US20170016309A1

US20170016309A1 - Long offset gas condensate production systems

Info

Publication number: US20170016309A1
Application number: US15/125,903
Authority: US
Inventors: James George Broze; Gaurav Bhatnagar; Karthik Ramanathan
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 2014-03-17
Filing date: 2015-03-13
Publication date: 2017-01-19
Also published as: AU2015231769A1; CN106103885A; BR112016021511A2; WO2015142629A1; EP3119984A1

Abstract

A long offset gas condensate production system comprising: a subsea production well; a subsea separator; and a subsea cooler.

Description

BACKGROUND

The present disclosure relates generally to long offset gas condensate production systems. More specifically, in certain embodiments the present disclosure relates to long offset gas condensate production systems capable of transporting gas and condensate across subsea floors and associated methods.
During the production, it is often desirable to transport oil long distances across a seafloor. Using subsea flowlines to tieback subsea wells to a remote processing facility is an established method for developing oil and gas fields. The design and specifications of the subsea flowlines may be driven by the needs of flow assurance management. Flow assurance management may include ensuring that the unprocessed well fluid are able to reach the process facility, arrive at the process facility above critical temperatures (such as the wax appearance temperature or cloud point and the hydrate equilibrium temperature), can be made to flow again after planned or unplanned shutdown (particularly with respect to clearing hydrate blockages), avoid hydrates, wax, asphaltene, scale, sand, and other undesirable contents from building up in the flowline, and can be made to flow at a range of driving pressures, flowrates, and compositions.
Typical methods used to achieve the many different demands of flow assurance may include using highly insulated flowlines, pipe-in-pipe flowlines, active heating of flowlines, and dual flowlines. These approaches, however, may have high costs. The oil industry is continually attempting to increase tieback distances and at the same time reduce the costs of those tieback systems. The challenge of having longer tieback distances while at the same time achieving acceptable costs is proving difficult for the industry, especially because subsea tiebacks tend to be the approach used for the smaller reservoirs (which demand lower costs.) Deeper water may also exacerbate the difficulties of subsea tie backs with the added disadvantage that it is much easier for hydrates that can block the flowlines to form in deep water. Flow assurance management may be especially problematic with fluids with high concentrations of water.
It is desirable to develop a method and system of transporting waxy fluids with significant formation water production through long offset distances within a single bare flowline. It is also desirable to develop a method and system of transporting fluids that mitigate or manage flow assurance risks and minimize costs.

SUMMARY

The present disclosure relates generally to long offset gas condensate production systems. More specifically, in certain embodiments the present disclosure relates to long offset gas condensate production systems capable of transporting gas and condensate across subsea floors and associated methods.
In one embodiment, the present disclosure provides a long offset gas condensate production system comprising: one or more subsea production wells; a subsea cooler, and a subsea separator.
In another embodiment, the present disclosure provides a long offset gas condensate production system comprising: one or more subsea production wells; a subsea separator; a subsea cooler; and a subsea compressor.
In another embodiment, the present disclosure provides a method of transporting gas and condensate across a subsea floor comprising: providing a long offset gas condensate production system; providing a subsea production stream, cooling the subsea production stream to form a cooled subsea production stream, separating the cooled subsea production stream into a produced water stream and a combined gas and condensate stream, and transporting the combined gas and condensate stream across the subsea floor.
The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the above recited features and advantages of the disclosure may be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to the embodiments thereof that are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are, therefore, not to be considered limiting of its scope. The figures are not necessarily to scale, and certain features and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

FIG. 1 is an illustration of a long offset condensate production system in accordance with an embodiment of the present disclosure.

FIG. 2 is an illustration of a long offset gas condensate production system in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

The present disclosure relates generally to long offset gas condensate production systems. More specifically, in certain embodiments the present disclosure relates to long offset gas condensate production systems capable of transporting gas and condensate across subsea floors and associated methods.
The description that follows includes exemplary apparatuses, methods, techniques, and/or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.
There may be several potential advantages of the systems and methods discussed herein. One potential advantage is that the methods and systems discussed herein may permit the transport of waxy fluids with significant amounts of formation water through long offset distances within single bare flowlines. Another potential advantage is that the methods and system discussed herein may manage or mitigate the flow assurance risks of transporting fluids through long offset distances.
Referring now to FIG. 1, FIG. 1 illustrates a long offset gas condensate production system 100 comprising a subsea production well 110; a subsea cooler 120; and a subsea separator 130.
In certain embodiments, subsea production well 110 may comprise a single subsea production well 110 or multiple subsea production wells 110. For example, in certain embodiments long offset gas condensate production system 100 may comprise one, two, three, four, five, or more subsea production wells 110. In certain embodiments, each of the multiple subsea production wells 110 may be connected to a subsea manifold 111 by one or more flowlines 112. In certain embodiments, subsea production well 110 may comprise a gas condensate well. In certain embodiments, subsea manifold 111 may comprise any conventional subsea manifold.
In certain embodiments, flowlines 112 may comprise any conventional subsea flowline. In certain embodiments, flowlines 112 may comprise non-CRA materials
In certain embodiments, subsea cooler 120 may comprise any conventional subsea cooler. In certain embodiments, subsea cooler 120 may be used in several different configurations to achieve different flow assurance benefits. For example, as shown in FIG. 1, subsea cooler 120 may be directly connected to a flowline 113 from subsea manifold 111. Alternatively, not illustrated in FIG. 1, subsea cooler 120 may be connected to a well stream directly from a subsea production well. In these configurations, the subsea cooler may be used to cool a subsea production stream before it enters subsea separator 130.
The use of these configurations may depend on the pressure, temperature and water-gas ratio of the fluid in flowlines 112 and/or 113. One benefit of these configurations is that at least a portion of the saturated water in the fluid in flowlines 112 and/or 113 may be removed by lowering the temperature of the fluid. This in turn may lead to lower total water amounts in subsequent streams resulting in much lower hydrate inhibitor dosages. In addition, less water in the fluid may also mitigate corrosion issues in fields with high CO₂content.
In other embodiments, not illustrated in FIG. 1, long offset gas condensate system may not comprise a subsea cooler before subsea separator. In certain embodiments, not illustrated in FIG. 1, long offset gas condensate system may comprise a subsea cooler without subsea separator and/or a compressor.
In certain embodiments, as shown in FIG. 1, flowline 121 from subsea cooler 120 may be connected directly to subsea separator 130. Alternatively, not illustrated in FIG. 1, a flowline from manifold 111 or one or more individual wells 110 may be connected directly to subsea separator 120.
In certain embodiments the subsea separator 130 may be a three-phase separator. In certain embodiments subsea separator 130 may be a two-phase separator. In certain embodiments, subsea separator 130 may be used capable of separating a production stream into a gas stream, a condensate stream, and a water stream. In certain embodiments, subsea separator 130 may comprise a gas flowline 132, a condensate flowline 133, and a water flowline 134.
In certain embodiments, the water stream separated from the production stream within subsea separator 130 may be disposed of or injected into a reservoir. In certain embodiments, water flowline 134 may be connected to a subsea water injection well 140. In certain embodiments, pump 135 may facilitate the flow of the water stream within water flowline 134 water from subsea separation 130 to subsea water injection well 140.
In certain embodiments, gas flowline 132 and condensate flowline 133 may combined to form a combined gas and condensate flowline 136. In certain embodiments, combined gas and condensate flowline 136 may comprise a DLC coated flowline. In certain embodiments, combined gas and condensate flowline 136 may comprise an electrically heated flowline. In certain embodiments, combined gas and condensate flowline 136 may be capable of transporting gas and condensate across the subsea floor to an onshore location.
In certain embodiments, long offset gas condensate production system 100 may comprise subsea pig launcher 150. In certain embodiments, subsea pig launcher 150 may be capable of launching pigs within combined gas and condensate flowline 136.
In certain embodiments, long offset gas condensate production system 100 may comprise paraffin inhibitor injection point 161. In certain embodiments, paraffin inhibitor injection point 161 may be located in combined gas and condensate flowline 136. In certain embodiments, a paraffin inhibitor may be injected into the subsea system at paraffin injection point 161 to mitigate wax deposition in flowlines.
Referring now to FIG. 2, long offset gas condensate production system 200 may comprise any combination of features discussed above with respect to long offset gas condensate production system 100. In certain embodiments, long offset gas condensate production system 200 may comprise a subsea production well 210; a subsea cooler 220; a subsea separator 230, and a subsea water injection well 240.
In certain embodiments, subsea production well 210 may comprise any combination of features described above with respect to subsea production well 210. As can be seen in FIG. 2, in certain embodiments subsea production system 200 may comprise multiple wells 210 connected to a manifold 211 by flowlines 213.
In certain embodiments, subsea cooler 220 may comprise any combination of features discussed above with respect to subsea cooler 120. As can be seeing in FIG. 2, in certain embodiments, subsea cooler 220 may be fluidly connected to subsea manifold 111 by a flowline 212.
In certain embodiments, subsea separator 230 may comprise any combination of features discussed above with respect to subsea separator 130. As can be seen in FIG. 2, in certain embodiments, subsea separator 230 may be connected to a subsea water injection well 240 by a water flowline 234. In certain embodiments, subsea separator 230 may also comprise a gas flowline 232 and a condensate flowline 233. In certain embodiments, gas flowline 232 and condensate flowline 233 may be combined to form a combined gas and condensate flowline 236
In certain embodiments, a subsea compressor 250 may be connected to combined gas and condensate flowline 236. In certain embodiments, subsea compressor 250 may be either dry gas or wet gas compressor. In certain embodiments, subsea compressor 250 may comprise a recycle stream 251. In certain embodiments, subsea compressor 250 may comprise a subsea cooler 252. In certain embodiments, the subsea cooler may be used to cool the combined gas and condensate flowline 236, recycle stream 251, or compressed gas and condensate flowline 237.
In certain embodiments, compressed gas and condensate flowline 237 may comprise a DLC coated flowline. In certain embodiments, compressed gas and condensate flowline 237 may comprise an electrically heated flowline. In certain embodiments, compressed gas and condensate flowline 237 may be capable of transporting gas and condensate across the subsea floor to an onshore location.
In certain embodiments, long offset gas condensate production system 200 may comprise subsea pig launcher 260. In certain embodiments, subsea pig launcher 260 may be capable of launching pigs within compressed gas and condensate flowline 237.
In certain embodiments, long offset gas condensate production system 200 may comprise paraffin inhibitor injection point 261. In certain embodiments, paraffin inhibitor injection point 261 may be located in compressed gas and condensate flowline 237. In certain embodiments, a paraffin inhibitor may be injected into the subsea system at paraffin injection point 261 to mitigate wax deposition in flowlines.
In certain embodiments, the present disclosure provides a method of transporting gas and condensate across a subsea floor. In certain embodiments, the method may comprise: providing a long offset gas condensate production system; providing a subsea production stream, cooling the subsea product stream to form a cooled subsea production stream, separating the cooled subsea production stream into a produced water stream and a combined gas and condensate stream and, and transporting the gas and condensate stream across the subsea floor. In certain embodiments, the long offset gas condensate production system may comprise any combination of features discussed above with respect to long offset gas condensate production systems 100 and 200.
While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

Claims

1. A long offset gas condensate production system comprising: one or more subsea production wells; a subsea separator; and a subsea cooler.

2. The long offset gas condensate production system of claim 1, wherein each of the one or more subsea production wells are connected to a subsea manifold by one or more flowlines.

3. The long offset gas condensate production system of claim 1, wherein the subsea cooler is connected directly to the one or more subsea production wells through one or more flowlines.

4. The long offset gas condensate production system of claim 2, wherein the subsea cooler is connected directly to the subsea manifold through a flowline.

5. The long offset gas condensate production system of claim 1, wherein the subsea separator is directly connected to the subsea cooler through a flowline.

6. The long offset gas condensate production system of claim 1, wherein the subsea separator is directly connected to the one or more subsea production wells by one or more flowlines.

7. The long offset gas condensate production system of claim 2, wherein the subsea separator is directly connected to the subsea manifold through a flowline.

8. The long offset gas condensate production system of claim 1, wherein the subsea separator comprises a three-phase separator.

9. The long offset gas condensate production system of claim 1, further comprising a water injection well.

10. The long offset gas condensate production system of claim 1, further comprising a subsea pig launcher.

11. The long offset gas condensate production system of claim 1, further comprising a paraffin injection point.

12. A long offset gas condensate production system comprising: one or more subsea production wells; a subsea separator; a subsea compressor; and a subsea cooler.

13. The long offset gas condensate production system of claim 12, wherein each of the one or more subsea production wells are connected to a subsea manifold by one or more flowlines.

14. The long offset gas condensate production system of claim 12, wherein the subsea cooler is connected directly to the one or more subsea production wells through one or more flowlines.

15. The long offset gas condensate production system of claim 13, wherein the subsea cooler is connected directly to the subsea manifold through a flowline.

16. The long offset gas condensate production system of any one of claims 12-15, wherein the subsea separator is directly connected to the subsea cooler through a flowline.

17. A method of transporting gas and condensate across a subsea floor comprising:

providing a long offset gas condensate production system;

providing a subsea production stream;

cooling the subsea production stream to form a cooled subsea production stream;

separating the cooled subsea production stream into a produced water stream and a combined gas and condensate stream;

and transporting the combined gas and condensate stream across the subsea floor.

18. The method of claim 17, wherein the long offset gas production system comprises the long offset gas condensate production system.

19. The method of claim 18, wherein the subsea production stream comprises a subsea production stream from the one or more subsea production wells.

20. The method of claim 18, wherein the subsea production stream is cooled in the subsea cooler.