Flare Recovery with Carbon Capture

A flare recovery method includes receiving a flare gas inlet stream that has C1-C8 hydrocarbons. The flare gas inlet stream is separated in a recovery column to produce a C1-C2 hydrocarbon stream and a C3-C8 hydrocarbon stream. The C3-C8 hydrocarbon stream is separated in a separation column to produce a C3 hydrocarbon stream and a C4-C8 hydrocarbon stream. The C4-C8 hydrocarbon stream is transported to a location for blending with crude oil. The C3 hydrocarbon stream is optionally recovered as a saleable product or is combined with the C1-C2 hydrocarbon stream to produce a flare gas stream.

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Description
CROSS-REFERENCE TO RELATED APPLICATION

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

An oil production site generates gas while recovering crude oil from a subterranean formation. The gas can include lighter hydrocarbons such as C1-C8 hydrocarbons, water, nitrogen, carbon dioxide, and other components. The gas is commonly combusted to convert the hydrocarbons in the gas into carbon dioxide and water, which are then released into the environment. The combustion of the gas may be referred to as a flare, and the gas that is combusted may be referred to as flare gas.

SUMMARY

In one aspect, the disclosure includes a method for flare recovery. A flare gas inlet stream is received, wherein the flare gas inlet stream comprises C1-C8 hydrocarbons. The flare gas inlet stream is separated in a recovery column to produce a C1-C2 hydrocarbon stream and a C3-C8 hydrocarbon stream. The C3-C8 hydrocarbon stream is separated in a separation column to produce a C3 hydrocarbon stream and a C4-C8 hydrocarbon stream.

In another aspect, the disclosure includes a set of process equipment for flare recovery. The set of process equipment includes a first multi-stage distillation column and a second multi-stage distillation column. The first multi-stage distillation column receives a flare gas inlet stream and produces a first overhead stream and a first bottoms stream. The second multi-stage distillation column receives the first bottoms stream and produces a second overhead stream and a second bottoms stream. The second bottoms stream comprises C4+ hydrocarbons, and the first multi-stage distillation column and the second multi-stage distillation column are the only two multi-stage distillation columns in the set of process equipment.

In yet another aspect, the disclosure includes a set of process equipment comprising a first column, a second column, an expander, and a compressor. The first column receives a C1-C8 hydrocarbon stream and produces a C1-C2 hydrocarbon stream and a C3-C8 hydrocarbon stream. The second column receives the C3-C8 hydrocarbon stream and produces a C3 hydrocarbon stream and a C4-C8 hydrocarbon stream. The expander expands the C1-C2 hydrocarbon stream to generate energy, and the compressor compresses the C1-C8 hydrocarbon stream using the energy generated by the expander before the C1-C8 hydrocarbon stream is fed to the first column.

These and other features will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the disclosure, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description, wherein like reference numerals represent like parts.

FIG. 1 is a schematic diagram of a system for recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream and a C1-C3 hydrocarbon stream.

FIG. 2 is a schematic diagram of a system for recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream.

FIG. 3 is a detailed diagram of a system of recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream and a C1-C3 hydrocarbon stream.

FIG. 4 is a detailed diagram of a system of recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream.

FIG. 5 is a detailed diagram of a system of recovering flare gas that has additional processing before the inlet stream is fed to the first column.

 DETAILED DESCRIPTION

It should be understood at the outset that although an illustrative implementation of one or more embodiments are provided below, the disclosed systems and/or methods may be implemented using any number of techniques, whether currently known or in existence. The disclosure should in no way be limited to the illustrative implementations, drawings, and techniques illustrated below, including the exemplary designs and implementations illustrated and described herein, but may be modified within the scope of the appended claims along with their full scope of equivalents.

Disclosed herein is a flare recovery process that recovers at least a portion of flare gas that would otherwise be combusted in a flare. In one embodiment, flare gas is separated into a C4+ hydrocarbon stream and a C1-C3 hydrocarbon stream. The C4+ hydrocarbon stream is combined with crude oil to increase the production of crude oil, and the C1-C3 hydrocarbon stream is used to generate energy or is flared. In another embodiment, the flare gas is separated into a C4+ hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream. The C4+ hydrocarbon stream is combined with crude oil, the C3 hydrocarbon stream is transported away by pipe, truck, or rail as saleable product, and the C1-C2 hydrocarbon stream is used to generate energy or is flared. The process reduces carbon emissions because a portion of the flare gas, which would normally be burned and produce carbon dioxide, is used to increase the production of crude oil and optionally to recover a C3 hydrocarbon stream. Specifically, one embodiment of the flare recovery process without C3 hydrocarbon recovery reduces carbon emissions by 27.80 mole %, and another embodiment of the flare recovery process with C3 hydrocarbon recovery reduces carbon emissions by 36.58 mole %, both in comparison to flaring the gas fed to the disclosed process. Furthermore, it should be noted that addition of the C4+ hydrocarbon stream to the crude oil does not cause the crude oil to fail any specifications (e.g., specifications for energy content, vapor pressure, etc.). This is accomplished in part by using two multistage separation columns to remove the C3 hydrocarbon from the C4+ hydrocarbons, where the C3 hydrocarbons would cause the crude oil to fail specifications. Additionally, certain embodiments may provide other benefits such as not requiring any refrigeration, only requiring two columns (e.g., only requiring two multistage separation columns), operating at relatively low pressures (e.g., 200-500 pounds per a square inch gauge (psi)), and having a post separation expansion process that generates energy. These and other features and benefits are described in greater detail below.

FIG. 1 is a schematic diagram of a system 100 for recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream and a C1-C3 hydrocarbon stream. First, a hydrocarbon stream 104 is recovered from a subterranean formation 102. Subterranean formation 102 may include one oil well or may include many oil wells (e.g., 10-100 oil wells), which may be on land or offshore. The hydrocarbon stream 104 contains heavy hydrocarbons (e.g., C9+ hydrocarbons), light hydrocarbons (e.g., C1-C8 hydrocarbons), water, nitrogen, carbon dioxide, and other components. The hydrocarbon stream 104 is passed to a heavy hydrocarbon separator 106 that separates the heavy hydrocarbons from the light hydrocarbons. The heavy hydrocarbon separator 106 produces a light hydrocarbon stream 108 containing the C1-C8 hydrocarbons, water, nitrogen, carbon dioxide, and other components (i.e., the flare gas) and produces a heavy hydrocarbon stream 110 containing the C9+ hydrocarbons. The light hydrocarbon stream 108 is then compressed at a compressor 112 to increase the pressure of the light hydrocarbon stream 108. In some embodiments, system 100 is operated at relatively low pressures such as, but not limited to, about 200 to about 500 psi. The compressor 112 produces a compressed light hydrocarbon stream 114 that is optionally fed to a dryer 116. The dryer 116 may include any equipment that can remove water from a hydrocarbon stream (e.g., a molecular sieve, glycol, etc.). The dryer 116 produces a dehydrated light hydrocarbon stream 118 that is fed to a recovery column 120.

The recovery column 120 is illustratively a distillation column, but can include alternative columns such as scrubbers, strippers, absorbers, adsorbers, packed columns, or a combination of column types. Such columns may employ weirs, downspouts, internal baffles, temperature control elements, and/or pressure control elements. Such columns also may employ some combination of reflux condensers and/or reboilers, including intermediate stage condensers and reboilers. The recovery column 120 generates an overhead recovery column stream 122 and a bottoms recovery column stream 124. The overhead recovery column stream 122 may comprise C1-C3 hydrocarbons, and the bottoms recovery column stream 124 may comprise C3-C8 hydrocarbons.

The bottoms recovery column stream 124 is fed to a separation column 126. Like the recovery column 120, the separation column 126 may also be a distillation column, a scrubber, a stripper, an absorber, an adsorber, a packed column, or a combination of column types. The separation column 126 generates an overhead separation column stream 128 and a bottoms separation column stream 130. The overhead separation column stream 128 may comprise C3 hydrocarbons, and the bottoms separation column stream 130 may comprise C4+ hydrocarbons (e.g., C4-C8 hydrocarbons). The bottoms separation column stream 130 is then optionally combined with the heavy hydrocarbon stream 110 in a mixer 132 to increase the amount of crude oil 134 produced. The mixer 132 may be a dynamic mixer, which contains moving parts to mix the constituent streams, or a static mixer, which may include internal baffles or may simply be a junction that combines the two constituent streams. It should be noted that the bottoms separation column stream 130 can be mixed with the heavy hydrocarbon stream 110 without causing the resulting crude oil 134 to fail any needed specifications such as, but not limited to, vapor pressure or energy content requirements.

Returning to the recovery column 120, the overhead recovery column stream 122 is fed to an expander 136. The expander 136 expands the overhead recovery column stream 122 to produce a cooled stream 138 that is at a lower pressure. The expansion optionally generates an energy stream 140 that can be used in other parts of the system 100. For instance, the energy stream 140 may be used to power the compressor 112. Then, the cooled stream 138 is mixed with the overhead separation column stream 128 in a mixer 142 to produce a residue stream 144. The mixer may be similar to mixer 132. The residue stream 144 may comprise C1-C3 hydrocarbons and may be used for energy recovery in an energy recovery unit 146. For instance, the residue stream 144 can be combusted in the energy recovery unit 146 to generate energy for the compressor 112 (e.g. residue stream 144 fay be a fuel for the compressor 112), the dryer 116 (e.g. for the regeneration gas heater for the molecular sieve unit), or the reboilers for columns 120 and 126. Finally, any remaining gas 148 from the energy recovery unit 146 may be flared in flare 150 as needed.

FIG. 2 is a schematic diagram of a system 200 of recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream. System 200 may be beneficial over system 100 described above in that a C3 hydrocarbon stream is produced. The C3 hydrocarbon stream is a saleable product that meets the specifications for (e.g., energy content and vapor pressure) and can be transported away by truck, rail, pipeline, or by any other means. However, if no means are available to transport the C3 hydrocarbon stream away (e.g., the system 200 is in an isolated location with no truck or pipeline access), then system 100 that does not produce the C3 hydrocarbon stream may be beneficial.

In system 200, components 202, 204, 206, 208, 210, 212, 214, 216, 218, 220, 222, 224, 226, 228, 230, 232, 234, 238, 246, 248, and 250 are the same as or are similar to components 102, 104, 106, 108, 110, 112, 114, 116, 118, 120, 122, 124, 126, 128, 130, 132, 134, 138, 146, 148, and 150 in system 100 and need not be described again. System 200 differs from system 100 in that the overhead separation column stream 228 containing C3 hydrocarbons is not mixed with the cooled stream 238. Instead, the overhead separation column stream 228 (i.e., the C3 hydrocarbon stream) is recovered by itself. The overhead separation column stream 228 is then used for energy recovery and/or is used as a saleable product and is transported away by truck, rail, pipeline, or by any other means. Additionally, the system 200 may optionally include a hydrogen sulfide removal unit 296 to remove hydrogen sulfide if necessary. For instance, the system 200 may use iron sponge, sulfanol, or iron chelate processing to remove hydrogen sulfide. The hydrogen sulfide removal unit 296 generates a sweetened propane product stream 298.

FIG. 3 is a detailed diagram of a system 300 of recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream and a C1-C3 hydrocarbon stream. The system 300 corresponds to system 100 in FIG. 1, but the system 300 is shown in greater detail. The system 300 begins with an inlet stream 302 being fed to a first compressor 304. The inlet stream 302 may comprise C1-C8 hydrocarbons, carbon dioxide, nitrogen, water, and other components included in flare gas. For instance, the inlet stream 302 may comprise about 96-about 100 mole % C1-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The first compressor 304 increases the pressure of the inlet stream 302 to generate a first compressed stream 306. The first compressor 304 may include compressors and/or pumps, which may be driven by electrical, mechanical, hydraulic, or pneumatic means. Specific examples of a first compressor 304 include centrifugal, axial, positive displacement, turbine, rotary, and reciprocating compressors and pumps.

The first compressed stream 306 is fed to a second compressor 308 to generate a second compressed stream 310. The second compressor 308 may include any of the types of compressors listed for first compressor 304. Additionally, a second compressor energy stream 312 is supplied to the second compressor 308 to power the second compressor 308.

The second compressed stream 310 is fed to a first cooler 314 (e.g., an air cooler) that generates a first cooled stream 316. The first cooled stream 316 may then optionally be processed through a dehydrator 318 (e.g., a molecular sieve, etc.) to remove any water from the stream if needed. Following the first cooler 314 and/or the dehydrator 318, the first cooled stream 316 is processed through a first heat exchanger 320 to produce a cooled recovery column inlet stream 322. The recovery column inlet stream 322 is fed to a recovery column 324. Recovery column 324 may include any of the types of columns listed for recovery column 104 in FIG. 1. Additionally, recovery column 324 may include a reboiler and/or a reflux. In the example shown in FIG. 3, recovery column 324 has a recovery column reboiler 326 that receives a recovery column reboiler energy stream 328 to power the recovery column reboiler 326. The reflux for the recovery column includes heat exchanger 354 and reflux separator 358.

The recovery column 324 generates a recovery column overhead stream 330 and a recovery column bottoms stream 332. The recovery column overhead stream 330 may comprise C1-C2 hydrocarbons, C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, the recovery column overhead stream 330 may comprise about 80-about 90 mole % C1-C2 hydrocarbons, about 10-about 20 mole % C3 hydrocarbons, about 0-about 2 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The recovery column bottoms stream 332 may comprise small amounts of C1-C2 hydrocarbons, C3-C8 hydrocarbons, trace amounts of carbon dioxide, and no nitrogen. For instance, the recovery column bottoms stream 332 may comprise about 5-about 15 mole % C1-C2 hydrocarbons, about 85-about 95 mole % C3-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and 0 mole % nitrogen. However, the precise compositions of streams 330 and 332 may vary, and they may contain other components in various amounts.

The recovery column bottoms stream 332 is then cooled through a second cooler 334 (e.g., an air cooler) to produce a separation column inlet stream 336. The separation column inlet stream 336 is fed to the separation column 338. Separation column 338 may include any of the types of columns listed for recovery column 120 in FIG. 1. Additionally, separation column 338 may include a reboiler and/or a compressor. In the example shown in FIG. 3, separation column 338 has a separation column reboiler 340 and a separation column reflux condenser 342. The separation column reboiler 340 receives a separation column reboiler energy stream 344 to power the separation column reboiler 340, and the separation column reflux condenser 342 generates a separation column condenser energy stream 346.

Separation column 338 generates an overhead separation column stream 348 and a bottoms separation column stream 350. The overhead separation column stream 348 may comprise C1-C2 hydrocarbons, C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, and trace amounts of carbon dioxide. For instance, the overhead separation column stream 348 may comprise about 30-about 40 mole % C1-C2 hydrocarbons, about 60-about 70 mole % C3 hydrocarbons, about 0-about 2 mole % C4-C8 hydrocarbons, and about 0-about 2 mole % carbon dioxide. The bottoms separation column stream 350 may comprise no C1-C2 hydrocarbons, trace amounts of C3 hydrocarbons, C4+ hydrocarbons (e.g., C4-C8 hydrocarbons), and no carbon dioxide. For instance, the bottoms separation column stream 350 may comprise about 0 mole % C1-C2 hydrocarbons, about 0-about 2 mole % C3 hydrocarbons, about 98-about 100 mole % C4+ hydrocarbons, and about 0 mole % carbon dioxide. The bottoms separation column stream 350 may then be combined with crude oil (e.g., C9− hydrocarbons) to increase the amount of oil produced, and the overhead separation column stream 348 is fed to a mixer 352.

Returning to the recovery column 324, the recovery column overhead stream 330 is cooled through second heat exchanger 354 to produce a separator inlet stream 356 that is fed to a reflux separator 358. Reflux separator 358 may be a phase separator, which is a vessel that separates an inlet stream into a substantially vapor stream and a substantially liquid stream, such as a knock-out drum, flash drum, reboiler, condenser, or other heat exchanger. Such vessels also may have some internal baffles, temperature control elements, and/or pressure control elements, but generally lack any trays or other type of complex internal structure commonly found in columns.

Reflux separator 358 produces a reflux separator bottoms stream 360 and a reflux separator overhead stream 366. Reflux separator bottoms stream 360 comprises C1 hydrocarbons, C2-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, reflux separator bottoms stream 360 may comprise about 20-about 30 mole % C1 hydrocarbons, about 70-about 80 mole % C2-C3 hydrocarbons, about 0-about 1 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 1 mole % nitrogen. Reflux separator overhead stream 366 comprises C1 hydrocarbons, C2-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, reflux separator overhead stream 366 may comprise about 80-about 90 mole % C1 hydrocarbons, about 10-about 20 mole % C2-C3 hydrocarbons, about 0-about 1 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 5 mole % nitrogen. Reflux separator bottom stream 360 is processed through a reflux pump 362 to produce a recovery column reflux stream 364 that is fed back to the recovery column 324. Reflux pump 362 receives energy through a reflux pump energy stream 363.

Reflux separator overhead stream 366 is then fed to an expander 368. Expander 368 may be an expansion turbine, which reduces the temperature and/or pressure of expander outlet stream 372 and produces an expander energy stream 370 (e.g. mechanical or electrical energy). The expander 368 may be coupled to the first compressor 304 such that the expander energy stream 370 created by the expansion process is used to run the first compressor 304.

From the expander 368, the expander outlet stream 372 is passed through the second heat exchanger 354 to cool the recovery column overhead stream 330 and to produce a heated expander outlet stream 374. Heated expander outlet stream 374 is then combined with overhead separation column stream 348 in mixer 352 to produce a mixer outlet stream 376. Mixer outlet stream 376 comprises C1 hydrocarbons, C2-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, mixer outlet stream 376 may comprise about 75-about 85 mole % C1 hydrocarbons, about 10-about 20 mole % C2-C3 hydrocarbons, about 0-about 1 mole % C4-C8 hydrocarbons, about 0-about 1 mole % carbon dioxide, and about 0-about 5 mole % nitrogen. Mixer outlet stream 376 is passed through first heat exchanger 320 to cool the first cooled stream 316 and to produce a cold residue stream 378. The cold residue stream 378 may be used to generate energy and/or the cold residue stream 378 may be combusted as flare gas. It should be noted that no compressors are included in system 300 after the mixer 352 to increase the pressure and/or the temperature of the cold residue stream 378 as may be required in other systems.

FIG. 4 is a detailed diagram of a system 400 of recovering flare gas in which the flare gas is separated into a C4+hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream. The system 400 corresponds to system 200 in FIG. 2, but the system 400 is shown in greater detail. The system 400 begins with an inlet stream 402 being fed to a first compressor 404. The inlet stream 402 may comprise C1-C8 hydrocarbons, carbon dioxide, nitrogen, water, and other components included in flare gas. For instance, the inlet stream 402 may comprise about 96-about 100 mole % C1-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The first compressor 404 increases the pressure of the inlet stream 402 to generate a first compressed stream 406. The first compressor 404 may include compressors and/or pumps, which may be driven by electrical, mechanical, hydraulic, or pneumatic means. Specific examples of a first compressor 404 include centrifugal, axial, positive displacement, turbine, rotary, and reciprocating compressors and pumps.

The first compressed stream 406 is fed to a second compressor 408 to generate a second compressed stream 410. The second compressor 408 may include any of the types of compressors listed for first compressor 404. Additionally, a second compressor energy stream 412 is supplied to the second compressor 408 to power the second compressor 408.

The second compressed stream 410 is fed to a first cooler 414 (e.g., an air cooler) that generates a first cooled stream 416. The first cooled stream 416 may then optionally be processed through a dehydrator 418 (e.g., a molecular sieve, etc.) to remove any water from the stream if needed. Following the first cooler 414 and/or the dehydrator 418, the first cooled stream 416 is processed through a first heat exchanger 420 to produce a cooled recovery column inlet stream 422. The recovery column inlet stream 422 is fed to a recovery column 424. Recovery column 424 may include any of the types of columns listed for recovery column 120 in FIG. 1. Additionally, recovery column 424 may include a reboiler and/or a reflux. In the example shown in FIG. 4, recovery column 424 has a recovery column reboiler 426 that receives a recovery column reboiler energy stream 428 to power the recovery column reboiler 426.

The recovery column 424 generates a recovery column overhead stream 430 and a recovery column bottoms stream 432. The recovery column overhead stream 430 may comprise C1-C2 hydrocarbons, C3 hydrocarbons, trace amounts of carbon dioxide, trace amounts of nitrogen, and no C4-C8 hydrocarbons. For instance, the recovery column overhead stream 430 may comprise about 80-about 90 mole % C1-C2 hydrocarbons, about 10-about 20 mole % C3 hydrocarbons, about 0-about 2 mole % carbon dioxide, about 0-about 2 mole % nitrogen, and about 0 mole % C4-C8 hydrocarbons. The recovery column bottoms stream 432 may comprise C3-C8 hydrocarbons, trace amounts of C1-C2 hydrocarbons, no carbon dioxide, and no nitrogen. For instance, the recovery column bottoms stream 432 may comprise about 90-about 100 mole % C3-C8 hydrocarbons, about 0-about 10 mole % C1-C2 hydrocarbons, about 0 mole % carbon dioxide, and about 0 mole % nitrogen. However, the precise compositions of streams 430 and 432 may vary, and they may contain other components in various amounts.

The recovery column bottoms stream 432 is then cooled through a second cooler 434 (e.g., an air cooler) to produce a separation column inlet stream 436. The separation column inlet stream 436 is fed to the separation column 438. Separation column 438 may include any of the types of columns listed for recovery column 120 in FIG. 1. Additionally, separation column 438 may include a reboiler and/or a compressor. In the example shown in FIG. 4, separation column 438 has a separation column reboiler 440 and a separation column reflux condenser 442. The separation column reboiler 440 receives a separation column reboiler energy stream 444 to power the separation column reboiler 440, and the separation column reflux condenser 442 generates a separation column condenser energy stream 446.

Separation column 438 generates a vapor stream 447, a propane product stream 448, and a bottoms separation column stream 450. The vapor stream 447 may comprise C1-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and no nitrogen. For instance, the vapor stream 447 may comprise about 90-about 100 mole % C1-C3 hydrocarbons, about 0-about 10 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0 mole % nitrogen. The propane product stream 448 may comprise small amounts of C1-C2 hydrocarbons, C3 hydrocarbons, small amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and no nitrogen. For instance, the propane product stream 448 may comprise about 10-about 20 mole % C1-C2 hydrocarbons, about 70-about 90 mole % C3 hydrocarbons, about 0-about 10 mole % C4-C8 hydrocarbons, about 0-about 1 mole % carbon dioxide, and about 0 mole % nitrogen. The bottoms separation column stream 450 may comprise trace amounts of C1-C3 hydrocarbons, C4+ hydrocarbons (e.g., C4-C8 hydrocarbons), no carbon dioxide, and no nitrogen. For instance, the bottoms separation column stream 450 may comprise about 0-about 5 mole % C1-C3 hydrocarbons, about 95-about 100 mole % C4+ hydrocarbons, about 0 mole % carbon dioxide, and about 0 mole % nitrogen. The bottoms separation column stream 450 may then be combined with crude oil to increase the amount of oil produced, and the propane product stream 448 may be recovered as saleable C3 product. Additionally, the system 400 may optionally include a hydrogen sulfide removal unit 496 to remove hydrogen sulfide if necessary. For instance, the system 400 may use iron sponge, sulfanol, or iron chelate processing to remove hydrogen sulfide. The hydrogen sulfide removal unit 496 generates a sweetened propane product stream 498.

Returning to the recovery column 424, the recovery column overhead stream 430 is cooled through second heat exchanger 454 to produce a separator inlet stream 456 that is fed to a reflux separator 458. Reflux separator 458 may be a phase separator, which is a vessel that separates an inlet stream into a substantially vapor stream and a substantially liquid stream, such as a knock-out drum, flash drum, reboiler, condenser, or other heat exchanger. Such vessels also may have some internal baffles, temperature control elements, and/or pressure control elements, but generally lack any trays or other type of complex internal structure commonly found in columns.

Reflux separator 458 produces a reflux separator bottoms stream 460 and a reflux separator overhead stream 466. The reflux separator bottoms stream 460 comprises C1 hydrocarbons, C2-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, the reflux separator bottoms stream 460 may comprise about 25-about 35 mole % C1 hydrocarbons, about 65-about 75 mole % C3 hydrocarbons, about 0-about 2 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The reflux separator overhead stream 466 comprises C1 hydrocarbons, C2-C3 hydrocarbons, about 0 mole % C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, the reflux separator overhead stream may comprise about 80-about 90 mole % C1 hydrocarbons, about 10-about 20 mole % C2-C3 hydrocarbons, about 0 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The reflux separator bottom stream 460 is processed through a reflux pump 462 to produce a recovery column reflux stream 464 that is fed back to the recovery column 424. Reflux pump 462 receives energy through a reflux pump energy stream 463.

Reflux separator overhead stream 466 is then fed to an expander 468. Expander 468 may be an expansion turbine, which reduces the temperature and/or pressure of expander outlet stream 472 and produces an expander energy stream 470 (e.g. mechanical or electrical energy). The expander 468 may be coupled to the first compressor 404 such that the expander energy stream 470 created by the expansion process is used to run the first compressor 404.

From the expander 468, the expander outlet stream 472 is passed through the second heat exchanger 454 to cool the recovery column overhead stream 430 and to produce a heated expander outlet stream 474. Heated expander outlet stream 474 is then passed through first heat exchanger 420 to cool the first cooled stream 416 and to produce a cold residue stream 478. The cold residue stream 478 may be used to generate energy and/or the cold residue stream 478 may be combusted as flare gas. It should be noted that no compressors are included in system 400 after the reflux separator 458 to increase the pressure and/or the temperature of the cold residue stream 478 as may be required in other systems.

FIG. 5 is a detailed diagram of a system 500 of recovering flare gas in which the flare gas is separated into a C4+ hydrocarbon stream, a C3 hydrocarbon stream, and a C1-C2 hydrocarbon stream. The system 500 is similar to the system 200 in FIG. 2 and the system 400 in FIG. 4, but the system 500 has additional processing before the inlet gas (e.g., the flare gas) is fed to the first column for separation. This additional processing may be beneficial in improving the recovery rates of the C4+ hydrocarbon stream and the C3 hydrocarbon stream. Also, the additional processing may be easier, less expensive, or more practical to implement. Furthermore, it should be noted that the additional processing shown in FIG. 5 can be added to any of the other systems (e.g., system 100 in FIG. 1, system 200 in FIG. 2, system 300 in FIG. 3, and system 400 in FIG. 4).

The system 500 begins with an inlet stream 502 being fed to a first compressor 504. The inlet stream 502 may comprise C1-C8 hydrocarbons, carbon dioxide, nitrogen, water, and other components included in flare gas. For instance, the inlet stream 502 may comprise about 96-about 100 mole % C1-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The first compressor 504 increases the pressure of the inlet stream 502 to generate a first compressed stream 506. The first compressor 504, as well as any of the other compressors in system 500, may include compressors and/or pumps, which may be driven by electrical, mechanical, hydraulic, or pneumatic means. Specific examples of a first compressor 504 include centrifugal, axial, positive displacement, turbine, rotary, and reciprocating compressors and pumps. Additionally, a first compressor energy stream 508 is supplied to the first compressor 504 to power the first compressor 504.

The first compressed stream 506 is fed to a second compressor 510. The second compressor 510 generates a second compressed stream 512 and is supplied with a second compressor energy stream 514. The second compressed stream 512 is fed to a first cooler 516 that generates a first cooled stream 518. The first cooler 516, as well as any of the other coolers in system 500, may comprise a cooler such as an air cooler or may comprise any other type of heat exchanger.

The first cooled stream 518 is fed to a first separator 520. In one embodiment, the first separator 520, as well as other separators in system 500, comprise a two-phase scrubber. However, embodiments of separators in system 500 are not limited to any particular kind of separator and can include any separator such as, but not limited to, a phase separator, a knock-out drum, a flash drum, a reboiler, a condenser, or a heat exchanger. The first separator 520 generates a first separator top stream 522.

The first separator top stream 522 is fed to a third compressor 524. The third compressor 524 generates a third compressed stream 526 and is supplied with a third compressor energy stream 528. The third compressed stream 526 is fed to a second cooler 530 that generates a second cooled stream 532. The second cooled stream 532 is fed to a second separator 534. The second separator 534 generates a second separator top stream 536 and a second separator bottom stream 538.

The second separator top stream 536 is fed to a fourth compressor 540. The fourth compressor 540 generates a fourth compressed stream 542 and is supplied with a fourth compressor energy stream 544. The fourth compressed stream 542 is fed to a third cooler 546 that generates a third cooled stream 548. The third cooled stream 548 is fed to a third separator 550 that generates a third separator top stream 552 and a third separator bottom stream 554. The third separator top stream 552 is cooled through a first heat exchanger 555 to generate a cooled recovery column inlet stream 556 that is fed to the recovery column 558. Returning to the second separator bottom stream 538, the second separator bottom stream 538 is transferred from the second separator 534 by a material transfer device 560 such as, but not limited to, a pump. The material transfer device 560 receives a material transfer device energy stream 562 and generates a material transfer device stream 564. The material transfer device stream 564 and the third separator bottom stream 554 are mixed together in a mixer 566 to generate a mixed recovery column inlet stream 568 that is fed to the recovery column 558.

The recovery column 558 may include any of the types of columns listed for recovery column 120 in FIG. 1. Additionally, recovery column 558 may include a reboiler and/or a reflux. In the example shown in FIG. 5, recovery column 558 has a recovery column reboiler 570 that receives a recovery column reboiler energy stream 572 to power the recovery column reboiler 570.

The recovery column 558 generates a recovery column overhead stream 574 and a recovery column bottoms stream 576. The recovery column overhead stream 574 may comprise C1-C2 hydrocarbons, C3 hydrocarbons, trace amounts of carbon dioxide, trace amounts of nitrogen, and no C4-C8 hydrocarbons. For instance, the recovery column overhead stream 574 may comprise about 75-about 85 mole % C1-C2 hydrocarbons, about 15-about 25 mole % C3 hydrocarbons, about 0-about 3 mole % carbon dioxide, about 0-about 1 mole % nitrogen, and about 0-about 1 mole % C4-C8 hydrocarbons. The recovery column bottoms stream 576 may comprise C3-C8 hydrocarbons, trace amounts of C1-C2 hydrocarbons, no carbon dioxide, and no nitrogen. For instance, the recovery column bottoms stream 576 may comprise about 90-about 100 mole % C3-C8 hydrocarbons, about 0-about 10 mole % C1-C2 hydrocarbons, about 0 mole % carbon dioxide, and about 0 mole % nitrogen. However, the precise compositions of streams 574 and 576 may vary, and they may contain other components in various amounts.

The recovery column bottoms stream 576 is then cooled through a fourth cooler 578 (e.g., an air cooler) to produce a separation column inlet stream 580. The separation column inlet stream 580 is fed to the separation column 582. The separation column 582 may include any of the types of columns listed for recovery column 120 in FIG. 1. Additionally, the separation column 582 may include a reboiler and/or a reflux. In the example shown in FIG. 5, the separation column 582 has a separation column reboiler 584 and a separation column reflux condenser 586. The separation column reboiler 584 receives a separation column reboiler energy stream 588 to power the separation column reboiler 584, and the separation column reflux condenser 586 generates a separation column condenser energy stream 590.

The separation column 582 generates a propane product stream 592 and a bottoms separation column stream 594. The propane product stream 592 may comprise small amounts of C1-C2 hydrocarbons, C3 hydrocarbons, small amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and no nitrogen. For instance, the propane product stream 592 may comprise about 10-about 20 mole % C1-C2 hydrocarbons, about 70-about 90 mole % C3 hydrocarbons, about 0-about 10 mole % C4-C8 hydrocarbons, about 0-about 1 mole % carbon dioxide, and about 0 mole % nitrogen. The bottoms separation column stream 594 may comprise trace amounts of C1-C3 hydrocarbons, C4+ hydrocarbons (e.g., C4-C8 hydrocarbons), no carbon dioxide, and no nitrogen. For instance, the bottoms separation column stream 594 may comprise about 0-about 5 mole % C1-C3 hydrocarbons, about 95-about 100 mole % C4+ hydrocarbons, about 0 mole % carbon dioxide, and about 0 mole % nitrogen. The bottoms separation column stream 594 may then be combined with crude oil to increase the amount of oil produced, and the propane product stream 592 may be recovered as saleable C3 product. Additionally, the system 500 may optionally include a hydrogen sulfide removal unit 596 to remove hydrogen sulfide if necessary. For instance, the system 500 may use iron sponge, sulfanol, or iron chelate processing to remove hydrogen sulfide. The hydrogen sulfide removal unit 596 generates a sweetened propane product stream 598.

Returning to the recovery column 558, the recovery column overhead stream 574 is cooled through a second heat exchanger 600 to produce a separator inlet stream 602 that is fed to a reflux separator 604. The reflux separator 604 may be a phase separator, which is a vessel that separates an inlet stream into a substantially vapor stream and a substantially liquid stream, such as a knock-out drum, flash drum, reboiler, condenser, or other heat exchanger. Such vessels also may have some internal baffles, temperature control elements, and/or pressure control elements, but generally lack any trays or other type of complex internal structure commonly found in columns.

The reflux separator 604 produces a reflux separator bottoms stream 606 and a reflux separator overhead stream 608. The reflux separator bottoms stream 606 comprises C1 hydrocarbons, C2-C3 hydrocarbons, trace amounts of C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, the reflux separator bottoms stream 606 may comprise about 15-about 20 mole % C1 hydrocarbons, about 75-about 80 mole % C2-C3 hydrocarbons, about 3-about 5 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The reflux separator overhead stream 608 comprises C1 hydrocarbons, C2-C3 hydrocarbons, about 0 mole % C4-C8 hydrocarbons, trace amounts of carbon dioxide, and trace amounts of nitrogen. For instance, the reflux separator overhead stream may comprise about 60-about 70 mole % C1 hydrocarbons, about 30-about 40 mole % C2-C3 hydrocarbons, about 0 mole % C4-C8 hydrocarbons, about 0-about 2 mole % carbon dioxide, and about 0-about 2 mole % nitrogen. The reflux separator bottom stream 606 is processed through a reflux pump 610 to produce a recovery column reflux stream 612 that is fed back to the recovery column 558. The reflux pump 610 receives energy through a reflux pump energy stream 614.

The reflux separator overhead stream 608 is then fed to an expander 615. The expander 615 may be an expansion turbine, which reduces the temperature and/or pressure of expander outlet stream 616 and produces an expander energy stream 618 (e.g. mechanical or electrical energy). The expander 615 may be coupled to the first compressor 504 such that the expander energy stream 618 created by the expansion process is used to run the first compressor 504.

From the expander 615, the expander outlet stream 616 is passed through the second heat exchanger 600 to cool the recovery column overhead stream 574 and to produce a heated expander outlet stream 620. The heated expander outlet stream 620 is then passed through first heat exchanger 555 to cool the third separator top stream 552 and to produce a cold residue stream 622. The cold residue stream 622 may be used to generate energy and/or the cold residue stream 622 may be combusted as flare gas. It should be noted that no compressors are included in system 500 after the reflux separator 604 to increase the pressure and/or the temperature of the cold residue stream 622 as may be required in other systems.

Furthermore, it should be noted that the systems 100, 200, 300, 400, and 500 shown in FIGS. 1-5 reduce carbon emissions by recovering hydrocarbons that would otherwise be combusted in a flare and enable those hydrocarbons to be used in energy recovery or for sale. For instance, in simulations, systems 100 and 300 were able to recover more than about 99 mole % of the C4-C8 hydrocarbons that enter the systems 100 and 300, and systems 200, 400, and 500 that include propane product recovery were able to recover more than about 97 mole % of the C4-C8 hydrocarbons and more than about 45 mole % of the C3 hydrocarbons that enter the systems 200, 400, and 500. These hydrocarbon recoveries result in a reduction of carbon emissions by about 27.80 mole % in systems 100 and 300, and result in a reduction of carbon emissions by about 36.58 mole % in systems 200 and 400, as compared to flaring the gas that is fed to systems 100, 200, 300, 400, and 500.

EXAMPLE 1

In one example, a process simulation was performed using the flare recovery system 300 shown in FIG. 3. The simulation was performed using Aspen Technology Inc.'s HYSYS version 8.8 software package. The specified values are indicated by an asterisk (*). The physical properties are provided in degrees Fahrenheit (F), pounds per a square inch gauge (psig), million standard cubic feet per day (MMSCFD), pounds per hour (lb/hr), barrels per a day (barrel/day), and British thermal units per hour (Btu/hr). The material streams, their compositions, and the associated energy streams produced by the simulation are provided in Tables 1, 2, and 3 below, respectively.

TABLE 1A Material Streams Name Recovery Recovery Recovery Separator Inlet Column Inlet Column Overhead Column Bottoms Inlet Stream 302 Stream 322 Stream 330 Stream 332 Stream 356 Vapor Fraction 1.0000 0.9412 1.0000 0.0000 0.8119 Temperature (F.) 100.0* 69.89 6.054 175.0 −46.00* Pressure (psig) 15.00* 365.0 360.0 360.0 355.0 Molar Flow (MMSCFD) 10.00* 10.0000 10.720 1.303 10.730 Mass Flow (lb/hr)  2.63E+04  2.63E+04  2.55E+04 8401  2.56E+04 Liquid Volume Flow 4744 4744 4930 1003 4941 (barrel/day) Heat Flow (Btu/hr) −3.93E+07 −4.06E+07 −4.19E+07 −8.75E+06 −4.38E+07

TABLE 1B Material Streams Name Heated Reflux Reflux Recovery Expander Outlet Expander Outlet Separator Overhead Separator Bottoms Column Reflux Stream 372 Stream 374 Stream 366 Stream 360 Stream 364 Vapor Fraction 0.9321 1.0000 1.0000 0.0000 0.0000 Temperature (F.) −165.4 −5.13 −46.0 −46.0 −44.95 Pressure (psig) 25.00* 20.0 355.0 355.0 455.0 Molar Flow (MMSCFD) 8.715 8.715 8.715 2.019 2.019 Mass Flow (lb/hr)  1.794E+04  1.794E+04  1.794E+04 7617  7.62E+03 Liquid Volume Flow 3752 3752 3752 1189 1189 (barrel/day) Heat Flow (Btu/hr) −3.421E+07 −3.241E+07 −3.310E+07 −1.069E+07 −1.068E+07

TABLE 1C Material Streams Name Cold Second First First Residue Compressed Cooled Compressed Stream 378 Stream 310 Stream 316 Stream 306 Vapor Fraction 1.0000 1.0000 0.9795 1.0000 Temperature (F.) 90.0* 559.5 110.0* 185.7 Pressure (psig) 15.0 375.0 370.0 28.6 Molar Flow (MMSCFD) 9.12 10.00 10.00 10.00 Mass Flow (lb/hr)  1.958E+04  2.628E+04  2.628E+04  2.628E+04 Liquid Volume Flow 3998 4744 4744 4744 (barrel/day) Heat Flow (Btu/hr) −3.340E+07 −3.235E+07 −3.975E+07 −3.819E+07

TABLE 1D Material Streams Name Separation Mixer Overhead Bottoms Column Inlet Outlet Separation Column Separation Column Stream 336 Stream 376 Stream 348 Stream 350 Vapor Fraction 0.0000 1.0000 1.0000 0.0000 Temperature (F.) 120.0* −0.991 109.1 288.6 Pressure (psig) 355.0 20.0 325.0 325.0 Molar Flow (MMSCFD) 1.303 9.117 0.402 0.901 Mass Flow (lb/hr)  8.40E+03  1.96E+04 1644  6.758E+03 Liquid Volume Flow 1003 3998 246.8 756.4 (barrel/day) Heat Flow (Btu/hr) −9.049E+06 −3.426E+07 1.859E+06 −6.224E+06

TABLE 2A Stream Compositions Name Recovery Recovery Recovery Separator Inlet Column Inlet Column Overhead Column Bottoms Inlet Stream 302 Stream 322 Stream 330 Stream 332 Stream 356 Comp Mole Frac (Methane) 0.7465* 0.7465 0.7366 0.0444 0.7358 Comp Mole Frac (Ethane) 0.0822* 0.0822 0.1101 0.0644 0.1102 Comp Mole Frac (Propane) 0.0608* 0.0608 0.1319 0.1986 0.1326 Comp Mole Frac (i-Butane) 0.0187* 0.0187 0.0014 0.1426 0.0014 Comp Mole Frac (n-Butane) 0.0281* 0.0281 0.0002 0.2157 0.0002 Comp Mole Frac (i-Pentane) 0.0150* 0.0150 0.0000 0.1151 0.0000 Comp Mole Frac (n-Pentane) 0.0169* 0.0169 0.0000 0.1297 0.0000 Comp Mole Frac (CO2) 0.0041* 0.0041 0.0044 0.0012 0.0044 Comp Mole Frac (n-Hexane) 0.0050* 0.0050 0.0000 0.0384 0.0000 Comp Mole Frac (n-Heptane) 0.0021* 0.0021 0.0000 0.0161 0.0000 Comp Mole Frac (n-Octane) 0.0044* 0.0044 0.0000 0.0338 0.0000 Comp Mole Frac (Nitrogen) 0.0162* 0.0162 0.0154 0.0000 0.0153

TABLE 2B Stream Compositions Name Heated Reflux Reflux Recovery Expander Outlet Expander Outlet Separator Overhead Separator Bottoms Column Reflux Stream 372 Stream 374 Stream 366 Stream 360 Stream 364 Comp Mole Frac (Methane) 0.8504 0.8504 0.8504 0.2411 0.2411 Comp Mole Frac (Ethane) 0.0851 0.0851 0.0851 0.2186 0.2186 Comp Mole Frac (Propane) 0.0412 0.0412 0.0412 0.5270 0.5270 Comp Mole Frac (i-Butane) 0.0002 0.0002 0.0002 0.0069 0.0069 Comp Mole Frac (n-Butane) 0.0000 0.0000 0.0000 0.0011 0.0011 Comp Mole Frac (i-Pentane) 0.0000 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Pentane) 0.0000 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (CO2) 0.0045 0.0045 0.0045 0.0040 0.0040 Comp Mole Frac (n-Hexane) 0.0000 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Heptane) 0.0000 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Octane) 0.0000 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0186 0.0186 0.0186 0.0013 0.0013

TABLE 2C Stream Compositions Name Cold Second First First Residue Compressed Cooled Compressed Stream 378 Stream 310 Stream 316 Stream 306 Comp Mole Frac (Methane) 0.8193 0.7465 0.7465 0.7465 Comp Mole Frac (Ethane) 0.0905 0.0822 0.0822 0.0822 Comp Mole Frac (Propane) 0.0672 0.0608 0.0608 0.0608 Comp Mole Frac (i-Butane) 0.0006 0.0187 0.0187 0.0187 Comp Mole Frac (n-Butane) 0.0001 0.0281 0.0281 0.0281 Comp Mole Frac (i-Pentane) 0.0000 0.0150 0.0150 0.0150 Comp Mole Frac (n-Pentane) 0.0000 0.0169 0.0169 0.0169 Comp Mole Frac (CO2) 0.0045 0.0041 0.0041 0.0041 Comp Mole Frac (n-Hexane) 0.0000 0.0050 0.0050 0.0050 Comp Mole Frac (n-Heptane) 0.0000 0.0021 0.0021 0.0021 Comp Mole Frac (n-Octane) 0.0000 0.0044 0.0044 0.0044 Comp Mole Frac (Nitrogen) 0.0178 0.0162 0.0162 0.0162

TABLE 2D Stream Compositions Name Separation Mixer Overhead Bottoms Column Inlet Outlet Separation Column Separation Column Stream 336 Stream 376 Stream 348 Stream 350 Comp Mole Frac (Methane) 0.0444 0.8193 0.1442 0.0000 Comp Mole Frac (Ethane) 0.0644 0.0905 0.2089 0.0000 Comp Mole Frac (Propane) 0.1986 0.0672 0.6316 0.0057 Comp Mole Frac (i-Butane) 0.1426 0.0006 0.0104 0.2015 Comp Mole Frac (n-Butane) 0.2157 0.0001 0.0012 0.3113 Comp Mole Frac (i-Pentane) 0.1151 0.0000 0.0000 0.1664 Comp Mole Frac (n-Pentane) 0.1297 0.0000 0.0000 0.1875 Comp Mole Frac (CO2) 0.0012 0.0045 0.0037 0.0000 Comp Mole Frac (n-Hexane) 0.0384 0.0000 0.0000 0.0555 Comp Mole Frac (n-Heptane) 0.0161 0.0000 0.0000 0.0233 Comp Mole Frac (n-Octane) 0.0338 0.0000 0.0000 0.0488 Comp Mole Frac (Nitrogen) 0.0000 0.0178 0.0000 0.0000

TABLE 3 Energy Streams Name Heat Flow (Btu/hr) Recovery Column Reboiler Energy Stream 328 6.470E+05 Reflux Pump Energy Stream 363 5.901E+03 Expander Energy Stream 370 1.108E+06 Second Compressor Energy Stream 312 5.839E+06 Separation Column Condenser Energy Stream 346 1.447E+06 Separation Column Reboiler Energy Stream 344 2.414E+06

EXAMPLE 2

In another example, a process simulation was performed using the flare recovery system 400 shown in FIG. 4. The material streams, their compositions, and the associated energy streams produced by the simulation are provided in Tables 4, 5, and 6 below, respectively.

TABLE 4A Material Streams Name Recovery Recovery Recovery Separator Inlet Column Inlet Column Overhead Column Bottoms Inlet Stream 402 Stream 422 Stream 430 Stream 432 Stream 456 Vapor Fraction 1.0000 0.9334 1.0000 0.0000 0.8119 Temperature (F.) 100.0* 72.44 6.955 252.8 −46.00* Pressure (psig) 15.00* 440.0 425.0 425.0 355.0 Molar Flow (MMSCFD) 10.00* 10.0 10.990 1.291 10.730 Mass Flow (lb/hr)  2.63E+04  2.63E+04  2.58E+04 8548  2.56E+04 Liquid Volume Flow 4744 4744 5045 1011 4941 (barrel/day) Heat Flow (Btu/hr) −3.93E+07 −4.07E+07 −4.29E+07 −8.29E+06 −4.48E+07

TABLE 4B Material Streams Name Expander Reflux Reflux Recovery Outlet Separator Overhead Separator Bottoms Column Reflux Stream 472 Stream 466 Stream 460 Stream 464 Vapor Fraction 0.9246 1.0000 0.0000 0.0000 Temperature (F.) −176.7 −49.0 −49.0 −47.88 Pressure (psig) 25.00* 420.0 420.0 520.0 Molar Flow (MMSCFD) 8.687 8.687 2.286 2.286 Mass Flow (lb/hr)  1.767E+04  1.767E+04 8110  8.11E+03 Liquid Volume Flow 3722 3722 1311 1311 (barrel/day) Heat Flow (Btu/hr) −3.413E+07 −3.301E+07 −1.176E+07 −1.175E+07

TABLE 4C Material Streams Name Cold Second First First Separation Residue Compressed Cooled Compressed Column Inlet Stream 478 Stream 410 Stream 416 Stream 406 Stream 436 Vapor Fraction 1.0000 1.0000 0.9732 1.0000 0.0000 Temperature (F.) 90.0* 587.4 110.0* 186.6 120.0* Pressure (psig) 15.0 450.0* 445.0 28.8 420.0 Molar Flow (MMSCFD) 8.69 10.00 10.00 10.00 1.291 Mass Flow (lb/hr)  1.767E+04  2.628E+04  2.628E+04  2.628E+04  8.55E+03 Liquid Volume Flow 3722 4744 4744 4744 1011 (barrel/day) Heat Flow (Btu/hr) −3.139E+07 −3.185E+07 −3.987E+07 −3.818E+07 −9.097E+06

TABLE 4D Material Streams Name Heated Bottoms Propane Expander Outlet Vapor Separation Column Product Stream 474 Stream 447 Stream 450 Stream 448 Vapor Fraction 1.0000 1.0000 0.0000 0.0000 Temperature (F.) −4.578 123.400 290.6 123.4 Pressure (psig) 20.0 325.0 325.0 325.0 Molar Flow (MMSCFD) 8.687 0.046 0.882 0.364 Mass Flow (lb/hr)  1.767E+04  2.04E+02  6.636E+03 1708 Liquid Volume Flow 3722 30 741.5 239.5 (barrel/day) Heat Flow (Btu/hr) −3.221E+07 −2.168E+05 −6.094E+06 −1.970E+06

TABLE 5A Stream Compositions Name Recovery Recovery Recovery Separator Inlet Column Inlet Column Overhead Column Bottoms Inlet Stream 402 Stream 422 Stream 430 Stream 432 Stream 456 Comp Mole Frac (Methane) 0.7465* 0.7465 0.7402 0.0000 0.7407 Comp Mole Frac (Ethane) 0.0822* 0.0822 0.1202 0.0539 0.1198 Comp Mole Frac (Propane) 0.0608* 0.0608 0.1197 0.2475 0.1196 Comp Mole Frac (i-Butane) 0.0187* 0.0187 0.0000 0.1448 0.0000 Comp Mole Frac (n-Butane) 0.0281* 0.0281 0.0000 0.2176 0.0000 Comp Mole Frac (i-Pentane) 0.0150* 0.0150 0.0000 0.1162 0.0000 Comp Mole Frac (n-Pentane) 0.0169* 0.0169 0.0000 0.1309 0.0000 Comp Mole Frac (CO2) 0.0041* 0.0041 0.0047 0.0000 0.0047 Comp Mole Frac (n-Hexane) 0.0050* 0.0050 0.0000 0.0387 0.0000 Comp Mole Frac (n-Heptane) 0.0021* 0.0021 0.0000 0.0163 0.0000 Comp Mole Frac (n-Octane) 0.0044* 0.0044 0.0000 0.0341 0.0000 Comp Mole Frac (Nitrogen) 0.0162* 0.0162 0.0151 0.0000 0.0151

TABLE 5B Stream Compositions Name Expander Reflux Reflux Recovery Outlet Separator Overhead Separator Bottoms Column Reflux Stream 472 Stream 466 Stream 460 Stream 464 Comp Mole Frac (Methane) 0.8581 0.8581 0.2946 0.2946 Comp Mole Frac (Ethane) 0.0858 0.0858 0.2491 0.2491 Comp Mole Frac (Propane) 0.0327 0.0327 0.4497 0.4497 Comp Mole Frac (i-Butane) 0.0000 0.0000 0.0001 0.0001 Comp Mole Frac (n-Butane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (i-Pentane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Pentane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (CO2) 0.0047 0.0047 0.0049 0.0049 Comp Mole Frac (n-Hexane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Heptane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Octane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0186 0.0186 0.0017 0.0017

TABLE 5C Stream Compositions Name Cold Second First First Separation Residue Compressed Cooled Compressed Column Inlet Stream 478 Stream 410 Stream 416 Stream 406 Stream 436 Comp Mole Frac (Methane) 0.8581 0.7465 0.7465 0.7465 0.0000 Comp Mole Frac (Ethane) 0.0858 0.0822 0.0822 0.0822 0.0539 Comp Mole Frac (Propane) 0.0327 0.0608 0.0608 0.0608 0.2475 Comp Mole Frac (i-Butane) 0.0000 0.0187 0.0187 0.0187 0.1448 Comp Mole Frac (n-Butane) 0.0000 0.0281 0.0281 0.0281 0.2176 Comp Mole Frac (i-Pentane) 0.0000 0.0150 0.0150 0.0150 0.1162 Comp Mole Frac (n-Pentane) 0.0000 0.0169 0.0169 0.0169 0.1309 Comp Mole Frac (CO2) 0.0047 0.0041 0.0041 0.0041 0.0000 Comp Mole Frac (n-Hexane) 0.0000 0.0050 0.0050 0.0050 0.0387 Comp Mole Frac (n-Heptane) 0.0000 0.0021 0.0021 0.0021 0.0163 Comp Mole Frac (n-Octane) 0.0000 0.0044 0.0044 0.0044 0.0341 Comp Mole Frac (Nitrogen) 0.0186 0.0162 0.0162 0.0162 0.0000

TABLE 5D Stream Compositions Name Heated Bottoms Propane Expander Outlet Vapor Separation Column Product Stream 474 Stream 447 Stream 450 Stream 448 Comp Mole Frac (Methane) 0.8581 0.0005 0.0000 0.0001 Comp Mole Frac (Ethane) 0.0858 0.2951 0.0000 0.1540 Comp Mole Frac (Propane) 0.0327 0.6754 0.0036 0.7849 Comp Mole Frac (i-Butane) 0.0000 0.0258 0.1887 0.0535 Comp Mole Frac (n-Butane) 0.0000 0.0029 0.3155 0.0073 Comp Mole Frac (i-Pentane) 0.0000 0.0000 0.1701 0.0000 Comp Mole Frac (n-Pentane) 0.0000 0.0000 0.1917 0.0000 Comp Mole Frac (CO2) 0.0047 0.0003 0.0000 0.0001 Comp Mole Frac (n-Hexane) 0.0000 0.0000 0.0567 0.0000 Comp Mole Frac (n-Heptane) 0.0000 0.0000 0.0238 0.0000 Comp Mole Frac (n-Octane) 0.0000 0.0000 0.0499 0.0000 Comp Mole Frac (Nitrogen) 0.0186 0.0000 0.0000 0.0000

TABLE 6 Energy Streams Name Heat Flow (Btu/hr) Recovery Column Reboiler Energy Stream 428 1.212E+06 Reflux Pump Energy Stream 463 6.516E+03 Expander Energy Stream 470 1.119E+06 Second Compressor Energy Stream 412 6.326E+06 Separation Column Condenser Energy Stream 446 1.036E+06 Separation Column Reboiler Energy Stream 444 1.852E+06

EXAMPLE 3

In another example, a process simulation was performed using the flare recovery system 500 shown in FIG. 5. The material streams, their compositions, and the associated energy streams produced by the simulation are provided in Tables 7, 8, and 9 below, respectively.

TABLE 7A Material Streams Name First Second First First Inlet Compressed Compressed Cooled Separator Top Stream 502 Stream 506 Stream 512 Stream 518 Stream 522 Vapor Fraction 1 1 1 1 1 Temperature (F.) 100 188.443956 300.1735188 120 120 Pressure (psia) 15 32.1574915 80 75 75 Molar Flow (MMSCFD) 257 257 257 257 257 Mass Flow (lb/hr) 810900.77 810900.77 810900.7699 810900.77 810900.77 Liquid Volume Flow 135413.561 135413.561 135413.5606 135413.561 135413.561 (barrel/day) Heat Flow (Btu/hr) −1.135E+09 −1.101E+09 −1054882926 −1.13E+09 −1.13E+09

TABLE 7B Material Streams Name Third Second Second Second Fourth Compressed Cooled Separator Top Separator Bottom Compressed Stream 526 Stream 532 Stream 536 Stream 538 Stream 542 Vapor Fraction 1 0.98614507 1 0 1 Temperature (F.) 260.233317 120 120 120 202.116522 Pressure (psia) 240 235 235 235 450 Molar Flow (MMSCFD) 257 257 253.4392818 3.56071821 253.439282 Mass Flow (lb/hr) 810900.77 810900.77 782550.9724 28349.7976 782550.972 Liquid Volume Flow 135413.561 135413.561 132285.9716 3127.58906 132285.972 (barrel/day) Heat Flow (Btu/hr) −1.077E+09 −1.14E+09 −1110838106 −28779233 −1.084E+09

TABLE 7C Material Streams Name Third Third Third Cooled Recovery Material Cooled Separator Top Separator Bottom Column Inlet Transfer Device Stream 548 Stream 552 Stream 554 Stream 556 Stream 564 Vapor Fraction 0.96927402 1 0 0.96926365 0 Temperature (F.) 120 120 120 100.299814 121.718355 Pressure (psia) 445 445 445 440 445 Molar Flow (MMSCFD) 253.439282 245.652112 7.787169644 245.652112 3.56071821 Mass Flow (lb/hr) 782550.972 733336.483 49214.48963 733336.483 28349.7976 Liquid Volume Flow 132285.972 126356.719 5929.252548 126356.719 3127.58906 (barrel/day) Heat Flow (Btu/hr) −1.125E+09 −1.071E+09 −53566359.2 −1.084E+09 −28739862

TABLE 7D Material Streams Name Mixed Recovery Recovery Recovery Separation Propane Column Inlet Column Overhead Column Bottoms Column Inlet Product Stream 568 Stream 574 Stream 576 Stream 580 Stream 592 Vapor Fraction 0 1 8.92809E−06 0 1 Temperature (F.) 120.890255 52.9001769 252.4654246 120 135.954766 Pressure (psia) 445 435 435 430 325 Molar Flow (MMSCFD) 11.3478879 285.709613 42.54406644 42.5440664 14.0505052 Mass Flow (lb/hr) 77564.2872 816821.106 276117.3047 276117.305 65601.9814 Liquid Volume Flow 9056.84161 145970.174 32797.56012 32797.5601 9180.64315 (barrel/day) Heat Flow (Btu/hr) −82306221 −1.246E+09 −267882455 −294113010 −67725992

TABLE 7E Material Streams Name Bottoms Reflux Reflux Recovery Separation Column Separator Inlet Separator Bottoms Separator Overhead Column Reflux Stream 594 Stream 602 Stream 606 Stream 608 Stream 612 Vapor Fraction 5.1681E−05 0.75261094 0 1 0 Temperature (F.) 285.498201 15 15 15 16.3760167 Pressure (psia) 325 430 430 430 530 Molar Flow (MMSCFD) 28.4935612 288.022756 71.25367932 216.769077 71.2536793 Mass Flow (lb/hr) 210515.323 825108.531 282037.6409 543070.89 282037.641 Liquid Volume Flow 23616.917 147354.936 43354.1739 104000.762 43354.1739 (barrel/day) Heat Flow (Btu/hr) −194018387 −1.31E+09 −385074964 −924461195 −384841408

TABLE 7F Material Streams Name Heated Expander Expander Cold Outlet Outlet Residue Stream 616 Stream 620 Stream 622 Vapor Fraction 0.91049577 1 1 Temperature (F.) −115.26219 39.6566147 90 Pressure (psia) 25 20 15 Molar Flow (MMSCFD) 216.769077 216.769077 216.769077 Mass Flow (lb/hr) 543070.89 543070.89 543070.8597 Liquid Volume Flow 104000.762 104000.762 104000.7599 (barrel/day) Heat Flow (Btu/hr) −957997692 −905556964 −892930137

TABLE 8A Stream Compositions Name First Second First First Inlet Compressed Compressed Cooled Separator Top Stream 502 Stream 506 Stream 512 Stream 518 Stream 522 Comp Mole Frac (Methane) 0.5507 0.5507 0.5507 0.5507 0.5507 Comp Mole Frac (Ethane) 0.1777 0.1777 0.1777 0.1777 0.1777 Comp Mole Frac (Propane) 0.1397 0.1397 0.1397 0.1397 0.1397 Comp Mole Frac (i-Butane) 0.0170 0.0170 0.0170 0.0170 0.0170 Comp Mole Frac (n-Butane) 0.0492 0.0492 0.0492 0.0492 0.0492 Comp Mole Frac (i-Pentane) 0.0120 0.0120 0.0120 0.0120 0.0120 Comp Mole Frac (n-Pentane) 0.0170 0.0170 0.0170 0.0170 0.0170 Comp Mole Frac (CO2) 0.0191 0.0191 0.0191 0.0191 0.0191 Comp Mole Frac (n-Hexane) 0.0080 0.0080 0.0080 0.0080 0.0080 Comp Mole Frac (n-Heptane) 0.0059 0.0059 0.0059 0.0059 0.0059 Comp Mole Frac (n-Octane) 0.0027 0.0027 0.0027 0.0027 0.0027 Comp Mole Frac (Nitrogen) 0.0010 0.0010 0.0010 0.0010 0.0010

TABLE 8B Stream Compositions Name Third Second Second Second Fourth Compressed Cooled Separator Top Separator Bottom Compressed Stream 526 Stream 532 Stream 536 Stream 538 Stream 542 Comp Mole Frac (Methane) 0.5507 0.5507 0.5578 0.0451 0.5578 Comp Mole Frac (Ethane) 0.1777 0.1777 0.1794 0.0597 0.1794 Comp Mole Frac (Propane) 0.1397 0.1397 0.1398 0.1336 0.1398 Comp Mole Frac (i-Butane) 0.0170 0.0170 0.0168 0.0345 0.0168 Comp Mole Frac (n-Butane) 0.0492 0.0492 0.0480 0.1306 0.0480 Comp Mole Frac (i-Pentane) 0.0120 0.0120 0.0113 0.0658 0.0113 Comp Mole Frac (n-Pentane) 0.0170 0.0170 0.0157 0.1148 0.0157 Comp Mole Frac (CO2) 0.0191 0.0191 0.0193 0.0031 0.0193 Comp Mole Frac (n-Hexane) 0.0080 0.0080 0.0064 0.1214 0.0064 Comp Mole Frac (n-Heptane) 0.0059 0.0059 0.0036 0.1716 0.0036 Comp Mole Frac (n-Octane) 0.0027 0.0027 0.0010 0.1197 0.0010 Comp Mole Frac (Nitrogen) 0.0010 0.0010 0.0010 0.0000 0.0010

TABLE 8C Stream Compositions Name Third Third Third Cooled Recovery Material Cooled Separator Top Separator Bottom Column Inlet Transfer Device Stream 548 Stream 552 Stream 554 Stream 556 Stream 564 Comp Mole Frac (Methane) 0.5578 0.5724 0.0945 0.5724 0.0451 Comp Mole Frac (Ethane) 0.1794 0.1817 0.1069 0.1817 0.0597 Comp Mole Frac (Propane) 0.1398 0.1376 0.2079 0.1376 0.1336 Comp Mole Frac (i-Butane) 0.0168 0.0158 0.0472 0.0158 0.0345 Comp Mole Frac (n-Butane) 0.0480 0.0442 0.1696 0.0442 0.1306 Comp Mole Frac (i-Pentane) 0.0113 0.0094 0.0710 0.0094 0.0658 Comp Mole Frac (n-Pentane) 0.0157 0.0125 0.1159 0.0125 0.1148 Comp Mole Frac (CO2) 0.0193 0.0197 0.0059 0.0197 0.0031 Comp Mole Frac (n-Hexane) 0.0064 0.0039 0.0844 0.0039 0.1214 Comp Mole Frac (n-Heptane) 0.0036 0.0015 0.0711 0.0015 0.1716 Comp Mole Frac (n-Octane) 0.0010 0.0002 0.0255 0.0002 0.1197 Comp Mole Frac (Nitrogen) 0.0010 0.0011 0.0001 0.0011 0.0000

TABLE 8D Stream Compositions Name Mixed Recovery Recovery Recovery Separation Propane Column Inlet Column Overhead Column Bottoms Column Inlet Product Stream 568 Stream 574 Stream 576 Stream 580 Stream 592 Comp Mole Frac (Methane) 0.0790 0.5372 0.0000 0.0000 0.0000 Comp Mole Frac (Ethane) 0.0921 0.2239 0.0410 0.0410 0.1242 Comp Mole Frac (Propane) 0.1846 0.2057 0.2910 0.2910 0.8637 Comp Mole Frac (i-Butane) 0.0432 0.0086 0.0939 0.0939 0.0093 Comp Mole Frac (n-Butane) 0.1574 0.0033 0.2985 0.2985 0.0026 Comp Mole Frac (i-Pentane) 0.0694 0.0000 0.0727 0.0727 0.0000 Comp Mole Frac (n-Pentane) 0.1155 0.0000 0.1029 0.1029 0.0000 Comp Mole Frac (CO2) 0.0051 0.0204 0.0000 0.0000 0.0001 Comp Mole Frac (n-Hexane) 0.0960 0.0000 0.0481 0.0481 0.0000 Comp Mole Frac (n-Heptane) 0.1026 0.0000 0.0357 0.0357 0.0000 Comp Mole Frac (n-Octane) 0.0550 0.0000 0.0160 0.0160 0.0000 Comp Mole Frac (Nitrogen) 0.0001 0.0009 0.0000 0.0000 0.0000

TABLE 8E Stream Compositions Name Bottoms Reflux Reflux Recovery Separation Column Separator Inlet Separator Bottoms Separator Overhead Column Reflux Stream 594 Stream 602 Stream 606 Stream 608 Stream 612 Comp Mole Frac (Methane) 0.0000 0.5347 0.1678 0.6553 0.1678 Comp Mole Frac (Ethane) 0.0000 0.2266 0.2812 0.2087 0.2812 Comp Mole Frac (Propane) 0.0086 0.2038 0.4946 0.1082 0.4946 Comp Mole Frac (i-Butane) 0.1356 0.0093 0.0292 0.0027 0.0292 Comp Mole Frac (n-Butane) 0.4444 0.0041 0.0139 0.0009 0.0139 Comp Mole Frac (i-Pentane) 0.1086 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Pentane) 0.1537 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (CO2) 0.0000 0.0206 0.0132 0.0230 0.0132 Comp Mole Frac (n-Hexane) 0.0718 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Heptane) 0.0534 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (n-Octane) 0.0239 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0009 0.0001 0.0012 0.0001

TABLE 8F Stream Compositions Name Heated Expander Expander Cold Outlet Outlet Residue Stream 616 Stream 620 Stream 622 Comp Mole Frac (Methane) 0.6553 0.6553 0.6553 Comp Mole Frac (Ethane) 0.2087 0.2087 0.2087 Comp Mole Frac (Propane) 0.1082 0.1082 0.1082 Comp Mole Frac (i-Butane) 0.0027 0.0027 0.0027 Comp Mole Frac (n-Butane) 0.0009 0.0009 0.0009 Comp Mole Frac (i-Pentane) 0.0000 0.0000 0.0000 Comp Mole Frac (n-Pentane) 0.0000 0.0000 0.0000 Comp Mole Frac (CO2) 0.0230 0.0230 0.0230 Comp Mole Frac (n-Hexane) 0.0000 0.0000 0.0000 Comp Mole Frac (n-Heptane) 0.0000 0.0000 0.0000 Comp Mole Frac (n-Octane) 0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0012 0.0012 0.0012

TABLE 9 Energy Streams Name Heat Flow (Btu/hr) Recovery Column Reboiler Energy Stream 572 3.7156E+07 Reflux Pump Energy Stream 614 2.3356E+05 Expander Energy Stream 618 3.3536E+07 Second Compressor Energy Stream 514 4.6508E+07 Separation Column Condenser Energy Stream 590 4.5804E+07 Separation Column Reboiler Energy Stream 588 7.8161E+07 Third Compressor Energy Stream 528 5.2941E+07 Fourth Compressor Energy Stream 544 2.6413E+07 Material Transfer Device Energy Stream 562 3.9371E+04

EXAMPLE 4

In another example, calculations were performed to determine the carbon reduction for a flare recovery process without C3 recovery and with C3 recovery. Table 10 shows the composition of a 10 MMSCFD inlet flow stream used for the calculations. Table 11 shows the composition of a resulting 9.1 MMSCFD residue flow stream without C3 recovery, and Table 12 shows the composition of a resulting 8.55 MMSCFD residue flow stream with C3 recovery. Based on the calculations, it was determined that the flare recovery process without C3 recovery reduces carbon emissions by about 27.80 mole %. The flare recovery process with C3 recovery reduces carbon emissions by about 36.58 mole %. Both processes recovery 750 barrels per a day of C4+ hydrocarbons that are blended with crude oil. Additionally, the flare recovery process with C3 recovery recovers about 54 mole % of the C3 hydrocarbons and produces 240 barrels per a day of C3 hydrocarbons.

TABLE 10 Inlet Flow Mole % Volume (MMSCFD) Moles/day Carbon # Carbon % Nitrogen 1.62 0.162 427.4406 0 0 CO2 0.41 0.041 108.1794 108.1794 0.00269 Methane 74.65 7.465 19696.57 19696.57 0.489829 Ethane 8.22 0.822 2168.865 4337.731 0.107874 Propane 6.08 0.608 1604.222 4812.665 0.119685 I-Butane 1.87 0.187 493.4037 1973.615 0.049081 N-Butane 2.81 0.281 741.4248 2965.699 0.073753 I-Pentane 1.5 0.15 395.7784 1978.892 0.049213 N-Pentane 1.69 0.169 445.9103 2229.551 0.055446 Hexanes 0.5 0.05 131.9261 791.5567 0.019685 Heptanes 0.21 0.021 55.40897 387.8628 0.009646 Octanes 0.44 0.044 116.095 928.7599 0.023097 Totals 100 10 26385.22 40211.08

TABLE 11 Residue Flow with No C3 Recovery Mole % Volume (MMSCFD) Moles/day Carbon # Carbon % Nitrogen 1.78 0.16198 427.3879 0 0 CO2 0.45 0.04095 108.0475 108.0475 0.003721 Methane 81.93 7.45563 19671.85 19671.85 0.677555 Ethane 9.05 0.82355 2172.955 4345.91 0.149686 Propane 6.72 0.61152 1613.509 4840.528 0.166722 I-Butane 0.06 0.00546 14.40633 57.62533 0.001985 N-Butane 0.01 0.00091 2.401055 9.604222 0.000331 I-Pentane 0 0 0 0 0 N-Pentane 0 0 0 0 0 Hexanes 0 0 0 0 0 Heptanes 0 0 0 0 0 Octanes 0 0 0 0 0 Totals 100 9.1 24010.55 29033.56

TABLE 12 Residue Flow with C3 Recovery Mole % Volume (MMSCFD) Moles/day Carbon # Carbon % Nitrogen 1.89 0.161595 426.372 0 0 CO2 0.45 0.038475 101.5172 101.5172 0.003981 Methane 85.99 7.352145 19398.8 19398.8 0.760637 Ethane 8.38 0.71649 1890.475 3780.95 0.148253 Propane 3.27 0.279585 737.6913 2213.074 0.086776 I-Butane 0.01 0.000855 2.255937 9.023747 0.000354 N-Butane 0 0 0 0 0 I-Pentane 0 0 0 0 0 N-Pentane 0 0 0 0 0 Hexanes 0 0 0 0 0 Heptanes 0 0 0 0 0 Octanes 0 0 0 0 0 Totals 100 8.55 22557.11 25503.36

EXAMPLE 5

In another example, actual inlet stream compositions for a flare recovery process were determined. Table 13 shows the composition of four different inlet streams that can be used in a flare recovery process.

TABLE 13 Flare Recovery Process Inlet Streams Embodi- Embodi- Embodi- Embodi- ment 1 ment 2 ment 3 ment 4 (% mol) (% mol) (% mol) (% mol) Methane (C1) 53.97 79.58 62.51 72.11 Ethane (C2) 17.42 11.58 15.63 15.08 Propane (C3) 13.69 4.29 10.55 7.40 i-Butane (i-C4) 1.67 0.40 1.49 0.76 n-Butane (n-C4) 4.82 0.90 3.79 1.71 i-Pentane (i-C5) 1.18 0.20 0.91 0.31 n-Pentane (n-C5) 1.67 0.20 1.11 0.34 n-Hexane (n-C6) 0.78 0.10 0.51 0.16 n-Heptane (C7) 0.58 0.00 0.19 0.05 n-Octane (C8) 0.19 0.00 0.07 0.02 n-Nonane (C9) 0.07 0.00 0.02 0.01 H2S 0.10 0.20 0.00 0.00 Nitrogen 0.10 1.00 0.42 0.50 CO2 1.87 1.40 1.37 1.41 n-Decane (C10) 0.03 0.00 0.01 0.01 H2O 1.87 0.15 1.41 0.15 Molecular Weight 28.58 20.26 25.64 22.28 (g/mol)

At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from 1 to 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R1, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R1+k*(Ru−R1), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, e.g., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. The use of the term “about” means ±10% of the subsequent number, with the exception that about 0% means ≤0.1%. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present disclosure. The discussion of a reference in the disclosure is not an admission that it is prior art, especially any reference that has a publication date after the priority date of this application. The disclosure of all patents, patent applications, and publications cited in the disclosure are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to the disclosure.

While several embodiments have been provided in the present disclosure, it should be understood that the disclosed systems and methods might be embodied in many other specific forms without departing from the spirit or scope of the present disclosure. The present examples are to be considered as illustrative and not restrictive, and the intention is not to be limited to the details given herein. For example, the various elements or components may be combined or integrated in another system or certain features may be omitted, or not implemented.

In addition, techniques, systems, subsystems, and methods described and illustrated in the various embodiments as discrete or separate may be combined or integrated with other systems, modules, techniques, or methods without departing from the scope of the present disclosure. Other items shown or discussed as coupled or directly coupled or communicating with each other may be indirectly coupled or communicating through some interface, device, or intermediate component whether electrically, mechanically, or otherwise. Other examples of changes, substitutions, and alterations are ascertainable by one skilled in the art and could be made without departing from the spirit and scope disclosed herein.

Claims

1-57. (canceled)

58. A method for flare recovery, comprising:

receiving a gas inlet stream, the gas inlet stream comprising C1-C8 hydrocarbons;
separating the gas inlet stream in a recovery column to produce a C1-C2 hydrocarbon stream and a C3-C8 hydrocarbon stream;
separating the C3-C8 hydrocarbon stream in a separation column to produce a C3 hydrocarbon stream and a C4-C8 hydrocarbon stream;
recovering the C3 hydrocarbon stream; and
combining the C4-C8 hydrocarbon stream with a C9+ hydrocarbon stream.

59. The method of claim 58, wherein the gas inlet stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the C1-C2 hydrocarbon stream comprises 80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the C3-C8 hydrocarbon stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide, the C3 hydrocarbon stream comprises 30-40 mole % C1-C2 hydrocarbons, 60-70 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, and 0-2 mole % carbon dioxide, and the C4-C8 hydrocarbon stream comprises 0 mole % C1-C2 hydrocarbons, 0-2 mole % C3 hydrocarbons, and 98-100 mole % C4-C8 hydrocarbons.

60. The method of claim 58, further comprising:

receiving a raw crude oil stream comprising C1-C9+hydrocarbons;
separating the raw crude oil stream into a C1-C8 hydrocarbon stream and the C9+ hydrocarbon stream, the C1-C8 hydrocarbon stream comprising the gas inlet stream;
combining the C3 hydrocarbon stream that is recovered with the C1-C2 hydrocarbon stream to produce a flare gas stream; and
combusting the flare gas stream.

61. The method of claim 58, further comprising:

receiving a raw crude oil stream comprising C1-C9+ hydrocarbons;
separating the raw crude oil stream into a C1-C8 hydrocarbon stream and the C9+ hydrocarbon stream, the C1-C8 hydrocarbon stream comprising the gas inlet stream;
collecting the C3 hydrocarbon that is recovered as a product, the product meeting energy requirements and vapor pressure requirements for transportation by truck or pipeline; and
combusting the C1-C2 hydrocarbon stream as a flare gas stream.

62. The method of claim 61, further comprising:

expanding the C1-C2 hydrocarbon stream to generate energy; and
compressing the gas inlet stream with the energy generated from the expansion.

63. The method of claim 62, further comprising compressing, cooling, and drying the gas inlet stream before the gas inlet stream is separated by the recovery column.

64. The method of claim 63, wherein the recovery column and the separation column are multi-stage distillation columns, and the recovery column and the separation column are the only two multi-stage distillation columns used in the method.

65. The method of claim 64, wherein no refrigeration processes are used in the flare recovery method.

66. The method of claim 65, wherein the C1-C2 hydrocarbon stream is not compressed after being separated from the C3-C8 hydrocarbon stream.

67. The method of claim 66, wherein the gas inlet stream and the C3-C8 hydrocarbon stream are separated in distillation columns operating at 200 pounds per a square inch (psi) to 500 psi.

68. The method of claim 67, wherein the C3-C8 hydrocarbon stream cannot be combined with raw crude oil stream because a combination of the C3-C8 hydrocarbon stream and the raw crude oil stream would not meet a crude oil specification, and a combination of the C4-C8 hydrocarbon stream and the C9+ hydrocarbon stream meets the crude oil specification.

69. The method of claim 68, wherein the gas inlet stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

70. The method of claim 69, wherein the C1-C2 hydrocarbon stream comprises 80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

71. The method of claim 70, wherein the C3-C8 hydrocarbon stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide.

72. The method of claim 58, further comprising transporting the C4-C8 hydrocarbon stream to a location for blending with raw crude oil.

73. The method of claim 58, further comprising compressing, cooling, and separating the gas inlet stream through a series of compressors, coolers, and separators before separating the gas inlet stream in the recovery column.

74. The method of claim 58, further comprising sweetening the C3 hydrocarbon stream to remove hydrogen sulfide from the C3 hydrocarbon stream.

75. A set of process equipment for flare recovery, comprising:

a first multi-stage distillation column configured to receive a gas inlet stream and produce a first overhead stream and a first bottoms stream, the gas inlet stream comprising C1-C8 hydrocarbons, the first overhead stream comprising C1-C2 hydrocarbons, and the first bottoms stream comprising C3-C8 hydrocarbons;
a second multi-stage distillation column configured to receive the first bottoms stream and produce a second overhead stream and a second bottoms stream, the second overhead stream comprising C3 hydrocarbons, and the second bottoms stream comprising C4-C8 hydrocarbons;
a piping line configured to receive and recover the C3 hydrocarbons; and
a mixer configured to combine the C4-C8 hydrocarbons with C9+ hydrocarbons, and the first multi-stage distillation column and the second multi-stage distillation column are the only two multi-stage distillation columns in the set of process equipment.

76. The set of process equipment of claim 75, wherein the gas inlet stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the first overhead stream comprises 80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the first bottoms stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide, the second overhead stream comprises 30-40 mole % C1-C2 hydrocarbons, 60-70 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, and 0-2 mole % carbon dioxide, and the second bottoms stream comprises 0 mole % C1-C2 hydrocarbons, 0-2 mole % C3 hydrocarbons, and 98-100 mole % C4-C8 hydrocarbons.

77. The set of process equipment of claim 75, further comprising:

a heavy hydrocarbons separator configured to receive a raw crude oil stream comprising C1-C9+hydrocarbons and separate the raw crude oil stream into a C1-C8 hydrocarbon stream and a C9+ hydrocarbon stream, the C1-C8 hydrocarbon stream comprising the gas inlet stream; and
a mixer configured to combine the second bottoms stream with the C9+ hydrocarbon stream.

78. The set of process equipment of claim 77, wherein the first bottoms stream cannot be combined with raw crude oil stream because a combination of the first bottoms stream and the raw crude oil stream would not meet a crude oil specification, and a combination of the second bottoms stream and the C9+ hydrocarbon stream meets the crude oil specification.

79. The set of process equipment of claim 75, wherein the second overhead stream is recovered as C3 product, and the C3 product meets energy requirements and vapor pressure requirements for transportation by truck or pipeline.

80. The set of process equipment of claim 75, wherein the second overhead stream is combined with the first overhead stream to produce a flare gas stream.

81. The set of process equipment of claim 75, further comprising an expander, the expander being configured to expand the first overhead stream to generate energy, and the energy being used to compress the gas inlet stream before the gas inlet stream is fed to the first multi-stage distillation column.

82. The set of process equipment of claim 75, further comprising:

a compressor configured to compress the gas inlet stream;
a cooler configured to cool the compressed gas inlet stream; and
a dehydrator configured to remove water from the cooled and compressed gas inlet stream.

83. The set of process equipment of claim 75, wherein no refrigeration equipment is included within the set of process equipment.

84. The set of process equipment of claim 75, wherein the second bottoms stream is transported to a location for blending with raw crude oil.

85. The set of process equipment of claim 75, wherein the first overhead stream is not compressed after being separated from the first bottoms stream.

86. The set of process equipment of claim 75, wherein the first multi-stage distillation column and the second multi-stage distillation column are configured to be operated in a pressure range of 200 pounds per a square inch gauge (psi) to 500 psi.

87. The set of process equipment of claim 75, wherein the gas inlet stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

88. The set of process equipment of claim 87, wherein the first overhead stream comprises 70-80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

89. The set of process equipment of claim 88, wherein the first bottoms stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide.

90. The set of process equipment of claim 75, further comprising multiple sets of compressors, coolers, and separators, the multiple sets of compressors coolers, and separators are arranged in series, and the multiple sets of compressors coolers, and separators are configured to compress, cool, and separate the gas inlet stream before the gas inlet stream is fed to the first multi-stage distillation column.

91. The set of process equipment of claim 75, further comprising a hydrogen sulfide removal unit that is configured to remove hydrogen sulfide from the second overhead stream.

92. A set of process equipment, comprising:

a first column that is configured to receive a C1-C8 hydrocarbon stream and produce a C1-C2 hydrocarbon stream and a C3-C8 hydrocarbon stream;
a second column that is configured to receive the C3-C8 hydrocarbon stream and produce a C3 hydrocarbon stream and a C4-C8 hydrocarbon stream;
a piping line configured to receive and recover the C3 hydrocarbon stream;
a mixer configured to combine the C4-C8 hydrocarbon stream with a C9+ hydrocarbon stream;
an expander that is configured to expand the C1-C2 hydrocarbon stream to generate energy; and
a compressor that is configured to compress the C1-C8 hydrocarbon stream using the energy generated by the expander before the C1-C8 hydrocarbon stream is fed to the first column.

93. The set of process equipment of claim 92, wherein the C1-C8 hydrocarbon stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the C1-C2 hydrocarbon stream comprises 80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen, the C3-C8 hydrocarbon stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide, the C3 hydrocarbon stream comprises 30-40 mole % C1-C2 hydrocarbons, 60-70 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, and 0-2 mole % carbon dioxide, and the C4-C8 hydrocarbon stream comprises 0 mole % C1-C2 hydrocarbons, 0-2 mole % C3 hydrocarbons, and 98-100 mole % C4-C8 hydrocarbons.

94. The set of process equipment of claim 92, further comprising a heavy hydrocarbons separator that is configured to receive a raw crude oil stream comprising C1-C9+hydrocarbons and separate the raw crude oil stream into the C1-C8 hydrocarbon stream and the C9+ hydrocarbon stream.

95. The set of process equipment of claim 92, further comprising piping that is configured to transfer the C4-C8 hydrocarbon stream to a location for blending with crude oil.

96. The set of process equipment of claim 92, further comprising piping that is configured to transfer the C3 hydrocarbon stream to a location for removal by truck, rail, or pipe.

97. The set of process equipment of claim 92, further comprising a molecular sieve that is configured to remove water from the C1-C8 hydrocarbon stream before the C1-C8 hydrocarbon stream is fed to the first column.

98. The set of process equipment of claim 92, wherein the first column and the second column are configured to be operated at pressures from 200 pounds per a square inch gauge (psi) to 500 psi.

99. The set of process equipment of claim 92, wherein the set of process equipment recovers more than 50 mole % of the C3 hydrocarbons from the C1-C8 hydrocarbon stream.

100. The set of process equipment of claim 92, wherein the C1-C2 hydrocarbon stream is not compressed after being separated from the C3-C8 hydrocarbon stream.

101. The set of process equipment of claim 92, wherein the first column and the second column are configured to be operated in a pressure range of 200 pounds per a square inch gauge (psi) to 500 psi.

102. The set of process equipment of claim 92, wherein the C1-C8 hydrocarbon stream comprises 96-100 mole % C1-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

103. The set of process equipment of claim 102, wherein the C1-C2 hydrocarbon stream comprises 70-80 mole % C1-C2 hydrocarbons, 10-20 mole % C3 hydrocarbons, 0-2 mole % C4-C8 hydrocarbons, 0-2 mole % carbon dioxide, and 0-2 mole % nitrogen.

104. The set of process equipment of claim 103, wherein the C3-C8 hydrocarbon stream comprises 5-15 mole % C1-C2 hydrocarbons, 85-95 mole % C3-C8 hydrocarbons, and 0-2 mole % carbon dioxide.

105. The set of process equipment of claim 92, further comprising multiple sets of compressors, coolers, and separators, the multiple sets of compressors, coolers, and separators being arranged in series, and the multiple sets of compressors, coolers, and separators are configured to compress, cool, and separate the C1-C8 hydrocarbon stream before the C1-C8 hydrocarbon stream is fed to the first column.

106. The set of process equipment of claim 92, further comprising a hydrogen sulfide removal unit that is configured to remove hydrogen sulfide from the C3 hydrocarbon stream.

Patent History
Publication number: 20190063826
Type: Application
Filed: Mar 4, 2016
Publication Date: Feb 28, 2019
Inventor: Eric Prim (Spring, TX)
Application Number: 16/081,548
Classifications
International Classification: F25J 3/02 (20060101); F25J 3/08 (20060101);