Patent Application
20240400922
Natural gas produced from a reservoir contains an amount of water and salt, as well as heavier hydrocarbons. Following production at a wellhead, the produced natural gas may undergo gas-oil separations to separate the natural gas produced into a raw natural gas, a raw condensate, and a produced water stream. The condensate typically includes a mixture of light and heavy hydrocarbons, water, and salts.
Prior to transporting the condensate for downstream processing, the condensates are typically stabilized, removing light (gaseous) hydrocarbons. The condensates from the gas-oil separation plant are fed to a stabilizer system, in which any dissolved light hydrocarbons are removed. One of the initial vessels in typical condensate stabilization systems is a stabilizer feed drum, receiving the raw condensate from the upstream gas-oil separations.
Stabilizer feed drums are used to maintain a supply volume of oil and condensates to be stabilized. Stabilizer feed drums are often employed as a conventional gravity separator, providing for some separation of free water from the oil prior to stabilization. However, as a conventional gravity separator, upsets in upstream gas-oil separations resulting in slugging of free or emulsified water into the stabilizer feed drum may result in incomplete water separations in the stabilizer feed drum. These upsets can thus result in a quantity of water carrying over into the stabilizer and may further result in salt fouling of stabilizer reboilers. The salt fouling of the reboilers is problematic, as it may result in production of off-spec product due to water or salt content as well as operational down time. Further, due to the potential for salt fouling, stabilizer column bottom temperatures may be limited, such as to around 230° F., which can significantly impact the TVP (true vapor pressure) of the resulting condensate product.
In one aspect, embodiments disclosed herein relate to a process for stabilizing a condensate feed and mitigating fouling. The process includes providing a raw condensate feed to a stabilizer feed drum, the raw condensate feed comprising hydrocarbons and greater than 2000 ppmv free and emulsified water. The free and emulsified water has greater than 40000 ppm salt (TDS). The stabilizer feed drum comprises a feed inlet, a water outlet, a vapor outlet, an unstabilized condensate outlet, and liquid-liquid separation parallel plate pack internals. The raw condensate flows from the feed inlet through the liquid-liquid separation parallel plate pack internals to separate the raw condensate and to form a water phase and an oil phase. The resulting oil phase comprises less than 500 ppmv free and emulsified water. The water phase is recovered via the water outlet and the oil phase is recovered via the unstabilized condensate outlet. The process then includes feeding the oil phase from the unstabilized condensate outlet to a stabilizer system. The stabilizer system includes a stabilizer column and one or more reboilers. In the stabilizer system, the oil phase is separated into a vapor and a stabilized condensate. The process includes operating the stabilizer column at an overhead pressure of greater than 12 bar gauge (175 psig) and a bottoms temperature of greater than 135° C. (275° F.), recovering the vapor as an overhead vapor from the stabilizer column and recovering the stabilized condensate as a bottoms from the stabilizer column. The stabilized condensate has a true vapor pressure (TVP) of less than 3.8 bar gauge (55 psig).
In another aspect, embodiments herein relate to a condensate stabilization system for stabilizing oil with minimal fouling. The condensate stabilization system includes a condensate feed system for providing a condensate feed, the condensate feed comprising hydrocarbons and greater than 2000 ppmv free and emulsified water, the free and emulsified water having greater than 40000 ppm salt (TDS). The condensate stabilization system also includes a stabilizer feed drum for receiving the condensate feed. The stabilizer feed drum is a vessel having a feed inlet, a water outlet, a vapor outlet, a condensate outlet. The stabilizer feed drum contains liquid-liquid separation parallel plate pack internals configured to separate the condensate feed into a water phase and an oil phase, the internals configured to produce an oil phase comprising less than 100 ppmv free or emulsified water. The stabilizer feed drum also contains a weir configured for separating the water phase from the oil phase and for directing the water phase to the water outlet and the oil phase to the condensate outlet. The condensate stabilization system further includes a stabilizer system including a stabilizer column and one or more thermosiphon reboilers. The stabilizer column includes an inlet for receiving the oil phase from the condensate outlet, a vapor overheads outlet, and a stabilized condensate bottoms outlet. The stabilizer system is configured for separating the oil phase into a vapor and a stabilized condensate. The condensate stabilization system also includes a control system configured for operating the stabilizer column at an overhead pressure of greater than 12.4 bar gauge (180 psig) and a bottoms temperature of greater than 137° C. (280° F.).
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
In one aspect, embodiments disclosed herein relate to systems and processes for condensate stabilization. In another aspect, embodiments disclosed herein relate to a condensate stabilization system having components to mitigate (minimize or eliminate) fouling and processes for the operation thereof. In yet another aspect, embodiments disclosed herein relate to processes for operating condensate stabilization systems herein to both mitigate fouling and provide a stabilized condensate having an improved quality.
Produced natural gas may be sequentially depressurized in a gas-oil separation plant to separate the gaseous hydrocarbons (e.g., methane and ethane, or methane, ethane, and propane) from the heavier hydrocarbon molecules, or condensate. Following separation of the produced natural gas to recover the gaseous hydrocarbons, the remaining unstabilized condensate may include heavier hydrocarbons (C3 or C4 up to C7 to C12 hydrocarbons, for example) along with dissolved gases (CO2, H2S, etc.) and dissolved gaseous hydrocarbons (methane and ethane). As noted above, the raw condensate as produced from the gas-oil separation plant may also include formation water and salts, or brine, whether due to process upsets or otherwise entrained with the raw, unstabilized condensate. The water may be present as free water or emulsified water. The raw, unstabilized condensate is then forwarded to a stabilization system for separation of any remaining water, salts, dissolved gases and dissolved gaseous hydrocarbons from the heavier hydrocarbons, producing a stabilized condensate.
During typical operations, the gas-oil separation plant may result in a raw condensate stream having minimal water and salts. Upstream process upsets, however, may result in slugs of brine being forwarded along with the unstabilized condensate to the condensate stabilization system. For example, a process upset in a high-pressure separator, a low-pressure separator, or associated equipment used in the gas-oil separation plant may result in a large amount of water and the associated salts being forwarded with the unstabilized condensate. While undesirable, such processing hiccups may result in the unstabilized condensate having, for example, a free and emulsified average water content of 2000 ppmv to 20000 ppmv or greater (0.2 vol % to 2.0 vol % or greater), such as 5000 ppmv or greater, where the water may have an average salinity of 80000 ppm (total dissolved solids, TDS) or greater.
Embodiments herein are directed toward condensate stabilization systems that are robust enough to accommodate such upstream process upsets. The unstabilized condensate is processed according to embodiments of systems and processes herein to produce a stabilized condensate. More specifically, embodiments herein may produce a high-quality stabilized condensate, even during process upsets that introduce a large amount of free and emulsified water and salt into the stabilization system. Stabilized condensates according to embodiments herein may have a negligible free and emulsified water content, a negligible salt content, and negligible gaseous hydrocarbons, as further detailed below, even during such upstream process upsets.
Systems and processes herein include a stabilizer feed drum and a stabilizer unit for stabilizing the raw, unstabilized condensate. The stabilizer feed drum initially receives the raw, unstabilized condensate feed, and separates the raw, unstabilized condensate into a water phase and an oil phase, which is stabilized within the stabilizer unit, separating the condensate from dissolved gases and dissolved gaseous hydrocarbons. In some embodiments, a portion of the dissolved gases and dissolved gaseous hydrocarbon gases may also be separated from the oil phase within the stabilizer feed drum. The raw, unstabilized condensate as received may include a higher quantity of free and emulsified water and dissolved salts (dissolved solids).
In some embodiments, the raw, unstabilized condensate as received in the condensate feed drum includes greater than 2000 ppmv free and emulsified water. The raw, unstabilized condensate as received may include free and emulsified water at a concentration of up to 20000 ppmv, 25000 ppmv, 30000 ppmv, or greater. In various embodiments, the raw, unstabilized condensate as received includes free and emulsified water at a concentration in a range from a lower limit of 2000, 3000, 4000, 5000, 6000, 7500, or 10000 ppmv to an upper limit of 15000, 20000, 25000, or 30000 ppmv, where any lower limit may be combined with any upper limit. The water may be present as water droplets or emulsified water carried by the raw, unstabilized condensate as received.
Associated with the water or brine, in some embodiments the raw, unstabilized condensate as received in the condensate feed drum includes free and emulsified water having a salinity (total dissolved solids content) of greater than 40000 ppm or greater than 60000 ppm. The free and emulsified water may have a salinity, for example, up to 200000 ppm. In various embodiments, the free and emulsified water has a salinity in a range from a lower limit of 40000 ppm, 50000 ppm, 60000 ppm, 70000 ppm, 80000 ppm, 90000 ppm or 100000 ppm to an upper limit of 120000 ppm, 150000 ppm, 160000 ppm, 175000 ppm, or 200000 ppm, where any lower limit may be combined with any upper limit.
Stabilizer feed drums according to embodiments herein include a feed inlet, a water outlet, a vapor outlet, and an unstabilized condensate outlet. The feed inlet receives the raw, unstabilized condensate from upstream processing. Following separations within the stabilizer feed drum, the separated water phase may be recovered via the water outlet, any dissolved gases and dissolved gaseous hydrocarbons (degassed from the raw, unstabilized condensate within the stabilizer feed drum) may be recovered via the vapor outlet, and the oil phase may be recovered by the unstabilized condensate outlet.
Stabilizer feed drums according to embodiments herein further include liquid-liquid separation internals. In some embodiments, the liquid-liquid separation internals are liquid-liquid separation parallel plate packs internals. The liquid-liquid separation internals are coalescing and settling media configured to coalesce the water droplets and emulsified water, facilitating the separation of the water droplets and emulsified water into a bulk water phase. The liquid-liquid separation parallel plate packs internals may include, for example, a coalescing section with parallel plate liquid-liquid coalescing media and OMNI-FITS self-supporting expansion rings mounted inside the feed drum. In some embodiments, the liquid-liquid separation internals are configured to separate the raw, unstabilized condensate as received into a water phase and an oil phase, where the oil phase comprises less than 500 ppmv free and emulsified water, such as less than 400 ppmv, less than 300 ppmv, less than 200 ppmv, or less than 100 ppmv free and emulsified water. In some embodiments, the oil phase may have, with respect to free and emulsified water, less than 90 ppmv water, less than 80 ppmv water, less than 70 ppmv water, less than 66 ppm water, less than 60 ppmv water, less than 50 ppmv water, less than 40 ppmv water, less than 30 ppmv water, less than 20 ppmv water, or less than 10 ppmv water. In some embodiments, the oil phase may have a concentration of free and emulsified water in a range from a lower limit of 1, 2, 3, 4, 5, 7.5, 10, 12.5, 15, 16, 17, 18, 19, or 20 ppmv to an upper limit of 45, 50, 55, 60, 65, 66, 67, 68, 69, 70, 71, 72, 73, 74, 75, 76, 77, 78, 79, 80, 85, 90, 95, or 100 ppmv, where any lower limit may be combined with any upper limit.
In addition to the free and emulsified water, the oil phase may be partially or fully saturated with water, the amount of which may depend on the temperature of the oil phase as well as the particular makeup of the hydrocarbon composition of the unstabilized condensate. For example, in some embodiments the oil phase may include emulsified and free water in a range from about 10 ppmv to 80 ppmv, such as 13 ppmv to 73 ppmv, or from 16 ppmv to 66 ppmv, while the saturated water content may be in a range from about 10 ppmv to 200 ppmv. While the free or emulsified water may contain a significant amount of dissolved salts, the saturated water has an insignificant amount of associated salts (negligible or no salts).
The stabilizer feed drum may include a turbulence isolation plate, which quiesces the flow regime of inlet condensate feed before the condensate enters the liquid-liquid separation internals. The turbulence isolation plate is a structure that is provided for isolating the inlet feed and turbulence, associated with introduction of the raw, unstabilized condensate feed into the stabilizer feed drum, from the liquid-liquid separation internals. The isolation plate may thus provide for a stable, laminar flow of the raw, unstabilized condensate as received across the liquid-liquid separation parallel plate pack internals, which provide the needed surface area and residence time to perform the desired coalescence of the free and emulsified water. The stabilizer feed drum may also include an expansion ring to support the liquid-liquid separation parallel plate pack internals and to accommodate for temperature changes and the associated dimensional changes of the vessel and its internal components. The droplet settling is strongly affected by both the droplet size and the distance the droplet must settle before it reaches the interface between the two liquid phases. Both of these factors can be influenced through the selection of internals to accelerate the separation. While larger droplets will settle quickly, smaller droplet dispersions require excessive settling times when they must travel long distances to the interface. With the use of parallel plates, many interfaces are provided within the same vessel, which allows significant reductions in separator vessel sizes.
Following separation of the phases across the liquid-liquid internals, the oil phase is separated from the water phase. A weir may be provided intermediate the water outlet and the unstabilized condensate outlet, the weir being configured for separating the oil phase from the water phase and for directing the water phase to the water outlet and for directing the oil phase to the unstabilized condensate outlet. The oil phase (unstabilized condensate) is then fed to the stabilizer unit.
The stabilizer unit includes a stabilizer column and one or more reboilers, the stabilizer column including an inlet for receiving the oil phase from the unstabilized condensate outlet, a vapor overheads outlet, and a stabilized condensate bottoms outlet. Heat input from the reboilers and separation internals, which may include trays, random packing, or structured packing, are then used to separate the oil phase into a vapor, recovered via the vapor overheads outlet, and a stabilized condensate, recovered via the stabilized condensate bottoms outlet. The recovered vapors may include water (from the saturated water content of the raw condensate), carbon dioxide, hydrogen sulfide, light hydrocarbons, and other gases (CO2, H2S, etc.) dissolved in the raw, unstabilized condensate as received. The light hydrocarbons may include, for example, gaseous hydrocarbons such as methane and ethane dissolved in the raw, unstabilized condensate as received, as well as a minor amount of propane and butane, depending upon separation efficiency and operating conditions. The stabilized condensate, as noted above, may include butanes, pentanes, and any heavier hydrocarbons contained in the condensate, and, depending upon operating conditions, a minor amount of ethane and propane. In this manner, a portion of the saturated water, most of the free water, and essentially all of the dissolved gases and dissolved hydrocarbon gases are removed from the condensate, rendering the condensate suitable for transport to downstream processing.
The reboilers used to provide the heat facilitating the separations within the stabilizer column are heat exchangers for indirectly exchanging heat between a heat exchange fluid, such as steam, a hot oil, or other types of heat exchange media, with the condensate being stabilized. In some embodiments, the reboilers are thermosiphon type reboilers. The thermosiphon reboilers may be heated using a hot oil supply, such as a hot oil having a temperature in a range from 204° C. to 288° C. (400° F. to 550° F.), such as about 232° C. (450° F.). The thermosiphon reboilers receive the hydrocarbon (HC) liquid from the stabilizer column to the reboiler shell side, and the hot oil then heats the shell side HC liquid condensate through the tube side to a boiling temperature and returning a vapor to the column.
The liquid received by the reboilers from the stabilizer column includes mostly hydrocarbons, but also includes free water and salts, or high salinity water, and saturated water, as received with the stabilizer column feed. The vaporization of the liquid may result in salt accumulation on reboiler tube surfaces, termed “salt fouling” herein. It has been found that an oil phase having greater than about 100 ppmv water, for example, may result in frequent salt fouling of the thermosiphon reboilers. In contrast, embodiments herein, including a stabilizer feed drum having liquid-liquid separation parallel plate pack internals as described above, providing an oil phase having less than about 66 ppmv water, result in negligible or no salt fouling of the reboilers.
The decrease or elimination of salt fouling in the stabilizer column reboilers has also been found by the present inventors to provide for the ability to use advantageous conditions within the stabilizer column so as to produce a higher quality stabilized condensate product. Operating conditions in the stabilizer units according to embodiments herein may include the following:
To facilitate operations so as to achieve the higher quality condensate product, embodiments of condensate stabilization systems herein may also include a control system configured for operating the stabilizer column at an overhead pressure of greater than 12.1 bar gauge (175 psig) and a bottoms temperature of greater than 132° C. (270° F.). The control system may, for example, be configured to operate the stabilization unit at conditions within the ranges exemplified in Table 1.
Stabilized condensate products produced according to embodiments herein, such as at the conditions outlined above for example, may have a true vapor pressure (TVP) of less than 3.79 bar gauge (55 psig). In various embodiments, stabilized condensate products produced according to embodiments herein may have a TVP in a range from a lower limit of 3.1, 3.17, 3.24, 3.31, 3.38, or 3.44 bar gauge to an upper limit of 3.45, 3.52, 3.59, 3.65 3.72, or 3.79 bar gauge (in a range from a lower limit of 45, 46, 47, 48, 49, or 50 psig to an upper limit of 50, 51, 52, 53, 54, or 55 psig), where any lower limit may be combined with any upper limit. Additionally, the stabilized condensate may have negligible or no free water and, as a result, may have a negligible salt content, such as from zero to 0.002 vol % water (or bottom sediment and water (BS&W) in some embodiments) and a non-measurable or trace amount of salts, such as less than 0.5 pounds salt per thousand barrels of condensate (less than 1.5 ppm).
In contrast to the systems herein, such as for systems containing only a gravity separation type condensate feed drum with upstream slug catchers, inefficient separation due to water slugging and the associated fear of fouling of reboilers may result in declined reboiler conditions, and consequently having lower stabilizer column bottoms product temperatures. Such operations may result in a higher TVP, such as greater than 4.13 bar gauge (greater than 60 psig), as well as a higher free or emulsified water and saturated water content, as well as salts associated with the free and emulsified water being contained in the stabilized product. Thus, stabilized condensates achievable via processes and systems herein have improved properties, including a lower TVP, a lower free water content, and a lower salt content for the stabilization system where the stabilizer feed drum is associated with liquid-liquid separation parallel plate pack internals as compared to the stabilization systems where the stabilizer feed drum is without liquid-liquid separation parallel plate packs internals and that are operated at conditions to account for or accommodate expected water slugging.
In some embodiments herein, the oil phase fed to the stabilizer column may be preheated, raising the temperature of the oil phase from a feed drum outlet temperature to a stabilizer column inlet temperature. Such exchange, in some embodiments, may occur in a feed/effluent exchanger, indirectly heating the oil phase fed to the stabilizer column by cooling of the stabilized condensate withdrawn as a product from the stabilizer unit.
Referring now to
Within the stabilizer feed drum are internal components including a turbulence isolation plate 16, which quiesces the flow regime of the inlet condensate, liquid-liquid separation parallel plate pack internals 18, and a weir 20. The turbulence isolation plate 16 may be located intermediate inlet 14 and liquid-liquid separation parallel plate pack internals 18, reducing the amount of turbulence in the fluid as it passes into and through the liquid-liquid separation parallel plate pack media. The turbulence isolation plate function is to quiesce the liquid flow prior to its entry into the liquid-liquid separation region. The quiescent flow provides an environment in which liquid-liquid separation is optimized. Without the turbulence isolation plate, turbulent flow may occur, in which the two phases are constantly mixed and therefore strict separation cannot be met irrespective of whether a large amount of residence time is made available. The separation media may be held in place, for example, by an expansion ring (not illustrated). Following coalescence of the free and emulsified water across the separation media, the resulting water phase may accumulate in a water sump 22, and the lighter oil phase may accumulate and flow over a top of weir 20 into oil sump 27. The water phase may then be recovered via outlet 24 and fed for water processing via flow line 26. In some embodiments, the oil phase may be essentially free of free and emulsified water, as well as their associated salts. Depending upon the operating conditions, as well as the amount of dissolved light components, a vapor phase 29 containing any dissolved gases and dissolved gaseous hydrocarbons released from the unstabilized condensate within the stabilizer feed drum may be recovered via a vapor phase outlet 33.
The oil phase, an unstabilized condensate including dissolved gases and dissolved gaseous hydrocarbons may be recovered via outlet 28 and fed via flow line 30 to stabilizer unit 31. Stabilizer unit 31 includes a stabilizer column 36 and one or more reboilers 48. In some embodiments, for example, stabilizer unit 31 may include two thermosiphon reboilers, as illustrated.
The unstabilized condensate feed recovered via flow line 30 may be preheated via a feed-effluent or feed-bottom exchanger 32 to form a preheated feed 34 fed to an upper portion of stabilizer column 36. In stabilizer column 36, dissolved gases, dissolved gaseous hydrocarbons, and saturated water contained within the unstabilized condensate may be stripped from the heavier hydrocarbons, producing a stabilized condensate. The stripped vapors may be recovered from stabilizer column 36 via overheads stream 38, combined with any vapors 29 recovered from the stabilizer feed drum, and sent via flow line 39 for compression and diverted to a downstream sour gas processing unit (not illustrated).
The stabilized condensate may be recovered from a sump of stabilizer column 36, as illustrated in
Operation of the stabilizer feed drum 12 and stabilizer unit 31 may be controlled by a control system (not illustrated), such as a digital control system. The control system may receive various readings from instruments, such as level controllers (LC), temperature controllers (TC), flow controllers (F), and pressure controllers, among other various measurement and control devices. For example, a flow of water phase recovered from water sump 22 may be controlled based on a measured level of the water/oil interface within the sump using level controller 58. Similarly, a flow of oil phase recovered via outlet 28 may be controlled based on a measured level of the oil phase within oil sump 27 using level controller 60.
Control of the operation of the stabilizer unit 31 may target one or more of a column bottoms temperature, a column overheads temperature, a column overheads pressure, and a column bottoms pressure. In some embodiments, the temperature profile within the column may be monitored via one or more temperature indicators (TI) 66 and may be controlled by a control system configured to target a particular reboiler vapor 52 outlet temperature, such as by temperature controller 62 and flow controller 64, where flow controller 64 may adjust an amount of hot oil 54 provided to reboiler 48 for vaporization of the liquid 50 provided to the reboiler. Other various control schemes may also be used to control stabilizer system operations so as to achieve the desired quality of the stabilized condensate according to embodiments herein.
Stabilization systems herein, such as that illustrated in
Stabilization systems such as illustrated in
Embodiments herein thus overcome the many challenges associated with upstream upsets and reboiler fouling during condensate stabilization. Stabilizer thermosyphon reboiler salt fouling is an ongoing challenge for a conventional gravity separation stabilizer feed drum of gas condensate stabilizer operation caused by mainly high free/emulsified water carry over with condensate feeding to the stabilizer due to free/emulsified water separation limitation of conventional gravity separation feed drum. In addition, eliminating periodical replacement of reboilers tube bundles due to reboilers frequent salt fouling.
As a result, the stabilizer unit requires frequent shutdown to conduct reboiler mechanical cleaning resulting in loss of production as well as significant maintenance cost along with significant cost due to change of reboilers tube bundles. Further, use of a stabilizer column temperature required to reduce stabilizer reboilers salt fouling impacts the condensate product for TVP (true vapor pressure). In addition, the high salt in the export condensate results in operation upset in downstream facilities along with impacting the equipment and piping reliability.
As an example of how systems according to embodiments herein may improve condensate stabilization operations and the resulting condensate product, simulations were performed to compare (i) a stabilization system having a gravity separation based feed drum design and operating conditions to avoid salt fouling with (ii) a stabilization system according to embodiments herein, including liquid-liquid separation plate pack internals and operating conditions selected devoid of concerns for salt fouling.
With respect to (i), a conventional gravity separation stabilizer feed drum at a design condensate rate of about 516.7 m3/h (about 78,000 BPD (barrel per day)) at 37.7° C. to 43.3° C. (100-110° F.) and 15.8 bar gauge (230 psig) with maximum free/emulsified water content >20,000 ppmv during slugging reduces the water separation efficiency due to generation of small water droplets in condensate caused by the high pressure drop (about 11.7 bar (170 psi)) across the pressure letdown valve. The free/emulsified water salinity (TDS, total dissolved solids) is about 40,000-200,000 ppm.
The condensate feed to the stabilizer unit consists of light and heavy hydrocarbon along with saturated water and free/emulsified water during slugging. During normal operation, the feed drum condensate inlet free/emulsified water is typically in a range from 2000 ppmv to 5000 ppmv. However, during upstream slugging, the inlet condensate free/emulsified water may increase up to 20,000 ppmv or greater at design condensate rates of about 516.7 m3/h (about 78,000 BPD (barrel per day)). The condensate enters from the stabilizer column to the thermosiphon reboilers shell-side in order to be heated by the hot oil supplied to the tube-side at about 232° C. (450° F.). The hot oil maintains the reboiler temperature to evaporate the lighter hydrocarbon and separate it to get stabilized condensate. However, when the high free/emulsified water (0.1->0.2% vol) condensate feed to the stabilizer to the thermosiphon reboilers (coming from conventional gravity separation feed drum during slugging), it is heated and evaporated along with the light hydrocarbons. Once the water is evaporated, the salt in the water is deposited on the reboiler tube skin, which results in stabilizer thermosyphon reboilers frequent salt fouling due to high free/emulsified water content condensate feed to the stabilizer column because of the free/emulsified water separation limitation of conventional gravity separation stabilizer feed drum.
To minimize the reboilers salt fouling intensity, the stabilizer column bottom temperature required is in a range from about 93° C. to 110° C. (200 to 230° F.), which results in a stabilized condensate product having a TVP of greater than 4.1 bar gauge (60 psig), such as from 4.8 to 5.4 bar gauge (70-78 psig). As simulated, a feed drum oil phase containing 2031 ppmv emulsified and free water, along with 2236 ppmv saturated water, processed through a stabilizer column targeting a bottoms temperature of 230° F. and a bottoms pressure of 11.7 bar gauge (170 psig) results in a stabilized condensate having a TVP of 4.5 bar gauge (66 psig) and an emulsified/free water content of 840 ppmv, along with associated salts carried by the water. Other simulations performed having an oil phase free water content of 0.1 to 0.2 vol %, and a stabilizer column bottoms temperature of 110-116° C. (230-240° F.) and bottoms pressure of 11.7 bar gauge (170 psig) result in a stabilized condensate product having a TVP of 4.1 to 5.4 bar gauge (60 to 78 psig) and 0.01 to 0.2 vol % water, including from 4 to greater than 10 pounds salt per thousand barrels of condensate (from 11 to greater than 28 ppm).
The high salt in the export condensate results in operation upset and loss of production due to stabilizer unit shutdown along with the associated maintenance cost for conducting mechanical cleaning and change of reboilers tube bundles due to frequent salt fouling. The high salt and high TVP in product condensate also results in downstream facilities operation upset along with impacting the equipment and piping reliability.
In comparison, simulations indicated that use of a stabilizer feed drum using liquid-liquid separation and elevated stabilizer column conditions may both eliminate stabilizer reboilers frequent salt fouling and provide an improved quality stabilized condensate product. At simulated inlet condensate stream free/emulsified water contents of 5,000 to greater than 20,000 ppmv fed at about 516.7 m3/h (about 78,000 BPD (barrel per day)) to the stabilizer feed drum, the outlet condensate free/emulsified water content is simulated to be in a range from about 16-66 ppmv. As the salt is carried by the free/emulsified water, not in the saturated water in the condensate nor in the condensate itself, low/negligible free/emulsified water content in the condensate will result in negligible reboiler salt fouling. As the free/emulsified water content in the condensate feed to the stabilizer column is very low (16-66 ppmv, for example), the salt in reboilers also will be insignificant. As the quantity of salt is negligible due to insignificant amount of free/emulsified water in the condensate feeding the stabilizer that will not be able to build a significant stable salt fouling layer on the reboilers tube surface even operating the stabilizer column (bottom) at the simulated higher temperatures, such as 143° C. (290° F.), because of very low (less than 20 ppmv) or negligible free water in the stabilizer feed condensate. At simulated conditions of 16 to 66 ppm free water in unstabilized condensate fed to the stabilizer column, and stabilizer column conditions including a bottoms temperature of 143° C. (290° F.) and a bottoms pressure of 12.4 bar gauge (180 psig), simulation results indicate a high quality condensate product, having a TVP of 3.4-3.7 bar gauge (50-54 psig), no free water, and negligible salt content.
By negating reboiler salt fouling due to upstream process upsets, embodiments herein allow operation of the stabilizer column at a high bottoms temperature, such as from 135° C. to 157° C. (275° F. to 315° F.), such as about 143° C. (290° F.). Operating the stabilizer column at these higher conditions, even with a raw condensate feed having a high water and salt content being provided to the stabilizer feed drum, will result a high-quality condensate product with a TVP of less than 3.8 bar gauge (55 psig), as well as no free/emulsified water in the product condensate.
It is worth mentioning that simulations of systems according to embodiments herein may result in 0.6 ppmv of free/emulsified water at the stabilizer outlet condensate product. This 0.6 ppmv is the typical maximum allowed for the stabilized condensate to meet pipeline requirements. To meet this product requirement, the feed drum outlet condensate required free/emulsified water 556 ppmv with stabilizer operating at higher bottom temperature 143° C. (290° F.) and 12.4 bar gauge (180 psig), at which the product condensate TVP was simulated to be 3.4 bar gauge (50 psig). Such results endorse the above-noted findings that embodiments herein, having 70-550 ppmv of free/emulsified water in the oil phase fed to the stabilizer column will have negligible salt, or negligible bottom sediment and water (BS&W). Subsequently, the reboiler salt fouling will be negligible, and the stabilizer operation will be smooth.
As a result of negligible salt fouling of reboilers, embodiments herein may result in maintenance cost avoidance, in addition to eliminate the significant cost of reboiler tube bundle replacement due to reboiler tube failure caused by reboilers frequent salt fouling. Total plant one time cost saving is about $8.00 MM (for two identical stabilizer trains, each of about $4.0 MM) due to using the liquid-liquid separation internals in the existing stabilizer feed drum instead of using conventional liquid-liquid Coalescer in downstream of stabilizer feed drum; in addition, the savings for a single plant may exceed $25 MM per year for the case of the plant total condensate feed rate of about 156,000 BPD with embodiments herein. Furthermore, embodiments herein will eliminate high salt in export condensate which leads to operation upset on downstream facilities and impact on the equipment and piping reliability.
In addition, a high TVP (4.1-5.4 bar gauge (60-78 psig)) condensate, resulting from operating at lower column temperatures to avoid salt fouling, has a possibility of two-phase flow in the downstream export piping, which is a potential reliability and integrity issue of the long export piping as the export piping is typically not designed to be operated for two phase flow. On the other hand, the high condensate product quality provided by embodiments herein will result in a higher value condensate product for export.
Inherently, stabilizer feed drums that utilize a conventional gravity separator have limitation of free/emulsified water separation. This limitation causes high free water carryover in condensate during upstream slugging, which results in stabilizer reboiler frequent salt fouling, operation upset, high salt in condensate and off spec product in addition to high TVP (true vapor pressure) due to operating the stabilizer column at comparatively lower temperature to minimize the salt fouling. In contrast, embodiments of the present disclosure provide for both of the following advantages: elimination of stabilizer thermosiphon reboilers salt fouling; and improvement in the stabilizer column performance. Additionally, embodiments herein may provide for one or more of the following advantages: improved downstream hydrocarbon processing, improved plant safety, improved operational efficiency; high product quality; reduced plant maintenance; improved equipment reliability; improved piping integrity; less frequent process upsets, off-spec product, and operation upsets of downstream facilities; less loss of production; elimination or reduction of reboilers tube failures; sign cost avoidance by eliminating reboiler mechanical cleaning; and enhanced equipment and piping reliability and integrity.
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
