This disclosure relates to systems and methods for separation of hydrocarbon containing fluids. More particularly, the disclosure is relevant to separating fluids having a gas phase, a hydrocarbon liquid phase, and an aqueous liquid phase.
Most formations bearing hydrocarbons simultaneously produce an oil phase, a gas phase and an aqueous phase, usually brine. Several wells can be tied together through a gathering line into a separation or processing plant, sometimes comprising just a simple tank, where initial gravity separation of water, oil and gas occurs. Theoretically, gas is taken from the top, water and sediments are drawn from the bottom, and the oil is drawn from the middle of the mixture. In practice, such separations have generally involved the direct heating of the hydrocarbon feed to achieve better separation of the three phases (the gas phase, the lighter hydrocarbon liquid or oil, and the heavier aqueous liquid). Unfortunately, when using conventional systems for separating the three phases, it can be difficult and costly to meet vapor pressure specifications. Accordingly, new techniques for better meeting vapor pressure specifications are of interest in the industry.
As disclosed herein, systems and methods for separation of hydrocarbon containing fluids are provided. Such systems and methods work to provide a superior solution for separating a three-phase feed having a gas phase, an aqueous liquid phase, and a hydrocarbon phase. The gas phase typically comprises a gaseous light hydrocarbon. The aqueous liquid phase generally comprises water, saltwater or brine, such as produced water from oil production operations. The hydrocarbon liquid phase is typically composed of hydrocarbons that are in a liquid state at temperatures from about 32° F. to about 150° F. at standard pressure. While the invention has wider applicability, a typical area where it is useful is in separating gaseous hydrocarbons and aqueous liquid entrained in a hydrocarbon feed from a producing oil well.
In one aspect, the present disclosure provides a process comprising introducing a first fluid into a first separation zone at a first pressure and a first temperature, wherein the first fluid comprises an aqueous liquid, a hydrocarbon liquid and a gas; separating a first portion of the gas and a first portion of the aqueous liquid from the first fluid in the first separation zone to produce a second fluid having a higher concentration of hydrocarbon liquid than the first fluid; indirectly heating the second fluid to a second temperature greater than the first temperature but below the saturation temperature of the aqueous liquid; reducing the pressure of the second fluid to a second pressure below the first pressure; and separating a second portion of the gas and a second portion of the aqueous liquid from the second fluid in a second separation zone to produce a third fluid having a higher concentration of hydrocarbon liquids than the second fluid. The pressure reduction step can occur after indirect heating of the second fluid, or before indirect heating of the second fluid. Further, the third fluid can be at a pressure equal to or less than the second pressure, and at a third temperature equal to or less than said second temperature.
In some embodiments, the first temperature of the process can be below 100° F. Optionally, the first temperature can be about ambient, about 32° F. to less than 100° F.; from about 50° F. to about 90° F.; or from 60° F. to 85° F. The second temperature can be above 100° F. The first pressure can be greater than 100 psig. The second pressure can be less than about 20 psig and optionally less than about 15 psig, less than about 12 psig, or less than about 10 psig.
In some embodiments, the third fluid can comprise less than 1% by volume aqueous liquid and less than 1% by volume gas, and optionally the third fluid can comprise less than 0.5% by volume aqueous liquid and less than 0.5% by volume gas, the third fluid can comprise less than 0.1% by volume aqueous liquid and less than 0.1% by volume gas, or the third fluid can be essentially free of aqueous liquid and gas.
Some embodiments use an indirect heating method carried out by the steps of introducing hot effluent gases from a burner into a fire-tube at least partially submerged in a bath fluid to thus heat the bath fluid, contacting the thus heated bath fluid with a coil, and introducing the second fluid into the coil to thus flow through the coil such that it is heated by the heated bath fluid.
Some embodiments use a separating method for the second separation zone comprising:
In another aspect, the present disclosure provides a system for separating aqueous liquid and a gas from a hydrocarbon feed. The system comprises a first three-phase separator wherein a first portion of the aqueous liquid and a first portion of the gas are separated from hydrocarbon feed to produce a first hydrocarbon-enriched stream; an indirect heater which receives and indirectly heats the first hydrocarbon-enriched stream; and a second three-phase separator wherein a second portion of the aqueous liquid and a second portion of the gas are separated from the thus heated hydrocarbon-enriched stream to produce a second hydrocarbon-enriched stream. The system can further include a pressure reducer that reduces the pressure of the first hydrocarbon-enriched stream. The location of the pressure reducer can be upstream of the second three-phase separator and downstream of the first three-phase separator. Additionally, the pressure reducer can be upstream of the indirect heater or downstream of the indirect heater.
The indirect heater of the system can comprise a burner, a container, a fire-tube and a coil. The container can hold a bath liquid. The fire-tube at least partially extends through the container and is connected to the burner such that hot gaseous effluent flows through the fire-tube and thus heats the bath liquid. The coil extends at least partially through the container. The coil is configured to receive the first hydrocarbon-enriched stream, which is thus heated by the contact of the coil with the bath liquid.
In some embodiments, the system can also comprise a two-phase separator located upstream from the first three-phase separator. The two-phase separator is configured to remove part of the gas from the feed stream prior to introduction to the first three-phase separator.
In some embodiments, the second three-phase separator of the system comprises a vessel. The vessel has a top portion, a bottom portion, a mid-portion, a partition and a downcomer. The top portion contains a series of baffles and has a first hydrocarbon-enriched stream inlet and a gas outlet. The bottom portion has a bottom and an aqueous fluid outlet. The mid-portion has a hydrocarbon fluid outlet. The partition is located in the mid-portion above the hydrocarbon fluid. The partition separates the top portion from the bottom portion. The downcomer is configured to introduce liquids from the top portion to the bottom of the bottom portion.
The present disclosure may be understood more readily by reference to the following description including the examples. In addition, numerous specific details are set forth in order to provide a thorough understanding of the embodiments described herein. However, those of ordinary skill in the art will understand that the embodiments described herein can be practiced without these specific details. In other instances, methods, procedures and components have not been described in detail so as not to obscure the related relevant feature being described. Additionally, the description is not to be considered as limiting the scope of the embodiments described herein.
Referring now to the drawings, wherein like reference numbers are used herein to designate like elements throughout the various views, various embodiments are illustrated and described. The figures are not necessarily drawn to scale, and in some instances the drawings have been exaggerated and/or simplified in places for illustrative purposes only. Where components of relatively well-known designs are employed, their structure and operation will not be described in detail. One of ordinary skill in the art will appreciate the many possible applications and variations of the present invention based on the following description.
The following describes a system of equipment whose individual benefits work to provide a superior solution for separating a three-phase feed having a gas phase, an aqueous liquid phase, and a hydrocarbon liquid phase. The gas phase typically comprises a gaseous light hydrocarbon, such as methane, ethane, propane, butane and the like. Generally, as used herein, gaseous light hydrocarbons are ones in a gaseous state at temperatures from about 32° F. to about 150° F. at standard pressure. The gas phase can also include non-hydrocarbons that are gaseous in the aforementioned temperature range, for example carbon dioxide and sulfur dioxide.
The aqueous liquid phase generally comprises water, saltwater or brine, such as produced water from oil production operations. The hydrocarbon liquid phase is typically composed of hydrocarbons that are in a liquid state at temperatures from about 32° F. to about 150° F. at standard pressure. While the invention has wider applicability, a typical area where it is useful is in separating gaseous hydrocarbons and aqueous liquid entrained in a hydrocarbon feed from a producing oil well.
The system in its most simple form is a separator followed by an indirect heater followed by another separator. There may be up or downstream equipment associated with this unit, most commonly, an upstream high-pressure gas separator to remove gaseous hydrocarbons from the hydrocarbon feed stream for sale.
As used herein, “direct heater” and “direct heating” refer to a style of heating where hot burner gases directly heat the treatment stream, typically process liquid or process gas. For example, a burner provides hot gasses that transfer their heat energy to the treatment stream flowing directly through coils installed inside the heater vessel. Alternatively, the hot gases may be introduced into a fire-tube, which is submerged in the treatment stream such that the treatment stream flows around the fire-tube and is thus heated. In this disclosure, the treatment stream is a three-phase hydrocarbon feed for separation.
As used herein “indirect heater” or “indirect heating” refers to a style of heating in which an intermediary bath liquid is directly heated by the hot burner gases and then the bath liquid is used to heat the treatment stream. For Example,
Turning now to
Optionally, a two-phase separator 228 can be utilized prior to first three-phase separator 224. Two-phase separator 228 is a separator where a feed stream is separated into two phases: gas and liquid. As illustrated, two-phase gas separator 228 can be utilized to separate part of the gas phase out from a high-pressure hydrocarbon feed stream having three phases. The gas phase portion separated out is typically rich in gaseous hydrocarbons and can be sold as a product.
Flow from two-phase separator 228 can be controlled by level control valve 230. Additionally, the pressure of the remaining three-phase feed can then be reduced at level control valve 230 and subsequently introduced into first three-phase separator 224. In first three-phase separator 224, a first portion of the aqueous liquid phase and a first portion of the gas phase are separated from hydrocarbon feed to produce a first hydrocarbon-enriched stream, that is a stream now richer in the liquid hydrocarbon phase. The first portion of the aqueous liquid phase can be disposed of as waste. The first portion of the gas phase can generally be sent to a flare to be burned as waste.
The first hydrocarbon-enriched stream is then sent to indirect heater 202, which indirectly heats the first hydrocarbon-enriched stream by use of a liquid bath as described above. Typically, the pressure of the first hydrocarbon-enriched stream can be reduced in pressure reducer 232 prior to introduction into indirect heater 202. This pressure reduction helps achieve the advantages attributed to lower heater duty. However, in some embodiments the pressure can be reduced after indirect heating by pressure reducer 234. In other embodiments, the pressure can be reduced both by pressure reducer 232 and 234. The use of indirect heat advantageously allows for one or both of the pressure reducers 232 and 234. Specifically, indirect heater 202 is placed near (e.g. ˜20 ft.) or in-line with the separators 224 and 226, which takes advantage of pressure reducers 232 and 234 without significant loss of heat or pressure drop through the piping. Conversely, a direct heater is usually installed outside the explosion limits (e.g. ˜200 feet), which requires significant heat duty to maintain proper temperature and results in high-pressure drop through the piping.
Next, the heated first hydrocarbon-enriched stream is introduced into second three-phase separator 226, wherein a second portion of the aqueous liquid phase and a second portion of the gas phase are separated from the thus heated hydrocarbon-enriched stream to produce a second hydrocarbon-enriched stream. The second portion of the aqueous liquid phase can be disposed of as waste. The second portion of the gas phase can generally be sent to flare to burn as waste. The second hydrocarbon-enriched stream can be sent to a tank 236 for storage.
The process will be further described with reference to a general schematic diagram of
The remaining portion of the feed stream from the two-phase separator generally still comprises two liquid phases and a gas phase, although the quantity of the gas phase has been reduced. This fluid stream 344 is introduced into a first three-phase separation zone 324. Fluid stream 344 can be introduced to first three-phase separation zone 324 without a pressure reduction, hence at a pressure of greater than 100 psig. However, generally the pressure of fluid stream 344 can be reduced prior to introduction into first three-phase separation zone 324. The pressure can be reduced to a pressure below 100 psig but above near atmospheric pressure (as described below); thus, will be at a mid-pressure. Generally, the mid-pressure is at least about 17 psig, and more typically at least about 20 psig or at least about 25 psig, and the mid-pressure generally is no greater than about 90 psig, and more typically no greater than about 70 psig. While the temperature at which fluid stream 344 is introduced into first three-phase separation zone 324 can be cooler than feed stream 340, which entered two-phase separation zone 328, generally fluid stream 344 is still about ambient as described above. In most embodiments, fluid stream 344 will not be heated prior to introduction into first three-phase separation zone 324 and will not be heated during separation within first three-phase separation zone 324. The temperature of the fluid stream 344 may undergo slight cooling from separation of the phases in first three-phase separation zone 324.
Within first three-phase separation zone 324, a portion of the gas and a portion of the aqueous liquid (indicated by water in
Enriched fluid stream 350 is introduced into the indirect heater (indirect heating zone) 302 so that it is indirectly heated to a second temperature greater than the first temperature but below the saturation temperature of the aqueous liquid. The saturation temperature is the temperature for a corresponding saturation pressure at which a liquid boils into its vapor phase. The liquid can be said to be saturated with thermal energy. The second temperature can depend on the composition of the enriched fluid stream and the pressure at which heat is applied. Typically, the second temperature is above 100° F. and, in some embodiments, up to about 160° F.
Generally, prior to indirect heating of enriched fluid stream 350, the pressure of enriched fluid stream 350 can be further reduced to near atmospheric pressure. “Near atmospheric” means a pressure just high enough to overcome the head losses of the indirect heater 302 and the piping to drive the fluid from indirect heater 302 into second three-phase separator 326, as described below. Near atmospheric pressure is close to, typically within about 10 psi of, the surrounding atmospheric pressure but less than the mid-pressure and the pressure of the initial feed stream. More generally, this is from about 0 psig to about 20 psig, more typically from about 5 psig to about 15 psig or from about 7 psig to about 12 psig and often about 10 psig or less. Reducing the pressure prior to indirect heating is believed to advantageously lessen the heater duty; thus reducing system demands and cost. However, it is within the scope of this disclosure to reduce the pressure to near atmospheric after indirect heating. Also, it is within the scope to step-wise reduce the pressure around the indirect heating; that is, to reduce the pressure between first three-phase separation zone 324 and indirect heater 302 to a pressure above near atmospheric and then further reducing the pressure between indirect heater 302 and second three-phase separation zone 326 to near atmospheric.
The resulting near-atmospheric heated fluid stream 352 is introduced into a second three-phase separator 326, wherein a second portion of the gas phase and a second portion of the aqueous liquid phase (water in
Turning now to
A partition 482 is located in mid-portion 464 above the hydrocarbon fluid outlet 476. Partition 482 separates top portion 462 from bottom portion 466. A downcomer 484 protrudes through partition 482 and is configured to introduce liquids from top portion 462 to the bottom 478 of bottom portion 466.
As illustrated in
The operation of the illustrated three-phase separator 426 comprises introducing a three-phase fluid stream from the indirect heater into vessel 460 through fluid stream inlet 472 located above the series of baffles 470 such that the fluid stream encounters baffles 470 thus enhancing the separation of the gas phase from the fluid stream. Subsequently, the liquid portion of the fluid stream settles down towards mid-portion 464 and encounters partition 482 and downcomer 484 such that the liquid portion is introduced to the bottom portion 466 of the separation zone through downcomer 484. At the bottom 478 of the separation zone, the hydrocarbon liquid phase rises to mid-portion 464 of the separation zone below partition 482, and the aqueous liquid phase remains at the bottom 478 of the separation zone. The gas phase is removed from the gas outlet 474 at the top of the separation zone. The aqueous liquid phase is removed from the aqueous liquid outlet 480 at the bottom 478 of the separation zone. The hydrocarbon liquid phase is removed from mid-portion 464 of the separation zone below partition 482.
The above described system and process allows for greater control of the process and resulting product. Control of the process and system can be appreciated with reference to
For example, Reid vapor pressure (RVP) specification can be better met by adjusting the processes to utilize near atmospheric pressure at the indirect heater and in the second three-phase separator (labeled as the “Tower” in
As a second example, temperature specifications can be better met by adjusting the system so that indirect heater 502 is run at a higher pressure with pressure reduction occurring between indirect heater 502 and second three-phase separator 526. In this configuration, level control (LC) 594 on each of the first three-phase separators 524 can maintain desired levels and allow the hydrocarbon stream from the first three-phase separators 524 to dump through LCV 596 as levels increase. Manual bypass valve 599 will be in the closed position and PCV 598 will modulate to maintain a backpressure to allow indirect heater 502 to operate near the pressure of the first three-phase separators 524 with minimal pressure drop to only insure adequate flow. For example, for first three-phase separators 524 operating at about 50 psig, backpressure can be about 45 psig. The pressure change to near atmospheric will happen at PCV 598, so that the fluid stream entering second three-phase separator 526 is at near atmospheric.
There are more advanced methods which can be utilized to control the system and process. For example, the system can be automated by using LIC (level indicator controllers or liquid level controllers), PID controllers, PIC controllers, programmable logic controllers (PLC), processors and the like, to detect liquid levels, pressures and temperatures and to adjust the valves accordingly.
For example, RVP specification can be met by using LIC at level control (LC) 594 on each of the first three-phase separators 524 to measure the level and deliver an input signal back to a PLC with LIC logic/PID control to deliver an output signal to LCV 596 to maintain desired level and allow the hydrocarbon stream from the first three-phase separators 524 to dump at a steady dump rate. Manual bypass valve 599 will still be in place but will no longer need to be used to achieve near atmospheric pressure. The PLC will adjust PCV 598 to the open position allowing the indirect heater 502 to operate at the pressure of second three-phase separator 526 plus head pressure, or near atmospheric pressure. Pressure change will happen at LCV 596.
For temperature specification operation, the LIC at the level control (LC) on each separator can measure the level and deliver an input signal back to a PLC with LIC logic/PID control to deliver an output signal to LCV 596 to maintain the desired level set point and allow the hydrocarbon stream from the first three-phase separators 524 to dump at a steady dump rate. Manual bypass valve 599 will still be in place but will no longer need to be used. A pressure transmitter can measure the upstream pressure of PCV 598 and deliver an input signal back to a PLC with PIC logic/PID control to deliver an output signal to PCV 598 to modulate so as to maintain a desired pressure set point (back pressure) and allow indirect heater 502 to operate near the pressure of the first three-phase separators 524 with minimal pressure drop to insure adequate flow. The pressure change to near atmospheric will happen at PCV 598.
With the use of automated logic control, the system has the opportunity to start utilizing advanced measurement devices to continually optimize the oil treating process to meet RVP specification and temperature specification simultaneously to achieve maximum oil production and optimizing the system control itself.
One aspect of the process and its control system will now be described in further detail with reference to
After the initial degassing of the feed stream is achieved, the remaining three-phase fluid stream 844 flows to first three-phase separator 824 where first three-phase separator 824 separates out the phases individually. As this separation occurs, the gas 846 from first three-phase separator 824 can be let down to flare pressure as there is not sufficient pressure left to enter the sales line. This happens across another pressure control valve (PVC) 847 monitoring the upstream pressure, which can be set at the desired operating pressure of first three-phase separator 824 to achieve optimum separation. PCV 847 holds backpressure on the system and lets down gas to the flare line as pressure increases. This will be referred to as flare gas 846.
The aqueous phase collects at the bottom of first three-phase separator 824 and can be monitored by a weighted displacer level control to detect interface of the oil/water layer. The level control can be a pneumatic type and can deliver a pneumatic direct acting signal to a level control valve (LCV) 849. As the aqueous phase level increases, the level control increases the signal to the level control valve so that the valve opens thus allowing the aqueous phase to dump. This can happen proportionally between level and output. The higher the level, the higher the output signal to the valve to open. The dumped aqueous phase is referred to as produced water 848. The remaining product, which is mostly liquid hydrocarbons or oil, accumulates in the oil bucket of the three-phase separator and can be monitored by another weighted displacer level control to detect the top of the liquid hydrocarbon level. As the liquid hydrocarbon level increases, the level control increases the signal to the level control valve (LCV) 851 so that LCV 851 opens thus allowing this enhanced fluid stream 850 to flow to indirect heater 802. This can happen proportionally between level and output. The higher the level, the higher the output signal to the valve to open. In some embodiments, LCV 851 will include a pressure reducer so that enhanced fluid stream 850 is introduced into indirect heater 802 at a lower pressure.
Since the top of the oil level is in contact with the gas section of first three-phase separator 824, a pneumatic float operated level switch can be installed to block the signal coming from the oil level control to the oil-level control valve. Blocking the signal allows the oil control valve to fail in a closed state so as to assure not to dump gas to indirect heater 802 in the event of a low oil level. This system can be pneumatically interlocked.
In indirect heater 802, enhanced fluid stream 850 from first three-phase separator 824 flows through the water bath heater coil wherein heat from the burner is cross exchanged indirectly from the fire-tube to the bath and then to the enhanced fluid stream. Temperature control is achieved through the burner management system (BMS), not shown. The BMS monitors the temperature of the heated fluid stream 852 exiting indirect heater 802 and adjusts the heat to maintain a desired set point that is calculated to de-gas the enhanced fluid stream to meet RVP after the final stage of separation. The bath temperature is also monitored as a secondary control to the process temperature. This helps to maintain a minimum and maximum bath temperature in the event of no flow. There also can be secondary shutdown devices such as low bath level, high stack temperature and flame failure monitors to shut down the heater for equipment protection. As the heated fluid stream 852 exits indirect heater 802, it has the option to pass through a pressure control valve or a manual bypass valve around the pressure control valve (represented by element 853 but which can be seen in more detail in
The final stage of separation happens in second three-phase separator 826. As heated fluid stream 852 enters second three-phase separator 826, entrained gas 854 is flashed off and goes directly to flare at near atmospheric pressure. The remaining fluid stream goes through a final separation internally to remove any residual aqueous phase. The aqueous phase collects at the bottom of second three-phase separator 826 and can be monitored by a weighted displacer level control to detect interface of the oil/water layer. The level control can be a pneumatic type and can deliver a pneumatic direct acting signal to a level control valve (LCV) 857. As the water level increases, the level control increases the signal to level control valve 857 so that the valve opens, thus allowing a second produced water 856 to dump. This happens proportionally between level and output. The higher the level, the higher the output signal to the valve to open. The remaining fluid stream 858 gravity feeds to the oil production tanks 836. Gas 835 from tank 836 is taken to flare. Product 837 can be removed from tank 836.
The above described system and process have the following benefits.
In order to illustrate the benefits of a system in accordance with this disclosure, the following calculated prophetic examples have been prepared. In each case, the controls and example are calculated for a three-phase hydrocarbon feed under the conditions indicated in Table 1.
The hydrocarbon liquid phase and gas phase components of the hydrocarbon feed are under the conditions indicated in Table 2 with the composition indicated in Table 3.
The aqueous liquid phase component of the hydrocarbon feed is under the same temperature and pressure conditions and has a standard liquid volumetric flow of 6000 bbl/d. For all the systems illustrated, it is assumed that the oil product needs to meet a 10.842 psi Reid vapor pressure (RVP).
Control I
Product properties are calculated for a separation system illustrated in
The heat treater vessel is operating at 125 psig with no upstream three-phase separation equipment. The model assumes a line heat loss resulting in 30° F. of heat loss for the fluid between entering line 613 and being taken off as product 619. The product (in stream 609) is depressurized to less than 1 psig (15 psia) downstream of the heat treater and upstream of the storage tank.
Table 4 below shows a comparison of Controls I to V and Example I. Note for Control I, the liquid product 619 is meeting the RVP specification (RVP Exiting Tankage) but the treated fluid entering the storage tank 615 is not (RVP Entering Tankage). Additionally, the system of Control I uses 9.6318e+006 Btu/h to heat the hydrocarbon feed. If additional heat losses occur or condensing of tank vapors occurs, the duty would increase within the heat treater and the amount of recovered oil product commonly decreases.
Control II
Product properties are calculated for a separation system illustrated in
Heat treater vessel 703 is operating at 35 psig with no upstream three-phase separation equipment. Accordingly, the liquid stream 725 undergoes depressurization prior to entering heat treater vessel 703. Subsequently, the enriched stream 709 from the heat treater vessel 703 is again depressurized to less than 1 psig (15 psia). Again, there is an assumed line heat loss resulting in 30° F. of heat loss for the fluid 713 between entering storage tank 715 and being taken off as product 719. The product (in stream 709) is depressurized from 35 psig to less than 1 psig (15 psia) downstream of the heat treater vessel and upstream of the storage tank.
Table 4 shows a comparison with Example I. Note in Control II, the liquid product 719 (RVP Exiting Tankage) is meeting the RVP specification (RVP Exiting Tankage) but the treated fluid entering the storage tank 713 is not (RVP Entering Tankage). Additionally, the system of Control II uses 9.78e+006 Btu/h to heat the hydrocarbon feed.
Control III
The properties are calculated for a system similar to that of Control II except the heater duty is increased to 13.3 MMBTU/hr in order to meet the RVP specification of the oil prior to entering the tankage (RVP Entering Tankage). The results are shown in Table 4. Note that the oil production reduces from 2632.1 bbl/d of oil in Control II to 2,398.6 bbl/d of oil for Control III.
Control IV
Product properties are calculated for a separation system similar to that of Control II, except that the heat treater is operating at 80 psig. Again, there is an assumed line loss resulting in 30° F. of heat loss for product entering the storage tank. The results are shown in Table 4.
For Control IV, the system uses 8.388e+006 Btu/h to heat the hydrocarbon feed. The liquid product exiting the storage tank is meeting the RVP specification (RVP Exiting Tankage) but the treated fluid entering the storage tank is not (RVP Entering Tankage).
Control V
Product properties are calculated for a separation system as per Control IV, except heater duty is increased to 13.6 MMBTU/hr in order to meet the RVP specification of the oil prior to entering the tankage (RVP Entering Tankage). The results are shown in Table 4. Note that the oil production reduces from 2492.5 bbl/d of oil in Control IV to 2,190.7 bbl/d of oil for Control V.
Product properties are calculated for a separation system in accordance with the current disclosure. The system is illustrated in
Table 4 shows a comparison of Example I with Controls I to V. Note in Example I, the liquid product 837 meets the RVP specification (RVP Exiting Tankage) and the treated fluid 852 entering the storage tank 836 (RVP Entering Tankage) also meets RVP specification. Additionally, Table 4 show that the system uses 1.5828e+006 Btu/h to heat the hydrocarbon feed, which is substantially less than the heat treater duty required for Control I through Control V. The heat treater duty required here is 16% or less than that in the other cases above. When a vapor pressure specification must be met prior to entering the tankage, this reduces to 12%. Liquid product yields of Example I are equal to that of Control I and II. Moreover, when the RVP specification must be met prior to entering the tankage, the system of Example I provides up to 10% higher volumetric yields than Control I and Control II.
While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Additionally, where the term “about” is used in relation to a range it generally means plus or minus half the last significant figure of the range value, unless context indicates another definition of “about” applies.
Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
This application claims the benefit of U.S. Provisional Application No. 62/413,079 filed Oct. 26, 2016, which is hereby incorporated by reference.
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3407805 | Bougard | Oct 1968 | A |
4778443 | Sands | Oct 1988 | A |
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Number | Date | Country | |
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62413079 | Oct 2016 | US |