Field of Invention

The invention relates to a separation system for boosting the pressure of production fluids from low pressure wells.

Background

The days of global peak oil production are long gone. With soaring global demand and depleting supplies of crude oil, maximizing oil production in mature fields is desirable.

In general, mature fields are oil fields that have been producing oil for a long period of time. However, the reservoir pressure of an oil field depletes over time. Due to pressure depletion, gas lifts are installed to encourage oil to the surface, wherein gas is piped down alongside the shaft such that bubbles are formed in the oil field to help reduce the viscosity and static head of the production fluid and help lift the oil up through the shaft.

Since pressure depletion is inevitable it is especially challenging to continue to produce as there is insufficient reservoir pressure to push the well fluids to the main processing facilities.

In addition, wellhead platforms are usually small and unmanned. As such, it is often not economical to develop or modify existing facilities to improve the pressure due to constraints on space, weight and/or cost. An aim of the invention is to address at least some of the above issues and provide a system for boosting the pressure of production fluids from low pressure oil wells.

Summary of Invention

In an aspect of the invention, there is provided a low pressure separation system comprising:

a separator for receiving fluid from a well, comprising a fluid inlet, a gas outlet and a liquid outlet;

a surge vessel for receiving liquid from the separator, comprising a liquid inlet and a liquid outlet;

a connecting pipe connecting the liquid outlet of the separator to the liquid inlet of the surge vessel;

an equalisation pipe connecting the surge vessel and the separator for selectively equalising the pressure therebetween;

characterised in that the surge vessel is provided with a gas pipe connected to a high pressure gas source for selectively using gas to force the liquid out of the liquid outlet of the surge vessel.

Advantageously the pressure from the high pressure gas is sufficient to force the liquid from the low pressure well to the downstream production header, without the need for pumps and associated utilities. As the system is tailored to boost the pressure of production fluids from low pressure wells, it is ideally suited for remote wellhead platforms where wells have insufficient pressure to deliver well fluids to production header, where space is a constraint, and manning is not required. In one embodiment each pipe is provided with limiting means for controlling the flow of fluid therethrough. Typically the limiting means comprises any or any combination of valves, check valves, restriction orifices, and/or the like. In one embodiment, the system comprises two configurations;

a filling configuration wherein liquid flows to the surge vessel, fluid is allowed to flow through the equalisation pipe, and gas is prevented from flowing through the gas pipe; and

a discharge configuration wherein fluid is prevented from flowing through the equalisation pipe, and gas is allowed to flow through the gas pipe to force the liquid out of the liquid outlet of the surge vessel.

Typically the surge vessel is provided with a high level sensor which activates the discharge configuration when it is reached by the level of liquid, and a low level sensor which activates the filling configuration when the level of liquid drops thereto.

Thus while the system is in the discharge configuration, liquid is supplied to the production header at the appropriate pressure, and the separator begins to fill with fluid such that when the system switches to the filling configuration, the liquid drains from the separator into the surge vessel and the cycle repeats.

In one embodiment the separator is provided with sufficient liquid hold-up volume to contain all the production fluid from the wells which is produced whilst the surge vessel is being pressurised in the discharge configuration. In one embodiment the liquid production rate can be calculated by summing the respective partial volumes between high and low level sensors for the number of discharge or filling cycles performed in a predetermined period of time. Thus advantageously a flowmeter is not required.

In one embodiment the surge vessel is provided with interface level measurement means such that the oil and produced water flow rates can be calculated by summing the respective partial volumes of each phase between high and low level sensors for the number of discharge or filling cycles performed in a predetermined period of time.

Typically the connecting pipe is provided with a check valve that prevents fluid flowing from the surge vessel to the separator. Advantageously this helps prevent gas escaping into the separator and to the gas vent.

Typically the connecting pipe extends to below the level of the low level sensor. Advantageously this provides a double seal to prevent high pressure gas from escaping to the separator. Firstly the check valve will prevent backflow to the separator. Secondly, the liquid seal in the surge vessel will prevent gas breakthrough from the surge vessel to the separator section.

In one embodiment the high pressure gas source is from a high pressure well, a high pressure production header, a gas lift system, an upstream first stage separator, or a compressor that compresses gas from the wells.

In one embodiment the separator receives fluid via a further separator operating at a higher pressure for separating liquid and gas. Typically the high pressure gas source is the further separator, at least part of the gas separated thereat being routed to the surge vessel. Thus the further (first stage) separator provides the gas for forcing out liquid from the surge vessel to the downstream header, and the requirement for an external gas source is eliminated.

In one embodiment the gas pipe is provided with a control valve which is regulated on differential pressure between downstream of said control valve and downstream of the liquid outlet of the surge vessel, typically beyond the restriction orifice. This ensures constant flow of liquid in the discharge configuration, irrespective of the actual operating pressure of the production manifold where the liquid is routed.

In one embodiment the surge vessel is provided with a heating coil through which the gas flows before it enters the surge vessel. Typically one or more valves and/or restriction orifices are provided to reduce the pressure of the gas. Advantageously this ensures the gas enters the surge vessel at an appropriate temperature and pressure, and the gas pressure can be reduced gradually in order to avoid sudden drops in temperature due to the Joule-Thomson effect.

In one embodiment the gas outlet includes a compressor for use in recovering gas for use as the high pressure gas source and/or for export.

In one embodiment the gas outlet of the separator is provided with a gas stack positioned vertically above the separator. Advantageously this prevents liquid drop out therefrom, as any liquid flows back to the separator.

Typically the gas stack is provided with a vent including a nozzle arrangement to allow a pressure drop of up to around 20kPa (0.2 bar) thereat. Advantageously this ensures that the gas exiting the vent nozzle will be in the superheated region of the phase envelope.

In a further aspect of the invention, there is provided a method of obtaining fluids from a low pressure well comprising the steps of:

receiving fluid from a low pressure well in a separator via a fluid inlet, gas being directed to a gas outlet, liquid being directed to a liquid outlet;

receiving liquid from the separator in a surge vessel via a connecting pipe, gas being selectively directed from the surge vessel to the separator via an equalisation pipe;

characterised in that when the liquid reaches a predetermined high level in the surge vessel, a valve on the equalisation pipe is closed and high pressure gas is directed into the surge vessel by opening a valve on a gas pipe, forcing the liquid out of the surge vessel via a liquid outlet; and

when the liquid drops to a predetermined low level in the surge vessel, the valve on the gas pipe is closed, and the valve on the equalisation pipe is opened to equalise the pressure between the surge vessel and the separator.

Advantageously, this relieves the high pressure gas from the surge vessel.

Brief Description of Drawings

It will be convenient to further describe the present invention with respect to the accompanying drawings that illustrate possible arrangements of the invention. Other arrangements of the invention are possible, and consequently the particularity of the accompanying drawings is not to be understood as superseding the generality of the preceding description of the invention. Figure 1 is a schematic view of a conventional low pressure separation system

Figure 2 is a schematic view of a low pressure separation system according to an embodiment of the invention: (a) in filling mode; (b) in discharge mode.

Figure 3 is a schematic view of a low pressure separation system according to a further embodiment of the invention.

Figure 4 is a schematic view of a low pressure separation system according to a yet further embodiment of the invention.

Figure 5 is a schematic view of a low pressure separation system according to a still further embodiment of the invention. Figure 6 is a schematic view of a low pressure separation system according to a further embodiment of the invention.

Figure 7 is a schematic view of a low pressure separation system according to a further embodiment of the invention (a) illustrating the vent (b) indicating the dewpoint line of gas in a graph of temperature vs pressure.

Figure 8 is a schematic view of an embodiment of a low pressure separation system with a further separator. Figure 9 is a schematic view of an embodiment of a low pressure separation system with a further, three-phase, separator. Detailed Description

With reference to Figure 1, there is illustrated a conventional low pressure separation system 10 according to the prior art in which flow 12 from a low pressure well is sent to a production separator 14 for two-phase separation. The gas is vented from the facility via a small vent stack 16. Mixed oil and water are passed under level control from the production separator to the liquids export system comprising two 100% multi stage centrifugal pumps 18, 20, one of which runs at normal speed, and the other on standby mode, to pump the fluids to the production header 22 However, the conventional low pressure separation system 10 requires a number of utilities 2, include power generators 4 to drive the pumps 18, 20, and fuel supply tanks 8. These utilities are relatively expensive and require a lot of space which may not be available e.g. on a mobile platform. In addition, the utilities incur additional maintenance and operational costs. Furthermore the conventional system cannot handle slugs or sand, and all the gas is vented with no option for recovery.

With regard to Figures 2a-b, there is illustrated a schematic diagram of a low pressure separation system according to an embodiment of the invention, comprising a Low Pressure Separator 30 mounted on top of a Surge Vessel 32.

The flows of fluids 12 from the low pressure wells are routed to the Low Pressure Separator 30 via fluid inlet 13 for two-phase separation of gases and liquids. The liquid hold-up time (i.e. the time it takes to fill the separator with liquid) is typically around 5 minutes but may be sized for whatever hold-up time according to the application. All associated and flash gas is vented via a vent stack on top of the gas outlet line of the Low Pressure Separator. The Low Pressure Separator is fitted with a fluid inlet device 33 for receiving wellstream fluid, and a gas outlet device 34 to prevent entrainment of liquid to the vent.

Liquids from the Low Pressure Separator 30 flow into the Surge Vessel 32 via a downcomer pipe 36. The Surge Vessel 32 is a two phase separator designed to handle maximum liquids with a liquid hold-up time of typically approximately 10 minutes but may be sized for whatever hold-up time is required according to the application. The sizing of liquid hold-up in the separator section and the surge vessel section is such that there is sufficient liquid hold-up volume in the Separator to allow for accumulation of liquid and thus to allow the well to continue to flow whilst the liquids in the Surge Vessel is being displaced.

The downcomer pipe 36 routes liquids from the Separator 30 to the Surge Vessel 32 and is designed to prevent high pressure gas and the liquids already in the Surge Vessel from backflowing to the Separator when the Surge Vessel is being pressurized in the Discharge Mode (described below). This is achieved by installing a check valve in the downcomer pipe and the downcomer pipe terminating below the Low Level 38 of the Surge Vessel. Thus, backflow of liquids is prevented by the check valve, and backflow of gas is prevented by both the check valve and the liquid seal. As the gas phase is more susceptible to leakage through the check valve, the liquid seal provides double protection against such potential leaks.

The Surge Vessel is also provided with a high pressure (HP) gas source 50, and an equalization line 52 connecting the surge vessel 32 and separator 30 for equalizing the gas pressure in the surge vessel as described below. During the filling period, the valve 40 at the equalization line 52 is open and the valve 42 at the HP gas line 54 is closed. Once liquid 56 in the surge vessel reaches the High Level 44 (Level Alarm High, LAH), as indicated in Figure 2a, a signal is triggered which shuts the valve 40 at the gas equalization line and opens the valve 42 at the HP gas line. This causes the HP gas to force the liquid out of the surge vessel to the downstream production header 22. The closure of the valve 40 at the equalization line 54 and the check valve 46 on the downcomer pipe 36 prevents HP gas from entering the Low Pressure Separator 30. As the liquid level drops and reaches the Low level 38 (Level Alarm Low, LAL), as indicated in Figure 2b, a signal is triggered that opens the valve 40 at the equalization line 52 and closes the valve 42 on the HP gas line 54. This causes the HP gas in the Surge Vessel 32 to be depressurized to the operating pressure of the Low Pressure Separator 30 via a restriction orifice 48 on the equalization line 52. Liquid accumulated in the Low Pressure Vessel 30 then flows into the Surge Vessel 32 and the process is repeated.

The liquid hold up time in the Surge Vessel is approximately 10 minutes from LAH to LAL level (i.e. it takes around 10 minutes for the liquid level to go from LAL to LAH). It is expected that the liquid will be discharged from LAH to LAL within 2 minutes. During the Discharge Mode, liquid accumulates in the Low Pressure Separator for approximately 3 minutes taking into account of the time for valve switching and pressurization of the Surge Vessel. Therefore based on these assumptions, the cycle of filling and discharge takes place every 7 minutes.

The aforementioned timings are typical to illustrate the working principles of the system. The sizing of the vessels and thus the hold-up times in the vessels may be changed according to the application specific requirements and space availability provided the sizing of liquid hold-up in the separator and the surge vessel is such that there is sufficient liquid hold-up volume in the Separator to allow for accumulation of liquid and thus to allow the well to continue to flow whilst the liquid in the Surge Vessel is being displaced.

Under the Discharge Mode, a constant outflow rate of liquid is maintained by a restriction orifice 59 at the liquid outflow line 23. If the pressure of the production manifold is constant, the flow can be maintained constant with a pressure controller 57 at the surge vessel.

In many cases however, the pressure of both the HP gas source and the pressure of the outgoing production line may be varying. To ensure a constant pressure drop across the restriction orifice and thus a constant flow, the HP gas supply control valve 42 is regulated on differential pressure between downstream of the control valve 55 and downstream of the restriction orifice 23. This ensures constant flow of liquid in the Discharge Mode, irrespective of the actual operating pressure of the production manifold where the liquid is routed. A flowmeter is not required to measure and totalize liquid production rate for the system as is generally required on production facilities. As the volume of liquid displaced during each cycle of the Discharge Mode is fixed i.e. partial volume of Surge Vessel between high level setting and low level setting, The total liquid flow over a fixed duration is thus determined by totalizing the number of discharge (or filling) cycles over a fixed duration multiplied by the partial volume of the Surge Vessel between the vessel low level 38 and high level 44 settings. In addition, if interface level measurement is provided for the Surge Vessel, both oil and produced water flowrates can be evaluated. Based on the interface level indication prior to the Discharge Mode, the partial volumes (between low and high level settings) of each of the oil and water phase is determined for each cycle. The flow of each phase over a fixed duration is then determined by summing the respective volumes of each phase for the number of discharge (or filling) cycles performed for the fixed duration. In this manner, the system will be able to report full production data with respect to gas, oil and produced water flowrates. Note that a gas flow meter may also be provided at the gas outlet line 16 of the Low Pressure Separator.

In most cases the gas produced is routed to a pipeline or downstream compression. In some cases however, where for example the gas amount is insignificant and uneconomical to be recovered, the gas is flared or vented. A typical issue when the gas is vented is that condensation of the gas occurs due to ambient cooling of the warmer gas, resulting in liquid droplet rain descending to grade level on the platform. Conventionally this is mitigated by providing heat tracing on the vent line which has at most marginal benefits, as the heat tracing, (depending on how the vent pipe is routed) tends to vaporize the liquids at the low points of the vent pipe ,thus saturating whilst warming the gas as it goes up the vent stack. This results in the vent gas being almost at its dewpoint as it is vented and due to its elevated temperature above ambient, condensation of the vent gas in many occasions is worsened.

For this system the above mentioned issues are mitigated by stack vertically above the Low Pressure Separator and having a nozzle arrangement at the vent tip to allow approximately 0.2 bar pressure drop at the vent tip 92, as illustrated in Figures 7a-b. The former will ensure that any liquid drop-out at the vent will flow back into the separator while the latter will ensure that the gas exiting the vent nozzle will be in the superheated region of the phase envelope.

Figure 3 shows a Low Pressure Production Unit similar to that described previously but wherein the low pressure separator 130 is in a vertical configuration. This would be ideal for a gas majority field.

Another configuration is to have both the Low Pressure Separator and the Surge Vessel as vertical vessels and as integral units.

In this embodiment, the flow is maintained constant with a Differential Pressure (DP) transmitter 53 that maintains a predetermined differential pressure between the gas entering the surge vessel (pressure controller 57) and the pressure on the liquid outflow line (pressure controller 61). Typically the predetermined differential pressure is lbarg (200kPa) higher for the gas entering the surge vessel compared to the pressure on the liquid outflow line. It will be appreciated that this arrangement may be applied to the other embodiments described herein.

Figure 4 depicts a representation of a blowcase mechanism which utilizes a minimal volume of HP Gas (e.g. Gaslift) as motive fluid to drive or transport the liquids to the downstream production header at the required pressure. The gas lift pressure entering the Surge Vessel is reduced at the upstream PCV and restriction orifice.

Arrival characteristics of the flow 12 from a low pressure well are 0.5barg (150kPa) and 40°C. However, to reach the production header 22 the pressure must be increased by the pressure controller 61 to the backpressure subjected to the header 22, typically in the range of 5-10barg (600-1 lOOkPa) such as 7barg (800kPa), to overcome the pressure drop and reach the production platform.

The aforementioned embodiments use an onsite source of high pressure gas to increase the flow pressure to the production header, typically from a gaslift compressor. The gas is typically available at pressures ranging from 50 barg (5.1MPa) to 100 barg (lO. lMPa) at ambient temperatures (typically around 20°C) and may often be letdown in pressure to approximately 10 barg (l . lMPa). With this pressure letdown the Joule-Thomson effect will drop temperatures of the motive gas to as low as minus 30°C which is undesirable as it will result in issues such as low temperature metallurgy requirements, hydrates, and icing of produced water, due to the low temperature of the motive gas

However these issues can be mitigated by providing a heating coil in the surge vessel to heat the motive gas.

In the example illustrated, the characteristics of gas at point A are 60barg (6.1MPa) and 20°C. The temperature is low due to the cooling of the gas as it is transported in the subsea pipeline from the main processing platform, as typical seabed temperatures are approximately 20°C. However the pressure is too high for use in the surge vessel as it would result in a higher vessel pressure rating which results in larger size, footprint and cost, as well as increase in gas flow rate requirement and gas depressurising time. The problem is that reducing the pressure also lowers the temperature to a level too low for use in the surge vessel e.g. freezing or below.

As such the gas is reduced in pressure via a Pressure Control Valve 62 to 28barg (2.9MPa) and 5°C at point B. A higher pressure drop would further reduce the temperature and would cause issues such as hydrate formation, change in pipe material, etc.

The gas then flows through a heating coil 64 within the Surge Vessel 32 to heat up the gas to 30°C at pressure of 27barg (2.8MPa) at point C, as the operating temperature of the liquid within Surge Vessel is 40°C. The gas is further reduced in pressure as it passes through a restriction orifice 66 to lObarg (l . lMPa) with a corresponding temperature of 18°C at point D. Thus, gas at a suitable pressure of lbarg (200kPa) above the production header pressure pushes the liquid out to the production header as previously described herein. The restriction orifice at the liquid outlet line ensures that liquid is sent to the production header at the required pressure by providing the 1 barg (200kPa) pressure drop.

Figure 5 shows a further embodiment of the Low Pressure Production Unit according to the invention which involves partial or full recovery of the vented gas. The advantage of this system is that it reduces or eliminates the hydrocarbon emissions to the atmosphere and utilizes part of the compressed gas to drive the liquids from the surge vessel to the downstream production header, whereas in conventional systems the gas is vented. This makes the system independent and self-containable.

The system typically comprises a Low Pressure Separator 30, a Surge Vessel 32 and a Compressor 70. The compressor may be a self-contained Integral Gas Engine Compressor including a compressor discharge air fin cooler. It will be appreciated that any other compressor types suitable for the service may be used. The separated gas is sent to the compressor 70. Excess gas (if any) is sent to the vent 116. Approximately 0.1-0.2 MMscfd from the compressor discharge (depending on the capacity of the system and the HP gas requirement) is used 72 as motive fluid to drive the liquids to the production header 22. The balance of compressed gas will be routed 74 to the liquid discharge line downstream of the Surge Vessel.

In case there is a compressor failure, all the gas will be vented and a backup HP Gas line (Gas Lift) 50 is provided to drive the liquids to the production header 22. Figure 6 shows a Low Pressure Unit with Slug and Sand Handling capability 80, comprising a Slug Handling device 82, a stilling well 84, sand handling device 86, etc.

The Slug Handling device 82 comprises a horizontal expanded pipe or vessel, capable of gas and liquid separation of fluid (such as FWS fluid), that has a Gas Bypass Line 88 at its upper section and is in operational connection with a Stilling Well 84 at its lower section. The Slug Handling device may be a conventional separator or a pipe piece without internals that is positioned horizontally with a slight tilt (approximately 10 degrees from the horizontal) to enable the liquid to flow effortlessly into the Stilling Well even with the presence of slug. The configuration of the Slug Handling Device 82 simplifies the controls associated with conventional slug catchers as it eliminates the need for liquid level control valve and thus improves the reliability of the system. In operation, fluid such as full wellstream (FWS) fluid is first routed to the slug handling device 82 for gas and liquid separation after which the liquids, including liquid slugs, are diverted into the Stilling Well and the gas is routed to the Gas Bypass Line 88. The height of this Stilling Well 84 is predetermined to provide sufficient liquid head to overcome pressure drop of the downstream system. The horizontal position of the slug handling device ensures that the presence of slug does not increase liquid head significantly, thus minimizing the incremental liquid head. Unlike the conventional slug catcher, the insignificant rise of liquid head and the constant flow of liquid to the separator even with the arrival of large liquid slugs maintains the pressure drop of the entire system.

Since sand is occasionally present in the incoming fluid, a sand trap 86 is installed at the bottom of the Stilling Well 84 where additional valves will be added to periodically remove the sand. There are two methods considered in this system for sand separation; gravity settling of the sand and cyclonic sand removal device.

The gas from the gas bypass line 88 is mixed with the liquid line 90 downstream of the Stilling Well before being sent to the Low Pressure Separator 30.

Figure 8 shows a low pressure separator 30 with surge vessel 32 combined with a further (first-stage) separator 94. The first stage separator operates at a higher pressure than the low pressure unit 30 which operates at atmospheric pressure to enable two phase separation and crude stabilization.

In operation, fluid such as FWS fluid 12 is initially routed to the first stage separator for gas and liquid separation whereby the liquids are diverted a low pressure unit 30 via outlet channel 96 while the gas is directed via outlet channel 98 to either a compression system or directly to the flare/vent system 216 depending on the application. The low pressure separator 30 and surge vessel 32 function to stabilize the liquid before it is sent to the export pipeline using the high pressure gas. The high pressure gas used to pressurize the liquids is tapped of from the first stage separator via channel 150.

In applications where oil and water separation is required, the further separator is a three-phase separator 194 as shown in Figure 9. The separated oil is sent to the low pressure separator 30 while the water is sent for treatment in the produced water treatment system 97 before being discharged 99.

Therefore the invention is a compact, simplified and independent system for separation or crude stabilization that does not require an external power supply, and is thus suitable for wellhead platforms. The system allows gas/liquid separation to be undertaken on the wellhead platform itself instead of on a central processing platform (CPP) or Floating Production, Storage & Offloading (FPSO) platform. This significantly reduces the export pipeline cost as the pipeline is designed only for liquids and at a much lower design pressure. Furthermore, only a Floating Storage & Offloading (FSO) platform is required instead of an FPSO as the gas separation has already been undertaken on the wellhead platform.

It will be appreciated by persons skilled in the art that the present invention may also include further additional modifications made to the device which does not affect the overall functioning of the device.