Natural Gas Liquids Recovery Plant Management Systems and Methods

The present disclosure relates generally to natural gas liquids recovery plant management systems and methods and, more particularly, to systems and methods for minimizing or eliminating flaring of dryout gas during natural gas liquids recovery plant operations for reduced greenhouse gas emissions.

As the global demand for energy grows, greenhouse gas emissions into the earth's atmosphere also increase. This growth in greenhouse gas emissions disrupts the balance of the earth's ecosystem and affects all life. Greenhouse gases, particularly carbon dioxide (CO), undesirably absorb and emit radiation into the atmosphere, causing a “greenhouse effect.” Attention to reducing greenhouse gases has focused on COemissions due to the ever-increasing combustion processes emitting COas a waste product into the environment.

Lawmakers worldwide have recently focused their efforts on cutting COemissions by championing carbon neutrality by legislating the development of new technologies and changing tax, penalty, and incentive programs to reduce COemissions and to develop new net zero carbon integrative processes. The International Energy Agency set forth a pathway for the global energy sector to reach net zero COemissions by 2050, which has the potential to abate about 80 gigatons of COreleased into the atmosphere. Accordingly, many countries and organizations have pledged to achieve this goal.

During conventional gas plant natural gas liquids (NGL) recovery, a significant way in which COescapes into the atmosphere is through the flaring of wet gas. NGL processing is achieved by means of cryogenic processing, with minimum temperatures as low as −80° C. or −100° C. To avoid hydrate formation during cryogenic processing, NGL, often naturally-fully or substantially-fully saturated with water vapor, must be dehydrated to less than 10 parts per million by volume (PPMV) to meet sales gas pipeline specifications of equal to or less than 147 PPMV (equivalent to 7 pounds per million standard cubic feet; MMSCF). Dryout gas is itself typically dry to remove the water vapor from raw NGL and other gas plant equipment and piping during a dryout process. Thereafter, water-saturated dryout gas (referred to herein as “dryout wet gas” or “wet gas”) is conventionally flared during the entire dryout process of generally 5 to 7 days, resulting in an average flaring of about 180 MMSCF for each dryout process and sizable COemissions, as well as a waste of otherwise valuable NGL raw material resources (e.g., for the production of chemicals, plastics, fuel blends, and the like).

Various details of the present disclosure are hereinafter summarized to provide a basic understanding. This summary is not an extensive overview of the disclosure and is neither intended to identify certain elements of the disclosure, nor to delineate the scope thereof. Rather, the primary purpose of this summary is to present some concepts of the disclosure in a simplified form prior to the more detailed description that is presented hereinafter.

According to an embodiment consistent with the present disclosure, methods for managing natural gas liquids (NGL) recovery systems may include 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.

In another embodiment, NGL recovery systems may include 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.

Any combinations of the various embodiments and implementations disclosed herein can be used in a further embodiment, consistent with the disclosure. These and other aspects and features can be appreciated from the following description of certain embodiments presented herein in accordance with the disclosure and the accompanying drawings and claims.

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.

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.

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.

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 COabatement can be advantageously realized.

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.

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.

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).

As described above, conventional NGL recovery plant dryout processes rely on flaring of dryout wet gas and thus produces significant COemissions. 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.

Referring now to, illustrated is a schematic representation of a portion of an NGL recovery plant facilityduring a dryout process in accordance with one or more embodiments of the MSM of the present disclosure. As shown in, three parallel NGL trains are provided. A first NGL recovery train includes exchanger, a second NGL recovery train includes exchangers,,, and, and a third NGL recovery train includes exchangersand. 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.

With continued reference to, dryout gasmay be received by gas dehydratorvia fluid conduitin 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.

Gas dehydratormay 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 dehydratormay 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.

Gas dehydratormay be in fluid communication with the second NGL recovery train via exchangerand fluid conduit. Dryout gasmay pass from gas dehydratorand to the second NGL recovery train through at least exchangers,, and, each in fluid communication via fluid conduitsand, respectively. A first portion of the dryout gasmay exit exchangerto the first NGL recovery train exchangerin fluid communication therewith via fluid conduit; a second portion of the dryout gasmay exit exchangerand continue to exchangerin fluid communication therewith via fluid conduit.

As shown, exchanger, as part of the second NGL recovery train, may be in fluid communication with separatorvia fluid conduit. Separatormay be any process equipment suitable for separating liquid from the feed dryout gasreceived therein (i.e., phase separation). Any separated liquid from dryout gasmay be accumulated within or removed from separatorto 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.

Dryout gasmay pass from separatorto the third NGL recovery train via fluid conduitinterposing separatorand exchanger. A first portion of the dryout gasmay exit exchangerto the second NGL recovery train exchangerin fluid communication therewith via fluid conduit; a second portion of the dryout gasmay exit exchangerand continue to exchangerin fluid communication therewith via fluid conduit. As shown in, exchangermay be in fluid communication with separatorvia fluid conduit, which may be any of the above-described separator types or configurations, without limitation. Thereafter, dryout gasmay be cycled from separatorto exchangerin fluid communication via fluid conduit.

With continued reference to, the dryout gasthat flows through exchangermay exit to exchangershell-side via fluid conduit, as previously described. Traditionally, exchangerwould be in fluid communication with open valvevia fluid conduitand via fluid conduit, the dryout gas(now wet gas) would be burned using flare burner. Fluid conduitand flare burnerare 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 gasfrom fluid conduitby bypassing closed valvethrough fluid conduit(“bypass fluid conduit”) and directing it to sales gas compressor.

As provided in, open valveis indicated as having internal transparency, whereas closed valveis indicated as having internal opacity; this graphic distinction is used throughout the present disclosure. The various valves of the present disclosure, including valveand valve, 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, valvemay be a PCV or a FCV and valvemay be a ZV.

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, 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.

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, 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.

Referring now to, 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.

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.

Accordingly, the MSM of the present disclosure may be used to minimize or eliminate flaring, resulting in a substantial reduction in COemissions.

As described above, conventional NGL recovery plant dryout processes rely on flaring of dryout wet gas and thus produces significant COemissions. 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.

Referring now to, and with continued reference to, illustrated is a simplified schematic representation of a portion of an NGL recovery plant facilityas part of a dryout process in accordance with one or more embodiments of the DSM of the present disclosure.

It is to be appreciated that the various valves described with reference tomay be any type of valve as described above with reference towithout limitation; any of the various exchangers described with reference tomay be any type and in any configuration as described above with reference towithout limitation, and the fuel gas compressor ofmay be any type of compressor and in any configuration as described with reference towithout limitation.

As shown in, a demethanizeris 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.

As shown in, the demethanizermay be in fluid communication with multiple fluid conduits,, and, to receive chilled natural gas during operation. Each of fluid conduitsandmay have arranged thereon open valvesand, respectfully. Fluid conduitmay have been arranged thereon closed valve, permitting fluid communication between conduitand fluid conduit, as described below. In one or more embodiments, open valvesandmay 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, fewer or greater than three fluid conduits may be used in fluid communication with the demethanizer, without limitation.

With continued reference to, dryout gasmay be received by exchanger(see also) via fluid conduitin fluid communication therewith. Fluid conduitmay have arranged thereon open valve. In some embodiments, open valvemay be a PCV.

As shown, exchangermay be in fluid communication with exchangervia fluid conduitto receive the dryout gastherethrough. From the exchanger, the dryout gasgas may pass to demethanizervia fluid conduitin fluid communication therewith. The demethanizermay be in fluid communication with fluid conduithaving open valve. In one or more aspects, valvemay be an AOV valve. As shown, fluid conduitmay bifurcate and be in fluid communication with two pumpsandand two open valvesand, respectfully, for drawing dryout gasfrom the demethanizer. In various aspects, open valvesandmay be MOVs. Thereafter, fluid conduitmay be reunited into a single fluid conduit.

A first portion of the dryout gasmay exit fluid conduitthrough open valveto fluid conduitin fluid communication therewith. In some instances, open valvemay be an LCV valve. Fluid conduitmay have arranged thereon open valveand may divert dryout gasto demethanizerthrough fluid conduit. In various aspects, open valvemay be an FCV valve that is 50% open.

A second portion of the dryout gasmay exit fluid conduitthrough open valveto fluid conduitin fluid communication therewith. Fluid conduitmay have arranged thereon open valveand may divert dryout gasto demethanizerthrough fluid conduit. In various aspects, open valvemay be a TCV.

Lastly, a third portion of the dryout gasmay exit fluid conduitthrough open valveto fluid conduitin fluid communication therewith. Fluid conduitarranged thereon open valveto exchanger(and eventually again to demethanizer). In various aspects, open valvemay be a BFV.

Dryout gasmay exit demethanizeras dryout wet gas via fluid conduitto exchangerin fluid communication therewith. Fluid conduitmay have been arranged thereon open valve. Exchangermay be arranged in series and in fluid communication with exchangervia fluid conduitto receive the dryout gas.

With continued reference to, traditionally, exchangerwould be in fluid communication with fluid conduitand the dryout gaswould be burned using flare burner(see also). Fluid conduitand flare burnerare 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 gasfrom fluid conduitby bypassing closed valvethrough fluid conduit(“bypass fluid conduit”) and directing it to fuel gas compressor.

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.

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, 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, and in any combination and configuration, without limitation.

Referring now to, 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.

Accordingly, the DSM of the present disclosure may be used to minimize or eliminate flaring, resulting in a substantial reduction in COemissions.

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.

In this Example, an Aspen HYSYS® simulator was used to simulate the MSM of the present disclosure.is a schematic portion of an NGL recovery plant facilityduring a dryout process created using Aspen HYSYS® simulation. As shown in, 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.

Referring specifically to, high-pressure (HP) gas streamflows into the inlet of tee. The HP gasis characterized by the plant data shown in Table 1 below as it flows to tee. The unit “MMSCFD” refers to million standard cubic feet per day.”

Streamis bifurcated by tee. A first portion of streamflows from teeas stream. Streamflows to compressor, which also receives dryout gas at molar flow at 9.807 MMSCFD, forming stream. Streamis then bifurcated by teeinto streamand stream. Streamflows through heating exchanger, open VLV valve, gas booster, and mixer. The streambetween the gas boosterand the mixeris characterized by the plant data shown in Table 2 below.