Patent Application
20220154080
The invention relates to a system for recovering natural gas liquid from a low pressure source at low temperatures.
A natural gas stream often contains light hydrocarbons. Natural gas liquids (NGL) is the general term for liquids extracted from the natural gas stream (ethane and heavier products) and within this liquefied petroleum gas (LPG) is the term used to refer to extracted liquids where the main components are propane, n-butane and iso-butane.
Low pressure hydrocarbon gases particularly associated gas from oil and gas production facilities pose significant challenges for operators worldwide as typically the facilities are stranded with lack of infrastructure to route the produced gas. In addition, being at low pressure, the cost associated with the additional compression facilities very often makes it uneconomical to monetize the gas. Decline in well pressures of mature fields also makes it challenging to install additional compression facilities to boost pressure of produced gas. As a result, in many facilities, the associated gas produced is utilized as fuel gas while the balance is being flared. The often overlooked feature of low pressure gas from producing wells is that being at low pressure the vapor liquid equilibrium of the production fluid favours higher content of C4+ components in the gas phase, resulting in richer gas being used as fuel gas or flared. This results in significant amount of C4+ components which can be recovered as condensates being flared. For low pressure gas, it is estimated that for each MMscf of gas, recoverable condensates are in the order of 30 bbls to 100 bbls (MMscf=millions of standard cubic feet; bbls=barrels).
In addition, recovery of these condensates from the gas stream is expected to reduce CO2 emissions due burning as fuel gas or flaring by up to 30% which is in line with the recent Paris Agreement within the United Nations Framework Convention on Climate Change dealing with GHG (Green House Gas) emission mitigation and adaptation starting in 2020 by decreasing the carbon footprint in the flared gas. An ambitious target has been set to curb the increase in global average temperatures to well below 2° C. above pre-industrial levels and to pursue efforts to limit this to 1.5° C. and ultimately net-zero GHG emissions by 2100.
Removal of NGLs from natural gas is desirable for the following reasons:
Depending on the requirement, hydrocarbon dew point control packages or cryogenic plants can be used to extract NGL from gas streams. Hydrocarbon dew point refers to the temperature at any pressure range or the pressure at any temperature range where hydrocarbons begin to condense from the gas mixture.
There are various types of Hydrocarbon Dew Point Control (HCDPC) units available in the market to extract NGL (Natural Gas Liquid) from a natural gas stream (associated or non-associated gas). The following is a brief review of the methods used to reduce hydrocarbon dew point in gas streams. As these processes are well known, for the sake of brevity, process descriptions are not included as they are well covered in the literature:
1) Low Temperature Separation (LTS)
If the raw gas is at high pressure, the removal of hydrocarbons can be accomplished by refrigeration obtained through the expansion of gas by means of a Joule-Thomson (JT) valve. Injection of glycol is required to prevent the formation of hydrates. However, if the raw feed gas pressure is low, condensate recovery is poor due to the small change in pressure achievable and hence the low JT effect. In addition, recovery of the glycol requires additional apparatus, such as a reboiler, a condenser and a reflux column. External utilities like hot oil and cooling water are required to operate both the reboiler and condenser.
2) Turbo-Expander Dew Point
This process is a variation of the LTS process in which the energy pressure held in the gas is used to move an expander turbine, which in the isoentropic expansion generates refrigeration and exports mechanical work. This work is used to drive a compressor to partially restore the gas pressure. Here again, the raw feed gas pressure has to be relatively high to generate adequate chilling for NGL recovery.
3) Refrigeration
The most common method used for gas dew point control is mechanical refrigeration. This technology is suited especially when pressure is not available to be used to self-refrigerate the gas. Mechanical refrigeration system however are bulky and expensive which includes compression equipment and power consumption.
4) Adsorption
This method uses adsorbents like silica gel that have the capability to adsorb heavy hydrocarbons. The system is set up in multiple beds cycling in short operating cycles of adsorption, desorption, of approximately 20 minutes. This method was well used in the 60s and early 70s and was gradually abandoned. Recently, new adsorption materials are making this method economically attractive for certain project applications. However, these adsorbent again typically operate effectively with higher feed gas pressures with regeneration and recovery of NGLs being undertaken at lower pressure and higher temperatures.
5) Static Expansion Devices
The Vortex-Tube Device and the Supersonic Tube technology. For these devices also require high pressure gas for the system to generate adequate chilling of the gas stream for NGL extraction.
6) Membranes
Silicon rubber membranes, for example, have the ability to permeate heavy hydrocarbons rather than light. This makes them a potential candidate for dew point control. However, these systems require some amount of pre-treatment to protect the membranes and compression of the permeate stream to minimize NGL losses. In addition, to be economically viable, these systems require relatively high inlet gas pressures.
As can be seen from the preceding discussions, whilst there are many NGL recovery systems by means of various types of HCDPC units, these are only really suitable for feed gas streams that operate at relatively high pressures. In addition, the refrigeration systems that can handle low pressure feed gas streams, are very bulky, complex and costly, making them economically not viable for many low pressure applications.
There are many facilities where natural gas is produced at low pressures of between 3 to 20 barg and these include:
The installation of HCDPC units for NGL extraction from low pressure natural gas has both the economic and environmental benefits as the main polluting components from the off gas are separated and the value added products like lean natural gas and NGL are produced. The burning of methane rich gas produced from this unit without polluting and soot forming components is beneficial from an environmental point of view.
While it is noted that NGLs constitute a small fraction of natural gas from wells and various other sources, however its contribution towards greenhouse gas emissions is significant when the gas is burnt as fuel gas or flared. Typically, CO2 emissions can be reduced by approximately 30% with extraction of NGLs from the gas. It is more significant for low pressure natural gas as the vapour liquid equilibrium favours vaporization of heavy ends into the gas phase resulting in higher content of NGLs in the gas stream. Ironically though, it is the low pressure natural gas streams that are typically disposed as fuel gas or flared as is uneconomical to recover.
The above clearly indicates that the Industry is presently striving for a new flexible, reliable and a safe process that can cost effectively extract NGLs from low pressure natural gas.
Utilising a JT Valve located downstream of the Cold Separator helps to maximise liquid drop-out from the associated gas stream for low operating pressures of the associated gas. However, at operating pressures below the cricondentherm, the temperature and/or pressure may have to be reduced more significantly to cause liquid drop-out (required for the separator to work), but as a result hydrates may form and cause blockages. An aim of the invention therefore is to provide a system for recovering NGLs which operates effectively with a low pressure source of natural gas.
In an aspect of the invention, there is provided a system for recovering natural gas liquid from a gas source, comprising:
Advantageously the upstream compression of the gas allows a larger cooling effect over the heat exchanger due to the greater pressure drop (the JT effect) and thus condensate recovery is improved.
Advantageously the antifreeze agent prevents blockages by ensuring hydrates do not form, and self-regenerates within the system to prevent loss thereof
In one embodiment the antifreeze agent is monoethylene glycol (MEG). In a further embodiment the antifreeze agent is monopropylene glycol (MPG).
In one embodiment the evaporant is water. However it will be appreciated that other liquids e.g. propane may be used as a suitable evaporant depending on the temperature and pressure conditions.
In one embodiment the separator is provided with a heater for de-emulsifying the liquid in the separator. Typically 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.
The bottom section of the cold separator will collect both the recovered condensate and rich MEG. These two liquids are immiscible and will settle down in the bottom section of the separator to form two distinct phases for separation. However, under cold conditions (<15° C.), a MEG/Condensate emulsion forms. The separation of recovered condensate and MEG is very poor due to high viscosity. Emulsion formation is favoured by low temperature (<15° C.) and high MEG concentration. By increasing the liquid temperature above 15° C. the viscosity is reduced and the emulsion is broken down.
The configuration is analogous to the kettle reboiler, where the liquid (recovered condensate and MEG-water mixture) contained in the bottom of the cold separator is withdrawn and warmed up to a higher temperature (>15° C.). The fluid is then recycled back to the cold separator where the separation for recovered condensate and MEG-water mixture takes place.
In one embodiment the expansion means is a Joule-Thomson valve. In another embodiment the expansion means and compression means are provided by respective sides of a turbo expander. In yet another embodiment, the expansion means is a Static Expansion Device such as a Vortex-Tube Device or Supersonic Tube technology.
Typically the expansion means reduces the pressure of the gas and as a result reduces the temperature thereof.
In a conventional system the JT valve or other expansion means is upstream of the separator. When the gas source is at high pressure a large pressure drop can take place at the JT valve resulting in a large reduction in temperature. However, for low pressure gas sources only a small pressure drop can take place, so the reduction in temperature is smaller. Thus in a conventional system adequate chilling for condensate recovery cannot be generated from low pressure gas sources.
However, in the present invention the JT valve or other expansion means is downstream of the separator. The condensate recovery is done at the supplied raw gas pressure (or higher followed by the compression in the turbo-expander) before the isentropic expansion takes place via the JT valve or other expansion devices downstream of the separator to attain the cold energy. This configuration will help to move the operating point of the cold separator to a higher quality line value for better liquid dropout. Liquid evaporant such as water is injected to increase the enthalpy of the expanded-chilled-dry gas, reducing the temperature of the raw feed gas further by the evaporative cooling means thereof to achieve the required low temperatures for a more effective and higher condensate recovery compared to a conventional system even for low pressure gas sources.
In one embodiment the cooling means is a seawater or air cooler, which does not significantly change the pressure of the fluid.
In one embodiment 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.
In one embodiment the gas from the second outlet may be flared off.
In one embodiment the liquid separated in the separator comprises an aqueous part and a condensate. Typically the condensate comprises hydrocarbons (including NGL), which are directed to an outlet for further treatment. Typically the aqueous part comprises the liquid agent. Thus the hydrocarbons are separated from the aqueous liquid by de-emulsification.
In one embodiment 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.
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.
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.
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.
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.
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.
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.
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
In more detail:
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.
With regard to
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.
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).
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.
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.
5. With further reference to
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).
7. The gas from the recovery vessel 240 (V-1001) is then routed to the downstream gas facilities 218 .
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.
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.
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.
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).
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.
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.
MEG is the preferred antifreeze agent because:
Nevertheless, it should be appreciated that other agents could be used, such as monopropylene glycol (MPG).
With regard to
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.
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.
| Number | Date | Country | Kind |
|---|---|---|---|
| PI2019001292 | Mar 2019 | MY | national |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/MY2020/050014 | 3/13/2020 | WO | 00 |
