Systems And Methods For Pressure Boosting Of Liquids Of A Hydrocarbon Gas-Liquid Separator Using One Or More Pumps On Seabed

Description

This application claims the benefit of priority to U.S. provisional application having Ser. No. 61/604366, filed on Feb. 28, 2012. This and all other extrinsic materials discussed herein are incorporated by reference in their entirety. Where a definition or use of a term in an incorporated reference is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein applies and the definition of that term in the reference does not apply.

FIELD OF THE INVENTION

The field of the invention is systems and methods for pressure boosting of liquids on seabed.

BACKGROUND

The following background discussion includes information that may be useful in understanding the present invention. It is not an admission that any of the information provided herein is prior art or relevant to the presently claimed invention, or that any publication specifically or implicitly referenced is prior art.

In a subsea development, boosting of fluid pressure at the well site is needed if the natural pressure is insufficient to overcome the hydrostatic and frictional pressure drop in the tieback pipelines. Traditionally, pressure boosting has been achieved by various methods with the reservoir and the well. However it has become increasingly desirable to be able to boost the pressure at seabed. Although a number of seabed pressure boosting methods have been developed, all of them suffer from one or more disadvantages.

For example, one known method utilizes multiphase pumping at seabed, which takes the full flowstream and boosts the fluid pressure using centrifugal, helicon-axial or twin-screw pumps. Although these pumps are designed to handle a large range of gas volume fraction (GVF), the discharge pressure of the pumps fails to meet required levels if the GVF is too large.

Another known method uses caisson separation and liquid pumping, which is described in U.S. Pat. No. 4,676,308 to Chow, et al.; U.S. Pat. No. 4,900,433 to Dean, et al.; U.S. Pat. No. 5,474,601 to Choi; U.S. Pat. No. 6,688,392 to Shaw; and U.S. Pat. No. 7,766,081 to Brown, et al. This method has been used in the various projects including, for example, Texaco™ Highlander, Petrobras™ VASPS (Vertical Annular Separation and Pumping System) tests, Shell™ BC-10, and Shell Perdido.

In caisson separation and liquid pumping, the produced fluids are flown into the annulus of a caisson (or dummy well) and tubing string is installed below the seabed. Typical caissons are several hundred feet long. As the produced fluids move in the annulus, the fluids separate into gas and liquid. The gas flows upward in the annulus and exit the caisson through the top. The liquid accumulates in the bottom, and is boosted by the electrical submersible pump installed at the bottom of the tubing string. The boosted liquid flows out of the caisson through the tubing. Caisson separation and liquid pumping is disadvantageous because it generally requires a drilling rig for installing the caisson and for repair or replacement of the electrical submersible pumps (ESPs). The high cost of drilling rigs, particularly those for deep water, significantly increases the cost of installation, maintenance and repair.

It is also known to pump full produced stream using an ESP installed at the seabed or in a riser. See, e.g., U.S. Pat. No. 6,412,562 to Shaw; U.S. Pat. No. 7,516,795 to Euphemio, et al.; U.S. Pat. No. 7,565,932 to Lawson; U.S. Pat. No. 8,083,501 to Scarsdale; and U.S. pat. publ. no. 2010/0119380 to Wilson et al. (publ. May 2010). However, such method is disadvantageous in that the ESPs can only handle a gas volume fraction (GVF) of up to 30% in most applications, which generally limits the method's applicability to heavy oil having sufficiently high pressure at the pump suction to keep the GVF within a required range.

Another known method is to utilize a subsea riser separator, which is discussed in U.S. Pat. No. 6,651,745 to Lush et al. This method uses a riser at seabed with a hydraulically driven centrifugal pump to boost the pressure of the liquid. However, such method can be problematic as the required riser height can be substantial and the riser is therefore prone to stability problems. In addition, the need for a riser increases the cost of fabrication and installation, and limits the availability of vessels having the required installation capability.

Thus, there is still a need for systems and methods configured to separate gas and liquid such that the GVF of the liquid is reduced while using one or more pumps to pressure boost liquids in the separator to a required level.

SUMMARY OF THE INVENTION

The inventive subject matter provides apparatus, systems and methods in which one can boost the pressure of liquids at seabed using one or more pumps embedded in a hydrocarbon gas-liquid separator. In preferred embodiments, the one or more pumps, and preferably, one or more ESPs, are installed in a liquid storage section of the gas-liquid separator located on the seabed. The one or more pumps can be selected such that they collectively boost the pressure of the liquid to a required level.

The inventive subject matter discussed herein is applicable for both new subsea tiebacks and retrofitting existing facilities, and thus can be configured to adjust to a range of different flow rates depending on the specific application. The ability to retrofit existing facilities advantageously enhances subsea production of those facilities. Such existing facilities can include those facilities disposed in shallow (e.g., <1,000 feet (304.8 meters)) or deepwater (e.g., between 1,000-5,000 feet (304.8-1524 meters)) installations and having low to medium flow rates (e.g., 2,000-10,000 BOPD), moderate design pressure (e.g., approx. 5,000 psig) and high GVF (e.g., at least 80%). New deepwater installations can include those disposed subsea at a depth of between 7,000-10,000 feet (2134-3048 meters), for example, and having high flow rates (e.g., 20,000-30,000 BOPD), high design pressure (e.g., at least 10,000 psig) and medium GVF (e,g., between 40%-70%).

It is contemplated that the systems and methods discussed herein can be applicable for subsea multiphase pumping installations where the total well stream GVF is between 40%-100% and pump differential pressure is between about 700 psig to about 3,300 psig.

Unless the context dictates the contrary, all ranges set forth herein should be interpreted as being inclusive of their endpoints, and open-ended ranges should be interpreted to include commercially practical values. Similarly, all lists of values should be considered as inclusive of intermediate values unless the context indicates the contrary.

Various objects, features, aspects and advantages of the inventive subject matter will become more apparent from the following detailed description of preferred embodiments, along with the accompanying drawing figures in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic of one embodiment of a system for pressure boosting of liquids in a hydrocarbon gas-liquid separator.

FIG. 2 is a schematic of another embodiment of a system for pressure boosting of liquids in a hydrocarbon gas-liquid separator.

FIG. 3 is a diagram of another embodiment of a system for pressure boosting of liquids in a hydrocarbon gas-liquid separator.

FIG. 4 is a perspective view of one embodiment of a system for pressure boosting of liquids in a hydrocarbon gas-liquid separator.

FIG. 5 is a diagram of another embodiment of a system for pressure boosting of liquids from a well in a hydrocarbon gas-liquid separator.

FIG. 6 is a flowchart of one embodiment of a method for increasing a pressure of liquids in a hydrocarbon gas-liquid separator disposed at seabed.

DETAILED DESCRIPTION

One should appreciate that the disclosed techniques provide many advantageous technical effects including (i) reducing the GVF of the liquid, which enables the application for production with high GVF which exceeds the limit for seabed multiphase pumping; (ii) reducing the initial and long-term costs of the system by utilizing ESPs; (iii) eliminating the need for caisson, which thereby also reduces the installation cost; (iv) allowing the use of ESPs in subsea developments with much higher gas to liquid ratios; (v) reducing the vertical dimension of the installation, which enables the system to be installable by more vessels while also reducing the overall cost of the system. Advantageously, it is contemplated that the system described herein can be installed, serviced and retrieved with a medium speed vehicle (MSV), without requiring a drilling rig.

The following discussion provides many example embodiments of the inventive subject matter. Although each embodiment represents a single combination of inventive elements, the inventive subject matter is considered to include all possible combinations of the disclosed elements. Thus if one embodiment comprises elements A, B, and C, and a second embodiment comprises elements B and D, then the inventive subject matter is also considered to include other remaining combinations of A, B, C, or D, even if not explicitly disclosed.

In FIG. 1, a system 100 for pressure boosting of liquids in a hydrocarbon gas-liquid separator 102 on a seabed is shown. In preferred embodiments, the separator 102 can comprise a generally horizontal subsea separator having upper and tower sections 104 and 106. As used herein, the term “generally horizontal” means within 15 degrees of horizontal. In some contemplated embodiments, each of the upper and lower sections 104 and 106 comprises a cylindrical vessel that is disposed with a slight slope with respect to the seabed, and preferably no more than 30 degrees. Preferably, the upper section 104 can comprise the separation section and the bottom section 106 can comprise the section for liquid residence. In such embodiments, the upper section can include a gas-liquid interface as shown in FIG. 1. Much like traditional gas-liquid separators, in such embodiments, gas can exit the upper section 104 of the separator 102 through a conduit 108 in the upper section 104. From conduit 108, it is contemplated that gas can flow naturally through a separate gas pipeline such as that shown in FIG. 5, or through a conduit built into an umbilical. Alternatively, at least a portion of the gas could be compressed and mixed with the pumped liquid.

The separator can be of any commercially suitable type including, for example, multiple level connected pipes, finger-type slug catchers, large diameter vertical separator vessel, and a long section of large diameter pipe. However, in especially preferred embodiments, the separator comprises multi-level piping, with a first set of pipes disposed in an upper section 104 and a second set of pipes disposed below the upper section 104. An example of this is shown in FIG. 4, although it is contemplated that each set of pipes could include at least five, and still further at least ten pipes, in parallel, for example. The use of multiple bays or sets of pipes enables the system 100 to have a high degree of scalability for a wide range of flow rates, as additional pipes could be added or removed depending on the specific application. In addition, the use of pipes allows the system 100 to be well-suited for deepwater and ultradeep water environments.

It is contemplated that the pipes can each comprise a length of between 60-100 feet (18.29-30.48 meters), and more preferably between 75-85 feet (22.86-25.91 meters) in length. However, the actual length and other dimensions of the pipes will depend on the specific application including the volume of liquid storage needed and the dimensions and numbers of pumps. It is further contemplated that the pipes can act as slug catchers due to the low gas and liquid velocities in the separator 102. The low velocities also help to reduce liquid carry over, and reduce, and preferably eliminate, the need for anti-foamers.

The upper and tower sections 104 and 106 can be fluidly coupled conduits 110 and 112 that are each preferably sized and dimensioned. to facilitate (a) liquid flow through the conduits 110 and 112 without entraining gas and (b) the migration of gas from the lower section 106 to the upper section 104. Although dual conduits are shown, it is important to provide suitable connections between the upper and tower sections 104 and 106 (i.e., gas separation section and liquid residence section) to allow vapor to escape from liquid in the tower section 106 and, at the same time, facilitate separated liquid from the upper section 104 to flow to the lower section 106. Thus, depending upon the overall length of the separator 102 including the upper and lower sections, and other factors, three or more connections between the upper and lower sections 104 and 106 may be used to accomplish this objective.

One or more pumps 114, preferably compact oil field pumps, and more preferably electrical submersible pumps (ESPs), can be installed in the lower section 106 (i.e., liquid storage section). In some contemplated embodiments, the one or more pumps 114 can be embedded within the separator 102, and even within the lower section 106. If necessary for liquid residence time or pump operation, for example, additional cylindrical vessels can be added between the upper and lower sections 104 and 106. The suction of the ESP 114 is preferably at the lower end of the liquid section 106, as shown in FIG. 1, to minimize the quantity of vapor carry over. In preferred embodiments, the separator 102 is sized and dimensioned to maintain the GVF in the liquid at the pump suction within a suitable range for the one or more pumps 114 or other commercially suitable compact oil field pump. The separator 102 advantageously reduces the GYF of the liquid to allow the use of well-proven and cost-effective pumps such as ESPs where it otherwise may not be possible.

It is further contemplated that system 100 could include two or more pumps, and preferably two or more ESPs, to provide redundancy in system 100 and thereby allow for maintenance or replacement of an ESP or other pump while minimizing interference with system operation.

The lower section 106 of separator 102 can be sized and dimensioned such that the lower section 106 is sufficiently sized to allow for gas bubbles to migrate to the gas phase in the separator 102. In addition, the liquid flow to the one or more pumps 114 can be routed in such a way to cool the pump's motor as the liquid approaches the pump suction. The one or more pumps 114 advantageously boost the pressure of the liquid to the required level. The liquid can exit the separator 102 through discharge conduit 118. Electrical cable 120 can be installed alongside the discharge conduit 118 to provide power to the one or more pumps 114.

For applications with high solid production, system 100 can include a jetting system to periodically remove deposited solids, which can be configured to run through the ESPs to the liquid output conduit 118. In extreme cases, a compact desander could be installed upstream of the system 100.

As shown in FIG. 1, a top assembly 122 can be coupled to the separator 102 at or near where the liquid exits the separator through the discharge conduit 118. The top assembly 122 can be coupled to the separator 102 via flanges or other commercially suitable fasteners. The top assembly 122 can also provide a suitable electrical connection for the electrical cable 120.

Should the one or more pumps 114 need to be repaired or replaced, the separator 102 can advantageously be removed to the water's surface. In such cases, the top assembly 122, the discharge conduit 118, and the one or more pumps 114 can be removed from the separator 102 and later reinstalled after the maintenance activities are complete.

As shown in FIG. 2, the top assembly 222 can alternatively be configured such that the discharge conduit 218 and the one or more pumps 214 are housed separately from, but coupled to, the separator 202. In this mariner, should the one or more pumps 214 require maintenance or replacement, only the pump housing would need to be retrieved on maintenance thereby reducing the time and cost for maintenance. With respect to the remaining numerals in FIG. 2, the same considerations for like components with like numerals of FIG. 1 apply.

FIG. 3 illustrates a diagram of another embodiment of a system for pressure boosting of liquids in a hydrocarbon gas-liquid separator 300 on a seabed. With respect to the remaining numerals in FIG. 3, the same considerations for like components with like numerals of FIG. 1 apply.

FIG. 4 illustrates yet another embodiment of a system 400 for pressure boosting of liquids in a hydrocarbon gas-liquid separator 402. The separator can include dual pipes in both the upper and lower sections 404 and 406. Although dual piping is shown, it is contemplated that three or more pipes could be included in each of the upper and lower sections 404 and 406 depending on the specific application. Preferably, the upper and lower sections 404 and 406 are disposed in parallel with respect to each other, and are preferably disposed with a slight incline with respect to the seabed, such that inlet 401 is lower than outlet 408.

As shown in FIG. 4, the upper and lower sections of pipes can be fluidly coupled via connecting conduits 410 and 412. As discussed above, although a total of four connecting conduits are shown, the number of connecting conduits used can vary to allow vapor to escape from liquid in the lower section 106 and, at the same time, facilitate separated liquid from the upper section 404 to flow to the lower section 406.

FIG. 5 illustrates another embodiment of a system 500 for pressure boosting of liquids from a well in a hydrocarbon gas-liquid separator. The well can be fluidly coupled to the system 500 via a jumper. The system 500 preferably includes the gas-liquid separator and at least one pump and preferably at least one ESP. The pressurized fluid stream from the at least one pump and the gas stream can be fed through gas and liquid product conduits to a floating platform, for example.

In FIG. 6, one embodiment of a method for increasing a pressure of liquids in a hydrocarbon gas-liquid separator disposed at seabed is shown. In step 610, a separator is provided having upper and lower sections that are fluidly coupled by at least one conduit. In step 620, a well output fluid can be received in the upper section of the separator. The separator is configured to separate a gas portion of the well output fluid from a liquid portion in step 630. Finally, in step 640, a pressure of the liquid portion can be increased using a first pump to produce a pressurized output fluid.

The first pump can comprise an ESP in step 642, and the first pump is preferably embedded within the lower section of the separator in step 644.

In step 612, the separator can be disposed generally horizontal with respect to the seabed, the upper and lower sections comprise upper and lower cylinders, and the upper and lower cylinders are slightly inclined with respect to the seabed. In step 614, the upper cylinder is disposed approximately parallel to the lower cylinder.

In step 616, the upper and lower sections are each disposed generally horizontal with respect to the seabed. In step 618, the separator is sized and dimensioned such that the gas volume fraction of the liquid at an inlet to the first pump is preferably between 40%-70%.

As used in the description herein and throughout the claims that follow, the meaning of “a,” “an,” and “the” includes plural reference unless the context clearly dictates otherwise. Also, as used in the description herein, the meaning of “in” includes “in” and “on” unless the context clearly dictates otherwise. Also, the term “approximately” means within five percent (5%) unless otherwise defined herein.

The recitation of ranges of values herein is merely intended to serve as a shorthand method of referring individually to each separate value falling within the range. Unless otherwise indicated herein, each individual value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g. “such as”) provided with respect to certain embodiments herein is intended merely to better illuminate the invention and does not pose a limitation on the scope of the invention otherwise claimed. No language in the specification should be construed as indicating any non-claimed element essential to the practice of the invention.

Groupings of alternative elements or ernbodiments of the invention disclosed herein are not to be construed as limitations. Each group member can be referred to and claimed individually or in any combination with other members of the group or other elements found herein. One or more members of a group can be included in, or deleted from, a group for reasons of convenience and/or patentability. When any such inclusion or deletion occurs, the specification is herein deemed to contain the group as modified thus fulfilling the written description of all Markush groups used in the appended claims.

As used herein, and unless the context dictates otherwise, the term “coupled to” is intended to include both direct coupling (in which two elements that are coupled to each other contact each other) and indirect coupling (in which at least one additional element is located between the two elements). Therefore, the terms “coupled to” and “coupled with” are used synonymously.

It should be apparent to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the scope of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced. Where the specification claims refers to at least one of something selected from the group consisting of A, B, C . . . and N, the text should be interpreted as requiring only one element from the group, not A plus N, or B plus N, etc.