LNG Lecture (2) PDF

CHME 361- Petroleum and Gas Technologies Fall 2024 Dr. Saad Ali Al-Sobhi LNG process 8 Oct 2024  Announcement  Guest lecture 14 Oct 2024 2  Term project (Environmental Assessment)...

CHME 361- Petroleum and Gas Technologies Fall 2024 Dr. Saad Ali Al-Sobhi LNG process 8 Oct 2024  Announcement  Guest lecture 14 Oct 2024 2  Term project (Environmental Assessment) Raw Energ y materials *Product Raw Material GTL Extraction Ammonia Methanol Ethylene Preparation Production Emission Product Other discharges and 3 Revisit: Topics to be covered Topics Chapter Section CO Weeks Introduction to chemical processes: anatomy of chemical processes, concepts of material and energy 3 balance, process utilities Petroleum technology: crude oil, its sources, properties and formation, composition and markets. Oil drilling 3 and recovery and economics Refinery operations: type of refineries, unit operations, products and their uses (diesel, gasoline, naphtha etc. 3 Gas technologies: gas sources and formation, different type of gas operations, supply chain, gas technologies such as LNG and the GTL industries. Overview on the 3 LNG technology and unit operations Environmental impacts of the oil and gas industries, Sources of emission in gaseous, liquid. Solid hazardous 2 waste Total 14 weeks  Outline  LNG supply chain  Process description of inlet receiving unit  Different system for acid gases removal  Claus process for sulfur recovery  Dehydration system for water removal  NGL recovery  N2 rejection unit  Liquefaction system 5 6 Overall LNG process block diagram  Introduction  The natural gas we use as consumers is almost entirely methane, although natural gas is associated with a variety of other compounds and gases (e.g., ethane, propane, butane, pentanes, hydrogen sulfide [H2S], carbon dioxide [CO2], helium and nitrogen), as well as oil and water, which must be removed during production prior to liquefaction.  Natural gas entering a liquefaction plant must be pretreated to remove impurities to prevent freezing out in the process equipment, corrosion, and depositions on heat exchanger surfaces, and to control heating values in the final product.  LNG supply chain https://www.youtube.com/watch?v=rjlRTFyennU 9  Liquefied natural gas (LNG)  Liquefied natural gas (LNG) is natural gas in a liquid form that is clear, colorless, odorless, noncorrosive, and nontoxic.  It is made from natural gas and has many applications, including use as a fuel for power generation, industrial and home heating, and as a chemical feedstock.  LNG is formed when natural gas is cooled by a refrigeration process to temperatures of between –159 and –162 °C through a process known as liquefaction.  During this process, the natural gas, which is primarily methane, is cooled below its boiling point, whereby certain concentrations of hydrocarbons, water, carbon dioxide, oxygen, and some sulfur compounds are either reduced or removed. 10  Liquefied natural gas (LNG)  Natural gas is transported by pipeline to its consumers, but when the distance between source and consumption is great (1500 km by sea or 5000 km over land), then liquefaction of the gas to reduce its volume by a factor of 600 becomes economic.  LNG is transported in double-hulled ships specifically designed to handle the low temperature of LNG. These carriers are insulated to limit the amount of LNG that evaporates.  LNG plants produce LNG and condensate (natural gasoline) products, and in some cases LPGs (propane and butane). 11 Gas well components 12 Different natural gas compositions 13  Sales gas specifications  Natural-gas pipeline specifications – The most important specifications are Water content, Hydrogen sulfide content, Gross heating value. – Note that both water and hydrogen sulfide must be removed to very low concentrations. – Heating value is more complex-specifications usually range from 950 to 1200 Btu/scf. 14  LNG product specifications Value Unit Specification *Wobbe Index KWh/Nm3 13.066-16.328 Gross Calorific Value (GCV) KWh/Nm3 11.131-12.647 LNG Density Kg/m3 430-478 Molecular Weight Kg/Kmol 16.52 - 18.88 Methane % mol 85.0 min, 97.0 max i-Butane & n- Butane % mol 4 max i- Pentane & n-Pentane % mol 2 max Nitrogen %mole 1.24 max Hydrogen sulfide (H2S) mg/Nm3 5.0 max Total sulphurmg/Nm3 30.0 max Temperature °C -158 max *Normal Cubic Meter or Nm3 shall mean the quantity of Natural Gas, which at conditions of absolute pressure 1.01325 bar and temperature zero (0) degree Celsius, occupies volume of one (1) cubic meter. The Wobbe Index is defined as WI=CV [divided by] SG[0.5], where CV is the calorific value (higher heating value, HHV) of the fuel and SG is the fuel's specific gravity. Heating value is in units of Btu/ft3 15 Overall LNG process block diagram  (1) Inlet gas receiving unit  The slug catcher captures the largest liquid slugs expected from the upstream operation and then allows them to slowly drain to the downstream processing equipment to prevent overloading the system.  The slug catcher design is either a “vessel type” or a “finger type.”  The slug catcher serves as a three-phase separator where the gas, hydrocarbon liquids (condensate), and aqueous phase are separated.  A condensate stabilization unit is typically designed to produce a condensate with Reid vapor pressure (RVP) specification of 8-12 psia.  Reid Vapor Pressure (RVP) is used to determine the condensate vapor pressure and it must be in the range that doesn't allow the light components to separate as a gas phase in the storage tanks or transport pipelines. The optimum value of Reid Vapor Pressure in winter is usually 12 psia and in the summer is 10 psia  (2) Acid gas removal unit Step two in the LNG processing is cleaning the natural gas at the liquefaction plant. A series of processing steps allows the separation and removal of the various unnecessary compounds from the natural gas prior to liquefaction. The acid gas removal unit is designed to remove the acidic components to meet sales gas, sulfur and CO2 specifications. H2S must be removed to meet the sales gas specification of 4 ppmv, or ¼ grains per 100 scf of gas. In addition, COS, mercaptans, and other organic sulfur species must be removed. Considering today’s stringent emission regulations, acid gas removal unit alone may not be sufficient to meet the requirements. Treated gas from the acid gas removal unit may need to be further treated with additional units, such as molecular sieves or sulfur scavengers.  Gas treating units/Acid gas recovery unit (AGRU)  A number of processes are available to remove H2S and CO2 from natural gas  Some have found wide acceptance in the gas processing industry, whereas others are currently being considered.  There are three commonly used solvent absorption processes for acid gas removal in natural gas processing plants: chemical absorption, physical absorption, and the mixed solvents processes 21 Amine solvent type Amine process Amine process component Absorber column Shell and tube heat exchanger Stripper or desorber Reboiler Reclaimer  Chemical Solvent Processes  Chemical absorption processes, in which the H2S, CO2, and to some extent COS are chemically absorbed  The advantage of a chemical solvent process such as amine is that the solubility of aromatics and heavy hydrocarbons in the aqueous solvent is low and hence lower hydrocarbon losses.  The disadvantage is their high energy consumption, in amine regeneration heat duty and cooling duty.  Common examples of amine processes are aqueous solutions of alkanol amines such as monoethanolamine(MEA), diglycolamine (DGA), diethanolamine (DEA), diisopropanolamine (DIPA), and methyldiethanolamine (MDEA)  With the exception of MDEA, amines are generally not selective and will remove both CO2 and H2S from the gas. Amine can also be formulated by solvent suppliers to increase their selectivity and/or absorption capacity  Typically, the MDEA selectivity toward H2S is highest at low operating pressures such as in the tail gas unit, but its selectivity is significantly reduced at high pressure.  Typical operating parameters for commonly used generic Amines Solvent MEA DGA DEA DIPA MDEA Typical 15-20 45-50 25-30 30-40 35-50 concentration, wt % *Typical lean 0.1-0.15 0.05-0.1 0.05- 0.02- 0.004-0.01 loading, mol/mol 0.07 0.05 *Typical rich 0.3-0.35 0.35-0.4 0.35-0.4 0.3-0.4 0.45-0.55 loading, mol/mol Typical steam 1.0 -1.2 1.1-1.3 0.9-1.1 0.8-1.1 0.9-1.1 use, Ib/gal Heat of reaction 825 850 653 550 475 with CO2, Btu/Ib Heat of reaction 820 674 511 475 455 with H2S, Btu/Ib *Rich Amine Loading (RAL) is determined by measuring the amount of acid gas contained in the amine stream exiting the Amine Contactor. This is typically represented in a mol ratio ((mol of CO2 + mol H2S)/mol amine). *Lean Amine Loading (LAL) is determined by measuring the amount of acid gas contained in the 25  Physical Solvent Processes  Physical absorption processes use a solvent that physically absorbs CO2, H2S, and organic sulfur components (COS, CS2, and mercaptans).  Physical solvents can be applied advantageously when the partial pressure of the acid gas components in the feed gas is high, typically greater than 50 psi.  However, physical solvents are not as aggressive as chemical solvents in deep acid gas removal and may require additional processing steps.  The main advantages of physical solvent processes are that the solvent regeneration can be partially achieved by flashing of the solvent to lower pressures, which significantly reduces the heating requirement for regeneration.  The main disadvantage of the physical solvent unit is the coabsorption of hydrocarbons, which reduces the heating value of the product gas.  Example is Selexol, a physical solvent, unlike amine-based acid gas removal solvents that rely on a chemical reaction with the acid gases. It is dimethyl ether of polyethylene glycol.  Since no chemical reactions are involved, Selexol usually requires less energy than the amine-based processes.  Mixed Solvent Processes  Mixed solvent processes use a mixture of a chemical and a physical solvent.  They are used to treat high acid gas content gases while meeting the deep removal of the chemical solvents.  To some extent, these favorable characteristics make them a good choice for many natural gas treating applications.  The Shell Sulfinol process is one of the proven mixed solvent processes Self test/Class activity 28  Sulfur Recovery and Handling Unit  Gas from the amine regenerator contains concentrated H2S, which cannot be vented for safety reasons or flared due to acid gas pollution  If reinjection wells are available, acid gas can be reinjected into the reservoirs for sequestration  Sulfur recovery system can meet 99.9% sulfur removal target, which is needed to meet today’s emission requirements  There are many sulfur recovery technologies that are available with different levels of performance in terms of operation and results.  The selection of the sulfur technology mainly depends on the amount of H2S, CO2, and other contaminants in the feed gas  Liquid redox technology is suitable for small SRUs (below 20 tons per day)  For the larger units, the Claus sulfur technology is the most common  Sulfur Recovery (Claus  technology) The common method for converting H2S into elemental sulfur in a gas processing plant is the Claus technology-based process  The Claus process is basically a combustion unit and, to support the sulfur conversion reaction, the acid gas must contain sufficient H2S to support the heat of combustion.  Typically, the H2S content in the acid gas must be greater than 40 mol%.  If the feed gas contains insufficient H2S, additional processing steps are required, which may require supplemental preheating, oxygen enrichment, or acid gas enrichment  In a conventional Claus process, the reaction is carried out in two stages.  Sulfur Recovery (Claus technology) The first stage is the thermal section  where air is used to oxidize about one-third of the H2S content in the sour gas to SO2. This reaction is highly exothermic and typically about 60-70% of the H2S in the sour gas is converted to sulfur.  In the thermal stage, the hot gases are cooled to 600-800 °F and the waste heat is used to generate HP steam.  During this process, the S2 sulfur species are converted to other sulfur species, primarily S6 and S8.  The gases are finally cooled, to 340-375 °F, in a sulfur condenser by generating low-pressure steam. The second stage is a catalytic stage.  The residual H2S is converted in usually three stages of reactors where sulfur is converted by reaction of the residual H2S with SO2 at lower temperatures, typically 400-650 °F.  Sulfur recovery efficiencies for a two-stage catalytic process are about 90-96%, and for a three-stage process, the efficiencies can be increased to about 95-98%.  Claus process reaction Thermal stage: partial combustion of H2S (1/3rd) with air or O2 3/2 O2 + 3 H2S ---2 H2S +SO2 +H2O Side reactions at thermal stage due to presence of HC and /or CO2 CO2 +H2S—COS+H2O CO2+2H2S—CS2+2H2O Followed by catalytic stages (1-3 stages) claus reaction at moderate temperature (190-360 °C) 2 H2S +SO2 –3/x Sx +2 H2O Overall claus reaction O2 + 2 H2S ---2/x Sx +2 H2O  Cumulative S Recovery yields Thermal 1st Cat 2nd Cat 3rd Cat Tail gas stage stage stage stage treatme 55-70% 80-90% 85-95% 95-98% nt 99- 99.9% Overall LNG process block diagram  Gas dehydration Unit  Treated gas from the AGRU is fed to the gas dehydration unit to avoid any potential problems resulting from water vapor condensation and accumulation in the pipelines (i.e., plugging and corrosion)  There are several methods of dehydrating natural gas, including absorption, adsorption, and direct cooling of the wet gas.  However, the absorption processes using liquids (i.e., glycol) and the adsorption processes using solid desiccants (i.e., molecular sieves, silica gels) are the most common.  The direct cooling method by expansion or refrigeration, with injection of hydrate inhibitors, is common for less dew point depression in the production of pipeline gas in mild weather regions.  Several other advanced dehydration technologies (i.e., membranes and supersonic processes) offer some potential advantages, particularly for offshore applications due to their compact design.  Gas dehydration Unit  Although many liquids possess the ability to absorb water from gas, the liquid that is most desirable to use for commercial dehydration purposes should possess the following properties: 1. High absorption efficiency 2. Easy and economic regeneration 3. Noncorrosive and nontoxic 4. No operational problems, such as high viscosity when used in high concentrations 5. Minimum absorption of hydrocarbons absorption in the gas and no potential contamination by acid gases.  Glycols are the most widely used absorption liquids as they provide the properties that meet the commercial application criteria.  Gas dehydration Unit  The commonly available glycol properties can be found in manufacturers’ websites.  Their pros and cons can be summarized as follows 1. Monoethylene glycol (MEG): High vapor pressure and seldom used in contactor at ambient temperature due to high losses in the treated gas. Normally, it is used as hydrate inhibitor whereby it can be recovered from gas by separation at below ambient temperatures. It is used in glycol injection exchanger operating at - 20 °F to minimize losses. 2. Diethylene glycol: High vapor pressure leads to high losses in contactor. Low decomposition temperature requires low reconcentrator temperature (315-340 °F) and thus glycol purity is not high enough for most applications. 3. Triethylene glycol (TEG): Relatively low vapor pressure when operating at below 120 °F. The glycol can be reconcentrated at 400 °F for high purity. 4. Tetraethylene glycol: More expensive than TEG but less glycol loss at high gas contact temperatures. Reconcentrate at 400-430 °F.  TEG is the most common liquid desiccant used in natural gas dehydration.  TEG  For a typical TEG dehydration unit. As can be seen, wet natural gas is processed in an inlet filter separator to remove liquid hydrocarbons and free water.  The separator gas is then fed to the bottom chamber of an absorber where residual liquid is further removed. It should be cautioned that hydrocarbon liquids must be removed as any entrainments will result in fouling of the processing equipment and produce carbon emissions.  The separator gas is then contacted counter-currently with TEG, typically in a packed column. 39  Natural gas recovery (NGL) recovery  Recovery of NGL components in gas not only may be required for hydrocarbon dew point control in a natural gas stream (to avoid the unsafe formation of a liquid phase during transport), but also yields a source of revenue.  Regardless of the economic incentive, gas usually must be processed to meet the specification for safe delivery and combustion. Hence, NGL recovery profitability is not the only factor in determining the degree of NGL extraction  The NGL recovery unit can be designed for propane recovery or ethane recovery.  For operating flexibility, the NGL recovery process can be designed for either ethane recovery or ethane rejection when ethane margins are low.  Lean Oil Absorption  The lean oil absorption process was developed in the early 1910s and was used exclusively until the 1970s.  The absorption unit uses a lean oil to absorb the C3+ components, followed by a deethanizer, and a rich oil still to regenerate the rich oil.  Propane and butane products can be produced. A typical refrigerated lean oil absorption process is shown  To allow the unit to operate at low temperatures, the feed gas must be injected with ethylene glycol solution to avoid hydrate formation in the heat exchangers.  Turboexpander NGL recovery  The term “turboexpander” refers to an expander/compressor machine as a single unit.  It consists of two primary components, the radial inflow expansion turbine and a centrifugal compressor integrated as a single assembly.  The expansion turbine is the power unit and the compressor is the driven unit.  In cryogenic NGL recovery processes, the turboexpander achieves two different but complementary functions.  The main function is to generate refrigeration to cool the gas stream. 43 block diagram for liquefied natural gas (LNG)  NGL fractionation  Once NGLs have been removed from the natural gas stream, they must be fractionated into their base components, which can be sold as high-purity products.  Fractionation of the NGLs may take place in the gas plant but may also be performed downstream, usually in a regional NGL fractionation center.  A typical process flow schematic is shown. NGLs are fractionated by heating the mixed NGL stream and processing them through a series of distillation towers.  Fractionation takes advantage of the differing boiling points of the various NGL components. As the NGL stream is heated, the lightest (lowest boiling point) NGL component boils off first and separates.  The overhead vapor is condensed, a portion is used as reflux, and the remaining portion is routed to product storage. The heavier liquid mixture at the bottom of the first tower is routed to the second tower where the process is repeated and a different NGL component is separated 46  Liquefaction and refrigeration  Refrigeration systems are common in the natural gas processing industry and processes related to the petroleum refining, petrochemical, and chemical industries. Several applications for refrigeration include NGL recovery, LPG recovery, hydrocarbon dew point control, reflux condensation for light hydrocarbon fractionators, and LNG plants  Selection of a refrigerant is generally based upon temperature requirements, availability, economics, and previous experience. For example, in a natural gas processing plant, ethane and propane may be at hand, whereas in an olefins plant, ethylene and propylene are readily available  The refrigeration effect can be achieved by using one of these cycles:  Vapor compression-expansion  Absorption  Steam jet (water-vapor compression)  The vapor-compression refrigeration cycle can be represented by the process flow and P-H diagram is shown Vapor compression-expansion  Classification of the liquefaction cycles The liquefaction cycle was classified according to three criteria: the number of cycles, the turbine based cycle, and the use of an MR.  The number of cycles is the number of working fluids used for the precooling, liquefaction, and subcooling of the natural gas. Thus, “three cycles” means that three working fluids are used for precooling, liquefaction, and subcooling; “two cycles” means that two working fluids were used for the same purposes; and “one cycle” means that only one working fluid was used.  The turbine-based cycle is a cycle with an expander. This cycle is preferred for use in peak-shaving plants because of its simplicity and the possibility of quick startup during operation.  The amount of refrigerant that can be expended by the expander, however, is smaller than that by the valve, and the liquefied refrigerant cannot be expanded by the expander. Thus, for large-scale LNG liquefaction, the valve is used instead of the expander.  The use of an MR means that the cycle is operated with an MR instead of a pure refrigerant. The MRC can be classified according to the use of an MR for precooling, liquefaction, or subcooling. 49  Single flow LNG process  The basic single flow LNG process consists of the following:  A plate-fin heat exchanger set in a cold box, where the natural gas is cooled to LNG temperatures by a single MRC  A separation vessel, where the mixed refrigerant (MR) is separated into a liquid fraction. The liquid fraction and a gas fraction provides the cold temperature after expansion in a J-T valve for the natural gas precooling and liquefaction.  A gas reaction that provides the LNG subcooling temperature after condensation and J-T expansion at the bottom of the heat exchanger.  Recompression of the cycle gas streams leaving the heat exchanger in the turbo compressor.  Cooling of the compressed cycle gas against air or water.  Multistage MR process  The multistage MR process is comprised of the following:  A coil-wound heat exchanger (CWHE) where the natural gas is precooled, liquefied, and subcooled against various fractions of a single MRC.  A medium-pressure refrigerant separator, from which the liquid is used to provide the precooling duty after J-T expansion to the lower section of the CWHE  The combined refrigerant cycle stream from the bottom of the CWHE is compressed in a two stage compressor with intercooling and after cooling against air or water  Mixed fluid cascade process  The mixed fluid cascade (MFC) process is highly efficient due to the low shaft power consumption of the three MRC compressors The process is comprised of the following:  Plate-fin heat exchangers for natural gas precooling.  CWHEs for the natural gas liquefaction and LNG subcooling.  Three separate MRCs, each with different compositions, that result in minimum compressor shaft power requirement.  Three cold suction turbo compressors. Up to 12 MTPA LNG can be produced in a single train 53  Main heat exchanger https:// www.youtube.com/ watch?v=KTkOjIH5B18 54  Nitrogen Rejection Unit  The nitrogen content in natural gas varies depending on the gas reservoirs  Nitrogen can be naturally occurring in high concentrations in some gas fields, such as in the South China Sea where 30-50% nitrogen content gas  When nitrogen is present in high concentrations, it should be removed to meet the sales gas heating value specification.  There are several methods for removing nitrogen from natural gas.  Nitrogen removal by cryogenic separation is more efficient than other alternatives.  Membrane separators and molecular sieves can be used for nitrogen rejection, but their processing capacity is relatively limited.  They are suitable for bulk separation and are not economical to meet stringent specifications  There are four generic cryogenic processes for nitrogen removal: single column process, double-column process, preseparation column (or three column) process, and the two-column process. These processes vary in complexity and efficiency  Nitrogen Rejection Unit  If nitrogen is vented, the hydrocarbon content of the nitrogen vent stream must meet the environmental regulation, typically set at 0.5-1 mol%  Process selection for the NRU should be based on operating flexibility, complexity, and sensitivity to feed gas compositions in addition to life cycle costs.  The key parameters for process selection are feed gas nitrogen and CO2 contents, feed pressure, flow rate, methane recovery, and contaminant levels. The more important parameter is the CO2 tolerance of the selected process (Trautmann et al., 2000).  A process that has very little CO2 tolerance may require a costly deep CO2 removal system, such as molecular sieve, whereas a more CO2-tolerant process may only require an amine system.  Single-Column Nitrogen Rejection  The single-column process shown utilizes a single distillation column typically operating at 300-400 psig  operated by a closed-loop methane heat-pump system that provides both the reboiler duty and the condensing duty.  In this process, feed gas is cooled in heat exchanger HE-1 using the overhead nitrogen and bottom reboiler methane as the coolants.  This method, which is applicable for feed gas with nitrogen contents below 30%, can produce HP rejected nitrogen  The drawback is the high power consumption by the heat pump compressor  Two-Column Nitrogen Rejection  The two-column process is similar to the three column process, without the intermediate column.  The process comprises a HP prefractionator and a low-pressure column.  Similar to the three column design, the prefractionator reduces the CO2 content in the feed gas to the low-pressure column and is therefore more CO2 tolerant.  The design of the two-column process is simpler than the three-column process.  If it is used to process a lower-nitrogen- content gas (below 50%), the operating pressure of the low-pressure column can be increased to reduce energy consumption  Three-Column Nitrogen Rejection  The three-column (preseparation column) process, is a variation of the double-column process where the process is made up of the HP column (prefractionator), intermediate- pressure column, and the low-pressure column.  The prefractionator can remove the bulk of the methane and CO2 content as a bottom product, thereby concentrating the nitrogen content in the overhead.  With a lower CO2 content to the cold section, the process is more CO2 tolerant and can operate with a higher CO2 content feed gas with CO2 content up to 1.5 mol%.  The prefractionator column operates at a higher pressure with temperature ranging between -150 °F and -180 °F, which would avoid any CO2 freezing problem.  This was a very important consideration in the design selection since the streams coming from the NGL plants are already dry and treated for CO2.  Additional CO2 removal would add to the capital and operating cost of the project.  In addition, the heavy hydrocarbons in the feed are recovered in the residue stream from the bottoms of the prefractionator column. This increases the hydrocarbon recoveries and revenues from the NRU.  Double-Column Nitrogen Rejection  This process uses two distillation columns operating at different pressures that are thermally linked, where the condenser for the HP column is used to reboil the low pressure column.  The process provides all the refrigeration for the separation through the J-T effect by cascaded pressure letdown of the feed.  The nitrogen is produced at low pressure and vented to the atmosphere.  The process basically fractionates the feed gas stream in the low-pressure column, which operates at the cold portion of the nitrogen rejection unit (NRU), typically at -250 °F to -310 °F, which is prone to CO2 freezing.  The CO2 content in the feed gas must therefore be removed to a very low level to avoid freezing in the tower.  In this process, which is applicable for the feed gas with nitrogen contents above 30%  Summary  Liquefied natural gas (LNG) is natural gas, primarily composed of methane, which has been converted to liquid form for ease of storage and transport.  LNG takes up about 1/600 the volume of natural gas.  The conversion of natural gas to its liquefied form allows for the transport of greater quantities  Liquefaction describes the process of cooling natural gas to -162°C (-259°F) until it forms as a liquid.  LNG must be turned back into a gas for commercial use and this is done at regasification plants. 61 Questions 62