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United States Patent Application 20170145330
Kind Code A1
Kemmet; Ryan May 25, 2017

METHOD AND SYSTEM FOR CONVERTING FLARE GAS

Abstract

A volume of natural gas including a volume of methane and a volume of other alkanes may be cleaned of the other alkanes using a steam reformer system to create synthesis gas. This synthesis gas may then be combined with hydrogen to produce methane and water.


Inventors: Kemmet; Ryan; (Chandler, AZ)
Applicant:
Name City State Country Type

Advanced Green Innovations, LLC

Chandler

AZ

US
Family ID: 1000002447440
Appl. No.: 15/362598
Filed: November 28, 2016


Related U.S. Patent Documents

Application NumberFiling DatePatent Number
PCT/US15/26510Apr 17, 2015
15362598
62003532May 27, 2014

Current U.S. Class: 1/1
Current CPC Class: C10L 3/08 20130101
International Class: C10L 3/08 20060101 C10L003/08

Claims



1-20. (canceled)

21. A method for controlling a system to clean flare gas, the method comprising: receiving output measurements from the system, the output measurements including one or more of a CO.sub.2 output and a methane output; determining if one or more of the CO.sub.2 output measurement and the methane output measurement are different than a CO.sub.2 output set point and a methane output set point; adjusting one or more of an inlet water flow to at least one steam reformer system and an inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and a methane output set point being different than the CO.sub.2 output measurement and the methane output measurement; wherein the at least one steam reformer system is configured to: receive a volume of natural gas from the inlet gas flow, the volume of natural gas including a volume of methane and a volume of other alkanes, receive a volume of water from the inlet water flow, and crack at least a portion of the volume of other alkanes from the volume of natural gas to generate synthesis gas from the volume of natural gas and the volume of water.

22. The method according to claim 21 further combining the synthesis gas with hydrogen to form methane.

23. The method according to claim 21, wherein the output measurements further include a pressure output.

24. The method according to claim 21, wherein the CO.sub.2 output measurement is higher than the CO.sub.2 output set point and the methane output measurement is lower than the methane output set point.

25. The method according to claim 24, wherein the adjusting the one or more of the inlet water flow to at least one steam reformer system and the inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and the methane output set point being different than the CO.sub.2 output measurement and the methane output measurement includes decreasing the inlet water flow.

26. The method according to claim 25, further comprising decreasing the inlet gas flow in response to determining that a methane output from the system does not increase.

27. The method according to claim 21, wherein the CO.sub.2 output measurement is higher than the CO.sub.2 output set point and the methane output measurement is higher than the methane output set point.

28. The method according to claim 27, wherein the adjusting the one or more of the inlet water flow to at least one steam reformer system and the inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and the methane output set point being different than the CO.sub.2 output measurement and the methane output measurement includes decreasing the inlet water flow.

29. The method according to claim 21, wherein the CO.sub.2 output measurement is lower than the CO.sub.2 output set point and the methane output measurement is lower than the methane output set point.

30. The method according to claim 29, wherein the adjusting the one or more of the inlet water flow to at least one steam reformer system and the inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and the methane output set point being different than the CO.sub.2 output measurement and the methane output measurement includes decreasing the inlet gas flow.

31. The method according to claim 30, further comprising increasing both the inlet gas flow and the inlet water flow in response to determining that a methane output from the system does not increase.

32. A system for converting an input gas stream containing methane gas and other hydrocarbons into a methane-rich stream, comprising: a steam reformer reactor configured to receive input water and the input gas stream to produce a synthesis gas therefrom by (a) converting at least a portion of the other hydrocarbons of the input gas stream with the input water to the synthesis gas, and (b) allowing at least a portion of the methane gas from the input gas stream to pass through the steam reformer system unconverted, wherein the synthesis gas includes carbon oxide gas and hydrogen gas; and a methanation reactor in fluid communication with the steam reformer reactor to receive the synthesis gas and the unconverted methane gas to produce the methane-rich stream by (a) converting at least a portion of the carbon oxide gas and at least a portion of the hydrogen gas in the synthesis gas to additional methane gas, and (b) combining the unconverted methane gas and the additional methane gas, whereby the methane-rich stream has a greater methane concentration than the input gas stream.

33. The system according to claim 32, further comprising a hydrogen generator in fluid communication with the methanation reactor, wherein hydrogen is supplied by the hydrogen generator to the methanation reactor in response to determining that mass balancing needs adjustment in the methanation reactor.

34. The system according to claim 33, wherein the hydrogen generator comprises: another steam reformer reactor configured to receive the input water and the input gas stream to produce another synthesis gas therefrom by (a) cracking at least a portion of the other hydrocarbons, and (b) cracking at least a substantial portion of the methane gas of the input gas stream with the input water to the another synthesis gas with a lesser portion of the input water, wherein the another synthesis gas includes carbon oxide gas and hydrogen gas; and a hydrogen purifier in fluid communication with the another steam reformer reactor to separate the hydrogen gas in the another synthesis gas from the carbon oxide gas allowing a partial pressure of the hydrogen gas to pass through the hydrogen purifier to the methanation reactor as required.

35. The system according to claim 33, wherein the hydrogen generator comprises a hydrogen supply in fluid communication with the methanation reactor that allows supplied hydrogen gas to flow to the methanation reactor as required.

36. The system according to claim 34, further comprising the hydrogen purifier in fluid communication with a burner system of at least one of the steam reformer reactor and the methanation reactor, wherein a portion of the synthesis gas fuels the burner system.

37. The system according to claim 32, wherein the methanation reactor is configured to combine the hydrogen gas with the carbon oxides from the synthesis gas to form the additional methane gas and residual water.

38. The system according to claim 37, further comprising a water removal system in fluid communication with the methanation reactor to remove at least a portion of the residual water from the methane-rich stream.

39. The system according to claim 38, wherein the water removal system is in fluid communication with an inlet water source to receive the residual water for replenishing the input water.

40. A system for converting an input gas stream containing methane gas and other hydrocarbons, comprising: a steam reformer reactor configured to receive water and the input gas stream to produce a synthesis gas therefrom by (a) converting at least a portion of the other hydrocarbons of the input gas stream with the water to the synthesis gas with a lesser portion of the water, and other gases, and (b) allowing at least a portion of the methane gas from the input gas stream to pass through the steam reformer system unconverted; wherein the other gases in the output stream includes carbon oxide gas and hydrogen gas, a methanation reactor configured to receive the synthesis gas and to produce a methane-rich stream therefrom having a greater methane concentration than the input stream; wherein the methanation reactor is configured to convert at least a portion of the carbon oxide gas and at least a portion of the hydrogen gas in the synthesis gas to additional methane gas to produce a gas output composed of the methane gas and the additional methane gas.
Description



CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application is a Continuation of International Application No. PCT/US2015/026,510, with an international filing date of Apr. 17, 2015, which claims priority to U.S. Provisional Application No. 62/003,532 filed on May 27, 2014.

TECHNICAL FIELD

[0002] The invention relates to a method and apparatus arranged and designed for converting natural gas with high gas liquids content at remote locations to pipeline quality natural gas.

BACKGROUND

[0003] Oil wells often have an amount of natural gas associated with them. The natural gas must be removed in order to remove the oil. Currently the majority of this natural gas is flared or burned. The flaring process causes volatile organic compound emissions and is being targeted for removal for environmental protection reasons.

[0004] Natural gas associated with oil wells, though mostly methane, is often high in alkanes other than methane, such as ethane, propane and butane. These higher carbon number alkanes are of high value in the oil and gas industry and, in some embodiments, may allow for transport of the energy in the form of a highly dense liquid.

[0005] Remote processing of natural gas to remove the natural gas liquids or convert the entire stream to liquids has attracted great attention. The two leading processes in this industry are membrane separation and gas to liquid conversion. Both of these processes are energy intensive and require onsite electrical power generation if used in remote wells.

[0006] Membrane separation pressurizes the stream to high pressures (1000+ PSI) and forces the gas through membrane sieves which force the liquids to condense and allow the liquids to be removed. Membrane separation is unable typically to remove ethane because of its small size and relatively close size to methane. The resulting natural gas from membrane separation is not of pipeline quality because of its ethane content.

[0007] Gas to liquid conversion involves first converting the methane stream into synthesis gas, which is a combination of hydrogen, carbon monoxide, and carbon dioxide. The synthesis gas is then processed to react the stream into high carbon number alkanes (e.g., by Fischer-Tropsch processes). Typically the target liquid produced is methanol.

[0008] These two technologies do allow for the ultimate removal and transport of natural gas streams at well sites as liquids, but are very energy intensive and require onsite electrical power to be utilized. Remote oil wells sites have electrical demands that currently are fed by local diesel generators. Where the gas extracted from the oil well is of a high enough quality, natural gas generators are used. Well sites prefer to use the gas from the nearby well because it is a byproduct of oil removal and, without the processes described above, cannot be utilized at all. Currently available and utilized natural gas generators require near pipeline quality natural gas in order to work properly.

SUMMARY

[0009] In one embodiment, a method may clean flare gas by receiving a volume of natural gas, where the volume of natural gas includes a volume of methane and a volume of other alkanes. The method may then control both an inlet flow of the volume of natural gas and a volume of water to at least one reformer system and cause the at least one reformer system to crack, convert, or change at least a portion of the volume of other alkanes from the volume of natural gas. In this way, the at least one steam reformer system generates synthesis gas from the volume of natural gas and the volume of water. The method may then combine the synthesis gas with hydrogen to form methane.

[0010] In a further embodiment, a method may control a system to clean flare gas. For example, the method may receive output measurements from the system. These output measurements may include one or more of a CO.sub.2 output and a methane output. The method may also determine if one or more of the CO.sub.2 output measurement and the methane output measurement are different than a CO.sub.2 output set point and a methane output set point, and adjust one or more of an inlet water flow to at least one steam reformer system and an inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and a methane output set point being different than the CO.sub.2 output measurement and the methane output measurement. The at least one steam reformer system may be configured to facilitate the formation of methane by:

1) receiving a volume of natural gas from the inlet gas flow, the volume of natural gas including a volume of methane and a volume of other alkanes; 2) receiving a volume of water from the inlet water flow; and 3) crack at least a portion of the volume of other alkanes from the volume of natural gas to generate synthesis gas from the volume of natural gas and the volume of water. The method may then combine the synthesis gas with hydrogen to form methane.

[0011] In a still further embodiment, a system for cleaning flare gas may include at least one steam reformer system, a methanizer, and a controller. The at least one steam reformer system may be in fluid communication with both a source of natural gas and a source of water. The at least one steam reformer system may also be configured to crack a volume of alkanes from a volume of natural gas to produce a volume of synthesis gas. The methanizer may be in fluid communication with both the at least one steam reformer system and a source of hydrogen. The methanizer may be configured to combine the volume of synthesis gas with a volume of hydrogen to form methane. The controller may include one or more memories, one or more processors in communication with the one or more memories, and one or more computer-readable instructions stored in the one or more memories and executable by the one or more processors. The instructions may be executable to receive output measurements from the system. The output measurements may include one or more of a CO.sub.2 output measurement and a methane output measurement. The instructions may be further executable to determine if one or more of the CO.sub.2 output measurement and the methane output measurement are different than a CO.sub.2 output set point and a methane output set point, and to adjust one or more of an inlet water flow to at least one steam reformer system and an inlet gas flow to the at least one steam reformer system in response to the CO.sub.2 output set point and a methane output set point being different than the CO.sub.2 output measurement and the methane output measurement.

BRIEF DESCRIPTION OF THE DRAWINGS

[0012] The figures described below depict various aspects of the methods, systems, and devices disclosed herein. It should be understood that each figure depicts an embodiment of a particular aspect of the disclosed methods, systems, and devices, and that each of the figures is intended to accord with a possible embodiment thereof. Further, wherever possible, the following description refers to the reference numerals included in the following figures, in which features depicted in multiple figures are designated with consistent reference numerals.

[0013] Non-limiting and non-exhaustive embodiments of the devices, systems, and methods, including the preferred embodiment, are described with reference to the various figures disclosed.

[0014] The headings provided herein are for convenience only and do not necessarily affect the scope or meaning of the claimed embodiments. Further, the drawings have not necessarily been drawn to scale. For example, the dimensions of some of the elements in the figures may be expanded or reduced to help improve the understanding of the embodiments. Moreover, while the disclosed technology is amenable to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and are described in detail below. The intention, however, is not to limit the embodiments described. On the contrary, the embodiments are intended to cover all modifications, equivalents, and alternatives falling within the scope of the embodiments as defined by the appended claims.

[0015] FIG. 1 illustrates components of a system for converting flare gas in an embodiment of the disclosure;

[0016] FIG. 2 illustrates one embodiment of a method for converting flare gas in an embodiment of the disclosure;

[0017] FIGS. 3A, 3B, 3C, and 3D illustrate embodiments of a method for controlling a system to convert flare gas in an embodiment of the disclosure; and

DETAILED DESCRIPTION

[0018] The present disclosure describes the use of a novel combination of a synthesis gas generator combined with a hydrogen generator, a methanizer, and a dehydrator to create pipeline quality natural gas with little input energy required.

[0019] In an embodiment, a process (200, 300, 320, 350, 370--see FIGS. 2, 3A, 3B, 3C, and 3D) may convert natural gas with other alkanes present into natural gas with little or no alkanes present. The processes 200, 300, 320, 350, 370 result in both the creation of synthesis gas and the methanization of that gas to form methane and water. In order to for the mass balance to work through a methanizer 102 (FIG. 1), additional hydrogen must be added. This additional hydrogen can be pulled from the synthesis gas as a portion of the flow that has the carbon monoxide and carbon dioxide removed and/or the hydrogen can be supplied from an outside source 115.

[0020] With reference FIGS. 1, 2, and 3A-D, in some embodiments, an inlet gas 104 including high alkane gas has a ratio of carbon to hydrogen of about 2:5.75. Inlet gas may include flare gas of varying composition that enters the system 100. This gas may contain alkanes propane and ethane in high mole fraction as well as carbon dioxide, nitrogen, and water vapor, the largest mole fraction is methane. This stream of high alkane gas may be combined with heat and water resulting in carbon monoxide and carbon dioxide in equal parts and hydrogen in half as much as the input plus the amount of hydrogen from water. To form methane and water from a synthesis gas stream, seven parts hydrogen must combine with one part carbon dioxide and one part carbon monoxide. This results in a need for extra hydrogen in embodiments of the system 100 that utilize a stream of high alkane gas.

[0021] Chemical reactions involved in the system 100 and the methods 200, 300, 320, 350, and 370 to clean flare gas as herein described may include:

C.sub.2H.sub.5 75+3H.sub.2O.fwdarw.CO+CO.sub.2+5.86H.sub.2

CO+CO.sub.2+7H.sub.2.fwdarw.2CH.sub.4+3H.sub.2O

C.sub.2H.sub.5 75+3H.sub.2O.fwdarw.CO+CO.sub.2+5.86H.sub.2+1.14H.sub.2.fwdarw.2CH.sub.4+- 3H.sub.2O

[0022] In one embodiment, at step 202 (FIG. 2), sulfur removing filter system 106 may remove organic sulfurs and hydrogen sulfide from a high alkane gas stream to create a sulfur free natural gas stream. In some embodiments, the system 106 may remove the organic sulfurs and hydrogen sulfide through hydrogenation and absorption. In some embodiments, a single stage well head gas compressor compresses inlet gas streams into a pressure vessel which holds the gas at a higher pressure than required by the reformer and outputs gas pressure as required by reformer. A gas compressor 108 may compress the sulfur free gas stream to a nominal pressure or may completely compress the gas to ensure movement of the gas through the system 100. In some embodiments, in order to accomplish pipeline water specifications, a secondary gas compressor 109A and/or 109B may be required to force water out of the resulting stream. At step 204, the process may also input water and at step 206, filter the water for reactors/reformers 114A and 114B, as described herein. In some embodiments, reformers 114A and 114B may include a steam methane reformation system and/or a steam ethane reformation system.

[0023] The gas stream may pass through an inlet reservoir 110 and regulator 112 to be separated into one or more reformer systems 114A, 114B. Additionally, the process 200 may pass a volume of the natural gas to burners 115A and 115B associated with each reactor, as further explained, below. At steps 208 and 210, the process 200 may pass the gas stream through mass flow controllers 116A, 116B. At steps 212 and 214, the process 200 may pass the filtered water through reactor water pumps 124, 125 to the reactors 114A and 114B. In some embodiments, the reactors 114A, 114B may be configured as steam methane reformers that include nickel-based catalysts. Regardless of the configuration, at steps 216 and 218, the process may cause one or more of the reactors 114A, 114B, to generate synthesis gas. In some embodiments, at steps 218A and 218B, one or more burners 115A and 115B may control an amount of heat for the reactors 114A, 114E to facilitate a reaction. The burners 115A and 115E may burn the input gas to achieve a proper temperature in the reformers 114A and 114B associated with the burners. In some embodiments, the burner 115B heats the reformer 114B to a temperature to cause the cracking of C2+ hydrocarbons, and may not crack or reform methane. In further embodiments, a burner system (i.e., burner 115A) may heat a reformer system reactor (i.e., reformer 114A) may be heated to a temperature to cause the cracking of methane and all hydrocarbons. The reformers 114A and 114B may receive water from a source 122. The water may require filtration before being received by the reformer(s). The water is turned to steam in the reactors and the steam along with the catalyst and increased temperature in the reactors may crack or break apart the hydrocarbons.

[0024] At step 220, one or more of steam methane reformers may communicate the synthesis gas to a hydrogen purifier 118. For example, the feed from the reformer system 114A may be fed to the hydrogen purifier 118 which allows a partial pressure of hydrogen to pass the purifier 118. In some embodiments, the purifier 118 may be configured to heat palladium or any other material and to separate hydrogen in the synthesis gas from carbon monoxide and carbon dioxide. A portion of synthesis gas may be sent through the purifier 118 to remove CO and CO.sub.2 from the stream, leaving 95% purity hydrogen. In other embodiments, the system 100 may include a hydrogen supply 115 in combination with or in lieu of a reformer (e.g., 114A) to supply hydrogen to the methanizer 102. The remaining flow that does not flow through the hydrogen purifier 118 may then flow back to the burner system 115A for complete burning.

[0025] At step 222, in embodiments of the system 100 that include a reformer to produce hydrogen (e.g., the reformer 114A), an exhaust 120 may provide an outlet on the purifier 118 for gases other than hydrogen. In some embodiments, the steam methane reformers 114A, 114B may be heated at steps 218A and 218B by the inlet natural gas stream and a portion of the synthesis gas stream, which enables a nearly pure output of carbon dioxide from the exhaust 120 at step 222. Also, in some embodiments, water from a water source 122 may be input at steps 212 and 214 into the reformers 114A, 114B via a pump 124. The pump 124 may be configured to match the flow of the water to the flow of the inlet gas stream.

[0026] At step 224, the resulting synthesis gas stream and hydrogen stream may be combined and flow through a methanizer 102. The hydrogen flow combines with the synthesis gas flow from the reformer 114B system in the methanizer 102. The methanizer 102 is configured to combine the hydrogen with the CO and CO.sub.2 from the reformer 114B synthesis gas stream to form methane and water. In some configurations, the methanizer includes a nickel based catalyst which is different from the catalyst of the reformers 114A, 114B. At step 226, a majority of the water is removed from the resulting methane and water stream from the methanizer, and the resulting stream is mostly methane. In some embodiments, the water may be recovered and reused through a de-ionization filtration system 128 via a pump 130 as feed stock for the one or more reformers 114A, 114B. The deionized water system may create water to the purity and ion specification as required by the reformer systems 114A and 114B. In some embodiments, the means 126 includes a secondary process that forces the removal of water through deliquescent desiccant dehydration or may remove water by a coalescing, mechanical, and desiccant separation of water from the stream. The removed water may then be cycled back to the water supply 122 or otherwise fed back to the steam reformer systems 114A and 114B.

[0027] At steps 228, 230, and 232, sensors 132, 134, 136 may measure the natural gas output as a measures of the methane and carbon dioxide or other hydrocarbons, as well as the output pressure of the natural gas stream. In some embodiments, the output pressure controls the total flow out of the system. The process 200 may measure the methane and carbon dioxide or other matter in the stream using infrared sensors. In some embodiments, a sensor 132 may measure the output stream of natural gas as including about 90% or greater methane. At step 234, the process 200 may out put a gas stream including methane. These measurements, possibly including other measures, may then be processed by a controller 140, as further described, below.

[0028] Control of the system 100 and processes 200, described above, and 300, 320, 350, 370, described below, may be facilitated using computer-readable instructions that are stored within a tangible memory of a controller 140. The controller 140 may include both a memory 140A for storing instructions and a microcontroller or processor 140B for executing instructions to control the system 100 and processes 200, 300, 320, 350, 370 and any other computer-controlled functions for converting flare gas, as described herein. The processor 140B may include a register set or register space which may be entirely on-chip, or alternatively located entirely or partially off-chip and directly coupled to the processor 140B via dedicated electrical connections and/or via an interconnection bus. The processor 140B may be any suitable processor, processing unit or microprocessor. Although not shown, the system 100 or any system employing various embodiments system 100 as herein described may be a multi-processor device and, thus, may include one or more additional processors that are identical or similar to the processor 140B and that are communicatively coupled to an interconnection bus. The processor 140B may also be coupled to a chipset, which includes a memory controller and a peripheral input/output (I/O) controller. As is well known, the chipset typically provides I/O and memory management functions as well as a plurality of general purpose and/or special purpose registers, timers, etc. that are accessible or used by one or more processors coupled to the chipset. The memory controller performs functions that enable the processor controller (or processors if there are multiple processors) to access a system memory and a mass storage memory (not shown).

[0029] The processor 140B may also include one or more memories 140A storing instruction modules to implement flare gas conversion strategies such as a method 200 (FIG. 2) or 300, 320, 350, 370 (FIGS. 3A, 3B, 3C, and 3D) for converting flare gas to natural gas or other functions as herein described. For example, a flare gas conversion control module 140C may be stored in memory 140A and include tangible computer-executable instructions that are stored in a non-transitory computer-readable storage medium. The instructions of the flare gas conversion control module 140C are executed by the processor 140B or the instructions can be provided from computer program products that are stored in tangible computer-readable storage mediums (e.g. RAM, hard disk, optical/magnetic media, etc.).

[0030] To maintain target output methane molar percentages of flow, the control of the system 100 requires that the gas streams that are input to the various components of the system 100 are able to be varied. The embodiments described herein generally rely on steam methane reformation and methanation. The steam methane reformer system 114A and steam ethane reformer system 114B add water (in the form of steam) and gas together to crack the hydrocarbons. At different temperatures, additional hydrocarbons will crack. The lighter hydrocarbons have a higher activation energy and require additional heat input to crack. In order to run the reformer systems without coking them, water should be above a 1:1 steam to carbon ratio. The methanation step 224 (FIG. 2) has water as resultant of the reaction, which means the more water there is in the inlet stream to the methanation step, the slower the reaction may occur. To resolve this conflict, the controller 140 may execute one or more instructions to precisely control water in the reformer system 114B. For the reformer system 114A, excess water has no effect because only hydrogen is ultimately resulting.

[0031] With reference to FIG. 3A, a process 300 executed by the controller 140 may control the pressure within the system 100 to achieve optimal or desired conversion of flare gas as herein described. At step 302, the controller 140 may receive a measured output pressure from the system 100. At step 304, if the measured output pressure is lower than a set point pressure to achieve optimal or desired flare gas conversion, then, at step 306, the controller 140 may cause flow to one or more of the mass flow controllers 116A, 116B and to a reactor water pump 125 for reformer system 114B to increase. Alternately to step 304, if the measured output pressure is higher than a set point pressure to achieve optimal or desired flare gas conversion at step 308, then, at step 310, the controller 140 may cause flow to one or more of the mass flow controllers 116A, 116B and to a reactor water pump 125 for reformer system 114B to decrease.

[0032] With reference to FIG. 3B, in order to control the water flow from the water source 122 to the reformer systems 114A, 114B, the controller 140 may execute one or more instructions to continuously or periodically monitor an output gas stream for methane and carbon dioxide content. In some embodiments, the goal for the system 100 is to achieve an output of greater than 90% methane and less than 5% carbon dioxide. The sensors 132, 134, may sense methane and carbon dioxide levels using infrared sensors or other devices. Adjusting the water can have several effects on the system. First, if there is too much water, more CO.sub.2 will be produced in the reformer system 114B because there is more oxygen that can bond to carbons. The controller 140 may then execute an instruction to decrease the water input to allow less oxygen to be bonded to carbons, resulting in increased CO production, which is easier to convert to methane and water in the methanation reactor 102. Lowering the water flow may increase the reactions available in the methanation reactor 102. In some embodiments, the goal of the water system that feeds reformer system 114B is always to be at the lowest flow possible while producing the least amount of CO.sub.2 and the most amount of methane. There are a few possible reasons to have lower than expected methane molar % coming out of the system 100, thus the controller 140 implements two approaches. For example, an excess amount of hydrogen in the output gas composition makes it difficult to measure the composition. In this scenario, decreasing the flow rate from the reformer system 114A may be the best result. Further, there also could be hydrocarbon slip coming from the reformer system 114B and this would need to be resolved with additional water.

[0033] The process 320 (FIG. 3B) illustrates various steps executed by the controller 140 to control the system 100 and adjust the output flow. At step 322, the sensors 132 and 134 may measure the CO.sub.2 and Methane of the gas output by the system 100. If, at step 324, the CO.sub.2 is higher than a set point and the methane is lower than the set point, the controller 140 may execute an instruction to decrease inlet water flow to the reformer system 114B at step 326. The controller 140 and sensors 132 and 134 may continue to monitor the output and, at step 328, if the methane does not increase, then the controller 140 may execute an instruction to decrease inlet gas flow to the reformer system 114A at step 330.

[0034] If, at step 332, the CO.sub.2 is higher than a set point and the methane is also higher than the set point (e.g., about 7% CO.sub.2 and about 91% methane), the controller 140 may execute an instruction to decrease inlet water flow to the reformer system 114B at step 334.

[0035] If, at step 336, the CO.sub.2 is lower than a set point and the methane is also lower than the set point (e.g., about 3% CO.sub.2 and about 85% methane), the controller 140 may execute an instruction to decrease inlet gas flow to the reformer system 114A at step 338. The controller 140 and sensors 132 and 134 may continue to monitor the output and, at step 328, if the methane does not increase, then the controller 140 may execute an instruction to increase inlet water flow to the reformer system 114B at step 342 and also increase inlet gas flow to the reformer system 114A at step 344.

[0036] If, at step 346, the CO.sub.2 is lower than a set point and the methane is higher than the set point, the controller 140 may take no action at step 348.

[0037] With reference to FIG. 3C, the controller 140 may execute a process 350 at step 352 to control inlet water flow to the reformer system 114A by accessing a table that is based on the inlet gas flow for the reformer system 114E at step 354.

[0038] With reference to FIG. 3D, the controller 140 may execute a process 370 at step 372 to control each of the burners 115A and 115B by executing a PID loop to maintain an optimal temperature for the reformer systems 114A 114B at step 374.

[0039] Flare Gas is typically composed of Methane, Ethane, Propane, Butane, Pentane and some Hexane. It may have additional components as well, but these natural gas liquids in the natural gas cause the gas to not be able to be used in generators or put onto the pipeline.

[0040] Table 1 shows an example composition of flare gas,

TABLE-US-00001 TABLE 1 NAME MOL % Nitrogen 7 Methane 42.4 Ethane 18.7 Propane 19.2 Butane 8.3 Pentane 2.3 Hexane 1.4

[0041] This results in an average ratio of hydrogen to carbon of 2.87:1

[0042] At a 4:1 ratio of hydrogen to carbon, it is clear that additional hydrogen is needed to turn all of the carbon into methane.

[0043] Starting with a steam-methane reformer 114A capable of converting larger hydrocarbons the resulting gas is typically H2+0.5 CO+0.5 CO.sub.2, meaning 50% of the carbons become CO and 50% become CO.sub.2.

[0044] The next step includes combining this gas flow with a near 100% hydrogen stream from a second steam methane reformer that has had the CO and CO.sub.2 filtered out and putting this combined stream through a methanizer 102.

[0045] A methanizer 102 may for example be used in gas chromatographs to help in the detection of small concentrations of CO and CO.sub.2, or as a final purification means on hydrogen generators that are feeding fuel cells, to ensure no CO or CO.sub.2 enters the fuel cell--it converts these to methane and water.

[0046] According to aspects of the disclosure, the resulting gas has a large concentration of water combined with methane; this water needs to be removed before the methane is usable. Water removal from methane may be performed by various methods including coalescing and membrane filtration, with regenerative desiccant as needed.

[0047] According to aspects of the disclosure, at least one means of generating syn gas from a varied gas composition, combined with at least one means of generating hydrogen from a varied gas composition, combining the syn gas and hydrogen streams and causing this combined stream to enter at least one means for combining syn gas and hydrogen into methane and water.

[0048] According to still further aspects, adding a means to remove the water from the methane of various types, adding sulfur filtration before the reforming means, adding compression systems before and after, and/or adding de-ionized water systems, may be further included.

[0049] According to aspects of this disclosure, Steam Methane Reformers, Hydrogen Purifiers, Methanizers and Water Removal systems are combined to produce a system and method of operation and output.

[0050] Reference in this specification to "one embodiment" or "an embodiment" means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the disclosure. The appearances of the phrase "in one embodiment" in various places in the specification are not necessarily all referring to the same embodiment, nor are separate or alternative embodiments mutually exclusive of other embodiments. Moreover, various features are described which may be exhibited by some embodiments and not by others. Similarly, various requirements are described which may be requirements for some embodiments but not for other embodiments.

[0051] From the foregoing, it will be appreciated that, although specific embodiments of the technology have been described herein for purposes of illustration, various modifications may be made without deviating from the spirit and scope of the technology. Further, certain aspects of the new technology described in the context of particular embodiments may be combined or eliminated in other embodiments. Moreover, while advantages associated with certain embodiments of the technology have been described in the context of those embodiments, other embodiments may also exhibit such advantages, and not all embodiments need necessarily exhibit such advantages to fall within the scope of the technology. Also contemplated herein are methods which may include any procedural step inherent in the structures and systems described. Accordingly, the disclosure and associated technology can encompass other embodiments not expressly shown or described herein.

[0052] The terms used in this specification generally have their ordinary meanings in the art, within the context of the disclosure, and in the specific context where each term is used. It will be appreciated that the same thing can be said in more than one way. Consequently, alternative language and synonyms may be used for any one or more of the terms discussed herein, and any special significance is not to be placed upon whether or not a term is elaborated or discussed herein. Synonyms for some terms are provided. A recital of one or more synonyms does not exclude the use of other synonyms. The use of examples anywhere in this specification, including examples of any term discussed herein, is illustrative only and is not intended to further limit the scope and meaning of the disclosure or of any exemplified term. Likewise, the disclosure is not limited to various embodiments given in this specification. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure pertains. In the case of conflict, the present document, including definitions, will control.

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