SYSTEM FOR RECOVERING NATURAL GAS LIQUID FROM LOW PRESSURE SOURCE AT LOW TEMPERATURES

Abstract

A system for recovering natural gas liquid from a gas source, comprising compression means (206) for increasing the temperature and pressure of the fluid from the gas source, cooling means (230) for cooling the fluid from the compression means, a gas/gas heat exchanger (204), fluid from the gas source flowing from a first inlet to a first outlet; at least one separator (208) for receiving the fluid from the first outlet of the gas/gas heat exchanger (204) and separating liquid from the gas, the gas from the separator being directed to expansion means (206) for reducing the temperature and pressure of the gas, the aqueous part of the liquid from the separator and/or the gas from the expansion means being directed to the gas/gas heat exchanger (204) where it flows therethrough from a second inlet to a second outlet for cooling the fluid flowing between the first inlet and first outlet, wherein injection means are provided between the cooling means and the gas/gas heat exchanger for saturating the gas with a liquid agent, wherein the liquid agent comprises an evaporant and an antifreeze agent; and a recovery vessel (240) is provided downstream of the second outlet, the antifreeze agent being recovered therein for injection into the fluid from the gas source upstream of the first inlet.

Claims

1. A system for recovering natural gas liquid from a gas source (210), comprising: compression means (206) for increasing the temperature and pressure of the fluid from the gas source; cooling means (230) for cooling the fluid from the compression means; at least one gas/gas heat exchanger (204), fluid from the cooling means flowing from a first inlet to a first outlet; at least one separator (208) for receiving the fluid from the first outlet of the gas/gas heat exchanger (204) and separating liquid from the gas; the gas from the separator being directed to expansion means (206) for reducing the temperature and pressure of the gas; the aqueous part of the liquid from the separator and the gas from the expansion means being directed to the gas/gas heat exchanger (204) where they flow therethrough from a second inlet to a second outlet for cooling the fluid flowing between the first inlet and first outlet; wherein injection means are provided between the cooling means and the gas/gas heat exchanger for saturating the gas with a liquid agent; characterised in that the liquid agent comprises an evaporant and an antifreeze agent; and a recovery vessel (240) is provided downstream of the second outlet, the antifreeze agent being recovered therein for injection into the fluid from the gas source upstream of the first inlet wherein the expansion means and compression means are provided by respective sides of a turbo expander, and wherein the aqueous part of the liquid from the separator and the gas from the expansion means is warmed by the gas/gas heat exchanger as they flow from the second inlet to the second outlet such that the evaporant is absorbed by the gas thereby increasing recovery of the antifreeze agent.

2. (canceled)

3. The system according to claim 1 wherein the evaporant is water.

4. The system according to claim 1 wherein the antifreeze agent is monoethylene glycol or monopropylene glycol.

5. The system according to claim 1 wherein the separator is provided with a heater for de-emulsifying the liquid in the separator.

6. The system according to claim 1 wherein the heater is located in a separate vessel which receives liquid from the bottom of the separator, warms the liquid, then returns the liquid to the separator.

7. The system according to claim 1 wherein the cooling means is a seawater or air cooler, which does not significantly change the pressure of the fluid.

8. The system according to claim 1 wherein the gas/gas heat exchanger comprises a series of heat exchangers and/or a multi-section heat exchanger comprising independent compartments within the same closure.

9. The system according to claim 1 wherein the liquid separated in the separator comprises an aqueous part and a condensate, the condensate comprising hydrocarbons which are directed to an outlet for further treatment, the aqueous part comprising the liquid agent.

10. The system according to claim 1 wherein the condensate from the separator is spiked into a surge vessel, provided for separating gas, water and oil at low pressure, the condensate being directed through a column of material through which gas from the surge vessel passes in the opposite direction to strip off C3- components from the condensate and recover heavy ends from the gas.

Description

BRIEF DESCRIPTION OF DRAWINGS

[0060] 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.

[0061] FIG. 1 is a graph of water saturation of HC gas against pressure at different temperatures.

[0062] FIG. 2 illustrates a known NGL recovery system.

[0063] FIG. 3 illustrates an NGL recovery system according to an embodiment of the invention.

[0064] FIG. 4 illustrates a cold separator with a heater for emulsion treatment.

[0065] FIG. 5 illustrates a system for condensate spiking.

DETAILED DESCRIPTION

[0066] Hydrocarbon Dew Point Control (HCDPC) of low pressure gas uses the concept of evaporative cooling, coupled with a gas expansion device which may either be a JT Valve, Static Expansion Devices or a Turbo-Expander, to chill the gas stream to condense and remove the heavier hydrocarbon components (NGLs) from the natural gas stream.

[0067] Evaporative cooling is the addition of water vapor into gas that is water dew pointed, which causes lowering the temperature of the gas. The energy needed to evaporate the water is taken from the gas in the form of sensible heat, which reduces the temperature of the gas, and converted into latent heat, the energy present in the water vapor component of the gas, whilst the gas remains at a constant enthalpy value. This conversion of sensible heat to latent heat is known as an adiabatic process because it occurs at a constant enthalpy value. Evaporative cooling therefore causes a drop in the temperature of gas proportional to the sensible heat drop and an increase in humidity (or water vapor content) of the gas proportional to the latent heat gain.

[0068] A simple example of natural evaporative cooling is perspiration, or sweat, secreted by the body, evaporation of which cools the body. The amount of heat transfer depends on the evaporation rate, however for each kilogram of water vaporized 2257 kJ of energy at 35° C. are transferred. The evaporation rate depends on the temperature and humidity of the air, which is why sweat accumulates more on humid days, as it does not evaporate fast enough.

[0069] The evaporative cooling medium as used in this invention is typically fresh (demineralized) water but may be any medium that achieves vaporization in the gas stream to convert sensible heat in the gas to latent heat of vaporization of the medium.

[0070] It is also noted that the description of the system as detailed in this document are mainly applicable for low pressure systems, where typically water is used as the evaporative medium, the concept as detailed here may also be used for high operating pressure systems with a suitable alternative evaporative medium.

[0071] In the case where water is used as an evaporative medium, this concept is particularly suited for low pressure gas stream which does not have enough upstream pressure to chill the gas on expansion through either a JT Valve, Static Expansion Devices or a Turbo-Expander (or a combination). It is noted that, typically on expansion of low pressure gas, the water dew point of the expanded (lower pressure) gas is significantly lowered. This is because at low pressures (around less than 20 barg), the saturation water content of gas increases exponentially as the gas pressure is lowered (at constant temperature). This fact is demonstrated in FIG. 1.

[0072] FIG. 2 illustrates an NGL recovery system 102 which comprises a gas/gas heat exchanger 104, a separator 108, and a JT valve 106 located downstream of the separator 108. In addition, a liquid injection system 120 is provided downstream of the JT valve to increase the enthalpy of the expanded-chilled-dry gas, reducing the temperature of the raw feed gas further by the evaporative cooling mean thereof could achieve the required low temperatures for an effective and higher condensate recovery compared to a conventional system even for low pressure gas sources 110. The separator provides gas, NGL and water to respective outlets 116, 112, 114, and the water therefrom may be used as a water supply for the liquid injection means. The lean gas is directed towards the flare point 118.

[0073] In more detail: [0074] Feed gas 110 from the upstream production facility is routed to a Gas-Gas Exchanger 104. The hot feed gas stream is chilled by the cold gas stream from the JT-Valve 106. Other gas expansion device could be static expansion device or turbo-expander. [0075] The chilled feed gas stream is then routed to the Cold Separator 108 where 3 phase gas-oil-water separation is undertaken. [0076] The separated gas is routed to the JT-Valve 106, the oil phase to the downstream NGL processing facilities 112 and the aqueous phase 114 is re-injected 120 into the gas stream downstream of the JT-Valve 106. [0077] The expanded and chilled gas from the JT-Valve 106 is then routed to the Gas-Gas Exchanger 104 for heat cross exchange to chill the incoming feed gas stream. Prior to routing to the Gas-Gas Exchanger, condensed water from the Cold Separator with make-up of fresh water is injected 120 into the gas stream from the JT-Valve. In addition, the heated and water saturated gas downstream of the Gas-Gas Exchanger may be cooled and the condensed water removed and recycled for injection upstream of the Gas-Gas Exchanger. This will potentially avoid the need for make-up Fresh Water. [0078] At the Gas-Gas Exchanger 104, the chilled gas increases in temperature (i.e. is superheated) by the incoming hot feed gas stream and simultaneously evaporation of the injected aqueous medium in the cold side of the exchanger occurs. To maximize the cooling duty of the exchanger (and thus minimize the hot feed gas stream outlet temperature), the injection rate of the condensed and fresh water make-up is set to saturate the cold side gas at its outlet conditions. An excess amount may be injected beyond its saturation point to ensure that TDS content of the aqueous phase does not exceed its saturation point to avoid solid deposition at the Gas-Gas Exchanger 104. [0079] From the Gas-Gas Exchanger 104, the heated gas stream is routed to the downstream gas facilities.

[0080] As the JT Valve is located downstream of the Cold Separator, liquid drop-out from the associated gas stream for low operating pressures of the associated gas is maximised. This is due to the fact that the operating point will move toward a higher quality line within the phase envelope.

[0081] With regard to FIG. 3, an embodiment of the invention is illustrated which addresses this issue. The following describes the configuration of the system, herein referred to as LP-CRS:

[0082] 1. Feed gas 210 from the upstream production facility, which may have a temperature in the range of 30-55° C. and pressure of less than 10 barg, is routed to the compressor side of the turbo-expander 206 (KT-1000) which is driven by the turbo-expander. The gas is then compressed thereby increasing the temperature to around 70-100° C. and pressure of around 14-15 barg, before being routed to the compressor discharge cooler 230 (E-1000) where it is cooled by seawater or air to around 40° C. without significant reduction in pressure.

[0083] 2. The gas is then routed to a single pass multi-section heat exchanger 204 (E-1001) where it is gradually chilled to the temperature within the approximate range of −20° C. to −45° C. The low pressure cool gas leaving the turbo-expander 206 (KT-1000) and cold fluid leaving the Cold Separator 208 (V-1000) may be used as cooling medium for heat exchanger 204 (E-1001).

[0084] 3. A glycol-based anti-freeze agent such as Monoethylene Glycol (MEG) from Recovery Vessel 240 (V-1001) is injected 242 into the gas stream leaving the cooler 230 (E-1000), prior to the heat exchanger 204 for hydrate inhibition and as an anti-freeze agent to enable the system to perform at lower temperatures in order to maximize condensate recovery.

[0085] 4. The cold gas stream 244 from the heat exchanger 204 (E-1001) is then routed to the Cold Separator 208 (V-1000) for three phase separation. Recovered condensate 246 is stabilized first before spiked into the existing Surge Vessel in the processing facility. Cold lean gas is routed to the expansion side of the turbo expander 206. The cold condensed water 248 with the glycol-based anti-freeze agent is injected into the low pressure cool gas stream 250 leaving the expansion side of the turbo expander 206 (KT-1000). The injection of condensed water into this cool gas stream, now at a temperature of around −85° C. to −90° C. and pressure of about 2-3 barg, enables further cooling of the gas stream entering the cold separator 208 (V-1000) to be achieved via the heat exchanger 204 (E-1001) and at the same time the glycol-based anti-freeze agent presence in the condensed water prevents hydrate and ice formations during the evaporative cooling. The MEG concentration shall be maintained between 70% to 75 wt %, to avoid freezing inside the Cold Separator 208 and downstream of the turbo-expander 206.

[0086] 5. With further reference to FIG. 4, the separator 208 is fitted with appropriate internals for efficient three-phase separation and a heater 252 in a side vessel 262 through which the liquid is circulated by pump 260 for emulsion treatment. The emulsion forms due to the low temperature of the fluid as it enters the cold separator 208, but can be heated to above 15° C. through a tap-off line from the discharge of the compressor side of the turbo-expander 206 (KT-1000), at which temperature the oil separates from the water (and aqueous MEG) and floats on top thereof where it can tapped off by as condensate 246.

[0087] 6. The cold fluid and anti-freeze agent from the separator 208 which is passed through the heat exchanger 204 (E-1001) is partially heated thereby to a temperature of around 35° C. without much drop in pressure to vaporize some amount of water from the MEG in order to obtain fairly lean MEG solution (80-85 wt %) in the recovery vessel 240 (V-1001).

[0088] 7. The gas from the recovery vessel 240 (V-1001) is then routed to the downstream gas facilities 218 .

[0089] 8. Fresh MEG may be added in the recovery vessel 240 from a lean source 256 whereafter the lean MEG is routed back for injection 242. The pressure of the MEG is increased to around 15barg using a pump 258 to ensure that it can be injected i.e. it is at a higher pressure than the gas stream at the injection point.

[0090] Advantageously the LP-CRS system is supplied with feed gas at a pressure lower than its Cricondentherm pressure. In contrast to the conventional approach, the isentropic expansion takes place downstream of the cold separator to provide the chilling, resulting in a higher liquid drop-out from the gas. This is because the operating point has moved vertically deeper into the phase envelope (toward a higher quality line), thus resulting in higher amount of condensate recovery from the gas.

[0091] The expansion is paired with the evaporative cooling method by re-injecting separated condensed water to expanded-chilled-dry gases which is passed to an inlet gas-gas compact heat exchanger to achieve a deeper chilling. The operating point will move further horizontally deep into the phase envelope as the temperature is getting lower.

[0092] The LP-CRS system is designed in such a way that to have the operating point move deeper into the phase envelope, by chilling the gas at a higher pressure (<the Cricondentherm pressure).

[0093] It will be appreciated that in the current invention the MEG recovery is self-contained and integrated with the LP-CRS system. MEG recovery takes place downstream of the lean gas stream and only needs a recovery vessel with an optional condenser to prevent MEG loss—advantageously no reboiler is required, and there is no need for an external cold utility for the condenser. The recovered MEG water mixture has a sufficiently high MEG content (80 to 85 wt %) to work as a hydrate inhibitor.

[0094] Furthermore the current invention will see the MEG recovery system operating at a much lower temperature (<50° C.). This will mitigate the MEG degradation and fouling issue encountered by the conventional MEG recovery system which operate at high temperature (approx. 160° C.). MEG degradation temperature (163° C.) is based on reboiler heat flux of 12,000 BTU/ft2 which equates to a film temperature of 215° C.

[0095] MEG is the preferred antifreeze agent because: [0096] It has the lowest molecular weight in comparison with other glycols, and thus less amount is needed for the same extent of anti-freezing; [0097] It has lower viscosity than the other glycols at the same operating temperature, which has a higher pumpability at low temperature; [0098] It has an appreciably lower freezing point of its water solution compared to other glycols, which is suitable to act as hydrate inhibitor at deep cold condition; and [0099] It is less soluble in the condensed hydrocarbons than the other glycols, which will see a minimum loss of MEG in the recovery process.

[0100] Nevertheless, it should be appreciated that other agents could be used, such as monopropylene glycol (MPG).

[0101] With regard to FIG. 5, the condensate 246 that is recovered from the LP-CRS is spiked back into the existing Surge Vessel 264, through a pipe-piece stabilization column 266 fitted with packing 268. The surge vessel 264 is a three phase separator for separating gas 272, water 274 and crude oil 276, operating at low pressure (e.g. 0.5 barg), receiving oil output 270 from an upstream separator operating at higher pressure (e.g. 10 barg). Therefore, the condensate will be stabilized through this pipe-piece as it passes down therethrough while the gas 272 from the surge vessel moves up therethrough, and commingles with the crude oil prior to storage in FPSO or exporting to pipeline. The pipe piece stabilization column strips off most of the lighter C3− components from the condensate and at the same time the condensate recovers a small amount of heavy ends from the gas leaving the existing Surge Vessel.

[0102] Besides that, spiking crude into crude oil improves the crude API gravity as well as improves flow assurance issue for fields facing with wax issues. The condensate that is recovered from the flare acts as a wax inhibitor which reduces the wax fraction in the crude.

[0103] It will be appreciated by persons skilled in the art that the present invention may also include further additional modifications made to the system which does not affect the overall functioning of the system.