Classifications

• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
  • C10G1/02—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by distillation
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
  • C10G1/002—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal in combination with oil conversion- or refining processes
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G35/00—Reforming naphtha
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds

Definitions

• the present disclosure relates in general to systems and methods useful in the production of biocrude from biomass, where biocrude is a liquid fuel like petroleum crude that can be upgraded to the whole distillate range of petroleum derived fuel products.
• biocrude is a liquid fuel like petroleum crude that can be upgraded to the whole distillate range of petroleum derived fuel products.
• the present disclosure relates to systems and methods for production of biocrude using hydrothermal liquefaction (HTL).
• HTL hydrothermal liquefaction
• HTL requires very high pressures and temperatures, about 3,000 psi and 300 °C. These temperatures and pressures are a very challenging operating conditions particularly under continuous processing conditions, typically requiring specialized pumps, depressurizing valves and pressure recovery, heat exchangers that are not commercially available, exotic metallurgy and atypical wall thicknesses.
• heat exchangers that are not commercially available, exotic metallurgy and atypical wall thicknesses.
• there are numerous issues related to excessive wear and tear, safety, redundancy requirements and very high costs In particular, the high thermal energy required to heat feed biomass slurry to the desired temperature must be recovered for economic viability, thereby requiring heat exchangers capable of operating at the target temperatures and pressures which are not commercially available for the relatively high processing rates.
• Systems and methods of using same are described which reduce or overcome many of the faults of previously known HTL systems and methods.
• Systems and methods of the present disclosure comprise converting biomass at high volumetric flow rates into biocrude using HTL while minimizing hydrothermal carbonization.
• the biomass is prepared to generate a biomass slurry for HTL processing.
• a first aspect of the disclosure is a system comprising (or consisting essentially of, or consisting of): a well having a well depth, a top positioned at a surface location, and a bottom portion positioned at a subterranean location, the well comprising a casing and one or more tubing (in certain embodiments, coiled tubing) positioned therein, forming an annulus there between, the casing and the one or more tubing defining a hydrothermal liquefaction (HTL) reaction zone in the bottom portion of the well and a heat transfer and separation zone above the HTL reaction zone; the well further comprising a cable comprising an electric heating element positioned in one or more of the one or more the tubing in the HTL reaction zone and configured to transfer energy endothermically to a biomass slurry flowing downward through at least one of the one or more tubing, and convert at least a portion of the biomass slurry into biocrude oil by HTL, the biomass slurry entering into the tubing at the top of
• a third aspect of this disclosure is a method comprising (or consisting essentially of, or consisting of): flowing a biomass slurry into a top of one or more tubing positioned inside a casing of a well, the well having a well depth, a top positioned at a surface location, and a bottom portion positioned at a subterranean location, the well comprising a casing and one or more tubing positioned therein, forming an annulus there between, the casing and the one or more tubing defining a hydrothermal liquefaction (HTL) reaction zone in the bottom portion of the well and a heat transfer and separation zone above the HTL reaction zone; heating the biomass slurry flowing downward through the HTL reaction zone employing a cable comprising an electric heating element positioned in one or more of the one or more tubing in the HTL reaction zone; converting at least a portion of the biomass slurry into biocrude oil by HTL in the HTL reaction zone, the biomass slurry entering into the tubing at
• a fourth aspect of this disclosure is a method comprising (or consisting essentially of, or consisting of): flowing a biomass slurry into a top of a single tubing positioned inside a casing of a well, the well having a well depth, a top positioned at a surface location, and a bottom portion positioned at a subterranean location, the well comprising a casing and a tubing positioned therein, forming an annulus there between, the casing and the tubing defining a hydrothermal liquefaction (HTL) reaction zone in a first section of the bottom portion, a return fluid plenum in a second section of the bottom portion, the second section located below the first portion, and a heat transfer and separation zone above the HTL reaction zone; heating the biomass slurry flowing downward through the HTL reaction zone employing a cable comprising an electric heating element positioned in the tubing in the HTL reaction zone; converting at least a portion of the biomass slurry into biocrude oil by HTL
• the annual global biomass volume is estimated to be 5 billion tons/yr. that could be converted to potentially generate 12.6 billion bbl. of biocrude.
• systems and methods with a single well reactor having a single inner tubing and surface separation facility could process 46,000 tons of wet biomass annually while generating 45,000 bbl. (7,150 m 3 ) of biocrude.
• preventing 20,000 tons/yr. of CO 2 emissions which is the equivalent of the emissions from 4,200 vehicles. This excludes the use of char sludge which encapsulates the carbon preventing further CO 2 emissions.
• Certain systems and methods of the present disclosure generate greater than 10X more energy than they consume, and in certain embodiments greater than 20X more energy than they consume.
• Certain systems and methods of the present disclosure can use renewable sources of power to operate the process.
• the systems and methods of the present disclosure utilize hydrothermal liquefaction for the conversion of biomass to biocrude.
• the biomass is made into a slurry of approximately 20 percent biomass, 75 percent water and 5 percent inert solids; and pumped into a deep well with an inner and outer tube which could be a non-producing oil and gas well with a typical production casing (outer tube) and production tubing (inner tube).
• Certain embodiments may comprise pumping the biomass slurry at a flow rate of approximately 10 m 3 /hr. into the inner tube at about 100 psi to a depth of about 2,380 m (length of the inner tube) and product fluid returned to the surface in the annulus.
• An electrically heated cable is located at the bottom of the inner tube and operated to preheat the incoming fluid, in certain embodiments up to 300 °C. Preheating comes from the countercurrent flow of hot product fluid in the annulus, the inner and outer tubes essentially forming a tube in tube heat exchanger.
• the hydrostatic pressure may range from about 2,500 to about 3,000 psi where the biomass conversion reactions take place.
• the product fluid comprising biocrude then moves up the annulus along with water and some gases (CO 2 mostly with some CH4).
• CO 2 mostly with some CH4
• heat losses to the environment are minimized through the selection and placement of thermally resistant and high insulating drilling fluids and cement during well construction. High solids in the feed material are prone to settling and plugging the wellbore when circulation is temporarily stopped.
• a non-thermally sensitive inorganic additive is used to create a shear thinning feed biomass slurry.
• heat transfer and reaction kinetics are enhanced through the selection of static mixers, pipe geometry and flow regimes in the inner and outer tube. As the biomass is heated to 300 °C, hydrothermal carbonization of biomass occurs between temperatures ranging from about 180 to about 250 °C which reduces the biocrude yield. In certain embodiments of the present disclosure, carbonization is reduced through pipe geometry design, velocity and residence time control.
• systems of this disclosure may be devoid of heat exchangers employing inert metals, or other expensive equipment.
• systems of the present disclosure may be devoid of any unit or component that would introduce an oxidizing chemical into the biomass slurry.
• FIG. 1 schematically illustrates generic HTL systems and methods for producing biocrude oil, which may then be separated into renewable chemicals, hydrocarbon biofuels for transportation uses, and renewable fuels for heating;
• FIG. 2 is a graphical representation of change of oxygen content of lignocellulose as molecular weight is lowered by processing the lignocellulose into biocrude and the processing the biocrude into fuel;
• FIGS. 3A, 3B, 5, 6, 8, 9, 11, 11A, 11B, 11C, 12, 13A, 13B, 15, 17, 18, 18A, 22, and 23, schematically illustrate various system and method embodiments in accordance with the present disclosure
• FIG. 4 is a schematic representation of a material balance for one system with one feed tube and method embodiment of the present disclosure
• FIGS. 7 and 10 are graphical representation of pressure and temperatures in HTL systems and methods in accordance with the present disclosure, specifically pressure and temperature combinations to avoid hydrothermal carbonization and promote HTL;
• FIGS. 14A and 14B are graphical representation of pressure vs. residence time and temperature vs. residence time, respectively, in HTL systems and methods in accordance with the present disclosure, specifically pressure, temperature, and residence time combinations to avoid hydrothermal carbonization and promote HTL;
• FIG. 16A is a schematic illustration of a mixing collar sleeve producing turbulent flow conditions
• FIG. 16B is a schematic illustration of laminar flow conditions when the mixing collar is not present in well reactors in accordance with the present disclosure
• FIGS. 19, 20, 21A, and 21B are schematic illustrations of electrical heating elements, electrical power supply systems, and how the electrical heating elements may be introduced into the well reactors in certain embodiments of the present disclosure
• FIGS. 24 and 25 illustrate schematically the effect that formation temperature has on system heat loss in embodiments of the present disclosure
• FIG. 26 illustrates graphically, and FIG. 27 schematically illustrates days to reach steady state temperature at certain distances from the wellbore wall in certain embodiments of the present disclosure
• FIG. 29 illustrates graphically heat loss vs. depth at various time intervals in certain embodiments of the present disclosure
• FIGS. 32 and 32 A illustrate schematically the use of insulating cement and insulating drilling fluid in well reactors in certain embodiments of the present disclosure
• FIGS. 33A, 33B, and 33C illustrate typical well construction, HTL well construction using drilling fluid and non-insulating cement (“NIC”), and well construction using drilling fluid, insulating cement (“IC”), and NIC;
• NIC non-insulating cement
• Bioenergy is a renewable energy that uses biomass to produce energy. Biomass can be sewage sludge, manure, municipal solid waste, agriculture, forest residues, energy crops and others. The major concerns of bioenergy are biomass availability, sustainability issues and competition between the alternative uses of biomass (for instance, competition for feed and food).
• waste streams may contribute to an improvement of bioenergy production.
• use of waste for production of energy contributes to a circular economy that, in turn, is a global plan for reduction of waste generation and reduction of the use of resources.
• Moura, T. C. P. “Modelling of Wet Air Oxidation in a Deep Well Reactor for Biomass Treatment” , Master thesis (October 2021), available from A Faculdade De Engenharia Da Universidade Do Porto Em Chemical Engineering (hereafter “Moura”).
• biocrude is similar to petroleum crude and can be upgraded to the whole distillate range of petroleum derived fuel products.
• a discussion of biocrude properties is presented herein.
• At higher temperatures above about 374 °C gasification processes start to dominate and the process is defined as hydrothermal gasification, resulting in the production of a synthetic fuel gas.
• Elliott, et al. “Hydrothermal liquefaction of biomass: Developments from batch to continuous process”. Bioresource Technology 178. 147 - 156 (2015) ISSN 0960-8524, Published by Elsevier Ltd. (hereafter Elliott).
• Hydrothermal liquefaction is a thermochemical process that depolymerizes biomass present in a pretreated wet biomass slurry 5 into liquid fuels 21 in a HTL reactor 6 operating at high temperature and pressure and sufficient time to decompose the solid natural polymeric structure to mostly liquid compounds. It is a flexible conversion process due to the variability of bio-based or waste feedstock 2 that have been successfully tested. Biomass wet waste 3 is pretreated in a pretreater 4.
• An HTL product fluid 7 is routed to a phase separator 8 where the product fluid 7 is separated into a water stream 9 that is separated and recycled to pretreater 4, a biochar and sludge stream 11, and a stream 13 comprising primarily biocrude oil.
• Biocrude stream 13 is further separated into a hydrocarbon light ends stream 15 that may be further processed into renewable chemicals, a middle distillates stream 19, and a hydrocarbon heavy ends stream that may be used as renewable fuels stream 17 for heating purposes.
• Middle distillate stream 19 may be further processed by one or more catalytic processes in one or more process units 10, for example catalytic hydrotreating (where hydrogen is added in stream 23, promoting breakdown of large molecules into smaller molecules), and/or catalytic reforming in a catalytic reforming unit (CRU to enhance cyclic hydrocarbons such as benzene, toluene, and xylenes and hydrogen) to form hydrocarbon biofuels for transportation uses.
• CRU catalytic reforming unit
• the key advantage of why the HTL process is successful is because the feedstock 2 of the HTL process does not have to undergo a separate drying process but undergoes pretreatment 4 to provide the pretreated biomass slurry 5.
• Water 9 in the HTL process serves as a reactant and catalyst in the subcritical region as the properties of the water change in the extreme.
• the dielectric constant of water decreases significantly, as compared to ambient water. For example, the dielectric constant of water changes from about 80 at 20 °C and decreases below 20 at 300 °C.
• the water in the hydrothermal liquefaction process acts as a solvent and a reactant. When water is heated close to its critical temperature in a pressurized system, it begins to behave as a non-polar liquid and dissociates much easier. The non-polar behavior of the liquid helps to solvate the organics in the biomass, and the H 3 O+ and OH- ions aid in the conversion of biomass molecules into more desirable compounds.
• HTL off-gas stream 25 consisting of CO 2 , CH4, CO and H 2 , primarily composed of 92 percent CO 2 and 8 percent C 1 -C5 gases.
• CO 2 and hydrocarbon gases in stream 25 can be separated using well established methods such as amine solution extraction and pressure swing adsorption allowing for the recovery of hydrocarbon gases to supplement fuel consumption in the general process or electricity production.
• HTC hydrothermal carbonization
• Liquid biocrude is the key product of HTL systems and methods of the present disclosure. With an upgrading process, this biocrude can be transformed to the whole distillate range of petroleum-derived equivalent fuel products. When compared to gasification, pyrolysis and HTL have a simpler technical conversion of biomass to a liquid fuel . However, when compared to pyrolysis oils, the lower oxygen content in HTL biocrude makes it less corrosive and provides it with higher heating value. Conventional (fossil fuel-derived) petroleum that has a calorific content of 43-46 MJ/kg compared with 30-36 MJ/kg for HTL bio-crude, and 15-22 MJ/kg for pyrolysis oils.
• HTL processes have been shown to produce bio-oils with energy densities between 35-37 MJ/kg and bio-char with an energy density around 28 MJ/kg which is similar to that of coal.
• the hydrothermal liquefaction of biomass has been previously shown to produce more energy than it consumes (Gollakota, 2017). This means that systems and methods of the present disclosure could be run by burning part of the oil/ char they produce and have a percentage left over. The percentage remaining can even be chemically upgraded to produce transportation fuels.
• the main pathway that produces biocrude in systems and methods of the present disclosure is through the reduction of oxygen and other oxidizing compositions in the biomass feed.
• Oxygen accounts for about 40-60 percent of the dry weight of biomass. This is done in systems and methods of the present disclosure by reducing the number of oxygen molecules bound to the organics and increasing the organic molecules size. The reduction of bound oxygen reduces the solubility of the organic compound by making it less polar and more hydrophobic. This reduction in oxygen increases the energy density of the resulting biocrude.
• biomass can be processed in HTL systems and methods of the present disclosure because of the hydrophilic nature of biomass and the reasonable ease in forming water slurries of biomass particles at pumpable concentrations, typically from about 5 to about 35 percent dry solids.
• lignocellulosic biomass which is lower in moisture content
• recovery and reuse of the water for slurry preparation is a key feature.
• high-moisture biomass like algae, some dewatering is desired prior to processing in order to lessen the processing costs of excessive water.
• Table 2 presents some common feedstock utilized in HTL systems and methods of the present disclosure. Wet feedstocks are particularly suited for the HTL systems and methods of the present disclosure and especially algae biomass.
• the systems and methods of the present disclosure continuously convert biomass at high volumetric flow rates into biocrude using hydrothermal liquefaction while minimizing hydrothermal carbonization.
• Biomass is prepared to generate a biomass slurry for HTL processing.
• HTL requires very high pressures and temperatures, for example from about 2,500 psi to about 3,500 psi and from about 250 °C to about 350 °C, or from about 2,700 psi to about 3,300 psi and from about 275 °C to about 325 °C, or about 3,000 psi and about 300 °C. These temperatures and pressures are very challenging operating conditions particularly under continuous processing conditions.
• systems and methods of the present disclosure utilize a deep well, in certain embodiments deep wells commonly drilled and constructed for oil and gas production. These deep wells can safely and inexpensively generate the high pressures required via hydrostatic pressure by using commonly available metallurgy, dimensions and geometry. The depth of the well determines the pressure. In certain embodiments, as in embodiment 100 illustrated schematically in FIGS.
• the well includes an inner tubing 32 and an outer tubing (casing) 30 where the feed slurry enters inner tubing 32 at the top 44 of the well at the surface 46 and flows to the bottom portion 42 of the well, and product fluid 7 returns to the surface in an annulus 38 formed between inner tubing 32 and casing 30.
• No high-pressure pumping is required as the systems and methods take advantage of the hydraulic U tube effect and hydrostatic pressure simultaneously.
• Biomass slurry 5 is heated at the bottom of the well to the target temperature by a heating element 36 of an electric cable 34 but prior to reaching bottom portion 42 of the well, while product fluid 7 returning in annulus 38 preheats the incoming biomass slurry 5.
• the majority of the heat in product fluid 7 is recovered via the transfer of thermal energy from the hot product fluid 7 flowing upward in annulus 38 to the incoming cold feed biomass slurry 5 in a heat transfer and separation zone 40.
• the temperature of the preheated feed slurry in inner tubing 32 is boosted at bottom portion 42 (HTL reaction zone) of the well under pressure to ensure the biomass slurry fluid remains as a liquid for the hydrothermal liquefaction reactions to occur.
• the deep well will essentially be our reactor.
• the heat source comes from the submersed electrical resistance heater cable (34, 36 powered by a power source 48, which may employ grid power or other power) which is commonly used in oil and gas production to reduce viscosity of heavy oils and waxes, flow assurance and to increase production or other methods of heating inner tubing 32.
• a power source 48 which may employ grid power or other power
• FIG. 3A Also illustrated in FIG. 3A are pressure chart 52, depth chart 54, and a schematic scale model of the well reactor at 1 : 12.222 scale ratio.
• certain systems and methods of the present disclosure may employ: (a) energy recovery; (b) feed slurry preheating; c) boost heating to reach HTL temperature; and d) drilling fluid and/or cements having insulating properties to minimize heat losses. Some or all of these may be satisfied by the design of specific thermal components, as well as configuration design of the processing systems.
• thermal management in systems and embodiments of the present disclosure may include one or more of the following components: (1) a heat exchanger which is designed to ensure the thermal energy recovery with primary functions of feed biomass slurry preheating and product fluid cooling; (2) the electrical heater, which serves to boost the temperature after pre-heating; and (3) the well reactor where the majority of chemical HTL reactions occur.
• An HTL products fluid stream 7 includes 17.1 metric tons/day biochar, 20 metric tons/day biocrude, 163 metric tons/day water, and 9 metric tons/day solids, as depicted in chart 64.
• Recovered water stream 9 is 147 metric tons/day
• an HTL sludge stream 11 includes 17.1 metric tons/day biochar, 25.8 metric tons/day water, and 6.8 metric tons/day solids, as depicted in chart 66.
• recovered biocrude stream 13 is 15.7 metric tons/day.
• While one main objective of the systems and methods of the present disclosure is to minimize solids residue in the form of sludge, some production of sludge is inevitable.
• the solid residue (mostly made up of biochar) produced from hydrothermal liquefaction systems and methods of the present disclosure can be used for soil amendment to earn GHG credits. According to some estimates, about 75 percent of the organic compounds in the biochar would break down into the soil while the remaining carbon would be released into the atmosphere as GHG emissions.
• outer tube 30 (casing) diameter is designed to provide low velocity and laminar flow regime to:
• Mixer collar 154 can also be made of hollow material.
• an upper end of mixer collar sleeve 154 has a flat face to promote the disruption of flow, rather than a sloped face.
• Mixing collar 154 can be secured with a latch or strapping or two halves screwed together.
• mixing collar sleeve 154 covers the top and bottom sections of collar 156 so that mixing collar sleeve 154 can rest on collar 156 to prevent sliding of mixing collar sleeve 154 in normal contraction/expansion and flow of fluids. All materials used for securing should be of similar properties as mixing collar sleeve 156.
• the number of mixing collar sleeves 154 is dependent upon the flow regime and distance where the flow returns from turbulent to laminar flow.
• mixing collars sleeves 154 are positioned apart a distance ranging from about 3 to about 15 m (from about 10 to about 50 feet). If oil field production tubing is used as inner tubing 32, then interconnecting tube collars 156 are typically utilized every 9.15 m (30 ft), therefore in those embodiments each mixing collar sleeve is positioned at each tube collar 156.
• multiple feed biomass slurry inner tubings 32 may be utilized within a single wellbore, each having its own heater cable 36.
• the wellbore geometry should be such that the fluid velocities, residence times and flow regimes remain in the same range as outlined herein. Generally, this would involve a larger diameter outer tubing 30 to accommodate a larger flow through annulus 38.
• the flow to each inner tubing 32 would be controlled to be independent and monitored so as not to have reverse flow. It will be understood that other embodiments are possible than those illustrated in FIGS. 18 and 18A.
• the number of inner tubing 32 and heater cables 34, 36 may be lower or higher than illustrated.
• FIG. 18A illustrates seven inner tubing 32 and seven heater cables 36.
• heating in HTL reaction zone (42, 112) is provided by heater cable 34 placed inside inner tubing 32.
• the downhole power and heating cable 34 consists of two sections: power transmission and heating.
• FIG. 19 illustrates schematically a portion of the power transmission cable, with some parts cut away, including the heating element 34, magnesium oxide insulation 190, and a stainless steel sheath 192.
• the power transmission and heating sections are bonded together in series and wound on a single spool at the surface.
• the coiled power cable 208a & 208b provides the required voltage from the power control cabinet 201 to the coiled heating cable 209.
• the downhole heating cable provides the heating density required for maintaining wellbore temperature. This designed cable will produce heat via resistance and the skin effect principle for safe and effective heating downhole of the feed biomass slurry.
• Insulation Resistance > 300M ⁇ km (Temperature at 20°C, Humidity 80%)
• Heat loss to the formation is greatest at the cold start of the process where the temperature gradient between the fluid 7 in the annulus and the formation 28 is the greatest. As illustrated in FIG 30B, the heat loss to the formation 28 reduces over time as the formation around the wellbore increases in temperature, specifically the delta T associated at that depth which is variable with depth, i.e. heat loss is greater at the bottom of the wellbore vs surface.
• the majority of the heat is transferred to the formation as the starting fluid 5 (feed biomass slurry or a simple water starting fluid) is circulated through the wellbore.
• the starting fluid is circulated in and out of the wellbore until the formation reaches target temperature after which the feed biomass slurry can be fed into the deep well reactor.
• foamed thermal resistant cement may withstand stresses and loads that occur in well construction during the curing, pressure test, completion, production, and injection phases of its life and provide zonal isolation during the life of the well.
• Petty et al. “Life Cycle Modeling of Wellbore Cement Systems Used for Enhanced Geothermal System Development”, Proceedings 28th Workshop on Geothermal Reservoir Engineering Stanford University, Stanford, California, January 27-29, 2003.
• the density of cement is 1.96 kg/L and was reduced to 1.08 kg/L with 20% foam cement, a 45 percent reduction.
• the thermal conductivity of the 20 percent foam cement was reduced by 65 percent.
• Maddi “Smart Foam Cement Characterization for Real Time Monitoring of Ultra-Deepwater Oil Well Cementing Applications” (2016).
• the overall impact of a 65 percent reduction in thermal conductivity of cement on the entire wellbore results in an initial reduction of 4 percent in heat loss based on the example wellbore.
• drilling fluid 98 permeates into formation 28 between cement 90 and formation 28, and some drilling fluid 98 remains behind the most outer casing 92 and formation 28 by design, typically between 1 mm - 50 mm respectively.
• a well can be drilled using air drilling methods in formations where there is no influx of water or hydrocarbon liquids. Compressed air at high flow rates and moderate pressures are used to circulate through the well bore. Air drilling eliminates the use of liquids entirely thereby inherently generating a porous and insulating layer between the outer casing 92 and formation 28 and the cement 90 and formation 28. Mist and foam drilling can also provide similar benefits as they use limited amounts of water.
• drilling fluid 98 behind the casing can be displaced entirely with insulating cement (IC) 272 along with non-insulating cement (NIC) 90 used for securing the casing as illustrated in FIG. 33C.
• IC insulating cement
• NIC non-insulating cement
• embodiment 1100 includes equipment at both surface and subsurface that are fully integrated. The process takes in biomass materials and outputs four products: biocrude, process water, process gas and sludge.
• This module The purpose of this module is to receive, screen, store the feed biomass material as it is received. Feed materials are sampled, homogenized, and adjusted for viscosity and solids content with water. The module also grinds the feed solids for the target particle size. Various wet biomass materials collected from sources are dumped or pumped into the receiving pit 71. Material is typically received in vacuum trucks 70, tankers, sealed roll off bins and other containers. A gantry crane (not illustrated) equipped with a clam shell bucket homogenizes the material into a homogenous mixture/slurry in pit 71.
• the grinding system in embodiment 1100 includes feed prep tank 75, grinder pump 82 having a hardened impeller and pump housing for attrition, classifying vibrating screen 80, and an oversize particle return and feed prep tank 75.
• the biomass slurry is received in the grinding system receiving tank(s) 71 from one or more trucks 70 (or via railroad or other transport mechanism) and pumped to the classifying vibrating screen 73.
• the grinder pump 82 includes a hardened impeller and pump housing designed for attrition of the biomass materials while pumping the biomass slurry to the classifying vibrating screen 73.
• the classifying vibrating screen 73 utilizes 1 mm screens to separate >1 mm for further attrition.
• Module 2 Feed Slurry, Mix and Pump Module
• the feed tanks 304 are equipped with agitators which could include circulating pumps with jets or standard shaft/impeller agitators to ensure solids remain suspended in the slurry. Feed tanks 304 can also receive various chemicals 302 to assist with the process such as corrosion inhibitors, cleaning chemicals such as surfactants, pH adjustment chemicals such as sodium hydroxide, sulfuric acid, chlorine, and the like, heterogeneous and non-heterogeneous catalysts, and thermal resistant rheological additives such as bentonite.
• the biomass slurry feed pump 306A, 306B may be a vertical multistage centrifugal slurry pump capable of pumping up to 10,000 L/hr., 100 cP, 1.5 SG and 7 bar such as a Gol Pump model SBI 10 - 16.
• Biomass slurry 5 from feed tanks 304 is pumped at ⁇ 100 psi pressure and ambient temperature into the feed preheater heat exchanger 310, which may be a plate frame heat exchanger or other design, where feed biomass slurry 5 is heated with return HTL product fluid 7 A (from which light ends have been removed in two-phase separator 308) from annulus 38 of well reactor 100.
• HTL product fluid 7 comprises products from the hydrothermal liquefaction reactions of the biomass, typically biocrude, biochar, water, gasses, and inert materials at temperature less than about 70 °C and less than about 100 psi.
• Module 3 Deep Well Reactor Module
• the purpose of the Deep Well Reactor Module is to take the feed biomass slurry 5 and apply sufficient pressure, temperature and residence time for HTL reactions to occur while minimizing hydrothermal carbonization reactions. After the conversion of the biomass slurry, the HTL product fluid and gas byproducts are returned to the surface for separation and recovery.
• the preheated feed biomass slurry 5 enters the deep well biomass conversion reactor 100 through the inner tubing 32 of the reactor about 2380 m (about 7800 ft.) in length that comprises two zones. As the feed biomass slurry 5 travels to the bottom of inner tubing 32, it gathers heat from HTL product fluid 7 in annulus 38 to about 280 °C to 2160 m, referred to herein as Zone 1, Heat Transfer
• HTL product fluid 7 travels to the surface counter-currently to feed biomass slurry 5.
• Feed biomass slurry 5 is further subjected to heat from the heater cable 36, raising the temperature from about 280 °C to the target of 300 °C, referred to as Zone 2 HTL Reaction (112).
• the residence time of feed biomass slurry 5 in inner tubing 32 in Zone 1 and 2 are about 48 minutes and about 5 minutes, respectively, which times may vary depending on the feed biomass slurry characteristics, well reactor structure, and efficiency of the heater cable.
• the residence time in Zone 1 should preferably be as low as practical, ranging from about 20 to about 60 minutes.
• the residence time in Zone 2 should be such that the fluid temperature is raised to the target temperature in as short as time as possible which ranges from about 2 to about 8 minutes.
• the velocity of feed biomass slurry 5 in inner tubing 32 may range from about 0.6 to about 1.5 m/s, and velocity of HTL product fluid 7 in annulus 38 may range from about 0.10 to about 0.2 m/s.
• Feed biomass slurry 5 exits inner tubing 32 at about 2,380 m and enters return plenum 114 where the flow is thereafter channeled to annulus 38 where HTL product fluid 7 travels to the surface.
• HTL reactions occur in Zone 2 (112), both in inner tubing 32 and in annulus 38 at temperatures ranging from about 280 °C to about 300 °C and pressures ranging from about 180 to about 205 bar.
• the wellbore is heated to ensure that feed biomass slurry 5 will reach the target temperature.
• the temperature of the steel tubing/casing, concrete and adjacent drilling fluid is heated followed by the formation to a certain distance as described previously herein. This is generally referred to as the soak period which has been calculated to be approximately 15 days based on assumptions of well construction and formation characteristics used in the modeling.
• the heat is provided by circulating a heat soak fluid, for example, but not limited to inorganic fluids such as water, steam, nitrogen, air, synthetic air, and organic fluids, such as natural gas, light hydrocarbons, glycol solutions, and the like through inner tubing 32 and heated with the 350 kW heater cable 36.
• the heat soak fluid if not already at temperature (such as when steam is used), is heated to about the same temperature as the feed biomass slurry.
• the heat soak fluid in annulus 38 heats outer steel tubing/casing 92, cement 90 and/or 272, drilling fluid 98, and formation 28.
• water used as the heat soak fluid the same water is returned to inner tubing 32 inlet 44 and recirculated.
• the feed biomass slurry can be initiated at a rate that matches the heat energy available which equals the heat generation from the heater cable less the heat loss to the formation as previously discussed. Heat loss to the formation is continuously decreasing over time and therefore the feed biomass slurry feed rate can be increased accordingly.
• the heat soak period can be accelerated by adding heat at the surface to the water or other heat soak fluid exiting annulus before returning to the inner tubing.
• the heating at the surface can be performed by a traditional water heater, raising the temperature to below boiling point of approximately 90 °C while ensuring that the annulus water temperature does not exceed boiling temperature. This accelerated heat soak configuration is not illustrated in FIGS. 34A and 34B.
• CO 2 and some hydrocarbon gasses are formed in the practice of the systems and methods of the present disclosure, as described earlier. These gasses are in the liquid phase due to the hydrostatic pressure in the well bore, however as the flow of liquids travels to the surface, gaseous products separate from the liquid phase.
• the gas flow pattern is dependent upon volume, density, temperature, pressure, pipe geometry that determines the relative velocities of gas and liquid. The flow pattern starts as a single liquid phase flow transitioning to bubble flow somewhere in the wellbore annulus and eventually reaching annular flow regime as fluid nears the surface while gas velocities increase significantly.
• Module 4 Gas-Liquid-Sludge Separation & Storage Module [0203] The purpose of this module is to separate the gas/liquid/solids phases from Module 3. The phases are further separated and/or treated for maximum recovery of valuable products and to minimize waste. The valuable products are stored with non-biocrude products either recycled internally or sold externally.
• the gas and liquid in annulus 38 exit the wellbore and are routed into one or more two phase separators (308).
• the liquid phase is allowed to settle (via gravity?) under velocity and pumped via transfer pump Pl to preheater heat exchanger 310, and then to oil/water separator 314, while the gas phase from two phase separator 308 is transferred to a knock-out vessel 342.
• the liquid level in two phase separator 308 is determined by regulating BPV 341 which also controls the flow of liquid to the oil/water/sludge separator (OWS), 314.
• OWS 314 can be accomplished with a knock-out vessel transfer pump P2 or the pressure in two- phase separator 308 via a valve (not illustrated in FIG. 41) working in concert with BPV 341.
• OWS 314 separates the incoming fluid into three streams via gravity.
• One stream is a “raw” biocrude stream 7B, essentially floating oil in OWS 314 which is skimmed and transferred via recovered raw biocrude pump P3 to a recovered raw biocrude tank 320 and a polishing step to remove solids and water contaminants via biocrude polishing centrifuge including a disc stack 322 which further separates the recovered raw biocrude into (A) a saleable, in-spec biocrude (13) that is routed to tank 324, routed to sales tanks 326 via storage pump P10, and to offloading to trucks or other transport 330 via biocrude sale pump P9; (B) process water (9) which is routed from polishing centrifuge including a disc stack 322 to recovered water tank 332 for recycling via recovered water pump P7, and (C) sludge (11) which is routed to sludge receiver 334, sludge auger 336, and
• a second stream produced by OWS 314 is an emulsion (9a) - a floating middle layer composed of oil/water and fine solids emulsion which may build up overtime in OWS 314; in certain embodiments this emulsion layer is intermittently processed with an OWS centrifuge or tricanter 318 via an emulsion pump P4, tricanter feed pump P6, and tricanter feed tank 316.
• Tricanter 318 recovers more biocrude 7B, returns separated process water 9 to recovered water tank 332, and routs recovered sludge 11 to sludge receiver 334 for disposal or sale.
• Demulsifier chemicals may also be used in OWS 314 to aid in the separation process.
• a third stream produced by the OWS 314 is sludge (9).
• Sludge is a settled solids layer that contains unreacted biomass solids, carbonized biomass and other inert feed solids residuals and water slurry.
• This sludge is removed from OWS 314 via pump P5 and continuously processed with tricanter 318 or a separate decanter (not shown) for dewatering.
• the dewatered solids 11 are collected in sludge receiver 334 and managed as previously described.
• the separated water from Tricanter or decanter 318 is collected in recovered water tank 332 which is subsequently returned to Module 1, 76A and 76B.
• the sludge consisting mostly of biochar is analyzed and stored to determine value as a soil amendment for further reuse or disposal.
• the gas phase separated in two- phase separator 308 from the raw biocrude stream 7 is processed to remove fine droplets of water and/or biocrude contaminants that are entrained in the gas phase. These contaminants are removed using one or more knock out vessels 342, 346, which in certain embodiments may include coalescing media, along with a heat exchanger (condenser) 344 that chills the gas stream using a chiller 352 and chiller circulation pump P8 to further remove any contaminants in the vapor phase. Any recovered liquid is returned to OWS 314 for recovery.
• a heat exchanger condenser
• the polished gas phase which contains mostly CO 2 but also some non-condensable gasses such as light hydrocarbons (C 1 - C 4 ), and small quantities of H 2 and CO, is processed to separate CO 2 via commonly available methods such as membrane or pressure swing adsorption or amine solution (348).
• the CO 2 free gas phase can then be used as fuel for internal processes as natural gas (NG), used in a natural gas generator 350, or sold as renewable natural gas (RNG).
• NG natural gas
• RNG renewable natural gas
• a rupture disc 354 allows venting to a vent line 356. In certain embodiments several rupture discs of various pressure ratings may be employed, and/or one or more pressure relief valves.
• FIGS. 35A and 35B are schematic illustrations of various phases of flow in the annulus in certain systems and methods of the present disclosure
• FIG. 35C is a graphical representation of the flow regimes illustrated schematically in FIG. 35B.
• Approximately 16 percent (dry ash free wt%) of the feedstock is converted into HTL off-gas comprising CO 2 , CH 4 , CO and H 2 , primarily composed of 92 percent CO 2 and 8 percent C 1 -C 5 gasses.
• HTL off-gas comprising CO 2 , CH 4 , CO and H 2 , primarily composed of 92 percent CO 2 and 8 percent C 1 -C 5 gasses.
• Two-phase flow in vertical pipelines may be categorized into five different flow patterns, as illustrated in FIGS. 35A-C and listed here: Bubble flow, Slug flow, Churn flow, Froth flow and Annular flow. h
• DTS Distributed Temperature Sensing
• Yokogawa yokogawa.com
• Yokogawa is an integrated optical fiber sensing system designed to provide the most accurate distributed temperature measurements over long distances while reducing operating costs and increasing production. Measuring temperature across the entire wellbore can provide greater insight into the temperature profile of the fluid temperature thereby providing greater process control and troubleshooting.
• DTS Distributed temperature sensing systems
• DTS Distributed temperature sensing systems
• the DTS systems can locate the temperature to a spatial resolution of 1 m with accuracy to within ⁇ 1°C at a resolution of 0.01°C. Measurement distances of greater than 30 km can be monitored and some specialized systems can provide even tighter spatial resolutions.
• Systems and methods of the present disclosure advantageously reduce or eliminate high pressure pumping as the pressure is generated using hydrostatic pressure.
• the reacted fluid is produced at high pressure and high temperature that is later cooled using a high pressure heat exchanger and let down to a low pressure of only a few bars.
• the typical approach used in these applications has been to use slurry pressure letdown valves to accomplish this pressure letdown. These valves usually control the level in the upstream pressure vessel, which receives direct effluent from the product reactor and allows low pressure liquid separation.
• slurry block valves upstream and downstream of the pressure letdown valves have been used to isolate the letdown valves for maintenance/repair and by-pass of the process stream.
• Block valves and pressure bleed valves are used throughout the plants to isolate process equipment such as pumps, pressure letdown valves, sampling lines, instrumentation, bypass lines, and the like from the flow medium when these equipment components need repair or replacement. Because of the combination of temperatures to 300°C, pressures to 3000 psig, and the abrasiveness of the solid particles in the biomass slurry, these valves require special considerations in the design, selection of materials, and fabrication.
• HTL is an energy-intensive process that operates at high temperature and pressure. With these high operating conditions, heat and energy recovery during cooling and depressurization of the product flow greatly affects the economic competitiveness of the process. (Ong et al.) Therefore, the pre-heating of the feed biomass slurry with the hot HTL product fluid is critical to the systems and methods of the present disclosure. This is accomplished through the use of heat exchangers, however these heat exchangers are not commercially available. It is possible to custom design such a heat exchanger but it will be very expensive with exotic metallurgy and thickness, and requires a very large footprint.
• the current calculations herein used a standard production tubing made of carbon steel with moderate thermal conductivity but using metals such aluminum, which would normally not be applied in oil and gas production due to the corrosive nature of the produced water/brines, has merit due to the unique aspects of the deep well HTL reactor and feed biomass slurries.
• the feed biomass slurries are generally fresh water based, low chlorides, low oxygen (also no oxidizers are added) and contain minimal dissolved solids and are near neutral pH (or can be made to a neutral pH without impacting the HTL reactions).
• Aluminum and aluminum alloys provides the advantage of light weight, high strength is not required, low cost, can be extruded for unique surface geometries (such as axial fins for increased heat transfer surface) and made in long sections. Corrosion protection is important and can detrimental. For example, cannot touch the steel (carbon or stainless steel) as it will promote galvanic reaction and lead to corrosion which of course is the principle of anodic protection.
• the use of aluminum or aluminum alloys carries some risk that requires further investigation but has potential and plenty benefits.
• NOx nitrogen oxides
• PM particulate matter
• UHC unbumt hydrocarbon
• Oxygen Content - Liquefaction biocrudes have significant oxygen content resulting from the depolymerization of biomass components (i.e., cellulose, hemicellulose and lignin). These oxygenated compounds take the form of organic acids, alcohols, ketones, aldehydes, sugars, furans, phenols, guaiacols, syringols, and other oxygenates. In crude oil refining, oxygen is removed to prevent poisoning of catalysts in the reforming process. Studies correlating oxygen content to fuel properties, engine operation and performance have been done on biodiesel. Lower CO emissions and PM have been observed for relatively highly oxygenated fuels such as biodiesel.
• Nitrogen Content Nitrogen in fuel may interact with degradation products and form solid deposits. Nitrogen content is not regulated by diesel or biodiesel standards, although in crude oil refining, nitrogen content is reduced through hydrotreatment to minimize catalyst deactivation and improve diesel stability. Biocrude from HTL of lignocellulosic materials usually has low levels of nitrogen with a maximum of 2 percent. Higher levels of nitrogen have been reported for biocrudes produced from garbage, wastewater sludge, and algae (up to 10 percent) due to the protein content of the feedstock.
• Sulfur Content The sulfur content of fuel is a regulated quantity as burning sulfur in fuel produces sulfur oxides and sulfate particles that contribute to PM emissions. Moreover, sulfur can cause increased cylinder wear and deposit formation. ASTM D975 and D6751 limits sulfur content in diesel and biodiesel, respectively, to 15 ppm. Lignocellulosic materials and algae have very minimal sulfur content. Biocrude has been produced with only 0.1-1.3 wt % sulfur. Biochar, on the other hand, has a higher sulfur content, which may mean reactions in liquefaction favor sulfur binding into compounds in the solid fraction.
• Chemical Composition - Diesel is mainly composed of alkanes, alkenes and aromatics, while biodiesel is more oxygenated, comprised of fatty acid methyl/ethyl esters.
• HTL biocrude is a complex mixture of oxygenated organic chemicals, aliphatics, sugars, oligomers, nitrogenous aliphatics, and nitrogenous aromatics. Table 10 shows the main chemical groups for biocrude.
• the chemical composition of biocrudes is usually determined through gas chromatography-mass spectrometry (GC-MS).
• GC-MS gas chromatography-mass spectrometry
• NMR nuclear magnetic resonance
• FTICR-MS Fourier transform ion cyclotron resonance-mass spectrometry
• Cetane Number is related to the fuel ignition delay time.
• Dorn et al. determined the relationship between fuel components and CN. Normal alkanes increase cetane number the most, followed by branched alkanes, normal alkenes, branched alkenes, cycloalkanes, and aromatics.
• a high CN signifies good ignition quality, good cold start properties, minimal white smoke in exhaust , and low UHC and CO emissions.
• a low CN is related to a longer ignition delay time, which leads to higher amounts of injected fuel mixed prior to combustion. This then causes high rates of combustion and pressure rise that manifests as diesel knock. This also brings about premixed burning that leads to high combustion temperatures and increased NOx.
• Vapor Pressure - Total vapor pressure of the fuel is dependent on the interactions of components within the mixture. Vapor pressure of a mixture can be estimated through the use of activity coefficients and thermodynamic models. These models demonstrate the dependence of vapor pressure on fuel chemical composition. As a fuel property, vapor pressure affects performance of fuels, especially during cold start conditions. However, a high vapor pressure is a concern due to higher fuel evaporation that contributes to increased hydrocarbon emissions. [0241] From the foregoing detailed description of specific embodiments, it should be apparent that patentable systems, methods, and computer-readable media have been described.

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• 2023
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