Process for blending two or more flows of liquefied hydrocarbons

Abstract

A method for blending two liquefied hydrocarbon streams. The method includes pumping a first liquefied hydrocarbon stream to a first blending point, pumping a second liquefied hydrocarbon stream to the first blending point, and combining the first and second liquefied hydrocarbon streams at the blending point in a volume ratio of the first liquefied hydrocarbon stream to the second liquefied hydrocarbon stream ranging from 1:500, preferably 1:100 to a maximum of 500:1, to provide a composite stream. The composite stream is supplied to the delivery system from the first blending point via a composite conduit at an operating pressure higher than the saturation pressure of the composite stream, while the composite stream moves from the first blending point to the final valve just upstream of the inlet of the delivery system.

Description

Technical Field

[0001]

[0001] This specification generally relates to the field of hydrocarbon blends, and more specifically to a process for blending two or more streams of liquefied hydrocarbons.

Background Art

[0002]

[0002] This section is intended to introduce various aspects of the technology that may be relevant to exemplary embodiments of the present invention. This description is thought to be useful in providing a framework for facilitating a better understanding of specific aspects of the present invention. Therefore, it should be understood that this section should be read from this perspective and not necessarily as an endorsement of any prior art.

[0003]

[0003] Generally, it is commercially important to liquefy natural gas at extremely low temperatures so as to produce LNG for easier storage and transportation. The basic reason for liquefying natural gas is that liquefaction reduces the volume, thereby enabling the storage and transportation of large amounts of liquefied gas in a container at low pressure or even at atmospheric pressure in an economical way, and thereby providing a technically reasonable and safe solution in situations where pipeline transportation is not practical or economically feasible.

[0004]

[0004] In order to increase the calorific value of LNG to meet market demands, it is known to blend LNG products, which mainly contain methane, with other components such as light hydrocarbons such as ethane, propane, or butane. For example, U.S. Patent Application Publication 20140338393 discloses a method for producing a blended mixture of liquefied natural gas to meet the specific requirements of an operator at a production facility, application site, or fuel supply station by blending lean liquefied natural gas and rich liquefied natural gas together. In another example, International Publication 2005093017 describes a composition suitable for use as a fuel composition, comprising a mixture of natural gas and synthetic light hydrocarbons such as C2-C5 paraffins, olefins and mixtures thereof obtained by hydrocarbon synthesis reactions, particularly suitable for blending such synthetic light hydrocarbons with natural gas derived from LNG produced in an LNG process. In yet another example, U.S. Patent No. 8,381,544 discloses modifying the calorific value of liquefied natural gas by adding high-calorific value components by cooling the high-calorific value components with LNG before combining them with LNG.

[0005]

[0005] In addition, U.S. Patent No. 1,141,6012 discloses inline mixing of hydrocarbon liquids from multiple containers into a single pipeline, where the hydrocarbon liquids are generally hydrocarbons that exist as viscous liquids in subsurface formations and on the surface, as well as gasoline, crude oil, pyrolysis oil, and other substances that exist in a liquid state under atmospheric conditions. Therefore, this patent reference does not address the challenges of blending liquefied hydrocarbons. [Overview of the Initiative]

[0006]

[0006] However, these disclosures do not address the potential challenges associated with blending two liquefied hydrocarbon streams having different properties, such as density. Therefore, it is desirable to have an improved process for blending two or more liquefied hydrocarbon streams. These and other objectives will become apparent from the disclosures provided herein.

[0007]

[0007] A method is provided for blending two or more liquefied hydrocarbon streams in a facility, the facility comprising: a first storage container for storing a first liquefied hydrocarbon which is optionally liquefied natural gas; a delivery system for delivering the first liquefied hydrocarbon to a downstream treatment device which optionally includes a regasifier; and a network of conduits. The conduit network comprises (i) a first blend point located downstream of the first storage container and upstream of the delivery system; (ii) a first conduit segment for providing fluid communication between the first storage container and the first blend point; (iii) a second conduit segment for providing fluid communication between a second liquefied hydrocarbon source and the first blend point, wherein optionally the second liquefied hydrocarbon is selected from the group consisting of liquefied ethane, liquefied butane, liquefied propane, and any combination thereof; and (iv) a composite conduit for providing fluid communication between the first blend point and the delivery system. The composite conduit includes a first end valve just upstream of the inlet of the delivery system. The method includes (a) pumping a first liquefied hydrocarbon stream from a first storage container to a first blending point via a first conduit segment; (b) pumping a second liquefied hydrocarbon stream from a second liquefied hydrocarbon source to the first blending point via a second conduit segment; (c) combining the first liquefied hydrocarbon stream and the second liquefied hydrocarbon stream at the first blending point in a volume ratio ranging from 1:500, preferably 1:100 to a maximum of 500:1, to provide a composite stream; (d) providing at least a portion of the composite stream, including all of it, from the first blending point to a delivery system via a composite conduit; and (e) providing the composite stream with an operating pressure exceeding the saturation pressure of the composite stream (preferably at least 0.1 bar, more preferably at least 0.5 bar, and most preferably at least 1.2 bar) while the composite stream is in a segment of the composite conduit between the first blending point and the first end valve.

[0008]

[0008] Optionally, in some embodiments, the conduit network further comprises a return composite conduit (160) for providing fluid communication between a first blend point and a storage container, and optionally, the storage container is the first storage container. The return composite conduit comprises a second end valve just upstream of the outlet of the return composite conduit. In such embodiments, the method may further include providing at least a portion of the composite flow from the segment of the composite conduit upstream of the first end valve to the storage container, and providing the portion of the composite flow with an operating pressure exceeding the saturation pressure of the composite flow (preferably at least 0.1 bar, more preferably at least 0.5 bar, and most preferably at least 1.2 bar) while the portion of the composite flow is in the segment of the composite conduit between the first blend point and the second end valve.

[0009]

[0009] Optionally, in some embodiments, at least a portion of the combined flow, including all of it, is not provided to the storage container.

[0010] Optionally, in some embodiments, the composite conduit is located upstream of the first final valve and downstream of the first blend point, and optionally further comprises a first subsequent blend point located either upstream or downstream of the return composite conduit. In such embodiments, the method may further include (f) providing a first liquefied hydrocarbon source, optionally, a second flow of the first liquefied hydrocarbon from a first storage vessel, to the first subsequent blend point; and (g) combining the composite flow and the second flow of the first liquefied hydrocarbon at the first subsequent blend point in a volume ratio ranging from 25:1, preferably 50:1 to a maximum of 500:1, or combining the first flow of the first liquefied hydrocarbon and the second liquefied hydrocarbon ethane flow at the first blend point in a volume ratio ranging from 1:500, preferably 1:100 to a maximum of 50:1.

[0010]

[0011] Optionally, in some embodiments, the composite conduit further comprises a second subsequent blending point located downstream of the final valve and upstream of the blend product storage container. In such embodiments, the method may further include (f) providing a third flow of the first liquefied hydrocarbon from a first liquefied hydrocarbon source to a second subsequent blending point, wherein such source, unlike the first storage container, may optionally be equipped with a boil-off gas management system (150); and (g) combining the combined flow and the third flow of the first liquefied hydrocarbon at a second subsequent blending point in a volume ratio ranging from 25:1, preferably 50:1 to a maximum of 150:1, a first LNG flow and an ethane flow at a first blending point in a volume ratio ranging from 1:500, preferably 1:100 to a maximum of 50:1, and a combined flow and a second flow of the first liquefied hydrocarbon at a first subsequent blending point in a volume ratio ranging from 100:1, preferably 150:1 to a maximum of 500:1.

[0011]

[0012] Optionally, in some embodiments, the composite conduit further comprises a subsequent blending point located downstream of the final valve and upstream of the blend product storage vessel. In such embodiments, the method may further include (f) providing another flow of the first liquefied hydrocarbon from a second source of the first liquefied hydrocarbon to the subsequent blending point, which optionally, unlike the first storage vessel, may optionally be equipped with a boil-off gas management system; and (g) combining the composite flow and the other flow of the first liquefied hydrocarbon at the subsequent blending point (308) in a volume ratio ranging from 25:1, preferably 50:1 to a maximum of 500:1, or combining the first flow of the first liquefied hydrocarbon and the second liquefied hydrocarbon at the first blending point in a volume ratio ranging from 1:500, preferably 1:100 to a maximum of 50:1.

[0012]

[0013] Optionally, in some embodiments, a combined flow downstream of the first end valve and any subsequent blend point may be optionally downstream of a second end valve. In such embodiments, the combined flow may include a volume ratio of at least 2:1, preferably at least 3:1, and more preferably 4:1 of a first liquefied hydrocarbon, preferably LNG, to a second liquefied hydrocarbon, preferably liquefied ethane.

[0013]

[0014] Optionally, in some embodiments, the method may further include providing a total operating pressure of at least 2 barg to the conduit network.

[0015] Optionally, in some embodiments, the method may further include reducing the operating pressure of the combined flow downstream of the second final valve to below the saturation pressure of the combined flow. In such embodiments, the method may further include reducing the operating pressure of the combined flow downstream of the second final valve to the storage pressure of the storage container.

[0014]

[0016] Optionally, in some embodiments, step (a) is preferably performed before step (b). In such embodiments, step (a) may include circulating a first flow of the first liquefied hydrocarbon from the first storage container through a first portion of a conduit, a composite conduit, optionally back to the first storage container, and optionally through a boil-off gas management system.

[0015]

[0017] Optionally, in some embodiments, the second liquefied hydrocarbon may be liquefied ethane, and the source of the liquefied ethane may be selected from the group consisting of land storage, ethane transport ships, and any combination thereof.

[0016]

[0018] Optionally, in some embodiments, the facility may include an LNG regasification facility.

[0019] Optionally, in some embodiments, the method may further include providing the contents of a storage container to a dispensing system. [Brief explanation of the drawing]

[0017]

[0020] [Figure 1] The diagram shows an exemplary embodiment of a system for use in blending two or more liquefied hydrocarbon streams, according to the aspects disclosed herein.

[0021] [Figure 2] The diagram shows an exemplary embodiment of another system for use in blending two or more liquefied hydrocarbon streams, according to the aspects disclosed herein.

[0022] [Figure 3] The diagram shows an exemplary embodiment of yet another system for use in blending two or more liquefied hydrocarbon streams, according to the aspects disclosed herein.

[0023] [Figure 4] The diagram shows an exemplary embodiment of yet another system for use in blending two or more liquefied hydrocarbon streams, according to the aspects disclosed herein. [Modes for carrying out the invention]

[0018]

[0024] The present invention will be described in detail below with reference to the embodiments shown in the accompanying drawings. References to “one embodiment,” “embodiment,” and “exemplary embodiment” indicate that the embodiments described may include certain features, structures, or characteristics, but not all embodiments necessarily include certain features, structures, or characteristics. Furthermore, such phrases do not necessarily refer to the same embodiment. Moreover, where certain features, structures, or characteristics are described in relation to an embodiment, whether explicitly stated or not, any impact on such features, structures, or characteristics in relation to other embodiments will be known to those skilled in the art. Other appropriate modifications and adaptations of various conditions and parameters commonly encountered in the art will be apparent to those skilled in the art and are within the spirit and scope of the present invention.

[0019]

[0025] The description in this specification provides numerous specific details for a complete understanding of the exemplary embodiments, but it will be apparent to those skilled in the art that the embodiments can be implemented without some or all of these specific details. In other instances, well-known process steps and / or structures are not described in detail so as not to unnecessarily obscure the present invention. The features and advantages of the embodiments can be better understood by reference to the following drawings and description.

[0020]

[0026] Furthermore, when the same element is used in one or more figures, the same reference numeral is used in each figure, and a detailed description of the element is provided only at its first occurrence. Specific features or components of the system or process described herein may be omitted in a particular illustrated configuration for clarity.

[0021]

[0027] A common concern when blending LNG products with lighter hydrocarbons is the possibility of forming layered liquid layers (or stratification) of different densities within the storage container. Typically, heat leaking into the blended LNG product through the storage container walls slowly warms the blended LNG in contact with the container walls and bottom plate. This warmer blended LNG has a lower density, which increases its buoyancy and causes it to slowly rise within the bulk LNG stock. At the top of the liquid column (liquid-vapor interface), this warmer LNG releases the excess heat it has accumulated through evaporation, becoming colder and denser, which then reduces its buoyancy and causes the colder blended LNG to slowly descend within the bulk LNG stock. This natural convection occurs uninterrupted as long as the density difference within the blended LNG bulk stock is less than 1%. If the bulk density is greater than 1%, different LNG layers form, hindering the natural convection of the bulk LNG. When LNG blends with different densities may be introduced into the same vessel, especially in this case where the density difference between lean LNG (methane) and liquefied ethane is at least 10%, maintaining homogeneity and mitigating sedimentation is essential. Once a layered liquid layer forms, rollover can occur when the density difference between the two layers becomes small enough and natural convection from the bottom layer reaches the free surface. The subsequent mixing of these layers is accompanied by a large increase in the normal evaporation rate, which is proportional to the amount of superheat accumulated in the bottom layer. This physical phenomenon associated with the mixing of layered LNG is commonly and descriptively called "rollover." However, high-intensity rollover can cause vapor releases that exceed the vessel's designed vapor handling capacity, thus overpressuring the storage vessel and potentially causing it to rupture.

[0022]

[0028] Although the present disclosure often refers to LNG and ethane as two streams of liquefied hydrocarbons that benefit from the blending methods described herein, it should be understood that the principles provided by the present disclosure can be applied to blend other streams of liquefied hydrocarbons, such as (i) LNG and liquefied propane, or (ii) LNG and a mixture of liquefied ethane, liquefied propane, liquefied butane, and any combination thereof.

[0023]

[0029] As used herein, the term "hydrocarbon" has its ordinary meaning and includes molecules composed of various combinations of carbon and hydrogen, which may be of fossil (e.g., natural gas) or biological origin (e.g., biomethane). The term "liquefied hydrocarbon" refers to a hydrocarbon that occurs as a gas at atmospheric pressure and ambient temperature and whose state changes due to a decrease in temperature and / or an increase in pressure, or a combination of both, and becomes a liquid under the new pressure-temperature conditions. In some cases (such as in the case of natural gas liquefaction), this phase change can also be combined with a subsequent decrease in operating pressure to suit downstream processes (e.g., atmospheric storage of LNG), and the temperature of the liquefied hydrocarbon stream can be further reduced. The specific combination of pressure and temperature at which the gas liquefies varies depending on the type of hydrocarbon. Further, hydrocarbons may be described as light or heavy depending on the number of carbon and hydrogen atoms in the molecule. Examples of liquefied hydrocarbons include alkanes (or paraffins) (e.g., methane - CH4, ethane - C2H6, propane - C3H8, butane: normal butane and isobutane - C4H 10 , natural gasoline or pentanes plus - C5H 12 , and heavier ones); and alkenes (or olefins) (e.g., ethylene - C2H 44 , propylene - C3H6, normal butylene and isobutylene - C4H8).

[0024]

[0030] This disclosure provides a method for performing an operation to blend two liquefied hydrocarbon flows in an LNG facility to produce liquefied natural gas having a desired composition, thereby reducing the risk of stratification. Furthermore, certain embodiments of the method of this disclosure allow at least a portion of the blended product flow, including all of it, to be sent to a delivery system, with the option of partially or completely bypassing a storage vessel. As used herein, the term delivery system has its usual meaning and generally refers to a pumping device that sends a liquefied hydrocarbon flow, such as LNG, to downstream processing, for example, to convert the liquefied hydrocarbon flow into vapor and send it to a pipeline system for consumer use, and / or to load the liquefied blended product for distribution, including ISO containers, road or rail vehicles, bunkering, etc. In context, a facility, in particular a regasification facility, typically provides liquefied hydrocarbons to a delivery system for processing downstream via a storage vessel that is in fluid communication with such delivery system. Embodiments of the present disclosure provide an option for delivering the blended product to a delivery system without first sending the blended LNG flow through a storage vessel, thereby providing improved operational efficiency. In addition, bypassing the storage vessel reduces the need to involve an associated BOG management system to manage boil-off gas (BOG) formed from the portion entering the receiving vessel. This is particularly relevant in assets where the BOG management system is an operational constraint, especially a significant one. Furthermore, bypassing the storage vessel may reduce, and potentially eliminate, any risks associated with stratification within the storage vessel, thereby enabling the mitigation of the proposed mitigation measures. Embodiments of the present method may provide other additional advantages that will be apparent to those skilled in the art.In addition, certain embodiments of the methods described herein can be adapted to suit the blend of lean LNG and liquefied ethane at various LNG facilities or locations using existing infrastructure at each location, so as to meet desired LNG and / or natural gas specifications (e.g., Wobbe Index (WI), Lower Heating Value (LHV), Methane Number (MN), or Incomplete Combustion Factor (ICF)).

[0025]

[0031] Figures 1 to 4 illustrate various facilities comprising a storage container 102 for storing a first liquefied hydrocarbon, preferably LNG, and a delivery system 106 for providing the liquefied hydrocarbon flow to downstream processing such as a regasifier. The illustrated facilities further comprise a network of conduits that have fluid communication with both the storage container 102 and the delivery system 106. Optionally, the LNG facility may further comprise a return composite conduit 160 for providing fluid communication between a composite conduit 116 and the storage container 102. While Figures 1 to 4 show conduit 160 as carrying the composite flow from conduit 116 to container 102, it should be understood that conduits can, alternatively or in addition, carry the composite flow from conduit 116 to another suitable storage container (either on land and / or on a ship), even if not explicitly shown. In general, liquefied natural gas (LNG) is liquefied natural gas (primarily methane). It should be understood that the diagram omits certain parts of the conduit network, such as recirculation and load / unload conduits, which are not explicitly mentioned but are still part of the facility as can be understood by those skilled in the art. Depending on the application, the LNG can be stored in containers 102 and / or 106 at temperatures below -110°C, more typically below -145°C, for example, between -159°C and -162°C. The LNG in container 102 is typically lean LNG at the start of the blending operation. In certain embodiments involving sending a combined or blended flow back into container 102, the composition of the LNG will be "richer" at the end of the blending operation compared to at the start of the blending operation. Generally speaking, "lean" LNG exhibits a relatively lower calorific value, while "rich" LNG contains a larger proportion of heavier hydrocarbons, which give a higher calorific value. Lean LNG can be further enriched by methods described herein, among others, to meet various market quality specifications, such as the Wobbe index (WI), lower heating value (LHV), methane number (MN), or incomplete combustion factor (ICF).

[0026]

[0032] The conduit network comprises a first blend point, which in a preferred embodiment may be referred to as an LNG-ethane blend point 108, located between the pier and the storage container (102). The conduit network further comprises a first conduit segment 110 (which may be referred to as an LNG conduit 110 in a preferred embodiment where the first liquefied hydrocarbon is LNG) and a second conduit segment 112 (which may be referred to as an ethane conduit 112 in a preferred embodiment where the second liquefied hydrocarbon is ethane). The first conduit segment 110 provides fluid communication between the first storage container 102 and the first blend point 108. The second conduit segment 112 provides fluid communication between the storage container 114 for the second liquefied hydrocarbon and the first blend point 108. The container 114 may be referred to as an ethane supply source 114 when referring to a preferred embodiment where the second liquefied hydrocarbon is ethane. The first blend point 108 is a fluid conduit joint between the first conduit segment 110 and the second conduit segment 112. Preferably, the first blend point 108 is the connection between the recirculation line and the unload line, or near the connection. As can be seen from the figure, the blend point 108 is also upstream of the delivery system 106. The blend point 108 is a fluid conduit joint known to those skilled in the art. For example, suitable examples of blend point 108 include T-joints, Y-joints, mixed T-joints, Y-pipe fittings, and any combination thereof.

[0027]

[0033] In a preferred embodiment, the second liquefied hydrocarbon is ethane. The liquefied ethane can be stored at temperatures below -30°C, more typically below -75°C, depending on the application, for example, between -80°C and -89°C. Figure 1 shows the ethane supply source 114 as being on a ship (e.g., a liquefied ethane transporter), but it should be understood that the ethane supply source 114 may preferably be, in addition to or alternatively, a land-based storage container as known to those skilled in the art. The conduit network further comprises composite conduits 116 to provide fluid communication between the first blend point 108 and the delivery system 106 for downstream processing, for example, to convert the liquefied hydrocarbon stream into vapor to be delivered to the pipeline system for consumer use. For certain assets such as liquid-in liquid-out LNG, the distribution system may include cryogenic distribution pipelines, or alternatively, pumping equipment, as well as LNG loading facilities such as LNG vessels (e.g., bunker ships), LNG load tankers, LNG railcars, and / or LNG ISO containers.

[0028]

[0034] Suitable storage methods for liquefied hydrocarbons such as LNG, liquefied ethane, and others described herein are known to those skilled in the art. For example, a suitable example may include a single containment system that may be self-supporting and typically has an inner wall or primary container for holding a cooled liquid. The inner container may be surrounded by an outer wall, thereby forming an annular space in which insulation can be held. The single containment system may be further insulated, such as a base and roof, as well as external insulation. Another suitable example includes a double containment system that typically adds a secondary wall to the single containment system, which may contain both liquid and vapor.

[0029]

[0035] A first flow of a first liquefied hydrocarbon, preferably liquefied natural gas (LNG), is pumped from the storage container 102 to a first blending point 108 through a first conduit segment 110 (which may be referred to as the LNG conduit 110 in a preferred embodiment). Referring to Figure 1, the pumping of the LNG flow can be carried out by at least a pumping device 120. A liquefied ethane flow is pumped from the ethane source 114 to the LNG-ethane blending point 108 through the ethane conduit 112. As used herein, the terms “liquefied ethane,” “liquid ethane,” or “ethane” refer to a liquefied hydrocarbon flow containing at least 50 mol%, preferably at least 95 mol%, of ethane. As described elsewhere in this disclosure, liquefied hydrocarbons other than LNG and liquefied ethane can be blended using the methods described herein. For example, when LNG is blended with liquefied propane, the liquefied hydrocarbon stream that is liquefied propane contains at least 50 mol%, preferably at least 95 mol%, of propane, and in the case of liquefied butane, the liquefied hydrocarbon stream contains at least 50 mol%, preferably at least 95 mol%, of butane. Optionally, if the liquefied hydrocarbon stream is not essentially composed of the components of its name (for example, if the liquefied ethane stream is not essentially all ethane), the remainder of the stream, where applicable, is selected from the group consisting of ethane, methane, propane, butane, and any combination thereof. For example, an example of a mixture of liquefied hydrocarbons as defined herein may be LPG, which stands for liquefied petroleum gas and includes a mixture that is mostly propane, mostly butane, or mostly a mixture of both propane and butane.

[0030]

[0036] Referring to Figure 1, the pumping of the liquefied ethane flow can be carried out by at least the pumping device 118. The first LNG flow and the ethane flow are combined at the LNG-ethane blending point 108 at a volume blending ratio of LNG to ethane ranging from 1:500 to a maximum of 500:1, preferably from 1:100 to a maximum of 500:1, and more preferably from 1:10 to a maximum of 1:500, to give a combined flow. Those skilled in the art will understand that, taking into account various factors such as the specifications of the equipment and infrastructure involved in the blending operation (e.g., conduit network, pumps, storage containers, valves, etc.) and the safe operating envelope (SOE), an appropriate flow velocity of the first LNG flow and the liquefied ethane flow can be selected to achieve a desired blending ratio within the ranges described herein. A suitable number and type of pumps for implementing the method described herein are known to those skilled in the art. In addition, or alternatively, the pumping device may be part of the existing infrastructure and equipment of a facility such as a regasification plant.

[0031]

[0037] In one embodiment, the combined flow can be delivered from a first blending point 108 to a distribution system 106 for the blend product storage via at least a combined conduit 116, and returned to a container 102 and / or another suitable storage container via a conduit 160, or not. In certain embodiments, if the combined flow is returned to a container 102, the product in the container 102 can also be delivered to the distribution system 106 using existing infrastructure (not shown) of a particular facility, typically such as an LNG import facility. Preferably, the flow velocities of the LNG flow and the ethane flow by the respective pumps provide sufficient force to move the combined flow to the distribution system 106 or the LNG storage container 102 (or another storage container (not shown)) without requiring additional pumping equipment.

[0032]

[0038] The conduit network may include a number of valves, as known to those skilled in the art, to control the flow rates of various flows. For example, referring to Figure 1, optionally, the LNG conduit 110 may include a valve 122 for controlling the flow rate of a first LNG flow from storage vessel 102 to LNG-ethane blend point 108. Optionally, the ethane conduit 112 may include a valve 124 for controlling the flow rate of liquefied ethane flow from ethane source 114 to LNG-ethane blend point 108. In embodiments including a return composite conduit 160, the conduit 160 may include a valve 162 for controlling the flow rate from composite conduit 116 to vessel 102 (and / or another suitable storage vessel (not shown)). The valve 162 can be operated or controlled to allow the composite flow to partially or completely bypass vessel 102. Regardless of the number of valves that are arranged throughout the entire network of conduits, such as the LNG conduit 110, the ethane conduit 112, and the composite conduits 160 and 116, and which control the flow rate of each flow, the conduit network includes a final valve 126. The final valve 126 is the last valve through which the composite flow flows before it is introduced into the delivery system 106. That is, the final valve 126 is the valve just upstream of the inlet to the delivery system 106 of the blend product storage container. In embodiments that also include a return composite conduit 160, valve 162 can also be considered another final valve before the composite product is introduced into the container 102.

[0033]

[0039] During the blending operation at least, the composite conduit 116 and optionally conduit 160 have an operating pressure, at least due to the force exerted by the flow of the composite flow through each composite conduit 116, and any available flow control devices in the conduit, such as the final valve 126 and optionally valve 162. While the composite flow is being delivered to its destination (either the delivery system 106 and / or container 102 (or another container)), the portions of each composite conduit 116 and / or 160 between the LNG-ethane blending point 108 and upstream of each final valve 126 and / or 162 are provided with an operating pressure higher than the saturation pressure of the composite flow, preferably at least 0.1 bar above the saturation pressure of the composite flow, more preferably at least 0.5 bar above, and most preferably at least 1.2 bar above. While an operating pressure at least 1.2 bar higher than the saturation pressure of the combined flow is most preferable to provide the most favorable buffer for adapting to fluctuations in pressure conditions along the conduit 116, embodiments having an operating pressure lower than or equal to the saturation pressure of the combined flow can still provide the benefits described herein. The saturation pressure of the combined flow may change as it moves through the conduit 116 to the blend product storage container 106, at least due to heat transfer from the environment and / or equipment. Generally, the saturation pressure of the combined flow increases as the combined flow moves through the combined conduit 116 toward the container 106. Any operating pressure in the combined conduit 116 between the LNG-ethane blend point 108 and the final valve 126 may be frequently adjusted, preferably in response to monitoring, to adapt to the increase in saturation pressure, and / or the saturation pressure of the combined flow may be reduced to ensure that the operating pressure remains higher than the saturation pressure of the combined flow as the saturation pressure changes. In addition to the other advantages described elsewhere in this disclosure, the method described herein reduces two-phase flow formation in that portion of the composite conduit 116 (whether localized or sustained) by providing an operating pressure equal to or higher than the saturation pressure of the composite flow in the portion of the composite conduit 116 between the blend point 108 and the final valve 126.Therefore, the method described herein can minimize operational disturbance and equipment damage (e.g., erosion of valves due to cavitation), as is known to those skilled in the art. The term “saturation pressure” has its usual meaning and includes the definition of the pressure at which a fluid exists as both vapor and liquid, where the evaporation rate is equal to its condensation rate for a given temperature. In this scenario, the saturation pressure of the combined flow is the pressure at which the combined flow exhibits both gas and liquid phases, which are in thermodynamic equilibrium at the temperature of the combined flow. The saturation pressure of the combined flow while it is in the respective combined conduits 160 and / or 116 between the LNG-ethane blend point 108 and the respective end valves 126 and / or 162 can be appropriately determined by those skilled in the art based on the temperature and blend ratio of the combined flow (both of which can be measured by sensors). The conduit network may be equipped with appropriate sensors known to those skilled in the art to provide relevant data for carrying out the method described herein. Examples of suitable sensors include hydrometers, gravimeters, densimeters, density measuring sensors, gravity measuring sensors, pressure transducers, temperature sensors, flowmeters, mass flowmeters, Coriolis meters, other measuring sensors for determining density, gravity, or other variables as understood by those skilled in the art, or a combination thereof. The determination of the saturation pressure of the composite flow can be performed manually or autonomously using a computer or other similar process control system, thereby allowing subsequent corrective operations (e.g., increasing the system operating pressure, increasing the blend ratio, or other) to be performed as desired. The method described herein provides an operating pressure in each composite conduit 116 and / or 160 between the LNG-ethane blend point 108 and the respective end valves 126 or 162 that is higher than the saturation pressure of the composite flow, preferably at least 0.1 bar above the saturation pressure of the composite flow, more preferably at least 0.5 bar above, and most preferably at least 1.2 bar above. By providing such an operating pressure higher than the saturation pressure of the combined flow, the combined flow can be kept in the liquid phase while flowing through these segments of the conduit, even though the pressure conditions along such conduit segments change.

[0034]

[0040] Preferably, the operating pressure of the composite flow within the composite conduit and other parts of the conduit network can be monitored by sensors or the like, as is known to those skilled in the art. Monitoring allows for continuous monitoring of the operating conditions of the composite flow, ensuring that the operating pressure in the composite conduit 116 remains above the saturation pressure of the composite flow (preferably at least 0.1, 0.5, or 1.2 bar above). Optionally, and preferably, operating pressures of the composite flow upstream of each final valve 126 or 162 that are higher than the saturation pressure of the composite flow can be provided by adjusting the opening ratio of each final valve 162 or 126 to provide a desired operating pressure upstream of each final valve. The opening ratio of the final valve 126 can be continuously adjusted as needed during the blend operation, as described herein, to provide a desired operating pressure above the saturation pressure of the composite flow.

[0035]

[0041] Optionally, in addition to or alternatively, the saturation pressure of the composite flow can be reduced by adjusting the volume ratio of the first LNG flow to liquefied ethane along the composite conduit 116 by providing an LNG-ethane blending point 108 and / or additional blending points. Generally, additional blending points allow more LNG to be added to the composite flow, thereby lowering the saturation pressure of the composite flow and providing another option to ensure that an operating pressure of the composite flow higher than the saturation pressure of the composite flow is achieved. For example, referring to Figure 2, the composite conduit 116 further comprises a subsequent blending point (208) located upstream of valve 162, and, if present, upstream of final valve 126 and downstream of LNG-ethane blending point 108. As can be seen in Figure 2, the conduit network further comprises another conduit segment 216 (which may be referred to as the second LNG conduit 216 in a preferred embodiment) for providing fluid communication between the storage container 102 (or a second preferred source of LNG, not shown in Figure 2) and the subsequent blending point 208. In a scenario in which the second LNG flow comes from the storage container 102, the second LNG conduit 216 can provide fluid communication between the subsequent blending point 208 and the container 102 via a connection with the LNG conduit 110, or it can be directly connected to the container 102. If desired, a second flow of the first liquefied hydrocarbon, preferably LNG, can be supplied from the storage container 102 (or a second source of LNG) to the subsequent blending point 208 via the second LNG conduit 216. Optionally and preferably, the second LNG conduit 216 may further comprise a valve 222 for controlling the flow rate of the second LNG flow through the second LNG conduit 216. For example, the valve 222 may be closed if blending at the subsequent blending point 208 is undesirable, and opened if blending of additional LNG into the combined flow is desired. The opening of the valve 222 can be adjusted to achieve a desired blend ratio at the subsequent blending point 208.In Figure 2, the combined flow and the second LNG flow are combined at a subsequent blending point 208 in a ratio of 25:1, preferably ranging from 50:1 to a maximum of 500:1, and the first LNG flow and the ethane flow are combined at an LNG-ethane blending point 108 in a ratio preferably ranging from 1:100 to a maximum of 50:1. Because additional blending points are provided, the ratio of LNG to ethane at the LNG-ethane blending point 108 can be smaller than if there were only a single blending point (i.e., 108). For example, in a single blend point scenario, the ratio of LNG to ethane at the LNG-ethane blend point ranges from 1:500 to a maximum of 500:1 for the multiple blend point scenario shown in Figure 2, where the ratio of LNG to ethane at LNG-ethane blend point 108 is 1:500, preferably 1:100 to a maximum of 50:1, and at the subsequent blend point 208, the ratio of the combined flow to the second LNG flow is 25:1, preferably 50:1 to a maximum of 500:1. As will be understood by those skilled in the art, in the multiple blend point scenario, the range of blend ratios provided can be extended or modified to suit the specific requirements of the asset and / or process. For example, the first blend point may have a blend ratio of 1:1, while the second blend point may have a blend ratio of 47:1.

[0036]

[0042] Optionally, in addition to or alternatively, different blending points may exist downstream of the final valve 126. For example, referring to Figure 3, the composite conduit 116 further comprises a subsequent blending point 308 located downstream of the final valve 126 and upstream of the delivery system 106. Optionally, and alternatively, the subsequent blending point 308 may be located upstream of the final valve 126, depending on the specific arrangement of the existing infrastructure of the plant in which the blending operation is performed. The conduit network may further comprise a BOG conduit 148 providing fluid communication between the storage vessel 102 (and / or the steam space of other vessels, both onshore and onshore, available in the LNG asset, although not shown in the provided figures) and the boil-off gas (BOG) management system 150. During the operation of the LNG facility 100, including while the LNG is stored in container 102, BOG is generated in container 102 (and / or other available in the LNG asset, not shown in the provided diagrams) due to at least heat leakage from the environment and / or energy input from the unload pump, and steam flow resulting from the pressure difference between the LNG carrier and the storage container 106. The BOG (in the gas phase) is typically removed from the storage container 102 (and / or other available in the LNG asset, not shown in the provided diagrams) to mitigate the effects of pressure rise if the BOG were left in container 102. The BOG management system 150 typically comprises a boil-off gas compressor and condensation column for condensing the BOG and recovering it as LNG (other technical options and configurations may apply), and the LNG is delivered to the delivery system 116A via a return conduit 316.

[0037]

[0043] As can be seen from Figure 3, the conduit network further comprises a third LNG conduit 316 for providing fluid communication between a first source of liquefied hydrocarbons such as LNG (this source may differ from container 102, optionally illustrated as a BOG management system 150) and a subsequent blending point 308. If desired, another LNG flow can be supplied from the BOG management system 150 to the subsequent blending point 308 via the third LNG conduit 316. Although not shown, it should be understood that the third LNG conduit 316 may further comprise valves for controlling the flow rate of the LNG flow through the conduit. In Figure 3, the combined flow and the LNG flow from the BOG management system 150 are combined at the subsequent blending point 208 in a ratio of 25:1, preferably ranging from 50:1 to a maximum of 500:1, and the first LNG flow and the ethane flow are combined at the LNG-ethane blending point 108 in a ratio of 25:1, preferably ranging from 50:1 to a maximum of 500:1. In the multiple blending point scenario shown in Figure 3, the blend ratio of LNG to ethane at the LNG-ethane blending point 108 is 1:500, preferably ranging from 1:100 to a maximum of 50:1, and at the subsequent blending point 308, the ratio of the combined flow to the LNG flow from the BOG management system 150 is 25:1, preferably ranging from 50:1 to a maximum of 500:1.

[0038]

[0044] Referring to Figures 3 and 4, the conduit network may optionally further comprise conduit 152 downstream of blend point 108 and, if present, blend point 208, for providing fluid communication between the composite conduit 116 and the BOG management system 150. As is standard in BOG management systems based on recondensers, at least a portion of the composite flow can be supplied to the BOG management system 150 for the purpose of recondensing the BOG flow 148 (and / or other BOG flows originating from other LNG storage vessels or field processes, not shown in the provided figures). The blended LNG conduit 152 may further comprise valves (not shown) to enable control over the amount of the composite flow, if present, for supplying to the BOG management system 150. Optionally, alternatively, or in addition, the blended LNG conduit 152 may serve another purpose inside or outside the BOG management system 150, not shown in the provided figures.

[0039]

[0045] Optionally, in addition to or alternatively to this, both additional blending points may exist alongside the LNG-ethane blending point 108. For example, referring to Figure 4, the composite conduit 116 includes both subsequent blending points 208 and 308, as shown in Figures 2 and 3, respectively. In the multiple blending point scenario shown in Figure 4, (i) the blending ratio of LNG to ethane at the LNG-ethane blending point 108 is in the range of 1:500, preferably 1:100 to a maximum of 50:1; (ii) the blending ratio of the composite flow to the second LNG flow at the subsequent blending point 208 is in the range of 25:1, preferably 50:1 to a maximum of 150:1; and (iii) the blending ratio of the composite flow to the LNG flow from the BOG management system 150 at the subsequent blending point 308 is in the range of 100:1, preferably 150:1 to a maximum of 500:1. Depending on the specific configuration of the asset implementation of this blending process, the conduit network may have more than three blending points (e.g., 108, 208, and 308) than the three shown in the figure to achieve a desired operating pressure higher than the saturation pressure of the combined flow. As will be understood by those skilled in the art, in a multiple blending point scenario, the range of blending ratios provided can be extended or modified to suit the specific requirements of the asset and / or process. For example, the first blending point (e.g., 108) may have a blending ratio of 1:1 for the first liquefied hydrocarbon flow to the second liquefied hydrocarbon flow, while subsequent blending points (e.g., 208 and / or 308) may have a blending ratio of 47:1 for the combined flow to the first liquefied hydrocarbon flow.

[0040]

[0046] Optionally and preferably, various blending scenarios (e.g., one or more blending points) and blending ratios within the provided range can be selected to achieve a volume blending ratio of at least 2:1, preferably at least 3:1, and more preferably at least 4:1 of LNG to ethane in the combined flow downstream of the final valve 162 and / or the final valve 126 (in the case of a scenario with a single blending point and / or multiple blending points having a subsequent blending point 208), or downstream of the subsequent blending point 308 (in the case of a scenario including blending point 308).

[0041]

[0047] The BOG management system 150 is not shown but may be present in other figures such as Figure 1, and the BOG conduit 148 is included as part of the existing infrastructure of the LNG plant as described herein and known to those skilled in the art, and should be understood to be present to provide fluid communication between the storage container 102 (or other container or vessel present on site) and the BOG management system 150 to manage the accumulation of BOG in the storage container 102 (or other container or vessel present on site). The BOG management system 150 may be bypassed during blending operations, as shown at least in Figures 1 and 2.

[0042]

[0048] Optionally, and preferably, a first LNG flow is pumped to the LNG-ethane blend point 108 at a volumetric flow rate and pressure that may be adjusted throughout the blending operation to meet the relevant process requirements. The flow velocity and pressure of the first LNG flow pumped to the blend point 108 may be adjusted, but it is preferable to minimize the rate of change in the operation of the first LNG flow to a reasonable and / or practical extent. On the other hand, the volumetric flow rate and pressure of the liquefied ethane flow in the ethane conduit 112 may be appropriately adjusted, as is known to those skilled in the art, to meet a desired blend ratio of LNG to liquefied ethane at the LNG-ethane blend point 108 in the case of a single blend point, ranging from 1:500, preferably 1:100 to 500:1, or to meet a range of blend ratios at other blend points in a scenario involving multiple blend points as described herein.

[0043]

[0049] The embodiments described herein provide options for implementation, such as a choice between a single-point blending operation or a multi-point process, to allow consideration of various factors when optimizing the blending operation as desired. For example, a facility having a hydraulic pressure limitation on a conduit segment upstream of the first blending point 108 (e.g., at least a portion of the first blending point conduit 110 has a reduced inner diameter, such as 12 inches or less, or a smaller inner diameter than the diameter of conduit 116 and / or conduit 112). Such limitations may restrict a single-point blending operation in terms of flow velocity and blend ratio possibilities (including a reduction in the amount of second liquefied hydrocarbon that can be blended) and higher operating costs, and in such scenarios a multi-point blending operation may be more suitable. In addition, multi-point blending operations allow for improved control and flexibility of the overall operation.

[0044]

[0050] Referring to Figures 1 to 4, the composite conduit 116 continues through the final valve 126 to provide a composite flow (which may be from one or more blending points) delivery system 106 downstream of the final valve 126. Optionally, and preferably, the operating pressure of the composite flow is increased by the delivery system 106 to produce a pressurized composite flow, which is supplied to a downstream LNG vaporization system to produce a regasified natural gas flow with a pressure suitable for entering a fluid-connected natural gas utility grid. Suitable means or apparatus for increasing the pressure in the delivery system 106 are provided elsewhere in this disclosure and can be selected by those skilled in the art based on conditions and parameters specific to a particular facility or apparatus.

[0045]

[0051] Optionally, in addition to or alternatively, the operating pressure of the composite flow in each composite conduit 116 (including 116A) and / or 160 and 116A may also be influenced, as will be understood by those skilled in the art, by the operating conditions of the downstream system communicating with the conduit located downstream of each final valve 162 or 126.

[0046]

[0052] Optionally, the blending operation can be further improved by providing an operating pressure higher than the saturation pressure of the combined flow in the receiving storage container (a storage container into which the combined flow is supplied, e.g., container 102), which reduces the time it takes to complete the blending operation. It should be understood that higher operating pressures are subject to limitations imposed by the safety operating parameters of each storage container. Preferably, the operating pressure of the container receiving the combined flow is at least 5% higher, more preferably at least 50% higher, and most preferably at least 100% higher than the saturation pressure of the combined flow. A suitable way to provide such a container having an operating pressure higher than the saturation pressure of the combined flow is, as is known to those skilled in the art, by adjusting the BOG pressure setpoint.

[0047]

[0053] The options for providing receiving storage vessels with operating pressures higher than the saturation pressure of the combined flow are limited by the safety operating parameters of each storage vessel and are not typical in standard operating practices for these vessels (primarily for the storage of liquefied hydrocarbons for transport), but can be implemented as desired. If higher operating pressures are used, they can be provided to each storage vessel temporarily for part or all of the duration of the blending operation, or maintained after the blending operation, as desired.

[0048]

[0054] Generally, for storage, it is desirable to maintain a relatively low operating pressure, preferably as low as possible within the relevant technical and contractual constraints, to maintain a correspondingly low temperature of the product in the storage vessel, thereby optimizing the volume of the storage vessel and reducing BOG formation. Even lower operating pressures over longer periods are more desirable, as they can help minimize changes in LNG quality over time. It should be understood that the standard practice of maintaining low operating pressure for receiving storage vessels is also available as an option for selection during some or all of the blending operations. Implementing the desired operating pressure for a particular receiving vessel is primarily achieved by managing the BOG of each vessel, which is typically done through the relevant BOG management system. During the blending operation, providing higher operating pressure to applicable storage vessels may reduce or potentially eliminate the rapid flow of the combined flow entering each vessel, thereby minimizing or eliminating the rate of boil-off gas formation associated with the blending operation. Minimizing or eliminating the rate of BOG formation during the blending operation relieves constraints on boil-off gas management, thereby shortening the operation time. Once the blending operation is complete, the operating pressure of each vessel may be reduced to return to the standard operating pressure, or optionally maintained in accordance with the relevant technical and contractual constraints imposed on the vessel and its cargo. The BOG (Body Overgrowth) can be managed after the blending operation using standard operating procedures, thereby allowing the blending operation to proceed without the time delays associated with BOG management.

[0049]

[0055] The method of this disclosure addresses certain adverse effects of blending two different liquefied hydrocarbons in a tank, e.g., stratification, by promoting in-line blending of two different liquefied hydrocarbons in a conduit under an operating pressure higher than the saturation pressure of the combined flow. Since the saturation pressure of the combined flow can fluctuate throughout its movement from the blending point 108 to its destination, e.g., back to the container 102, the reference to “saturation pressure of the combined flow” is generally in the context of a particular segment of the conduit. Adjusting the blend ratio and / or providing additional blending points, as described herein, are some preferred methods for manipulating the operating pressure of the relevant segment of the conduit and / or influencing the saturation pressure of the combined flow within the relevant segment to achieve a desired level of operating pressure higher than the saturation pressure of the combined flow, thereby ensuring that the combined flow remains in a liquid state.

[0050]

[0056] In addition, the method described herein further provides options for reducing the operating time of the blending operation by minimizing BOG control requirements during the blending operation, thereby by providing each receiving storage container with an operating pressure higher than the saturation pressure of the combined flow in order to minimize the rapid flow of the combined flow when the combined flow enters each storage container.

[0051]

[0057] As described herein, the methods herein can be used to perform blending operations of two flows of LNG and liquefied hydrocarbons such as liquefied ethane, particularly in existing facilities using infrastructure already in use in standard operations such as LNG regasification. For example, an LNG facility that supplies LNG or natural gas to downstream users aims to supply “rich” LNG to downstream users, which is limited by the influx of lean LNG from the global market, and the methods herein can be used to add liquefied ethane (or another lighter hydrocarbon or mixture of light hydrocarbons) to the LNG from the facility using existing infrastructure such as pumps, conduits, and valves. Where blending operations are desirable, specific operating parameters of the facility can be modified to implement the methods herein.

[0052]

[0058] During standard operation, the LNG import facility operates with its standard parameters to enable the regasification of LNG. If blending of LNG with another liquefied hydrocarbon is desired, the method described herein can be used with minimal modification to existing infrastructure and ease of transition between blending mode and normal plant operation mode (e.g., discharge for downstream processing). Before the blending operation begins, the product in storage container 102 is typically lean LNG, which can be further enriched with another liquefied hydrocarbon. Before combining lean LNG with other liquefied hydrocarbons such as ethane, the lean LNG is sent from storage container 102 to the LNG pier and back to the LNG storage container (for example, from container 102 to blend point 108 via conduit 110 (or another similar conduit), back to container 102 (or another container) via conduit 160, and then sent to delivery system 106, passing through the BOG management system 150 (partially or completely as shown in Figures 3 and 4), or completely bypassing the BOG management system 150 (as shown in Figures 1 and 2)).

[0053]

[0059] Before the second liquefied hydrocarbon stream is supplied to the first blending point 108, lean LNG from the storage vessel 102 is preferably supplied to the first blending point 108, supplied to the delivery system 106 at least via conduit 116, optionally returned to vessel 102 (both may be part of the normal delivery operation), and supplied to 106 to ensure cooling of at least the blending path of the combined stream. After the circulation of the first liquefied hydrocarbon is established, the second liquefied hydrocarbon stream can be pumped from the second vessel 114 according to embodiments described herein to initiate the blending operation. This includes supplying the combined stream to the delivery system 106 at an operating pressure higher than the saturation pressure of the combined stream. Additional advantages of recirculating LNG (under various circulation scenarios) (i) before the addition of the second liquefied hydrocarbon (e.g., liquefied ethane) and (ii) during the blending operation include keeping the various conduits cool, in particular to minimize vapor formation at the blending point 108 and to facilitate mixing. Furthermore, if desired and if the equipment is available, LNG circulation provides LNG to the BOG management system 150, thereby enabling the re-condensation of BOG upstream of the LNG delivery system 106. The lean LNG circulation as described above can be appropriately facilitated by various pumping devices such as pumps 118 and 120. Once lean LNG recirculation is established, if not already done, a liquefied ethane flow can be pumped from the ethane supply source 114 according to the embodiments described herein to initiate the blending operation. That is, the first LNG flow is pumped into the conduit network before the liquefied ethane flow.

[0054]

[0060] The combined flow can be returned to container 102 or another container as part of a circulation or recirculation path, while having an operating pressure higher than the saturation pressure of the combined flow in at least the portion of conduit 116 between blend point 108 and end valve 162. In addition to this, or alternatively, certain embodiments of the methods described herein provide the option of partially or completely bypassing storage containers such as container 102 by sending the combined flow to a delivery system 106 without being provided to containers such as 102 via conduit 160, under an operating pressure higher than the saturation pressure of the combined flow in at least the portion of conduit 116 between blend point 108 and end valve 126. The operating pressure of the combined flow is increased by the delivery system 106 to produce a pressurized combined flow, which is provided to a downstream LNG vaporization system to produce a regasified natural gas flow with a pressure suitable for entering a fluid-connected natural gas utility grid. Suitable means or apparatus for increasing the pressure in the delivery system 106 are provided elsewhere in this disclosure and can be selected by those skilled in the art based on conditions and parameters specific to a particular facility or apparatus.

[0055]

[0061] The operating parameters of the blending operation described herein affect the operating pressure of the conduit network compared to standard operating parameters. Optionally, and preferably, the conduit network is provided with an operating pressure of at least 2 bar g (bar gauge) to adapt to the shock from the blending operation while satisfying the operating parameters. Suitable methods for providing a conduit network with such an operating pressure are known to those skilled in the art. Once the blending operation is complete, such as when a second liquefied hydrocarbon, such as liquefied ethane, has been blended in a desired amount, the liquefied ethane flow is reduced and stopped. Standard operations are resumed, including returning the operating pressure of the conduit network to its standard parameters. The properties of the regasified blend product downstream of the delivery system 106, preferably the "rich" LNG compared to the LNG before blending, can be continuously monitored (e.g., Wobbe index) to ensure that the natural gas supplied to the utility grid meets specific specifications such as quality, flow rate, and pressure. During the blending operation, information regarding the quality of the regasified blended product (e.g., Wobbe index) is preferably provided to the blending operation to allow adjustment of the blend ratio between the two liquefied hydrocarbon streams and to ensure that the regasified blended product stream meets the desired product quality specifications. The same principle applies to applications where the blended LNG is supplied to other downstream users, such as in the case of a liquid-in / liquid-out terminal (described in

[0031] ). In embodiments where the operating pressure of each storage vessel, such as 102, is increased to exceed the saturation pressure of the combined stream, the operating pressure of each vessel may also be reduced to its standard parameter. After the blending operation, the blended product in vessel 102 may be stored as inventory or managed in other ways, such as distribution in accordance with contractual obligations.

[0056]

[0062]

[0063] In applications where the combined flow may be recirculated or distributed among various storage containers (not shown) so that at least a portion of the combined flow, including all of it, is delivered to the blend point as if it were lean LNG, accumulation of a second liquefied hydrocarbon (e.g., liquefied ethane) may occur. That is, if the blending operation is carried out over a period of time, the first liquefied hydrocarbon flow pumped to the first blend point 108 contains an increasing amount of the second liquefied hydrocarbon over time. Such accumulation can be explained by adjusting the blend ratio at the LNG-ethane blend point 108. The LNG facility typically includes equipment for continuously monitoring the characteristics of the LNG flowing through the conduit network, including sensors (e.g., flow rate). The continuous monitoring equipment allows for continuous adjustment of the flow rate of each flow, preferably the liquefied ethane flow, to achieve a desired blend ratio.

[0057]

[0064] Optionally, and preferably, the flow rate of the composite flow in the portion of the composite conduits 160 and 116 upstream of valve 162 and final valve 126 is preferably carried out under turbulent conditions.

[0058]

[0065] Although not illustrated, it should be understood that the principles described herein can be applied to provide a blend between a liquefied ethane transporter and a floating storage and regasification unit (FSRU), which typically comprises an LNG storage container, a BOG management system, and a delivery system.

[0059]

[0066] Methods provided herein, particularly those involving in-line mixing of a first LNG flow and a liquefied ethane flow under turbulent conditions, can maximize the mixing of LNG and liquefied ethane in the combined flow, thereby enabling the combined flow to exhibit homogeneous composition and characteristics (e.g., density), and as a result, the combined flow can be delivered homogeneously to the storage container 102 (or other container, whether on-site or on a ship) and / or to the delivery system 106, thereby mitigating the risk of fluid stratification or commercial problems at controlled transport points (e.g., natural gas grid injection points). However, in-line blending operations can introduce partial vaporization with two-phase flow formation due to the difference in specific enthalpy between the lean LNG flow and the liquid ethane flow, which can lead to the undesirable risk of excessive pipe vibration resulting in pipe stress and fatigue. Methods described herein address potential two-phase flow formation by maintaining the operating pressure of the combined flow higher than the saturation pressure of the combined flow.

[0060]

[0067] It should be understood that, although not illustrated, several embodiments, including all of the methods described herein, can be controlled and / or implemented using a computer program. This computer program may be called a controller. For example, a computer program can be used to control the discharge pressure and flow rate of a pump, the operating pressure of a system, in particular through the manipulation of the opening ratio of a flow control valve. Suitable computer programs include those executed by a data processor. Where used herein, references to computer programs are intended to be equivalent to references to program elements and / or computer-readable media containing instructions for controlling a computer system to coordinate the execution of the methods described herein. Computer programs may be implemented as computer-readable instruction code by using any suitable programming language, such as Java®, C++, etc., and may be stored in computer-readable media (such as removable disks, volatile or non-volatile memory, embedded memory / processors, etc.). The instruction code is operable to program a computer or any other programmable device to perform an intended function. Computer programs may be available from a network, such as the World Wide Web, and may be downloaded from there. The various embodiments described herein may each be implemented by a software computer program; however, they may also each be implemented by one or more specific electronic circuits or hardware. Furthermore, the present invention may be implemented in a hybrid form, i.e., a combination of software modules and hardware modules. In addition to or alternatively, any or all embodiments of the methods described herein may be performed manually by one or more human operators having relevant operational knowledge of the facility.

[0061]

[0068] While specific embodiments have been described herein, it should be understood that such descriptions are not intended to limit the embodiments described. Rather, any combination of the features and elements provided above, whether relating to a different embodiment or not, is intended to implement and practice the intended embodiments. Furthermore, while the embodiments disclosed herein may achieve advantages over other possible solutions or the prior art, whether or not a particular advantage is achieved by a given embodiment does not limit the scope of this disclosure. Accordingly, the aspects, features, embodiments, and advantages described herein are merely illustrative and should not be considered elements or limitations of the appended claims unless expressly stated in the claims.

Claims

1. A method for blending two or more liquefied hydrocarbon streams in a facility, wherein the facility - A first storage container (102) for storing a first liquefied hydrocarbon, wherein optionally the first liquefied hydrocarbon is liquefied natural gas, - A delivery system (106) for sending the first liquefied hydrocarbon to a downstream processing device, wherein the downstream processing device optionally includes a regasifier, - A network of conduits, i. A first blend point (108) located downstream of the first storage container (102) and upstream of the dispensing system (106), ii. A first conduit segment (110) for providing fluid communication between the first storage container (102) and the first blend point (108), iii. A second conduit segment (112) for providing fluid communication between a second source of liquefied hydrocarbons (114) and the first blend point (108), wherein the second conduit segment (112) optionally comprises the second liquefied hydrocarbons selected from the group consisting of liquefied ethane, liquefied butane, liquefied propane, and any combination thereof. iv. A composite conduit (116) for providing fluid communication between the first blend point (108) and the delivery system (106), comprising a network of conduits, wherein the composite conduit (116) includes a first final valve (126) located immediately upstream of the inlet of the delivery system (106), The method described above is (a) Pumping a first liquefied hydrocarbon stream from the first storage container (102) to the first blend point (108) via the first conduit segment (110), (b) Pressurizing a second liquefied hydrocarbon stream through the second conduit segment (112) from the supply source (114) of the second liquefied hydrocarbon to the first blend point (108), (c) To provide a composite flow by combining the first liquefied hydrocarbon flow and the second liquefied hydrocarbon flow at the first blending point (108) in a volume ratio of 1:500, preferably in the range of 1:100 to a maximum of 500:1, (d) To provide at least a portion of the combined flow from the first blend point (108), including all of it, to the delivery system (106) via the combined conduit (116), (e) A method comprising providing the combined flow with an operating pressure exceeding the saturation pressure of the combined flow (preferably at least 0.1 bar, more preferably at least 0.5 bar, and most preferably at least 1.2 bar) while the combined flow is in a segment of the combined conduit (116) between the first blend point (108) and the first final valve (126).

2. The conduit network further comprises a return composite conduit (160) for providing fluid communication between the first blend point (108) and the storage container, optionally the storage container being the first storage container (102), and the return composite conduit (160) comprising a second final valve immediately upstream of the outlet of the return composite conduit, and the method, To provide at least a portion of the composite flow from the segment of the composite conduit upstream of the first final valve (126) to the storage container, A method further comprising providing the portion of the composite flow with an operating pressure exceeding the saturation pressure of the composite flow (preferably at least 0.1 bar, more preferably at least 0.5 bar, and most preferably at least 1.2 bar) while the portion of the composite flow is between the segment of the composite conduit (116) between the first blend point (108) and the second final valve (126).

3. The method according to claim 2, wherein at least a portion of the combined flow, including all of it, is not provided to the storage container (102).

4. The composite conduit (116) is located upstream of the first final valve (126) and downstream of the first blend point (108), and further comprises a first subsequent blend point (208) optionally located either upstream or downstream of the return composite conduit (160), and the method is (f) The first source of liquefied hydrocarbons, optionally, provides a second flow of the first liquefied hydrocarbons from the first storage container (102) to the first subsequent blending point (208), (g) The method according to any one of claims 1 to 3, further comprising: (g) combining the combined flow and the second flow of the first liquefied hydrocarbon at the first subsequent blending point (208) in a volume ratio of 25:1, preferably 50:1 to a maximum of 500:1, and combining the first flow of the first liquefied hydrocarbon and the flow of the second liquefied hydrocarbon ethane at the first blending point (108) in a volume ratio of 1:500, preferably 1:100 to a maximum of 50:

1.

5. The composite conduit (116) further comprises a second subsequent blending point (308) located downstream of the final valve (126) and upstream of the blend product storage container (102), and the method, (f) Providing a third flow of the first liquefied hydrocarbon from the first liquefied hydrocarbon source to the second subsequent blending point (308), wherein the source is different from the first storage container (102) and optionally includes a boil-off gas management system (150). (g) The method according to claim 4, comprising: (g) combining the combined flow and the third flow of the first liquefied hydrocarbon at a second subsequent blending point (308) in a volume ratio of 25:1, preferably 50:1 to a maximum of 150:1, wherein the first liquefied hydrocarbon flow and the second liquefied hydrocarbon flow are combined at a first blending point (108) in a volume ratio of 1:500, preferably 1:100 to a maximum of 50:1, and the combined flow and the second flow of the first liquefied hydrocarbon are combined at a first subsequent blending point (208) in a volume ratio of 100:1, preferably 150:1 to a maximum of 500:

1.

6. The composite conduit (116) further comprises a subsequent blending point (308) located downstream of the final valve (126) and upstream of the blend product storage container (102), and the method is (f) Providing another flow of the first liquefied hydrocarbon from the first liquefied hydrocarbon source to the subsequent blend point (308), wherein the source is different from the first storage container (102) and optionally includes a boil-off gas management system (150). (g) The method according to claim 1, comprising combining the combined flow and the other flow of the first liquefied hydrocarbon at the subsequent blend point (308) in a volume ratio of 25:1, preferably 50:1 to a maximum of 500:1, and combining the first flow of the first liquefied hydrocarbon and the flow of the second liquefied hydrocarbon at the first blend point (108) in a volume ratio of 1:500, preferably 1:100 to a maximum of 50:

1.

7. The method according to any one of claims 1 to 6, wherein the combined flow downstream of the first final valve (126) and any subsequent blend point (308), and optionally downstream of the second final valve (162), comprises a volume ratio of at least 2:1, preferably at least 3:1, more preferably 4:1 of the first liquefied hydrocarbon, preferably LNG, to the second liquefied hydrocarbon, preferably liquefied ethane.

8. The method according to any one of claims 1 to 7, further comprising providing the conduit network with a total operating pressure of at least 2 barg.

9. The method according to any one of claims 1 to 8, further comprising reducing the operating pressure of the combined flow downstream of the second final valve (162) to below the saturation pressure of the combined flow.

10. The method according to claim 9, further comprising reducing the operating pressure of the combined flow downstream of the second final valve (162) to the storage pressure of the storage container (102).

11. The method according to any one of claims 1 to 10, wherein step (a) is performed before step (b).

12. The method according to claim 11, wherein step (a) comprises circulating the first flow of the first liquefied hydrocarbon from the first storage container (102) through the first portion of the conduit (110), the composite conduit (116), optionally back to the first storage container (102), and optionally through a boil-off gas management system (150).

13. The method according to any one of claims 1 to 12, wherein the second liquefied hydrocarbon is liquefied ethane, and the source of the liquefied ethane is selected from the group consisting of land storage, ethane transport ships, and any combination thereof.

14. The method according to any one of claims 1 to 13, wherein the facility includes an LNG regasification facility.

15. The method according to any one of claims 1 to 14, further comprising providing the contents of the storage container (102) to the dispensing system (106).

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