Patent Application
20100147527
1. Field of the Disclosure
The present disclosure relates generally to a subsea system, and in particular, to a subsea boosting cap system.
2. Description of the Related Art
In fluid production subsea systems, it is common to adopt an artificial lift method as a means to achieve economic viable levels of crude oil production and/or improve the reservoir oil recovery. A common method of artificial lift is the use of pumps, such as, for example, Coaxial Centrifugal Pumps (CCPs), which enable increased production rate results. However, current solutions often employ CCPs made to be installed inside subsea wellheads or similar constructions, which imposes a dimensional constraint in diameter. This can result in completion hardware that is excessively tall/large with more complex stack up construction, which could reduce the system reliability and consequentially add some environmental risks.
From a performance view point, this complexity in construction can also result in a long and winding plumbing arrangement, which can cause significant pressure losses with potential detrimental consequences for the production flowrate, resulting in negative financial implications for the oilfield lifetime sustainability. Likewise, taking into consideration the required space on offshore vessels, a heavy, long and/or large pump arrangement adds more difficulties and risks for the installation and intervention activities as well as for onboard repairs. This can result in larger deployment vessels and thus more expensive offshore operations. It can also result in increased risk to the environment due to increased potential leakage paths. These concerns can be especially problematic in deep water fields where the extreme underwater environment can complicate installation and/or repair of subsea equipment, thus resulting in longer shutdown periods and higher costs.
The present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the issues set forth above. For example, the present disclosure can provide one or more of the following advantages: reduced installation costs; reduced operating or equipment costs; increased production rates by reducing the pressure losses across the flow path; reduced equipment size and/or weight; and reduced environmental risks.
An embodiment of the present disclosure is directed to an offshore fluid production system. The system comprises a subsea wellbore at a first position on an ocean floor. A subsea boosting cap system is positioned in a second position on the ocean floor that is different from the first position. The subsea boosting cap system comprises an anchor assembly capable of attaching to the sea floor, the anchor assembly comprising a pump cavity capable of receiving a removable pump assembly. The boosting cap system further comprises a valve system attached to the anchor assembly. The valve system comprises an inlet flow path and an outlet flow path, the inlet flow path being in fluid communication with the subsea wellbore. The boosting cap system further comprises a boosting cap covering the pump cavity. The boosting cap comprises a first flow path configured to provide fluid communication between an inlet flow path and the removable pump assembly when the removable pump assembly is positioned in the pump cavity. A second flow path provides fluid communication between the removable pump assembly and the outlet flow path when the removable pump assembly is positioned in the pump cavity. The boosting cap system also comprises a crossover flow path providing fluid communication between the inlet flow path and the outlet flow path. The crossover flow path bypasses the pump cavity. The valve system is capable of directing fluid flow to the first flow path and the crossover flow path. A downflow production line can be in fluid communication with the outlet flow path of the boosting cap system.
Another embodiment of the present disclosure is directed to a subsea boosting cap system. The system comprises an anchor assembly capable of attaching to the sea floor. The anchor assembly comprises a pump cavity capable of receiving a removable pump assembly. A valve system is attached to the anchor assembly. The valve system comprises an inlet flow path and an outlet flow path, the inlet flow path being capable of fluidly communicating with a subsea wellbore. A boosting cap covers the pump cavity. The boosting cap comprises a first flow path configured to provide fluid communication between the inlet flow path and the removable pump assembly when the removable pump assembly is positioned in the pump cavity. A second flow path provides fluid communication between the removable pump assembly and the outlet when the removable pump assembly is positioned in the pump cavity. A crossover flow path provides fluid communication between the inlet flow path and the outlet flow path, the crossover flow path bypassing the pump cavity. The valve system is capable of directing fluid flow to the first flow path and to the crossover flow path.
Yet another embodiment of the present disclosure is directed to a method for removing a pump assembly positioned in a pump cavity of a subsea boosting cap system having a crossover flow path that bypasses the pump cavity. The method comprises flowing a production fluid through a boosting cap flow path to a pump assembly. The flow of fluid through the pump assembly is stopped. The boosting cap positioned over the pump assembly can be removed. The pump assembly can be removed from the pump cavity. The boosting cap can be replaced over the pump cavity. The fluid can be flowed through the crossover flow path while the pump assembly is removed from the pump cavity.
While the disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
The subsea boosting cap system 106 can include an anchor assembly 110 capable of securing the system to the sea floor. Anchor assembly 110 can be the structural foundation of the system, providing the mechanical support and stability on the mudline sea floor. Anchor assembly 110 can also provide the system vital interlinks and structural basis to receive the inlet and outlet flowline connections, power connections and hydraulic connections for system monitoring and operability.
The anchor assembly 110 can be any suitable type of anchor assembly known in the art. In an embodiment of
In an embodiment, lower frame 118 can be shaped in a manner so as to provide the ability to form a hydro cushion effect when the frame starts to embed into the sea bed. Lower frame 118 can further provide differential pressure when the suction process is started, causing the hydrostatic head to push down the structure into the sea bed until a desired depth is achieved. In an embodiment, the shape of lower frame 118 can be, for example, an upside-down cupped shape forming an enclosed space 120. An opening 122 is formed by lower frame 118 at an end of enclosed space 120, which is designed to allow lower frame 118 to be embedded in the sea floor via a suction force. A suction anchoring tube 124 can be connected to a stab or other conduit (not shown) that can provide a fluid pathway for providing the desired suction to the enclosed space 120 through lower frame 118.
While the above described embodiment employs suction to provide a desired anchor to the sea floor, any other suitable technique for anchoring a structure to the sea floor can be employed in place of or in addition to the anchoring structure of
Subsea boosting cap system 106 can include a valve system 126 attached to the anchor assembly 110 and to a boosting cap 162. Valve system 126 comprises an inlet 128 and an outlet 130. Inlet 128 can be in fluid communication with the subsea wellbore 102 via a production jumper 132. Outlet 130 can be in fluid communication with the downflow production line 108 via a production jumper 134.
Production jumpers 132 and 134 can be attached to the inlet 128 and outlet 130 by any suitable connectors 133, which can be, for example, guide and hinge over connecting devices. An example of a suitable guide and hinge over connecting device is disclosed in WO2008/063080 A1, entitled A CONNECTOR MEANS, by MOGEDAL, Knut et al. and published on May 29, 2008, the disclosure of which is hereby incorporated by reference in its entirety. Other suitable connectors 133 include clamp type devices that can be locked by ROV with a torque tool, hydraulically actuated devices, mechanically actuated devices and/or electrically actuated devices.
Valve system 126 can comprise one or more valves for controlling the flow of fluid through the subsea boosting cap system 106. Any suitable type of valves can be employed. In an embodiment, isolation valves 136 and directional valves 138 can be employed. Isolation valves 136 can be capable of stopping or starting fluid flow through a given flow path. The function of the isolation valves 136 can generally be classified as the tertiary barrier of the overall offshore fluid production system 100, because they are often located in the intermediary position of the subsea field lay out.
Directional gate valves 138 are capable of switching flow from one flow path to another, as discussed in detail below.
In an embodiment, the valve body 142 can be the main structural member of the system. For example, valve body 142 can integrate all components to provide structural capacity, flow path integrity, and pressure containing capability. In an embodiment, valve body 142 has a dual bore passage configuration which provides the ability to divert the flow according to the position of gate 140. In other embodiments, valve body 142 can have three or more passages. Examples of such embodiments are disclosed in Co-pending U.S. Patent Application No. _[Atty Docket No. AKER.022U]_, the disclosure of which is hereby incorporated by reference in its entirety.
The upper valve seats 144 and the lower valve seats 146 physically engage the gate 140 and the valve body 142 so as to provide sealing capability on both sides of gate 140 around both flow paths 155 and 157. In this design concept, the valve seats 144 and 146 can provide isolation between the dual flow paths 155 and 157.
A bonnet assembly 154 can enclose a stem 150 and stem seal packing 152. The stem 150 can be the physical link between an actuator 151 and the gate 140. Actuator 151 can be any suitable actuation system. Such actuations systems are well known in the art. The stem 150 can act as a dynamic barrier of the system, connecting the gate 140 to the actuator 151 to provide the valve functional motion. While the bonnet assembly 154 is illustrated with a single stem 150, any suitable number and type of actuators can be employed, such as one or more hydraulic, manual, electrical and ROV operated actuators. Bonnet 154 can provide structural retention for the dynamic sealing around the stem 150, as well as structural strength to mount an actuation system of any type.
In an embodiment, directional valve 138 can comprise a single gate 140 activated by a single actuator. In other embodiments, multiple gates and/or multiple actuators can be employed. The gate 140 can either be made as one integral piece or as an assembly of multiple parts, as desired. A sealing system (not shown) between gate 140 and valve seats 144 and 146, as well as between the valve seats and valve body 142, can include any suitable type of sealing mechanism. For example, the sealing mechanism can comprise a metal to metal type seal, or any other suitable type of seal made of any suitable material.
Directional valve 138 can include a single inlet, illustrated as flow path 153, and two outlets, flow paths 155 and 157, as illustrated in the embodiment of
Referring again to
The boosting cap 162 is configured to allow fluid connection with the valve system 126. In an embodiment, at least a portion of the valve system 126 of
Boosting cap 162 comprises the first flow path 158, which can be configured to provide fluid communication between the inlet flow path 188 and the removable pump assembly 116 when removable pump assembly 116 is positioned in pump cavity 114. Boosting cap 162 further comprises a second flow path 160, which is configured to provide fluid communication between the removable pump assembly 116 and outlet flow path 189 when removable pump assembly 116 is positioned in pump cavity 114.
In an embodiment, boosting cap 162 further comprises a crossover flow path 156 configured to provide fluid communication between the inlet flow path 188 and outlet flow path 189. This configuration allows fluid flow from the subsea wellbore to bypass the pump cavity 114 when desired, such as when removable pump assembly 116 is removed from the pump cavity 114 for maintenance and/or repair.
In an alternative embodiment, illustrated in
Referring again to
The pumps 164 can be enclosed inside a suitable enclosure, such as, for example, a canister 165. Canister 165 can provide physical protection for the pumps 164 by providing structural integrity and physical capability to withstand installation and operational loads. Canister 165 can also act as a pressure barrier to the environment.
The removable pump assembly 116 can include any suitable means for providing power to the pumps 164, such as, for example, a high voltage penetrator 174. In an embodiment, as illustrated in
While the high voltage penetrator 174 is illustrated at a horizontal position by the side of the spool adapter 166, it can be installed at any suitable position and be configured in any suitable spatial arrangement with respect to the subsea boosting cap system 106. For example, it can be positioned on an upper side of the boosting cap 162 in a horizontal or vertical arrangement via an ROV flying lead. ROV flying leads are well known in the art.
In an embodiment, pump assembly 116 can further include a settling cavity 168 to accommodate deposition of contaminants, such as debris and/or denser parts of the produced fluid. Fluid flow path 158 is in fluid communication with settling cavity 168 via a third fluid flow path 170. Fluid is pumped up from the settling cavity through a fourth flow path 172, through second flow path 160 in the boosting cap 162, and then through outlet flow path 189 to the outlet 130. Thus, settling cavity 168 can close the loop between the third fluid flow path 170 and the fourth flow path 172.
The various portions of the pump assembly 116 can be fastened together by any suitable manner that can provide the desired seal integrity and physical capability to withstand installation and operational loads. For example, clamps 175 can be used to fasten both the spool adapter 166 and the settling cavity 168 to the canister 165, as illustrated in the embodiment of
The pump assembly 116 can employ seals to provide desired protection from leakage into and out of the various connections between the different parts of pump assembly 116. For example, seals 178 can be employed for sealing the canister 165. Seals 180 can provide sealing around flow bores, such as the flow bore connections between the canister 165 and the settling cavity 168. Seals 178 and 180 can be any suitable type of seals, such as, for example, metal-to-metal seals.
Periodic maintenance or replacement of the pump assembly 116 can involve removing the pump assembly 116 from the subsea boosting cap system 106. If a spare pump assembly is available, the boosting cap 162 and pump assembly 116 can be retrieved to the surface, where the pump assembly 116 can be replaced by the spare pump assembly. Then the boosting cap 162 and spare pump assembly can be re-installed in the subsea boosting cap system 106.
Thus, in situations where the subsea boosting cap system 106 is in bypass mode for a relatively long period of time, such as where a spare pump assembly is not available, the boosting cap 162 can be attached to the pressure cap 176 to provide a double barrier while the fluid production system 100 is under production mode (e.g., while hydrocarbon fluids are flowing through crossover flow path 156). Alternatively, it may be desirable to employ the boosting cap system 106 in bypass mode for periods of time without the pressure cap 176.
In the embodiment of
In an embodiment of
A boosting cap flowbore connector 186 can be attached to boosting cap 162 in an embodiment of
As shown in the embodiment of
In an embodiment, production fluid can be flowed through the crossover flow path after the boosting cap is replaced, but while the pump assembly is removed from the pump cavity, as shown at 212. In another embodiment where a system such as that shown in the embodiment of
In an embodiment, the method can include positioning a pressure cap 176 over the pump cavity, in addition to replacing the boosting cap, after the pump assembly is removed. As discussed above, the pressure cap can provide a second barrier to help prevent fluid spills while the pump assembly is removed.
For the offshore contingency where the pressure cap 176 is used, the pressure cap 176 can be installed on the ocean surface, such as onboard an intervention vessel. Alternatively, pressure cap 176 can be installed in a subsea operation. An example of a subsea installation employing the pressure cap 176 can include the following main steps: First, the pressure cap 176 can be run via a running tool and deployed on a subsea boosting cap system intervention receptacle (not shown), which can be used for holding the cap 176 while the running tool removes the pump assembly 116. The running tool can then lock and lift the boosting cap 162 and removable pump assembly 116 to deploy it in a mudmatt receptacle (also not shown), where the running tool releases the boosting cap 162 from the spool adapter 166 of the removable pump assembly 116. At this point in time, new seals can be placed by an ROV on flowline connection porches, as is well known in the art. After that, the running tool can move and lock the boosting cap 162 onto the pressure cap 176. The boosting cap/pressure cap assembly is then positioned back into the pump cavity 114. The connection system is then locked to the inlet and outlet connectors. The running tool can then be locked onto the spool adapter 166 of the pump assembly 116 that was removed from the pump cavity, and the pump assembly 116 can be transported to the surface.
The systems of the present disclosure can be installed using any suitable method. The following method provides one illustrated example for anchoring the Suction Anchoring Structure. First, the Suction Anchoring Structure can be prepared with a vent hatch opened, as is well known in the art. Slings can be attached from the Suction Anchoring to the vessel crane master, with a heave compensator at a non-active mode. The suction anchoring system can be lowered through the splash zone with the vent hatch open. Run down toward the seabed can occur at any suitable speed, such as at speeds of about 0.5 m/s. The suction anchoring system can be stopped around 3 meters above the seabed and the heave compensator can be placed at active mode. Run in speed can then be reduced as desired (e.g., as slow as possible) when entering into the seabed, while watching for correct alignment. After entering the seabed, lowering can be continued until slack is produced in the slings. Then an ROV can close the vent hatch and hook up a suction stab into the suction anchoring tube. Suction can then be started to force the frame down into the seabed until the final desired depth is achieved.
While the systems of the present disclosure have generally been shown as having a vertical configuration, one of ordinary skill in the art would readily understand that the systems can also be configured in any other direction, such as to have a horizontal or angular configuration.
Although various embodiments have been shown and described, the disclosure is not so limited and will be understood to include all such modifications and variations as would be apparent to one skilled in the art.
This application claims priority to U.S. Provisional Patent Application 61/122,001, filed Dec. 12, 2008, and entitled SUBSEA BOOSTING CAP SYSTEM, the disclosure of which is hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 61122001 | Dec 2008 | US |
