator 502 may be fluidly coupled to the second pump 400. Each respective pump may be configured to drive the formation water 156 out of the assembly housing 140 through respective housing water outlets 210 (e.g., a first housing water outlet 608 and a second housing water outlet 610) via respective water outlet lines 234 (e.g., a first water outlet line 612 and a second water outlet line 614). Alternatively, the respective water outlets 506, 604 of the first fluid separator 500 and the second fluid separator 502 may both be connected to the first pump 602 to reduce a number of pumps needed in the fluid separator assembly 124.
Accordingly, the present disclosure may provide a fluid separator assembly having a fluid separator configured to operate in a vertical portion of a multilateral well. The systems and methods may include any of the various features disclosed herein, including one or more of the following statements.
Statement 1. A fluid separator system, comprising: a separator housing; a turbine chamber formed within the separator housing; a fluid inlet configured to receive formation fluid and direct the formation fluid into the turbine chamber, wherein the formation fluid includes oil and water; a turbine disposed within the turbine chamber, wherein the turbine is configured to rotate to at least partially separate the formation fluid into formation oil and formation water; an oil outlet configured to receive the formation oil separated from the formation fluid and direct the formation oil toward an upper production tubing; and a water outlet configured to receive the formation water separated from the formation fluid and direct the formation water out of the separator housing.
Statement 2. The fluid separator system of statement 1, wherein the turbine is configured to rotate at a speed above a threshold speed to generate artificial gravity for the formation fluid disposed in the turbine chamber, and wherein the artificial gravity is configured to separate the formation oil of the formation fluid from the formation water of the formation fluid based on density.
Statement 3. The fluid separator system of statement 1 or statement 2, wherein the turbine includes a base portion and a bladed portion, wherein a radially outer surface of the base portion includes a cylindrical shape, and wherein the bladed portion includes a plurality of blades secured to the radially outer surface of the base portion.
Statement 4. The fluid separator system of any preceding statement, wherein the base portion includes a hollow central portion, and wherein the oil outlet is disposed within the hollow central portion of the base portion of the turbine.
Statement 5. The fluid separator system of any preceding statement, wherein the fluid inlet includes an inlet nozzle configured accelerate the flow rate of the formation fluid passing through the fluid inlet and to direct the flow of the formation fluid toward the turbine, and wherein a force exerted on at least one blade of the turbine via the flow of the formation fluid is configured to drive rotation of the turbine within the turbine chamber.
Statement 6. The fluid separator system of any preceding statement, wherein the turbine is disposed in the turbine chamber in a position axially between the inlet nozzle and the water outlet.
Statement 7. The fluid separator system of any preceding statement, further comprising a motor configured to drive rotation of the turbine.
Statement 8. The fluid separator system of any preceding statement, wherein a lower axial end of the turbine is axially offset from a bottom surface of the turbine chamber to form a lower flow path for the formation oil to flow across the turbine to the oil outlet, and wherein an upper axial end of the turbine is axially offset from a top surface of the turbine chamber to form an upper flow path for the formation oil to flow across the turbine to the oil outlet.
Statement 9. The fluid separator system of any preceding statement, wherein the separator housing is configured to be positioned within a multilateral well at a junction between a main bore and at least one lateral bore of the multilateral well.
Statement 10. The fluid separator system of any preceding statement, wherein the separator housing is configured to be positioned within a vertical portion of a multilateral well.
Statement 11. The fluid separator system of any preceding statement, wherein the separator housing is disposed within an assembly housing of a fluid separator assembly, wherein the assembly housing includes a hollow interior extending through the assembly housing, and wherein the separator housing is secured within the hollow interior of the assembly housing.
Statement 12. The fluid separator system of any preceding statement, wherein the fluid separator assembly further includes a pump disposed within the assembly housing, wherein the water outlet is fluidly coupled to the pump, and wherein the pump is configured to drive the formation water separated from the formation fluid out of the assembly housing.
Statement 13. The fluid separator system of any preceding statement, wherein the assembly housing further includes at least one oil outlet line extending through the assembly housing, wherein the oil outlet line is configured to fluidly couple the oil outlet with the upper production tubing.
Statement 14. The fluid separator system of any preceding statement, wherein the fluid inlet is configured fluidly connect a lower production tubing to the turbine chamber, wherein the fluid inlet is configured to receive the formation fluid from the lower production tubing and direct the formation fluid into the turbine chamber.
Statement 15. A system, comprising: an assembly housing;
Statement 16. The system of statement 15, further comprising a second electrical submersible pump positioned within the assembly housing, wherein the oil outlet is fluidly coupled to the second electrical submersible pump, and wherein the second electrical submersible pump is configured to drive the formation oil separated from the formation fluid toward the upper production tubing.
Statement 17. The system of statement 15 or statement 16, further comprising a plurality of fluid separators disposed within the assembly housing, wherein the fluid separators of the plurality of fluid separators are connected to the lower production tubing in parallel.
Statement 18. The system of any of statements 15-17, further comprising a plurality of fluid separators disposed within the assembly housing, wherein the fluid separators of the plurality of fluid separators are connected to the lower production tubing in series.
Statement 19. The system of any of statements 15-18, further comprising a water outlet line and a one-way check valve disposed within the water outlet line, wherein the electrical submersible pump is fluidly connected to an annulus of a main bore of a multilateral well via the water outlet line, and wherein the one-way check valve is configured to prevent water from flowing back into the fluid separator.
Statement 20. A method, comprising: drawing a formation fluid into a fluid separator, wherein the fluid separator comprises: a separator housing; a turbine chamber formed within the housing; a fluid inlet configured to receive formation fluid and direct the formation fluid into the turbine chamber, wherein the formation fluid includes oil and water; a turbine disposed within the turbine chamber, wherein the turbine is configured to rotate to at least partially separate the formation fluid into formation water and formation oil; an oil outlet configured to receive the formation oil separated from the formation fluid and direct the formation oil toward an upper production tubing; and a water outlet configured to receive the formation water separated from the formation fluid and direct the formation water out of the separator housing; separating the formation oil of the formation fluid from the formation water of the formation fluid via artificial gravity generated via rotation of the turbine; drawing the formation oil separated from the formation fluid to a surface via the upper production tubing; and expelling the formation water from the fluid separator and into an annulus of a main bore and/or a lateral bore of a multilateral well.
The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods may also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. The systems and methods may comprise any of the various features disclosed herein, comprising one or more of the following statements.
For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present examples are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only, and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all of the examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
The present application is a non-provisional conversion of U.S. Provisional Application Ser. No. 63/534,788, filed Aug. 25, 2023, the entire disclosure of which is incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 63534788 | Aug 2023 | US |
