WO2012067754A1

WO2012067754A1 - Process for making synthetic natural gas

Info

Publication number: WO2012067754A1
Application number: PCT/US2011/057205
Authority: WO
Inventors: Raymond Francis Drnevich
Original assignee: Praxair Technology, Inc.
Priority date: 2010-11-19
Filing date: 2011-10-21
Publication date: 2012-05-24
Also published as: CN103189481A; KR101929066B1; KR20140000281A; CN103189481B

Abstract

The present invention relates generally to a gasification process and system for making synthetic natural gas using low purity oxygen. A portion of the cleaned syngas is shifted to a H₂/CO ratio of at least 30/1 before being remixed with the other portion of the syngas to make a syngas stream having a H_2/CO ratio of 1 or less. The final syngas stream is feed to the methanation unit to produce synthetic natural gas.

Description

PROCESS FOR MAKING SYNTHETIC NATURAL GAS

Field of the Invention

[0001] The present invention relates generally to a gasification process and system for making synthetic natural gas using low purity oxygen.

Background of the Invention

[0002] Energy demand is increasing across the globe and the cost of fossil fuels continues to increase. Natural gas is taking an increasingly important role in energy production since it use generally results in reduced emissions of greenhouse gases as compared to coal or oil. In fact, the vast majority of new power plants in the U.S. and in many other countries are projected to be natural gas powered adding concern to the longevity of the world's dependence on lower emission generating fossil fuels. The substitution of natural gas by using an equivalent derived from carbon or hydrocarbon containing feedstocks such as coal, biomass, petroleum coke, or solid waste could subsidize the demand for natural gas for many years. Moreover, the conversion of coal to a substitute gas could significant extend the role of natural gas in power plants well beyond the life of current reserves while also utilizing the world's abundant coal resources.

[0003] This substitute gas, known as "synthetic natural gas" or "substitute natural gas" (SNG), is simply a manufactured form of natural gas. It is created by converting or reforming the carbon based feedstock into methane and other light hydrocarbons and can be used in almost every way that natural gas is used today. Typically, the feedstock is gasified with the resulting synthesis gas (syngas), containing predominately hydrogen (H2) and carbon monoxide (CO), converted to methane, the major component of natural gas. SNG has the added benefit of being capable of being distributed through existing infrastructure and marketed using existing trade and supply networks.

[0004] The commercial viability of producing SNG is directly dependent upon the efficiency of the process. The effective gasification of the feedstock requires the use of oxygen in place or air. Typically, the oxygen is produced using known technology for the cryogenic distillation of air wherein the air is separated into its component parts. Such plants are known as air separation plants (ASUs). The ASUs produce the oxygen feed streams used in the gasification reaction. Current SNG processes utilize high purity oxygen streams, typically containing above about 99.5% oxygen, which are more expensive to produce then low purity oxygen streams, below about 98%> oxygen by volume. Thus it would be desirable to design a process for the production of SNG using low purity oxygen streams in the gasification reaction to reduce costs and improve the economic value of the SNG product.

Brief Summary of the Invention

[0005] The present invention provides a process and system for the production of synthetic natural gas from the methanation of syngas using low purity oxygen, such as below 98%>. The process also provides high purity hydrogen such as above 99% hydrogen by volume.

[0006] According to this process and system, a process for the production of synthetic natural gas meeting pipeline specifications is provided comprising: introducing a carbon containing feedstock into a gasifier in the presence of oxygen wherein the oxygen is feed into the gasifier at a purity of less than 98%; gasifying the feedstock to produce a raw syngas stream with a H₂/CO ratio of 1 or less;

splitting the raw syngas stream into at least a first stream and a second stream;

sending the first stream to an acid gas removal system to remove at least sulfur compounds to make a cleaned first stream;

sending the second stream to a sour water gas shift reactor to adjust the H₂/CO ratio to at least 30/1 to make an adjusted syngas stream;

sending the adjusted syngas stream to the acid gas removal system to remove at least the sulfur compounds and C02 and make a cleaned second stream; sending the cleaned second stream to a gas separation unit to produce a high purity hydrogen stream and a tail gas stream;

mixing the cleaned first stream and at least part of the hydrogen stream to produce a methanation feed stream with a H₂/CO ratio of at least 3/1;

sending the methanation feed stream to a methanation unit to convert the methanation feed stream into a product stream containing at least methane and water; and

separating the water from the product stream to make the synthetic natural gas.

Brief Description of the Drawings

[0007] Figure 1 is a schematic flow diagram showing a two train gasification system as known in the prior art using a high purity oxygen stream.

[0008] Figure 2 is a schematic flow diagram showing one embodiment implementation of the present invention with a two train gasification system using a low purity oxygen stream.

[0009] Figure 3 is a graph showing the impact of oxygen purity on the quality of the SNG product gas.

Detailed Description of the Invention

[0010] Processes for the production of SNG are known. Typically, methane is produced from syngas typically generated from the gasification of fossil based carbon containing feedstock into gases including carbon oxides, methane, C2 to C5 hydrocarbons and hydrogen. Typical feedstocks are coal, petroleum coke, residual heavy oil including oil-bearing secondary materials, biomass, solid wastes and other high molecular weight hydrocarbons.

[0011] SNG must meet pipeline specifications to be commercially viable.

"Pipeline specifications" is understood to generally mean having sufficient heating value to meet energy requirements at least equivalent to commercial natural gas. In this way, methane content is indirectly specified because the methane concentration reflects the heating value of the SNG. International specifications can vary with, for example, United States requirements at 950 and European specifications (based on North Sea gas) at 800 BTU higher heating value (HHV) per standard cubic foot (SCF). "Pipeline specifications" for purposes of this application means SNG having a heat value of at least 950 BTU (HHV) per SCF. The methane concentration of the SNG is more than 92% and preferably more than 93% by volume (all percentages for gas purities herein are by volume). Conventional designs of gasification systems for the production of SNG involves facilities having the following known equipment:

one or more ASUs producing oxygen at a purity 99% or more for the gasification process;

at least one gasifier fed with coal, petroleum coke, and other high molecular weight hydrocarbons producing a syngas with a H2/CO ratio of 1 or less (the gasifier may be a quench or include other means for gas cooling with or without steam production);

sour water gas shift reactors used to adjust the H2/CO ratio;

gas cooling and/or energy recovery systems;

acid gas removal systems generally based on a physical solvent designed to selectively remove sulfur compounds and C02 from the adjusted syngas;

methanation systems designed to convert the CO and hydrogen into methane and water; and

water separation and/or drying systems to provide pipeline quality SNG.

[0012] Often economies of scale dictate that at least two complete processing trains should be used and the process can produce hydrogen as a co-product from these systems. When hydrogen is a co-product, a portion of the syngas goes through a water-gas-shift reactor to adjust the H₂/CO ratio.

[0013] According to these conventional systems, high purity oxygen is required for the gasification step to minimize the inert gases contained in the final SNG product. Depending on the composition of the feedstock sent to the gasifier, it can be difficult to produce a SNG with sufficient heating value to meet pipeline specifications. The oxygen supply system (e.g. one or more air separation units (ASU)) is generally designed for high purity oxygen such as greater than 99%) to minimize the introduction of inert materials (nitrogen and argon) that would dilute the product SNG. In addition, the ASU is the largest power consuming equipment associated with gasification systems and it is well known that producing oxygen at a purity level of about 95% can reduce the separation energy needed by the ASU by 15%) or more when compared to an ASU producing oxygen at a purity level of 99% or more. Thus it would be desirable to use lower purity oxygen in the production of SNG to reduce power consumption.

[0014] According to the present invention, the gasification process can be conducted using low-purity oxygen, such as less than 98%> oxygen and preferably ranging from 94%> to 97% oxygen, for producing pipeline quality SNG. Most preferably, the oxygen will have a purity level at about 95% oxygen. The process of the present invention that enables the use of low purity oxygen for producing SNG has the following equipment and process design:

[0015] One or more ASUs producing oxygen at a purity of less than 98%> for the gasification process;

sending the oxygen to at least one gasifier, preferably an entrained flow gasifier, fed with a suitable carbon containing feedstock, to produce a syngas stream with a H₂/CO ratio of 1 or less (the gasifier may be a quench or include other means for gas cooling with or without steam production);

splitting the syngas stream from the gasifier into at least a first stream and a second stream (preferably the ratio of the first stream to the second stream is such that after processing, the mixing ratio of two streams result in a final syngas stream with an H2/CO ratio of at least 3/1);

sending the first steam to an acid gas removal system based on a physical solvent, such as methanol, designed to selectively remove at least the sulfur compounds and optionally C0₂ from the adjusted syngas;

sending the second stream to: (a) a sour water gas shift reactor used to adjust the H₂/CO ratio to at least 30/1, and preferably above about 50/1, (b) an acid gas removal system based on a physical solvent, such as methanol, designed to selectively remove sulfur compounds and C02, and (c) a gas separation system, such as a hydrogen pressure swing adsorption (PSA) unit, to produce a high purity hydrogen stream, preferably with a purity of at least 99% and more preferably above 99.5% and which at least a portion of can be optionally recovered for use external to synthetic natural gas production;

mixing the first and second streams to produce a feed stream with a H2/CO ratio of at least 3/1;

sending the feed stream to a methanation unit designed to convert the feed stream into methane and water; and

separating the methane and water in a water separation and/or drying system to provide pipeline quality SNG.

[0016] With reference to a conventional system as shown in Figure 1 , the description for elements identified with a number followed by an "a" is a designation of the "a" train of processing elements and the description for elements identified with a number followed by a "b" is a designation of the "b" train of processing elements. The "a" and "b' elements are identical and only the "a" train will be described below. A number followed by a "c" is a designation of a third gasification train that is often referred to as a "spare gasifier" that provides syngas to either the "a" train or the "b" train when either the gasifier within the "a" train or the "b" train is unavailable.

[0017] Feed 10a which can be dry or slurried in water or other suitable solvent/carrier is introduced into gasifier 72a along with oxygen 12a from ASU 70a. The feedstock is typically coal, biomass, petroleum coke or biomass materials as described above. The present process is preferably used with coal. If the feed is dry, steam is generally added to the gasifier (not shown) to moderate reactor temperatures. Exiting gasifier 72a is the raw syngas 14a at a pressure generally above about 450 psia and having a H₂/CO ratio of 1 or less. The raw syngas stream 14a is split into two streams; first stream 18a which is sent to sour shift reactor 74a and bypass stream 16a which bypasses the sour shift unit and is mixed with the shifted syngas stream 20a exiting the sour shift reactor 74a to make a mixed syngas stream 22a. Stream 18 normally represents between 60% and 70% of the flow in stream 14a. Prior to entering sour shift reactor 74a, the temperature and moisture content of first stream 18a is adjusted to ensure that the conditions in the sour shift reactor 74a (normally containing a suitable catalyst such as an iron based catalyst) are amenable to producing a mixed syngas stream 22a that has a H₂/CO ratio of about 3. Although not shown, the sour shift reactor 74a could contain 1 to 3 stages of shift conversion reactors with syngas cooling after each stage. Any steam generated from cooling the syngas is sent to the power generation system (84a). The mixed syngas stream 22a then enters an optional gas cooling unit 76a that produces steam from the heat removed from the hot mixed syngas stream 22a. The mixed syngas stream 22a is further cooled to near ambient temperature, usually with cooling water (not shown).

[0018] Steam stream 34a leaves the gas cooling section and is sent to power generation unit 84a. Gasifier 72a can optionally produce steam for use for power generation. Power generation includes the use of steam in steam turbines to produce electric power or alternatively drive the compressors required for the ASU(s). Streams 30a through 36a represent flow lines transporting steam from methanation unit 80a, gasifier 72a and gas cooling unit 76a to power generation system 84a. The power generation system can include a steam turbine, a gas turbine, a steam boiler or steam superheater (boiler/superheater), a heat recovery steam generator (HRSG), or any combination of the above, but will contain at least one steam turbine. Generally a portion of streams 26a and 26b (not shown) are sent to the steam turbine as fuel and/or as fuel to the boiler/superheater or HRSG to produce steam and provide superheated steam for a steam turbine. Also, some of the steam generated in gasifier 72a, sour shift reactor 74a, and/or gas cooling unit 76a can be used to adjust the moisture content of first stream 18a and/or provide heat for regenerating the solvent used in acid gas removal system 78a (not shown). Alternatively, the power generation system could consist of a combined-cycle system which involves gas turbines, steam generation using a heat recovery steam generator, and a steam turbine as are known.

[0019] The cooled mixed syngas stream 24a is fed to an acid gas removal system78a typically using a physical sorbent, such as methanol, as used in Lurgi's Rectisol process for the purification and conditioning of syngas. The acid gases removed from the syngas include C0₂ which is either vented or collected for sequestration purposes (not shown) and sulfur containing gases such as H₂S which are concentrated and sent as stream 44a to a sulfur recovery unit 86a. The sulfur recovery unit 86a is usually designed to convert the sulfur containing gases to elemental sulfur or sulfuric acid which typically have some market value. The clean mixed syngas 26a leaves the acid gas removal system 78a and is heated (not shown) and fed to methanation unit 80a. The methanation unit 80a consists of multiple catalytic stages with gas recycle and heat removal systems to generate steam as are well know.

[0020] Additional heat is removed so that cleaned stream 29a leaving the methanation unit (80a) is near ambient temperature and the water formed in the methanation reactor is condensed and sent for reuse or disposal. Steam is sent to power generation system 84a through line 30a or sent to other uses. Cleaned stream 29a, which normally contains 93% to 96% methane and less than about 1% hydrogen, is dried in drying unit 82a using, for example, either a methanol or a glycol based dehydration system. Stream 90a leaving drying unit 82a meets pipeline specifications and can be optionally compressed prior to entering the pipeline distribution network. As is recognized by one skilled in the art, the methanation units 80a and 80b can be combined into a single methanation unit for both trains.

[0021] As mentioned earlier, the "b" train performs identical functions to the "a" train. When one of the gasifiers 72a or 72b is down for maintenance or other reasons, a spare gasifier 72c is made operational. If gasifier 72a is not operational, stream 14c and 14cl are used to provide raw syngas to the "a" train. Similarly, if gasifier 72b is not operational, syngas is supplied from gasifier 72c to the 'b" train through lines 14c and 14c2.

[0022] Referring now to Figure 2, the two train configuration shown in Figure 1 is modified to provide for rejection of inert gases from the feed to the methanation units 80a and 80b. The "a" train which will process between about 60%> to 70%> of the combined flow of 18a and 18b is modified so that the sour shift system 74a produces an adjusted syngas stream 22a (rather than a mixed syngas stream as shown in Figure 1) having a H₂/CO ratio of greater than 30/1 and which is not mixed with syngas coming from gasifier 72a as in Figure 1. The adjusted syngas stream22a is sent through a dedicated gas cooling unit 76a and acid gas removal system 78a followed by a gas separation unit, such as a pressure swing adsorption (PSA) unit, 92 that produces a high purity hydrogen stream, typically with at least 99% of hydrogen by volume and preferably greater than 99.5% hydrogen by volume (less than 1% and 0.5%> by volume of inert gases, respectively). Some of the hydrogen can be used for other purposes such as providing hydrogen for refinery processes. The PSA tail gas stream 94 contains the majority of impurities originally present in cleaned mixed syngas stream 26a such as carbon oxides, methane, hydrogen, nitrogen, and argon.

[0023] One advantage of the present process is that the acid gas removal system (as used in Figure 2) does not need to remove as much C02 as systems 78a and 78b in Figure 1. A PSA unit can be used in the present process to remove the C02 to a level that is lower than typically available with prior used acid gas removal systems. In addition, the C02 removal from system 78b in Figure 2 can be eliminated entirely saving capital and operating costs. The use of a PSA also allows for lower cost alternatives for sulfur compound and C02removal than are currently used in conventional processes. For example, an

adsorption/regeneration acid gas removal system such as a Selexol system or an amine system could be used in place of the Rectisol system.

[0024] PSA tail gas stream 94 is sent to the power generation system where it can be compressed and used as a fuel for a gas turbine or used as supplementary fuel in a boiler in the power generation system 84a similar to the use of a portion of streams 26a and 26b as described for Figure 1. The high purity hydrogen stream 27a leaving PSA 92 is divided into two streams; a first hydrogen stream 27b and a second hydrogen stream 27d. The "b" train in Figure 2 has no sour shift reactor (74b in figure 1). The raw syngas 14b is sent directly to the gas cooling unit 76b and then to acid gas removal system 78b. After acid gas removal, a first portion of clean mixed syngas stream 26b is sent to the "a" train as first cleaned mixed syngas stream 26e where it is mixed with hydrogen stream 27d to form the first methanation feed stream 28a for the methanation unit 80a. A second portion of cleaned mixed syngas stream 26b forms second cleaned mixed syngas stream 26d and is mixed with hydrogen stream 27b coming from PSA 92 to form the second methanation feed stream 28b and sent to the methanation unit 80b. First and second methanation feed streams 28a and 28b each contain hydrogen and carbon monoxide at a H₂/CO ratio of at least 3/1. The methanation units 80a and 80b and drying units 82a and 82b function as described for Figure 1.

[0025] Table 1 summarizes the compositions of the key process streams for the production of SNG as shown in Figures 1 and 2 as a function of the oxygen purity fed to the gasifier based on process simulations. The gas compositions are shown at the reference numerals corresponding to those shown in the Figures. These simulations use an entrained flow gasifier with a petroleum coke feed. For the prior art technology as shown as Figure 1 , the compositions show the small variation in inert content (nitrogen and argon) in the raw syngas with increasing concentrations in the feed to the methanation unit and the final product. Only the SNG produced with oxygen having a purity of 98% and more meets the product specification of over 92% methane. An oxygen purity of 99% was required in the Figure 1 process to achieve a methane concentration of more than 93%. As can be seen from the simulation defined as Figure 2, the invention uses the same feed composition as the prior art but with oxygen having a purity of only 95%.

Because of the ability of the hydrogen PSA to remove higher levels of inert gases after shift conversion (74a) and acid gas removal (78a), the concentration of inert gases to the methanation unit (80a) and in the final product are similar to the concentrations found in the Figure 1 prior art process using the higher cost 99.5% purity oxygen. Performance Summary - mole %

Figure 1 Figure 2

Oxygen Purity

99.5% 99.0% 98.0% 96.0% 95.0% 95.0% (% volume)

Raw Syngas 18a/18b 18a/18b 18a/18b 18a/18b 18a/18b 18a/18b

Composition(Dry

Basis)

CO 53.8% 53.7% 53.6% 53.3% 53.2% 53.2%

C02 9.0% 9.0% 8.9% 8.9% 8.9% 8.9%

CH4 0.7% 0.7% 0.7% 0.7% 0.7% 0.7%

H2 33.6% 33.6% 33.5% 33.4% 33.3% 33.3%

H2S 1.7% 1.7% 1.7% 1.7% 1.7% 1.7%

COS 0.1% 0.1% 0.1% 0.1% 0.1% 0.1%

N2 0.9% 0.9% 0.9% 1.1% 1.4% 1.4%

Ar 0.1% 0.2% 0.5% 0.7% 0.7% 0.7%

Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Methanation

29a/29b 29a/29b 29a/29b 29a/29b 29a/29b 28a/28b Feed

Composition(Dry

Basis)

CO 23.5% 23.4% 23.3% 23.2% 23.1% 24.6%

C02 0.9% 0.9% 0.9% 0.9% 0.9% 0.1%

CH4 0.8% 0.8% 0.8% 0.8% 0.8% 0.3%

H2 73.7% 73.6% 73.4% 73.0% 72.8% 73.9%

H2S 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

COS 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

N2 1.0% 1.0% 1.0% 1.3% 1.5% 0.7%

Ar 0.1% 0.3% 0.5% 0.8% 0.8% 0.5%

Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

SNG Product 90a/90a 90a/90a 90a/90a 90a/90a 90a/90a 90a/90a

Composition(Dry

Basis)

CO 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

C02 0.7% 0.7% 0.7% 0.6% 0.6% 0.5%

CH4 93.7% 93.2% 92.3% 90.5% 89.6% 93.6%

H2 1.3% 1.3% 1.3% 1.3% 1.3% 1.4%

H2S 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

COS 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%

N2 3.8% 3.8% 3.7% 4.6% 5.6% 2.5%

Ar 0.5% 1.0% 2.0% 3.0% 2.9% 2.0%

Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%

Btu/Scf (HHV) = 952 947 938 920 911 952 [0026] Figure 3 shows the impact of oxygen purity on the quality of the SNG product gas. Referring now to Figure 3, oxygen used with a petroleum coke fed to an entrained flow gasification system producing SNG using the prior art process in Figure 1 is shown. Pipeline quality natural gas can only be achieved with the prior art process using an oxygen stream with a purity of 99.5% or greater.

However, pipeline quality natural gas (at least 950 BTU(HHV)/SCF) can be easily achieved by using the inventive process as described in Figure 2 with an oxygen stream with a purity of 95.0%. If the target energy content of the SNG need to be higher than 950 BTU (HHV)/SCF, then 96% oxygen can be used with only a small power penalty compared to 95% oxygen feed.

[0027] It should be apparent to those skilled in the art that the subject invention is not limited by the figures or disclosure provided herein which have been provided to merely demonstrate the advantages and operability of the present invention. The scope of this invention includes equivalent embodiments, modifications, and variations that fall within the scope of the attached claims.

Claims

WHAT IS CLAIMED IS:

1. A process for the production of synthetic natural gas comprising:

introducing a carbon containing feedstock into a gasifier in the presence of oxygen wherein the oxygen is feed into the gasifier at a purity of less than 98%; gasifying the feedstock to produce a raw syngas stream with a H₂/CO ratio of 1 or less;

sending the adjusted syngas stream to the acid gas removal system to remove at least the sulfur compounds and C02 and make a cleaned second stream;

sending the cleaned second stream to a gas separation unit to produce a high purity hydrogen stream and a tail gas stream;

separating the water from the product stream to make the synthetic natural gas.

2. The process of claim 1 wherein the synthetic natural gas has a heat value of at least 900 BTU (HHV) per SCF.

3. The process of claim 1 wherein the oxygen has a purity level ranging from 94% to 97% by volume.

4. The process of claim 3 wherein the oxygen has a purity of about 95% by volume.

5. The process of claim 1 wherein the acid gas removal system removes C02 from the first stream.

6. The process of claim 5 wherein the synthetic natural gas has a methane concentration of more than 92% by volume.

7. The process of claim 6 wherein the second stream sent to the sour water gas shift reactor is adjusted to have a H₂/CO ratio above about 50/1.

8. The process of claim 1 wherein the hydrogen stream has a hydrogen purity of at least 99%.

9. The process of claim 8 wherein at least a portion of the hydrogen stream is recovered for use external to synthetic natural gas production.

10. The process of claim 1 wherein at least a portion of the tail gas stream exiting the gas separation unit is sent to the power generation system.

11. The process of claim 10 wherein a portion of the tail gas stream is compressed and used as a fuel for a gas turbine.

12. The process of claim 1 wherein the gas separation unit is a hydrogen PSA unit.

13. The process of claim 1 wherein the gasifier is an entrained flow gasifier.

14. A process to make a methane containing gas containing at least 92% methane by volume, the process comprising the gasification of a carbon containing feedstock in the present of oxygen in a gasification unit to produce a syngas stream and sending the syngas stream to a methanation process to convert the syngas stream into the methane containing gas; the improvement comprising: feeding oxygen stream having a purity of less than 98% by volume oxygen into the gasification unit to make a raw syngas stream and splitting the raw syngas stream leaving the gasification unit into a first stream and a second stream;

sending the first stream to an acid gas removal system to remove at least sulfur compounds to make an cleaned first stream;

sending the second stream to a sour water gas shift reactor to adjust the H2/CO ratio to at least 30/1 to make a adjusted second stream and a tail gas stream; sending the adjusted second stream to the acid gas removal system to remove at least the sulfur and C02 compounds to make a cleaned second stream; sending the cleaned second stream to a gas separation unit to produce a at least a hydrogen stream having a hydrogen purity of at least 99% and recovering a at least a portion the hydrogen stream;

mixing the cleaned first stream and part of the hydrogen stream to produce a feed stream with a H₂/CO ratio of at least 3/1;

sending the feed stream to the methanation unit to produce a product gas containing at least methane, hydrocarbons and water, and

separating the water from the product gas to make a synthetic natural gas.

15. A gas system to make a methane containing gas containing at least 92% methane by volume, comprising in fluid communication:

a gasification unit to gasify a carbon containing feedstock in the present of a low purity oxygen stream of 94% to 97% oxygen by volume to produce a syngas stream;

an acid gas removal system to receive a first part of the syngas stream to remove at least the sulfur compounds and making a cleaned first stream;

a sour water gas shift reactor to receive a second part of the syngas stream to adjust the H2/CO ratio to at least 30/1 to make a adjusted second stream and a tail gas stream and sending the adjusted second stream to the acid gas removal system to remove at least the sulfur and C02 compounds to make a cleaned second stream;

an gas separation unit to receive the cleaned second stream and producing at least a hydrogen stream having a hydrogen purity of at least 99% and mixing the cleaned first stream and the hydrogen stream to produce a feed stream with a H₂/CO ratio of at least 3/1;

a methanation unit to receive the feed stream and produce a product gas containing at least methane, hydrocarbons and water; and

a unit for separating the water from the product gas to make the methane containing gas.