NATURAL GAS LIQUIDS RECOVERY PLANT MANAGEMENT SYSTEMS AND METHODS

Abstract

Methods for managing natural gas liquids (NGL) recovery systems may comprise receiving a dryout gas by at least one first exchanger, the at least one first exchanger being part of a first NGL recovery train; receiving the dryout gas from the at least one first exchanger by a first dehydrator; receiving the dryout gas from the first dehydrator by at least one second exchanger, the second exchanger being part of a second NGL recovery train; receiving the dryout gas from the at least one first exchanger and the at least one second exchanger by a third exchanger; and bypassing a flare burner by directing the dryout gas from the third exchanger to a gas sales compressor through a first bypass fluid conduit.

Claims

1. A method for managing a natural gas liquids (NGL) recovery system comprising: receiving a dryout gas by at least one first exchanger, the at least one first exchanger being part of a first NGL recovery train; receiving the dryout gas from the at least one first exchanger by a first dehydrator; receiving the dryout gas from the first dehydrator by at least one second exchanger, the second exchanger being part of a second NGL recovery train; receiving the dryout gas from the at least one first exchanger and the at least one second exchanger by a third exchanger; and bypassing a flare burner by directing the dryout gas from the third exchanger to a gas sales compressor through a first bypass fluid conduit.

2. The method of claim 1, further comprising monitoring data including at least one of flowrate, temperature, or pressure.

3. The method of claim 2, further comprising adjusting at least one of the flowrate, the temperature, or pressure to achieve a sales gas pipeline specification equal to or less than 147 PPMV.

4. The method of claim 1, further comprising monitoring data including at least one of flowrate, temperature, or pressure using a chemical process simulator.

5. The method of claim 4, further comprising adjusting at least one of flowrate, temperature, or pressure to achieve a sales gas pipeline specification equal to or less than 147 PPMV.

6. The method of claim 4, wherein the chemical process simulator is an Aspen HYSYS simulator.

7. The method of claim 1, further comprising: receiving the dryout gas from the at least one first exchanger by a demethanizer; receiving the dryout gas from the demethanizer by at least one fourth exchanger; and bypassing the flare burner by directing the dryout gas from the at least one fourth exchanger to a fuel sales compressor through a second bypass fluid conduit.

8. The method of claim 7, further comprising monitoring data including at least one of flowrate, temperature, or pressure.

9. The method of claim 8, further comprising adjusting at least one of flowrate, temperature, or pressure to achieve a sales gas pipeline specification equal to or less than 147 PPMV.

10. The method of claim 7, further comprising monitoring data including at least one of flowrate, temperature, or pressure using a chemical process simulator.

11. The method of claim 10, further comprising adjusting at least one of flowrate, temperature, or pressure to achieve a sales gas pipeline specification equal to or less than 147 PPMV.

12. The method of claim 10, wherein the chemical process simulator is an Aspen HYSYS simulator.

13. A natural gas liquids (NGL) recovery system comprising: a first NGL recovery train for receiving a dryout gas, the first NGL recovery train comprising a plurality of first exchangers; a first dehydrator in fluid communication with at least one of the pluralities of first exchangers for receiving the dryout gas; a second dehydrator in fluid communication with the first dehydrator for receiving the dryout gas; a second NGL recovery train comprising a plurality of second exchangers, wherein at least one of the pluralities of second exchangers is in fluid communication with the second dehydrator; wherein at least one of the pluralities of first exchangers is in fluid communication with at least one of the pluralities of second exchangers for receiving the dryout gas from the second NGL recovery train; a third NGL recovery train comprising at least one third exchanger in fluid communication with at least one of the pluralities of first exchangers for receiving the dryout gas; and a first bypass fluid conduit in fluid communication with the at least one third exchanger and a sales gas compressor, wherein the first bypass fluid conduit directs the dryout gas to the sales gas compressor and away from a flare burner.

14. The system of claim 13, further comprising a chemical process simulator in data communication with one or more of the at least one of the plurality of first exchangers, the first dehydrator, the second dehydrator, at least one of the plurality of second exchangers, the at least one third exchanger, the first bypass fluid conduit, or the sales gas compressor for monitoring data including at least one of flowrate, temperature, and pressure.

15. The system of claim 14, wherein the chemical process simulator is an Aspen HYSYS simulator.

16. The NGL system of claim 13, further comprising: a demethanizer in fluid communication with at least one of the pluralities of first exchangers for receiving the dryout gas; a fourth exchanger in fluid communication with the demethanizer for receiving the dryout gas; a fifth exchanger in fluid communication with the fourth exchanger for receiving the dryout gas; and a second bypass fluid conduit in fluid communication with the fifth exchanger and a fuel gas compressor, wherein the second bypass fluid conduit directs the dryout gas to the fuel gas compressor and away from the flare burner.

17. The system of claim 7, further comprising a chemical process simulator in data communication with one or more of the at least one of the plurality of first exchangers, the first dehydrator, the second dehydrator, at least one of the plurality of second exchangers, the at least one third exchanger, the first bypass fluid conduit, the sales gas compressor, the demethanizer, the fourth exchanger, the fifth exchanger, the second bypass fluid conduit, or the fuel gas compressor for monitoring data including at least one of flowrate, temperature, and pressure.

18. The system of claim 17, wherein the chemical process simulator is an Aspen HYSYS simulator.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0009] FIG. 1 is a schematic representation of a portion of an NGL recovery plant facility during a dryout process in accordance with one or more embodiments of the present disclosure.

[0010] FIG. 2 is a graph showing the results of moisture content from a chemical process in accordance with one or more embodiments of the present disclosure.

[0011] FIG. 3 is a schematic representation of a portion of an NGL recovery plant facility during a dryout process in accordance with one or more embodiments of the present disclosure.

[0012] FIG. 4 is a graph showing the results of moisture content from a chemical process in accordance with one or more embodiments of the present disclosure.

[0013] FIG. 5 is a schematic representation of a portion of an NGL recovery plant facility during a dryout process using chemical process simulation in accordance with one or more embodiments of the present disclosure.

DETAILED DESCRIPTION

[0014] Embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Like elements in the various figures may be denoted by like reference numerals for consistency. Further, in the following detailed description of embodiments of the present disclosure, numerous specific details are set forth to provide a more thorough understanding of the claimed subject matter. However, it will be apparent to one of ordinary skill in the art that the embodiments disclosed herein may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description. Additionally, it will be apparent to one of ordinary skill in the art that the scale of the elements presented in the accompanying Figures may vary without departing from the scope of the present disclosure.

[0015] Embodiments in accordance with the present disclosure generally relate to NGL recovery plant management systems and methods, more particularly, to systems and methods for minimizing or eliminating flaring of dryout gas (e.g., methane, ethane, and/or propane originating from a sales gas) during NGL recovery plant dryout, start-up operations for reduced greenhouse gas emissions (collectively dryout process or dryout operation). As described herein, the minimization or elimination of dryout gas flaring may be achieved by optimizing dryout parameters (e.g., flow, temperature, and pressure) and blending of dryout wet gas and dry sales gas or fuel gas from NGL recovery trains. As used herein, the terms NGL recovery train or NGL train, and grammatical variants thereof, refer to a processing unit used to convert natural gas to NGL using cryogenic processing.

[0016] In some embodiments, the present disclosure may utilize a chemical process simulator, such as an Aspen HYSYS simulator (available from Aspen Technology, Inc., Massachusetts, USA), of real-time NGL recovery plant data and plant configuration schemes to adjust a dryout process by diverting dryout wet gas to a sales gas compressor and/or diverting demethanizer wet gas to a fuel gas compressor. The simulator is in data communication with one or more aspects of the NGL recovery plant, as described below.

[0017] Accordingly, the systems and methods described herein effectively avoid wasting key NGL raw resources while advantageously meeting sales gas pipelines specifications and sales gas compressor moisture limits. Depending upon a particular NGL recovery plant's configuration, the systems and methods described herein can easily be adjusted to meet such requirements. As a result of implementing a diversion of wet gas from a dryout process to either or both of a sales gas compressor or a fuel gas compressor, flaring can be reduced by as much as 55 MMSCF compared to similar, traditional operations. As a result, upwards of about 3,250 tons of CO.sub.2 abatement can be advantageously realized.

[0018] As provided herein, the system and methods of the present disclosure may be described in terms of a Main System and Method (or MSM) in which wet gas from a dryout process is diverted to a sales gas compressor or a Demethanizer System and Method (or DSM) in which wet gas from a dryout process is diverted to a fuel gas compressor. A combination of each of the MSM and the DSM is contemplated as part of the present disclosure, without limitation.

[0019] The MSM and DSM described herein may rely on NGL recovery plant data, including flowrates, pressure, and temperature of sales gas produced from individual or parallel NGL trains during a dryout process. This plant data can be adjusted on a real-time basis to achieve desired moisture (water) content. More particularly, real-time, online measurements from various process outlets stemming from process fluid conduits (e.g., pipelines, tubulars, and the like) or equipment or embedded sensors within the NGL recovery plant may be used to ensure reduced moisture content and, further, to ensure sales gas water content meets specification requirements.

[0020] As part of a chemical simulation, the dryout wet gas stream is assumed to be saturated with moisture because of the dryout process described above. The simulator allows NGL recovery plant operators to manipulate the plant data to achieve desired sales gas pipelines specifications and sales gas compressor moisture limits, for example, based on the regular, real-time online measurements (see the Example below).

Main System and Method

[0021] As described above, conventional NGL recovery plant dryout processes rely on flaring of dryout wet gas and thus produces significant CO.sub.2 emissions. Differently, the MSM of the present disclosure minimizes or eliminates flaring of dryout wet gas by diverting it to a sales gas compressor in a controlled manner. More particularly, the dryout wet gas is diluted with gas from individual or parallel NGL trains and recycled to achieve sales gas specification requirements.

[0022] Referring now to FIG. 1, illustrated is a schematic representation of a portion of an NGL recovery plant facility 100 during a dryout process in accordance with one or more embodiments of the MSM of the present disclosure. As shown in FIG. 1, three parallel NGL trains are provided. A first NGL recovery train includes exchanger 120, a second NGL recovery train includes exchangers 104, 106, 108, and 110, and a third NGL recovery train includes exchangers 114 and 116. As used herein, the terms exchanger or NGL recovery train exchanger, and grammatical variants thereof, refers to any equipment suitable for heating or cooling a dryout gas stream using another, separate stream; generally, exchangers are relatively simple devices that allow heat to be exchanged between two fluids without the fluids directly contacting one another. As used herein, the term fluid, and grammatical variants thereof, refers to a flowable phase of matter including gases and liquids, which may or may not include solid particulates. Examples of suitable exchangers may include, but are not limited to, shell and tube exchangers, bayonet exchangers, double pipe exchangers, plate fin exchangers, air coolers, evaporators, condensers, reboilers, and any combination thereof. In one or more embodiments of the present disclosure, the exchangers include shell and tube exchangers along an NGL train.

[0023] With continued reference to FIG. 1, dryout gas 101 may be received by gas dehydrator 102 via fluid conduit 130 in fluid communication therewith. As used herein, the term fluid conduit, and grammatical variants thereof, refers to any conduit capable of allowing fluid flow including, for example, pipelines, tubulars, and the like, and any combination thereof.

[0024] Gas dehydrator 102 may be a single dehydrator or comprise multiple dehydrators (e.g., two or three dehydrators arranged in series or in parallel), without departing from the scope of the present disclosure. Gas dehydrator 102 may be configured to remove water from a dryout gas stream (as well as other gases as part of an NGL recovery process, such as from a refined gas stream). In one or more instances, examples of a suitable gas dehydrator of the present disclosure may include, but are not limited to, molecular sieves, refrigerators, liquid desiccants (e.g., glycol), solid desiccants (e.g., silica or calcium chloride), and any combination thereof.

[0025] Gas dehydrator 102 may be in fluid communication with the second NGL recovery train via exchanger 104 and fluid conduit 132. Dryout gas 101 may pass from gas dehydrator 102 and to the second NGL recovery train through at least exchangers 104, 106, and 108, each in fluid communication via fluid conduits 134 and 136, respectively. A first portion of the dryout gas 101 may exit exchanger 108 to the first NGL recovery train exchanger 120 in fluid communication therewith via fluid conduit 138; a second portion of the dryout gas 101 may exit exchanger 108 and continue to exchanger 110 in fluid communication therewith via fluid conduit 140.

[0026] As shown, exchanger 110, as part of the second NGL recovery train, may be in fluid communication with separator 112 via fluid conduit 142. Separator 112 may be any process equipment suitable for separating liquid from the feed dryout gas 101 received therein (i.e., phase separation). Any separated liquid from dryout gas 101 may be accumulated within or removed from separator 112 to be used for other processes or for proper disposal. Examples of suitable separators of the present disclosure may include, but are not limited to, a knock-out drum separator, a membrane separator, a flash drum separator, and the like, and any combination thereof. Moreover, any of the separators of the present disclosure may be arranged in series, parallel, or combinations thereof, without limitation.

[0027] Dryout gas 101 may pass from separator 112 to the third NGL recovery train via fluid conduit 144 interposing separator 112 and exchanger 114. A first portion of the dryout gas 101 may exit exchanger 114 to the second NGL recovery train exchanger 108 in fluid communication therewith via fluid conduit 148; a second portion of the dryout gas 101 may exit exchanger 114 and continue to exchanger 116 in fluid communication therewith via fluid conduit 150. As shown in FIG. 1, exchanger 116 may be in fluid communication with separator 118 via fluid conduit 152, which may be any of the above-described separator types or configurations, without limitation. Thereafter, dryout gas 101 may be cycled from separator 118 to exchanger 114 in fluid communication via fluid conduit 154.

[0028] With continued reference to FIG. 1, the dryout gas 101 that flows through exchanger 108 may exit to exchanger 120 shell-side via fluid conduit 138, as previously described. Traditionally, exchanger 120 would be in fluid communication with open valve 126 via fluid conduit 156 and via fluid conduit 158, the dryout gas 101 (now wet gas) would be burned using flare burner 124. Fluid conduit 158 and flare burner 124 are shown in dashed lines, along with an X to indicate that this traditional burning is not part of the MSM according to the present disclosure, but rather part of the prior art. Instead, the MSM of the present disclosure redirects dryout gas 101 from fluid conduit 156 by bypassing closed valve 128 through fluid conduit 160 (bypass fluid conduit) and directing it to sales gas compressor 122.

[0029] As provided in FIG. 1, open valve 126 is indicated as having internal transparency, whereas closed valve 128 is indicated as having internal opacity; this graphic distinction is used throughout the present disclosure. The various valves of the present disclosure, including valve 126 and valve 128, may be any of several valve types suitable for use as part of an NGL recovery plant dryout process. Examples of suitable valves for use according to the present disclosure may include, but are not limited to, pressure control valves (PCV), flow control valves (FCV), zone valves (ZV), level control valves (LCV), motor operated valves (MOV), temperature control valves (TCV), butterfly valves (BFV), air operated valves (AOV), a pressure relieve valve (VLV), and the like, and any combination thereof. In one or more aspects, valve 126 may be a PCV or a FCV and valve 128 may be a ZV.

[0030] As used herein, the term sales gas compressor, and grammatical variants thereof, refers to a compressor that is used to transport utility gas from a gas processing plant (e.g., NGL recovery plant) to a location for consumption (e.g., in homes or factories). Any of the compressors of the present disclosure, including sales gas compressor 122, include any process equipment suitable for increasing the pressure, temperature, and/or density of a dryout gas stream. Examples of suitable compressors for use in the systems and methods of the present disclosure may include, but are not limited to, reciprocating compressors, centrifugal compressors, axial compressors, positive displacement compressors, rotary compressors, turbine compressors, and the like, and any combination thereof. Moreover, any of the compressors of the present disclosure may be arranged in series, parallel, or combinations thereof, without limitation.

[0031] Various real-time plant data may be obtained during the MSM, such as for use with a chemical process simulator as described above. For example, flowrate, temperature, pressure, and/or moisture may be measured at outlets in fluid communication with one or more of the fluid conduits or one or more of the equipment (i.e., dehydrator, separators, exchangers, compressors) shown in FIG. 1, without limitation. The real-time plant data may be gathered by taking physical samples or otherwise by inclusion of embedded sensors within fluid conduits or equipment. Suitable sensors may measure one or more types of real-time plant data and may include, but are not limited to, differential pressure flow sensors, thermal flow sensors, negative temperature coefficient thermistor sensors, resistance temperature detector sensors, thermocouple sensors, and the like, and any combination thereof.

[0032] Referring now to FIG. 2, illustrated is a graph showing results from a chemical process according to the MSM described above. As shown, the moisture content target is 20 PPMV during the measured dryout process. After less than 4 hours and 48 minutes, the moisture content during the dryout process as a result of employing the MSM was below the moisture content target and continued to decline until measurement was ceased at 6 hours.

[0033] Accordingly, the present disclosure further provides methods including receiving a dryout gas by at least one first exchanger, the at least one first exchanger being part of a first NGL recovery train. Thereafter, the dryout gas may be received from the at least one first exchanger by a first dehydrator, followed by receiving the dryout gas from the first dehydrator by at least one second exchanger, the second exchanger being part of a second NGL recovery train. Next, the method includes receiving the dryout gas from the at least one first exchanger and the at least one second exchanger by a third exchanger, and additionally the method includes bypassing a flare burner by directing the dryout gas from the third exchanger to a gas sales compressor through a first bypass fluid conduit. In some embodiments, the methods further include the DSM process described in greater detail below, encompassing receiving the dryout gas from the at least one first exchanger by a demethanizer. The dryout gas then passes through two exchangers and bypasses the flare burner by directing the dryout gas to a fuel sales compressor through a second bypass fluid conduit.

[0034] Accordingly, the MSM of the present disclosure may be used to minimize or eliminate flaring, resulting in a substantial reduction in CO.sub.2 emissions.

Demethanizer System and Method

[0035] As described above, conventional NGL recovery plant dryout processes rely on flaring of dryout wet gas and thus produces significant CO.sub.2 emissions. Differently, the DSM of the present disclosure minimizes or eliminates flaring of dryout wet gas by diverting it to a fuel gas compressor in a controlled manner; the composition of the dryout wet gas is moreover similar to that of the specification of fuel gas. More particularly, the dryout wet gas is diluted with high-pressure residue gas to achieve sales gas specification requirements, alone or in combination with the MSM described above.

[0036] Referring now to FIG. 3, and with continued reference to FIG. 1, illustrated is a simplified schematic representation of a portion of an NGL recovery plant facility 300 as part of a dryout process in accordance with one or more embodiments of the DSM of the present disclosure.

[0037] It is to be appreciated that the various valves described with reference to FIG. 3 may be any type of valve as described above with reference to FIG. 1 without limitation; any of the various exchangers described with reference to FIG. 3 may be any type and in any configuration as described above with reference to FIG. 1 without limitation, and the fuel gas compressor of FIG. 3 may be any type of compressor and in any configuration as described with reference to FIG. 1 without limitation.

[0038] As shown in FIG. 3, a demethanizer 302 is provided. As used herein, the term demethanizer, and grammatical variants thereof, refers to an equipment column used as part of an NGL recovery process to separate methane rich residue gas from heavier hydrocarbons. The demethanizer may comprise various internal components, such as trays or packing, to effectively serve as a distillation tower to boil off methane gas.

[0039] As shown in FIG. 3, the demethanizer 302 may be in fluid communication with multiple fluid conduits 320, 322, and 324, to receive chilled natural gas during operation. Each of fluid conduits 320 and 322 may have arranged thereon open valves 328 and 330, respectfully. Fluid conduit 324 may have been arranged thereon closed valve 332, permitting fluid communication between conduit 324 and fluid conduit 354, as described below. In one or more embodiments, open valves 328 and 330 may be bypass valves that are open one crack to bypass fluid conduits having closed valves arranged thereon (not shown). It is to be appreciated that while three fluid conduits are shown in fluid communication with demethanizer 302, fewer or greater than three fluid conduits may be used in fluid communication with the demethanizer 302, without limitation.

[0040] With continued reference to FIG. 3, dryout gas 301 may be received by exchanger 102 (see also FIG. 1) via fluid conduit 326 in fluid communication therewith. Fluid conduit 326 may have arranged thereon open valve 334. In some embodiments, open valve 334 may be a PCV.

[0041] As shown, exchanger 102 may be in fluid communication with exchanger 310 via fluid conduit 336 to receive the dryout gas 301 therethrough. From the exchanger 310, the dryout gas 301 gas may pass to demethanizer 302 via fluid conduit 338 in fluid communication therewith. The demethanizer 302 may be in fluid communication with fluid conduit 340 having open valve 342. In one or more aspects, valve 342 may be an AOV valve. As shown, fluid conduit 340 may bifurcate and be in fluid communication with two pumps 344 and 346 and two open valves 348 and 350, respectfully, for drawing dryout gas 301 from the demethanizer 302. In various aspects, open valves 348 and 350 may be MOVs. Thereafter, fluid conduit 304 may be reunited into a single fluid conduit.

[0042] A first portion of the dryout gas 301 may exit fluid conduit 340 through open valve 352 to fluid conduit 354 in fluid communication therewith. In some instances, open valve 352 may be an LCV valve. Fluid conduit 354 may have arranged thereon open valve 356 and may divert dryout gas 301 to demethanizer 302 through fluid conduit 324. In various aspects, open valve 356 may be an FCV valve that is 50% open.

[0043] A second portion of the dryout gas 301 may exit fluid conduit 340 through open valve 352 to fluid conduit 358 in fluid communication therewith. Fluid conduit 358 may have arranged thereon open valve 360 and may divert dryout gas 301 to demethanizer 302 through fluid conduit 338. In various aspects, open valve 360 may be a TCV.

[0044] Lastly, a third portion of the dryout gas 301 may exit fluid conduit 340 through open valve 352 to fluid conduit 362 in fluid communication therewith. Fluid conduit 362 arranged thereon open valve 364 to exchanger 102 (and eventually again to demethanizer 302). In various aspects, open valve 364 may be a BFV.

[0045] Dryout gas 301 may exit demethanizer 302 as dryout wet gas via fluid conduit 366 to exchanger 304 in fluid communication therewith. Fluid conduit 366 may have been arranged thereon open valve 368. Exchanger 302 may be arranged in series and in fluid communication with exchanger 306 via fluid conduit 370 to receive the dryout gas 301.

[0046] With continued reference to FIG. 3, traditionally, exchanger 306 would be in fluid communication with fluid conduit 372 and the dryout gas 301 would be burned using flare burner 124 (see also FIG. 1). Fluid conduit 372 and flare burner 124 are shown in dashed lines, along with an X to indicate that this traditional burning is not part of the DSM according to the present disclosure, but rather part of the prior art. Instead, the DSM of the present disclosure redirects dryout gas 301 from fluid conduit 374 by bypassing closed valve 375 through fluid conduit 376 (bypass fluid conduit) and directing it to fuel gas compressor 312.

[0047] As used herein, the term fuel gas compressor, and grammatical variants thereof, refers to a compressor that is used to process non-sales gas to be used as fuel to drive various processes and systems as part of a NGL recovery plant.

[0048] Like the MSM, various real-time plant data may be obtained during the DSM, such as for use with a chemical process simulator as described above. For example, flowrate, temperature, pressure, and/or moisture may be measured at outlets in fluid communication with one or more of the fluid conduits or one or more of the equipment (i.e., demethanizer, exchangers, compressors) shown in FIG. 3, without limitation. The real-time plant data may be gathered by taking physical samples or otherwise by inclusion of embedded sensors within fluid conduits or equipment. Suitable sensors may include any of the types of sensors described above with reference to FIG. 1, and in any combination and configuration, without limitation.

[0049] Referring now to FIG. 4, illustrated is a graph showing results from a chemical process according to the DSM described above. As shown, the moisture content target is 20 PPMV during the measured dryout process. After significantly less than 8 hours and 24 minutes, the moisture content during the dryout process as a result of employing the DSM was below the moisture content target and continued to decline until measurement was ceased after 10 hours and 48 minutes.

[0050] Accordingly, the DSM of the present disclosure may be used to minimize or eliminate flaring, resulting in a substantial reduction in CO.sub.2 emissions.

[0051] To facilitate a better understanding of the embodiments of the present disclosure, the following example of a preferred or representative embodiment is given. In no way should the following example be read to limit, or to define, the scope of the present disclosure.

Example

[0052] In this Example, an Aspen HYSYS simulator was used to simulate the MSM of the present disclosure. FIG. 5 is a schematic portion of an NGL recovery plant facility 500 during a dryout process created using Aspen HYSYS simulation. As shown in FIG. 5, the specifications of sale of the sales gas compressor from the MSM dryout process described herein with three running trains meets sales gas pipeline specifications. Temperature, pressure, and flowrate were measured at various stages, as described below.

[0053] Referring specifically to FIG. 5, high-pressure (HP) gas stream 502 flows into the inlet of tee 504. The HP gas 502 is characterized by the plant data shown in Table 1 below as it flows to tee 504. The unit MMSCFD refers to million standard cubic feet per day.

TABLE-US-00001 TABLE 1 Measurement Result Molar Flow 400.0 MMSCFD Pressure 380.0 psig Temperature 140.0 F. Water Content 0.9477 lb/MMSCF Water Dew Point 24.6 F.

[0054] Stream 502 is bifurcated by tee 504. A first portion of stream 502 flows from tee 504 as stream 505. Stream 505 flows to compressor 506, which also receives dryout gas at molar flow at 9.807 MMSCFD, forming stream 510. Stream 510 is then bifurcated by tee 512 into stream 514 and stream 516. Stream 514 flows through heating exchanger 518, open VLV valve 520, gas booster 522, and mixer 524. The stream 514 between the gas booster 522 and the mixer 524 is characterized by the plant data shown in Table 2 below.

TABLE-US-00002 TABLE 2 Measurement Result Pressure 165.0 psig Temperature 167.6 F.

[0055] Low-pressure (LP) gas stream 526 also flows to mixer 524. The LP gas stream 526 is characterized by the plant data shown in Table 3 below as it flows to mixer 524.

TABLE-US-00003 TABLE 3 Measurement Result Molar Flow 160.0 MMSCFD Pressure 165.0 psig Temperature 140.0 F. Water Content 0.9477 lb/MMSCF Water Dew Point 36.84 F.

[0056] The LP gas stream 526 mixes with stream 514 to form stream 528. Stream 528 flows through separator 530, compressor 532, cooling exchanger 534, and tee 536. Stream 528 is characterized by the plant data shown in Table 4 below as it flows between mixer 524 and tee 536.

TABLE-US-00004 TABLE 4 Measurement Result Molar Flow 160.0 MMSCFD Temperature 140.0 F. Water Content 0.9477 lb/MMSCF Water Dew Point 36.84 F.

[0057] Referring back to stream 516 flowing through tee 512, stream 516 flows through heating exchanger 538 and gas booster 540 at a molar flow of 9.087 MMSCFD. From gas booster 540, stream 516 flows to mixer 542. Stream 516 is characterized by the plant data shown in Table 5 below as it flows between gas booster 540 and mixer 542.

TABLE-US-00005 TABLE 5 Measurement Result Molar Flow 9.159 MMSCFD Pressure 390.0 psig Temperature 140.0 F.

[0058] Referring back to stream 502, stream 502 flows through tee 504 to bifurcate and form stream 546. Stream 546 mixes with stream 516 in mixer 524 to form stream 548. Stream 548 flows to tee 536. Stream 548 is characterized by the plant data shown in Table 6 below as it flows between mixer 542 and tee 536.

TABLE-US-00006 TABLE 6 Measurement Result Pressure 380.0 psig Temperature 140.0 F. Water Content 9.421 lb/MMSCF Water Dew Point 25.87 F.

[0059] Streams 548 and 528 combine at tee 536 to form stream 550. Stream 550 flows through separator 552, compressor 554, and cooling exchanger 556. Stream 550 is characterized by the plant data shown in Table 7 below as it flows between tee 536 and cooling exchanger 556.

TABLE-US-00007 TABLE 7 Measurement Result Molar Flow 560.1 MMSCFD Pressure 380.0 psig Temperature 134.3 F. Water Content 7.000 lb/MMSCF Water Dew Point 18.72 F.

[0060] As part of the MSM described herein, the stream 550 is recycled as stream 558 to join stream 514 one or more times, and recycled as stream 560 to join 505 one or more times. Stream 562 flows to a sales gas compressor (not shown) at a water content of 7.0 lb/MMSCF, meeting required sales gas pipeline specifications.

[0061] Accordingly, the present disclosure provides methods and systems that are well adapted for minimizing or eliminating flaring of dryout gas during NGL recovery plant dryout, start-up operations for reduced greenhouse gas emissions.

[0062] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the invention. As used herein, for example, the singular forms a, an, and the are intended to include the plural forms as well, unless the context clearly indicates otherwise. It will be further understood that the terms contains, containing, includes, including, comprises, and/or comprising, and variations thereof, when used in this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups thereof.

[0063] Terms of orientation are used herein merely for purposes of convention and referencing and are not to be construed as limiting. However, it is recognized these terms could be used with reference to an operator or user. Accordingly, no limitations are implied or to be inferred. In addition, the use of ordinal numbers (e.g., first, second, third, etc.) is for distinction and not counting. For example, the use of third does not imply there must be a corresponding first or second. Also, if used herein, the terms coupled or coupled to or connected or connected to or attached or attached to may indicate establishing either a direct or indirect connection, and is not limited to either unless expressly referenced as such.

[0064] While the disclosure has described several exemplary embodiments, it will be understood by those skilled in the art that various changes can be made, and equivalents can be substituted for elements thereof, without departing from the spirit and scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation, or material to embodiments of the disclosure without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiments disclosed, or to the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, or component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.