US20200239785A1

US20200239785A1 - Organic acid removal from liquid hydrocarbon product streams

Info

Publication number: US20200239785A1
Application number: US16/741,906
Authority: US
Inventors: Charles R. Bolz; Suriyanarayanan Rajagopalan; Mohsen N. Harandi; David W. Staubs
Original assignee: ExxonMobil Research and Engineering Co
Current assignee: ExxonMobil Technology and Engineering Co
Priority date: 2019-01-24
Filing date: 2020-01-14
Publication date: 2020-07-30
Also published as: WO2020154129A1

Abstract

Systems and processes for removing organic acids from liquid hydrocarbon product streams are provided. The systems and processes can include injecting an ammoniated water wash into a liquid hydrocarbon product stream, such as an effluent stream from a methanol conversion process, and subsequently separating the treated liquid hydrocarbon product stream from the wash water. The addition of ammonia can reduce the amount of water wash by an unexpected amount.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 62/796,167, filed on Jan. 24, 2019, the entire contents of which are incorporated herein by reference.

FIELD

Systems and processes for removing organic acids from liquid hydrocarbon products streams are disclosed.

BACKGROUND

Various industrial processes are utilized for the conversion of low boiling carbon-containing compounds to higher value products. For example, the commercial methanol-to-gasoline (MTG) process produces gasoline from methanol using ZSM-5 catalysts. In the MTG process, methanol is first dehydrated to dimethyl ether. The methanol and/or dimethyl ether then react in a series of reactions that result in formation of aromatic, paraffinic, and olefinic compounds. The resulting product includes liquefied petroleum gas (LPG) and a high-quality gasoline comprised of aromatics, paraffins, and olefins. However, in certain conventional processes the liquid hydrocarbon products can include small amounts of organic acids that can cause corrosion of processing equipment, which can lead to costly repairs and plant downtime. It would be desirable to mitigate the corrosive effect of the organic acids in the MTG process or other oxygenate conversion processes.

SUMMARY

In various aspects, a method for removing organic acids from a liquid hydrocarbon product stream is provided. The method can include exposing a liquid hydrocarbon product stream comprising naphtha boiling range compounds, light ends, and 1 ppmw or more of organic acids to a water wash stream comprising ammonia to form a treated liquid hydrocarbon product stream. The amount of the water wash stream can be 0.5 L to 20 L per barrel of the liquid hydrocarbon product stream. The water wash can include a) 4.0 g or more of ammonia per barrel of the liquid hydrocarbon product stream, b) a ratio of moles of ammonia in the water wash to moles of the organic acids in the liquid hydrocarbon product stream is 1.5 or more, or c) a combination of a) and b).

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 depicts an example system for removal of organic acids from liquid hydrocarbon product streams.

FIG. 2 depicts a graph showing estimated organic acid removal efficiency from a deethanizer feed with five pounds per hour of ammonia in a water wash stream at various rates.

FIG. 3 depicts a graph showing estimated organic acid removal efficiency from a deethanizer feed with seven pounds per hour of ammonia in a water wash stream at various rates.

FIG. 4 depicts a graph showing estimated organic acid removal efficiency from a deethanizer feed with ten pounds per hour of ammonia in a water wash stream at various rates.

FIG. 5 depicts a graph showing estimated organic acid removal efficiency from a deethanizer feed with twelve pounds per hour of ammonia in a water wash stream at various rates.

DETAILED DESCRIPTION

Overview
In various aspects, systems and processes for removing organic acids from liquid hydrocarbon product streams are provided. In aspects, the system can include injecting an ammoniated water wash into a liquid hydrocarbon product stream and subsequently separating the treated liquid hydrocarbon product stream from the wash water. The treated liquid hydrocarbon product stream can then be utilized in any convenient manner, such as separation of a desired gasoline product from a remaining portion of the treated liquid hydrocarbon product.
Certain conventional processes can be utilized for converting oxygenates into hydrocarbon products, such as the MTG process. In certain conventional MTG processes, once the methanol is converted to the liquid hydrocarbon product a series of downstream processes are utilized to remove excess water and/or other undesirable conversion products, such as durene (1,2,4,5, tetra-methyl benzene). In such conventional systems, the liquid hydrocarbon product may first be separated from the water in a conventional product separator. The resultant separated liquid hydrocarbon product contains naphtha boiling range compounds and light ends, in addition to small amounts of water, dissolved hydrogen, and other light gases. In conventional systems, the separated liquid hydrocarbon product is sent to a de-ethanizer for removal of at least a portion of the C₂₋ compounds (two carbon atoms or less) from the C₃₊ compounds (three carbon atoms or more, such as the naphtha boiling range compounds). The C₃₊ effluent from the de-ethanizer can then be subjected to a stabilizer to separate the C₃-C₄compounds from the naphtha boiling range compounds. In such systems, the naphtha boiling range compounds are then subjected to a splitter where a light and heavy fraction is separated. The heavy fraction is subjected to hydrotreatment to remove the durene or other undesirable large compounds, and may then be mixed with the light fraction for further processing of naphtha boiling range compounds into gasoline. Conventional MTG processes are described in U.S. Pat. No. 4,482,772.
In certain conventional systems, the resulting liquid hydrocarbon product from the MTG process can include organic acids in amounts sufficient to cause corrosion when in contact with stagnant water, which depending upon system design, may be at one or more locations within the downstream MTG system. In one example, corrosion may occur where the light fraction from the splitter is stored. Such corrosion can be detrimental to the MTG systems and downstream refinery processes. Therefore, there is a need to mitigate the corrosion issues that arise from the organic acids present in the liquid hydrocarbon product.
As noted above, in certain systems, the corrosion can occur where the light fraction of naphtha boiling range compounds is stored. However, treating this downstream light fraction may result in water saturation of the gasoline product, which could present haze problems in cold weather thereby requiring additional drying facilities. Further, treating the downstream light fraction of naphtha boiling range compounds would not prevent any potential corrosion on upstream MTG conversion or product separation systems. While the liquid hydrocarbon product exiting the upstream conversion product separator may be subjected to a water wash in an attempt to remove the organic acids, the volumes of water required to remove substantial amounts of the organic acids would be too resource intensive to process in conventional systems.
The systems and processes described herein solve one or more the above-mentioned problems related to the presence of organic acids in an MTG conversion product. It has been discovered that addition of ammonia to a water wash stream for washing of the liquid hydrocarbon product upstream of the de-ethanizer allow for an unexpectedly large reduction in the amount of water that is needed for effective removal of organic acids. Without being bound by any particular theory, it is believed that at least a portion of the organic acids are solvated within the liquid hydrocarbon product, and as a result cannot be easily transferred to a neutral aqueous phase. Addition of a weak base, such as ammonia, can allow water wash to act as an extraction, so that the organic acids can be efficiently transferred to the aqueous phase corresponding to the water wash. By improving the ability to transfer the organic acids from the hydrocarbon phase to the aqueous phase, the amount of water required to achieve a desired level of organic acid removal can be reduced by an unexpectedly large amount. As shown below, the reduction in volume of water can correspond to a reduction by an order of magnitude or more.
For example, in certain aspects, exposing a liquid hydrocarbon product stream to ammonia in an amount of 4.0 g or more of ammonia (in an aqueous solution) per barrel of the liquid hydrocarbon product stream can significantly reduce the organic acids present therein. With regard to the water wash, the volume of the water wash stream containing the ammonia can correspond to 0.5 L or more of water wash per barrel of the liquid hydrocarbon product stream (or 2.0 L or more). As discussed below, in certain aspects, the aforementioned small amounts of ammonia reduce the water wash amount over at least one order of magnitude compared to the amounts required to remove organic acids in the absence of the ammonia. Further, the processes described below can include monitoring the pH of the separated water wash stream in order to ensure the appropriate amount of organic acids are being removed from the liquid hydrocarbon product.
In this discussion, the “naphtha boiling range” is defined as 50° F. (−10° C., roughly corresponding to the lowest boiling point of a pentane isomer) to roughly 437° F. (−225° C.). Thus, the phrase “naphtha boiling range compounds” refers to one or more compounds having boiling points in the naphtha boiling range. Further, in this discussion, “light ends” refers to hydrocarbon compounds that exhibit a boiling range below the naphtha boiling range described above. It is noted that due to practical consideration during fractionation (or other boiling point based separation) of hydrocarbon-like fractions, a fuel fraction formed according to the methods described herein may have T5 and T95 distillation points corresponding to the above values (or T10 and T90 distillation points), as opposed to having initial/final boiling points corresponding to the above values. While various methods are available for determining boiling point information for a given sample, for the claims below ASTM D86 is a suitable method for determining distillation points (including fractional weight distillation points) for a composition.
All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
Processes for Organic Acid Removal from Liquid Hydrocarbon Product Streams
As discussed above, in various aspects, processes for the removal of organic acids from liquid hydrocarbon product streams are described. In aspects, the liquid hydrocarbon product stream can be an effluent from an oxygenate conversion process, such as the MTG process described above. In various aspects, the liquid hydrocarbon product stream can include naphtha boiling range compounds, light ends, organic acids, small amounts of water, or a combination thereof. In certain aspects, the naphtha boiling range compounds present in the liquid hydrocarbon product stream can exhibit a Research Octane Number (RON) of 70 or more, or 80 or more, or 90 or more, such as up to 110 or possibly still higher. The Research Octane Number (RON) can be determined according to ASTM D2699. In aspects, small amounts of water can be present in the liquid hydrocarbon product stream prior to the water washing, such as water in an amount of 10 ppm to 3000 ppm, or 200 ppm to 2000 ppm. In some aspects, the liquid hydrocarbon product stream can be a de-ethanizer feed. As used herein, a de-ethanizer feed refers to a liquid hydrocarbon product stream from a MTG conversion process that is intended to be subjected to a de-ethanizer for removal of C₂₋ hydrocarbons.
The organic acids present in the liquid hydrocarbon product stream can include any organic acids produced from the conversion of oxygenates to a liquid hydrocarbon product stream. In some aspects, the organic acids can include acids having six carbon atoms or less, or five carbon atoms or less. For example, the organic acids can include formic acid, acetic acid, propionic acid, butyric acid, or combinations thereof. In certain aspects, collectively, the organic acids can be present in the liquid hydrocarbon product stream in an amount of 1 ppmw to 700 ppmw, or 5 ppmw to 500 ppmw, or 10 ppmw to 300 ppmw, or 50 ppmw to 700 ppmw, or 50 ppmw to 500 ppmw. It should be understood that the relative amount of organic acids and the specific types of organic acids present in a liquid hydrocarbon product stream can vary based on the upstream oxygenate conversion processes utilized.
In certain aspects, the ammoniated water wash stream can include ammonia in any amount. In certain aspects, the ammonia is present in an amount that is a molar equivalent or molar excess of the amount of organic acids present in the liquid hydrocarbon product stream. In one aspect, the ratio of moles of ammonia to moles of organic acids can be 1.0 or more, or 1.5 or more, or 1.8 or more, or 2.0 or more, or 3.0 or more, or 4.0 or more, such as up to 10 or possibly still higher.
In various aspects, ammonia can be present in an amount of 4.0 g or more per barrel of liquid hydrocarbon product stream, or 5.0 g or more, or 5.5 g or more, or 7.5 g or more, or 10 g or more, such as up to 50 g or possibly still higher. In aspects, the ammonia can be present in an amount of 4.5 g to 50 g per barrel of liquid hydrocarbon product stream, 5.5 g to 40 g per barrel of liquid hydrocarbon product stream, or 7.5 g to 35 g per barrel of liquid hydrocarbon product stream.
In various aspects, the water in the ammoniated water wash stream is present in an amount of 20 liters (L) or less per barrel of liquid hydrocarbon product stream, 15 L or less per barrel of liquid hydrocarbon product stream, or 10 L or less per barrel of liquid hydrocarbon product stream. In the same or alterative aspects, the water in the ammoniated water wash stream is present in an amount of 0.5 liters (L) or more per barrel of liquid hydrocarbon product stream, 2.0 L or more per barrel of liquid hydrocarbon product stream, or 3.5 L or more per barrel of liquid hydrocarbon product stream. In certain aspects, the water in the ammoniated water wash stream is present in an amount of 0.5 L to 20 L per barrel of liquid hydrocarbon product stream, 2.0 L to 15 L per barrel of liquid hydrocarbon product stream, or 2.0 L to 10 L per barrel of liquid hydrocarbon product stream.
In certain aspects, the ammonia and water are housed separately and the ammonia can be injected into the water wash stream prior to contact with the liquid hydrocarbon product stream. In such aspects, the ammonia and water can be arranged and housed in any convenient manner that can be used in refinery systems.
As discussed above, in certain aspects, the liquid hydrocarbon product stream, e.g., a de-ethanizer feed, is exposed to the ammoniated water wash stream upstream of a de-ethanizer. In such aspects, the ammoniated water wash stream may be injected into the liquid hydrocarbon product stream using any devices or processes convenient for use in a refinery setting. For instance, in one aspect, the ammoniated water wash may be spray injected into the liquid hydrocarbon product stream in such a manner so as to maximize intermixing. In one aspect, the liquid hydrocarbon product stream is exposed to the ammoniated water wash stream in a deethanizer feed conduit in fluid communication with a deethanizer.
In aspects, after exposure of the ammoniated water wash stream, the liquid hydrocarbon product stream can be separated from the water wash stream. In such aspects, the water wash and liquid hydrocarbon product can be separated using any technique that is convenient in a refinery setting, such as a coalescer. In such aspects, the water stream exits the coalescer and can be treated and/or re-used as a water wash stream, while the treated liquid hydrocarbon product stream separately exits the coalescer and can then proceed for downstream processing, such as with a de-ethanizer. In one or more aspects, the pH of the separated water wash stream can be 5.5 or more, 6 or more, or 7 or more, such as up to 9.0 or possibly still higher.
In certain aspects, 80% or more, or 90% or more, or 95% or more, or 99% or more of the organic acids that were present in the liquid hydrocarbon product stream can be removed by the ammoniated water wash and subsequent separation of the water wash stream from the treated liquid hydrocarbon product stream. In certain aspects, 80% or more, or 90% or more, or 95% or more, or 99% or more of the acetic acid, propionic acid, butyric acid, formic acid, or a combination thereof that was present in the liquid hydrocarbon product stream can be removed by the ammoniated water wash and subsequent separation of the water wash stream from the treated liquid hydrocarbon product stream.
As discussed above, in certain aspects, the pH of the water wash exiting the coalescer can be monitored in order to ensure effective organic acid removal from the liquid hydrocarbon product stream. In such an aspect, any convenient pH monitoring device can be utilized. Further in such aspects, the pH mentoring device may be in communication with the ammonia injection system to meter the appropriate amount of ammonia into the water wash stream.
In certain aspects, the ammoniated water wash system can be a one stage or two stage process. For instance, in one aspect, the liquid hydrocarbon product stream can be exposed to a single ammoniated water wash stream and subsequently separated, e.g., via a coalescer, and then proceed to downstream processing. In an alternative aspect, the liquid hydrocarbon product stream can be exposed to a first ammoniated water wash stream and subsequently separated, e.g., via a coalescer, followed by exposure to a second ammoniated water wash stream, separated, and then the treated hydrocarbon product stream can proceed to downstream processing.

Example Ammoniated Water Wash System

FIG. 1 depicts one example system 100 for removing organic acids from a liquid hydrocarbon product stream. The system 100 includes a water injection system 110, an ammonia injection system 120, and a coalescer 130. In certain aspects, the water injection system 110 includes a water wash tank 112 and a pump 114. In the aspect depicted in FIG. 1, ammonia from the ammonia injection system 120 mixes with the water wash upstream of the pump 114, and the pump 114 can inject the ammonia-containing water wash into the hydrocarbon product stream, e.g., a de-ethanizer feed 140, at a position 142 downstream of the pump 114. In such aspects, the mixture of the ammoniated water wash and de-ethanizer feed 140 is sent to the coalescer 130 to separate the de-ethanizer feed 140 from the water wash. The coalescer 130 can be any convenient type of coalescer. In aspects, as discussed above, the ammonia in the water wash aids in solubilizing the organic acids from the de-ethanizer feed into the aqueous phase (e.g., the water wash). The coalescer 130 can separate a hydrocarbon phase (for eventual introduction into the de-ethanizer) from the aqueous phase created by introduction of the water wash. The aqueous phase can include the majority the organic acids that were originally present in the de-ethanizer feed. In such aspects, the hydrocarbon phase exits the coalescer 130 and is sent to the d-eethanizer, while the water wash, ammonia, and organic acids, can exit the coalescer 130 and be further processed, e.g. in order to re-use the water for further water washing. In aspects, the water stream that exits the coalescer 130 can be monitored, e.g., with a pH monitoring device 150, to determine the level of organic acid removal from the de-ethanizer feed 140.
As discussed above, the pH of the water stream separated from the hydrocarbon phase can be monitored to ensure the appropriate amount of organic acids are being removed from the liquid hydrocarbon product. In such aspects, the pH monitoring device 150 can be in communication with a motor 122 in order to inject the appropriate amount of ammonia into the water wash system. Any convenient pH monitoring device can be utilized in the system 100 described herein.
As described above, in certain aspects, the liquid hydrocarbon product stream can be exposed to a two stage ammoniated water wash. In such an aspect, a second coalescer (not shown) may be utilized to separate the water wash from the liquid hydrocarbon product stream. Further, in such an aspect, the separated water wash can be processed for re-use in the system.

Example 1—Simulated One and Two Stage Water Wash of Liquid Hydrocarbon Product Stream

A system similar to that described in FIG. 1, absent the ammonia injection system, was utilized to model water washing of a de-ethanizer feed to determine acid removal. Prior to this modeling, a commercial model was utilized to estimate the concentrations of acetic acid and propionic acid in a separator liquid stream or de-ethanizer feed, and was determined to be between 73-88 ppmw of acetic acid and 48-56 ppmw for propionic acid. A MTG system producing at about 13,500 barrels per day was used in the modeling.
In the modeling, various wash water rates were injected into the de-ethanizer feed without ammonia and a commercial system was used to model the amount of acid taken up by the water phase verses the hydrocarbon phase.
In data not shown, it was estimated that it would take approximately 400 gallons per minute (gpm) of water injection (without ammonia) to reduce the acetic acid concentration by 90%.
In additional data not shown, modeling was also conducted on a two stage water wash system. While the wash water requirements are significantly reduced when compared to the one stage water wash system, high water rates are still required to reduce the acid concentration of the de-ethanizer feed stream in this two stage system. For instance, in data not shown, while 90% acetic acid extraction is possible at a 100 gpm water rate, 200 gpm is needed to extract the same level of propionic acid compared to the single stage case.

Example 2—Simulated Ammoniated Water Wash of Liquid Hydrocarbon Product Stream at Varying Ammonia Levels

In this Example 2, the system and modeling parameters used above were also used in this Example 2, except that this Example 2 include injecting various amounts of ammonia into the water wash.
FIG. 2 depicts a plot of the water wash rates versus the amount of acid recovered in the water with an ammonia injection rate of five pounds per hour. As can be seen in FIG. 2, water wash rates of 100 gpm are required to achieve an approximately 90% recovery of acetic acid in the water wash, where even at 100 gpm less than 60% recovery of propionic acid was achieved. In this particular model and example of FIG. 2, the molar ratio of ammonia to the combined amount of acetic acid and propionic acid is approximately 0.7:1.
FIG. 3 depicts a plot of the water wash rates versus the amount of acid recovered in the water with an ammonia injection rate of seven pounds per hour. As can be seen in FIG. 3, the injection of seven pounds per hour of ammonia at a water wash rate of approximately 25 gpm resulted in approximately a 90% acetic acid recovery in the water wash. However, only approximately about 60% recovery of propionic acid was obtained at the 25 gpm water wash rate. In this particular model and example of FIG. 3, the molar ratio of ammonia to the acetic acid and propionic acid is approximately 1:1.
FIG. 4 depicts a plot of the water wash rates versus the amount of acid recovered in the water with an ammonia injection rate of ten pounds per hour. As can be seen in FIG. 4, unexpectedly, the injection of ten pounds per hour of ammonia at a water wash rate of approximately 10 gpm resulted in over a 99% recovery of acetic acid and over 95% recovery of propionic acid in the water wash. In this particular model and example of FIG. 4, the molar ratio of ammonia to the acetic acid and propionic acid is approximately 1.5:1.
FIG. 5 depicts a plot of the water wash rates versus the amount of acid recovered in the water with an ammonia injection rate of twelve pounds per hour. As can be seen in FIG. 5, the injection of twelve pounds per hour of ammonia at a water wash rate of approximately 10 gpm resulted in over a 99.6% recovery of acetic acid and over 98% recovery of propionic acid in the water wash. In this particular model and example of FIG. 5, the molar ratio of ammonia to the acetic acid and propionic acid is approximately 1.8:1.
As can be seen in FIGS. 4 and 5, with ten and twelve pounds per hour of ammonia, respectively, and a water wash rate of approximately 20-30 gpm, there is a more gradual increase in the amount of acid recovery, compared to between 10-20 gpm water wash rate.
Overall, the results above show that as little as 10-20 gpm of wash water could be employed to extract over 95% of the acetic and propionic acid present in the deethanizer feed, which would greatly reduce the corrosivity of the finished light gasoline product when ten to twelve pounds per hour of ammonia is injected into the water wash stream. The data from these Examples also shows that maintaining the proper ammonia dosage is much more important than the wash water injection rate.
Further, sensitivity studies show that at 20 gpm wash water rate with no ammonia injection the resulting pH of the waste water stream from the coalescer would be approximately 3.5. At an ammonia dosing rate of 12 lbs/hr the waste water stream pH would be 7.7.

Additional Embodiments

Embodiment

1

A method for removing organic acids from a liquid hydrocarbon product stream, comprising: exposing a liquid hydrocarbon product stream comprising naphtha boiling range compounds, light ends, and 1 ppmw or more of organic acids to a water wash stream comprising ammonia to form a treated liquid hydrocarbon product stream, an amount of the water wash stream being 0.5 L to 20 L per barrel of the liquid hydrocarbon product stream, wherein the water wash comprises a) 4.0 g or more of ammonia per barrel of the liquid hydrocarbon product stream, b) a ratio of moles of ammonia in the water wash to moles of the organic acids in the liquid hydrocarbon product stream is 1.5 or more, or c) a combination of a) and b).

Embodiment 2

The method of Embodiment 1, wherein the liquid hydrocarbon product stream has a T95 distillation point of 225° C. or less.

Embodiment 3

The method of any of the above embodiments, wherein the naphtha boiling range compounds comprise a Research Octane Number (RON) of 80 or more (or 90 or more).

Embodiment 4

The method of any of the above embodiments, wherein the liquid hydrocarbon product stream, prior to the exposing, further comprises 10 ppmw to 3000 ppmw of water.

Embodiment 5

The method of any of the above embodiments, wherein the liquid hydrocarbon product stream comprises 1 ppmw to 500 ppmw of the organic acids.

Embodiment 6

The method of any of the above embodiments, further comprising, subsequent to the exposing, separating the water wash stream from the treated liquid hydrocarbon product stream to form a separated water wash stream.

Embodiment 7

The method of Embodiment 6, wherein the separated water wash stream comprises a pH of 5.5 or more (or 6.0 or more, or 7.0 or more).

Embodiment 8

The method of any of the above embodiments, wherein the water wash comprises 7.5 g or more of ammonia per barrel of hydrocarbon liquid product.

Embodiment 9

The method of any of the above embodiments, i) wherein the organic acids comprise organic acids having 5 carbon atoms or less; ii) wherein the organic acids comprise formic acid, acetic acid, propionic acid, butyric acid, or a combination thereof;
or iii) a combination of i) and ii).

Embodiment 10

The method of any of the above embodiments, further comprising separating at least a portion of the C₂₋ hydrocarbons from the treated liquid hydrocarbon product stream.

Embodiment 11

The method of Embodiment 10, wherein the separating at least a portion of the C₂₋ hydrocarbons from the treated liquid hydrocarbon product stream comprises exposing the treated liquid hydrocarbon product stream to a de-ethanizer.

Embodiment 12

The method of any of the above embodiments, further comprising, prior to the exposing the liquid hydrocarbon product stream to the water wash stream comprising ammonia, converting one more oxygenates to an intermediate product stream; and separating at least a portion of water and gas from the intermediate product stream to form the liquid hydrocarbon product stream.

Embodiment 13

The method of any of the above embodiments, wherein the liquid hydrocarbon product stream is derived from an oxygenate conversion process.

Embodiment 14

The method of any of the above embodiments, wherein the liquid hydrocarbon product stream comprises 10 ppmw or more of the organic acids, or 50 ppmw or more.

Embodiment 15

A treated liquid hydrocarbon product stream according to the method of any of Embodiments 1-14.
Although the present invention has been described in terms of specific embodiments, it is not so limited. Suitable alterations/modifications for operation under specific conditions should be apparent to those skilled in the art. It is therefore intended that the following claims be interpreted as covering all such alterations/modifications as fall within the true spirit/scope of the invention.

Claims

1. A method for removing organic acids from a liquid hydrocarbon product stream, comprising:

exposing a liquid hydrocarbon product stream comprising naphtha boiling range compounds, light ends, and 1 ppmw or more of organic acids to a water wash stream comprising ammonia to form a treated liquid hydrocarbon product stream, an amount of the water wash stream being 0.5 L to 20 L per barrel of the liquid hydrocarbon product stream, the water wash comprising 4.0 g or more of ammonia per barrel of the liquid hydrocarbon product stream.

2. The method of claim 1, wherein the liquid hydrocarbon product stream has a T95 distillation point of 225° C. or less.

3. The method of claim 1, wherein the naphtha boiling range compounds comprise a Research Octane Number (RON) of 80 or more.

4. The method of claim 1, wherein the liquid hydrocarbon product stream, prior to the exposing, further comprises 10 ppmw to 3000 ppmw of water.

5. The method of claim 1, wherein the liquid hydrocarbon product stream comprises 1 ppmw to 500 ppmw of the organic acids.

6. The method of claim 1, further comprising, subsequent to the exposing, separating the water wash stream from the treated liquid hydrocarbon product stream to form a separated water wash stream.

7. The method of claim 6, wherein the separated water wash stream comprises a pH of 5.5 or more.

8. The method of claim 1, wherein the water wash comprises 7.5 g or more of ammonia per barrel of hydrocarbon liquid product.

9. The method of claim 1, i) wherein the organic acids comprise organic acids having 5 carbon atoms or less; ii) wherein the organic acids comprise formic acid, acetic acid, propionic acid, butyric acid, or a combination thereof; or iii) a combination of i) and ii).

10. The method of claim 1, wherein a ratio of moles of the ammonia in the water wash to moles of the organic acids in the liquid hydrocarbon product stream is 1.5 or more.

11. The method of claim 1, further comprising separating at least a portion of the C₂₋ hydrocarbons from the treated liquid hydrocarbon product stream.

12. The method of claim 11, wherein the separating at least a portion of the C₂₋ hydrocarbons from the treated liquid hydrocarbon product stream comprises exposing the treated liquid hydrocarbon product stream to a de-ethanizer.

13. The method of claim 1, further comprising, prior to the exposing the liquid hydrocarbon product stream to the water wash stream comprising ammonia, converting one more oxygenates to an intermediate product stream; and separating at least a portion of water and gas from the intermediate product stream to form the liquid hydrocarbon product stream.

14. The method of claim 1, wherein the liquid hydrocarbon product stream is derived from an oxygenate conversion process.

15. A method for removing organic acids from a liquid hydrocarbon product stream, comprising:

exposing a liquid hydrocarbon product stream comprising naphtha boiling range compounds, light ends, and 1 ppmw or more of organic acids to a water wash stream comprising ammonia to form a treated liquid hydrocarbon product stream, wherein the water wash stream is present in an amount of 0.5 L to 20 L per barrel of the liquid hydrocarbon product stream, and wherein a ratio of moles of ammonia in the water wash to moles of the organic acids in the liquid hydrocarbon product stream is 1.5 or more.

16. The method of claim 15, further comprising, subsequent to the exposing, separating the water wash stream from the treated liquid hydrocarbon product stream to form a separated water wash stream.

17. The method of claim 16, wherein the separated water wash stream comprises a pH of 5.5 or more.

18. The method of claim 15, wherein the liquid hydrocarbon product stream comprises 1 ppmw to 500 ppmw of the organic acids.

19. The method of claim 15, i) wherein the organic acids comprise organic acids having 5 carbon atoms or less; ii) wherein the organic acids comprise formic acid, acetic acid, propionic acid, butyric acid, or a combination thereof; or iii) a combination of i) and ii).

20. The method of claim 15, further comprising separating at least a portion of the C₂₋ hydrocarbons from the treated liquid hydrocarbon product stream.