OFFSHORE FLOATING UTILITY PLATFORM AND TIE-BACK SYSTEM

Abstract

The present invention relates to a system for producing hydrocarbons from remote subsea wells to a host production facility using a portable floating utility platform and tie-back system. The subject system comprises a floating utility platform positioned near a plurality of subsea wells; a plurality of control umbilicals connecting said platform to a well control system positioned near the wells and a pump and separation control system wherein the produced hydrocarbons flow from the well control system through a HIPPS to the pump and separation control system; and a host production platform equipped to receive the produced hydrocarbons from a reduced pressure export flowline that transports the hydrocarbons the entire tie-back length from the pump and separation control system to the host production platform. Optionally, the system can provide seawater injection capabilities as well as a single-track pigging.

Description

RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No. 62/697,210 filed Jul. 12, 2018. The entire contents of the above application are hereby incorporated by reference as though fully set forth herein.

FIELD

The present invention relates to the field of subsea hydrocarbon production. More specifically, the present invention relates to a system for producing hydrocarbons from remote subsea wells to a host production facility using a portable floating utility platform and tie-back system.

BACKGROUND

With larger oil and gas discoveries becoming less common, especially in the Gulf of Mexico, attention has turned to previously untapped, less economically viable discoveries. However, with crude oil prices remaining depressed, it is simply not economically feasible for companies to manufacture and deploy new production facilities to these remote, smaller reservoirs, especially in deeper water. For example, the cost alone to develop a deep-water strategy, and then manufacture and deploy the necessary infrastructure, can exceed a billion dollars and take up to ten years. With stagnant oil prices below sixty dollars per barrel, and these remote reservoirs estimated to yield less than 100 MM barrels of equivalent (BOE) of crude oil, the economics do not justify such an investment.

This inherent problem has forced offshore production companies, especially in the Gulf of Mexico, to develop “tie back” systems that utilize long umbilicals and subsea systems to connect these less commercially viable reservoirs to existing production platforms (or “host platforms”). However, current tie-back systems presently available have their own technical and commercial limitations. Current tie-back systems comprise three essential elements: (i) a host production platform that (ii) utilizes a plurality of umbilicals to provide necessary well-control and subsea support, and (iii) at least one flowline for transporting hydrocarbons from the well(s) to the host platform. A typical subsea development system consists of at least one subsea production well or wells, a manifold (if there is more than one well), pipeline end terminations (PLETS), and an umbilical termination assembly, connected by flowlines, jumpers, flying leads and umbilicals. The capital cost and technical requirements for flow assurance in these conventional tie-back systems have limited the tie-back distance to approximately a twenty-five (25+/−) mile radius from the host facility, leaving several reservoirs out of reach from existing facilities. In the Gulf of Mexico alone, there exists several additional, commercially viable remote discoveries, that remain untapped because of the limitations associated with current tie-back systems.

Additionally, the Bureau of Safety and Environmental Enforcement (BSEE) has not been willing to allow long distance tie-back systems to utilize a high-integrity pressure protection system (HIPPS) as a safeguard to prevent over pressurization in flowlines. A HIPPS is installed in the flowline near the wellhead in order to monitor pressure in the flowline, and if needed, close off the flowline through a series of hydraulically actuated valves. A HIPPS generally consists of a plurality of sensing elements used to measure flowline pressure, a processor adapted to compute the values from the sensing elements to determine whether the flowline is over pressurized, and if so, the processor will send a demand signal to the host platform through an umbilical to close the hydraulically actuated valves. However, BSEE has yet to approve a HIPPS for a long distance conventional tie-back system due to the fact that the demand signal must travel up to twenty-five (25) miles from the well to the host facility; the time delay between the signal demand and actual shut-off is too long and exposes flowlines to over pressurization for an unacceptable amount of time.

Without a HIPPS in place, BSEE requires every component of the system from the wellhead to the host production facility, including all flowlines, be tested to withstand maximum shut-in reservoir pressure. In the Gulf of Mexico, reservoir pressures can reach 15,000 psi. Equipping conventional tie-back systems with piping that meets these standards significantly increases capital development costs, especially when the tie-back system is servicing multiple wells. With a HIPPS in place, BSEE would allow for production flowlines to be rated for dramatically lower pressures, thus reducing excess material costs, up to as much as 350%, as distances increase between the remote wells and the host facility.

Additionally, current tie-back systems are limited in their ability to provide water injection (a.k.a waterflooding) treatments to the reservoir as a means to enhance hydrocarbon production. For offshore developments, waterflooding involves drilling injection wells into the reservoir and introducing treated water into the reservoir to increase depleted pressure in the reservoir, allowing for additional hydrocarbons to be produced. As tie-back distances increase, the required control umbilicals, power umbilicals, risers, and equipment to facilitate such treatments render this option less viable from an economics and technical standpoint.

Additionally, as tie-back distance increases for these systems and reservoir pressure is depleted, it becomes critical for the system to provide power generation capabilities to subsea booster pumps near the well in order to facilitate transportation of the hydrocarbons back to the host facility. Like waterflooding, power for these booster pumps is provided though umbilicals connected to the host facility. And in similar fashion, when it comes to servicing more remote wells, an umbilical connection between the subsea pumping system and the host facility becomes less viable.

BRIEF SUMMARY OF THE INVENTION

It is the object of the present invention to overcome the economical and technical limitations in current tie-back systems by developing an improved system that still utilizes an existing host production facility, but greatly increases the tie-back length while simultaneously providing a safer, more productive, and cost-efficient method for producing hydrocarbons from these remote reservoirs.

In the preferred embodiment, the tie-back system comprises a floating utility platform positioned near a plurality of subsea wells; a plurality of control umbilicals connecting said platform to a well control system positioned near the wells and a pump and separation control system wherein the produced hydrocarbons flow from the well control system through a HIPPS to the pump and separation control system; and a host production platform equipped to receive the produced hydrocarbons from a reduced pressure export flowline that transports the hydrocarbons the entire tie-back length from the pump and separation control system to the host production platform. Although the preferred embodiment utilizes the HIPPS in tandem with a subsea pump and separation control system, alternative embodiments may use one without the other.

Optionally, the system further provides a more efficient and affordable method for pigging the export flowline. “Pigging” is a term used in the art to refer to a method of cleaning and inspecting the export flowline through the process of deploying single unit “pigs” into the flowline. For existing tie-back systems, a pig launching station located on the host facility is connected to the well control system via one high pressurized flow line and the pig receiving station would also be located on the host production platform and connected to the second high pressure export flowline transporting the hydrocarbons to the host facility, such that a closed loop is formed. The pig launching station would launch a “pig” that would travel through the aforementioned loop, serving to unclog and clean any blockages in the export flowline. Unlike current tie-back systems, the disclosed system does not require a closed loop for pigging capabilities. Rather, the floating utility platform may be equipped with a pig launching station wherein pigs will be launched directly into a low pressure export flowline via a WYE fitting or some other comparable fitting and received by the host production facility.

Optionally, the system further provides water flooding capabilities known in the art to these remote reservoirs to enhance hydrocarbon production combined with power generation capabilities for subsea pumps to export hydrocarbons from depleted reservoirs back to the host facility.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is schematic diagram of the preferred embodiment of the present system.

FIG. 2 is schematic diagram of the preferred embodiment of the present system showing a plurality of subsea wells interconnected by a well control system.

FIG. 3 is a schematic diagram for a High Integrity Pressure Protection System (HIPPS) incorporated into the preferred embodiment of the present system.

FIG. 4 is a schematic diagram of the preferred embodiment of the present system showing the subsea pump and separation control system.

FIG. 5 is a schematic diagram for a pigging system incorporated into the preferred embodiment of the present system.

FIG. 6 is a schematic diagram for a seawater treatment and injection system incorporated into the preferred embodiment of the present system.

DETAILED DESCRIPTION

Turning to FIG. 1, a schematic diagram of the preferred system is shown. The system comprises a host production platform 10 spaced apart from a floating utility platform 20 that is positioned near a plurality of subsea wellheads 110, and a network of subsea systems, including a well control system 25 (as shown in detail in FIG. 2) utilizing a HIPPS 35 (as shown in detail in FIG. 3), a pump and separation control system (as shown in detail in FIG. 4), an optional pigging system 55 (shown in FIG. 5), an optional seawater treatment and injection system 65 (shown in FIG. 6), and a plurality umbilicals used to connect the utility platform 20 to the various subsea systems, as well as flowlines that are used to transport hydrocarbons from the well to the host production platform 10. The host production platform 10 is further equipped to receive the hydrocarbons via a fortified steel catenary riser (“SCR”) 30 adapted to receive the hydrocarbons from the low-pressure export flowline 50.

Turning to FIGS. 1-2, the preferred system anticipates the floating utility platform 20 may be positioned up to approximately one radial mile from any of the subsea wells 100 that are interconnected via the well control system 25. Necessary power, chemicals, and well control are provided to the well control system 25 via a first umbilical 70 from the utility platform 20. The first umbilical 70 terminates at a subsea termination unit 80 where a plurality of flying leads 90 provide utilities and control over each subsea tree 120 (positioned on top of a wellhead 110), a subsea manifold 140 (if more than one well is being serviced), and the HIPPS module 150. Although the figures demonstrate that the subsea termination unit 80 is raised above the sea floor, this was purely for ease in demonstrating the connections in the well control system 25. For purposes of this application, the subsea termination unit 80 is located on the sea floor. Assuming a plurality of wells 100 are being serviced, the crude oil from the wells 100 is transported from the wellheads 110 and trees 120, to the manifold 140 via compliant high-pressure flowlines 130, commonly known as “jumpers” in the art. The HIPPS module 150 may be incorporated into the manifold 140 or connected to the manifold 140 by a high-pressure flowline 130.

Turning to FIG. 3, a HIPPS requires control equipment and power generation capabilities on the topside of the utility platform 20, including a HIPPS control panel, a hydraulic power unit, and an electrical power unit (not shown). The utilities provided by the topside equipment are connected to the subsea HIPPS module 150 via the first umbilical 70, that terminates at the subsea termination unit 80, were power is passed through to the connecting leads 90. The module 150 comprises a plurality of pressure sensors 160 adapted to measure the pressure in the flowline 130, and a processor 170 adapted to perform diagnostics on the input pressure values and determine if a demand signal should be sent to the shut-down valves 180 to prevent overpressurization. The fortified flowline 190 from the HIPPS module 150 to the subsea pump and separation module 210 is rated to full reservoir shut-in pressure to account for any overpressurization caused by the delay between the transmission of a demand signal and the shut-down valves 180 being activated.

Turning to FIG. 4, the preferred system further comprises a subsea pump and separation control system 45 that is connected to the utility platform 20 by a second umbilical 200 that provides power, controls, and hydraulics to a pump module 210 on the sea floor. At a minimum, the pump module 210 comprises at least a single pump and an equivalent back-up pump that are regulated by valves and a control unit inside the pump module. An example of a pump module known in the art that may be incorporated into the system is the helicoaxial multiphase pump module, or any type of similar module. According to BSEE standards, the fortified pipeline 190 transporting hydrocarbons from the well control system 25 to the pump module 210, or if using a HIPPS, from the HIPPS module 150 to the pump module 210, must be rated to withstand full reservoir shut-in pressure. The preferred system anticipates the pump module 210 may be positioned up to approximately one radial mile from the HIPPS module 150 or well control system 25. As shown in FIG. 1, the subsea pump module 210 is positioned on the sea floor approximately beneath the floating utility platform 20. When activated, the booster pumps within the pump module 210 function to reduce backpressure on the reservoir. Back pressure is related to the resistance to flow downstream from the well to the host platform. For the subject system, the back pressure tells you how much pressure is needed to achieve a certain flowrate. By reducing backpressure in the flowline, a depleted reservoir pressure is sufficient to produce additional hydrocarbons from the well and transport those hydrocarbons over greater distances to the host production platform 10. For the disclosed system, the use of a HIPPS in tandem with the subsea pump and separation control system 45 allow not only additional hydrocarbons to be produced from a remote well, but also allows those hydrocarbons to be transported up to a distance of approximately one hundred miles to the host production platform 10 via a lower pressure compliant export flowline 50.

Turning to FIG. 5, as an additional option, the preferred system allows the incorporation of a single-track pigging system 55, as opposed to a closed-loop system utilized in existing tie-back systems. The pigging system 55 comprises topside equipment on the utility platform 20, including at a minimum a pig launching unit, pigging pump, isolation valve skid, and a hydraulic power unit (not shown). This equipment allows a pig to be propelled from the pig launcher on the topside of the platform 20 through a SCR 220 and into the low-pressure export pipeline 50 via a Wye fitting 250, such as the piggable Wye fittings manufactured by Oceaneering®, located inside the subsea pigging skid 230. The pigging skid 230 further comprises at least one actuator valve 240 that controls the access of a pig into the WYE fitting 250. The valve 240 can be open and closed by using a remote operated vehicle (ROV), or via the second umbilical 200 if the valve is hydraulically actuated.

As a second option, the system may further comprise a seawater treatment and injection system 65 to provide waterflooding capabilities to enhance hydrocarbon recovery from depleted wells. As seen in FIG. 6, waterflooding requires a separate pre-drilled injection well 270 that is spaced apart from the previously disclosed subsea systems and is connected to the utility platform 20 via a water injection SCR 260. The utility platform 20 is equipped with required topside equipment (not shown) known in the art that enables treated seawater to be pumped through the injection SCR 260 and into the injection well 270. In general, topside seawater intake pumps will lift seawater to the top side; the water is then filtered through a coarse strainer and microfiltration skid. Next, the water is pumped through a sulfate reduction membrane to remove sulfate ions and a deaeration membrane to remove oxygen before being pressurized and pumped into the injection SCR by a plurality of injection pumps. This process is repeated as much and as often as necessary to replenish depleted pressure in the reservoir, allowing for additional hydrocarbons to be recovered.

For the purposes of promoting an understanding of the principles of the invention, reference has been made to the preferred embodiments illustrated in the drawings, and specific language has been used to describe these embodiments. However, this specific language intends no limitation of the scope of the invention, and the invention should be construed to encompass all embodiments that would normally occur to one of ordinary skill in the art. The particular implementations shown and described herein are illustrative examples of the invention and are not intended to otherwise limit the scope of the invention in any way. For the sake of brevity, conventional aspects of the method (and components of the individual operating components of the method) may not be described in detail. Furthermore, the connecting lines, or connectors shown in the various figures presented are intended to represent exemplary functional relationships and/or physical or logical couplings between the various elements. It should be noted that many alternative or additional functional relationships, physical connections or logical connections might be present in a practical device. Moreover, no item or component is essential to the practice of the invention unless the element is specifically described as “essential” or “critical”. Numerous modifications and adaptations will be readily apparent to those skilled in this art without departing from the spirit and scope of the present invention.

Claims

1. A system for producing hydrocarbons from a subsea well, comprising:

a. a floating utility platform;

b. a host production platform operable to receive hydrocarbons;

c. a well control system;

d. a HIPPS;

e. a pump and separation control system;

f. a first umbilical and a second umbilical; and

g. a reduced pressure export flowline; wherein the first umbilical connects the utility platform to the well control system and the second umbilical connects the utility platform to the pump and separation control system; wherein hydrocarbons are produced from the subsea wells into the well control system; wherein the produced hydrocarbons are exported from the well control system, through a HIPPS, to the pump and separation control system before being exported to the host production platform via the reduced pressure export flowline.

2. The system of claim 1 wherein the well control system connects to a plurality of wells.

3. The system of claim 1 wherein the pump and separation control system is positioned up to one mile from the well control system.

4. The system of claim 1 wherein the host production platform is position up to one hundred miles away from the pump and separation control system.

5. The system of claim 1 further comprising a single-track pigging system, wherein one end of the system is connected to the utility platform and the other end is connected to a reduced pressure export flowline.

6. The system of claim 1 further comprising a seawater treatment and injection system that is connected to the utility platform via a SCR on one end and the other end is connected to an injection well, wherein treated seawater is pumped from the utility platform through the SCR and into the injection well.

7. A system for producing hydrocarbons from a subsea well, comprising:

a. a floating utility platform;

b. a host production platform operable to receive hydrocarbons;

c. a well control system;

d. a pump and separation control system; and

e. a first umbilical and a second umbilical; wherein the first umbilical connects the utility platform to the well control system and the second umbilical connects the utility platform to the pump and separation control system; wherein hydrocarbons are produced from the subsea wells into the well control system; wherein the produced hydrocarbons are exported from the well control system to the pump and separation control system before being exported to the host production platform via a compliant export flowline.

8. The system of claim 7 wherein the well control system connects to a plurality of wells.

9. The system of claim 7 wherein the pump and separation control system is positioned up to one mile from the well control system.

10. The system of claim 7 wherein the host production platform is position up to one hundred miles away from the pump and separation control system.

11. The system of claim 7 further comprising a single-track pigging system, wherein one end of the system is connected to the utility platform and the other end is connected to the compliant export flowline.

12. The system of claim 7 further comprising a seawater treatment and injection system that is connected to the utility platform via a SCR on one end and the other end is connected to an injection well; wherein treated seawater is pumped from the utility platform through the SCR and into the injection well.

13. A system for producing hydrocarbons from a subsea well, comprising:

a. a floating utility platform;

b. a host production platform operable to receive hydrocarbons;

c. a pump and separation control system;

d. an umbilical that connects the utility platform to the pump and separation control system; wherein the pump and separation control system is operable to export produced hydrocarbons from existing wells to the host production platform via a compliant export flowline.

14. The system of claim 13 wherein the host production platform is position up to one hundred miles away from the pump and separation control system.

15. A system for producing hydrocarbons from a subsea well, comprising:

a. a floating utility platform;

b. a host production platform operable to receive hydrocarbons;

c. a well control system; and

d. a seawater treatment and injection system; wherein an umbilical connects the utility platform to the well control system; wherein the produced hydrocarbons are exported from the well control system to the host production platform via a compliant export flowline; wherein the seawater treatment and injection system is connected to the utility platform via a SCR on one end and the other end is connected to an injection well that is spaced apart from the well control system, wherein treated seawater is pumped from the utility platform through the SCR and into the injection well.

16. The system of claim 15 wherein the well control system is connected to a plurality of wells.

17. The system of claim 15 further comprising a single-track pigging system, wherein one end of the system is connected to the utility platform and the other end is connected to the reduced pressure export flowline.

18. A method for producing hydrocarbons from a subsea well, comprising:

a. providing a floating platform positioned in proximity to a subsea well;

b. providing a well control system;

c. providing a subsea HIPPS;

d. providing a pump and separation control system;

e. providing a plurality of control umbilicals connecting said utility platform to the well control system, HIPPS, and pump and separation control system;

f. providing a host production platform operable to receive the produced hydrocarbons;

g. providing a reduced pressure export flowline;

h. producing the hydrocarbons from the well and transporting the hydrocarbons through a compliant high-pressure flowline connecting the well control system, the HIPPS, and the pump and separation control system, and

i. pumping the hydrocarbons through the reduced pressure export flowline to the host production platform.

19. The method according to claim 18, further comprising the step of controlling the pressure in the reduced pressure export flowline connecting the pump and separation control system to the host production platform through a plurality of subsea pumps.

20. The method of claim 18, further comprising the step of transporting the hydrocarbons a distance of up to one hundred miles from the pump and separation control system to the host production platform.

21. The method of claim 18, further comprising the step of injecting treated seawater into the well reservoir by providing a seawater treatment and injection system that is connected to the utility platform via a SCR on one end and the other end is connected to an injection well, wherein treated seawater is pumped from the utility platform through the SCR and into the injection well.

22. The method of claim 18, further comprising the step of pigging the reduced pressure export flowline by providing a single-track pigging system that is connected to the utility platform on one end and the other end is connected to the reduced export flowline.