CN117957185A - Autonomous modular flare gas conversion systems and methods - Google Patents

Abstract

Systems and methods are provided for producing a final product from an off-gas, such as flare gas, using fuel-rich partial oxidation. In one embodiment, the system and method uses an aspirated piston engine and turbine engine for fuel-rich partial oxidation of flare gas to form synthesis gas, and a reactor to convert the synthesis gas to a final product. In one embodiment, the end product is methanol.

Description

Autonomous modular flare gas conversion systems and methods

The application comprises the following steps: (i) The filing date benefit of U.S. provisional filing serial No. 63/189,756 filed at month 5 and 18 of 2021, and claims priority benefit thereof, according to 35u.s.c. ≡119 (e) (1); (ii) The filing date benefit of U.S. provisional filing serial No. 63/213,129 filed at month 21 of 2021 and claims priority benefit thereof according to 35u.s.c. ≡119 (e) (1); (iii) The filing date benefit of U.S. provisional filing serial No. 63/197,898 filed at 7 of 6 th of 2021 is claimed and priority benefit is claimed in accordance with 35u.s.c. ≡119 (e) (1); and (iv) claims the filing date benefit of U.S. provisional application serial No. 63/304,463, filed on day 28 at month 1 2022, in accordance with 35u.s.c. ≡119 (e) (1), and claims the priority benefit thereof, the entire disclosure of each application being incorporated herein by reference.

Technical Field

The present invention relates to new and improved methods, apparatus and systems for recovering and converting off-gas, such as flare gas, into useful and economically viable materials.

Background

The term "flare gas" and similar such terms should be given their broadest possible meaning and shall include gases produced, associated with, or produced from petroleum and natural gas production, hydrocarbon wells (which shall include both conventional and non-conventional wells), petrochemical processing, refining, landfill, wastewater treatment, dairy, livestock production, and other municipal, chemical, and industrial processes. Thus, for example, flare gas will include retentate gas, associated gas, landfill gas, vent gas, biogas, digester gas, mini-gas, and remote gas.

Typically, the composition of the flare gas is a mixture of different gases. The composition may depend on the source of the flare gas. For example, the gases released during oil and gas production contain mainly natural gas. More than 90% of natural gas is methane (CH ₄), and also contains ethane and small amounts of other hydrocarbons, water, N ₂, and CO ₂. The flare gas from refineries and other chemical or manufacturing operations may typically be a mixture of hydrocarbons, in some cases H ₂. Landfill gas, biogas or digester gas may typically be a mixture of CH ₄ and CO ₂, along with small amounts of other inert gases. In general, the flare gas may comprise one or more of the following gases: methane, ethane, propane, n-butane, isobutane, n-pentane, isopentane, n-hexane, ethylene, propylene, 1-butene, carbon monoxide, carbon dioxide, hydrogen sulfide, hydrogen, oxygen, nitrogen, and water.

Most flare gas is produced from a small single point source, such as many oil or gas wells in an oil field, landfill, or chemical plant. Prior to the present invention, flare gas, particularly flare gas produced from hydrocarbon production wells and other smaller point sources, was burned to destroy it, and in some cases may have been vented directly to the atmosphere. Such flare gas cannot be economically recovered and used. The combustion or emissions of flare gas from hydrocarbon production and other activities, or both, have raised serious concerns over pollution and greenhouse gas production.

Unless otherwise indicated, the terms "syngas" and "synthesis gas" and similar such terms as used herein should be given their broadest possible meaning and shall include gases having a mixture of H ₂ and CO as the principal components; and may also contain CO ₂、N₂ and water, as well as small amounts of other substances.

The term "product gas" and similar such terms as used herein should be given their broadest possible meaning unless otherwise indicated and will include gases having H ₂, CO, and other hydrocarbons, and typically include a significant amount of other hydrocarbons, such as methane.

The term "reprocessed gas" as used herein includes "synthesis gas", "synthesis gas" and "product gas" unless otherwise indicated.

Unless otherwise indicated, the terms "partially oxidized," "partially oxidized," and similar such terms as used herein refer to a chemical reaction in which a sub-stoichiometric mixture of fuel and air (i.e., a fuel-rich mixture) partially reacts (e.g., burns) to produce syngas. The term partial oxidation includes Thermal Partial Oxidation (TPOX) and Catalytic Partial Oxidation (CPOX), which typically occur in non-catalytic reformers. The partial oxidation reaction has the general formula

As used herein, unless otherwise indicated, the term "CO ₂ e" is used to define carbon dioxide equivalent of other stronger greenhouse gases to carbon dioxide (e.g., methane and nitrous oxide) based on the inter-government climate change committee (IPCC) fifth evaluation report (AR 5) method, based on 100 years of global warming potential. The term "carbon intensity" refers to the life cycle CO ₂ e produced per unit mass of product.

As used herein, unless otherwise indicated, the terms% and mol% are used interchangeably and refer to the mole of the first component as a percentage of the total, e.g., mole of the formulation, mixture, substance or product.

As used herein, recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein. Unless otherwise indicated herein, each individual value within the range is incorporated into the specification as if it were individually recited herein.

Generally, unless otherwise indicated, the term "about" as used herein is intended to include the greater of a variation or range of ±10% or experimental or instrumental errors associated with obtaining the stated values.

As used herein, unless otherwise indicated, room temperature is 25 ℃, and standard temperatures and pressures are 15 ℃ and 1 atmosphere (1.01325 bar).

Unless specifically provided, all entropy values discussed in the specification and shown in the figures (particularly the T-S diagram), including entropy states, entropy points, specific entropy points, and specific entropy values, are based on or used as reference states absolute zero (i.e., 0 deg. K, -273.15 deg. c) and 1 atmosphere.

Related art and terminology

In the production of natural resources from formations within the earth, wells or boreholes are drilled into the earth until the natural resources are deemed to be in place. These natural resources may be hydrocarbon reservoirs, including natural gas, crude oil, and combinations thereof; the natural resource may be fresh water; it may be a source of geothermal energy; or it may be some other natural resource located underground.

These resource-containing formations may be hundreds, thousands or tens of thousands of feet below the earth's surface, including below the bottom of a body of water, such as below the sea floor. These formations may cover areas of different sizes, shapes, and volumes in addition to being located at different depths within the earth.

Typically, as a general illustration, in drilling, an initial borehole is first drilled into the surface of the subsurface, such as land or the seabed, and then a subsequent smaller diameter borehole is drilled to extend the total depth of the borehole. In this way, as the entire borehole gets deeper, its diameter gets smaller; resulting in what can be thought of as a telescoping assembly of holes, wherein the largest diameter hole is located at the top of the borehole closest to the earth's surface.

Thus, for example, the beginning of the subsea drilling process may be explained generally as follows. Once the rig is positioned above the water surface above the area to be drilled, an initial borehole is formed by drilling a 36 inch hole into the surface to a depth of about 200 to 300 feet below the sea floor. A 30 inch cannula was inserted into the initial borehole. Such a 30 inch cannula may also be referred to as a catheter. The 30 inch conduit may or may not be cemented in place. During this drilling operation, a riser is typically not used, and cuttings from the borehole, such as earth and other materials removed from the borehole by drilling activities, are returned to the seafloor. Next, a 26 inch diameter borehole was drilled into the 30 inch casing, extending the borehole depth to about 1000 to 1500 feet. Such drilling operations may also be performed without the use of risers. A 20 inch cannula was then inserted into the 30 inch catheter and 26 inch borehole. This 20 inch sleeve was cemented in place. A wellhead was secured to the 20 inch casing. (in other operations, an additional smaller diameter borehole may be drilled and a smaller diameter casing inserted into the borehole while the wellhead is secured to the smaller diameter casing.) then a BOP (blowout preventer) is secured to the riser and lowered through the riser to the sea floor; wherein the BOP is fixed at the wellhead. From this point on, all drilling activities in the borehole are performed through the riser and BOP.

It should be noted that marine riser-free underwater drilling operations are also contemplated.

For land-based drilling processes, the steps are similar, but large diameter tubulars of 30-20 inches are typically not used. Thus, typically, the diameter of the skin sleeve is typically about 13/8 inch. This may extend from the surface (e.g., wellhead and blowout preventer (BOP)) to depths of tens to hundreds of feet. One of the purposes of the surface casing is to meet the environmental requirements for protecting groundwater. The surface casing should have a diameter large enough to allow the passage of production equipment and circulating mud such as drill strings, electronic Submersibles (ESPs), and the like. Below the casing, one or more intermediate casings of different diameters may be used. (it should be understood that portions of the borehole may not be cased, and these portions are referred to as open hole.) although larger or smaller sizes may be used, they may range in diameter from about 9 inches to about 7 inches and may extend to depths of thousands to tens of thousands of feet. A production tubing is located inside the casing, extending up from the production or production zone of the borehole and through a wellhead at the surface. There may be a single production tubing or multiple production tubing in a single borehole, each production tubing ending at a different depth.

By using hydraulic fracturing techniques, fluid communication between the formation and the well may be greatly increased. The date of first use of hydraulic fracturing can be traced back to the end of the 40 th 20 th century and the beginning of the 50 th 20 th century. Typically, hydraulic fracturing treatments include pressing fluid into a well and into a formation, the fluid entering the formation and breaking, e.g., forcing a rock layer to crack or fracture. The channels or flow paths created by these cracks may have cross-sections with dimensions of a few micrometers, a few millimeters or even larger. The fracture may also extend several feet, tens of feet, or more from all directions of the well. It should be remembered that the longitudinal axis of the well in the reservoir may not be perpendicular: it may be inclined (up or down) or may be horizontal. For example, in the exploitation of shale gas and oil, wells are typically substantially horizontal in the reservoir. The well section located within the reservoir, i.e., the section of the reservoir containing natural resources, may be referred to as the producing zone.

As used herein, unless otherwise indicated, the terms "hydrocarbon exploration and production," "exploration and production activities," "E & P," and "E & P activities," and similar such terms are to be given their broadest possible meanings and include surveying, geological analysis, well planning, reservoir management, drilling, workover and completion activities, hydrocarbon production, hydrocarbon removal from a well, hydrocarbon collection, secondary and tertiary recovery from a well, management of hydrocarbons removal from a well, and any other upstream activities.

As used herein, unless otherwise indicated, the term "earth" shall be given its broadest possible meaning and includes the ground, all natural materials such as rock, and man-made substances such as concrete found in or likely to be found in the ground.

As used herein, unless otherwise indicated, "offshore" and "offshore drilling activities" and similar such terms are used in their broadest sense and shall include drilling activities on or in any body of water, whether fresh water or brine, whether man-made or naturally occurring, such as rivers, lakes, canals, inland, oceans, sea regions (such as north sea), estuaries and bays (such as the gulf of mexico). As used herein, unless otherwise indicated, the term "offshore drilling rig" will be given its broadest possible meaning and will include fixed towers, supply vessels, platforms, barges, jack-up platforms, floating platforms, drill ships, dynamically positioned drill ships, semi-submersible platforms, and dynamically positioned semi-submersible platforms. As used herein, unless otherwise indicated, the term "seafloor" will be given its broadest meaning and shall include any surface of the earth, whether fresh or salty, whether man-made or naturally occurring, beneath or at the bottom of any body of water.

As used herein, unless otherwise indicated, the term "borehole" shall be given its broadest possible meaning and includes any opening formed in the earth that is substantially longer than its width, such as wells, wellbores, boreholes, micro-holes, micro-boreholes, and other terms commonly used or known in the art, to define these types of elongate passages. Wells also include exploration wells, production wells, disposal wells, re-entry wells, rework wells, and injection wells. They include cased and uncased wells, as well sections of these wells. Uncased or open hole sections are also known as open hole or open hole sections. The bore holes may also have differently oriented sections or portions, which may have straight portions and arcuate portions, and combinations thereof. Thus, as used herein, unless specifically stated otherwise, the "bottom" of a borehole, the "bottom surface" of a borehole, and similar terms refer to the end of a borehole, i.e., the portion of the borehole furthest from the opening of the borehole, the earth's surface, or the start of the borehole, along the path of the borehole. The terms "side" and "wall" of the borehole should be given their broadest meaning and include the longitudinal surface of the borehole, whether a casing or liner is present or not, as such these terms shall include the side of the open borehole or the side of the casing already positioned within the borehole. The borehole may be composed of a single channel, multiple channels, connecting channels (e.g., a branched configuration, a fishbone structure, or a comb structure), and combinations and variations thereof.

Drill holes are typically formed and advanced by using mechanical drilling equipment with a rotary drilling tool (e.g., a drill bit). For example, typically, when drilling holes in the earth, a drill bit extends into the earth and rotates to drill holes in the earth. In order to perform a drilling operation, the drill bit must be pressed against the material to be removed with sufficient force to exceed the shear strength, compressive strength, or a combination thereof of the material. Substances cut from the earth are often referred to as cuttings, such as waste, which may be rock fragments, dust, rock fibers, and other types of substances and structures that may result from the interaction of the drill bit with the earth. These cuttings are typically removed from the borehole by use of a fluid, which may be a liquid, foam, or gas, or other substances known in the art.

As used herein, unless otherwise indicated, the term "drill pipe" will be given its broadest possible meaning and includes all forms of pipe used for drilling activities; and refers to a single tube segment or a single piece tube. As used herein, the terms "drill pipe column," "rod column," "column," and similar types of terms shall be given their broadest possible meaning and include two, three, or four sections of drill pipe that are typically connected together by a joint having a threaded connection. As used herein, the terms "drill string," "tubular string," and similar types of terms shall be given their broadest definition and shall include one or more columns that are connected together for use in a borehole. Thus, the drill string may include many columns and hundreds of drill pipe sections.

As used herein, unless otherwise indicated, the terms "formation," "reservoir," "producing zone," and similar terms are to be given their broadest possible meaning and shall include all locations, regions, and geologic features within the earth that contain, may contain, or are considered to contain hydrocarbons.

As used herein, unless otherwise indicated, the terms "field," "oilfield," and similar terms are to be given their broadest possible meaning and are intended to include any region of land, sea, or water that is loosely or directly associated with a formation, and more specifically, associated with a resource-containing formation, and thus, an oilfield may have one or more exploration and production wells associated therewith, an oilfield may have one or more government agencies or private resource leases associated therewith, and one or more oilfield may be directly associated with a resource-containing formation.

As used herein, unless otherwise indicated, the terms "conventional natural gas," "conventional petroleum," "conventional products," and similar such terms are to be given their broadest possible meaning and include hydrocarbons, such as natural gas and petroleum, that are captured in the earth's structure. Typically, in these conventional formations, hydrocarbons have migrated into the permeable or semi-permeable formation to trap or the area where they accumulate. Typically, in conventional formations, a non-porous layer is located over or surrounding the region of accumulated hydrocarbons, essentially trapping the hydrocarbon accumulation. Conventional reservoirs have historically been the source of most hydrocarbons produced. As used herein, unless otherwise indicated, the terms "unconventional natural gas," "unconventional petroleum," "unconventional products," and similar such terms are to be given their broadest possible meaning and include hydrocarbons that are stored in impermeable rock and do not migrate to trapped or aggregated areas.

Global warming and environmental problems

Fig. 22 shows the relative hazard of exhaust emissions to the environment compared to CO ₂, an acknowledged high problem gas.

The global warming potential of flare gas and methane slip from blowdown is not so emphasized as to its environmental impact. According to the 2019 International Energy Agency (IEA) report, about 2000 hundred million cubic meters (bcm) of waste or flare gas was burned or vented to the atmosphere in 2018. About 50bcm of gas is vented and about 150bcm of gas is burned in the flare. Combustion aims to convert hydrocarbons to CO ₂, but its peak efficiency is 98% and efficiency is reduced in windy conditions. The combination of inefficient combustion and emissions results in a total CO ₂ e emission of about 1.4 gigatons of CO ₂, which corresponds to about 2.7% of all artificial CO ₂ sources per year.

This background section is intended to introduce various aspects of the art that may be associated with embodiments of the present invention. Accordingly, the above discussion in this section provides a framework for better understanding of the present invention and should not be deemed an admission of prior art.

Disclosure of Invention

There is a long-felt, expanding and unmet need for systems, apparatus and methods for converting otherwise uneconomical hydrocarbon-based fuels (e.g., flare gas) into value-added, easily transportable products such as methanol, ethanol, mixed alcohols, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals. The present invention addresses these needs, among other things, by providing articles, devices, systems, and processes taught and disclosed herein.

Accordingly, there is provided a system for converting flare gas to a final product, the system having: a reformer stage and a synthesis stage; the reformer stage includes: an inlet for receiving a flare gas stream; an air inlet for receiving an air flow; a mixer for combining the air stream and the flare gas stream; wherein the mixer is configured to provide a mixture having a rich fuel/air equivalence ratio; a gas-absorbing reformer configured to operate under fuel/air rich conditions; wherein the reformer is configured to operate in a partial oxidation combustion window; whereby the reformer is configured to convert the mixture into synthesis gas; a line for flowing the synthesis gas to the synthesis stage; the synthesis stage comprises: a line for receiving the synthesis gas stream from the reformer stage; a synthesis unit configured to receive the synthesis gas and convert the synthesis gas to a final product; a control system configured to operate the reformer stage at a predetermined partial oxidation temperature and a predetermined partial oxidation pressure, and to operate the synthesis stage at a predetermined synthesis temperature and a predetermined synthesis pressure.

Further, a system for converting flare gas to a final product is provided, the system having: a torch air source, defining an initial specific entropy; an oxygen source, wherein the oxygen source comprises air; defining a fuel/air mixture having an initial specific entropy; a control system; a suction reformer; a reformer is coupled to the control system and is configured to partially oxidize a mixture of the oxygen source and the flare gas; thereby providing a reprocessed gas stream comprising synthesis gas; a synthesis unit coupled to the control system and configured to provide a first product stream comprising a final product; wherein the final product stream and the exhaust product stream define a final specific entropy; the control system is configured as an operating system, wherein a difference between a starting specific entropy and a final specific entropy is less than about 1kJ/kg ℃; and wherein, during operation, the system is configured to produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

Further, there is provided a continuous process for converting flare gas to methanol, the process comprising: receiving a flare gas stream from a source, wherein: the flare gas stream has a rate of about 50000scfd to about 30000000 scfd; the flare gas stream has a composition, wherein the composition varies over time; compressing the flare gas stream to provide a compressed flare gas stream, wherein the compressed flare gas stream has a pressure of about 8 bar to about 60 bar; mixing the compressed flare gas stream with air to provide a fuel/air rich mixture; partially oxidizing the fuel/air rich mixture in the reformer at a temperature of about 700 ℃ to about 1200 ℃ to provide a reprocessed gas stream; wherein the reprocessed gas stream has a synthesis gas having a synthesis gas composition; passing the reprocessed gas stream through a deoxygenation reactor, thereby removing any excess oxygen from the reprocessed gas stream to provide a deoxygenated reprocessed gas stream; removing water from the deoxygenated, reprocessed gas stream to provide a synthesis gas stream; controlling the pressure and temperature of the synthesis gas stream to provide a predetermined synthesis temperature and synthesis pressure of the synthesis gas stream; flowing the synthesis gas stream into a synthesis unit at a predetermined synthesis temperature and synthesis pressure; converting the synthesis gas stream in a synthesis unit, thereby providing a first product stream having methanol; and removing a substance from the first product stream, the substance having hydrogen; thereby providing a second product stream; wherein the second product stream has at least about 80% methanol and thus at least about 80% purity.

Still further, there is provided a continuous process for converting flare gas to methanol, the process comprising: receiving a flare gas stream from a source, wherein the flare gas stream has a flow rate; receiving an air flow from an air inlet; mixing a flare gas stream with a flow of air to provide a fuel/air mixture; wherein the fuel/air mixture defines an initial specific entropy; flowing a fuel/air mixture having a pressure of about 8 bar to 60 bar into a reformer, partially oxidizing the fuel/air rich mixture in the reformer at a temperature of about 700 ℃ to about 1200 ℃ to provide a reprocessed gas stream; wherein the reprocessed gas stream has a synthesis gas having a synthesis gas composition; controlling the pressure and temperature of the reprocessed gas stream to provide a predetermined synthesis temperature and a predetermined synthesis pressure of the synthesis gas stream; converting the reprocessed gas stream in the synthesis unit at a predetermined synthesis temperature and synthesis pressure in the synthesis unit to provide a first product stream comprising methanol; wherein the first product stream and the off-gas product stream thus define a final specific entropy; and wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃.

Additionally, a system for converting flare gas to an end product is provided, the system having: a torch air source, defining an initial specific entropy; an air source; a fuel/air mixture defining an initial specific entropy; a control system; a suction reformer; the reformer is coupled to a control system and configured to partially oxidize a mixture of air and flare gas; thereby providing a reprocessed gas stream comprising synthesis gas; a synthesis unit coupled to the control system and configured to provide a first product stream comprising a final product; wherein the final product stream and the offgas product stream define a final specific entropy; the control system is configured as an operating system, wherein a difference between the initial specific entropy and the final specific entropy is less than about 1kJ/kg ℃; and wherein during operation the system is configured to net carbon negative, whereby during operation the system produces less than about-20 kgCO e per 1 kilogram of end product provided.

Further, a system for converting flare gas to a final product is provided, the system having: a torch air source, defining an initial specific entropy; an air source; a fuel/air mixture defining an initial specific entropy; a control system; a suction reformer; the reformer is coupled to a control system and configured to partially oxidize a mixture of air and flare gas; thereby providing a reprocessed gas stream comprising synthesis gas; a synthesis unit coupled to the control system and configured to provide a first product stream comprising a final product; wherein the final product stream and the offgas product stream define a final specific entropy; the control system is configured as an operating system, wherein a difference between the initial specific entropy and the final specific entropy is less than about 1kJ/kg ℃; wherein during operation the system is configured to be net carbanionic, whereby during operation the system produces less than about-20 kgCO e per 1 kg of end product provided; and wherein during operation, the system is configured to produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

Further, a process for converting flare gas to a final product is provided, the process comprising: receiving flare gas from a source; forming a mixture of flare gas and an oxygen source, wherein the oxygen source has air, thereby defining a fuel/air mixture; wherein the fuel/air mixture defines an initial specific entropy; partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream having a synthesis gas composition; converting the reprocessed gas stream in a synthesis unit to provide a first product stream having a final product; wherein the first product stream and the off-gas product stream thus define a final specific entropy; and wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃.

Still further, there is provided a carbon neutral process for converting flare gas to an end product, the process comprising: (a) receiving a flare gas stream from a source; (b) compressing flare gas; (c) partially oxidizing the flare gas to provide a reprocessed gas; and, (d) converting the reprocessed gas into a final product; wherein steps (a) through (d) produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

Additionally, a net carbon negative process is provided for capturing and converting flare gas to a final product comprising methanol, the process comprising: (a) receiving a flare gas stream from a source; (b) compressing the flare gas to a predetermined partial oxidation pressure; (c) Mixing the flare gas with air to provide a fuel mixture, wherein the fuel/air equivalence ratio of the fuel mixture is greater than 1; (d) Partially oxidizing the flare gas at a predetermined partial oxidation temperature to provide a synthesis gas, wherein the synthesis gas has an H ₂/CO ratio of from about 1 to about 3; (e) Converting the synthesis gas to a final product at a predetermined synthesis temperature and a predetermined synthesis pressure; wherein the final product comprises methanol; and wherein steps (a) through (e) are net carbanionic, whereby each step produces less than about-20 kgCO e per 1kg of methanol produced.

Additionally, a carbon neutral process for making a final product is provided, the process comprising: (a) partially oxidizing the flare gas to provide a reprocessed gas; (b) converting the reprocessed gas into a final product; wherein each partial oxidation of 1 kilogram of flare gas steps (a) through (b) produces less than 2.0kg of CO ₂; and wherein steps (a) through (b) are net carbanionic, whereby the steps produce less than about-20 kg CO2e per 1 kg of final product produced.

Still further, a process for converting flare gas to a final product is provided, the process comprising: (a) receiving flare gas from a source; (b) Forming a mixture of flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy; (c) Partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition; (d) Converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy; wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; and wherein steps (a) through (d) receive 1 kilogram of flare gas to produce less than 2.0kg of CO ₂.

Further, a system for converting flare gas to a final product is provided, the system having: a reformer stage and a synthesis stage; the reformer stage includes: an inlet for receiving a flare gas stream; an air inlet for receiving an air flow; a gas-absorbing reformer configured to operate under fuel/air rich conditions; wherein the reformer is configured to operate in a partial oxidation combustion window; whereby the reformer is configured to convert a mixture of flare gas and air into synthesis gas; a line for flowing the synthesis gas to the synthesis stage; the synthesis stage comprises: a line for receiving the synthesis gas stream from the reformer stage; a synthesis unit configured to receive the synthesis gas and convert the synthesis gas to a final product; and a control system configured to operate the reformer stage at a predetermined partial oxidation temperature and a predetermined partial oxidation pressure, and to operate the synthesis stage at a predetermined synthesis temperature and a predetermined synthesis pressure.

Further, a process for converting flare gas to a final product is provided, the process comprising: (a) receiving flare gas from a source; (b) Forming a mixture of flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy; (c) Partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition; (d) Converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy; wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; and wherein steps a) through d) are net carbanionic, whereby these steps result in less than about-20 kgCO e per 1 kg of end product provided.

Further, a process for converting flare gas to a final product is provided, the process comprising: (a) receiving flare gas from a source; (b) Forming a mixture of flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy; (c) Partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition; (d) Converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy; wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; wherein steps a) through d) produce less than 2.0kg of CO ₂ per 1 kg of flare gas received; and wherein steps (a) through (d) are net carbanionic, whereby each of these steps produces less than about-20 kg CO2e per 1 kg of final product provided.

Additionally, these systems, methods, and devices are provided having one or more of the following features: wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following: a compression ratio in the range of about 8:1 to about 17:1; an intake manifold air temperature of ambient to about 300 ℃; intake manifold air pressure from ambient to about 5 bar; ignition timing between TDC and 50 degrees before TDC; and an engine speed of about 8000rpm to about 1500 rpm.

Additionally, these systems, methods, and devices are provided having one or more of the following features: wherein the reformer is a reciprocating engine; and the reciprocating engine has at least one of: a compression ratio in the range of about 8:1 to about 17:1; an intake manifold air temperature of ambient to about 300 ℃; intake manifold air pressure from ambient to about 5 bar; ignition timing between TDC and 50 degrees before TDC; or an engine speed of about 8000rpm to about 1500 rpm.

Additionally, these systems, methods, and devices are provided having one or more of the following features: wherein the reformer comprises a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of: a first partial oxidation combustor; a two-stage combustion process; a gas turbine combustor; and a combustion cycle time of 5 milliseconds to 50 milliseconds.

Further, these systems, methods, and devices are provided having one or more of the following features: wherein the reformer comprises a gas turbine assembly; and the gas turbine assembly has at least one of: a first partial oxidation combustor; a two-stage combustion process; a gas turbine combustor; or a combustion cycle time of 5 milliseconds to 50 milliseconds.

Still further, these systems, methods, and devices are provided having one or more of the following features: having a hydrogen separation unit to provide a recovered hydrogen stream to the system; having a hydrogen separation unit to provide a recovered hydrogen stream for mixing with the synthesis gas; having a hydrogen separation unit to provide a recovered hydrogen stream for mixing with the synthesis gas; and wherein the control system is configured to control the mixing of the recovered hydrogen with the syngas to provide a predetermined H ₂ to CO ratio.

Additionally, these systems, methods, and devices are provided having one or more of the following features: wherein the suction reformer comprises a reciprocating engine having a variable compression ratio; and also has: a sensor system for detecting ignition/combustion behavior in a range from pre-ignition to misfire; and is configured to transmit detected ignition/combustion behavior information; wherein the control system is in control communication with the sensor system and the engine; wherein the control system is configured to adjust the engine compression ratio based on the detected ignition/combustion behavior information; and, thus, the control system is configured to adjust the compression ratio in response to variability in the composition of the flare gas.

Further, these systems, methods, and devices are provided having one or more of the following features: having a fuel conditioning system to remove liquids and contaminants detrimental to downstream components to provide a conditioned fuel source; having a separation assembly associated with the synthesis unit, wherein byproducts are selectively removed in situ from the synthesis unit; having a separation assembly associated with the synthesis unit, wherein byproducts are selectively removed from the synthesis unit by a liquid or gas purge; wherein the byproduct is water; wherein the separation assembly comprises at least one of a membrane separation device, an absorption device, an adsorption device, or a distillation device; having a separation assembly associated with the synthesis unit, wherein the final product is selectively removed in situ from the synthesis unit; having a separation assembly associated with the synthesis unit, wherein the final product is selectively removed from the synthesis unit by liquid or gas purging; wherein the final product is methanol; wherein the separation assembly comprises at least one of a membrane separation device, an absorption device, an adsorption device, or a distillation device.

Additionally, these systems, methods, and devices are provided having one or more of the following features: wherein the engine is a compression ignition engine; wherein the engine is a spark ignition engine; wherein the engine is an opposed piston free piston linear internal combustion engine; wherein the engine is a crankshaft driven opposed piston internal combustion engine with a crankshaft phaser for rotating the phase of one piston relative to the other piston to vary the overall compression ratio; wherein the engine is a conventional spark-ignition reciprocating engine, wherein the engine is configured for variable effective compression ratio, utilizing a camshaft phaser to rotate an intake camshaft and an exhaust camshaft, thereby affecting valve opening and closing; wherein the engine is configured for variable effective compression ratio, valve opening and closing is achieved with variable lift, duration valve train, or both; and wherein the engine includes a multi-link system configured to rotate the crankshaft and includes an actuator motor configured to change an end point of the multi-link system.

Further, these systems, methods, and devices are provided having one or more of the following features: including passing the flare gas stream through a first heat exchanger, wherein the first heat exchanger receives a reprocessed gas stream from the reformer; whereby the flare gas stream is heated; including controlling partial oxidation in the reformer; whereby the composition of the synthesis gas in the reprocessed gas stream does not change as the composition of the flare gas stream changes; wherein the predetermined synthesis temperature is from about 200 ℃ to about 300 ℃; wherein the predetermined synthesis pressure is from about 30 bar to about 100 bar; wherein the predetermined synthesis temperature is from about 200 ℃ to about 300 ℃, and the predetermined synthesis pressure is from about 30 bar to about 100 bar; wherein the second product stream has at least 93% methanol and thus a purity of at least 93%; wherein the second product stream has from 90% to 95% methanol and is thus from 90% to 95% pure; wherein the reformer has a suction reformer; wherein the reformer has one or more of a gas turbine engine, a combustion box, an internal combustion engine, an otto cycle reciprocating engine, a diesel cycle reciprocating engine; wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from 1.1 to about 4; wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from about 1.5 to about 3.0; wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from about 1.5 to about 2.5; wherein the ratio of H ₂ to CO in the syngas is from about 1.0 to about 2.0; wherein the ratio of H ₂ to CO in the synthesis gas is from 0.8 to 2.5; wherein the ratio of H ₂ to CO in the syngas is from about 2 to about 3; wherein the ratio of H ₂ to CO in the synthesis gas is from 1.1 to 2.5; wherein the ratio of H ₂ to CO is less than 3; wherein the ratio of H ₂ to CO is less than 2.5; wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following: a compression ratio in the range of about 8:1 to about 17:1; an intake manifold air temperature of ambient to about 300 ℃; intake manifold air pressure from ambient to about 5 bar; and an ignition timing between TDC and 50 degrees before TDC; an engine speed of about 1500rpm to about 8000 rpm; wherein the reformer is selected from the group consisting of a two-stroke reciprocating engine and a four-stroke reciprocating engine; wherein the reformer is a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of: a first partial oxidation combustor; a two-stage combustion process; a gas turbine combustor; and a combustion cycle time of 5 milliseconds to 50 milliseconds; including capturing and using heat generated by the partial oxidation of a fuel/air rich mixture, wherein the heat is used in a continuous process for converting flare gas to methanol; wherein the flare gas stream has a rate of about 50000scfd to about 30000000 scfd; wherein the flare gas stream has a rate of greater than about 200000 scfd; wherein the flare gas stream has a rate of greater than about 200000 scfd; wherein the flare gas stream has a composition, wherein the composition varies over time; wherein the partial oxidation of the flare gas is conducted at a specific entropy of greater than about 7.1kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of greater than about 7.5kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of greater than about 8.0kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of about 7.1kJ/kg ℃ to about 8.6kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and1 atmosphere; comprising providing a fuel/air mixture to a reformer at a predetermined reformer pressure, wherein the partial oxidation is performed in the reformer at a predetermined reformer temperature; comprising controlling the pressure and temperature of the reprocessed gas stream to provide a predetermined synthesis temperature and a predetermined synthesis pressure of the reprocessed gas stream; wherein the final product is selected from the group consisting of methanol, ethanol, ammonia, mixed alcohols, dimethyl ether and F-T liquid; wherein the final product consists of methanol; wherein the final product consists essentially of methanol; wherein the predetermined temperature and pressure include one, more than one, or all of: (i) The predetermined partial oxidation temperature is from about 700 ℃ to about 1200 ℃; (ii) a predetermined partial oxidation pressure of about 1 bar to about 70 bar; (iii) a predetermined synthesis temperature of about 200 ℃ to about 300 ℃; and (iv) the predetermined resultant pressure is from about 30 bar to about 100 bar; wherein the change in the composition of the flare gas does not change the composition of the final product; and wherein the change in the composition of the flare gas does not require a change in one or more of a predetermined synthesis temperature, a predetermined synthesis pressure, a predetermined reformer temperature, and a predetermined reformer pressure; wherein byproducts are selectively removed in situ from the synthesis unit; wherein the byproducts are selectively removed from the synthesis unit by liquid or gas purging; wherein the byproduct is water; wherein the selective removal is by at least one of membrane separation, absorption, adsorption, or distillation; wherein the final product is selectively removed in situ from the synthesis unit; wherein the final product is selectively removed from the synthesis unit by liquid or gas purging; wherein the final product is methanol; wherein the selective removal is by at least one of membrane separation, absorption, adsorption, or distillation; wherein the source of the flare has the composition listed in tables 1 and 2; and wherein the source of the torch has a varying composition, wherein the varying composition is within the composition ranges listed in tables 1 and 2.

Still further, these systems, methods, and devices are provided having one or more of the following features: wherein the step of partially oxidizing the flare gas comprises combusting a mixture of the flare gas and an oxygen source; wherein the oxygen source comprises air and the mixture has a fuel/air equivalence ratio greater than 1; wherein the oxygen source comprises air and the mixture has a fuel/air equivalence ratio of from 1.1 to about 4; wherein the oxygen source comprises air and the mixture has a fuel/air equivalence ratio of from about 1.5 to about 3.0; using water, steam, or both in the step of partially oxidizing the flare gas; wherein the step of partially oxidizing the flare gas occurs in a gas-fired reformer; wherein the step of partially oxidizing the flare gas occurs in a reformer stage of the liquid-gas system; and wherein the reformer stage comprises one or more of a gas turbine engine, a combustion box, and a reciprocating engine; wherein the step of converting the reprocessed gas into the final product is performed at a predetermined synthesis temperature and a predetermined synthesis pressure; wherein the predetermined synthesis temperature is from about 200 ℃ to about 300 ℃; wherein the predetermined synthesis pressure is from about 30 bar to about 100 bar; wherein the predetermined synthesis temperature is from about 200 ℃ to about 300 ℃, and the predetermined synthesis pressure is from about 30 bar to about 100 bar; wherein the step of partially oxidizing the flare gas is performed at a predetermined reformer temperature and a predetermined reformer pressure; wherein the predetermined reformer temperature is from about 700 ℃ to about 1200 ℃; wherein the predetermined reformer pressure is from about 1 bar to about 70 bar; wherein the predetermined reformer temperature is from about 700 ℃ to about 1200 ℃; and the predetermined reformer pressure is from about 1 bar to about 70 bar; wherein the step of converting the reprocessed gas into the final product is performed at a predetermined synthesis temperature and a predetermined synthesis pressure; and the predetermined synthesis temperature is from about 200 ℃ to about 300 ℃, and the predetermined synthesis pressure is from about 30 bar to about 100 bar; a step of removing excess oxygen from the reprocessing gas; wherein the reprocessing gas comprises synthesis gas; wherein the reprocessing gas is comprised of syngas; wherein the change in the composition of the flare gas does not change the composition of the final product; wherein the step of converting the reprocessed gas into the final product is performed at a predetermined synthesis temperature and a predetermined synthesis pressure; wherein the step of partially oxidizing the flare is performed at a predetermined reformer temperature and a predetermined reformer pressure; wherein the change in the composition of the flare gas does not change the composition of the final product; and wherein the change in the composition of the flare gas does not require a change in one or more of a predetermined synthesis temperature and a predetermined synthesis pressure; wherein the step of converting the reprocessed gas into the final product is performed at a predetermined synthesis temperature and a predetermined synthesis pressure; wherein the step of partially oxidizing the flare gas is performed at a predetermined reformer temperature and a predetermined reformer pressure; wherein the change in the composition of the flare gas does not change the composition of the final product; and wherein the change in the composition of the flare gas does not require a change in one or more of a predetermined synthesis temperature, a predetermined synthesis pressure, and a predetermined reformer temperature; wherein less than 1.0kg of CO ₂ is produced per 1kg of flare gas treated, wherein less than 0.5kg of CO ₂ is produced per 1kg of flare gas treated, wherein less than 0.1kg of CO ₂ is produced per 1kg of flare gas treated, wherein less than 0.05kg of CO ₂ is produced per 1kg of flare gas treated, wherein the reprocessing gas comprises syngas; wherein the reprocessing gas consists essentially of syngas; wherein the reprocessing gas is comprised of syngas; wherein the final product is a liquid; wherein the final product is selected from the group consisting of methanol, ethanol, mixed alcohols, ammonia, dimethyl ether and F-T liquid; wherein the final product comprises methanol; wherein the final product consists essentially of methanol; wherein steps (a) through (d) or (a) through (e) are net carbanionic, whereby each of these steps produces less than about-20 kg co2e per 1kg of final product produced; wherein steps (a) through (d) or (a) through (e) are net carbanionic, whereby each of these steps produces less than about-40 kgCO e per 1kg of end product produced; wherein steps (a) through (d) or (a) through (e) are net carbanionic, whereby each of these steps produces less than about-100 kg CO2e per 1kg of final product produced; wherein steps (a) through (d) or (a) through (e) are net carbanionic, whereby each of these steps produces from about-20 kgCO e to about-150 kgCo e per 1kg of methanol produced; wherein steps (a) through (d) or (a) through (e) are net carbanionic, whereby each of these steps produces from about-40 kg CO2e to about-130 kg CO2e per 1kg methanol produced; and wherein the predetermined temperature and the predetermined pressure comprise one, more than one, or all of: (i) The predetermined partial oxidation temperature is from about 900 ℃ to about 1150 ℃; (ii) a predetermined partial oxidation pressure of about 1 bar to about 70 bar; (iii) a predetermined synthesis temperature of about 200 ℃ to about 300 ℃; and (iv) the predetermined resultant pressure is from about 30 bar to about 100 bar.

Additionally, these systems, methods, and devices are also provided having one or more of the following features: wherein less than about-40 kg CO2e per 1kg of end product is produced; wherein less than about-100 kg CO2e per 1kg of end product is produced; wherein about-20 kg CO2e to about-150 kg CO2e per 1kg methanol produced; wherein about-40 kg CO2e to about-130 kg CO2e per 1kg methanol produced; wherein less than 1.0kg of CO ₂ is produced per kilogram of flare gas, wherein less than 0.5kg of CO ₂ is produced per kilogram of flare gas, and wherein less than 0.1kg of CO ₂ is produced per kilogram of flare gas; wherein less than 0.05kg of CO ₂ is produced per kg of flare gas; the method of any of claims 73 to 78, wherein the partial oxidation of the flare gas is performed at a specific entropy of greater than about 7.1kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of greater than about 7.5kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of greater than about 8.0kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere; wherein the partial oxidation of the flare gas is conducted at a specific entropy of about 7.1kJ/kg ℃ to about 8.6kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere.

Further, these systems, methods, and devices are provided having one or more of the following features: wherein the initial specific entropy differs from the final specific entropy by less than about 0.5kJ/kg ℃; wherein the difference between the initial specific entropy and the final specific entropy is less than 0.3kJ/kg ℃; and wherein the initial specific entropy differs from the final specific entropy by less than 0.2kJ/kg ℃.

Further, these systems, methods, and devices are provided having one or more of the following features: wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following: a compression ratio in the range of about 8:1 to about 17:1; an intake manifold air temperature of ambient to about 300 ℃; intake manifold air pressure from ambient to about 5 bar; to about 300 ℃; ignition timing between TDC and 50 degrees before TDC; and an engine speed of about 8000rpm to about 1800 rpm; wherein the reformer is selected from the group consisting of a two-stroke reciprocating engine and a four-stroke reciprocating engine; wherein the reformer is a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of: a first partial oxidation combustor; two-stage combustion; a gas turbine combustor; and a combustion cycle time of 5 milliseconds to 50 milliseconds.

Still further, these systems, methods, and devices are provided having one or more of the following features: wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from 1.1 to about 4; wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from about 1.5 to about 3.0; wherein the rich fuel/air mixture has a fuel/air equivalence ratio of from about 1.5 to about 2.5; wherein the ratio of H ₂ to CO in the syngas is from about 1.0 to about 2.0; wherein the ratio of H ₂ to CO in the synthesis gas is from 0.8 to 2.5; wherein the ratio of H ₂ to CO in the syngas is from about 2 to about 3; wherein the ratio of H ₂ to CO in the synthesis gas is from 1.1 to 2.5; wherein the ratio of H ₂ to CO is less than 3; wherein the ratio of H ₂ to CO is less than 2.5.

Drawings

Fig. 1 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 2 is a T-S diagram of an embodiment of a thermodynamic state point for converting flare gas and other waste into synthesis gas and then into value added products using an embodiment of a suction process in accordance with the present invention.

Fig. 3 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 4 is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using the system of FIG. 3 in accordance with the present invention.

Fig. 5 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 6 is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using the system of FIG. 5 according to the present invention.

FIG. 7 is a partial cutaway perspective view of an embodiment of a gas turbine for use in an embodiment of a reformer stage according to the present disclosure.

FIG. 7A is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using an embodiment of the present system according to the present invention.

Fig. 8 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 9 is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using the system of FIG. 8 with a spark-ignition reciprocating engine in accordance with the present invention.

FIG. 9A is a table listing embodiments of the operating conditions of the system of FIG. 8 and the operating conditions of FIG. 9 with a spark-ignition reciprocating engine in accordance with the present invention.

Fig. 10A is a cross-sectional view of an embodiment of an engine reformer according to the present disclosure.

FIG. 10B is a cross-sectional view of an embodiment of a variable compression engine reformer showing piston height in accordance with the present invention.

FIG. 11 is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using the system of FIG. 8 with a compression ignition reciprocating engine in accordance with the present invention.

Fig. 12 is a cross-sectional view of an opposed-piston internal combustion reciprocating reformer engine in accordance with the present invention.

FIG. 13 is a graph comparing displacement of opposed-piston engine reformers according to the present disclosure.

Fig. 14 is a schematic flow diagram of an embodiment of a system and process of a modular reformer stage according to the present disclosure.

FIG. 15 is a schematic flow chart diagram of an embodiment of a system and process of a modular synthesis stage according to the present invention.

Fig. 16 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 17 is a T-S diagram illustrating an embodiment of a process, operating conditions, and thermodynamic state points for converting flare gas to synthesis gas and then to methanol using the system of FIG. 16 according to the present invention.

FIG. 17A is a graph showing compressor power as a function of engine back pressure in accordance with an embodiment of the present system.

Fig. 18 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

Fig. 19 is a schematic flow chart diagram of an embodiment of a system and process in accordance with the present invention.

FIG. 20A is a pie chart illustrating the composition of an embodiment of lean flare gas that may be processed by the present system and method according to the present invention.

FIG. 20B is a pie chart illustrating the composition of an embodiment of rich flare gas that may be processed by the present system and method according to the present invention.

FIG. 21 is a graph showing various compositions and varying Wobbe numbers of flare gas versus fuel heating value that may be processed by embodiments of the present systems and methods according to the present invention.

Fig. 22 is a table showing global warming potential values.

Fig. 23 is a graph comparing CO2e of an example of methanol according to the present invention with methanol obtained from a conventional method.

FIG. 24 is a schematic diagram of an embodiment of a control system for embodiments of the present system and method according to the present invention.

FIG. 25 is a detailed schematic diagram of an embodiment of a control system for use with embodiments of the present system and method according to the present invention.

The T-S diagrams of these figures are all drawn and depicted on diagrams having the same axes. The unit of the specific entropy axis (x-axis) is kJ/kg℃and the entropy per unit mass of air is described. The temperature axis (y-axis) is in degrees celsius and describes the fluid temperature, assuming properties similar to air. The relationship between temperature and isobars is determined by the physical properties of the fluid.

Detailed Description

The present invention relates generally to systems, apparatus and methods for recovering useful material from off-gas such as flare gas in an economical manner. Embodiments of the present invention generally relate to systems, apparatus, and methods for achieving such recovery at a smaller, isolated, or remote location or point source of exhaust gas.

Embodiments of the present invention generally relate to methods, apparatus, and systems for utilizing flare gas to produce a reprocessed gas and then utilizing the reprocessed gas to provide useful and economically viable materials. In particular, embodiments of the present invention relate to methods, apparatus and systems for producing, recovering and treating reprocessed gases to provide useful and economically viable materials.

Embodiments of the present invention have reciprocating engines, gas turbine engines, or both to produce reprocessed gas, preferably syngas. These embodiments may be modular and may be easily and quickly positioned in difficult to access locations, locations with limited area for placement of the system, and combinations and variations of these locations where flare gas is typically produced.

System and procedure overview

Generally, embodiments of the present systems and methods may be associated with hydrocarbon fuel sources. The hydrocarbon fuel may be solid, liquid, gas, slurry, combinations and variations of these. Preferably, the hydrocarbon fuel is an off-gas, and in particular flare gas. The system is in fluid communication with a hydrocarbon fuel source via, for example, piping, conduit tubing, hoses, etc., and hydrocarbon fuel is provided to the system in this manner. The hydrocarbon source may be an active source in that the hydrocarbon is actively flowing, for example, from a subterranean borehole, hydrocarbon producing well, refinery or chemical plant. The hydrocarbon source may be a static source in that the hydrocarbon is contained in and obtained from a stored or collected source such as a storage tank, tank farm, tank truck, railcar, barge, container, or the like. The hydrocarbon fuel source may be a combination and variation of active and static sources.

Typically, a hydrocarbon fuel source (e.g., flare gas) and an oxygen source (e.g., air) are fed to the reformer unit where the hydrocarbon fuel source is converted to a reprocessing gas, such as syngas, preferably by controlled and predetermined combustion. The reformer stage of the universal system and method may also have equipment for treating and processing the incoming hydrocarbon fuel source (e.g., flare gas) and oxygen source (e.g., air), as well as equipment for treating the reprocessed gas (e.g., syngas), such as valves, controllers, compressors, sensors and monitors, temperature control systems, mixers, filters and screens, separators, equipment for removing water, guard beds, guard bed reactors, deoxygenation reactors, and other treatment and processing equipment and methods. It should be appreciated that some or all of the reprocessing gas, such as syngas, processing equipment and methods may be staged or located in a general system other than the reformer stage.

In general, the reformer and reformer stages are preferably operated in a predetermined manner to optimize the composition of the obtained reprocessed gas (e.g., syngas) so that the reprocessed gas (e.g., syngas) has a predetermined composition that is determined to have optimal performance in its conversion to value-added products (e.g., methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, as well as combinations and variations of these).

Typically, the reprocessed gas (e.g., syngas) from the reformer is provided to a synthesis unit (e.g., a methanol unit) where the reprocessed gas (e.g., syngas) is converted to value-added products such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, as well as combinations and variations of these. Preferably, the value-added product is collected and stored as a liquid. It should be appreciated that the value added product may be gaseous, or in other states. The synthesis stage, such as a methanol synthesis stage, may have additional equipment and methods for processing and treating the incoming reprocessed gas (e.g., syngas), as well as for treating and processing value-added products (e.g., methanol), including, for example, valves, controllers, compressors, sensors and monitors, mixers, filters and screens, temperature control systems, separators, water removal equipment, and other processing and processing equipment and methods. When value added products (e.g., methanol) are formed, the pressure of the reprocessing gas (e.g., syngas) may and preferably is controlled (e.g., compressed) prior to being provided to the synthesis unit (e.g., methanol unit).

Generally, the systems and methods may have additional separation and treatment equipment, for example, to remove hydrogen from value added products such as methanol. In these embodiments, the hydrogen gas may preferably be used to generate electricity to operate the system, as well as potentially other devices, such as systems that produce excess electricity.

These stages may be in a single system, in a single integrated system, in separate systems, in two or more modular systems, and in combinations and variations of these systems.

Generally, the system and method has a control system. The control system may include a computer having a processor, a memory, and a data memory. The control system may also include controllers, such as program logic controllers ("PLCs"), input/output ("I/O"), sensors, graphical User Interfaces (GUIs), and communication protocols and capabilities, such as web servers, mobile phones, satellites. In an embodiment, the control system includes a blockchain for authenticating the operation of the system and method, such as the quality balance of the method and operation, and verifying, encrypting, and authenticating data related to carbon capture, greenhouse gas reduction, carbon credits, and the like.

Accordingly, preferred embodiments of the present system relate to liquid to gas systems and methods, such as flare gas to methanol.

In general, a reformer may be one or more devices or device components that burn off-gas, such as flare gas, under controlled and predetermined conditions to provide a reprocessed gas. Preferably, one or more of the temperature, pressure and composition of the reprocessed gas is optimised for use in the synthesis stage, and the controlled and predetermined conditions under which the reformer is operated are optimised to provide such optimised temperature, pressure and composition of the reprocessed gas. Thus, and in general, a reformer may have one or more combustion devices, combustion chambers, engines, internal combustion engines, reciprocating engines, rotary engines, gasoline engines (i.e., spark ignition), diesel engines (i.e., compression ignition), jet engines, turbine engines, gas turbine engines, air-breathing combustion devices, and combinations and variations of these, as well as other peripheral or auxiliary devices and equipment.

Embodiments of the present invention may be used to capture uneconomical hydrocarbon-based fuels of primarily gaseous hydrocarbons at the wellhead and at remote locations and convert them into more valuable readily condensable or liquid compounds, such as methanol. One source of fuel may be associated gas or flare gas, which is a byproduct of an oil well. Another source is flare gas produced by industrial processes, such as refinery flare gas. Yet another source may be biogas from a landfill site or an anaerobic digester.

Generally, embodiments of the present systems and methods use an off-gas, preferably flare gas. Examples of the composition of flare gas that any reformer of the present systems and methods can treat to a reprocessing gas that is then processed by the synthesis unit to value added products (e.g., methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals) are listed in tables 1 and 2. The flare gas may have one or more of the different amounts of one or more of the components or ingredients listed in these tables and all.

TABLE 1 examples of flare gas compositions

TABLE 2 examples of biogas flare gas compositions

FIGS. 20A and 20B also provide compositions of flare gas that may be present and treated by embodiments of the present invention. FIG. 20A illustrates a typical composition of lean flare gas and FIG. 20B illustrates a typical composition of rich flare gas. The lean flare gas and the rich flare gas may have methane 2001, ethane 2002, propane 2003, butane 2004, impurities 2005, and the rich flare gas may also include pentane 2006 and hexane and heavier hydrocarbons 2007. FIG. 21 is a graph illustrating Wobbe number versus various compositions and varying fuel heating values of flare gas that may occur and be treated by embodiments of the present invention.

In embodiments of the present systems and methods, and in embodiments of small modular systems, these compositions (e.g., table 1, table 2, fig. 20A, fig. 20B, fig. 21) represent compositions and variations in compositions that the present systems and methods can be used for gas-to-liquid synthesis (e.g., feed gas-to-liquid methanol).

The present invention (including the exemplary embodiments) may use and reprocess flare gas of any of the ranges of compositions and components listed in tables 1, 2 and combinations of compositions and ranges in these tables, as well as other ranges of compositions and components. One of the reasons that these gases are not economical is the large variation in the composition of the flare gas. Thus, the composition of flare gas may vary from source to source, the composition of the same source may vary from day to day (transients), from season to season (e.g., biogas), and as sources (e.g., wells) age. These variations have an effect on combustion properties such as: heating value, cetane number (delay in fuel ignition time), and octane number (anti-pre-ignition due to compression). Embodiments of the present reformer address these variations and provide the ability to operate in a consistent and efficient manner to treat the composition of these varied flare gases at the source site to provide a reprocessed gas, such as syngas, and preferably a syngas that is consistent, predetermined, and both with respect to composition and temperature of the syngas.

Turning to fig. 1, a general embodiment of a system and method for converting an off-gas (e.g., flare gas) to a value-added product (e.g., methanol) is shown. The system 100 has a reformer stage 101 and a synthesis stage 102. The system 100 has an air inlet 110 that feeds air into a compressor 111 that compresses the air. The compressed air is fed into the mixer 113 through the heat exchanger 120 a. The system has an exhaust gas (e.g., flare gas) inlet 114. The exhaust gas flows into the mixer 113 through the heat exchanger 120 b. As taught and disclosed in this specification, the mixer 113 provides a predetermined mixture of air and exhaust gas to the reformer 114.

The fuel-air mixture formed in mixer 113 is preferably rich, more preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

It should be appreciated that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As used herein, "aspirated" reformers and aspirated engines are understood to also include engines that use air modified by the addition of water, oxygen, or both.

The reformer 114 combusts a predetermined mixture of flue gas and air (e.g., flare gas and air) to form a reprocessed gas (e.g., syngas). The syngas flows through the heat exchangers 120a, 120b and enters the filter 115, such as a particulate filter.

After passing through the filter 115, the reprocessing gas (e.g., syngas) flows to a guard bed reactor assembly 116 having two guard bed reactors 116a, 116 b. Guard bed reactor 116 has materials, such as catalysts, that remove contaminants and other materials from the syngas that may damage, inhibit or contaminate subsequent devices and processes in the system. For example, guard bed reactor 116 may contain a catalyst or other material to remove sulfur (e.g., sponge iron, zinc oxide, or the like) and halogenated compounds.

After exiting guard bed reactor 116, the reprocessing gas (e.g., syngas) flows to deoxygenation reactor 117. The deoxygenation reactor 117 removes excess oxygen from the reprocessed gas (e.g., syngas) by oxidizing combustible compounds in the mixture, such as methane, CO, and H ₂, where the oxygen is converted to water. The catalyst for the deoxygenation reaction is platinum, palladium, and other active materials supported on alumina or other catalyst support materials.

The system 100 has a cooling system 150 that uses a cooling fluid, such as cooling water, that flows through a cooling line, such as 151.

After exiting deoxygenation reactor 117, the reprocessed gas (e.g., syngas) flows to heat exchanger 120c. The reprocessing gas (e.g., syngas) then flows from the heat exchanger 120c to a water removal unit 118, such as a water separator, mist eliminator, dryer, membrane, cyclone, desiccant, or similar device, where water is removed from the reprocessing gas (e.g., syngas). Typically, the reprocessing gas (e.g., syngas) exiting unit 118 should have less than about 5 wt.% water, less than about 2 wt.%, less than about 1 wt.%, and less than about 0.1 wt.% water.

The overall (general) reaction of the rich fuel/air mixture to produce synthesis gas is given by:

wherein the stoichiometric coefficients a, b, c are determined by chemical kinetics, conservation of atomic species, and reaction conditions.

In addition to the syngas, minor components in the gas exiting the reformer may include steam, CO ₂, and various unburned hydrocarbons.

After exiting unit 118, the now dry reprocessed gas (e.g., syngas) is in synthesis stage 102. In stage 102, now dry reprocessing gas (e.g., syngas) flows to assembly 130. Assembly 130 provides for the controlled addition of hydrogen from line 131 to the now dry reprocessing gas (e.g., syngas). In this way, the ratio of the syngas components may be adjusted and controlled to a predetermined ratio. The hydrogen is provided by a hydrogen separation unit 139. The rate-adjusted dry reprocessed gas (e.g., syngas) exits the assembly 130 and flows to the compressor 132. The compressor 132 compresses the reprocessed gas (e.g., syngas) to the optimum pressures taught and disclosed herein for use by the synthesis unit 133. Preferably, the synthesis unit 133 is a two-stage unit having a first reactor unit 133a and a second reactor unit 133 b. Each reactor is a pressure vessel through which the process gas flows in an exothermic reaction. The catalyst bed tubes are typically exposed to a cooling water bath at a controlled temperature and pressure. The synthesizing unit 133 also has a heat exchanger 120e.

The synthesis unit 133 converts the rate-adjusted dry reprocessed gas (e.g., syngas) to value-added products (e.g., methanol, ethanol, mixed alcohols, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals). The value added product (e.g., methanol, etc.) flows into heat exchanger 120d. Value added products (e.g., methanol, etc.) flow to the collection unit 140. The collection unit 140 collects the value added product (e.g., methanol, etc.) and flows it through line 141 for sale, storage, or further processing.

Typically, the synthesis gas is compressed to a pressure of about 15 to about 100 bar, and preferably 30 to 50 bar, about 25 to about 80 bar, at least about 10 bar, at least about 25 bar and at least about 50 bar, and greater and lower pressures. The temperature of the pressurized syngas is adjusted to a temperature of about 150 ℃ to about 350 ℃, and preferably 250 ℃, about 200 ℃ to about 300 ℃, about 250 ℃ to about 375 ℃, greater than 125 ℃, greater than 150 ℃, greater than 200 ℃, greater than 250 ℃, greater than 350 ℃ and less than 400 ℃, and higher and lower temperatures. The pressure and temperature controlled synthesis gas is then fed to a reactor for converting the synthesis gas into more useful, easier to transport and economically viable products such as methanol, ethanol, mixed alcohols, ammonia, dimethyl ether, F-T liquids and other fuels or chemicals. In a preferred embodiment, methanol is produced using a synthesis gas to methanol reaction, a CO hydrogenation reaction, a CO ₂ hydrogenation reaction, and a reverse water shift, using an actively cooled reactor, such as a heat exchange reactor or a boiling water reactor, and a copper-containing catalyst, such as Cu/ZnO/Al ₂O₃, and the like. The following reactions can be used in the general examples of synthetic states:

CO+2H ₂→CH₃ OH (CO hydrogenation)

Hydrogenation of CO ₂+3H₂→CH₃OH+H₂O(CO₂

CO+H ₂O→CO₂+H₂ (reverse water gas shift)

Typically, and in preferred embodiments, the characteristic length scale of the reactors used in the system is small enough (e.g., microchannels or mini-channels) that they can be formed into unusual shapes and topologies using new 3D printing techniques for metals and other high temperature materials, allowing for compact packaging and tight control of reaction conditions. Other strategies to enhance downstream synthesis reactions, such as selectively removing product from the reactor in situ or in a tightly coupled manner, may also be considered to shift equilibrium-limited reactions to higher conversion. Such process intensification may minimize the need for large recycle streams or allow the reaction to proceed under milder conditions (e.g., lower pressure), thereby increasing safety margins.

Typically, when reacting the syngas to form higher value products, also unreacted H ₂.H₂ is produced that can be collected and sold or used to drive a gas turbine or a second generator to produce additional electricity.

Typically, the H ₂/CO ratio in the syngas produced by the engine may be adapted to the downstream conversion process. For example, for methanol synthesis or Fischer-Tropsch (F-T) synthesis, the ideal H ₂/CO ratio is 2 to 3. The maximum possible H ₂/CO ratio is ideal for ammonia synthesis or hydrogen production and can be increased by, for example, adding steam to promote the water gas shift reaction. For ammonia and hydrogen production, CO is not required for downstream synthesis. Thus, CO and CO ₂ byproducts may be collected, sequestered, stored, or used for other purposes.

The collection unit 140 also has a line that flows the gas separated from the value-added product (e.g., methanol, etc.) to a valve 135 where the gas is sent to a hydrogen separation unit 139, a recycle loop 136, or both. The recycle loop has a compressor 134 and a valve 138 to feed value added products (e.g., methanol, etc.) into the synthesis unit 133. The hydrogen separation may be achieved via membrane separation or Pressure Swing Adsorption (PSA) or the like in the hydrogen separation unit 139.

Turning to FIG. 2, a temperature-entropy (T-S) diagram of the general operation and operational thermodynamics of a system of the type shown in FIG. 1 is shown. The overall conversion process from off-gas (e.g., flare gas) to useful products (e.g., methanol) is described using the T-S diagram of fig. 2. The graph uses the properties of air to approximate the process in terms of air standards. Fig. 2 outlines the general solution and operation of a system such as that shown in fig. 1 from thermodynamic, temperature and pressure perspectives. The figure shows the start-up of the process at ambient conditions, high temperature and pressure conditions for rich partial oxidation in the reformer, and high pressure and low temperature reactions for methanol synthesis. Thus, the temperature and entropy at 60 bar pressure is shown as dashed line 201, dashed line 202 at 30 bar pressure, dashed line 203 at 8 bar pressure and dashed line 204 at 1 bar pressure. The temperature and pressure of the incoming air (e.g., fig. 1, 110) and the off-gas (e.g., flare gas) (1 atmosphere corresponds to 1.013 bar.) are at point 206 (fig. 2). The operating conditions of the reformer stage (e.g., fig. 1, 101) are shown in region 210 (fig. 2). Region 210 has a temperature at 900 ℃ or above 900 ℃. The region 210 has two sub-regions 210a, 210b. The sub-region 210a is a lower pressure region (from less than 1 bar to about 25 bar). Sub-region 210b is a higher pressure region (about 20 bar to about 100 bar), particularly a high pressure region for rich partial oxidation conditions in the reformer (e.g., fig. 1, 114), which is a preferred condition for embodiments of the present invention. The optimal operation of the synthesis stage (e.g., fig. 1, 131) is shown in region 211 of methanol synthesis. Region 211 is at a temperature of 200 ℃ to 300 ℃ and a pressure of about 20 bar to 100 bar. Preferred areas of methanol production are from 200 ℃ to 300 ℃ and pressures from 30 bar to 100 bar.

Thus, FIG. 2 is a graphical representation of the conditions that may be generally used in a system to convert flare gas to the final product (methanol in this case), and preferably such conversion occurs with a neutral (i.e., providing all of the energy required to operate the system and process, or positive, providing excess energy) energy balance. The unit of the specific entropy axis (x-axis) is kJ/kg℃and the entropy per unit mass of air is described. This type of graph is a convenient way to show physical processes such as compression and expansion (nearly vertical lines between pressure levels) and heat exchange (typically at nearly constant pressure). The ideal compression or expansion is isentropic, meaning that there is no change in entropy between the two pressure levels. The compression of the real equipment is non-isentropic, as indicated by the non-vertical line. The temperature axis (y-axis) is in degrees celsius and describes the fluid temperature, assuming that the fluid has properties similar to air. The relationship between temperature and isobars is determined by the physical properties of the fluid. One of the benefits of the T-S diagram is that the relationship between the physical process and the composition can be visually represented.

The partial oxidation window 210 defines the temperature and pressure regions where critical Partial Oxidation (POX) reactions occur to produce syngas. This region defines the reaction conditions that result in a reaction time scale that is comparable to the combustion residence time in the reformer (e.g., gas turbines, typically 5ms to 50 ms). Typically, the POX reaction occurs at a much higher temperature than the downstream synthesis (e.g., methanol) reaction, which means that the temperature needs to be reduced in a heat exchanger prior to the methanol reactor.

The methanol synthesis window 211 defines the temperature and pressure region where the methanol synthesis reaction occurs. This region defines the reaction conditions that result in a reasonably balanced conversion of the equilibrium limited reaction. For such exothermic processes, lower temperatures favor equilibrium conversion, but are limited at the lower end due to ensuring adequate catalyst activity. Higher pressures produce higher equilibrium concentrations due to the net reduction in moles in the reaction, but require the cost of compression and high pressure design. Although the figures specifically show methanol synthesis windows, it should be understood that other possible downstream synthesis reactions (e.g., fischer-Tropsch) require similar conditions.

In an embodiment, the present system may be a mobile system contained within a shipping container frame that is to be mounted on a single semi-truck trailer, about 40 feet to about 60 feet long, about 6 feet to about 10 feet wide, and about 7 feet to about 15 feet high. The system may also be assembled into a flare gas recovery system in one, two or more separate shipping containers or open trays and then at the location of the flare gas, such as an oilfield, well, offshore platform or Floating Production Storage and Offloading (FPSO) vessel.

In embodiments of these mobile systems, they are sized and configured to handle a flare gas flow of about 250000scfd to 30000000scfd, about 400000scfd to 30000000scfd, about 500000scfd to about 20000000scfd, about 600000scfd to about 15000000scfd, about 700000scfd to about 10000000scfd, about 1000000scfd to about 25000000scfd, greater than about 250000scfd, greater than about 500000scfd, greater than about 750000scfd, less than 10000000scfd, less than 5000000scfd, and less than 1000000scfd, as well as greater and lesser flows. It is also contemplated that one, two, or more of these mobile systems may be placed in locations associated with flare gas, such as an oilfield having a large number of wells, and that flare gas may be piped from several wells to these mobile systems. Thus, a complete coverage area is provided, i.e., capturing and recovering all of the flare gas produced by the oilfield.

Embodiments of the present invention are useful in small facilities using one or more syngas engines, targeting 600000scfd (standard cubic feet per day) of inlet gas. The scale of such facilities may vary from 80000scfd to 3000000scfd, or 20000scfd to 100000 scfd.

Embodiments of the present invention may be incorporated into one or more modular, interconnected pallets or containers that are built at a central manufacturing plant location and then installed at a site location. A small number of modules comprise such a system and when connected in the field they form an integrated system. The modular nature of the assembly enables it to be applied at remote locations over a range of inlet gas feed volumes while minimizing site labor.

Generally, embodiments of these systems and methods provide for low carbon reprocessing of flare gas, and preferably carbon neutral to negative and positive energy. In this way, embodiments of the present system and process capture the flare gas and convert the flare gas to end products (e.g., methanol, ethanol, etc.) while generating sufficient energy (mechanical energy, electrical energy, and both) to operate the system. In the manufacture of the final product, the system is essentially carbon neutral to negative due to a combination of two effects: (1) The carbon in the flare gas is not released as CO ₂ and methane slip, but is sequestered in the methanol, thereby replacing the flare gas emissions, and (2) methanol is produced not by conventional means from natural gas or coal, but by means of methanol produced from the flare gas.

Thus, in an embodiment, the system and process for producing a final product (e.g., methanol) provides a net negative CO2e for the process and the preparation of the final product. (in this specification, CO2e and CO ₂ e are synonymous.) thus, in preferred embodiments, the process and resulting end product (e.g., methanol) has about-40 kgCO e to-130 kg CO2e, less than-20 kgCO e, less than-40 kg CO2e, less than-60 kg CO2e, less than-100 kgCO e, and less than-130 kg CO2e per kilogram of downstream product (e.g., liquid methanol). It should be noted that a typical CO2e for methanol produced from natural gas is 2.1kg CO2e per kg methanol (based on 45kg CO2e/MMBTU methanol, 1040btu/scf natural gas and 0.8kg natural gas/m ³). From the IPCC AR5 estimate of methane, CO2e (carbon dioxide equivalent) is based on the global warming potential of methane over a 20 year time frame and is 85 times the global warming potential of CO ₂.

Thus, turning to fig. 23, a graph is shown that illustrates, among other things, significant improvement from the perspective of CO2e (and GWP) as compared to a conventional source of methanol (coal, natural gas, or CO ₂+H₂ or black liquor). FIG. 23 illustrates the significant reduction of CO2e of the present invention, wherein methanol is obtained using the system and process of the present invention to convert flare gas to synthesis gas and then to methanol.

More preferably, these reformers, synthesis units, and both may also generate enough energy to make the excess energy available for operating other equipment or for other purposes, such as oilfield operations, computers with high power requirements for processing complex algorithms, charged electric vehicles, battery storage, and the like.

More preferably, the control system (and subsystems, if any) operates the entire mobile system and process. The mobile system is configured for real-time or near real-time monitoring and control from a remote location or site.

In an embodiment, these systems also have monitoring and metering devices for monitoring and control and memory devices for recording the amount of flare gas processed, the amount of product produced, and the amount of CO ₂ produced (if any). This information will be recorded in a secure manner for use or transmission to support carbon capture credits, other regulatory or private equity rights, or transactions related to CO ₂.

More preferably, the control system (and subsystems, if any) operates the entire mobile system and process. The mobile system is configured for real-time or near real-time monitoring and control from a remote location or site.

Blockchain-based carbon capture or carbon compensation measurement records will improve the quality of the measurement system by networked, secure record keeping. Blockchain-based carbon credits may then be sold as carbon compensation on the voluntary carbon market as part of cryptocurrency or other verifiable tokens.

Reformer-overview based on reciprocating engine

Embodiments of the present invention have reciprocating engines and methods of operating these engines to treat variable combustion properties of an exhaust (e.g., flare gas) source. Thus, and in general, in some embodiments, the reformer 114 of fig. 1 is a reciprocating engine. One of the reasons that these gases are not economical is the large variation in the composition of the off-gas (e.g., flare gas). The result of the composition change is an effect on combustion properties such as: heating value, cetane number (delay in ignition time of fuel) and octane number (pre-ignition resistance due to compression). These changes may occur from source to source, the composition of the same source may vary from day to day (transients), from season to season (especially biogas), and over time as the source ages.

Conventional air-breathing reciprocating engines are typically designed to operate with fuels of narrow fuel specifications. For example, the compression ratio of an automotive gasoline engine is selected based on the mass of fuel used. The octane number of "normal" gasoline in the united states is 86 to 87. Higher performance (e.g., higher compression ratio) engines may require premium quality gasoline with an octane number of 91 to 94.

Embodiments of the present invention use a commercial reciprocating engine (e.g., an off-the-shelf engine) as a reformer to produce a reprocessed gas, such as syngas, by operating the reciprocating engine at a fuel rich condition of high fuel to air ratio (equivalence ratio in the range of 1.5 to 2.5). To allow the engine to operate off-design from its intended design point and to operate satisfactorily with fuels that vary over a wide range of octane and cetane, embodiments modify operating engine parameters including compression ratio, intake manifold air temperature, intake manifold air pressure, and engine speed. These improvements are applicable to compression ignition engines (diesel cycle) and spark ignition engines (otto cycle). For spark-ignition engines, the spark timing may also be used to adapt the engine operation to fuel variations.

In an embodiment of the modular system, the system and method utilize a nominally aspirated engine that is operated under rich conditions to produce a reprocessed gas (e.g., syngas) from an exhaust gas (e.g., flare gas) source. The variation in fuel composition results in a variation in combustion properties that affect engine operability. Specifically, for example, the affected operability parameters include:

■ Engine misfire—in one or more cylinders of an engine, there is no transition from spark discharge to propagating flame.

■ Pre-ignition-the combustion of a fuel-air mixture in one or more cylinders of an engine is advanced.

■ Autoignition (knocking) -spontaneous ignition of the fuel-air mixture prior to flame propagation.

■ Combustion efficiency is low-the unburned fuel content in the exhaust gas is high, because the exhaust valve is open before combustion is completed in the cylinder volume, or quenching on the unburned fuel and cold surfaces in the crack volume, possibly related to a misfire.

20A, 20B and 21, and tables 1 and 2 illustrate ranges of compositions of flare gas that may be processed into a reprocessed gas, such as syngas, by embodiments of a reciprocating engine reformer (including exemplary embodiments).

These mixtures and their individual components represent a broad range of octane numbers, with heavier hydrocarbons having lower octane numbers and therefore being more prone to pre-ignition or auto-ignition. Octane number is a key indicator of the reactivity of the mixture, and its specific values are shown in table 3. Table 3 shows the estimated values of the octane numbers of lean gas and rich gas in fig. 20A and 20 b.

Fig. 21 shows how the fuel energy per unit volume varies with the gas composition. This variation affects the size and control of the fuel delivery system and is addressed in this manner.

Table 3 (octane number of individual Components (octane number of research method octane number=RON))

Turning to fig. 21, it is shown that for gaseous fuels, variations in fuel composition also affect the energy content of the fuel, which can be quantified by the fuel heating value per unit volume (wobbe number). The graph shows a typical range of wobbe numbers for a range of fuel compositions versus fuel heating values.

Variations in fuel properties are fundamental contradictions in the design of reciprocating engine systems, and embodiments of the present invention address this issue. In one aspect, a high compression ratio and high intake air temperature facilitate combustion characteristics to produce a syngas having a desired H ₂/CO ratio (typically ranging from about 1.0 to about 2.0, preferably 1.5 to 2.0) while having low unburned fuel emissions. On the other hand, high compression ratios and high intake air temperatures may result in pre-ignition or auto-ignition of the fuel-air mixture (if the fuel becomes more reactive). Conversely, if fuel reactivity decreases, it would be beneficial to increase the compression ratio or intake air heating. Thus, setting a particular design point for an engine is not compatible with smooth engine operation using fuels with variable combustion properties (e.g., flare gas).

In an embodiment, a solution to this problem is to modify engine operating properties while the engine is operating. In an embodiment, the combination of modified key operating engine parameters includes:

■ Compression ratio (effective compression ratio or geometric compression ratio)

■ Range 8:1 to 17:1

■ Intake manifold air temperature ranges from ambient to 300 ℃.

■ Intake manifold air pressure, ambient pressure to 5 bar.

■ Ignition timing, TDC (top dead center, e.g., zero degrees) to MBT (minimum spark advance to achieve optimal torque, e.g., typical 30 degree, 15 to 45 degree range)

■ And engine speed, 800rpm to maximum engine speed (e.g., 1800 rpm)

■ The above condition ranges may be applied to two-stroke or four-stroke reciprocating engines.

In an embodiment, to detect if the engine is operating correctly, a set of sensors may be used in the controller, and preferably in the autonomous control system. The autonomous control system is preferably part of, or in control communication with, a control system of the overall system (e.g., system 100 of fig. 1), and may be, for example, a subsystem, a separate controller, and is also preferably in control communication with the overall control system of the overall system. These sensors may include:

■ Knock detection (vibration-based sensor) mounted on a cylinder block or cylinder head

■ Oxygen sensor (a sensor for estimating air-fuel ratio from exhaust gas composition, typically mounted downstream of an exhaust valve)

■ An exhaust gas temperature sensor (typically a thermistor or thermocouple) is mounted downstream of the exhaust valve.

■ Intake manifold temperature or pressure sensor.

■ Fuel sensors include mass flow, dew point temperature, and heating value (e.g., calorimeter).

In embodiments of the reciprocating engine, the fuel-air mixture is rich, preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

In embodiments of a reciprocating engine reformer, it is understood that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As defined herein, an "air-breathing engine" is understood to also include engines that use air modified by the addition of water or oxygen.

Reciprocating engines produce reprocessed gases such as synthesis gas (as well as thermal and mechanical energy, which may be used to drive and operate the overall process), which are then filtered, and heat from the synthesis gas is recovered by a heat exchanger.

In a reciprocating engine, the overall (general) reaction of the rich fuel/air mixture to produce syngas is given by:

wherein the stoichiometric coefficients a, b, c are determined by chemical kinetics, conservation of atomic species, and reaction conditions.

In addition to the syngas, minor components in the gas exiting the reciprocating engine include water vapor, CO ₂, and various unburned hydrocarbons.

Reformer-overview based on gas turbine engine

Embodiments of the present systems and methods utilizing a gas turbine reformer generally relate to systems, apparatus, and methods for converting an otherwise uneconomical hydrocarbon-based fuel (e.g., flare gas) into value-added, easily transportable products (such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, as well as combinations and variations of these). These embodiments generally have a flare gas (i.e., fuel) conditioning system, an air-breathing gas engine, and a conditioning assembly that conditions the syngas for storage, transportation, subsequent processing, and combinations and variations of these. The flare gas is conditioned to remove impurities and materials that may be detrimental to subsequent processing steps. The flare gas (e.g., the fuel gas of the system) is then mixed with air and ignited in the engine.

Embodiments of the present invention have a turbine engine, such as an air-breathing gas turbine engine, as a reformer that produces a reprocessed gas, preferably syngas. Thus, and in general, in some embodiments, the reformer 114 of FIG. 1 is a gas turbine engine. In some embodiments, gas turbines are preferred in certain situations (such as a larger amount of wellhead flow) because they provide advantages over embodiments that use reciprocating engines to produce syngas. Gas turbine based systems are suitable for larger scale gas-to-liquids (e.g., flare gas to methanol) applications where packaging limitations exist, such as site floor space limitations. Embodiments of the present system are modular and can be easily and quickly positioned in difficult to access locations, locations with limited area for placement of the system, and combinations and variations of these locations where flare gas is produced.

Further, gas turbine based systems have the ability to handle, e.g., receive and process into end products, flare gas has a wide and varied compositional range, which in some embodiments may provide advantages over reciprocating engines. Variations in the composition of the flare gas (i.e., fuel) can change the ignition characteristics and burn time. For reciprocating engines with a fixed compression ratio, such variations should be addressed to avoid potentially damaging engine knocks or misfires and exhaust valve overheating, among other problems.

Gas turbine combustion systems can burn a wide variety of liquid and gaseous fuels, preferably they are free of contaminants that can cause corrosion or deposition. Furthermore, the flame continues to burn in the gas turbine, unlike reciprocating engines, in which ignition must occur in each cylinder during each power stroke. In addition, the gas turbine may be operated continuously for about 8000 hours (some models may be up to 24000 hours, or even longer), without shutdown, and the overhaul time interval may be extended to more than 24000 hours. Due to the greater number of moving parts and greater wear surfaces, reciprocating engines typically must be shut down to replace lubricating fluid at intervals of about 2000 to 4000 hours, and overhauled for about 8000 to 12000 hours.

In some embodiments, one of the many advantages a gas turbine system may have over a reciprocating engine system is that the flare gas composition may vary and the gas turbine performance is not affected. In general, flare gases having the compositions listed in FIG. 20A, FIG. 20B, FIG. 21, and tables 1 and 2 may be treated by embodiments (including examples) of the gas turbine system of the present invention. However, some factors that may still have an impact on the performance of a gas turbine system include: 1) a dew point margin of 10 ℃ flare gas, i.e., superheating, ensuring that the gas is admitted to the fuel, 2) maintaining the heating value of the overall fuel >400BTU/scf, and 3) corrosive elements, such as vanadium, are filtered out prior to combustion.

Embodiments of the present systems and methods utilizing a gas turbine reformer generally relate to systems, apparatus, and methods for converting an otherwise uneconomical hydrocarbon-based fuel (e.g., flare gas) into value-added, easily transportable products (such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, as well as combinations and variations of these). These embodiments generally have a flare gas (i.e., fuel) conditioning system, an air-breathing gas turbine, and a conditioning assembly that conditions the syngas for storage, transportation, subsequent processing, and combinations and variations of these. The flare gas is conditioned to remove impurities and materials that may be detrimental to subsequent processing steps. The flare gas is then compressed to a pressure of about 8 to about 35 bar (typically corresponding to a pressure ratio of about 1.2 times the gas turbine air compressor), about 5 to about 40 bar, at least about 10 bar, at least about 20 bar, and at least about 1.1 times the gas turbine air compressor pressure ratio, about 1.05 times to about 1.8 times the gas turbine air compressor pressure ratio, and greater and lesser values. The compressed flare gas (i.e., the fuel of the system) is then mixed with air and ignited in the gas turbine. When mixed with the compressed fuel gas, the pressure of the air is preferably the same as the pressure of the fuel gas. The temperature of the compressor discharge air is a known function of the intake air temperature, compression ratio, and compressor efficiency, and the temperature of the compressed discharge air should be from about 150 ℃ to about 600 ℃, from about 150 ℃ to about 500 ℃, from about 200 ℃ to about 400 ℃, greater than about 150 ℃, greater than about 300 ℃, and greater than about 500 ℃. The temperature of the compressed off-gas (e.g., flare gas) should be from about 100 ℃ to about 300 ℃, from about 150 ℃ to about 300 ℃, from about 125 ℃ to about 200 ℃, greater than about 150 ℃, greater than about 200 ℃ and greater than about 250 ℃ and less than 350 ℃, as well as higher and lower values.

Generally, for embodiments of gas turbine reformers, the fuel-air mixture is rich, preferably having a total fuel/air equivalence ratio (Φ or ER) of 0.98 or greater, greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

In an embodiment of a gas turbine reformer, it is understood that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As defined herein, an "air-breathing engine" is understood to also include engines that use air modified by the addition of water or oxygen.

Preferably, the gas turbine is a smaller sized unit, about 200kW to about 5000kW, about 200kW to about 2000kW, and less than 6000kW, less than 5000kW, less than 3000kW, and less than 2000kW, although larger and smaller sizes may be used.

The gas turbine produces synthesis gas (as well as thermal and mechanical energy, which may be used to drive and operate the overall process), which is then filtered, and heat from the synthesis gas is recovered by a heat exchanger.

In a gas turbine, the overall (general) reaction of the fuel/air rich mixture to produce syngas is given by:

wherein the stoichiometric coefficients a, b, c are determined by chemical kinetics, conservation of atomic species, and reaction conditions.

In an embodiment of the system, when the shaft of the turbine rotates at a low start-up speed, the onset of combustion occurs in the combustion chamber of the gas turbine at near-ambient conditions.

An additional feature for one embodiment of the combustion chamber is staged fuel addition to extend the rich limit of combustion. For example, at the front of the combustion chamber, a portion of the fuel is mixed with air to produce a flame that burns very stably (e.g., near stoichiometric conditions). Downstream of the stable flame zone, additional fuel is added to meet the total equivalence ratio required to achieve the H ₂/CO ratio of the downstream process.

In addition to the syngas, minor components in the gas exiting the gas turbine include water vapor, CO ₂, and various unburned hydrocarbons.

Generally, embodiments of a partial oxidation gas turbine include a compressor, a combustor, and a turbine. The compressor draws in ambient air and increases the pressure. The air discharged from the compressor is mixed with an excessive amount of fuel and partially oxidized in the combustion chamber. The exhaust of the combustion chamber is expanded to ambient conditions by the turbine. The work produced by the turbine typically exceeds the work required to drive the compressor. A conceptual diagram of one embodiment of a portion is shown in fig. 7.

Turning therefore to FIG. 7, a reformer gas turbine assembly 700 is shown. The gas turbine 700 has a gas turbine engine 710 (e.g., an air-breathing turbine engine) with an air intake 711, a compressor 712, a turbine 713, and an exhaust stream 714. The gas turbine 710 has a shaft configured to rotate with the turbine and compressor, which is connected to a motor or generator 715. The gas turbine 700 has a two-part or two-stage combustor 740 that provides for the partial oxidation combustion of flare gas. The two-stage combustor 740 has a first stage, which is a rich partial oxidation combustor 741, and a second stage, which is a gas turbine 710. Flare gas is injected at 742 and partially combusted in the reaction zone 743 of the first stage combustion chamber 741. The products of this partial combustion are directed to a gas turbine 710 where they are further combusted with incoming air from an air intake 711 to provide syngas. Synthesis gas is produced in 743 (in the combustion chamber), flows upward and through heat exchanger 760, and then flows out line 733 to the synthesis stage. The reacted synthesis gas is returned from the synthesis unit via line 732. This gas stream is heated by the syngas generated in 743 and expanded by turbine 713. A portion of the gas stream in line 732 is unheated and flows through bypass line 731. This gas may have a high N ₂ gas flow for sealing and secondary cavities.

The numbers within the circles in fig. 7 relate to locations, e.g., status points, of the process conditions discussed with respect to the T-S diagram relating to the particular example and discussed in the example.

Example

The following examples are provided to illustrate various embodiments of the present exhaust gas conversion process and system. These examples are provided to illustrate various embodiments of the present gas-liquid conversion process and system. These examples are for illustrative purposes, may be prophetic, and should not be considered and should not limit the scope of the invention.

Embodiments of these examples 1 through 54 may have or utilize one or more of the embodiments, processes, methods, features, functions, parameters, components, or systems disclosed and taught in the "systems and processes-overview", "reciprocating engine-based reformer-overview" and "gas turbine engine-based reformer-overview" sections of this specification, as well as combinations and variations of each of these; and one or more of the embodiments, processes, methods, features, functions, parameters, components, or systems provided in one or more of the other examples and other embodiments taught and disclosed in this specification.

Example 1

A system and method for converting an otherwise uneconomical hydrocarbon-based fuel, such as flare gas, to a value-added, easily transportable product, such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, using an autonomous modular system comprising the following elements: (1) a fuel conditioning system meeting downstream component requirements; (2) A gas turbine engine adapted to operate the rich partial oxidation reformer to produce a synthesis gas mixture having an H ₂/CO ratio suitable for liquid synthesis; (3) An integrated heat exchanger, compression system components, and heat exchanger combination for producing synthesis gas for a downstream synthesis reactor; and (4) a downstream synthesis reactor system for producing a useful liquid hydrocarbon product.

Example 2

A system and method for converting an otherwise uneconomical hydrocarbon-based fuel, such as flare gas, to a value-added, easily transportable product, such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, using an autonomous modular system comprising the following elements: (1) a fuel conditioning system meeting downstream component requirements; (2) A gas turbine engine adapted to operate the rich partial oxidation reformer to produce a synthesis gas mixture having an H ₂/CO ratio suitable for liquid synthesis; (3) An integrated heat exchanger, compression system components, and heat exchanger combination for producing synthesis gas for a downstream synthesis reactor; (4) A downstream synthesis reactor system for producing a useful liquid hydrocarbon product; and (5) a hydrogen recycle loop for improving process performance of the overall system.

Example 3

The systems and methods of examples 1 and 2 may also have one, more or all of the following additional features: (6) An optional substantially oxygen-free gas recirculation loop for cooling and protecting downstream components of the combustion chamber, such as seals, bearings, and secondary cavities; (7) Subjecting the gas turbine inlet stream to optional O ₂ enrichment via a membrane separation or partial air separation unit; (8) A recuperator (from (3)) and a turbo-expander for recovering energy from the high pressure exhaust gas from the downstream synthesis reactor; (9) integration of the closed loop operating system with custom instrumentation; (10) A cloud-based remote monitoring system including anomaly detection for AI training for dynamic preventative maintenance and operational control; (11) An optional vent path for reinjection, completion, or other purposes with byproducts such as nitrogen, water, and CO ₂; (12) Water (or steam) is optionally injected into the rich combustor to increase the H ₂/CO ratio and reduce carbon build-up on the combustor and turbine inner surfaces.

Example 4

Gas-to-liquids systems employ uneconomical hydrocarbon-based fuels, such as flare gas, primarily gaseous hydrocarbons, at the wellhead and at remote locations and convert them to more valuable readily condensable or liquid compounds, such as methanol. One source of fuel may be associated gas or flare gas, which is a byproduct of an oil well. Another source may be biogas from a landfill site or an anaerobic digester.

A small scale facility, targeting 3000000scfd (standard cubic feet per day) of inlet gas. The scale of such facilities may vary from 300000scfd to 15000000 scfd. The facility is incorporated into one or more modular, interconnected pallets or containers that are built at a central manufacturing plant location and then installed at a site location. A small number of modules comprise such a system and when connected in the field they form an integrated system. The modular nature of the assembly enables it to be applied at remote locations over a range of inlet gas feed volumes while minimizing site labor. The modular nature further increases flexibility in deploying or redeploying these assets, reduces initial capital expenditure and project financial risk, allows process throughput to be matched to flare gas supplies, and shortens the time to market by allowing module manufacturing and site preparation to proceed in parallel.

Example 5

Turning to FIG. 3, a schematic diagram of a system and method, preferably a modular facility and process, for recovering and converting flare gas to methane is shown. FIG. 4 is a T-S diagram illustrating preferred operating conditions and process thermodynamic state points that may be used for operation of the embodiment of FIG. 3. The reference points (numbers 31, 32, 33, 34, 35, 36, 37, 37.5, 38, 39 in fig. 3) correspond to the process conditions, i.e. status points, of these locations in the system of fig. 3, which are represented in fig. 4 by the corresponding reference points. The main reference points (e.g., 35', 36') in fig. 4 indicate the expected cycling points that take into account component efficiency. Reference point 7.5 indicates the emissions of the downstream synthesis process. Reference points 33 _s and 35 _s indicate idealized isentropic process (vertical process line) conditions. The initial specific entropy of the process is at points 31, 32 (6.9 kJ/kg C.) and the final specific entropy point of the process is 39 (7.04 kJ/kg C.). Thus, the difference between the initial specific entropy and the final specific entropy was 0.14kJ/kg ℃.

Turning to FIG. 3, a combustor system 300 for converting flare gas from a flare gas source (e.g., oil well, gas well, fill, agricultural plant, wastewater treatment plant, etc.) to methanol is shown. The system 300 has a reformer portion or stage 350 and a synthesis portion or stage 351.

The system 300 has an air inlet 301 that allows air to flow to a filter 302 where dust, sand, particulates, etc. are removed from the air before flowing to a compressor 303 where they are compressed. The compressed air exits the compressor 303 and flows to an induction combustion box 304 where the flare gas is partially oxidized. The combustion box 304 may be single stage, two stage, or more.

Flare gas (e.g., raw flare gas) from a flare gas source (e.g., an oil or gas well or gas field) enters the system 300 through line 311 and flows to a separator 313 where liquid and gas are separated. From separator 313, separated liquid, including liquid hydrocarbons having 3 or more carbon atoms, flows through line 314. These liquids may flow through line 315 to storage tank 316, and the separated liquids may flow through line 317 and be pumped by pump 318 into combustion box 304.

The gas component of the flare gas exits the separator 313 via line 312 and flows to the gas conditioning unit 310. The gas conditioning unit 310 may remove substances that are detrimental to the process, including H ₂ S (hydrogen sulfide), as well as any substances that may damage or poison any catalyst used in the system. The conditioned flare gas exits the conditioning unit 310 and flows to a gas filter 309 where further harmful or detrimental substances, such as iron sulfide, sulfur, and any substances that may damage or poison any catalysts used in the system, are removed. The conditioned and filtered flare gas exits the filter 309 and flows into the gas compressor 306 driven by the motor 307. The compressor 306 compresses the flare gas to a predetermined pressure and temperature as taught and disclosed herein, such as shown in FIG. 4, and causes the flare gas to flow into the combustion box 304. Water, steam or oxygen may also be added to the combustion box 304 via line 305.

The compressed flare gas may be at a pressure of about 3 to about 60 bar, about 8 to about 35 bar (typically corresponding to about 1.2 times the pressure ratio of the gas turbine air compressor), about 5 to about 40 bar, at least about 10 bar, at least about 20 bar, and at least about 1.1 times the pressure ratio of the air compressor, about 1.05 times to about 1.8 times the pressure ratio of the gas air compressor, and greater and lesser values. The compressed flare gas (i.e., the fuel for the system 300) is then mixed with compressed air and ignited in the combustion box 304, which is partially oxidized in the combustion box 304. When air is mixed with the compressed flare gas, its pressure may be any of the above pressure ranges for the flare gas; and preferably the same as the pressure of the flare gas. In an embodiment of the process operation as shown in FIG. 4, the pressure of the flare gas and air is 8 bar when the flare gas and air are introduced into the combustion box 304 for partial oxidation to form syngas.

The syngas exits the combustion box 304 and flows into the turbine 320 where its pressure is reduced (see, e.g., state points 34 (preferably 8 bar) and 35 (preferably 1 bar)). The turbine 320 is connected to the compressor 303 by a rotating shaft 329, which rotates the compressor 303. The turbine 320 is connected to a motor or generator 336 via a rotating shaft 319 a. Rotating shaft 319b connects turbine 337 with motor or generator 336.

The syngas exits the turbine 320 via line 321 and flows into a filter 322 where particulates, such as soot, are removed. The synthesis gas then flows into heat exchanger 323 where the temperature is reduced to a methanol synthesis window, preferably 200 ℃ to 300 ℃ (see, e.g., fig. 4). The heat exchanger 323 is part of a heat exchanger loop 324. The syngas then flows from the heat exchanger 323 to the water separation unit 325. Water is removed from the water separation unit 325 via line 326. The syngas exits unit 325 and flows via line 321a to compressor 327 driven by motor 328. The compressor compresses the synthesis gas to about 30 to 100 bar. For the preferred operation shown in fig. 3 and 4, it is indicated by the status points 36 (1 bar) and 37 (30 bar).

The synthesis gas exits the compressor 327 and flows to the heat exchanger 329 where the temperature of the methanol synthesis window is maintained and the synthesis gas flows from the heat exchanger 329 to the synthesis unit 329 via line 321 b. The synthesis unit has two reactors 329a and 329b. It is noted that a single stage or reactor may be used, and that more than two stages or reactors may be used. The synthesis unit 329 has a line 335 for draining water, methanol or both. The synthesis unit 329 converts the synthesis gas to methanol, which then flows to the holding and separation unit 330. Unit 330 separates liquid methanol from any remaining gas. Methanol is removed via line 331 for storage, further processing, use, transportation, etc. The gas flows through line 332 to a hydrogen separator unit 333. The hydrogen leaves separation unit 333 via line 334 and flows back to synthesis unit 329 where it is used to adjust the H ₂/CO ratio of the synthesis gas. The remaining gas from unit 333, e.g., a low H ₂ concentration stream, is injected into turbine 320 via line 339 b; and through line 339a to turbine 337 and then to exhaust line 338.

This arrangement of components in this example is an efficient way to achieve a specific point of state for the process of producing methanol in a cost-effective manner. These status points include: 1) starting at ambient conditions, 2) increasing the temperature and pressure to achieve rich partial oxidation, and 3) cooling and pressurizing to achieve downstream synthesis. The carbon and energy intensity of the process can be managed by adjusting the cycling point to exactly match the POX and synthesis window. Furthermore, the circulation point may be adjusted to minimize the energy requirements of the downstream and downstream separation processes.

In the example of the state conditions of fig. 4, the operation of the system of fig. 3 is deployed around the rich reformer and synthesis reactor. Unlike conventional gas turbines and reciprocating engines, the combustion chamber 304 operates at rich conditions, up to an equivalence ratio of about 4, so that the fuel, i.e., flare gas, undergoes rich Partial Oxidation (POX). The system 300 has fuel (i.e., flare gas), a conditioning system, a heat exchanger, a compressor, and a turbine. The fuel conditioning system separates liquids from gases in the feed stream and removes compounds that may damage the gas turbine or synthesis reactor. The heat exchanger and compressor receive the syngas mixture at the outlet of the gas turbine and regulate temperature and pressure to provide the target conditions for the synthesis reactor. The synthesis subsystem has an optional H ₂ recycle loop. The synthesis reactor outlet gas is heated to high temperature in a recuperative (e.g., counter-current) heat exchanger and then expanded to ambient conditions.

Example 6

The system of fig. 3, as well as other embodiments of the present system, may be operated and configured in a manner that limits the expansion of gas through turbine 337 such that work from compressor 303 and turbine section 320 is matched. In this way, the off-gas from line 338 is pressurized above ambient pressure and less compression work is required, with compressor 303, and particularly 329, being required to meet the pressure required by downstream synthesis reactor 329, thus reducing compression stage and equipment complexity. For example, compressor 329 may be reduced in size, reduced in work required, and may even be omitted.

Example 7

Turning to FIG. 5, a schematic diagram of a system and method, preferably a modular facility and process, for recovering and converting flare gas to methane is shown. FIG. 6 is a T-S diagram illustrating preferred operating conditions and process thermodynamic state points that may be used for operation of the embodiment of FIG. 5. The reference points (numbers 51, 52, 53, 54, 55, 56, 57, 58, 59 in fig. 5) correspond to the process conditions, i.e. status points, of these locations in the system of fig. 5, and these process conditions are represented by the corresponding reference points in fig. 6. Reference point 53 _s indicates an idealized isentropic process (vertical process line) condition. The initial specific entropy of the process is at points 51, 52 (6.9 kJ/kg ℃), and the final specific entropy of the process is at point 58 (7.2 kJ/kg ℃). Thus, the difference between the initial specific entropy and the final specific entropy was 0.3kJ/kg ℃.

Turning to FIG. 5, a combustor system 500 for converting flare gas from a flare gas source (e.g., oil well, gas well, fill, agricultural plant, wastewater treatment plant, etc.) to methanol is shown. The system 500 has a reformer portion or stage 550 and a synthesis portion or stage 551.

The system 500 has an air inlet 501 that causes air to flow to a filter 502 where dust, sand, particulates, etc. are removed from the air before flowing to a compressor 503 where they are compressed. The compressed air exits the compressor 503 and flows to an induction combustion box 504 where the flare gas is partially oxidized. The combustion box 504 may be single stage, two stage, or more.

Flare gas (e.g., raw flare gas) from a flare gas source (e.g., an oil or gas well or gas field) enters the system 500 through line 511 and flows to a separator 513 where liquid and gas are separated. From separator 513, separated liquid, including liquid hydrocarbons having 3 or more carbon atoms, flows through line 514. Separate liquids may flow through line 514 and be pumped into combustion chamber 504 by pump 518.

The gas component of the flare gas exits the separator 513 via line 512 and flows to the gas conditioning unit 510. The gas conditioning unit 510 may remove materials that are detrimental to the process, including H ₂ S, as well as any materials that may damage or poison any catalyst used in the system. The conditioned flare gas exits the conditioning unit 510 and flows to a gas filter 509 where further harmful or detrimental substances, such as iron sulfide, sulfur, and any substances that may damage or poison any catalysts used in the system, are removed. The conditioned and filtered flare gas exits the filter 509 and flows into the gas compressor 506. The compressor 506 compresses the flare gas to a predetermined pressure and temperature as disclosed and taught herein, such as shown in FIG. 6, and causes the flare gas to flow into the combustion box 504. Water, steam or oxygen may also be added to the combustion box.

The compressed flare gas may be at a pressure of from about 3 to about 60 bar, from about 8 to about 35 bar (typically corresponding to about 1.2 times the pressure ratio of the gas turbine air compressor), from about 5 to about 40 bar, at least about 10 bar, at least about 20 bar, and at least about 1.1 times the pressure ratio of the air compressor, from about 1.05 times to about 1.8 times the pressure ratio of the gas air compressor, and greater and lesser values. The compressed flare gas (i.e., the fuel for the system 500) is then mixed with compressed air and ignited in the combustion box 504, being partially oxidized in the combustion box 504. When mixed with compressed flare gas, the pressure of the air may be any of the above pressure ranges of flare gas; and preferably the same as the pressure of the flare gas. In an embodiment of the process operation as shown in FIG. 6, the pressure of the flare gas and air is 8 bar when the flare gas and air are introduced into the combustion box 504 for partial oxidation to form syngas.

Compressor 503 is connected to a motor or generator 536 by a rotating shaft 529. The rotating shaft 519b connects the turbine 537 with a motor or generator 536.

The syngas exits the combustion box 504 via line 521 and flows into a filter 522 where particulates, such as soot, are removed. The synthesis gas then flows into heat exchanger 523 where the temperature is reduced to a methanol synthesis window, preferably 200 ℃ to 500 ℃ (see, e.g., fig. 6). The heat exchanger 523 is part of a heat exchanger circuit 524. The syngas then flows from the heat exchanger 523 to the synthesis unit 529. The synthesis unit has two reactors 529a and 529b. It is noted that a single stage or reactor may be used, and that more than two stages or reactors may be used. The synthesis unit 529 converts the synthesis gas to methanol, which then flows to the holding and separation unit 530. Unit 530 separates liquid methanol from any remaining gas. Methanol is removed via line 531 for storage, further processing, use, transportation, etc. The gas flows to the hydrogen separator unit 533 via line 532. The hydrogen leaves the separation unit 533 via line 534 and flows back to the synthesis unit 529 where it is used to adjust the H ₂/CO ratio of the synthesis gas. The remaining gas from unit 533, such as a low H ₂ concentration exhaust gas product stream, flows into turbine 537 and then into exhaust line 538.

In the condition of the state of fig. 6, the operation of the system of fig. 5 is spread around the integration of the synthesis reactor in the gas turbine cycle. The fuel system, compressor, and rich combustor are similar to the system of example 5. However, rather than delivering the combustion products to the turbine, in this example 7, the syngas at the outlet of the combustor 504 flows through the recuperator 523 until the syngas temperature is acceptable for the synthesis reactor 529. At the outlet of the synthesis reactor 529, the exhaust gas is returned through the recuperative heat exchanger system 524 and sent to the turbine 537 for expansion back to ambient pressure. The advantage of this embodiment over the embodiment of example 5 is that there are fewer components, but it requires a high temperature recuperative heat exchanger and more complex control.

Example 8

Embodiments of these systems and methods include using water in the off-gas (e.g., flare gas) or adding water directly to the POX combustor to increase the H ₂/CO ratio, thereby increasing the efficiency and effectiveness of the downstream synthesis reactor. This embodiment may be used with any of the systems of the present invention, including examples.

Example 9

Embodiments of these systems and methods include adding a substantially oxygen-free gas to a reformer (e.g., a turbine), including a gas such as at a high pressure side outlet of a hydrogen separator, to pressurize the seal and ensure that no air is brought into the secondary passage of the turbine. This embodiment may be used with any of the systems of the present invention, including examples.

Example 10

Hybrid systems consisting of a reciprocating engine and a gas turbine are also contemplated whereby the reciprocating engine may be used to assist in power generation or to supply additional syngas. The mixing system may include a reciprocating engine and a gas turbine sized to match the intake gas feed.

Example 11

In the embodiment of the system of fig. 1, the reformer is the gas injection turbine of fig. 7. The system may preferably operate as shown in the T-S diagram of fig. 7A. The reference points (numbers 3, 4, 5, 6, 7, 8 in fig. 7) correspond to the process conditions, i.e. status points, at these locations in the system of fig. 7, and these process conditions are represented by the corresponding reference points in fig. 7A. The status point 1 (not shown in FIG. 7) is the condition when flare gas is injected at 742. The initial specific entropy of the process is at points 1, 2 (6.9 kJ/kg ℃), and the final specific entropy of the process is at point 8 (7.2 kJ/kg ℃). Thus, the difference between the initial specific entropy and the final specific entropy was 0.3kJ/kg ℃.

Example 12

Turning to FIG. 8, an embodiment of a system and method for converting flare gas to value added products is shown. The system 800 has a reformer stage 801 and a synthesis stage 802. The system 800 has an air intake 810 that delivers air to a compressor 811 that compresses the air. The compressed air enters mixer 813 through heat exchanger 820 a. The system has a flare gas inlet 884. Flare gas flows into mixer 813 through heat exchanger 820 b. As disclosed and taught in greater detail herein, mixer 813 provides a predetermined mixture of air and flare gas to reformer 814, which is a reciprocating engine.

The fuel-air mixture formed in mixer 813 is preferably rich, more preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, about 1.1 to about 3, and greater.

It should be appreciated that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As used herein, "aspirated" reformers and aspirated engines are understood to also include engines that use air modified by the addition of water, oxygen, or both.

The reciprocating engine 814 combusts a predetermined mixture of flare gas and air to form syngas. The syngas flows through the heat exchangers 820a, 820b and enters a filter 815, such as a particulate filter.

After passing through filter 815, the syngas flows to a guard bed reactor assembly 816 having two guard bed reactors 816a, 816 b. Guard bed reactor 816 has materials, such as catalysts, that remove contaminants and other materials from the syngas that may damage, inhibit, or contaminate subsequent devices and processes in the system. For example, guard bed reactor 816 may contain a catalyst or other material to remove sulfur (e.g., sponge iron, zinc oxide, or the like) and halogenated compounds.

After exiting guard bed reactor 816, the syngas flows to deoxygenation reactor 817. Deoxygenation reactor 817 removes excess oxygen from the reprocessed gas (e.g., syngas) by oxidizing combustible compounds in the mixture, such as methane, CO, and H ₂, where the oxygen is converted to water. The catalyst for the deoxygenation reaction is platinum, palladium, and other active materials supported on alumina or other catalyst support materials.

The system 800 has a cooling system 850 that uses a cooling fluid, such as cooling water, that flows through a cooling line, such as 851.

After exiting deoxygenation reactor 817, the syngas flows to heat exchanger 820c. The reprocessed gas (e.g., syngas) then flows from heat exchangers 820f and 820c to a water removal unit 818, such as a water separator, mist eliminator, dryer, membrane, cyclone, desiccant, or the like, where water is removed from the syngas. Typically, the syngas exiting unit 818 should have less than about 5wt.% water, less than about 2 wt.%, less than about 1 wt.% and less than about 0.1 wt.% water.

After exiting unit 818, the now dried syngas is in synthesis stage 802. In stage 802, the now dry syngas flows to component 830. Component 830 provides for the controlled addition of hydrogen from line 831 to the now dry syngas. In this way, the ratio of the syngas components may be adjusted and controlled to a predetermined ratio. Hydrogen is provided by a hydrogen separation unit 839. The rate adjusted dry syngas exits assembly 830 and flows to compressor 832. Compressor 832 compresses the syngas to the optimum pressures taught and disclosed in this specification for use by synthesis unit 833. Preferably, the synthesis unit 833 is a two stage unit having a first reactor unit 833a and a second reactor unit 833 b. The synthesis unit 833 also has a heat exchanger 820e.

The synthesis unit 833 converts the rate adjusted dry synthesis gas to value added product methanol. Methanol flows into heat exchanger 820d. Methanol flows to the collection unit 840. The methanol is collected by collection unit 840 and passed through line 841 for sale, storage or further processing.

Typically, the synthesis gas is compressed to a pressure of about 15 to about 100 bar, and preferably 30 to 50 bar, about 25 to about 80 bar, at least about 10 bar, at least about 25 bar and at least about 50 bar, and greater and lower pressures. The temperature of the pressurized syngas is adjusted to a temperature of about 150 ℃ to about 350 ℃, and preferably 250 ℃, about 200 ℃ to about 300 ℃, about 250 ℃ to about 375 ℃, greater than 125 ℃, greater than 150 ℃, greater than 200 ℃, greater than 250 ℃, greater than 350 ℃ and less than 400 ℃, and higher and lower temperatures. The pressure and temperature controlled synthesis gas is then fed to a reactor for converting the synthesis gas into more useful, easier to transport and economically viable products such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids and other fuels or chemicals. In a preferred embodiment, methanol is produced using a synthesis gas to methanol reaction, a CO hydrogenation reaction, a CO ₂ hydrogenation reaction, and a reverse water shift, using an actively cooled reactor, such as a heat exchange reactor or a boiling water reactor, and a copper-containing catalyst, such as Cu/ZnO/Al ₂O₃, and the like.

Typically, and in preferred embodiments, the characteristic length scale of the reactors used in the system is small enough (e.g., microchannels or mini-channels) that they can be formed into unusual shapes and topologies using new 3D printing techniques for metals and other high temperature materials, allowing for compact packaging and tight control of reaction conditions. Other strategies to enhance downstream synthesis reactions, such as selectively removing product from the reactor in situ or in a tightly coupled manner, may also be considered to shift equilibrium-limited reactions to higher conversion. Such process intensification may minimize the need for large recycle streams or allow the reaction to proceed under milder conditions (e.g., lower pressure), thereby increasing safety margins.

Typically, the H ₂/CO ratio in the syngas produced by the engine may be adapted to the downstream conversion process. For example, for methanol synthesis or Fischer-Tropsch (F-T) synthesis, the ideal H ₂/CO ratio is 2 to 3. The maximum possible H ₂/CO ratio is desirable for ammonia synthesis or hydrogen production and can be increased by, for example, adding steam to promote the water gas shift reaction. For ammonia and hydrogen production, CO is not required for downstream synthesis. Thus, CO and CO ₂ byproducts may be collected, sequestered, stored, or used for other purposes.

The collection unit 840 also has a line that flows the gas separated from the methanol to a three-way junction 835 where the gas is sent to a hydrogen separator 839, a recycle loop, or both. The recycle loop has a compressor 834 and a valve 838 to feed methanol back to the synthesis unit 833. The hydrogen separation may be achieved via membrane separation or Pressure Swing Adsorption (PSA) or the like in the hydrogen separation unit 839.

The remaining gas after hydrogen separation is sent through loop 890 and heat exchanger 820f to turboexpander 891 where the gas is then sent to an exhaust pipe.

Example 13

In the embodiment of the system of fig. 8, the reformer 814 is a spark ignition (otto cycle) reciprocating engine. The system may preferably operate as shown in the T-S diagram of fig. 9. The reference points (numerals 81, 82, 83, 84, 85, 86, 87, 88, 89 in fig. 8) correspond to the process conditions, i.e. status points, of these locations in the system of fig. 8, and these process conditions are represented by the corresponding reference points in fig. 9. The line from the status points 84a 'to 84b' represents a decrease in the compression ratio that occurs in response to the more reactive flare gas fuel. The state point 85b relates to the syngas leaving the syngas reformer after expansion of the turbocharger. Expansion from 85 to 85b occurs within the turbocharger. The initial specific entropy of the process is at points 81, 82 (6.9 kJ/kg C.) and the final specific entropy of the process is at point 89 (6.95 kJ/kg C.). Thus, the difference between the initial specific entropy and the final specific entropy was 0.05kJ/kg ℃.

Fig. 9A is a table listing further operating conditions of the system of this example. Fig. 9A shows the compression power (total and net power) of a flare gas to methanol process using the turbo-expander 891 at 3 bar back pressure and 50 bar methanol synthesis pressure.

Example 14

In the embodiment of the system of fig. 8, the reformer 814 is a compression ignition (diesel cycle) reciprocating engine. The system may preferably operate as shown in the T-S diagram of fig. 11. The reference points (numerals 81, 82, 83, 84, 85, 86, 87, 88, 89 in fig. 8) correspond to the process conditions, i.e. status points, of these locations in the system of fig. 8, and these process conditions are represented by the corresponding reference points in fig. 11. The line from the status points 84a 'to 84b' represents a decrease in the compression ratio that occurs in response to the more reactive flare gas fuel. The state point 85b relates to the syngas leaving the syngas reformer after expansion of the turbocharger. Expansion from 85 to 85b occurs within the turbocharger. The initial specific entropy of the process is at points 81, 82 (6.9 kJ/kg C.) and the final specific entropy of the process is at point 89 (6.95 kJ/kg C.). Thus, the difference between the initial specific entropy and the final specific entropy was 0.05kJ/kg ℃.

Example 15

Turning to fig. 10A and 10B, an embodiment of a variable compression ratio engine is shown that may be used as a reformer in embodiments of the present system including examples. Variable compression ratio engine 1002 may be an engine such as a Nissan VC-turbo engine that uses a multi-rod system instead of a conventional connecting rod to rotate a crankshaft, and an actuator motor to vary the end point of the multi-rod system to vary the stroke of the piston to convert the compression ratio.

Fig. 10A is a cross-sectional view of a conventional engine 1001, as compared to a partial cross-sectional view of a variable compression engine 1002. The piston 1010 and the crank 1011 are identical. The conventional engine 1001 has a connecting rod 1020 and a second balancer 1021. Variable compression engine 1002 has a U-shaped link 1030, an L-shaped link 1031, a C-shaped link 1032, a control shaft 1033, an a-shaped link 1034, and an actuator motor 1035.

The components of variable compression engine 1002 allow for continuously varying compression ratios as needed ranging from about 8:1 (high load) to about 14:1 (low load). For an automobile engine manufactured by Nissan, the optimal compression ratio may be continuously set to match the driver's operation of the accelerator pedal. Fig. 10A and 10B show schematic diagrams of such a link mechanism. The effect of this linkage on piston height is shown in fig. 10B. This method may be applied to two-stroke or four-stroke reciprocating engines, but the engines described herein preferably operate as four-stroke engines. Thus, using a variable compression engine as a reformer, the optimal compression ratio for producing synthesis gas can be continuously set to accommodate varying combustion properties from flare gas having a variable compression ratio. In this manner, in an embodiment, the syngas is produced using an engine with a linkage mechanism for rotating a crankshaft to vary a compression ratio to operate rich with a variable flare gas composition.

Thus, and for illustration, turning to fig. 10B, the relative adjustment of a variable compression reciprocating engine reformer 1002 is shown. Piston height 1010a is used for a 14:1 compression ratio. Piston height 1010b is used for a compression ratio of 8:1. The adjustment of the linkages is illustrated by arrows 1031a and 1033 a.

Example 16

Turning to FIG. 12, an embodiment of an engine for generating syngas from compression ignition of a rich fuel-air mixture is shown, which is preferred for simplicity (a smaller number of parts) and better performance (a high compression ratio results in faster combustion time). The engine reformer may be used in embodiments of the present system, including examples. One example architecture is an opposed piston free piston linear internal combustion engine with an integrated linear motor/generator, such as the one produced by MAINSPRING ENERGY (also known as Etagen). U.S. patent No.2,362,151, the entire disclosure of which is incorporated herein by reference, discloses a basic engine configuration that is improved in accordance with the teachings of the present specification.

Thus, turning to fig. 12, a free piston engine "a" is connected to two single phase generators "B" and "B", which may be operated by the engine. When used as a reformer, the generator may not be present or may be used to power components in the system.

The free piston engine a has a cylinder 61, pistons 62-62a reciprocate in the cylinder 61, and the cylinder 61 is surrounded by a second cylinder 63, the second cylinder 63 having an annular water chamber 65 therein, the annular water chamber 65 surrounding an explosion chamber 64 of the engine. As shown, an annular air chamber 66 is formed at the end of the air cylinder 63 and is connected by a passage 67 so that the air pressures in the two chambers are equalized. An intake passage 68 leads from the chamber 66a to the interior of the cylinder 61, and an exhaust passage 69 leads from the opposite end of the cylinder 61 to the manifold 10.

Because the two ends of the device are identical, only one end will be described in detail, and like parts on the other end will be indicated with like characters followed by the character "a".

A passage 11 is formed through the outer end of the chamber 66, the passage 11 being fitted with an inwardly opening non-return valve 12, said passage leading to an annular cylinder 13 arranged axially relative to the cylinder 61, the diameter of the annular cylinder 13 being slightly larger than the cylinder 61 and being mounted at its end at 14. The cylinder 13 is provided at 15 with an air intake passage fitted at 18 with an inwardly operated check valve and disposed near the inner end of the cylinder.

The piston 12 has an enlarged head 17 thereon for reciprocal movement in the chamber 13 and a rod 18 projects axially outwardly from the head and passes through a bearing 19 in the outer end of the chamber 13 and has a shoulder 20 formed therein, as shown, on the outside of the chamber 13 to form a seat for a magnet 21.

The magnet 21 is a field magnet and in this example comprises a part 22 in the form of a circle on the shoulder 20, a second member 24 of smaller diameter on the part 22, and a winding wire on the second member, as indicated at 23, which is grounded to the second part. The second member 24 is also provided with a flange 25 which flange 25 extends outwardly from its outer end perpendicular to its axis and then is bent back in parallel relation to the axis, having a diameter slightly larger than the chamber 13, to enclose the magnet parts 22 and 24, as shown. The winding 23 is powered by a battery (shown at 26) which is grounded to the motor (shown at 21) and is connected to a bar 28 which is mounted on the motor (shown at 29) and extends forwardly parallel to its axis as shown. The slider 630 is slidably engaged with the bar 28 and is in fixed contact with the coil 23 so that the magnet is always energized regardless of its position relative to the fixed end of the device.

The armature includes a coil 631 located within a support cylinder 632, the support cylinder 632 being mounted at the outer end of the chamber to enclose the magnet elements 22 and 24. Wires shown at 633 connect armatures 631 and 631a and are electrically disconnected from these wires shown at 34.

As the device operates, outward movement of the piston head 17-17a draws air into the chamber 13-13a through the valve 16-16a and pushes air through the valve 12 into the chamber 66-66a as it moves inward. When the piston 62a opens the passage 68, the air in the chamber 68a is sufficiently compressed to forcibly flow into the cylinder 61. The exhaust passage 69 is opened substantially simultaneously with passage 68 so that air entering the cylinder 61 at 68 will clear the passage and take all burnt gas away at 69, filling the cylinder with fresh air.

However, in the movement of the piston 12-12a just described, the piston head 17-17a compresses the air trapped in the chamber 13-13a, which forms a cushion that forcibly drives the piston back into the cylinder 61, thereby compressing the air therein. As the pistons approach each other, compressed air, or at least a small portion thereof, trapped therebetween is expelled through passage 635 and conduit 637 to actuate plunger 638 in injector 639, where fuel enters at 49 and is expelled through valve 41 into combustion chamber 64. When pistons 62-62a are closest to each other, these components are proportioned to form a combustible mixture, and the resulting explosion again pushes the pistons outward to repeat the cycle. Valves at 47-47a are inserted into chambers 13-13a to allow air to be drawn into the chambers to compensate for air that may leak through heads 17-17a or through bearings 19-19 a.

In such an engine, the pistons 62-62a reciprocate at a high speed of tens of thousands of times per minute, and of course, the magnets 21-21a reciprocate at the same high speed. In this way, the mechanical energy of the motor is converted into electrical energy, as the rapid reciprocation of the magnetic field around the magnets 21-21a by the induction coils 631-631a will rapidly change the number of wires or the force through the coils.

The engine is modified by digital electronic control means (sensors and control systems) to achieve a practical and efficient engine for small-scale power generation. This approach may be applied to two-stroke or four-stroke reciprocating engines, but linear engines with fixed ports in the side wall typically operate as two-stroke engines. Thus, such a linear engine operating under rich conditions may be a reformer in any example of a system for generating synthesis gas. Preferably, the linear engine reformer is a free piston configuration with an electronically controlled linear motor/generator that allows the compression ratio to vary depending on the nature of the incoming fuel. Such linear engine reformers may also have a free-piston configuration with sensors to detect in-cylinder combustion behavior under rich conditions and automatically adjust the compression ratio.

Example 17

An embodiment of a variable compression ratio engine reformer for use in embodiments of the present system including examples is a crankshaft driven opposed piston engine utilizing a variable phaser on the crankshaft. The volume of the combustion chamber in such an engine is determined by the relative position of the pistons. The shifting movement of one piston toward the other increases the minimum volume, thereby decreasing the compression ratio. Turning to fig. 8, a comparison of displacement when opposing pistons are synchronized (left) and offset by 40 degrees (right) is shown. The compression ratio is relatively high when the pistons are synchronized and decreases when the pistons are offset. One example of an opposed piston linear engine with a crankshaft is the engine developed by ACHATES ENGINES.

In one embodiment, an opposed-piston engine reformer has a variable phaser on the crankshaft to produce syngas with variable fuel rich operation, which is novel.

This approach may be applied to two-stroke or four-stroke reciprocating engines, but linear engines with fixed ports in the side wall typically operate as two-stroke engines.

Example 18

Turning to fig. 14, a modular reformer system and process is shown as part of a liquid-to-gas system 1400. The system 1400 has a reformer stage 1401, the reformer stage 1401 being placed on a transport system 1490 (e.g. a tray, truck carriage, rail car, ship deck, barge, rig, drill ship, container or other platform, base or container), the transport system 1490 being easily movable by rail, air, truck or ship. Stage 1401 has a compressor 1411 and an engine reformer 1414, as well as other components labeled on the reference numerals as taught and disclosed in this specification. It should be appreciated that any engine reformer of the present system and example may be used in stage 1401. Stage 1401 provides clean syngas.

This stage may be used or located in any unit where the synthesis gas may be further processed into valuable products. For example, this stage 1401 may be used with a modular methanol synthesis unit of the invention (such as the unit of example 19).

Example 19

Turning to fig. 15, a modular methanol synthesis system and process is shown as part of a liquid-to-gas system 1400. The system 1400 has a synthesis stage 1402, which synthesis stage 1402 can be placed on a transport system 1491 (e.g., a tray, truck bed, railcar, ship deck, barge, drilling platform, drill ship, container or other platform, base or container), which transport system 1491 can be easily moved by rail, air, truck or ship. The stage 1402 is configured to receive clean syngas. This stage 1402 can be used with the reformer stage 1401 of example 18, as well as with other reformer stages taught and disclosed in this specification (including examples). Stage 1402 produces a final product, such as methanol, from the syngas.

Stage 1402 has a synthesis unit 1433, which is a two stage unit with a first reactor unit 1433a and a second reactor unit 1433 b. This stage has a hydrogen separator 1439, a collection unit 1440, and other components as labeled in the figures and taught and disclosed in this specification. It should be appreciated that any configuration of the present system and example composition phase may be used for phase 1402.

This stage 1402 may be located near a tank, storage vessel, or synthesis gas source and processes the synthesis gas into methanol.

Example 20

Turning to fig. 16, 17 and 17A. FIG. 16 illustrates an embodiment of a system and method for converting flare gas to value added products (e.g., methanol). The system 1600 has a reformer stage 1601 and a synthesis stage 1602. The system 1600 has an air intake that delivers air to a compressor 1611 that compresses the air. The compressed air enters the mixer through a heat exchanger. The system has a flare gas inlet. The flare gas flows into the mixer through a heat exchanger. As taught and disclosed in this specification, the mixer provides a predetermined mixture of air and exhaust gas to a reformer 1614, which is a reciprocating engine.

The fuel-air mixture formed in the mixer is preferably rich, more preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

It should be appreciated that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As used herein, "aspirated" reformers and aspirated engines are understood to also include engines that use air modified by the addition of water, oxygen, or both.

The reciprocating engine 1614 combusts a predetermined mixture of flare gas and air to form syngas. The syngas flows through the heat exchanger and enters a filter, such as a particulate filter.

After passing through the filter, the synthesis gas flows to a guard bed reactor assembly having two guard bed reactors. After exiting the guard bed reactor, the synthesis gas flows to a deoxygenation reactor. The deoxygenation reactor removes excess oxygen from the reprocessing gas (e.g., syngas).

The system has a cooling system that uses a cooling fluid, such as cooling water, that flows through the cooling line.

After exiting the deoxygenation reactor, the syngas flows to a heat exchanger. The reprocessed gas (e.g., syngas) then flows from the heat exchanger to a water removal unit, such as a water separator, mist eliminator, dryer, membrane, cyclone, desiccant, or the like, where water is removed from the syngas. Typically, the syngas exiting the water removal unit should have less than about 5 wt% water, less than about 2 wt%, less than about 1 wt% and less than about 0.1 wt% water.

After leaving the water removal unit, the now dried synthesis gas flows into the synthesis stage 1602. In stage 1602, the now dry syngas flows to components that provide for the controlled addition of hydrogen from the pipeline to the now dry syngas. In this way, the ratio of the syngas components may be adjusted and controlled to a predetermined ratio. The hydrogen is provided by a hydrogen separation unit 1639. The ratio-adjusted dry syngas exits the assembly and flows to compressor 1632. The compressor 1632 compresses the syngas to an optimal pressure as taught and disclosed in this specification for use by a synthesis unit 1633, which is a two-stage unit having a first reactor unit 1633a and a second reactor unit 1633 b. The synthesizing unit 1633 also has a heat exchanger.

The synthesis unit 1633 converts the rate adjusted dry syngas to a value added product, such as methanol. The methanol flows into the heat exchanger and then into the collection unit 1640. The collection unit 1640 collects the methanol and flows it through a pipeline for sale, storage or further processing.

The collection unit 1640 also has a line that flows the gas separated from the methanol to a three-way connection where the gas is sent to a hydrogen separator 1639, a recycle loop, or both. The recycle loop has a compressor and valves to feed methanol back to the synthesis unit 1633.

The system 1600 may preferably operate as shown in the T-S diagram of fig. 17. Reference points (numerals 161, 162, 163, 164, 165, 166, 167, 168, 169 in fig. 17) correspond to process conditions, i.e., status points, for these locations in the system of fig. 16, and these process conditions are represented by the corresponding reference points in fig. 17. The initial specific entropy of the process is at point 161 (6.9 kJ/kg C.) and the final specific entropy of the process is at point 169 (6.95 kJ/kg C.). Thus, the difference between the initial specific entropy and the final specific entropy was 0.05kJ/kg ℃.

Further, turning to FIG. 17A, predicted compressor work (total work and use only for syngas compression) is shown as a function of engine exhaust back pressure at 50 bar downstream synthesis pressure. These data were produced using a chemical process simulation that mass and energy balances embodiments of liquid-to-gas systems and methods of the type shown in fig. 16. The synthesis gas compressor is considered to be a three-stage compressor with inter-stage cooling. The isentropic efficiency of the compressor is assumed to be 75%, representing industrial centrifugal and reciprocating compressors. The syngas ratio adjusts the recycle stream to enter the compressor at the inlet of the second stage. Increasing the engine exhaust back pressure from 2 bar to 3 bar reduces the compression work by 20.4%. Increasing the back pressure further from 2 bar to 4 bar reduces the compression work by 28.0%. This trend indicates a reduction in backflow and therefore the optimum value of engine exhaust back pressure for the embodiment of fig. 16 will be in the range of 2 to 5 bar to balance the reduction in compression work with the reduction in engine reformer ventilation and performance degradation.

Example 21

Turning to FIG. 18, an embodiment of a system and method for converting flare gas to value added products (e.g., methanol) is shown. The system 1800 is configured to reduce the compression work required by raising the back pressure of the engine above ambient to about 5 bar.

The system 1800 has a reformer stage 1801 and a synthesis stage 1802. The system 1800 has an air intake that delivers air to a compressor 1811 that compresses the air. The compressed air enters the mixer through a heat exchanger. The system has a flare gas inlet. The flare gas flows into the mixer 1813 through the heat exchanger 1820 b. As taught and disclosed in this specification, the mixer 1813 provides a predetermined mixture of air and exhaust gas to the reformer 1814, which is a reciprocating engine.

The fuel-air mixture formed in the mixer is preferably rich, more preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

It should be appreciated that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As used herein, "aspirated" reformers and aspirated engines are understood to also include engines that use air modified by the addition of water, oxygen, or both.

The reciprocating engine 1814 combusts a predetermined mixture of flare gas and air to form syngas. The syngas flows through the heat exchanger and enters a filter, such as a particulate filter.

After passing through the filter, the synthesis gas flows to a guard bed reactor assembly having two guard bed reactors. After exiting the guard bed reactor, the synthesis gas flows to a deoxygenation reactor. The deoxygenation reactor removes excess oxygen from the reprocessing gas (e.g., syngas).

The system has a cooling system that uses a cooling fluid, such as cooling water, that flows through the cooling line.

After exiting the deoxygenation reactor, the syngas flows to a heat exchanger. The reprocessed gas (e.g., syngas) then flows from the heat exchanger to a water removal unit, such as a water separator, mist eliminator, dryer, membrane, cyclone, desiccant, or the like, where water is removed from the syngas. Typically, the syngas exiting the water removal unit should have less than about 5 wt% water, less than about 2 wt%, less than about 1 wt% and less than about 0.1 wt% water.

After leaving the water removal unit, the now dried syngas is in synthesis stage 1802. In stage 1802, the now dry syngas is flowed to an assembly that provides for controlled addition of hydrogen from a pipeline to the now dry syngas. In this way, the ratio of the syngas components may be adjusted and controlled to a predetermined ratio. The hydrogen is provided by a hydrogen separation unit 1839. The ratio-adjusted dry syngas exits the assembly and flows to compressor 1832. The compressor 1832 compresses the syngas to an optimal pressure as taught and disclosed in this specification for use by the synthesis unit 1833, which is a two-stage unit having a first reactor unit 1833a and a second reactor unit 1833 b. The synthesis unit 1833 also has a heat exchanger.

The synthesis unit 1833 converts the rate-adjusted dry syngas into value-added products, such as methanol. The methanol flows into the heat exchanger and then flows into the collection unit 1840. The methanol is collected by collection unit 1840 and passed through a pipeline for sale, storage, or further processing.

The collection unit 1840 also has a line that flows the gas separated from the methanol to a three-way junction where the gas is sent to a hydrogen separator 1839, a recycle loop, or both. The recycle loop has a compressor and valves to feed methanol back to the synthesis unit 1833.

Stage 1802 has a line 1883 for withdrawing depleted methanol from unit 1833b and delivering it through heat exchanger 1820d. Stage 1802 has a methanol desorber 1880 having a pump 1881. Line 1882 of desorber 1880 passes the methanol-rich product to heat exchanger 1820g.

In operation of system 1800, the preferred process uses a two-stage methanol synthesis reactor with reaction separation only in the second stage (Rxtr 2) 1833 b. The first stage (Rxtr 1) 1833a is typically far from equilibrium and reaction separation is not guaranteed. Examples shown in this figure are reactive absorption or membrane separation using liquid sweep. Methanol is selectively removed from the reactor in situ, producing a methanol-lean gas stream comprising predominantly unreacted synthesis gas and a methanol-rich absorbent stream. The main circulation loop is not used due to the improved single pass conversion compared to other embodiments. The methanol rich absorbent stream is valved to reduce the pressure and desorb the methanol which is then condensed and sent to the product stream. The absorbent, now in a regenerated state, is pumped back to the synthesis pressure and recycled to the reactor. The pumping work of the absorbent is minimal compared to the synthesis gas compressor work because the liquid absorbent is nearly incompressible. The reactor may be a trickle bed or a membrane reactor with the liquid absorbent (sweep) on the permeate side of the membrane. Any methanol that is not distributed into the absorbent condenses out of the gas phase in a downstream separation step and is mixed with the methanol product stream.

Example 22

Turning to FIG. 19, an embodiment of a system and method for converting flare gas to value added products (e.g., methanol) is shown. The system 1900 has a reformer stage 1901 and a synthesis stage 1902. The system 1900 has an air intake that feeds air to a compressor 1911 that compresses the air. Compressed air is fed into the mixer through a heat exchanger. The system has a flare gas inlet. The flare gas flows into the mixer 1913 through the heat exchanger 1920 b. As taught and disclosed in this specification, the mixer 1913 provides a predetermined mixture of air and exhaust gas to a reformer 1914, which is a reciprocating engine.

The fuel-air mixture formed in the mixer is preferably rich, more preferably having a total fuel/air equivalence ratio (Φ or ER) of greater than 1, greater than 1.5, greater than 2, greater than 3, about 1.5 to about 4.0, about 1.1 to about 3.5, about 2 to about 4.5, and about 1.1 to about 3, and greater.

It should be appreciated that oxygen may be added to the air. And water or steam may also be injected into the mixture of air and fuel, or injected into the air or fuel alone. About 1 to about 20 mole% water, about 10 to about 15 mole% water, about 5 to about 17 mole% water, more than 5 mole% water, more than 10 mole% water, more than 15 mole% water, and less than 25 mole% water may be injected. After the oxygen enrichment, the combustion air may contain from about 21% to about 90% oxygen. As used herein, "aspirated" reformers and aspirated engines are understood to also include engines that use air modified by the addition of water, oxygen, or both.

The reciprocating engine 1914 combusts a predetermined mixture of flare gas and air to form syngas. The syngas flows through the heat exchanger and enters a filter, such as a particulate filter.

After passing through the filter, the synthesis gas flows to a guard bed reactor assembly having two guard bed reactors. After exiting the guard bed reactor, the synthesis gas flows to a deoxygenation reactor. The deoxygenation reactor removes excess oxygen from the reprocessing gas (e.g., syngas).

The system has a cooling system that uses a cooling fluid, such as cooling water, that flows through the cooling line.

After exiting the deoxygenation reactor, the syngas flows to a heat exchanger. The reprocessed gas (e.g., syngas) then flows from the heat exchanger to a water removal unit, such as a water separator, mist eliminator, dryer, membrane, cyclone, desiccant, or the like, where water is removed from the syngas. Typically, the syngas exiting the water removal unit should have less than about 5 wt% water, less than about 2 wt%, less than about 1 wt% and less than about 0.1 wt% water.

After leaving the water removal unit, the now dried synthesis gas is in synthesis stage 1902. In stage 1902, the now dry syngas is flowed to components that provide for controlled addition of hydrogen from the pipeline to the now dry syngas. In this way, the ratio of the syngas components may be adjusted and controlled to a predetermined ratio. Hydrogen is provided by a hydrogen separation unit 1939. The ratio-adjusted dry syngas exits the assembly and flows to compressor 1932. The compressor 1932 compresses the syngas to an optimal pressure as taught and disclosed herein for use by the synthesis unit 1933, which is a two-stage unit having a first reactor unit 1933a and a second reactor unit 1933 b. The synthesis unit 1933 also has a heat exchanger 1920e.

The synthesis unit 1933 converts the rate adjusted dry syngas to value added products, such as methanol. The methanol flows into the heat exchanger and then into the collecting unit 1940. The collection unit 1940 collects the methanol and flows it through a pipeline for sale, storage, or further processing.

The collection unit 1940 also has a line that flows the gas separated from the methanol to a three-way junction where the gas is sent to a hydrogen separator 1939, a recycle loop, or both. The recycle loop has a compressor and valves to feed methanol back to the synthesis unit 1933.

Stage 1902 has a line 1983 for withdrawing water-depleted methanol from unit 1933b and passing it through heat exchanger 1920d. Stage 1902 has line 1987 from unit 1833b, which removes water-rich product.

System 1900 is for a gas-to-liquid process with byproduct reaction separation. The process uses a two-stage methanol synthesis reactor with reaction separation only in the second stage (Rxtr 2) 1933 b. The first stage (Rxtr 1) 1833a is typically far from equilibrium and reaction separation is not guaranteed. The example shown in this figure is membrane separation using a gas sweep. Water (a byproduct of the hydrogenation of CO ₂ to methanol) is selectively removed in situ from reactor 1833b (via line 1987) to produce a water-depleted gas stream comprising predominantly unreacted synthesis gas and a water-enriched purge gas. In this embodiment, the main circulation loop is not used due to the improved single pass conversion. Further, in this embodiment, regeneration of the purge flow (e.g., air in this embodiment) is not performed. Membrane reactors may use a polymer or ceramic membrane material on the permeate side of the membrane that is selectively permeable to water and a sweep gas (e.g., air). Removal of water shifts the equilibrium towards the product. The reverse water gas shift reaction converts CO ₂ to CO and thus this process also helps to convert CO ₂ to more active CO. Thus, this process is particularly attractive for CO ₂ -rich syngas streams, such as those produced by partial oxidation. The methanol condenses out of the gas phase in a downstream separation step and is mixed with the methanol product stream.

Example 23

One example of a methanol synthesis unit for use with any of the present systems, including the exemplary systems, is a quench-type methanol reactor. Cold reactor feed gas is injected between the catalyst beds to quench the gas exiting each catalyst bed and control the reactant feed temperature to each catalyst bed. The following parameters set the basis for the size of the methanol reactor.

4 Catalyst beds.

The inlet air temperature for each bed was 225 ℃, consistent with the feed temperature at the end of the expected catalyst donor lifetime. This sets the required quench gas flow.

Average gas velocity in the reactor < = 1ft/s. This parameter sets the minimum reactor diameter required.

Average gas residence time per catalyst bed > =2.5 seconds. This parameter sets the minimum average catalyst bed depth and thus the minimum tangential to tangential length of the reactor.

One parameter of methanol synthesis is the ratio of hydrogen to carbon oxides in the methanol reactor feed. The gas stoichiometry is defined as follows using the S ratio.

The preferred S ratio is between 2 and 2.3. A typical steam methane reformer produces a synthesis gas with an S ratio of about 3. However, the engine reformer of the present system may produce a syngas with an S ratio approaching 1. For this exemplary embodiment, the target S ratio is 2.1. To achieve this S ratio at the feed to the methanol reactor, a portion of the recycle loop gas needs to be routed through the hydrogen purification step. Thus, the target S ratio defines the dimensional basis of the hydrogen reclamation apparatus.

Example 23

An embodiment of a control system for operation and monitoring of the present system and process includes an example. The control system also has means for calculating, obtaining and storing data and information about the operation of the system and process (e.g., process information and data). The process data and information may include, among other things: mass balance data and information (e.g., kg of flare gas entering the system, kg of methanol produced, kg of off-gas produced, etc.), carbon capture data and information, data and information related to CO ₂ e, combinations and variations thereof, and other types of data and information. Such data and information may be used to verify or obtain carbon credits, such as at a carbon exchange, or to meet environmental regulatory reporting or monitoring requirements, among other things.

The controller has a control panel located on the system site (e.g., on a tray, at one or both stages of the modular system). The control panel will house control equipment such as controllers, marshalling panels, power supplies, network switches, etc. The control panel will include the basic process controller and the safety shutdown system. Preferably, all information will be available for monitoring and control from the control panel.

The process information and data on the field control panel will preferably be available for remote monitoring and limited remote control from a remote control room via a cellular (4G/5G) network, satellite or other wired or wireless communication mode.

Preferably, the level of automation provided by the control panel should be such that manual intervention by the operator is minimized under normal facility operating conditions. Abnormal events and conditions that occur during module startup and shutdown may require manual intervention. Preferably, the control panel should always be active and provide complete control, monitoring and protection of the module at all times.

Preferably, the control system should be designed to be fail safe so that when the power supply, the meter air supply or the control signals to/from the meter device are disconnected, the facility will be brought into a predetermined safe operating state.

Preferably, the control system should support a degree of redundancy and fault tolerance such that failure of any individual component of the system does not significantly adversely affect the controlled process.

Preferably, the control panel is used as an Integrated Control and Safety System (ICSS) to provide basic process control and basic safety functions to the system, and preferably includes one, more than one, and all of the following functions:

basic Process Control System (BPCS),

Safety Instrumented Systems (SIS), if it is determined that it is needed at a future stage of the project,

A corresponding human-machine interface (HMI) display,

The communication system is a communication system of a communication network,

Mechanical vendor system interface (such as anti-surge control system (ASC)).

Preferably, all field meters should be "smart" devices, e.g., the HART protocol can be used for meter diagnostics. The meter design and selection should conform to industry standards such as ISA (international automation association) and PIP (process industry practice). IEC61508 certified instruments are applied to SIL 1 or larger SIFs.

Example 24

Turning to fig. 24, a control and communication system network 2300 for use with the systems and processes (including examples) of the present invention is provided. The network 2300 includes and is in control communication with a flare gas to syngas to methanol system 2301, which is generally of the type disclosed and taught in the specification (including examples).

The system 2300 has a local, e.g., field control system 2320. The components of the field control system 2320 may be located on the system 2301 or in a box or housing connected to the system 2301. The components of system 2320 may be located in separate housings and enclosures, or in a single enclosure. The system 2320 has a controller 2321 with a processor and memory, a storage device 2322, an HMI (human-machine interface) 2323 and input/output (I/O) 2324, and a communication module 2325.

The system 2300 has many site communication paths, e.g., 2341, that constitute a local or site subnetwork 2340. Subnetwork 2340 may also communicate with other subnetworks via path 2342. These on-site communication pathways, such as 2341, communicate with one, more than one, and preferably all devices and components of the system 2301, including control communications, data and information. Additionally, these site paths, e.g., 2341, communicate with one, more than one, and preferably all of the sensors and monitoring devices and instruments in the system 2301, including control communications, data and information. In this manner, the field subnetwork 2340 can send and receive control communications as well as sensor data and information from the system 2301 to the control system 2320. In this manner, the in-situ control system 2320 is in control communication with the flare gas to syngas to methanol system 2301. In this manner, the field control system 2320 may operate and control the system 2301 and receive data and information regarding the processes and operation of the system 2301. The field control system 2320 may be configured, for example, along the route of the control system in example 23.

The field control system is in control communication with a remote control system 2350. In this manner, the remote control system 2350 may configure, control, alter, monitor, and both the on-site control system 2320, the system 2300. The remote control system has a system 2320, the system 2320 having a controller with a processor and memory, storage devices, HMI, and a communication module.

The remote control system 2350, the control system 2320, and both are configured to monitor, calculate, record, store, and transmit information regarding any and all aspects of the operation of the system 2301, such as flow rates, mass flow rates, densities, temperatures, settings of equipment, exhaust conditions, and the like. In one case, these operational aspects will include: mass balance data and information (e.g., kg of flare gas entering the system, kg of methanol produced, kg of vent gas produced, etc.). This information and data can be processed to determine and record GWP information and data, carbon capture information and data, CO2e information and data, preferably for operation of system 2301 in real time, and preferably for real time operation of system 2301. Such data and information may be used to verify or obtain carbon credits, such as at a carbon exchange, or to meet environmental regulatory reporting or monitoring requirements, among other things. Preferably, this GWP type of information is encrypted using a blockchain or some other encryption method to ensure its validity.

Thus, the control system 2320, the remote control system 2350, and both may be in control communication with another entity 2360. For example, entity 2360 may be a carbon exchange, which may be a government regulatory agency, which may be a trade regulatory agency, or other entity, such as a classroom. It should be noted that although the communication paths between entity 2360 and the control may be bi-directional communications, these paths do not send or receive any control communications. In this way, entity 2360 has no capability to control system 2301. Further, other information about the system 2301 may be provided to the entity 2360 as needed or desired.

Example 25

Turning to fig. 25, a schematic diagram of the architecture of a control communication network for use with the present system and process, including examples, is shown.

Example 26

Where the flare gas comprises H ₂ S, it is preferred that the flare gas be removed prior to its processing into synthesis gas. Batch and cyclic process techniques may be used to remove H ₂ S, which would include a packed bed with solid adsorbent/scavenger material. Liquid solvents, most commonly amines such as Methyldiethanolamine (MDEA), can be used to remove H ₂ S and CO ₂ from the flare gas stream. A typical configuration is to pass the amine solution through the absorber counter-current to the flare gas. The amine stays in a closed loop and is regenerated by heating.

Example 27

The present systems and methods, including examples, are operated to convert flare gas to methanol having a purity of about 80% and greater, at least about 85%, at least about 90%, at least about 93%, at least 95%, about 80% to 95%, and about 85% to about 90%.

Example 28

A system and method for converting an otherwise uneconomical hydrocarbon-based fuel, such as flare gas, to a value-added, easily transportable product, such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, using an autonomous modular system, the system comprising the following elements: (1) a fuel conditioning system meeting downstream component requirements; (2) A gas turbine engine adapted to operate the rich partial oxidation reformer to produce a synthesis gas mixture having an H ₂/CO ratio suitable for liquid synthesis; (3) An integrated heat exchanger, compression system components, and heat exchanger combination for producing synthesis gas for a downstream synthesis reactor; and (4) a downstream synthesis reactor system for producing a useful liquid hydrocarbon product.

Example 29

A system and method for converting an otherwise uneconomical hydrocarbon-based fuel, such as flare gas, to a value-added, easily transportable product, such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, using an autonomous modular system, the system comprising the following elements: (1) a fuel conditioning system meeting downstream component requirements; (2) A gas turbine engine adapted to operate the rich partial oxidation reformer to produce a synthesis gas mixture having an H ₂/CO ratio suitable for liquid synthesis; (3) An integrated heat exchanger, compression system components, and heat exchanger combination for producing synthesis gas for a downstream synthesis reactor; (4) A downstream synthesis reactor system for producing a useful liquid hydrocarbon product; and (5) a hydrogen recycle loop for improving process performance of the overall system.

Example 30

The systems and methods of examples 28 and 29 may also have one, more or all of the following additional features: (6) An optional substantially oxygen-free gas recirculation loop for cooling and protecting downstream components of the combustion chamber, such as seals, bearings, and secondary cavities; (7) Subjecting the gas turbine inlet stream to optional O ₂ enrichment via a membrane separation or partial air separation unit; (8) A recuperator (from (3)) and a turbo-expander for recovering energy from the high pressure exhaust gas from the downstream synthesis reactor; (9) integration of the closed loop operating system with custom instrumentation; (10) A cloud-based remote monitoring system including anomaly detection for AI training for dynamic preventative maintenance and operational control; (11) An optional vent path for reinjection, completion, or other purposes with byproducts such as nitrogen, water, and CO ₂; (12) Water (or steam) is optionally injected into the rich combustor to increase the H ₂/CO ratio and reduce carbon build-up on the combustor and turbine inner surfaces.

Example 31

Embodiments of these inventions provide a modular system that can be located near sources of uneconomical hydrocarbons (e.g., flare gas), synthesis gas, product gas, and reprocessing gas to convert these materials into higher value products. These inventions will be used to capture uneconomical hydrocarbon-based fuels of primarily gaseous hydrocarbons at the wellhead (e.g., flare gas) and at a remote location and convert them into more valuable readily condensable or liquid compounds such as methanol. One source of source fuel may be associated gas or flare gas, which is a by-product of an oil well. Another source may be biogas from a landfill site or an anaerobic digester.

A small scale facility, targeting 3000000scfd (standard cubic feet per day) of inlet gas. The scale of such facilities may vary from 300000scfd to 15000000 scfd. The facility is incorporated into one or more modular, interconnected pallets or containers that are built at a central manufacturing plant location and then installed at a site location. A small number of modules comprise such a system and when connected in the field they form an integrated system. The modular nature of the assembly enables it to be applied at remote locations over a range of inlet gas feed volumes while minimizing site labor. The modular nature further increases flexibility in deploying or redeploying these assets, reduces initial capital expenditure and project financial risk, allows process throughput to be matched to flare gas supplies, and shortens the time to market by allowing module manufacturing and site preparation to proceed in parallel.

Example 32

A modular unit with a set of unit-scale engine reformers and a unit-scale MeOH synthesis system, without a common BOP (facility balance).

Example 33

A modular unit having a set of unit-scale engine reformers and a unit-scale MeOH synthesis system with a common BOP.

Example 34

A modular unit having a set of unit-scale engine reformers provides a versatile, integral MeOH synthesis system.

Example 35

A modular unit having 900scfd (standard cubic feet per day) of feed gas (e.g., flare gas).

Example 36

A modular unit having 75000scfd of feed gas (e.g., flare gas) sized for a single engine reformer.

Example 37

A modular reformer stage having 2 or more, 3 or more, at least 5, at least 6 or 2 to 10 reformers. The reformer may be one or more of a gas turbine engine, a combustion box, an internal combustion engine, an otto cycle reciprocating engine, a diesel cycle reciprocating engine, and combinations thereof. Such modular reformer stages may be tray mounted, truck mounted, etc.

Example 38

In an embodiment of the invention, there is a rich reciprocating engine and a synthesis reactor. Unlike conventional reciprocating engines, the engine operates under rich conditions, with an equivalent ratio of up to 2.5, so the fuel undergoes rich Partial Oxidation (POX). Additional components include fuel conditioning systems, heat exchangers, compressors, and turbines. The fuel conditioning system separates liquids from gases in the feed stream and removes compounds that may damage the reciprocating engine or the synthesis reactor. The heat exchanger and compressor receive the syngas mixture at the outlet of the reciprocating engine and regulate temperature and pressure to provide the target conditions for the synthesis reactor. The synthesis subsystem has an optional H ₂ recycle loop. The synthesis reactor outlet gas is heated to high temperature in a recuperative (e.g., counter-current) heat exchanger and then expanded to ambient conditions.

Example 39

In this embodiment, it is preferred that when configuring and operating the syngas engine, to achieve preferred engine operation under conditions of sufficient rich combustion, to produce a syngas having a desired H ₂/CO ratio approaching 2. Even though acceptable operability is achieved using a fixed fuel composition, variations in fuel composition during field operation, such as in an oil well, will change combustion properties and result in poor engine operation. Accordingly, the engine has sensors and a control system that detect changes in the fuel combustion properties and adjust its parameters to achieve the desired engine operation. Engines combining sensing and variable compression ratios may overcome these challenges. The variable compression ratio engine adjusts the compression ratio of the internal combustion engine when the engine is operating. The variable compression engine allows the volume above the piston at top dead center to vary.

Example 40

One embodiment of a variable compression ratio engine reformer is through the use of variable valve timing, such as a cam phaser. Dual independent variable camshaft timing (Ti-VCT) is the name given by Ford corporation to engines capable of independently advancing or retarding intake and exhaust camshaft timing, unlike the original version of VCT that operates on only a single camshaft. This helps to improve power and torque, especially at lower engine RPM, as well as fuel economy and reduce emissions.

A "cam phaser" is an adjustable camshaft sprocket that can be rotated by a computer controlled servo system. The computer may advance or retard the cam continuously rather than operating at a fixed amount of advance or retard. One example of such an application is to improve drivability at light loads and low engine speeds (by reducing overlap of intake and exhaust events to minimize residual dilution) and to generate more power at high engine speeds (by delaying intake valve events to increase volumetric efficiency).

For rich operation where the syngas is produced, when the fuel composition is richer (the ratio of low octane components is greater), the purpose of retarding the timing of the intake valve event is to sufficiently retard valve closure to shorten the effective compression stroke and thus reduce the effective compression ratio.

When the fuel composition is lean (the ratio of high octane components is large), the purpose of advancing the intake valve timing is to advance the intake valve opening sufficiently to extend the effective compression stroke and thus increase the effective compression ratio. Operating at a higher effective compression ratio increases the pressure and temperature in the combustion chamber and thus enlarges the rich limit of lean gas.

Example 41

A VVT/cam (variable valve timing/cam) phaser engine that allows for compression ratios to vary depending on, among other things, the nature of the fuel that is admitted for rich combustion to produce syngas.

Example 42

A VVT/cam phaser engine with a sensor for detecting in-cylinder combustion behavior under rich conditions and automatically adjusting compression.

This method may be applied to two-stroke or four-stroke reciprocating engines.

Example 43

A system and method for converting an otherwise uneconomical hydrocarbon-based fuel, such as flare gas, to a value-added, easily transportable product, such as methanol, ethanol, ammonia, dimethyl ether, F-T liquids, and other fuels or chemicals, using an autonomous modular system, comprising the following elements: (1) a fuel conditioning system meeting downstream component requirements; (2) A gas-breathing gas engine adapted to operate the rich partial oxidation reformer to produce a synthesis gas mixture having an H ₂/CO ratio suitable for liquid synthesis; (3) An integrated heat exchanger, compression system components, and heat exchanger combination for producing synthesis gas for a downstream synthesis reactor; (4) A downstream synthesis reactor system for producing a useful liquid hydrocarbon product; and (5) a hydrogen recycle loop for improving process performance of the overall system.

Example 44

One example of a variable compression ratio engine is an opposed piston free piston linear internal combustion engine. Free piston engines are linear "crankless" internal combustion engines. The power delivered by the engine is not delivered via a crankshaft, but rather generates electrical energy by driving a turbine through exhaust gas or a linear motor/generator coupled directly to the piston.

Example 45

A rich-burn reciprocating engine and a synthesis reactor. Unlike conventional reciprocating engines, which operate under fuel-rich conditions, the equivalent ratio is up to 2.5, so the fuel undergoes fuel-rich Partial Oxidation (POX). Other components include fuel conditioning systems, heat exchangers, compressors, and synthesis reactors. The fuel conditioning system separates liquids from gases in the feed stream and removes compounds that may damage the reciprocating engine or the synthesis reactor. The heat exchanger and compressor receive the syngas mixture at the outlet of the reciprocating engine and regulate temperature and pressure to provide the target conditions for the synthesis reactor. The synthesis subsystem has an H ₂ recycle loop or CO ₂ scrubber for regulating the syngas ratio. Optionally, the gas at the synthesis process outlet is heated to high temperature in a recuperative (e.g., counter-current) heat exchanger and then expanded to ambient pressure, thereby providing shaft work for compression of the synthesis gas.

Example 46

The embodiments of the system of the above examples operate in a carbon neutral to negative manner, producing and releasing less than or equal to zero CO2e from a lifecycle perspective.

Example 47

One or more of the systems of the above examples are placed in an oilfield having a large number of wells. Flare gas from these wells is captured at the wellhead of each well and flows in piping and manifold systems to units where the flare gas is processed into end products, such as methanol.

Example 48

One or more of the systems of the above examples are placed at an livestock production farm, process or production facility. Methane-rich biogas from anaerobic digestion of livestock manure is collected and processed by the system into end products, such as methanol.

Example 49

One or more of the systems of the above embodiments are placed in a municipal wastewater treatment facility where the anaerobic digester produces fuel for the syngas unit and the methanol produced by the process is consumed by the denitrification process as part of the treatment process. This approach results in a localized and cyclic process of wastewater treatment.

Example 50

In an oilfield having several wells, gas wells, or both (e.g., 5 wells, 10 wells, 20 wells, or more), piping and distribution headers are used to collect and deliver flare gas from each well to one or more off-gas (e.g., flare gas) treatment units of the present invention, such as one or more systems of the examples described above.

Example 51

Hydrocarbon production activities, such as exploration, drilling, workover, and completion of hydrocarbon wells (e.g., oil or gas wells), may include planning and use of the systems (including the systems of the examples described above) and methods of the present invention. In this way, the overall impact of hydrocarbon production activities on global warming (e.g., GWP) may be mitigated or reduced. Thus, use of the system and method of the present invention, including examples, may be included in planning hydrocarbon activities, as well as obtaining regulatory approval for such activities.

Example 52

The systems and methods of the present invention, including exemplary systems and methods, wherein the source of flare gas is one or more of a hydrocarbon well, an oil well, an unconventional oil well, a conventional oil well, an offshore well, or an onshore well.

Example 53

The systems and methods of the present invention, including the systems and methods of the embodiments, wherein the source of the flare gas is selected from the group consisting of petrochemical processing, refining, landfill, wastewater treatment, and livestock.

Example 54

The embodiments of the system illustrated above operate in a positive energy manner, producing more power in an electrical form than is required to operate the system.

Title and examples

It should be understood that the headings used in this specification are for clarity, reference, and not limitation in any way. Accordingly, the process composition and disclosure described under one heading should be read in the context of the entire specification, including various examples. The use of headings in this specification should not be construed as limiting the scope of the invention.

It should be noted that there is no need to provide or set forth a theory of novel and breakthrough productivity, performance, or other beneficial features and properties that are the subject of or associated with the embodiments of the present invention. However, various theories are provided in this specification to further advance the art in this important area, particularly in the field of oil and gas exploration and production. These theories presented in this specification, unless explicitly stated otherwise, in no way limit, restrict or narrow the scope of the claimed invention. These theories may not be needed or practiced with the present invention. It should also be appreciated that the present invention may yield new heretofore unknown theories to explain the conductivity, cracking, drainage, resource production and functional characteristics of embodiments of the methods, articles, materials, devices and systems of the present invention; and these latter teachings should not be taken as limiting the scope of the invention.

In addition to those embodiments in the drawings and the embodiments disclosed in this specification, the various embodiments of the apparatus, systems, activities, methods and operations set forth in this specification may be used with, in or by various processes, industries and operations. The various embodiments of the devices, systems, methods, activities, and operations set forth in this specification may be used with the following processes: other process industries and operations that may be developed in the future: existing process industries and operations, which may be modified based in part on the teachings of this specification; as well as other types of gas recovery systems and methods. Further, the various embodiments of the devices, systems, activities, methods, and operations set forth in this specification may be used with different and various combinations. Thus, for example, the configurations provided in the various embodiments of the present description may be used together. For example, components having embodiments of A, A' and B and components having embodiments of a ", C, and D may be used together in various combinations, such as A, C, D, and A, A", C, and D, etc., in accordance with the teachings of the present specification. Therefore, the scope of protection provided by the present invention should not be limited to the particular embodiments, configurations, or arrangements set forth in the particular embodiments, examples, or embodiments in the particular drawings.

The present invention may be embodied in other forms than those specifically disclosed herein without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive.

Claims (111)

1. A system for converting flare gas to a final product, the system comprising:

a. A reformer stage and a synthesis stage;

b. the reformer stage includes:

i. an inlet for receiving a flare gas stream;

an air inlet for receiving an air flow;

a mixer for mixing the air stream and the flare gas stream; wherein the mixer is configured to provide a mixture having a rich fuel/air equivalence ratio;

A gas-absorbing reformer configured to operate under fuel/air rich conditions; wherein the reformer is configured to operate in a partial oxidation combustion window; whereby the reformer is configured to convert the mixture into synthesis gas;

a line for flowing the synthesis gas to the synthesis stage;

c. the synthesis stage comprises:

i. a line for receiving a synthesis gas stream from the reformer stage;

a synthesis unit configured to receive the synthesis gas and convert the synthesis gas to a final product;

d. A control system configured to operate the reformer stage at a predetermined partial oxidation temperature and a predetermined partial oxidation pressure; and operating the synthesis stage at a predetermined synthesis temperature and a predetermined synthesis pressure.

2. The system of claim 1, wherein the reformer stage and the synthesis stage are integral.

3. The system of claim 1, wherein the reformer stage and the synthesis stage are separate connectable modular units.

4. A system according to any one of claims 1 to 3, wherein the air-breathing reformer comprises a rich-burn, air-breathing reciprocating engine.

5. A system according to any one of claims 1 to 3, wherein the air-breathing reformer comprises a reciprocating engine with a variable compression ratio; and further comprising:

a. A sensor system for detecting ignition/combustion behavior in a range from pre-ignition to misfire;

And is configured to transmit detected ignition/combustion behavior information;

b. Wherein the control system is in control communication with the sensor system and the engine;

c. Wherein the control system is configured to adjust the engine compression ratio based on the detected ignition/combustion behavior information; and

D. Thus, the control system is configured to adjust the compression ratio in response to variability in the composition of the flare gas.

6. The system of any of claims 4-5, wherein the engine is a compression ignition engine.

7. The system of any of claims 4 to 5, wherein the engine is a spark ignition engine.

8. The system of any of claims 4 to 5, wherein the engine is an opposed-piston free-piston linear internal combustion engine.

9. A system according to any one of claims 4 to 5, wherein the engine is a crankshaft driven opposed piston internal combustion engine with a crankshaft phaser for rotating the phase of one piston relative to the other piston to vary the overall compression ratio.

10. The system of any one of claims 4 to 5, wherein the engine is a conventional spark-ignition reciprocating engine, wherein the engine is configured for variable effective compression ratio, with a camshaft phaser to rotate an intake camshaft and an exhaust camshaft, thereby affecting valve opening and closing.

11. The system of any of claims 4 to 5, wherein the engine is configured for variable effective compression ratio, with variable lift, duration valve train, or both to affect valve opening and closing.

12. The system of any of claims 4-5, wherein the engine comprises a multi-link system configured to rotate a crankshaft, and comprises an actuator motor configured to change an end point of the multi-link system.

13. The system of any one of claims 4 to 5, wherein the engine is a two-stroke engine.

14. The system of any one of claims 4 to 5, wherein the engine is a four-stroke engine.

15. The system of any one of claims 1 to 14, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 2 to about 3.

16. The system of any one of claims 1 to 14, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 0.8 to about 2.5.

17. The system of any one of claims 1 to 14, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 1.1 to about 2.5.

18. The system of any one of claims 1 to 14, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at less than about 3.

19. The system of any one of claims 1 to 14, wherein the predetermined temperature and pressure comprises one, more than one or all of: (i) The predetermined partial oxidation temperature is from about 700 ℃ to about 1200 ℃; (ii) The predetermined partial oxidation pressure is from about 1 bar to about 70 bar; (iii) The predetermined synthesis temperature is from about 200 ℃ to about 300 ℃; and (iv) the predetermined resultant pressure is from about 30 bar to about 100 bar.

20. A system according to any one of claims 1 to 3, wherein the reformer comprises one or more of a gas turbine engine, a combustion box, an internal combustion engine, an otto cycle reciprocating engine and a diesel cycle reciprocating engine.

21. The system of any one of claims 1 to 20, wherein the controller is configured to maintain a fuel/air equivalence ratio of about 1.5 to about 2.5.

22. The system of any of claims 1 to 20, wherein the controller is configured such that a change in the composition of the flare gas does not change the composition of the final product.

23. The system of any of claims 1 to 20, wherein the controller is configured such that a change in the composition of the flare gas does not change the composition of the final product; and wherein the change in the composition of the flare gas does not require a change in one or more of the predetermined synthesis temperature, the predetermined synthesis pressure, the predetermined reformer temperature, and the predetermined reformer temperature.

24. The system of any one of claims 1 to 23, comprising a water inlet, a steam inlet, or both for introducing water, steam, or both into the reformer.

25. A system according to any one of claims 1 to 3, wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following:

a) A compression ratio in the range of about 8:1 to about 17:1;

b) An intake manifold air temperature of ambient to about 300 ℃;

c) Intake manifold air pressure from ambient to about 5 bar;

d) Ignition timing between TDC and 50 degrees before TDC; and

E) An engine speed of about 8000rpm to about 1500 rpm.

26. The system of any of claims 1-3, wherein the reformer comprises a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of:

a) A first partial oxidation combustor;

b) A two-stage combustion process;

c) A gas turbine combustor; and

D) Combustion cycle times of 5 milliseconds to 50 milliseconds.

27. The system of any one of claims 1 to 26, comprising a hydrogen separation unit for providing a recovered hydrogen stream to the system.

28. The system of any one of claims 1 to 26, comprising a hydrogen separation unit for providing a recovered hydrogen stream for mixing with the synthesis gas.

29. The system of any one of claims 1 to 26, comprising a hydrogen separation unit for providing a recovered hydrogen stream for mixing with the synthesis gas; and wherein the control system is configured to control the mixing of the recovered hydrogen with the synthesis gas to provide a predetermined H ₂ to CO ratio.

30. The system of any one of claims 1 to 29, wherein the end product is selected from the group consisting of methanol, ethanol, mixed alcohols, ammonia, dimethyl ether, and F-T liquid.

31. A system for converting flare gas to a final product, the system comprising:

a) Defining a flare gas source of an initial specific entropy;

b) An oxygen source, wherein the oxygen source comprises air;

c) Defining a fuel/air mixture having an initial specific entropy;

d) A control system;

e) A suction reformer;

f) The reformer is coupled to the control system and configured to partially oxidize a mixture of the oxygen source and the flare gas; thereby providing a reprocessed gas stream comprising synthesis gas;

g) A synthesis unit, in combination with the control system, configured to provide a first product stream comprising a final product; wherein the final product stream and the exhaust product stream define a final specific entropy;

h) The control system is configured to operate the system, wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; and

I) Wherein, during operation, the system is configured to produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

32. A system for converting flare gas to a final product, the system comprising:

a) Defining a flare gas source of an initial specific entropy;

b) An air source;

c) Defining a fuel/air mixture having an initial specific entropy;

d) A control system;

e) A suction reformer;

f) The reformer is coupled to the control system and configured to partially oxidize a mixture of the air and the flare gas; thereby providing a reprocessed gas stream comprising synthesis gas;

g) A synthesis unit, in combination with the control system, configured to provide a first product stream comprising a final product; wherein the final product stream and the exhaust product stream define a final specific entropy;

h) The control system is configured to operate the system, wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; and

I) Wherein, during operation, the system is configured to be net carbanionic, whereby, during operation, the system produces less than about-20 kg co2e per 1 kg of end product provided.

33. A system for converting flare gas to a final product, the system comprising:

a) Defining a flare gas source of an initial specific entropy;

b) An air source;

c) Defining a fuel/air mixture having an initial specific entropy;

d) A control system;

e) A suction reformer;

f) The reformer is coupled to the control system and configured to partially oxidize a mixture of the air and the flare gas; thereby providing a reprocessed gas stream comprising synthesis gas;

g) A synthesis unit, in combination with the control system, configured to provide a first product stream comprising a final product; wherein the final product stream and the exhaust product stream define a final specific entropy;

h) The control system is configured to operate the system, wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃;

i) Wherein, during operation, the system is configured to be net carbanionic, whereby, during operation, the system produces less than about-20 kgCO e per 1 kilogram of end product provided; and

J) Wherein, during operation, the system is configured to produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

34. The system of any one of claims 31 to 33, comprising a reformer stage and a synthesis stage; wherein the reformer stage and the synthesis stage are integral.

35. The system of claims 31 to 33, comprising a reformer stage and a synthesis stage; and wherein the reformer stage and the synthesis stage are separate connectable modular units.

36. The system of any one of claims 31 to 33, wherein the induction reformer comprises a rich, induction reciprocating engine.

37. The system of any one of claims 31 to 33, wherein the suction reformer comprises a reciprocating engine with a variable compression ratio; and further comprising:

a. A sensor system for detecting ignition/combustion behavior in a range from pre-ignition to misfire; and is configured to transmit detected ignition/combustion behavior information;

b. Wherein the control system is in control communication with the sensor system and the engine;

c. Wherein the control system is configured to adjust the engine compression ratio based on the detected ignition/combustion behavior information; and

D. Thus, the control system is configured to adjust the compression ratio in response to variability in the composition of the flare gas.

38. The system of any one of claims 36 to 37, wherein the engine is a compression ignition engine.

39. The system of any one of claims 36 to 37, wherein the engine is a spark ignition engine.

40. The system of any one of claims 36 to 37, wherein the engine is an opposed-piston free-piston linear internal combustion engine.

41. A system according to any one of claims 36 to 37, wherein the engine is a crankshaft driven opposed piston internal combustion engine with a crankshaft phaser for rotating the phase of one piston relative to the other piston to vary the overall compression ratio.

42. The system of any one of claims 36 to 37, wherein the engine is a conventional spark-ignition reciprocating engine, wherein the engine is configured for variable effective compression ratio, with a camshaft phaser to rotate an intake camshaft and an exhaust camshaft, thereby affecting valve opening and closing.

43. The system of any one of claims 36 to 37, wherein the engine is configured for variable effective compression ratio, with variable lift, duration valve train, or both affecting valve opening and closing.

44. The system of any one of claims 36 to 37, wherein the engine comprises a multi-link system configured to rotate a crankshaft, and comprises an actuator motor configured to change an end point of the multi-link system.

45. The system of any one of claims 36 to 37, wherein the engine is a two-stroke engine.

46. The system of any one of claims 36 to 37, wherein the engine is a four-stroke engine.

47. The system of any one of claims 31 to 46, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 2 to about 3.

48. The system of any one of claims 31 to 46, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 0.8 to about 2.5.

49. The system of any one of claims 31 to 46, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at about 1.1 to about 2.5.

50. The system of any one of claims 31 to 46, wherein the controller is configured to maintain a ratio of H ₂ to CO in the syngas at less than about 3.

51. The system of any one of claims 31 to 46, wherein the predetermined temperature and pressure comprises one, more than one or all of: (i) The predetermined partial oxidation temperature is from about 900 ℃ to about 1150 ℃; (ii) The predetermined partial oxidation pressure is from about 1 bar to about 70 bar; (iii) The predetermined synthesis temperature is from about 200 ℃ to about 300 ℃; and (iv) the predetermined resultant pressure is from about 30 bar to about 100 bar.

52. The system of any one of claims 31 to 35, wherein the reformer comprises one or more of a gas turbine engine, a combustion box, an internal combustion engine, an otto cycle reciprocating engine, and a diesel cycle reciprocating engine.

53. The system of any one of claims 31 to 52, wherein the controller is configured to maintain a fuel/air equivalence ratio of about 1.5 to about 2.5.

54. The system of any of claims 31-52, wherein the controller is configured such that a change in the composition of the flare gas does not change the composition of the final product.

55. The system of any of claims 31-52, wherein the controller is configured such that a change in the composition of the flare gas does not change the composition of the final product; and wherein the change in the composition of the flare gas does not require a change in one or more of the predetermined synthesis temperature, the predetermined synthesis pressure, the predetermined reformer temperature, and the predetermined reformer temperature.

56. The system of any one of claims 31 to 52, comprising a water inlet, a steam inlet, or both for introducing water, steam, or both into the reformer.

57. The system of any one of claims 31 to 35, wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following:

f) A compression ratio in the range of about 8:1 to about 17:1;

g) An intake manifold air temperature of ambient to about 300 ℃;

h) Intake manifold air pressure from ambient to about 5 bar; to about 300 ℃;

i) Ignition timing between TDC and 50 degrees before TDC; and

J) An engine speed of about 8000rpm to about 1500 rpm.

58. The system of any one of claims 31 to 35, wherein the reformer comprises a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of:

e) A first partial oxidation combustor;

f) A two-stage combustion process;

g) A gas turbine combustor; and

H) Combustion cycle times of 5 milliseconds to 50 milliseconds.

59. The system of any one of claims 31 to 58, comprising a hydrogen separation unit for providing a recovered hydrogen stream to the system.

60. The system of any one of claims 31 to 58, comprising a hydrogen separation unit for providing a recovered hydrogen stream for mixing with the synthesis gas.

61. The system of any one of claims 31 to 58, comprising a hydrogen separation unit for providing a recovered hydrogen stream for mixing with the synthesis gas; and wherein the control system is configured to control the mixing of the recovered hydrogen with the synthesis gas to provide a predetermined H ₂ to CO ratio.

62. The system of any one of claims 31 to 61, wherein the end product is selected from the group consisting of methanol, ethanol, mixed alcohols, ammonia, dimethyl ether, and F-T liquid.

63. A system for converting flare gas to a final product, the system comprising:

a. A reformer stage and a synthesis stage;

b. the reformer stage includes:

i. an inlet for receiving a flare gas stream;

an air inlet for receiving an air flow;

A gas-absorbing reformer configured to operate under fuel/air rich conditions; wherein the reformer is configured to operate in a partial oxidation combustion window; whereby the reformer is configured to convert a mixture of flare gas and air into synthesis gas;

a line for flowing the synthesis gas to the synthesis stage;

c. the synthesis stage comprises:

i. a line for receiving a synthesis gas stream from the reformer stage;

a synthesis unit configured to receive the synthesis gas and convert the synthesis gas to a final product;

d. A control system configured to operate the reformer stage at a predetermined partial oxidation temperature and a predetermined partial oxidation pressure; and operating the synthesis stage at a predetermined synthesis temperature and a predetermined synthesis pressure.

64. The system of any one of claims 1 to 63, wherein the induction reformer comprises a rich, induction reciprocating engine having a variable compression ratio to produce a syngas mixture having a predetermined H ₂/CO ratio.

65. The system of any of the preceding claims, wherein steam or hydrogen is added to the incoming air or fuel and the amount of addition varies with engine compression ratio to achieve a desired combustion and a desired exhaust gas composition.

66. The system of any of the preceding claims, comprising a fuel conditioning system to remove liquids and contaminants detrimental to downstream components to provide a conditioned fuel source.

67. The system of any of the above claims, comprising a separation assembly associated with the synthesis unit, wherein byproducts are selectively removed in situ from the synthesis unit.

68. The system of any of the above claims, comprising a separation assembly associated with the synthesis unit, wherein byproducts are selectively removed from the synthesis unit by liquid or gas purging.

69. The system of any one of claims 67 to 68, wherein the byproduct is water.

70. The system of any one of claims 67 to 68, wherein the separation assembly comprises at least one of a membrane separation device, an absorption device, an adsorption device, or a distillation device.

71. The system of any of the above claims, comprising a separation assembly associated with the synthesis unit, wherein the end product is selectively removed in situ from the synthesis unit.

72. The system of any of the above claims, comprising a separation assembly associated with the synthesis unit, wherein the end product is selectively removed from the synthesis unit by a liquid or gas purge.

73. The system of any one of claims 71 to 72, wherein the end product is methanol.

74. The system of any one of claims 71 to 72, wherein the separation assembly comprises at least one of a membrane separation device, an absorption device, an adsorption device, or a distillation device.

75. A method of converting flare gas to a final product, the method comprising:

a. Receiving flare gas from a source;

b. Forming a mixture of the flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy;

c. partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition;

d. converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy;

e. Wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃;

And

F. Wherein steps a) through d) produce less than 2.0kg of CO ₂ per 1 kg of flare gas received.

76. A method of converting flare gas to a final product, the method comprising:

a. Receiving flare gas from a source;

b. Forming a mixture of the flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy;

c. partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition;

d. converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy;

e. wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃; and

F. wherein steps a) through d) are net carbanionic, whereby each of these steps provides less than about-20 kgCO e per 1 kg of end product.

77. A method of converting flare gas to a final product, the method comprising:

a. Receiving flare gas from a source;

b. Forming a mixture of the flare gas and an oxygen source, wherein the oxygen source comprises primarily air, thereby defining a fuel/air mixture, wherein the fuel/air mixture defines an initial specific entropy;

c. partially oxidizing the fuel/air mixture at a predetermined reformer temperature; thereby providing a reprocessed gas stream comprising synthesis gas having a synthesis gas composition;

d. converting the reprocessed gas stream in a synthesis unit to provide a first product stream comprising the final product and an off-gas product stream; defining a final specific entropy;

e. Wherein the initial specific entropy differs from the final specific entropy by less than about 1kJ/kg ℃;

f. wherein steps a) through d) produce less than 2.0kg of CO ₂ per 1 kg of flare gas received; and

G. Wherein steps a) through d) are net carbanionic, whereby each of these steps provides less than about-20 kgCO e per 1 kg of end product.

78. A method according to any one of claims 75 to 77, comprising compressing the fuel/air mixture to a predetermined reformer pressure.

79. A method according to any one of claims 75 to 78 comprising providing the fuel/air mixture to a reformer at a predetermined reformer pressure, wherein the partial oxidation is carried out in the reformer at a predetermined reformer temperature.

80. A method according to any one of claims 75 to 79, comprising controlling the pressure and temperature of the reprocessed gas stream to provide a predetermined synthesis temperature and a predetermined synthesis pressure of the reprocessed gas stream.

81. The method of any one of claims 75 to 80, wherein the end product is selected from the group consisting of methanol, ethanol, ammonia, dimethyl ether, and F-T liquid.

82. The method of any of claims 75-81, wherein the final product comprises methanol.

83. The method of claim 82, comprising the further step of removing a substance from the first product stream, the substance comprising hydrogen; thereby providing a second product stream; wherein the second product stream comprises at least about 90% methanol and is therefore at least about 90% pure.

84. The method of claim 82, wherein the second product stream comprises at least 93% methanol and is therefore at least 93% pure.

85. The method of claim 82, wherein the second product stream comprises 90% to 95% methanol and is thus 90% to 95% pure.

86. The method of claim 82, wherein the end product consists essentially of methanol.

87. The method of any one of claims 75 to 86, wherein the partial oxidation occurs in a reformer.

88. The method of any of the above claims 75-87, further comprising using water, steam, or both in the step of partially oxidizing the flare gas.

89. The method of any one of claims 75 to 87, wherein the reformer comprises a suction reformer.

90. The method of any one of the preceding claims 75 to 88, wherein the reformer comprises one or more of a gas turbine engine, a combustion box, an internal combustion engine, an otto cycle reciprocating engine, a diesel cycle reciprocating engine.

91. The method of any of the above claims 75-90, wherein the fuel/air rich mixture has a fuel/air equivalence ratio of from 1.1 to about 4.

92. The method of any of the above claims 75-90, wherein the fuel/air rich mixture has a fuel/air equivalence ratio of about 1.5 to about 3.0.

93. The method of any of the above claims 75-90, wherein the fuel/air rich mixture has a fuel/air equivalence ratio of about 1.5 to about 2.5.

94. The method of any of the above claims 75-93, wherein the ratio of H ₂ to CO in the syngas is about 1.0 to about 2.0.

95. The method of any one of claims 75 to 93, wherein the ratio of H ₂ to CO in the synthesis gas is 0.8 to 2.5.

96. The method of any one of claims 75 to 93, wherein the ratio of H ₂ to CO in the syngas is from about 2 to about 3.

97. The method of any one of claims 75 to 93, wherein the ratio of H ₂ to CO in the synthesis gas is 1.1 to 2.5.

98. The method of any one of claims 75 to 93, wherein the ratio of H ₂ to CO is less than 3.

99. The method of any one of claims 75 to 93, wherein the ratio of H ₂ to CO is less than 2.5.

100. The method of any of the above claims 75 to 99, wherein the partial oxidation of the flare gas is performed at a specific entropy of greater than about 7.1kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere.

101. The method of any of the above claims 75 to 99, wherein the partial oxidation of the flare gas is performed at a specific entropy of greater than about 7.5kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere pressure.

102. The method of any of the above claims 75 to 99, wherein the partial oxidation of the flare gas is performed at a specific entropy of greater than about 8.0kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere pressure.

103. The process of any of the above claims 75 to 99, wherein the partial oxidation of the flare gas is performed at a specific entropy of about 7.1kJ/kg ℃ to about 8.6kJ/kg ℃, wherein the reference state of the specific entropy is based on-273.15 ℃ and 1 atmosphere.

104. The method of any of the above claims 87 to 103, wherein the reformer is a reciprocating engine; and the reciprocating engine has one, more than one or all of the following:

a. A compression ratio in the range of about 8:1 to about 17:1;

b. An intake manifold air temperature of ambient to about 300 ℃;

c. Intake manifold air pressure from ambient to about 5 bar; to about 300 ℃; and

D. ignition timing between TDC and 50 degrees before TDC;

e. an engine speed of about 8000rpm to about 1800 rpm.

105. The method of any of claims 87 to 103, wherein the reformer is selected from the group consisting of a two-stroke reciprocating engine and a four-stroke reciprocating engine.

106. The method of any of the above claims 87 to 103, wherein the reformer is a gas turbine assembly; and the gas turbine assembly has one, more than one, or all of:

a. A first partial oxidation combustor;

b. two-stage combustion;

c. A gas turbine combustor; and

Combustion cycle time of 5 milliseconds to 50 milliseconds.

107. The method of claims 75-106, wherein the initial specific entropy differs from the final specific entropy by less than about 0.5kJ/kg ℃.

108. The method of claims 75-106, wherein the initial specific entropy differs from the final specific entropy by less than 0.3kJ/kg ℃.

109. The method of claims 75-106, wherein the initial specific entropy differs from the final specific entropy by less than 0.2kJ/kg ℃.

110. The method of any of the above claims 75-106, wherein the source of the flare has the composition listed in tables 1 and 2.

111. The method of any of the above claims 75 to 106, wherein the source of the torch has a varying composition, wherein the varying composition is within the range of compositions listed in tables 1 and 2.