WO2015010201A1

WO2015010201A1 - Low co2 emissions steam and/or hydrogen generation systems and processes for hydrocarbons recovery or upgrading

Info

Publication number: WO2015010201A1
Application number: PCT/CA2014/050688
Authority: WO
Inventors: Experience I. NDUAGU; Ian D. Gates
Original assignee: Uti Limited Partnership
Priority date: 2013-07-23
Filing date: 2014-07-22
Publication date: 2015-01-29
Also published as: CA2955749A1

Abstract

Systems and processes for generating steam and/or hydrogen with reduced carbon dioxide emissions are provided. Prior to steam generation by combustion of fuel, typically methane or natural gas, the fuel is decomposed into a solid carbon material and gaseous hydrogen. The hydrogen is combusted to generate steam plus combustion-product steam, which may be injected into a subterranean formation to recover hydrocarbons. The produced hydrogen may also be used in bitumen upgrading operations. The invention aims to generate less carbon dioxide emissions than conventional processes, by sequestering carbon in solid form from the fuel prior to combustion for steam generation.

Description

LOW C02 EMISSIONS STEAM AND/OR HYDROGEN GENERATION SYSTEMS AND PROCESSES FOR HYDROCARBONS RECOVERY OR

UPGRADING

FIELD OF THE INVENTION

The present invention relates to systems and processes for generating steam and/or hydrogen for use in thermal recovery and/or upgrading of hydrocarbons from subterranean formations. More specifically, the present invention relates to reduced carbon dioxide emissions steam and/or hydrogen generation systems and methods.

BACKGROUND OF THE INVENTION An increasing pressure on oil companies to reduce greenhouse gas (GHG) emissions and water footprint of bitumen extraction and upgrading has led to seeking alternative methods that are both environmentally friendlier and economically competitive with the conventional ways of bitumen production from tar sands (Charpentier, A. D., J. A. Bergerson, et al. (2009). "Understanding the Canadian oil sands industry's greenhouse gas emissions." Environmental Research Letters 4(1): 014005; Levi, M. A. (2009). The Canadian oil sands: energy security vs. climate change, Council on Foreign Relations; Bergerson, J. A. and D. W. Keith (2010). "The truth about dirty oil: Is CCS the answer?" Environmental Science & Technology 44(16): 6010-6015). Thermal hot-water or steam-based oil recovery processes (sometimes also referred to as thermal oil processes or thermal oil recovery) such as Hot Water Flooding, Steam Flooding, Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), or recovery processes that start with hot water and/or steam injection (e.g. in- situ combustion) use large volumes of water in the form of hot water and/or steam, to deliver energy, in the form of heat, underground to mobilize oil in a subterranean formation (also sometimes referred to herein as a "subsurface hydrocarbon reservoir"). "Oil" used herein refers to one or more of oil, heavy oil, and bitumen. Sample schematics of the SAGD, CSS, and Steam Flooding processes are shown in Figures 2, 3 and 4, respectively. The injected water is often produced back to the surface with the mobilized oil and is then processed by water treatment and re-heated into hot water or steam and reinjected into the subterranean formation. The typical injected water-to-oil ratio is equal to three or higher volumes of water (expressed as cold water equivalent, that is, at standard conditions) to one volume oil, i.e. >3 m³ water per m³ oil. Often, in most operations, between about 80 and 90% of the water injected into the reservoir is recovered during water treatment operations. This means that make-up water is required for these processes to replenish the lost water.

The generation of hot water and/or steam is accomplished by combusting fuel, which in most operations, is natural gas or methane. In the present disclosure, the term "fuel" includes natural gas and methane but does not exclude other fuels (e.g. other hydrocarbon fuels such as propane, octane, etc.); the terms "natural gas" and "methane" herein are interchangeable, and refer to natural gas, methane, or a combination thereof. The combustion of methane yields heat which is used to convert water to hot water and/or steam. In addition, this combustion of fuel produces large amounts of carbon dioxide (C0₂) which are typically emitted into the atmosphere. For steam-based recovery processes such as SAGD and CSS, at a steam-to-oil ratio (SOR) equal to about 3 m³/m³ (steam volume expressed as cold water equivalent volume), about 0.6 tonnes of carbon dioxide is emitted per m³ oil produced. As shown in Figure 1, at a SOR equal to about 6 m³/m³, about 1.4 tonnes of carbon dioxide is emitted per m³ oil produced. Thus, these steam-based recovery processes have high carbon intensities and thus, given environmental interests in reducing carbon dioxide emissions from recovery processes, there is a need for processes that generate steam for thermal oil recovery without significant carbon dioxide emissions.

Further, there is a need to reduce or eliminate make-up water requirements. In traditional practice, natural gas is combusted in industrial boilers where water is conveyed in tubes through a combustion zone. The water is heated and, for steam generation, boils within the tubes. For example, most industrial boilers use fire tubes or multiple pass boiler tubes. These forms of boilers keep the water and heat source, that is, the combustion zone, physically separate and thus heat transfer is controlled by heat transfer surfaces, for example, the heat transfer area of the fire tubes. A significant fraction of the heat generated in these types of boilers is lost with the combustion gases which are emitted to the environment. Other direct contact boilers, for example, the method taught in Canadian Patent No. 2,751,186, combine the combustion process and feed- water within a single process unit so that heat transfer is done within the combustion zone and thus there are no heat transfer surfaces. This leads to higher thermal efficiency than a typical drum boiler or one-through steam generator since in direct contact steam generation, no heat is lost with stack gases. However, the product of a direct contact steam generator, if used with oxygen as taught by US Patent Nos. 5,680,764 and 6,170,624, is a mixture of steam and carbon dioxide. Even in direct contact steam generators, despite their increased thermal efficiency with respect to traditional steam generators, carbon dioxide is generated within the process.

Steam-based oil recovery processes use large amounts of water and emit carbon dioxide into the atmosphere. There is potential that the carbon dioxide can be used for enhanced oil or gas recovery, see for example Canadian Patent No. 2,576,896 and Canadian Patent Application No. 2,619,557. In all those cases, the methods of capturing carbon dioxide for use in enhanced hydrocarbon recovery are complicated and capital intensive. However, after injectant (hot water and/or steam and carbon dioxide) breakthrough occurs in the recovery process (breakthrough occurs when the injected materials reach the production well), a significant fraction of the injected carbon dioxide will be produced with the produced oil and will be potentially released into the atmosphere. Thus, the capability for the enhanced oil recovery process to sequester carbon dioxide is limited. Carbon dioxide sequestration in deep saline aquifers is a potential technology for dealing with carbon dioxide emissions but it has not yet been proven to be commercially viable and is prone to many risks especially since the carbon dioxide must be sequestered underground for many thousands to tens of thousands of years. SUMMARY OF THE INVENTION

According to a broad aspect of the present invention, there is provided a steam and/or hydrogen generation system for use with a bitumen recovery or upgrading operation comprising: a decarbonization unit for receiving a first fuel and decomposing the first fuel into carbon black and hydrogen; and a combustor for receiving (i) air; (ii) the hydrogen or a second fuel, which is the same or different from the first fuel; and (iii) water and/or steam, and combusting same to generate heat for heating water to generate steam.

According to another broad aspect of the present invention, there is provided a method for generating steam and/or hydrogen comprising: decarbonizing a first fuel to yield carbon black and hydrogen in a decarbonization process; combusting air with the hydrogen or a second fuel to generate heat, the second fuel being the same as or different from the first fuel; and heating water with the heat generated from the combustion to produce steam.

According to yet another broad aspect of the present invention, there is provided a steam and/or hydrogen generation system for use with a bitumen recovery or upgrading operation comprising: a decarbonization unit for carrying out a decarbonization process that decomposes natural gas into carbon black and hydrogen; and a steam generator having a boiler and at least one tube, wherein combustion of the hydrogen occurs in the boiler and water passes through the at least one tube and is heated from the hydrogen combustion to generate steam.

According to still another aspect of the present invention, there is provided a method for generating steam and/or hydrogen comprising: decarbonizing natural gas to yield carbon black and hydrogen; injecting the hydrogen and air into a combustor; igniting the hydrogen and air; and feeding water through at least one tube passing through the ignited hydrogen and air to generate steam.

Further and other aspects of the invention will become apparent to one skilled in the art when considering the following detailed description of the preferred embodiments provided herein. BRIEF DESCRIPTION OF THE DRAWINGS

Drawings are included for the purpose of illustrating certain aspects of the invention. Such drawings and the description thereof are intended to facilitate understanding and should not be considered limiting of the invention. Drawings are included, in which:

Figure 1 is a graph illustrating the amount of carbon dioxide produced versus the steam-to-oil ratio (100% steam quality generated with efficiency of the steam generator equal to 0.75) from a prior art steam-based recoveiy process operating at 2,100 liPa.

Figure 2a and 2b show schematic side and front cross-sectional views, respectively, of a subterranean formation undergoing a prior art Steam Assisted Gravity Drainage ("SAGD") thermal recovery process.

Figure 3 is a schematic view of a prior art Cyclic Steam Stimulation themial recovery process. Figure 4 is a schematic view of a prior art Steam Flood thermal recovery process.

Figure 5 is a schematic flow diagram of a natural gas ("NG") decarbonization process.

Figure 6 is a schematic flow diagram showing bitumen recovery coupled to NG decarbonization technology and oxy-fired NG combustion, according to one embodiment of the present invention.

Figure 7 is a schematic flow diagram showing a zero emissions bitumen recovery process, according to another embodiment of the present invention.

Figure 8 is a schematic flow diagram showing a process for production of hydrogen by NG decomposition for synthetic oil production from bitumen, according to yet another embodiment of the invention. Figure 9 is a schematic flow diagram showing a process for zero emissions synthetic oil production from bitumen using hydrogen production from NG decarbonization, according to still another embodiment of the invention. Figure 10 is a graph showing energy intensity and C0₂ intensity (C0₂I) of steam generation for bitumen recovery for various processes.

Figure 11 is a graph showing energy intensity and C0₂ intensity (C0₂I) of steam generation for bitumen upgrading for various processes.

Figure 12 is a graph showing average values of steam energy requirements and GHG emissions from steam generation via a prior art process for some SAGD projects in Alberta, Canada. DETAILED DESCRIPTION

The detailed description set forth below in connection with the appended drawings is intended as a description of various embodiments of the present invention and is not intended to represent the only embodiments contemplated by the inventor. The detailed description includes specific details for the purpose of providing a comprehensive understanding of the present invention. However, it will be apparent to those skilled in the art that the present invention may be practiced without these specific details. In this description, the word "zero" means near zero or substantially zero. The word "emissions" refers to carbon dioxide emissions. Further, the word "steam" refers to steam, hot water, or a combination thereof. The words "air" and "oxygen" are interchangeable and each includes (i) pure oxygen and/or (ii) a combination of oxygen and other gases.

In one broad aspect of the present invention, there is provided a process for generating steam by decarbonizing the input fuel to produce carbon black, a solid stable form of carbon, and hydrogen. In a preferred embodiment, the input fuel is natural gas; however, other hydrocarbon fuels may be used. De-carbonizing the fuel into hydrogen, a high energy content fuel, helps reduce downstream carbon dioxide emissions, thereby obviating the requirement for subsequent carbon dioxide sequestration. Water can be generated from hydrogen combustion with air. More specifically, the process uses natural gas decarbonization ("NGD" and sometimes also referred to as "natural gas decomposition") technology which is a process that produces hydrogen via natural gas decarbonization, in the field of bitumen extraction and/or upgrading. The present invention provides a process for low emissions steam generation for steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) applications of bitumen recovery. This process produces hydrogen and carbon black from a known NGD technology (shown for example in Figure 5). In one embodiment, the process used to produce hydrogen and carbon black from natural gas may be either the Thermal Black process or a variant thereof.

The produced hydrogen is then used to generate steam for thermal oil recovery. The present invention may offer an environmentally friendlier alternative to the existing technologies that burn natural gas to generate steam for bitumen recovery. This method presents also an alternative to the conventional steam methane reforming (SMR) process widely used to produce hydrogen for bitumen upgrading (Gaudernack, B. and S. Lynum (1998). "Hydrogen from natural gas without release of C02 to the atmosphere." International journal of hydrogen energy 23(12): 1087-1093).

Another application of the present invention may be in bitumen upgrading. Hydrogen produced from the SMR process may be added to a bitumen upgrader to produce synthetic crude oil (SCO). For example, the SMR process generates about 10 tons C0₂ emitted per ton ¾ produced, while the present invention may result in about 1 ton C0₂ emissions per ton ¾. Therefore, application of the present invention may potentially result in approximately 90% reduction of CO₂ emissions from the bitumen upgrading - hydrotreating - process. C0₂ emissions may be further reduced if a fraction of the produced hydrogen is used to provide at least part of the energy required for the process. With reference to Figure 5, the Thermal Black process involves decomposing natural gas in the absence of oxygen. A reactor is preheated to greater than 1,000 °C, preferably about 1,300 °C, and natural gas is injected into the reactor and is decomposed into carbon and hydrogen. The carbon/hydrogen mixture is cooled with water and the carbon is separated from the hydrogen in large bag filters. Thermal decomposition of methane is moderately endo thermic with reaction chemistiy given by:

CH₄ + Heat→ C + 2H₂ (ΔΗ=75.6 kJ/mol) (1)

The energy requirement per mole of hydrogen produced (37.8 kJ/mol) is considerably less than that for the steam reforming process (63.3 kJ/mol H₂). An energy penalty incurred is typically less than 10% of the heat of methane combustion - equivalent to burning 14% of the hydrogen product.

The present invention comprises using the hydrogen by-product from the decarbonization of NG as fuel to preheat another reactor or for other applications, such as steam generation for bitumen recovery and hydrogen production for hydro treatment of bitumen to produce synthetic crude oil.

The conventional method of producing hydrogen used for upgrading bitumen to synthetic crude oil (SCO) is through steam methane reforming (SMR). The process involves a catalytic conversion of methane and steam to hydrogen and C0₂. About fifty percent of the hydrogen produced comes from steam and the other (about) fifty percent from methane. The reactions of SMR are as follows:

CH₄ + H₂0→ CO + 3H₂ (2) CO + H₂0 <→ C0₂ + H₂ (3) Reaction (2) involves a highly endothermic synthetic gas generation reaction (760- 925°C). To ensure a minimum concentration of CH₄ in the product stream, the process generally employs a steam to carbon ratio of 3 to 5 at a process temperature of 815°C and pressures up to 35 bar. Conversion levels of this reaction are usually below 90%. Water-gas shift reaction (3), an exothermic reaction (200-400°C), following a heat recovery step, reduces the CO content of the product to compositions less than 0.5%. The synthetic gas generation and the gas-shift reaction have energy requirements of 83.7 kJ/mole H₂ and -41.2 kJ/mole H₂, respectively, whereas the overall theoretical energy requirement of SM is 40.75 kJ/mole ¾. The SMR process generates between about 8.7 and 9.8 tons C0₂/ton H₂ produced. The thermal efficiency of SMR can range from 65% to 89%.

The present invention may be used with any hot water or steam-based thermal recovery processes including water flooding, steam flooding, Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), or combined steam-additive processes where the additive can be one or more of non-condensable gas, solvent, or surfactant. The present invention may also be used in other thermal oil recovery applications and for other substances for co-injection, which may further improve thermal oil recovery processes.

According to another broad aspect of the present invention, there is provided a hot water and/or steam generation system having: a NGD process, which may be powered by natural gas or produced hydrogen from the NGD process; and a steam generator having an inlet for hydrogen and water, an oxidant in forms of oxygen or air, a combustion chamber, and an outlet. In the combustion chamber, heat is added directly to the water which converts it to hot water and/or steam.

Further, the resulting steam arising from the water and from the hydrogen combustion reactions may be used as an injectant in a thermal oil process. An additive may be added to the injectant steam. In one embodiment, the additive is one or more of hydrocarbons, propane, butane, pentane, hexane, natural gas condensates, diluent, naphtha. The carbon black produced from the process is a by-product that may be sold for other industrial applications.

In one embodiment, the produced hydrogen or other fuel is combusted in a boiler and water is passed through at least one tube in the boiler and heated therein until it is hot water and/or steam. An oxy-fired combustor and air-fired H₂ combustor described hereinbelow may have a boiler for combusting fuel or hydrogen, and at least one tube for the passage and heating of water therethrough for steam generation. The product water from the combustor and/or combustion chamber is re-cycled as make-up water for hot water and/or steam generation.

For use in thermal oil recovery processes such as SAGD or CSS, the steam resulting from the steam generation process of the present invention is between about 500 and about 15,000 kPa. In CSS operations, the preferred range is between about 8,000 and about 13,000 kPa whereas in SAGD, the preferred range is from about 500 to about 7,000 kPa. The processes described herein may optionally add light hydrocarbons or other substances to the mixture of steam to act as a further solvent in the subterranean formation.

In another embodiment, the steam generation system described herein may be located remotely at well sites, in contrast to the standard practice of building a central plant for steam generation.

In the embodiments described herein, carbon dioxide emissions from fuel combustion may be reduced or even obviated since carbon is extracted from the fuel in the form of carbon black, a marketable product, prior to steam generation. Steam is then generated by combusting the remaining hydrogen extracted from the fuel and, when hydrogen is combusted, the result is steam and heat, without carbon dioxide. Through the use of the present invention, water is created as a by-product of hydrogen combustion. Therefore, the need for make-up water may potentially be reduced or eliminated in the process.

A steam and/or hydrogen generation system is described herein, which comprises a decarbonization unit for receiving a first fuel and decomposing the first fuel into carbon black and hydrogen; and a combustor for receiving (i) air; (ii) the hydrogen or a second fuel, which is the same or different from the first fuel; and (iii) water and/or steam, and combusting same to generate heat for heating water to generate steam.

In another embodiment, a steam and/or hydrogen generation system is provided herein, which comprises a decarbonization unit for carrying out a decarbonization process that decomposes natural gas into carbon black and hydrogen; and a steam generator having a boiler and at least one tube, wherein combustion of the hydrogen occurs in the boiler and water passes through the at least one tube and is heated from the hydrogen combustion to generate steam.

In one embodiment, the steam and/or hydrogen generation system is located remotely at a well site.

Methods for generating steam and/or hydrogen are provided herein. In one embodiment, the method comprises decarbonizing a first fuel to yield carbon black and hydrogen in a decarbonization process; combusting oxygen with the hydrogen or a second fuel to generate heat, the second fuel being the same as or different from the first fuel; and

heating water with the heat generated from the combustion to produce steam. In another embodiment, the method comprises decarbonizing natural gas to yield carbon black and hydrogen; injecting the hydrogen and oxygen into a combustor; igniting the hydrogen and oxygen; and feeding water through at least one tube passing through the ignited hydrogen and oxygen to generate steam. In one embodiment, the produced hydrogen and air are injected into the combustor at a pressure between about 500 and about 15,000 kPa. The steam generated may be used as an injectant in a thermal oil process. In a further embodiment, the method is carried out remotely at a well site. Business-as-usual case of a bitumen recovery plant

Conventional in situ bitumen recoveiy processes use steam generated from NG-fired steam generators. Steam to oil ratio (SOR) is a key unit of measuring efficiency of the bitumen recovery process. SOR measures the volume of steam injected into a bitumen reservoir to mobilize and recover a unit volume of bitumen. For example, considering a business-as-usual (BAU) case of a bitumen recovery plant having an SOR of 3 m³/m³ (wet basis) and producing bitumen at 147,850 bbl/d (about 23,508 m³/d) by burning NG, the BAU bitumen recovery plant uses about 3,605 tons/d NG (15°C and 15 bar) to generate high quality steam (e.g. the steam has a quality of about 0.96 to 1.0 produced at 35 bar) for use in SAGD operations. High quality steam refers to high pressure steam of quality above about 0.95. The NG used in this example is composed of 95 mol.% CH4, 2.5 mol.% C₂¾, 1.6 mol.% N₂, 0.7 mol.% C0₂ and 0.2 mol.% C3H8 and has low heating value (LHV) of 48 kJ/kg.

This BAU process provides 113,347 GJ/d for thermal recovery of bitumen. The process emits 6,380 tons/d C0₂ emissions, equivalent to 43 kg-C0₂/bbl bitumen produced. Assuming 90% of the steam is recovered as water and reused in steam generation, this plant has a water consumption footprint of 7,045 m³/d (6,430 tons/d).

Bitumen recovery coupled to NGD technology

One embodiment of the present invention involves applying the NG decarbonization technology to the BAU bitumen recovery process, which comprises decomposition (or thermal cracking) of NG to produce hydrogen and pure carbon. After separating the hydrogen from the carbon, the hydrogen is combusted in air to produce steam for bitumen recovery. Combustion of hydrogen produces pure water, which may be sufficient to reduce or eliminate the need for make-up water. NG decarbonization is energy intensive and its energy requirement may be supplied by oxy-fired NG combustion (referred to herein as "oxy-fired combustion") or burning a fraction of the hydrogen produced from the NG decarbonization (referred to herein as "hydrogen combustion"). In an oxy-fired combustion method, a mix of steam generated and flue gas stream, which is rich in C0₂, is injected into a hydrocarbon reservoir to recover bitumen and to sequester a portion of the C0₂. In hydrogen combustion, a fraction of the hydrogen product from the NG decarbonzation process is combusted to provide heat for the NG process, whereby only steam is generated in the process. The steam is then pumped underground to mobilize bitumen.

Comparison of BAU case and NGD-added cases Performance of the BAU bitumen recovery process was compared with that of the NGD-added processes. Since steam energy requirements constitute more than 90% of the in situ bitumen recovery processes, the performance of the SAGD process is evaluated by the thermal efficiency of the steam generation system, which is based on a first-law energy balance given by:

Net steam, generation efficiency

The first and second numerator terms represent the mass flow (kg/s) and mass enthalpy (kJ/kg) of steam, respectively whereas the first and second denominator terms represent mass flow (kg/s) and the LHV of NG, respectively. The term E_other is the sum of heat and work requirements related to auxiliary equipment such as compressors, pumps, and oxygen production from air separation unit (ASU): E other ^Compressor ^~Ί^~ ^Pump ¾S£F (5)

Similarly, boiler efficiencies for fuel boilers were calculated from: Wstvam 'Hsteam

fuel- boiler ^~ ,

HNG-boiier and η H2-boiier were used to represent efficiencies of NG and hydrogen boilers, respectively. Similar to Equation (4), the net boiler efficiencies were calculated when applicable (in processes where auxiliaries are included). The energy intensity of bitumen production was calculated as the sum of all the energy input (fuel, heat and power) into the process divided by the volume of bitumen produced. The energy intensities from this study are presented as gigajoule (GJ) energy per m³ bitumen. The quality of energy used for steam generation is factored in by accounting for efficiency losses of generating such energy by applying the 2^nd Law of Thermodynamics:

QNC ⁼ " LH¾G ⁼ ~~ (7) For a unit time (s), QNG is the energy content (GJ) of NG used to generate electric power, Qei (GJ) and η_ει is the power plant efficiency. This implies the primary energy content of NG is used in calculations instead of using the electricity value directly. Using Equation (7) the quality of energy input from electricity was accounted for by considering the energy content of NG used to generate electricity at 0.45 efficiency (assumed as the efficiency for a NG-fired electricity generation plant).

Emissions from the system were assessed by taking inventory of C0₂ emissions generated from energy use and from chemical process conversion. Carbon dioxide emissions intensity (C0₂I) for bitumen production was evaluated by dividing the sum of the C0₂ produced from energy consumption and generated by chemical reactions by the volume of bitumen produced. The capacity of a process to reduce C0₂ emissions was presented in terms of C0₂ reduction potential (CRP), a value computed by dividing the amount of C0₂ reduction a process achieves by the C0₂ emissions from the BAU process expressed as a percentage. Since water is lost in the BAU case but produced in the NGD-added cases, process water footprint was calculated as the water lost or produced divided by the volume of the produced bitumen. The integrated NGD processes described herein were modelled using ASPEN PLUS® software. The modelling results were used to compute the overall material and energy balances, and C0₂ emissions of the integrated processes, which are provided hereinbelow. Bitumen recovery coupled to NGD and oxy-fired combustion

High quality steam can be produced from hydrogen combustion steam generators and by using the heat from oxy-fired combustion flue gases. Air or oxygen may be used for hydrogen combustion. For heat generation, direct contact steam generation may be used.

Figure 6 shows a process 100 for bitumen recovery coupled with NGD teclinology and oxy- fired combustion. In this sample embodiment, natural gas NG-1 is fed to an NGD reactor B3, where the natural gas is decomposed thermally to produce hydrogen and carbon black. The NGD reactor is a stoichiometric reactor (Rstoic), which converts methane, ethane and propane in natural gas to elemental carbon and hydrogen.

The product from the NGD reactor is fed to a cyclone B4 for gas-solid separation (stream 102). The high temperature hydrogen product from the cyclone is cooled in a heat exchanger B7 (stream 104) where its energy supplies the sensible heat for heating the NG-1 prior to entering the reactor B3 (stream 113). Carbon black C_B is separated out from the cyclone and collected (stream 103). The remaining hydrogen product is then sent to a pressure swing adsorption vessel B6 (stream 112), where the hydrogen product is separated from impurities (stream 105).

After purification, the hydrogen product is fed to an air-fired hydrogen combustor B8 (stream 106), wherein it is combusted using air as oxidant to produce steam (stream 107). The combustor B8 may be for example, an equilibrium (REquil) reactor, requiring that reaction stoichiometry be specified. The air, prior to entering the combustor B8 (stream 111), may be compressed by a compressor B5. The reaction of hydrogen and oxygen is specified in the air-fired hydrogen combustor B8. It is also possible to use oxygen as an oxidant in combustor B8 but air was used in this sample embodiment as an illustration.

Water streams H20-1 and H20-2 are preheated via heat exchangers B9 and B20, respectively. After heating, H20-1 and H20-2 are pumped to reservoir injection pressures (e.g. 35 bar) by pumps Bl and B15, respectively (streams 108 and 114), prior to entering combustor B8 (streams 109 and 116) for the production of steam for thermal oil recovery. H20-1 and H20-2 may be from the same or different source.

In this sample embodiment, the heat requirements of the NGD reactor B3 are supplied through oxy-fired combustion. Natural gas NG-2 and oxygen 02 are supplied to an oxy-fired combustor B10. Combustor B10 may be for example, a REquil reactor. The reactions of methane, propane and ethane with oxygen to produce carbon dioxide and water are specified in the oxy-fired combustor. NG-2 may be from the same or different source as NG-1. Energy Q for the NGD reactor B3 is extracted from the flue gas stream of the oxy-fired NG combustor BIO (stream 125).

The flue gas from the combustor BIO goes through a series of heat exchangers Bl l and B16 (streams 117 and 121, respectively) and is then used to produce high quality steam for thermal bitumen recovery. A percentage of the flue gas stream is recycled to the combustor BIO to regulate the combustion flame temperature therein (stream 115). The flue gas stream is thereafter cooled to a temperature below the dew point (stream 119). In one embodiment, H20-2 may pass through heat exchanger B16 (stream 122) before entering combustor B8 (streams 126 and 116).

Optionally, the flue gas from the oxy-fired combustion may be used for thermal enhanced oil recoveiy (TEOR). This may further the process C0₂I and improve thermal oil recovery. For example, the flue gas (stream 119) may be compressed to 35 bar and injected into reservoir.

The steam produced by combustor B8 may then be injected into SAGD well pads B2 for thermal oil recovery (streams 107 and 110). Example 1 below provides an illustration of this embodiment where a bitumen recovery plant having an SOR of 3 m³/m³ (wet basis) and producing bitumen at about 147,850 bbl/d (23,508 m³/d) is considered. This plant generates high quality steam at about 240°C and 35 bar. Example 1

In this example, NG-1 is about 2,844.7 tons/d (about 236,906 m³/d at 15°C, 15 bar) of natural gas and is fed to the NGD reactor B3 where it is decomposed thermally at about 1,010°C to produce about 671.3 tons/d hydrogen and about 2,028.6 tons/d carbon. The hot hydrogen product from the NGD reactor is fed to cyclone B4 to separate out the carbon. The remaining hydrogen is then cooled in heat exchanger B7 where its energy supplies the sensible heat for heating the NG-1 feed to the reactor D3 from 15°C to 1,000°C. The cooled hydrogen goes to pressure swing adsorption vessel B6 for purification. The hydrogen product exiting vessel B6 is combusted with air in combustor B8 to produce steam.

The oxy- fired NG combustor BIO supplies heat to the NGD reactor. In this example, the oxy-fired NG combustor BIO is fed about 2,005.9 tons/d (167,072 Vd at 15°C, 15 bar) NG fuel (NG-2) and about 10,547 tons/d oxygen (02), to produce 11,185 GJ/d of heat for the NGD reactor. The temperature of the flue gas exiting the oxy- fired NG combustor BIO is reduced from 1,196°C to 1,035°C after supplying the heat requirements of the NGD reactor B3. The flue gas stream generates an additional 82,485 GJ/d of steam using heat exchangers Bl l and B16. This steam is combined with the steam generated by the hydrogen combustor B8 and used for bitumen recovery. After steam is generated therefrom, the flue gas stream is cooled to about 140°C, a temperature below the dew point. About eighty percent of the cooled flue gas stream is thereafter recycled back to the combustor B10 to regulate the combustion flame temperature.

^• C0₂ emissions of this process come mostly from oxy-NG combustion and from oxygen production. Commercial vendor data suggest that oxygen production supplied at 95% purity has energy requirement below 220 kWh/ton 0₂. 200 kWh/ton 0₂ is the valued used in the calculations herein but the actual value may be within the upper range.

By assuming an emission factor of a NG-fired power plant to be 450 g C0₂/kWh, the production of oxygen and other auxiliaries contribute ~759 kg C0₂/d and 503 kg C0₂/d, respectively, (equivalent to -55 kg C0₂/m³ bitumen). The emissions from oxy-NG combustion is 4,818 kg C0₂/d, and when combined with emissions of the auxiliaries results in a C0₂I of -260 kg C0₂/ m³ bitumen. This is a C0₂ reduction potential (CRP) equal to 42%-points if flue gases of the oxy-NG combustor are flared. The C0₂I of this process is relatively high considering that a significant amount of carbon emissions were avoided through NG decarbonization. However, it is noted that the composition of the oxy-NG combustion flue gas presents some potential usages. A C0₂-rich flue gas (>70 vol.%) is typical of an oxy-NG combustion. The C0₂-rich flue gas may be injected into underground reservoirs for enhanced bitumen recovery (e.g. above 200°C) or with additional energy input, the flue gas may be processed in a C0₂ removal unit to produce a stream of >95 vol.% C0₂ that is usable for enhanced oil recovery. In this example, the option of using the flue gas for thermal oil recoveiy was assessed. Before the flue gas was injected into the reservoir, the flue gas stream was compressed from 5 to 35 bar. The steam content of the flue gas stream alone is able to produce about 1,330 m³/d bitumen. Assuming that up to 50% of the C0₂ eventually escapes the reservoir formation into the atmosphere, the resulting C0₂I of the process becomes 174 C0₂/ m³ bitumen (a CRP of 61%). In a worst case scenario where 100% of the C0₂ eventually escapes the reservoir formation into the atmosphere, the result is a CRP of 39%, a performance worse than the case where the flue gases are emitted directly into the atmosphere. This is because the compressor work added to pressurize the gas stream to injection pressures yielded negative CPR benefits.

A benefit of this process is that a fraction of the C0₂ that would have been emitted to the atmosphere is fixed in solid form as carbon black. Besides the lower C0₂I and environmental benefits of this process, production of large amounts of marketable carbon black may render this process commercially attractive. In addition to the large amount of carbon black produced, combustion of the hydrogen product generates about 2,720 tons/d of pure water (264 kg/m³ bitumen), which may be sufficient to generate steam to produce about 2,267 m bitumen and more than half of the make-up water needed in the BAU case. Zero emissions NGD for bitumen recovery

Figure 7 illustrates a zero emissions bitumen recovery process 200 in which a fraction of the NGD-produced hydrogen is used to generate heat for NG decomposition. High quality steam is produced and used for thermal oil recovery. For heat generation, direct contact steam generation may be used.

The process is operated autothermally with its heat requirements supplied using a fraction of the hydrogen product from the NGD process while the other fraction is combusted in air to provide energy for high quality steam generation. With reference to Figure 7, natural gas NG is fed to an NGD reactor C3 to produce hydrogen and carbon black C_B. The NGD reactor is for example an RStoic reactor, which converts NG to elemental carbon and hydrogen. The hot product from the NGD reactor is sent to a cyclone C4 (stream 202) where carbon is separated out from hydrogen (stream

203) . The remaining hydrogen product is then cooled in a heat exchanger C7 (stream

204) , where its energy supplies sensible heat for heating the NG before the NG enters reactor C3 (stream 213). The cooled hydrogen is sent to a pressure swing adsorption vessel C6 (stream 212) where it is separated from impurities. The impurities are collected from vessel C6 (stream 205). The purified hydrogen is fed to an air-fired ¾ combustor C5 (stream 206). It is also possible to use oxygen as an oxidant in combustor C5 but ah was used in this sample embodiment as an illustration. Combustor C5 is for example a REquil reactor.

A supply of air is compressed by a compressor C12 and fed into combustor C5 (stream 217) for combustion with the purified hydrogen to produce heat and steam. The reaction of hydrogen and oxygen is specified in the air-fired ¾ combustor. The heat requirements of the NGD reactor are supplied by a fraction of the heat produced from combusting the hydrogen product in combustor C5. Combustion products, which consist mainly of steam, exit the combustor C5 (stream 207) and pass through a heat exchanger, where a portion of the heat extracted Q from the combustion products is supplied to reactor C3 (stream 231). The remaining heat portion is fed to heat exchanger C14 (stream 230) where it is used to heat up a water stream (stream 219) that has been pumped to reservoir injection pressure (e.g. 35 bar) by pump C13, to produce more steam. The steam generated may then be injected into SAGD well pads C2 for thermal oil recoveiy (streams 220 and 209). In one embodiment, a portion of the combustion products, after cooling, is recycled back to combustor C5 to regulate the hydrogen combustion temperature (stream 222). For example, 50% of the combustion products are recycled back to combustor C5. Stream 211 is a pressure safety vent stream which prevents pressure build up in combustor C5. Streams 216 and 221 contain the products of the hydrogen combustion process (which are mostly steam) from combustor C5. In this embodiment, NG is used only as a feed for hydrogen production while the produced hydrogen is the fuel for the NG decarbonization reaction.

Example 2 below provides an illustration of this embodiment where a bitumen recovery plant having an SOR of 3 m³/m³ (wet basis) and producing bitumen at about 147,695 bbl/d (23,483 m³/d) is considered. This plant generates high quality steam at about 240°C and 35 bar.

Example 2

In order to produce an equivalent amount and quality of steam as in Example 1, a larger amount of NG feed is required since a part of the hydrogen is used as fuel for the NG decarbonization process.

Air and hydrogen are fed into combustor C5 to produce high temperature steam and to meet the heat requirements of the NG decomposition process. Modeling results show that about 822.7 tons/d hydrogen is produced from -4,223 tons/d (i.e. 352,725 m³/d at 15°C and 15 bar) NG fed to the NG decomposition reactor C3 at 1,010°C. The hot hydrogen product from the NG decarbonization reactor C3 is cooled in heat exchanger C7 where its energy supplies the sensible heat for heating the NG feed from about 15°C to about 1,000°C.

About 40,000 tons/d air (19 % excess) is compressed to 5 bar by compressor C12 and fed into the combustor C5. NG decomposition reaction heat of about 25,000 GJ/d at about 1,010°C is supplied by using part of the energy generated from hydrogen combustion in combustor C5.

In this example, there is zero C0₂ emissions when the C0₂ content of air used for combustion is discounted. The C0₂ that would have been emitted into the atmosphere is sequestered in solid form as carbon black. In addition, large amounts (e.g. -4,531 tons/d) of valuable carbon black are produced as a by-product. The process produces about 6,082 tons/d pure water with a water footprint of 259 kg/m³ bitumen, which should be enough water to generate steam to produce -2,221 m³ bitumen and more than half of the make-up water needed in the BAU case.

Table 1 and Figure 10 show how some of the process performance parameters such as process energy intensity, process efficiency, CRP and water footprints compare with other process configurations. In Table 1 and Figure 10, "OxyNG + NGD + flaring" means oxy-NG combustion applied to NGD with flue gases flared. "OxyNG + NGD (TEOR -50% C0₂)" means oxy-NG combustion applied to NGD with 50% escape of the flue gases used for TEOR. "OxyNG + NGD (TEOR -100% C0₂)" means oxy-NG combustion applied to NGD with 100% escape of the flue gases used for TEOR. "Zero emissions NGD" means zero emissions NGD process, as described above.

Table 1. Process performance results for steam generation via NGD for bitumen recovery.

C0₂

Mnet ING Inet- reduction Water

Inet-SG Hloss

Concept short name H2Boiler boiler NGboiler potential, footprint

CRP

%- %- %- %- %- kg/m^a

%-points points points points points points bitumen

BAU case N/A 80 72 72 0 0 414

OxyNG + NGD + flaring 94.6 80 73.7 48.7 13.3 42 -116

OxyNG + NGD (TEOR -

78.8 92 85 50 12 61 -264 50% C0₂)

OxyNG + NGD (TEOR -

78.8 92 85 50 12 39 -264 100% C0₂)

Zero emissions NGD 79.7 N/A N/A 36.9 25.1 94 -259

Hydrogen production via NG decarbonizatioii

Figures 8 and 9 each show a process wherein the NGD process is integrated with hydrotreating to produce SCO from bitumen: i) oxy-NG combustion applied to NGD for bitumen upgrading (Figure 8); and ii) zero emissions hydrogen production for bitumen upgrading (Figure 9). Hydrogen produced from NGD is used as an alternative to the hydrogen produced from SMR. This approach may result in significant reductions in C0₂ when compared with the conventional SMR process,

Further emissions reductions may be realized when a fraction of the hydrogen product is used to fuel the NGD reaction. Hydrogen and marketable carbon black are the main products of this process. Clean water is also a product from hydrogen combustion, which is useful for bitumen recovery. Two approaches for generating heat for NGD for these processes are described herein: i) oxy-NG combustion and ii) hydrogen combustion.

Process performance of the SMR method, which is taken to be a BAU hydrogen process, was compared with those of abovementioned processes. The performance of a hydrogen process is computed by the thermal efficiency of the system, based on a first-law energy balance:

The first and second numerator terms represent the mass flow (kg/s) and the LHV of hydrogen, respectively whereas the first and second denominator terms represent mass flow (kg/s) and LHV of NG, respectively.

Similar to Equation (4), the net hydrogen production process efficiency was calculated by: Net hydrogenprocess efficiency = 3—f ^' — ^' (9)

C0₂ emissions of hydrogen production processes described therein were assessed by using the same methods applied in bitumen recovery. C0₂I for hydrogen production was evaluated by dividing the sum of C0₂ produced from energy consumption and generated by chemical reactions by the mass of produced hydrogen. The capacity of the proposed hydrogen processes to reduce C0₂ emissions was also presented in terms of CRP, computed as the amount of C0₂ reduction a process achieves divided by the C0₂ emissions from the BAU hydrogen process. Likewise, process water footprint for hydrogen production was calculated as the water lost or produced divided by the mass of the produced hydrogen.

Oxy-NG combustion applied to NGD for bitumen upgrading

Figure 8 is a schematic flow diagram showing a process 300 wherein NGD technology is integrated with synthetic oil production from bitumen. A bitumen upgrader (not shown) is coupled to the NG decarbonization technology. In this embodiment, oxy-fired NG combustion is used to generate heat for NG decarbonization. High quality steam is produced using the heat from the oxy-NG combustion flue gases and the produced steam is used for thermal oil recovery.

With reference to Figure 8, natural gas NG-1 is fed to an NGD reactor D3 to produce hydrogen and carbon. The NGD reactor D3 is an RStoic reactor, which converts methane, ethane and propane in NG to elemental carbon and hydrogen. The hot hydrogen product from reactor D3 passes through a cyclone D4 (stream 302) where carbon black CB is separated from the product (steam 303). The remaining hydrogen product is sent to a heat exchanger D7 for cooling (stream 304). The energy extracted by heat exchanger D7 supplies the sensible heat for heating NG-1 before NG-1 enters reactor D3 (stream 313). After cooling, the hydrogen product is fed to a pressure swing adsorption vessel D6 (stream 312), where the hydrogen is separated from impurities. The purified hydrogen product may then be used for bitumen upgrading. Natural gas NG-2 and oxygen 02 are supplied to an oxy-fired NG combustor D10, which may be for example a REquil reactor. The reactions of methane, propane and ethane with oxygen to produce C0₂ and water are specified in the oxy-fired NG combustor D10. The combustion of NG in combustor D10 is primarily for providing the reaction heat requirement for the NGD reactor D3. More specifically, the flue gas from combustor D10 are directed to a heat exchanger D14 (stream 317), whereby heat Q is extracted from the flue gas and supplied to NGD reactor D3 (stream 322).

Stream 320 is a pressure safety vent stream which prevents pressure build up in combustor D 10. Water H20-2 is preheated via a heat exchanger D5 (stream 314) and is then pumped by a pump D15 to a heat exchanger D16 (stream 323). The cooled flue gas (stream 321) is fed to heat exchanger D16, and the heat extracted from the flue gas is used to generate steam from the water H20-2 in the heat exchanger D16. The generated steam (stream 326) may then be used for thermal recovery of bitumen (e.g. SAGD well pads D2).

In one embodiment, part of the flue gas exiting from exchanger D16 (stream 318) is recycled back to maintain the combustion temperatures in combustor D10 (stream 315). Optionally, the remaining portion of the flue gas (stream 119) may be used for TEOR, which may further reduce the process C(¾I and improve the thermal oil recovery. The flue gas stream of the oxy-NG combustion process (stream 319) may be compressed (e.g. from 5 to 35 bar) and injected into reservoir.

Example 3 below illustrates the above-described oxy-NG combustion applied to NGD for bitumen upgrading process.

Example 3

In this example, 4,080 ton/d (339,778 m³/d at 15°C, 15 bar) of natural gas NG-1 is fed to the NGD reactor D3 at 1,010°C to produce about 878.8 tons/d hydrogen. The hot hydrogen product from the NGD reactor is fed to cyclone D4 to separate out the carbon. The remaining hydrogen is cooled in heat exchanger D7 where its energy supplies the sensible heat for heating NG-1 from 15°C to 1,000°C. The cooled hydrogen is sent to vessel D6, where the hydrogen is separated from impurities.

The oxy-fired NG combustor D10 was fed about 3,000 ton d (249,837 m³/d at 15°C, 15 bar) NG fuel (NG-2) and—11,464 tons/d oxygen (02) delivered at 15 bar. Energy from the flue gas generated by the oxy-fired NG combustor D10 is sent to the NGD reactor D3, as described above. The flue gas temperature was thereafter reduced from about 1,295°C to about 1,116°C, and the flue gas was used to generate steam in heat exchanger D16 with water from stream H20-2. Results show that for the production of 878.8 tons/d hydrogen, the heat requirement for NGD supplied by the oxy-NG combustion process is about 22,079 GJ/d. C0₂ emissions Of this process come mostly from oxygen production and oxy-NG combustion, resulting in 1,135 tons/d C0₂ and 7,206 tons/d C0₂, respectively.

Alongside the production of hydrogen, 43,700 tons of high quality steam was produced. Accounting for the energy for hydrogen production and steam generation results in emissions of 1.7 kg-C0₂/kg-H₂ (or 6.6 kg-C0₂/GJ steam) produced, if the flue gas stream is flared.

The performance results changes when the flue gas stream is used for TEOR. The steam content of the flue gas stream alone can produce 2,107 m³/d bitumen. Assuming that up to 50% of the injected C0₂ eventually escapes the reservoir formation into the atmosphere, the CRP increases from 83% to 89%. However an energy penalty of 2.5%-points is incurred. In a situation where 100% of the injected C0₂ escapes into the atmosphere, this scenario is unfavorable to almost all the process performance parameters, except for water footprint. This is because the additional energy input for flue gas compression brings resultant negative energy and C0₂ sequestration outcomes.

Zero emissions hydrogen production for bitumen upgrading

Figure 9 is a schematic flow diagram for a process 400 for zero emissions hydrogen production for bitumen upgrading. Bitumen upgrader (not shown) is coupled to the NG decarbonization technology of the process. In this embodiment, a fraction of the produced hydrogen from NGD is used to generate heat for NG decomposition. Besides the carbon byproduct from the NG decarbonization, a potential benefit of this embodiment may be that little or no carbon dioxide is emitted.

With reference to Figure 9, natural gas NG is fed to an NGD reactor E3, which is for example an RStoic reactor, which converts NG to elemental carbon and hydrogen. The heated product from the NGD reactor E3 is sent to a cyclone E4 for gas-solid separation (stream 402), where carbon C_B is separated out from the hydrogen product (stream 403). The remaining hydrogen product is cooled in a heat exchanger E7 (stream 404), where the energy extracted from the product supplies the sensible heat for heating the NG stream prior to it entering the NGD reactor (stream 413). The cooled hydrogen product is fed to a pressure swing adsorption vessel E6 where hydrogen is separated from impurities (stream 412). Impurities exit vessel E6 (stream 405) and purified hydrogen is supplied from vessel E6 (stream 406). A portion of the purified hydrogen is sent to an air- fired H₂ combustor E5 (stream 418). The remaining purified hydrogen may be used for the bitumen upgrading (stream H2).

A supply of air is compressed by compressor E12 and then fed into combustor E5 (stream 417). Combustor E5 may be for example a REquil reactor, wherein the reaction of hydrogen and oxygen is specified. The combustion product from combustor E5 is sent to a heat exchanger E20 where heat is extracted therefrom (stream 407).

Stream 411 is a pressure safety vent stream which prevents pressure build up in combustor E5. A portion of the heat Q extracted is used to for the heat requirements of the NGD reactor (stream 431) while the other portion (in stream 430) is sent to a heat exchanger E 14 for the production of steam.

Water is pumped by a pump El 3 into heat exchanger E14 (stream 419) and is heated by the heat supplied by the combustor E5 to produce steam. The generated steam

(streams 420 and 409) may then be used for thermal recovery of bitumen (e.g. SAGD well pads E2). After passing through heat exchanger E14, part of the combustion product, which is mostly water, is recycled back to combustor E5 (streams 416 and 422) to regulate the combustion temperature and to produce additional high quality steam usable for thermal oil recovery. The remaining part (streams 416 and 421) is combined with stream 420 and used for thermal bitumen recovery in well pads E2.

Example 4 below illustrates this embodiment. Example 4

In this example, 12,648 ton/d (1,053,312 Vd at 15°C, 15 bar) of NG was fed to the NGD reactor E3 at 1,010°C to produce about 3,003 tons/d hydrogen at 1,010°C. The hot product from the NGD reactor is sent to cyclone E4 wherein carbon is separated out from the hydrogen product. The remaining hydrogen product is cooled in heat exchanger E7 where energy is extracted from the hot product to supply the sensible heat for heating NG stream from 15°C to 1,000°C before the NG enters reactor E3. The cooled hydrogen product was purified in vessel E6.

A portion of the purified hydrogen was sent to combustor E5. Air compressed to 5 bar by compressor E12 is also sent to combustor E5, where the air is combusted with the purified hydrogen. Part of the heat generated from the combustion product is used to supply heat to the NGD reactor E3 and the remainder is used to generate steam in heat exchanger E14 (stream 430). Water is pumped into heat exchanger E14 at reservoir injection pressure of 35 bar and is heated by the heat provided by the combustion product. After cooling, about 5% of the products from the combustor was recycled to combustor E5. To meet the heat requirements, of an autothermal process producing 3,003 tons/d H₂, about 50,040 GJ/d heat is required. About 43,000 tons/d air (28% excess air), compressed to 5 bar was fed into the combustor E5. The emission from this process is about 1,042 tons-C0₂/d, which comes from auxiliary equipment (e.g. compressor and pump). Instead of generating C0₂ emissions, the carbon in the NG feed is sequestered as 9,070 tons/d of commercially viable carbon black product. The steam generated in this example should sufficient to thermally recover about 45,629 bbl/d (7,255 m³/d) bitumen.

Details of the process performance parameters are presented in Table 2 and Fig. 10. In Table 2 and Fig. 10, "OxyNG + NGD + flaring" means oxy-NG combustion applied to NGD with flue gases flared. "OxyNG + NGD (TEOR -50% C0₂)" means oxy-NG combustion applied to NGD with 50% escape of the flue gases used for TEOR. "OxyNG + NGD (TEOR -100% C0₂)" means oxy-NG combustion applied to NGD with 100% escape of the flue gases used for TEOR. "Zero emissions NGD" means zero emissions NGD process, as described above.

Table 2. Process performance results for hydrogen production via NGD for bitumen upgrading.

C0₂

Inet ri G Hnet- reduction Water

Π process ^lloss

Concept short name H2Boiler boiler NGboiler potential, footprint

CRP

%- %- %- %-points %-points %-points kg/kg-H₂ points points points

BAU case N/A 80 75-64 65-89 0 0 17.9

OxyNG + NGD +

flaring N/A 80 75 55 9.5-33.2 82.7 0

OxyNG + NGD

(TEOR -50% C0₂) N/A 78 72 52 13.3-37 88.8 -6.6

OxyNG + NGD

(TEOR -100% CO₂) N/A 78 72 52 13.3-37 84.7 -6.6

Zero emissions NGD 83.3 N/A N/A 44 21.3-45 95.7 -3.2

Figure 12 shows the average range of process energy intensity and the C0₂I values of the BAU steam generation process from SAGD project data obtained from publicly available online database of the Alberta Energy Regulator (AER) (AER. In situ process presentations. Alberta Energy Regulator, 2013; available at http://www.aer.ca/data-and-publications/activitv-and-data/in-situ-performance- presentations). The error bars in Figure 12 are associated with the GHG emissions of steam generation. Figure 12 shows that steam-based recovery processes have high recovery energy requirements, and consequently high GHG emissions intensities.

The GHG emissions presented in Fig. 12 are those associated with the processes of steam generation using once-through steam generators having efficiencies of about 0.85. This efficiency is 5% more than that of the BAU case, however, some of the projects operate at steam qualities higher than 0.96. The project data analysis accounted only for the energy of NG used to generate steam for SAGD bitumen recovery and the associated life cycle emissions of natural gas production and combustion. The life cycle emissions of NG production and combustion were estimated using an emission factor of 60.2 kg-C0₂e/GJ (GHGenius Model 4.03. Model background and structure. Natural Resources Canada, 2013). It is noted that, in general, the results obtained from computer modelling of the processes of the present invention fall mostly within the average range of values shown in Figure 12. With reference to Table 1 and Figure 10, the results show that the least performing concept may achieve a CRP of 42%-points whereas the best performing concept may achieve a CRP of 94%-points. The results indicate that the choice of a particular process over another may be a function of at least three major factors: energy penalty, economic costs and C0₂I.

Comparing the conventional SMR (BAU case) and the processes of the present invention, the processes of the present invention appear to be more competitive and may potentially offer huge GHG emissions benefits. For example, the SMR process generates 9.8 tons C0₂/ ton H₂ whereas the processes described herein may potentially emit less than 2 tons-C0₂/ton-H₂, which may result in a CRP of 85-96%- points.

Although the above-mentioned processes are described with respect to natural gas, the processes may be operable with other hydrocarbon fuels, such as propane, octane, etc.

The present invention may provide competitive advantages over existing technology. These advantages may include: a) Reduction in carbon dioxide emissions

The processes of the present invention may offer potentially huge emission reductions. Its application in SAGD or CSS in situ bitumen recovery may reduce the C0₂ emissions from about 43 kg-C0₂ bbl bitumen to about 0 - 17 kg-C0₂/bbl bitumen. This potential reduction in C0₂ emissions may help make achievable a zero emissions bitumen recovery process. Similarly, integration of the present invention with the bitumen upgrading process may reduce C0₂ emissions by about 87%.

The avoided C0₂ emissions are permanently sequestered in a solid form as carbon black, which is also a valuable product. Fixation of carbon emissions in solids is a thermodynamically stable, environmentally benign and permanent form of sequestration, with substantially no risk of leaking and no need for post-sequestration monitoring. The present invention substantially avoids the processes of post- combustion capture of C0₂ from flue gases, C0₂ compression to pipeline pressures and the uncertainties associated with storage of C0₂ in geological formations. b) Hydrogen production

Hydrogen is a product of the processes of the present invention. The conventional SMR process can generate 7 to 11 tons C0₂ emissions per ton H₂ produced while the process described herein may result in about 1 ton C0₂ emissions per ton H₂, Therefore, application of the present invention may result in about an 80-90% reduction of the C0₂ emissions of the bitumen upgrading - hydrotreating - process. However, the C0₂ emissions may potentially be avoided completely if a fraction of the produced hydrogen is used to provide for the process energy requirements. Apart from the potential environmental benefits of the present invention, capital cost reduction prospects are envisaged due to the simplicity of the process within the context of a thermal recovery process. The process described herein involves two unit operations while the SMR has three unit operations. c) Production of water and reduction of process water footprint

The present invention produces about 40-70 kg water for every barrel of bitumen produced. Since water consumption footprint and recycling are major sustainability challenges associated with bitumen recovery, the generation of water may present a promising prospect for the heavy oil industry. d) Economic benefits

Economic benefits from byproducts may offset the costs of additional energy requirements of the processes of the present invention. Carbon black produced from the process described herein is a valuable product with many existing and emerging markets. Great market potential exists in the rubber, plastics, ink and metallurgical industries (Gaudernack and Lynum 1998). The carbon black product may be sold as is or reprocessed to a high-tech commercially viable nano-carbon product. Depending on the carbon quality, carbon black price may vary from hundreds to thousands of dollars. For example, the price of good quality carbon black can be in the range of about $l,000/ton and about $4,000/ton. The total world production of carbon black is over 6 million tons annually (Muradov, N. (2000). Thermocatalytic C02-free production of hydrogen from hydrocarbon fuels. Proceedings of the 2000 Hydrogen Program Review, NREL/CP-570-28890). Thus, economic benefits from the carbon black byproduct may significantly reduce the cost of the producing hydrogen. e) Simple equipment setup

The present invention involves two characteristic unit operations: (i) NG decomposition and (ii) gas/solid separation. Conventional NG-fired steam generation plants and SMR plants cannot achieve a permanent C0₂ sequestration of its C0₂ emissions without adding more unit operations, which consequently leads to additional capital and operating costs.

The previous description of the disclosed embodiments is provided to enable any person skilled in the art to make or use the present invention. Various modifications to those embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the invention. Thus, the present invention is not intended to be limited to the embodiments shown herein, but is to be accorded the full scope consistent with the claims, wherein reference to an element in the singular, such as by use of the article "a" or "an" is not intended to mean "one and only one" unless specifically so stated, but rather "one or more". All structural and functional equivalents to the elements of the various embodiments described throughout the disclosure that are known or later come to be known to those of ordinary skill in the art are intended to be encompassed by the elements of the claims. Moreover, nothing disclosed herein is intended to be dedicated to the public regardless of whether such disclosure is explicitly recited in the claims. For US patent properties, it is noted that no claim element is to be construed under the provisions of 35 USC 112, sixth paragraph, unless the element is expressly recited using the phrase "means for" or "step for".

Claims

1. A steam and/or hydrogen generation system for use with a bitumen recovery or upgrading operation comprising:

a decarbonization unit for receiving a first fuel and decomposing the first fuel into carbon black and hydrogen; and

a combustor for receiving (i) air; (ii) the hydrogen or a second fuel, which is the same or different from the first fuel; and (iii) water and/or steam, and combusting same to generate heat for heating water to generate steam.

2. The system of claim 1 wherein the heat generated further provides energy to the decarbonization unit.

3. The system of claim 1 further comprising a hydrogen combustor for receiving air and the hydrogen, and combusting same to generate steam.

4. The system of claim 1 wherein the first fuel is methane or natural gas or a combination thereof.

5. The system of claim 1 wherem the steam generated is used as an mjectant in a thermal oil process.

6. The system of claim 1 wherein the hydrogen is used for a hydrocarbons upgrading process.

7. The system of claim 1 wherein the system is located remotely at a well site.

8. A method for generating steam and/or hydrogen comprising:

decarbonizing a first fuel to yield carbon black and hydrogen in a decarbonization process;

combusting air with the hydrogen or a second fuel to generate heat, the second fuel being the same as or different from the first fuel; and heating water with the heat generated from the combustion to produce steam.

9. The method of claim 8 further comprising supplying energy to the decarbonization process using a portion of the heat generated from the combustion.

10. The method of claim 8 further comprising injecting air and hydrogen or the second fuel into a combustor at a pressure between about 500 and about 15,000 kPa and using the steam generated as an injectant in a thermal oil recovery process.

11. The method of claim 10 further comprising producing oil and condensed water from the injected steam from the thermal oil recovery process through a production well.

12. The method of claim 10 further comprising adding an additive to the injected steam.

13. The method of claim 12 wherein the additive is one or more of hydrocarbons, propane, butane, pentane, hexane, natural gas condensates, diluent, and naphtha.

14. A steam and/or hydrogen generation system for use with a bitumen recovery or upgrading operation comprising:

a decarbonization unit for canying out a decarbonization process that decomposes natural gas into carbon black and hydrogen; and

a steam generator having a boiler and at least one tube, wherein combustion of the hydrogen occurs in the boiler and water passes through the at least one tube and is heated from the hydrogen combustion to generate steam.

15. The system of claim 14 wherein the steam generated is used as an injectant in a thermal oil process.

16. The system of claim 14 wherein the combustion of the hydrogen also provides energy to the decarbonization unit.

17. The steam generation system of claim 14 wherein the decarbonization unit is powered by natural gas.

18. A method for generating steam and/or hydrogen comprising:

decarbonizing natural gas to yield carbon black and hydrogen;

injecting the hydrogen and air into a combustor;

igniting the hydrogen and air; and

feeding water through at least one tube passing through the ignited hydrogen and air to generate steam.

19. The method of claim 18 further comprising injecting the hydrogen and air into the combustor at a pressure between about 500 and about 15,000 kPa and using the steam generated as an injectant in a thermal oil process.

20. The method of claim 19 further comprising producing oil and condensed water from the injected steam from the thermal recoveiy process through a production well.

21. The method of claim 18 wherein the method is carried out remotely at a well site.

22. The method of claim 19 further comprising adding an additive to the injected steam.

23. The method of claims 22 wherein the additive is one or more of hydrocarbons, propane, butane, pentane, hexane, natural gas condensates, diluent, and naphtha.