Patent Application
20070193303
The current invention is related to hydrocarbon fluid processing plants, methods of designing hydrocarbon fluid processing plants, methods of operating hydrocarbon fluid processing plants, and methods of producing hydrocarbon fluids using hydrocarbon fluid processing plants. More particularly, some embodiments of the invention are related to natural gas liquefaction plants, methods of designing natural gas liquefaction plants, methods of operating natural gas liquefaction plants and methods of producing LNG using natural gas liquefaction plants.
Large volumes of natural gas (i.e., primarily methane) are located in remote areas of the world. This gas has significant value if it can be economically transported to market. Where the gas reserves are located in reasonable proximity to a market and the terrain between the two locations permits, the gas is typically produced and then transported to market through submerged and/or land-based pipelines. However, when gas is produced in locations where laying a pipeline is infeasible or economically prohibitive, other techniques must be used for getting this gas to market.
A commonly used technique for non-pipeline transport of gas involves liquefying the gas at or near the production site and then transporting the liquefied natural gas to market in specially-designed storage tanks aboard transport vessels. The natural gas is cooled and condensed to a liquid state to produce liquefied natural gas (“LNG”). LNG is typically, but not always, transported at substantially atmospheric pressure and at temperatures of about −162° C. (−260° F.), thereby significantly increasing the amount of gas which can be stored in a particular storage tank on a transport vessel. Once an LNG transport vessel reaches its destination, the LNG is typically off-loaded into other storage tanks from which the LNG can then be revaporized as needed and transported as a gas to end users through pipelines or the like. LNG has been an increasingly popular transportation method to supply major energy-consuming nations with natural gas.
Processing plants used to liquefy natural gas are typically built in stages as the supply of feed gas, i.e. natural gas, and the quantity of gas contracted for sale, increase. One traditional method of building an LNG processing plant is to build up a plant site in several sequential increments, or parallel trains. Each stage of construction may consist of a separate, stand-alone train, which, in turn, is comprised of all the individual processing units or steps necessary to liquefy a stream of feed gas into LNG and send it on to storage. Each train may function as an independent production facility. Train size can depend heavily upon the extent of the resource, technology and equipment used within the train, and the available funds for investment in the project development.
A traditional LNG train is typically designed to operate at a selected natural gas feed processing rate and normally are not designed or operated at significantly reduced natural gas feed processing rates. This lack of natural gas feed processing rate flexibility reduces the ability of a traditional LNG train plant to adapt to changing market conditions. This lack of natural gas feed processing rate flexibility results in a narrow range of economic operability for a traditional LNG train plant.
Due to the increase in demand seen in recent years, increased emphasis has been placed on cost and schedule efficiency of new gas liquefaction projects in order to reduce the cost of the delivered gas. Large natural gas liquefaction projects expose the developers to substantial commercial risk due to the large initial capital costs ($5 billion or more) of these projects. Improvements in cost, design, and schedule efficiency can help mitigate the substantial commercial risk associated with large LNG development projects.
One embodiment of the invention includes a hydrocarbon fluid processing plant including a plurality of process unit module types, the plurality of process unit module types including at least a first process unit module type including one or more first process unit modules and a second process unit module type including two or more integrated second process unit modules wherein at least one of the first process unit modules and at least one of the second process unit modules are sized at their respective substantially maximum processing efficiency.
An alternative embodiment of the invention includes a method of designing a hydrocarbon fluid processing plant, including: A) providing the identity of a plurality of process unit module types included in the hydrocarbon fluid processing plant, the plurality of process unit module types including at least a first process unit module type and a second process unit module type; B) determining a first maximum processing efficiency for a first process unit module of the first process unit module type and a second maximum processing efficiency for a second process unit module of the second process unit module type; and C) designing the hydrocarbon fluid processing plant, the hydrocarbon fluid processing plant design including one or more first process unit modules sized to substantially meet the first maximum processing efficiency and one or more second process unit modules sized to substantially meet said second maximum processing efficiency.
An alternative embodiment of the invention includes a method of designing an expanded processing capacity of a hydrocarbon fluid processing plant having an existing plant maximum feed processing capacity, including: A) providing the existing configuration of the hydrocarbon fluid processing plant, the hydrocarbon fluid processing plant including a plurality of process unit module types; B) determining a first process unit module type requiring additional maximum feed processing capacity to increase the existing plant maximum feed processing capacity; C) determining the maximum processing efficiency of a first process unit module of the first process unit module type; and D) designing an expanded hydrocarbon fluid processing plant, the design including the addition of one or more first process unit modules sized to substantially meet the maximum processing efficiency.
An alternative embodiment of the invention includes a method of operating a hydrocarbon fluid processing plant having a plurality of process unit module types, the plurality of process unit module types including at least a first process unit module type comprised of one or more first process unit modules and a second process unit module type comprised of two or more integrated second process unit modules wherein at least one of the first process unit modules and at least one of the second process unit modules are sized at their respective substantially maximum processing efficiency, the method including: A) determining a first plant feed processing rate; B) determining the number of process unit modules of each process unit module type required to meet the first plant feed processing rate; C) commissioning at least the number of each process unit module of each process unit module type required to meet the first plant feed processing rate determined in step (B); and D) producing a hydrocarbon fluid product.
An alternative embodiment of the invention includes a method of producing hydrocarbon fluids using a hydrocarbon fluid processing plant, the hydrocarbon fluid processing plant comprised of a plurality of process unit module types, each of the plurality of process unit module types comprised of one or more process unit modules, the method including: A) providing at least one original process unit module for each process unit module type included in the plurality of process unit module types, one or more of the original process unit modules sized at their respective substantially maximum processing efficiency, thereby providing a first phase hydrocarbon fluid processing plant; B) providing one or more additional process unit module(s) for one or more process unit module type(s) included in the first phase hydrocarbon fluid processing plant, the additional process unit module being integrated with the original process unit module within the process unit module type, thereby providing a second phase hydrocarbon fluid processing plant; and C) producing hydrocarbon fluids from the second phase hydrocarbon fluid processing plant.
An alternative embodiment of the invention includes a method of producing liquefied natural gas, including: A) providing an LNG liquefaction plant comprising a plurality of product sized process unit module types, the LNG liquefaction plant having a first plant maximum feed processing capacity; B) expanding the maximum feed processing capacity of at least one but less than all of the product sized process unit module types to achieve a second plant maximum feed processing capacity that is 10 percent or greater than the first plant maximum feed processing capacity; and C) producing LNG in the LNG liquefaction plant after initiation of the expanding step (B).
An alternative embodiment of the invention includes a method of producing liquefied natural gas using an LNG liquefaction plant, the LNG liquefaction plant including a plurality of process unit module types, each of the plurality of process unit module types comprised of one or more process unit modules, the method including: A) providing at least one original process unit module for each process unit module type included in the plurality of process unit module types, thereby providing a first phase LNG liquefaction plant; B) producing first LNG from the first phase LNG liquefaction plant; C) constructing one or more additional process unit modules for one or more process unit module types included in the first phase LNG liquefaction plant while completing at least a portion of the producing step (B); D) placing the one or more additional process unit modules in service, the additional process unit modules being integrated with the original process unit module within the process unit module type, thereby providing a second phase LNG liquefaction plant; and E) producing second LNG from the second phase LNG liquefaction plant.
An alternative embodiment of the invention includes an LNG liquefaction plant including one or more high construction cost product sized process unit module types and one or more low construction cost product sized process unit module types, at least one of the low construction cost product sized process unit module types having a maximum feed processing capacity that is at least 110 percent of the maximum feed processing capacity of at least one of the high construction cost product sized process unit module types.
An alternative embodiment of the invention includes a method of producing liquefied natural gas including: A) providing an LNG liquefaction plant comprising a plurality of process unit module types, the LNG liquefaction plant having at least a first refrigerant circuit, the first refrigerant circuit including at least one first refrigerant compressor service type, the first refrigerant compressor service type comprised of one or more original first refrigerant compressors in parallel, the LNG liquefaction plant having a plant maximum feed processing capacity; B) expanding the plant maximum feed processing capacity of the LNG liquefaction plant by adding at least one additional first refrigerant compressor to the first refrigerant compressor service type, the additional first refrigerant compressor being integrated with the one or more original first refrigerant compressors within the first refrigerant compressor service type; and C) producing LNG in the LNG liquefaction plant after initiation of the expanding step (B).
An alternative embodiment of the invention includes a method of producing liquefied natural gas using an LNG liquefaction plant, the LNG liquefaction plant including a plurality of process unit module types, each of the plurality of process unit module types comprised of one or more process unit modules, the method comprising: A) providing at least one original process unit module for each process unit module type included in the plurality of process unit module types, thereby providing a first phase LNG liquefaction plant; B) providing at least one second process unit module for each process unit module type included in the plurality of process unit module types, thereby providing a second phase LNG liquefaction plant; C) integrating one or more of the original process unit modules with one or more of the second process unit modules for two or more respective process unit module types; and D) producing LNG from the LNG liquefaction plant after initiation of said integrating step (C).
As used herein and in the claims the phrase “hydrocarbon fluid processing plant” means any processing plant that processes a hydrocarbon fluid feed into a product that is changed in some way from the feed. For example, the feed may be changed in composition, physical state and/or combinations of physical state and composition. One example of a hydrocarbon fluid processing plant is a LNG liquefaction plant.
As used herein and in the claims the phrase “LNG liquefaction plant” means a hydrocarbon fluid processing plant that includes processing a feed stream which comprises gaseous methane into a product stream that includes liquid methane. For example an LNG liquefaction plant may include a cryogenic heat exchanger, refrigerant compressors and/or an expansion step. An LNG liquefaction plant may optionally include other fluid processing steps. Non-limiting examples of optional fluid processing steps include feed purification processing steps (liquids removal, hydrogen sulfide removal, carbon dioxide removal, dehydration), product purification steps (helium removal, nitrogen removal), and non-methane product production steps (deethanizing, depropanizing, sulfur recovery). One example of an LNG liquefaction plant includes, for example, a plant that converts a gaseous feed stream containing methane, ethane, carbon dioxide, hydrogen sulfide and other species to liquefied natural gas which contains methane and reduced amounts of some other non-methane species as compared to the feed stream.
As used herein and in the claims the phrase “equipment types” means any type of processing equipment used in any type of process unit module. Non-limiting examples of equipment types include compressors, heat exchangers, distillation columns, flash drums, reactors, pumps, expanders, gas turbines, motors, fired heaters, liquid/gas contactors, liquid/gas separation drums and other processing equipment used in hydrocarbon fluid processing plants.
As used herein and in the claims the phrase “process unit module” means a single grouping of one or more equipment types that, when taken together, complete a specific process function in a hydrocarbon fluid processing plant or support the completion of that function in a hydrocarbon fluid processing plant. For example, such functions include steps which change the temperature, pressure, composition, physical state and/or combinations of temperature, pressure, physical state and composition of a material. Additionally, process units which support these functions include, for example, process units that provide electricity, steam, and/or cooling water to process units which complete a processing step. Non-limiting examples of process unit modules include utility units, gas preheat units, slug catcher units, offgas compressor units, condensate stabilizer units, acid gas removal contactor units, acid gas removal regenerator units, sulfur recovery units, dehydration units, deethanizer units, depropanizer units, fractionation units, pre-cooling heat exchanger units, cryogenic heat exchanger units, refrigerant compressor units, nitrogen rejection units, cogeneration units, liquefaction units, helium recovery units, compression units, refrigerant preparation units, and combinations thereof.
As used herein and in the claims the phrase “process unit module type” means the total amount of a particular type of process unit module in a hydrocarbon fluid processing plant. Process unit module types are made up of one or more process unit modules. For example, a particular process unit module type may be made up of multiple process unit modules in parallel, each process unit module having the capacity to perform the same processing step.
As used herein and in the claims the phrase “maximum feed processing capacity” means the maximum processing capacity of a particular process unit module type included in a hydrocarbon fluid processing plant on a hydrocarbon fluid processing plant feed basis. Maximum feed processing capacity represents the amount of feed to a hydrocarbon fluid processing plant, which may be different from the amount of feed to the particular process unit module type, that can be processed by a hydrocarbon fluid processing plant having a particular process unit module type capacity. For example, if a hydrocarbon fluid processing plant has three process unit module types, A, B and C; if process unit module type A is running at full capacity while the hydrocarbon fluid processing plant is running 100 units of feed, then the maximum feed processing capacity of process unit module type A is 100 units. This is true even if process unit module type A is actually processing 150 units of an intermediate stream, 50 units of an intermediate stream or zero units of an intermediate stream. Further, if process unit module type B is not running at full capacity while the hydrocarbon fluid processing plant is running 100 units of feed, and process unit module type B is 10 percent unloaded on a hydrocarbon fluid processing plant feed basis, meaning that process unit module type B could run at 10 percent greater capacity, then the maximum feed processing capacity of process unit module type B could be stated as 110 units.
As used herein and in the claims the phrase “plant maximum feed processing capacity” means the maximum feed processing capacity of the entire hydrocarbon fluid processing plant.
As used herein and in the claims the phrase “plant minimum feed processing capacity” means the minimum feed processing capacity of the entire hydrocarbon fluid processing plant that can be run in a stable operating mode. A stable operating mode is one in which the control system effectively controls the relevant process variables and the equipment types operate at substantially their design effectiveness. For example, in a stable operating mode distillation columns will achieve substantially the desired degree of separation and compressors will be able to develop substantially the required head without entering surge mode.
As used herein and in the claims the phrase “construction cost” means the total cost for an item, for example a process unit module or a process unit module type, at a location such that the module is ready to be placed into service. Construction costs include fabrication costs, installation costs, equipment costs, procurement costs, licensing costs, training costs, commissioning costs, etc.
As used herein and in the claims the phrase “construction cost per unit of maximum feed processing capacity” means the “construction cost” divided by the “maximum feed processing capacity” for an item, for example a process unit module or a process unit module type.
As used herein and in the claims, the phrase “maximum processing efficiency” means the process unit module capacity size for a process unit module type that minimizes its cost per unit of process unit module capacity, where the cost can be selected from the total process module construction cost, the total process unit module operating cost, the total process unit module lifecycle cost, or combinations thereof.
As used herein and in the claims the phrase “life cycle cost” means a combined measure of the construction cost, and operating cost of an equipment type or process unit module. For example, the life cycle cost can be expressed in present value currency, where the construction cost value is expressed substantially in terms of present value currency, and the present value equivalent of the operating cost can be computed by adjusting the future expenditure to a present value through accounting for the time value of money in methods known to those skilled in the art.
As used herein and in the claims the term “integrated” used with respect to process unit module types means that the process unit module type is composed of a plurality of process unit modules in parallel with each process unit module providing a portion of the process unit module type maximum feed processing capacity and the process unit module type being configured such that each process unit module is 1) able to process any portion of the hydrocarbon fluid processing plant feed, any portion of the hydrocarbon fluid processing plant product or any portion of a particular intermediate stream of the hydrocarbon fluid processing plant and/or 2) is able to complete any particular processing step in the hydrocarbon fluid processing plant, and/or 3) is able to complete any portion of a particular support service for a process unit module type, a plurality of process unit modules or a plurality of equipment types in the hydrocarbon fluid processing plant, in any of 1, 2 and 3 above without regard to the source of the respective feed, product, intermediate stream, processing step, process unit module type, plurality of process unit modules or plurality of equipment types.
As used herein and in the claims the phrase “product sized process unit module types” means a process unit module type whose capacity (size) is determined principally by the most valuable product stream rate for the hydrocarbon fluid processing plant. The most valuable product stream is the product stream that yields the highest total revenue (e.g. market price times quantity produced, not necessarily the product with the highest value per unit of quantity). For example, for an LNG liquefaction plant the most valuable product stream is the LNG product stream. Non-limiting examples of product sized process unit module types for an LNG liquefaction plant include acid gas removal contactor units, dehydration units, deethanizer units, cryogenic heat exchanger units, refrigerant compressor units, nitrogen rejection units, liquefaction units, helium recovery units, and combinations thereof. Non-limiting examples of process unit module types that are not product sized process unit module types for an LNG liquefaction plant include utility units, sulfur recovery units, cogeneration units, gas preheat units, slug catcher units, offgas compressor units, condensate stabilizer units, acid gas removal regenerator units, and fractionation units.
As used herein and in the claims the phrase “high construction cost product sized process unit module types” means a product sized process unit module type that represents more than 10 percent of the cost of constructing a hydrocarbon fluid processing plant containing such process unit.
As used herein and in the claims the phrase “low construction cost product sized process unit module types” means a product sized process unit module type that represents less than 7 percent of the cost of constructing a hydrocarbon fluid processing plant containing such process unit.
As used herein and in the claims the phrase “transportation vessel” means any vessel which is capable of transporting a hydrocarbon fluid product over land or water. Transportation vessels may include one or more of rail cars, tanker trucks, barges, ships or other means of traveling over land or water.
As used herein and in the claims the phrase “capital cost basis” means any cost basis that represents capital and non-capital costs on a capital cost equivalent basis. Capital costs typically represent costs to design, procure, construct, and install equipment, as well as any other costs incurred by a project prior to the initial startup of the plant or plant modification. Non-capital costs, such as continuous operating costs, can be transformed to capital costs equivalent by determining the “Present Value” of such continuous costs or by determining the capital cost that would effect the same economic benefit as the continuous costs. These economic evaluation techniques are commonly employed by those skilled in the art.
As used herein and in the claims the phrase “modular heat exchanger” means a heat exchanger whose primary exchange function can be expanded easily by the addition of similar sized exchangers.
As used herein and in the claims the phrase “refrigerant circuit” means the processing steps performed to prepare a spent refrigerant for its subsequent use in performing a cooling function. A refrigerant circuit may include, for example, compression of the spent refrigerant to a high pressure, cooling and condensation of the high-pressure refrigerant, and a means of reducing the condensed refrigerant's pressure (e.g., expansion). After exiting the refrigerant circuit a refrigerant may enter a heat exchanger that accomplishes the desired cooling function.
As used herein and in the claims the phrase “operating cost” means any costs that are incurred during the routine operation of the plant. For example, operating costs include repair costs, salaries and wages, chemical and catalyst costs, and other routine plant operating costs.
One embodiment of the invention includes a hydrocarbon fluid processing plant. The hydrocarbon fluid processing plant may include a plurality of process unit module types. For exemplary purposes one general arrangement of one type of hydrocarbon fluid processing plant will be briefly described with reference to
An LNG liquefaction plant 45 may consist of several discrete processing sections. Exemplary processing sections include the inlet facilities, gas treating, dehydration, gas liquefaction, refrigerant compression, and refrigerant preparation, each of which may be carried out in one or more process unit module types. The concept is most easily described through using an example of a LNG liquefaction plant contained in
Feed gas is received into the inlet facilities, which separate the gas from liquid water and any hydrocarbon liquids (condensate) that may be present. The inlet facilities may also stabilize the condensate into a saleable product. The inlet facilities may consist of a slug catcher unit 30, various separation vessels (not shown), a condensate stabilizer unit 31, an off gas compressor unit (not shown) to return the condensate stabilizer offgas to the main gas stream, and a feed gas preheat unit 32. The feed stream is initially passed through a slug catcher and separation equipment (not shown) to remove the bulk of the components that tend to cause freezing and plugging problems in a cryogenic process. Condensed liquids (gas condensate) separated from the gas stream are generally at high pressure, such as 500-1000 psig or higher and contain significant amounts of dissolved methane and ethane. For transportation and subsequent use, the condensate is typically stabilized in the condensate stabilizer unit 31; that is, the vapor pressure is reduced, typically below atmospheric pressure. Removing the light hydrocarbons to lower the vapor pressure not only increases the heating value of the condensate product, but it also reduces potential problems caused by later off-gassing of the light components, as the pressure and temperature of the condensate change during transport and storage.
The major process functional areas in the gas treating and dehydration section are the acid gas removal (AGR) system, including the AGR contactor unit 33 and AGR regenerator unit 34, mercury adsorbent (not shown), and dehydration unit 35. A variety of processes have been used to treat the gas to remove acid gases (H2S and CO2). One process for treating a sour gas stream involves contacting the gas stream in a contactor vessel with a solvent (e.g., organic amines such as methyldiethanolamine and other additives) which absorbs the acid gases and carries them out of the gas stream.
In order for processes of this type to be economical, the “rich” solvent must be regenerated in the AGR regenerator unit 34 so that it can be reused in the treatment process. That is, the acid gases (both CO2 and H2S) and the hydrocarbons are removed or substantially reduced in the rich solvent before it can be reused in the process. The rich solvent may be regenerated by passing it into a regenerator vessel where substantially all of the acid gases are removed, after which the regenerated solvent is returned for use in the treatment process. A sulfur product may then be recovered from the H2S by processing the recovered acid gas stream through a Sulfur Recovery Unit (SRU) 38.
A dehydration unit 35, using molecular sieves and/or glycol processes for example, removes H2O to a dew point level compatible with the LNG product temperature of −260° F. The dehydration adsorbent vessels may generally be comprised of parallel vessels which cycle from dehydrating the feed gas to regenerating mode.
The gas liquefaction section 37 generally contains one or more cryogenic heat exchanger units and optionally one or more pre-cooling heat exchanger units for cooling the natural gas stream from near ambient temperature to cryogenic temperature by heat exchange with one or more refrigerants. The cryogenic heat exchangers used in the cryogenic heat exchanger unit may be, for example, spiral wound heat exchangers, sometimes referred to as spool wound heat exchangers, or brazed aluminum, plate-fin heat exchangers.
The refrigerant compression units (not shown) take the evaporated refrigerant exiting the cryogenic heat exchangers and/or pre-cooling heat exchangers and compress it to a pressure sufficient for its condensation and re-use. LNG liquefaction plants may have one or more refrigerant compression circuits that may use single component refrigerants (e.g. propane) or mixed refrigerants (e.g. methane, ethane and propane). Where two or more refrigerant circuits are employed the respective circuits may cool and condense the natural gas stream in series, in parallel or in a cascade arrangement where one refrigerant circuit is used to cool a second refrigerant, which in turn cools the natural gas stream.
Although many refrigeration cycles may be used to liquefy natural gas, the following three types are further illustrated: (1) “cascade cycle” which uses multiple single component refrigerants in heat exchangers arranged progressively to reduce the temperature of the gas to a liquefaction temperature, (2) “expander cycle” which expands gas from a high pressure to a low pressure with a corresponding reduction in temperature, and (3) “multi-component refrigeration cycle” which uses a multi-component refrigerant in heat exchangers. Most natural gas liquefaction cycles use variations or combinations of these three basic types.
A mixed refrigerant gas liquefaction system involves the circulation of a multi-component refrigeration stream, usually after precooling with propane or another mixed refrigerant. An exemplary multi-component system may comprise methane, ethane, propane, and optionally other light components. Without precooling, heavier components such as butanes and pentanes may be included in the multi-component refrigerant. Mixed refrigerants exhibit the desirable property of condensing and evaporating over a range of temperatures, which allows the design of liquefaction systems that can be thermodynamically more efficient than pure component refrigerant systems.
The refrigerant preparation unit (not shown) contains one or more distillation columns that can produce from the feed gas ethane, propane, etc., products that can be used to compose some or all of the refrigerants used within the liquefaction unit 37.
Another optional component of the gas liquefaction section 37 or a separate stand alone unit, is a distillation tower, such as a scrub tower (not shown), demethanizer unit (not shown), or deethanizer unit 36, that has as least the function of removing pentane and heavier components from the feed gas to prevent freezing in the cryogenic heat exchangers. Some plants may use a demethanizer unit or deethanizer unit 36 instead in order to produce some natural gas liquids as separate products. Natural gas leaving the dehydration unit 35 may be fractionated. In this schematic, part of the C3+ hydrocarbons are separated from the natural gas by means of a deethanizer distillation column. The light fraction collected at the top of the deethanizer column is passed to the liquefaction unit 37. The liquid fraction collected at the bottom of the deethanizer column is sent to a fractionation unit 40 for recovery of C3/C4 liquid petroleum gas (LPG) and C5+ liquid (condensate). This arrangement is preferred if the LPG product is intended to be sold separately. In locations where the feed gas has a low LPG content or the LPG has low value, the deethanizer column may be replaced by a scrub tower which removes pentane and heavier hydrocarbons to a specified level.
An LNG plant may also include a sulfur recovery unit (SRU) 38 and nitrogen rejection unit (NRU) 39, and perhaps a helium recovery unit (HRU) 39. Several processes have been developed for direct conversion of H2S to elemental sulfur. Most conversion processes are based on oxidation-reduction reactions where H2S is converted directly to sulfur. In large liquefaction trains, the Claus process converts H2S to sulfur by “burning” a portion of the acid gas stream with air in a reaction furnace. This provides SO2 for reaction with unburned H2S to form elemental sulfur by the Claus reaction: 2H2S+SO2→3/2S2+2H2O.
At the end of the liquefaction process 37, the LNG may be treated to remove nitrogen (NRU) and perhaps to recover helium (HRU) 39, if any is present. Processes to accomplish this purification can be provided by licensors. A large portion of the nitrogen that may be present in natural gas is typically removed after liquefaction since nitrogen will not remain in the liquid phase during transport of conventional LNG and having nitrogen in LNG at the point of delivery is undesirable due to sales specifications. For storage and/or shipping the pressure of the liquefied natural gas is usually decreased to near atmospheric pressure. Such pressure reduction is often called an “end flash” reduction, resulting in end flash gas and LNG. An advantage of such an end flash reduction is that low boiling components, such as nitrogen and helium, are at least partially removed from the LNG along with some methane. The end flash gas may be used as fuel gas in the mechanical-drive gas turbines or in a power generation plant 41. The helium recovery is optional depending on the amount of helium in the natural gas feed stream and the market value of helium.
Cogeneration units 41 may be used to reduce costs associated with energy usage in commercial and industrial operations. In an exemplary cogeneration unit 41, a mechanical-drive gas turbine, driving a refrigeration compressor, or an electrical power generator, such as a gas-fired turbine driving a generator, is used to generate electricity for supplying the electrical needs of the plant. Any excess electrical power generated can be sold to a power company or used in the LNG plant, and electrical power is purchased from the power company only to the extent necessary to supplement the amount of electrical power produced by the cogeneration unit 41. Wastes such as heat loss are reduced by utilizing heat generated as a result of production of electrical power for supplying or at least contributing to the heat and/or cooling demands for the plant. Heat produced as a result of operation of the gas-fired turbine may be extracted from the exhaust gases by way of a heat exchanger and used in supplying heating demands for the plant, such as steam. Alternatively, the steam generated from this process is used to generate more electricity in a steam-driven turbine-generator.
One embodiment of the invention includes a design concept for a hydrocarbon fluid processing plant, for example an LNG liquefaction plant, that it is both cost effective at any plant capacity and that it is expandable. In alternative embodiments of the invention a portion of the plant can be completed and commissioned while an expansion portion of the same plant can be constructed. Such an arrangement has the advantage that hydrocarbon production can be started earlier than would be allowed had the entire train been constructed at once, therefore improving the overall project economics. This type of arrangement alters the concept of a train in favor of a larger, more integrated plant that can more easily take advantage of economies of scale. Some embodiments of this invention are particularly applicable to an LNG project that is planned for a large resource where an initial liquefaction train would be constructed and later expanded. Such a development plan could be accomplished with some pre-investment in the initial construction phases with the benefit of shortening the required schedule of the expansion.
One method for designing, constructing, and/or operating a cost effective hydrocarbon fluid processing plant may include designing one or more process unit modules of one or more process unit module types at substantially their respective maximum processing efficiency. A process unit module's maximum processing efficiency is the process unit module capacity or size for a process unit module type that minimizes any one or more of the total process unit module construction cost per unit of process unit module capacity, the total process unit module operating cost per unit of process unit module capacity, the total process unit module life cycle cost per unit of process unit module capacity or combinations of such costs. Preferably the maximum processing efficiency is determined with respect to total process unit module life cycle cost per unit of process unit module capacity as this measure is best suited to realizing the lowest overall cost for a hydrocarbon fluid processing plant over the life of such a plant. Life cycle cost is a combined measure of the construction cost and operating cost of an equipment type or process unit module. Whatever cost measure is used it is preferably to adjust the cost to a capital cost basis. Non-capital costs, such as continuous operating costs, can be equivalently compared to capital costs by determining the “Present Value” of such continuous costs, which is a technique commonly employed by those skilled in the art. The substantially maximum processing efficiency is alternatively within 25 percent of the actual maximum processing efficiency. Alternatively, the substantially maximum processing efficiency is within 20, 15, 10 or 5 percent of the actual maximum processing efficiency.
To determine the maximum processing efficiency of a process unit module, the relationship of cost and design capacity for one or more equipment items is determined. Preferably, the relationship of cost and design capacity for the higher cost equipment items is determined. This relationship accounts for the design limits for those equipment types by adding parallel equipment, when the design limit is reached for a single piece of equipment. The total cost for a process unit module may include the sum of the major equipment cost, minor equipment cost and installation cost. The last two costs are usually expressed as a fraction of the major equipment cost based on similar modules actually built in the past. Installation costs include the cost of other pieces of hardware, such as pipes, valves and fittings, the costs of labor to install and the costs of other incidental items, such as, welding consumables and tools. For example, the major equipment types of a deethanizer process unit module may consist of a distillation column, several heat exchangers, separator drums, and pumps. Once the cost-capacity relationship is determined, the maximum processing efficiency can be found by locating the minimum cost per process unit module capacity through any standard optimization technique. For example, for complicated process unit modules the most expensive single piece of equipment may be used as an approximation of the overall process unit module cost. Alternatively, multiple pieces of equipment of multiple equipment types may be used to approximate the overall process unit module cost. Preferably, one or more of the high construction cost equipment types are used. For example, a deethanizer process unit module may consist of a distillation column, several heat exchangers, separator drums, and pumps. The most expensive single equipment item in the module may be the deethanizer column, which may be used to approximate the cost-capacity relationship of the module as a whole. Once the cost-capacity relationship is determined or approximated, the maximum processing efficiency can be found be locating the minimum cost per process unit module capacity through any standard optimization technique. The maximum processing efficiency will tend toward larger capacity until some cost, manufacturing, materials, transportation, or installation limit is reached. For example, the size of cryogenic heat exchangers may be limited by manufacturing techniques and/or equipment transportation limits. Building an LNG train for a higher capacity than can be accommodated by a single cryogenic exchanger would necessitate using two smaller exchangers in parallel. This splitting of the exchanger service and the use of smaller exchangers may negate the advantages of the natural economies of scale.
This design philosophy seeks to determine the optimal size for a process unit module of the respective process unit module types included in a selected hydrocarbon fluid processing plant. Once the optimal size is determined then multiple process unit modules of a process unit module type which are designed at substantially their maximum processing efficiency can be integrated into larger capacity parallel units, either initially during construction of the first phase of a plant or when expanding an existing plant to provide additional feed processing capacity for a particular process unit module type. By designing two or more of the process unit module types to include process unit modules at their respective maximum processing efficiency a more economic plant may be constructed, operated, and expanded as market conditions dictate.
Prior design philosophies have focused on designing and constructing the most costly piece of equipment just large enough to meet the desired plant processing capacity and then designing the other equipment and units to match the capacity of the most costly piece of equipment. One embodiment of the current invention abandons this prior philosophy and designs the process unit modules of multiple process unit module types at their respective maximum processing efficiency. Once the maximum processing efficiency of a process unit module type is determined, then one or more of the process unit modules can be included in a design to meet the desired plant maximum feed processing capacity for a hydrocarbon fluid processing plant. The design methodologies discussed herein are also applicable to expanding the capacity of an existing hydrocarbon fluid processing plant. An existing hydrocarbon fluid processing plant may also be expanded, before or after commissioning, by adding one or more additional process unit modules to the existing process unit modules in order to expand the process unit module type maximum feed processing capacity.
In alternative embodiments, multiple process unit modules can be integrated such that the multiple process unit modules act as a single common processing unit within the hydrocarbon fluid processing plant. Examples of particular types of integration include process unit modules that are parallel integrated and/or internally integrated. Parallel integrated includes, for example, where two or more process unit modules share one or more common inlet streams and one or more common outlet streams. Internally integrated includes, for example, one or more process unit modules that contain certain equipment types that share one or more common inlet streams and one or more common outlet streams.
By integrating multiple process unit modules within a process unit module type, increased operating flexibility can be obtained. In one alternative embodiment, two or more process unit module types are integrated. In one alternative embodiment, three, four, five, six or all the process unit module types of a hydrocarbon fluid processing plant are integrated.
A hydrocarbon fluid processing plant designed or constructed with multiple process unit module types made up of one or more process unit modules designed at their respective maximum processing efficiency may have process unit module types with different respective maximum feed processing capacities. Because the different process unit modules are designed to an economic efficiency target, as opposed to matching a capacity target, the respective process unit module types are not necessarily of an identical maximum feed processing capacity. In alternative embodiments of the invention, the maximum feed processing capacity of different process unit module types may differ by more than 10 percent. In alternative embodiments, one process unit module type may have a maximum feed processing capacity that is less than 85 or 80 percent of a second and/or third process unit module type.
In one alternative embodiment of the invention the maximum processing efficiency is determined for a process unit module type and a standardized process unit configuration is determined. Two substantially equally configured process unit modules are process unit modules that have substantially the same general process flow scheme. For example, a process flow scheme for a process unit module includes at least the arrangement of equipment types and the arrangement of flow paths for transporting the process fluids among the equipment types. The standardized process unit configuration may then be repeated for multiple process unit modules for a process unit module type in a hydrocarbon fluid processing plant. Preferably the standardized process unit configuration is also of a standardized size or capacity. Substantially equally sized process unit modules are process unit modules that preferably have the same processing capacity. Alternatively, equally sized process unit modules are process unit modules where their capacity is within 15 percent of each other. Alternatively, their capacity is within 10, 5 or 2 percent of each other. In this way a standardized process unit module can be repeated in parallel to expand the maximum feed processing capacity of the process unit module type in either an initially designed or constructed plant or to expand the plant maximum feed processing capacity of an existing plant. In either case, the individual standardized process unit modules are preferably integrated to provide operational flexibility.
A process unit module may be comprised of one or more different equipment types. In one alternative embodiment of the invention, the equipment types that make up a standardized process unit module are substantially equally sized and/or equally configured. Two substantially equally sized pieces of equipment means that the two pieces of equipment have about the same processing capacity. Preferably, their capacity is within 15 percent of each other. Alternatively, their capacity is within 10, 5 or 2 percent of each other. Two substantially equally configured pieces of equipment are of essentially the same design. If two pieces of equipment are fabricated and installed at different times then the manufacturer of the equipment can be expected to make incremental changes or improvements to the equipment, however, the two pieces of equipment will remain of essentially the same design to the extent they are relatively interchangeable.
By standardizing the process unit modules and/or equipment types comprising the process unit modules a designer, constructor, or operator of a hydrocarbon fluid processing plant may realize a more cost efficient plant. For example, a plant designer can design a single process unit module and repeat the design to reach a desired process unit module type maximum feed processing capacity, thus reducing design costs. In essence the process unit module design can be reused multiple times. Savings may be realized when constructing a plant with standardized process unit modules by obtaining lower purchase prices for multiples of certain identical equipment types. Additionally, by targeting equipment sizes that can be provided by multiple manufacturers, competitive bidding may be used to obtain lower costs. For example, where a plant designer or constructor desires a process unit module or equipment type of a certain large capacity and there is only one or limited manufacturers for an equipment type of a certain large size, the desired capacity can be obtained using multiple smaller capacity pieces of equipment which multiple manufacturers can provide. Thus the total equipment cost for a certain desired capacity may actually be lower by purchasing multiple smaller capacity pieces of equipment. Additionally, common spare parts can be stocked for unscheduled repairs, thus reducing or delaying replacement part purchases. Savings may be realized in operating a plant with standardized process unit modules and/or equipment types because the operators of the plant will only have to learn how to operate and repair a limited number of process unit modules and/or equipment types.
In one alternative embodiment of the invention, a hydrocarbon fluid processing plant with significant feed processing capacity flexibility is provided. A hydrocarbon fluid processing plant that contains process unit module types comprised of multiple integrated process unit modules may have considerable plant feed processing capacity flexibility. For example a process unit module type comprised of four equally sized, integrated process unit modules could be operated in a stable manner at least at 25, 50, 75 and 100 percent of its maximum feed processing capacity by placing into service or taking off line one or more respective process unit modules. Where multiple process unit module types are within each of multiple process unit modules, the respective process unit module types can also be operated at multiple feed processing capacities. Additional feed processing capacity flexibility could be realized through using multiple integrated equipment types within a process unit module, thus providing additional flexibility in feed processing capacity. Alternatively, certain process unit module types could include variable speed (variable capacity) equipment as opposed to fixed speed (fixed capacity) equipment. For example, compressors could be coupled to variable speed electric motors as opposed to fixed speed gas turbines. In one alternative embodiment, the hydrocarbon fluid processing plant may have a plant minimum feed processing capacity that is 75 percent or less than the plant maximum feed processing capacity. Alternatively, the hydrocarbon fluid processing plant may have a plant minimum feed processing capacity that is 70, 65, 60, 55, 50, 45, 40, 35, 30 or 25 percent or less than the plant maximum feed processing capacity.
The design, construction and operation methodologies discussed above are particularly suited to large LNG liquefaction plants and/or LNG liquefaction plants that increase capacity over time to become large LNG liquefaction plants. In one embodiment the LNG liquefaction plant has a plant maximum feed processing capacity of greater than 4 million tons per year capacity (MTA). In alternative embodiments, the LNG liquefaction plant has a plant maximum feed processing capacity of greater than 5, 6, 7, 8, or 9 million tons per year (MTA). In one embodiment the LNG liquefaction plant can expand over time to be a large LNG liquefaction plant as previously discussed. In one embodiment the LNG liquefaction plant begins at a first phase plant maximum feed processing capacity of 1 to 5 MTA. In alternative embodiments, the LNG liquefaction plant begins at a first phase plant maximum feed processing capacity of 1.5 to 4.5, 2.0 to 4, or 2.5 to 3.5 MTA. In one embodiment the LNG liquefaction plant expands in phases at a phase expansion size in plant maximum feed processing capacity increments of 1 to 5 MTA. In alternative embodiments, the LNG liquefaction plant expands in phases at a phase expansion size in plant maximum feed processing capacity increments of 1.5 to 4.5, 2.0 to 4, or 2.5 to 3.5 MTA. In one embodiment, the LNG liquefaction plant expands in a first phase and 1 to 6 subsequent phases. Alternatively, the LNG liquefaction plant expands in a first phase and 2 to 5, or 2 to 3 subsequent phases.
One embodiment of the invention includes expanding the plant maximum feed processing capacity of a hydrocarbon fluid processing plant by expanding the maximum feed processing capacity of one or more of the process unit module types but less than all of the process unit module types included in the hydrocarbon fluid processing plant. In one embodiment, the process unit module types are product sized process unit module types. Product sized process unit module types are process unit module types whose capacity (size) is determined principally by the most valuable product stream rate for the hydrocarbon fluid processing plant. In an LNG liquefaction plant the most valuable product stream is LNG. This embodiment of the invention may be implemented with one or more of the various aspects of the invention described herein. In one embodiment of the invention an existing hydrocarbon fluid processing plant which is comprised of one or more product sized process unit module types having product sized process unit modules designed at their respective maximum processing efficiency is expanded by expanding the maximum feed processing capacity of one or more of the product sized process unit module types but less than all of the product sized process unit module types included in the hydrocarbon fluid processing plant. As previously discussed, a hydrocarbon fluid processing plant designed or constructed with multiple process unit module types made up of one or more process unit modules designed at their respective maximum processing efficiency may have process unit module types with different respective maximum feed processing capacities. Because the different process unit modules are designed to an economic efficiency target, as opposed to matching a capacity target, the respective process unit module types are not necessarily of an identical maximum feed processing capacity. One embodiment of the invention takes advantage of the unequal maximum feed processing capacities of different process unit module types in expanding a hydrocarbon fluid processing plant. In this embodiment the plant maximum feed processing capacity can be expanded by adding additional product sized process unit modules for the product sized process unit module types that require additional capacity to increase the plant maximum feed processing capacity while not adding additional product sized process unit modules to one or more of the product sized process unit module types that do not require additional maximum feed processing capacity to increase the plant maximum feed processing capacity. By using such an expansion scheme the life cycle cost of the hydrocarbon fluid processing plant can be lowered as compared to prior art schemes.
One alternative embodiment includes a hydrocarbon fluid processing plant comprised of one or more high construction cost product sized process unit module types and one or more low construction cost product sized process unit module types where at least one of the low construction cost product sized process unit module types has a maximum feed processing capacity that is at least 110 percent of the maximum feed processing capacity of at least one of the high construction cost product sized process unit module types. This embodiment of the invention may be implemented with one or more of the various aspects of the invention described herein. This embodiment may be used for a LNG liquefaction plant that produces LNG.
In alternative embodiments of the invention, the maximum feed processing capacity of one or more low construction cost product sized process unit module types is at least 115, 125, 135 or 150 percent of the maximum feed processing capacity of at least one of the high construction cost product sized process unit module types. In alternative embodiments the high construction cost product sized process unit module types have a total construction cost per unit of maximum feed processing capacity that is 1.25, 1.5, 1.75 or 2.0 times or greater the total construction cost per unit of maximum feed processing capacity of the low construction cost product sized process unit module types. In alternative embodiments the low construction cost product sized process unit module types are selected from acid gas removal contactor units, dehydration units, fractionation units, nitrogen rejection units, and helium recovery units. In alternative embodiments the high construction cost product sized process unit module types are selected from inlet facilities units (i.e. slug catcher unit, gas preheat unit and condensate stabilizer unit), refrigerant compression units, cryogenic heat exchanger units, and liquefaction units.
In an alternative embodiment a first phase hydrocarbon fluid processing plant can be expanded while the first phase hydrocarbon fluid processing plant is producing hydrocarbon fluid products. This method may be used for a LNG liquefaction plant that produces LNG. In this embodiment, a first phase hydrocarbon fluid processing plant may be provided. The first phase hydrocarbon fluid processing plant may be comprised of a plurality of process unit module types and the respective process unit module types may be comprised of one or more process unit modules. The method may include producing a hydrocarbon fluid (e.g. LNG) from the first phase hydrocarbon fluid processing plant while constructing one or more additional process unit modules for one or more of the process unit module types included in the first phase hydrocarbon fluid processing plant. The method may include placing the one or more additional process unit modules in service and integrating the additional process unit modules with the original process unit modules of a process unit module type to provide a second phase hydrocarbon fluid processing plant with increased capacity. The method may include producing hydrocarbon fluid (e.g. LNG) from the second phase hydrocarbon fluid processing plant. This embodiment of the invention may be implemented with one or more of the various aspects of the invention described herein.
In alternative embodiments of the method the additional process unit modules may be placed in service while producing hydrocarbon fluids in the first phase plant or placed in service during limited downtimes. In one embodiment the method may include placing the one or more additional process unit modules in service while producing hydrocarbon fluids from the first phase hydrocarbon fluid processing plant. Provisions for installing the integrated additional units may be included with the first phase hydrocarbon processing plant and may include tie-ins, block valves, isolation valves, balancing valves, blind flanges, spectacle blinds, headers, and manifolds. In one embodiment the method may include producing hydrocarbon fluids from the first phase hydrocarbon fluid processing plant while at least partially accomplishing placing the one or more additional process unit modules in service. In one embodiment the method may include not producing hydrocarbon fluids from the first phase hydrocarbon fluid processing plant while at least partially accomplishing placing the one or more additional process unit modules in service. In one embodiment the method may include not producing hydrocarbon fluids from the first phase hydrocarbon fluid processing plant for less than 30 days while at least partially accomplishing placing the one or more additional process unit modules in service. In alternative embodiments the method may include not producing hydrocarbon fluids from the first phase hydrocarbon fluid processing plant for less than 20, 10, 5, 2, or 1 days while at least partially accomplishing placing the one or more additional process unit modules in service.
The method may be used to increase the plant maximum feed processing capacity in an economically advantageous way. For example, the plant maximum feed processing capacity may be increased while continuing to produce hydrocarbon fluids in a first phase hydrocarbon fluid processing plant or by shutting down the hydrocarbon fluid processing plant for only a limited time. In this way the first phase plant can continue to make valuable products while being expanded, thus avoiding or reducing the lost revenues. Alternatively, the additional process unit modules may be placed into service while the hydrocarbon fluid processing plant in down for scheduled maintenance. In addition the method may be used to build a relatively smaller first phase plant, placing the first phase plant in service to generate product revenues and then expanding the plant maximum feed processing capacity once a product revenue stream is established. This stepwise expansion can be repeated as a resource development plan is expanded and/or as buyers are identified for the hydrocarbon fluid processing plant's products. In one embodiment the LNG liquefaction plant begins at a first phase plant maximum feed processing capacity of 1 to 5 MTA. In alternative embodiments, the LNG liquefaction plant begins at a first phase plant maximum feed processing capacity of 1.5 to 4.5, 2.0 to 4, or 2.5 to 3.5 MTA. In one embodiment the LNG liquefaction plant expands in phases at a phase expansion size in plant maximum feed processing capacity increments of 1 to 5 MTA. In alternative embodiments, the LNG liquefaction plant expands in phases at a phase expansion size in plant maximum feed processing capacity increments of 1.5 to 4.5, 2.0 to 4, or 2.5 to 3.5 MTA. In one embodiment, the LNG liquefaction plant expands in a first phase and 1 to 6 subsequent phases. Alternatively, the LNG liquefaction plant expands in a first phase and 2 to 5, or 2 to 3 subsequent phases. In this way capital plant costs can be more evenly balanced with revenue generation, thus lowering a plant's life cycle cost by delaying capital investment to a later time when market conditions may be more favorable.
One embodiment of the invention includes a method of producing hydrocarbon fluids. The method includes providing a hydrocarbon fluid processing plant having a plant maximum feed processing capacity, the plant comprising a plurality of process unit module types and having at least a first refrigerant circuit. The first refrigerant circuit may include at least one first refrigerant compressor service type comprised of one or more original first refrigerant compressors in parallel. The method may include expanding the plant maximum feed processing capacity of the plant by adding at least one additional first refrigerant compressor to the first refrigerant compressor service type, where the additional first refrigerant compressor is integrated with the one or more original first refrigerant compressors within the first refrigerant compressor service type. The method may include producing a hydrocarbon fluid (e.g. LNG) in the hydrocarbon fluid processing plant (e.g. LNG liquefaction plant) after initiation of the expansion step. This embodiment of the invention may be implemented with one or more of the various aspects of the invention described herein. This embodiment may be used for a LNG liquefaction plant that produces LNG.
In alternative embodiments the compressors may be of certain character to enhance the design, construction and operation of a hydrocarbon fluid processing plant. In one embodiment the method may include at least one of the original first refrigerant compressors and at least one of the additional first refrigerant compressors being substantially equally sized. In one embodiment the method may include at least one of the original first refrigerant compressors and at least one of the additional first refrigerant compressors being substantially equally mechanically configured. In one embodiment the method may include the original first refrigerant compressors being comprised of a plurality of first refrigerant compressors and the plurality of original first refrigerant compressors having a maximum combined processing capacity where the maximum combined processing capacity is less than the processing capacity of the largest commercially available compressor for that service. In one embodiment the method may include each of the plurality of original first refrigerant compressors having a processing capacity less than the processing capacity of the largest commercially available compressor. As previously discussed, savings may be realized when constructing a plant with standardized process unit modules by obtaining lower purchase prices for identical multiples of certain equipment types, for example compressors. Additionally, by targeting compressor sizes that can be provided by multiple manufacturers, competitive bidding may be used to obtain lower costs. For example, where a plant designer or constructor desires a process unit module having a certain compression capacity, there may be only one or a limited number of manufacturers of certain large size compressors. Alternatively, multiple smaller capacity compressors which may be provided by multiple manufactures can be used to obtain the desired capacity, thus potentially lowering the overall compression circuit cost.
In one embodiment the method may include the original and/or additional first refrigerant compressors being electric-motor drive compressors. In one embodiment the method may include the original and/or additional first refrigerant compressors being gas-turbine drive compressors. Depending on the circumstances, it may be desirable to use variable speed electric-motor drive compressors which have the benefit of being capable of operating over a range of capacities. Especially when the plant is coupled with a cogeneration unit that generates enough electricity for the electric drive compressors. Cogeneration units may be used to reduce costs associated with energy usage for compressor drives. In an exemplary cogeneration system, an electrical power generator, such as a gas-fired turbine driving a generator, may be used to generate electricity for supplying the electrical needs of the electric motor drive compressors. Wastes such as heat loss may be reduced by utilizing heat generated as a result of production of electrical power for supplying or at least contributing to the heat and/or cooling demands for the plant. Heat produced as a result of operation of the gas-fired turbine may be extracted from the exhaust gases by way of waste heat boilers used to generate steam which may be used in supplying heating demands for the plant. Alternatively, the steam generated in the waste heat boiler may be used to generate more electricity in a steam-driven turbine-generator. Where variable operating capacity is not important or there is insufficient electricity available, gas turbines may alternatively be desirable.
In one embodiment the method may include the first refrigerant circuit further including one or more plate-fin heat exchangers and/or one or more spiral wound heat exchangers, where respective heat exchangers are adapted to cool a natural gas stream through heat exchange with refrigerant compressed by the first refrigerant compressors. In one embodiment the method may include the one or more plate-fin heat exchangers, for example brazed aluminum plate-fin heat exchangers. Alternatively, the plurality of plate-fin heat exchangers may be arranged in a cold box. Traditionally large spiral wound heat exchangers have been used to provide the surface area needed in large LNG liquefaction plants. However, these large spiral wound heat exchangers are often more expensive compared to plate fin heat exchangers. In some cases it may be more economic to manifold together multiple smaller plate-fin heat exchangers into a cold box in place of using a large spiral wound heat exchanger. As previously discussed, savings may be realized when constructing a plant with standardized process unit modules by obtaining lower purchase prices for multiples of certain identical equipment types, for example plate-fin heat exchangers. Additionally, by targeting smaller plate-fin heat exchangers that can be provided by multiple manufactures, competitive bidding may be used to obtain lower costs.
One embodiment of the invention includes a method of producing hydrocarbon fluids using a hydrocarbon fluid processing plant where the hydrocarbon fluid processing plant is comprised of a plurality of process unit module types and each of the plurality of process unit module types is comprised of one or more process unit modules. This embodiment may be used for a LNG liquefaction plant that produces LNG. The method may include providing a first phase LNG liquefaction plant by providing at least one original process unit module for each process unit module type included in the plurality of process unit module types. The first phase plant may be a stand-alone plant that can be placed into service to begin generating product revenues. The method may include providing a second phase LNG liquefaction plant by providing at least one second process unit module for each process unit module type included in the plurality of process unit module types, integrating one or more of the original process unit modules with one or more of the second process unit modules for two or more respective process unit module types, and producing hydrocarbon fluids from the hydrocarbon fluid processing plant after initiation of integrating one or more of the original process unit modules with one or more of the second process unit modules for two or more respective process unit module types. The method may alternatively include integrating one or more of the original process unit modules with one or more of the second process unit modules of three, four, five, six, seven or more or all of the respective process unit module types. The integration of the process unit modules of the first phase plant with those of the second phase plant may provide additional operational flexibility as previously discussed for other embodiments of the invention. In addition, this embodiment of the invention may be implemented with one or more of the various aspects of the invention described herein to obtain further benefits.
The scale to which large hydrocarbon fluid processing plants, for example large LNG liquefaction trains, are built may require many of the larger equipment items to be installed in multiple, parallel process unit modules. As discussed herein additional benefits are obtained when the multiple parallel process unit modules are integrated. As hydrocarbon fluid processing plant sizes increase, more pieces of equipment must be designed, for example 2×50%, 3×33%, 4×25%, etc. (or 3×50%, 4×33%, 5×25%, etc, if an installed spare is used), parallel process unit modules, because a single item would be prohibitively large, heavy, or outside of experience limits. In order to maximize economy of scale, it may be preferable to purchase each individual equipment item as large as possible.
An LNG liquefaction plant typically consists of several discrete processing sections, as previously discussed. In order to take advantage of some embodiments of the plant design concepts discussed herein, each process unit module type within a process functional area may be designed in as few multiples as possible, taking maximum advantage of economies of scale and/or at sizes which are consistent with a respective process unit module types maximum processing efficiency. One embodiment of this concept is most easily described through using an example of a large, 20 million ton per annum (MTA) LNG liquefaction plant.
A single slug catcher unit can likely handle all of the feed gas for this very large plant, although two condensate stabilizer units may be necessary. Even though two condensate stabilizer units may be necessary, only one offgas compressor unit may be required due to the relatively small volume through this operation. However, four or more gas preheat units may be needed due to the large flow rate through each of these items.
The AGR system often contains one of the heaviest items in the liquefaction plant: the AGR contactor vessel. Up to four of these high pressure vessels may be required in the plant. Exemplary acid gas removal contactor units containing multiple acid gas contactor vessels were previously discussed with reference to
In the exemplary plant, several mercury adsorbent vessels may be required. Molecular sieve systems generally consist of two or more parallel vessels, even for the smallest plants. In this large scale plant, it would not be unusual to require fifteen or more vessels, depending on the technology specified.
In some LNG liquefaction plants, the gas liquefaction unit limits the capacity of the train because of the heat exchange technology employed, e.g., a spiral-wound heat exchanger. Due to the fabrication cost of these exchangers, there is a strong incentive to purchase them near their maximum capacity. For example, if an exchanger's maximum capacity was 5 MTA, building a 6 MTA plant using two 3 MTA exchangers would not be cost-effective. One embodiment of the concept described herein preferably uses instead a modular heat exchanger type, typically a brazed aluminum, plate-fin heat exchanger. Such a large liquefaction plant may require dozens of the largest plate-fin heat exchangers that can be built. Alternatively, a liquefaction plant this large may be able to employ multiples (five or more) of the spiral wound heat exchangers, as long as each of the exchangers is near the maximum available size to take advantage of economies of scale.
In the pre-cooling heat exchanger unit, cryogenic heat exchanger unit and refrigerant compression units, multiple like service compressors may be integrated to provide refrigerant compression to one or more like service cryogenic heat exchangers. A single refrigerant preparation unit may be used to prepare single component or mixed component refrigerants. In one embodiment, the entire plant requirements could be served by a single fractionation unit.
Another component of the gas liquefaction section or a stand alone unit is a distillation tower such as a scrub tower, demethanizer column, or deethanizer column, that has as least the function of removing pentane and heavier components from the feed gas to prevent freezing in the cryogenic heat exchangers. For a 20 MTA plant, two to three parallel columns of whichever variety is selected may be required.
At the end of the liquefaction process, the LNG is treated to remove nitrogen in a nitrogen rejection unit (NRU) and perhaps to recover helium, if any is present. An LNG liquefaction plant would also typically require a sulfur recovery unit (SRU) These units could be designed with the methodologies described herein. Processes to accomplish these purifications are provided by licensors, who can be instructed and supervised to design their systems in accordance with this philosophy.
In order to maximize the benefit of one embodiment of this invention, the evolution of the plant capacity could always be planned so that the most expensive equipment types and/or process unit modules are always fully utilized. For example, if the refrigerant compression unit module or modules were the most expensive, then the initial LNG liquefaction plant could be designed with perhaps two refrigerant compression unit modules and an appropriate number of other functional process unit modules of the other process unit module types to handle the desired plant throughput. If upon plant expansion, one more refrigerant compression unit modules were required, then an appropriate number of other process unit modules of the other functional process unit module types could be added in order to fully utilize the available capacity of the most costly process unit module.
The overall unit cost of a plant designed, constructed and/or operated using the methodologies described herein may be lower than a plant designed by the traditional train concept because each of the equipment types and/or process unit modules would be constructed at a very large scale and/or at its respective maximum processing efficiency. Engineering costs could also be reduced because only one piece of equipment of an equipment type must be designed, although several would be fabricated. Costs could also be reduced through the sharing of a control system and large-scale utility systems.
One potential advantage of a plant of this design is its modularity. Because nearly every equipment item is provided in multiple, a portion of the plant could be completed and commissioned while other portions of the plant are still under construction. This concept could have enormous benefits for project economics because more revenue would be generated early in the project lifetime. Also, without shutting down the entire plant various portions of the plant can be taken down for maintenance, which results in higher plant availability.
The methods described herein may be used to design one or more process unit module types or a complete hydrocarbon fluid processing plant. The methods may also be used to expand the capacity of an existing process unit module type or hydrocarbon fluid processing plant. A unit or plant so designed may be constructed and operated more efficiently using the methods described herein. Such units and plants may be used to produce salable products (e.g. LNG) which may be transported to market through pipelines and/or through the use of transportation vessels. Transportation vessels may include one or more of rail cars, tanker trucks, barges, ships or other means of traveling over land or seas.
Certain features of the present invention are described in terms of a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges formed by any combination of these limits are within the scope of the invention unless otherwise indicated. Although some of the dependent claims have single dependencies in accordance with U.S. practice, each of the features in any of such dependent claims can be combined with each of the features of one or more of the other dependent claims dependent upon the same independent claim or claims.
The present invention has been described in connection with its preferred embodiments. However, to the extent that the foregoing description is specific to a particular embodiment or a particular use of the invention, this is intended to be illustrative only and is not to be construed as limiting the scope of the invention. On the contrary, it is intended to cover all alternatives, modifications, and equivalents that are included within the spirit and scope of the invention, as defined by the appended claims.
This application is the National Stage of International Application No. PCT/US2005/020674, filed Jun. 10, 2005, which claims the benefit of U.S. Provisional Application No. 60/580,746, filed 18 Jun. 2004.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US05/20674 | 6/10/2005 | WO | 12/15/2006 |
| Number | Date | Country | |
|---|---|---|---|
| 60580746 | Jun 2004 | US |
