Process for blending two or more liquefied hydrocarbon streams

Abstract

A process for blending two liquefied hydrocarbon streams. The method includes pumping a first liquefied hydrocarbon stream to a first blending point; pumping the second liquefied hydrocarbon stream to a first blending point; the first liquefied hydrocarbon stream and the second liquefied hydrocarbon stream are combined at the blending point in a volume ratio of the first liquefied hydrocarbon stream to the second liquefied hydrocarbon stream of 1: 500, preferably 1: 100 and up to 500: 1 to provide a combined stream. The combined flow is provided from the first blending point to the delivery system via the combined conduit at an operating pressure above the saturation pressure of the combined flow at least as the combined flow travels from the first blending point to a final valve immediately upstream of the inlet of the delivery system.

Description

TECHNICAL FIELD

[0001] The present specification generally relates to the field of hydrocarbon blending, and more specifically to a method of blending two or more liquefied hydrocarbon streams. BACKGROUND

[0002] This section is intended to introduce the reader to various aspects of art that can be related to the exemplary embodiments of the present application and is not intended to limit the scope of the present application. The following discussion is intended to provide the reader with a better understanding of the various aspects of the present application relating to the nature of the art. Accordingly, the section is not admitted to be prior art merely by its inclusion in this section.

[0003] Generally, it is commercially important to liquefy natural gas at cryogenic temperatures to produce LNG, for more convenient storage and transportation. The basic reason for liquefying natural gas is that liquefaction results in a reduction in volume, which makes it possible to store and transport large quantities of liquefied gas in containers at low pressure or even at atmospheric pressure in an economic manner, and thus to provide a technically reliable and safe solution in cases where pipeline transportation is not practical or economically feasible.

[0004] It is known to blend the LNG product, which mainly comprises methane, with another component such as a light hydrocarbon (such as ethane, propane or butane) to increase the LNG heating value to meet market demand. For example, US20140338393 discloses a method of producing a blended mixture of liquefied natural gas by blending a lean liquefied natural gas and a rich liquefied natural gas together to meet specific requirements of an operator at a production facility, application site, or gas station. As another example, WO2005093017 discloses a composition comprising a mixture of natural gas and synthetic light hydrocarbons (such as C2 to C5 paraffins, olefins, and mixtures thereof) obtained by hydrocarbon synthesis reactions, suitable for use as a fuel composition, in particular a blend of such synthetic light hydrocarbons with natural gas derived from LNG produced in a LNG process. As yet another example, US8381544 discloses changing the heating value of liquefied natural gas by adding a higher heating value component, the method first using LNG to cool a higher heating value component stream, and then combining the higher heating value component with the LNG.

[0005] Further, US 11416012 discloses mixing hydrocarbon liquids from multiple vessels on-line into a single pipeline, wherein the hydrocarbon liquids are typically those that exist in a liquid state under atmospheric conditions, such as hydrocarbons, gasoline, crude oil, pyrolysis oil, etc. that exist as viscous liquids in subterranean geologic formations and on the surface. Thus, this patent reference does not address the challenge of blending liquefied hydrocarbons.

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

[0007] A method is provided for blending two or more liquefied hydrocarbon streams at a facility, the facility including a first storage vessel for storing a first liquefied hydrocarbon, the first liquefied hydrocarbon optionally being liquefied natural gas; a send-out system that sends the first liquefied hydrocarbon to a downstream processing plant, the downstream processing plant optionally including a regasification plant; and a network of conduits. The network of conduits includes: (i) a first blending point located downstream of the first storage vessel and upstream of the send-out system, (ii) a first conduit segment that provides fluid communication between the first storage vessel and the first blending point, (iii) a second conduit segment that provides fluid communication between a source of a second liquefied hydrocarbon and the first blending point, optionally the second liquefied hydrocarbon being selected from the group consisting of liquefied ethane, liquefied butane, liquefied propane, and any combination thereof; and (iv) a combined conduit that provides fluid communication between the first blending point and the send-out system. The combined conduit includes a first final valve immediately upstream of an inlet of the send-out system. The method includes: (a) pumping a first liquefied hydrocarbon stream from the first storage vessel to the first blending point via the first conduit segment; (b) pumping a second liquefied hydrocarbon stream from the source of the second liquefied hydrocarbon to the first blending point via the second conduit segment; (c) combining the first liquefied hydrocarbon stream and the second liquefied hydrocarbon stream at the first blending point at a volumetric ratio ranging from 1 :500, preferably 1 : 100, and up to 500: 1, to provide a combined stream; (d) providing at least a portion of the combined stream, including all of the combined stream, from the first blending point to the send-out system via the combined conduit, and (e) providing an operating pressure to the combined stream that is higher than a saturation pressure of the combined stream, preferably at least 0.1 bar higher, more preferably at least 0.5 bar higher, most preferably at least 1.2 bar higher, when the combined stream is located between the first blending point and the combined conduit segment upstream of the first final valve.

[0008] Optionally, in some embodiments, the network of conduits further includes a return combined conduit (160) that provides fluid communication between the first blending point and a storage vessel, optionally the storage vessel being the first storage vessel. The return combined conduit includes a second final valve immediately upstream of an outlet of the return combined conduit. In such embodiments, the method can further include providing at least a portion of the combined stream from the combined conduit segment upstream of the first final valve to the storage vessel; providing an operating pressure to the portion of the combined stream that is higher than a saturation pressure of the combined stream, preferably at least 0.1 bar higher, more preferably at least 0.5 bar higher, most preferably at least 1.2 bar higher, when the portion of the combined stream is located in the combined conduit segment between the first blending point and the second final valve.

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

[0010] Optionally, in some embodiments, the combination conduit further comprises a first subsequent blending point located upstream of the first final valve and downstream of the first blending point, and optionally upstream or downstream of the reflux combination conduit. In such embodiments, the method can further comprise: (f) providing a second stream of first liquefied hydrocarbons from a source of first liquefied hydrocarbons, optionally the first storage vessel, to the first subsequent blending point; (g) combining the combined stream and the second stream of first liquefied hydrocarbons at the first subsequent blending point at a volumetric ratio ranging from 25: 1, preferably 50: 1, and up to 500: 1, wherein the first stream of first liquefied hydrocarbons and the stream of second liquefied hydrocarbon ethane stream are combined at the first blending point at a volumetric ratio ranging from 1 :500, preferably 1 : 100, and up to 50: 1.

[0011] Optionally, in some embodiments, the combination conduit further comprises a second subsequent blending point located downstream of the final valve and upstream of the blended product storage vessel. In such embodiments, the method can further comprise: (f) providing a third stream of first liquefied hydrocarbons from a source of first liquefied hydrocarbons to the second subsequent blending point, such source being different from the first storage vessel, and which can optionally comprise an evaporated gas management system (150); (g) combining the combined stream and the third stream of first liquefied hydrocarbons at the second subsequent blending point at a volumetric ratio ranging from 25: 1, preferably 50: 1, and up to 150: 1, wherein the first stream of LNG and the stream of ethane are combined at the first blending point at a volumetric ratio ranging from 1 :500, preferably 1 : 100, and up to 50: 1, and wherein the combined stream and the second stream of first liquefied hydrocarbons are combined at the first subsequent blending point at a volumetric ratio ranging from 100: 1, preferably 150: 1, and up to 500: 1.

[0012] Optionally, in some embodiments, the combination conduit further comprises a subsequent blending point located downstream of the final valve and upstream of the blended product storage vessel. In such embodiments, the method can further comprise: (f) providing another stream of first liquefied hydrocarbons from a second source of first liquefied hydrocarbons to the subsequent blending point, optionally such source being different from the first storage vessel, optionally comprising an evaporated gas management system; (g) combining the combined stream and the another stream of first liquefied hydrocarbons at the subsequent blending point (308) at a volumetric ratio ranging from 25: 1, preferably 50: 1, and up to 500: 1, and wherein the first stream of first liquefied hydrocarbons and the stream of second liquefied hydrocarbons are combined at the first blending point at a volumetric ratio ranging from 1 :500, preferably 1 : 100, and up to 50: 1.

[0013] Optionally, in some embodiments, the combined stream is downstream of the first final valve and any subsequent blending points, and it can also optionally be downstream of the second final valve. In such embodiments, the combined stream can have a volume ratio of the first liquefied hydrocarbon, preferably LNG, to the second liquefied hydrocarbon, preferably liquefied ethane, of at least 2: 1, preferably at least 3: 1, and more preferably 4: 1.

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

[0015] Optionally, in some embodiments, the method can further include reducing the operating pressure of the combined stream downstream of the second final valve to less than the saturation pressure of the combined stream. In such embodiments, the method can further include reducing the operating pressure of the combined stream downstream of the second final valve to the storage pressure of the storage vessel.

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

[0017] Optionally, in some embodiments, the second liquefied hydrocarbon can be liquefied ethane, and the source of the liquefied ethane is selected from the group consisting of onshore storage and ethane carrier ships, and any combination thereof.

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

[0019] Optionally, in some embodiments, the method can further include providing the contents of the storage vessel to a send-out system. BRIEF DESCRIPTION OF DRAWINGS

[0020] Figure 1 A diagram depicting an exemplary embodiment of a system for blending two or more liquefied hydrocarbon streams according to aspects disclosed in the present disclosure.

[0021] Figure 2 A diagram depicting another exemplary embodiment of a system for blending two or more liquefied hydrocarbon streams according to aspects disclosed in the present disclosure.

[0022] Figure 3 A diagram depicting yet another exemplary embodiment of a system for blending two or more liquefied hydrocarbon streams according to aspects disclosed in the present disclosure.

[0023] Figure 4FIG. 1 depicts an exemplary embodiment of a system for blending two or more liquefied hydrocarbon streams according to aspects disclosed in the present disclosure. DETAILED DESCRIPTION

[0024] The present application will now be described in detail by referring to embodiments of the application as illustrated in the drawings. References to "one embodiment," "an embodiment,” "exemplary embodiment,” etc. indicate that the described embodiment can include a particular feature, structure, or characteristic, but every embodiment can not necessarily include the particular feature, structure, or characteristic. Moreover, such phrases are not necessarily referring to the same embodiment. Furthermore, when a particular feature, structure, or characteristic is described in connection with an embodiment, it is submitted that it is within the knowledge of those skilled in the art to effect such feature, structure, or characteristic in connection with other embodiments whether or not explicitly described. Other suitable modifications and adaptations of various conditions and parameters normally encountered in the field and / or of the described implementations as derived from the consideration of this disclosure within its spirit and scope, will be evident to those skilled in the art.

[0025] While the forgoing description provides many specifics, for the purpose of illustration, one of skill in the art will appreciate that the implementation can be practiced without some or all of these specifics. In other instances, well known process steps and / or structures have not been described in detail in order to not unnecessarily obscure the application. The features and advantages of the implementations can be better understood with reference to the drawings and following discussion.

[0026] In addition, when like elements are used in one or more of the drawings, the same reference numerals are used in all of the drawings and the detailed description, and only the first occurrence of the element is described in some detail. Some features or components of the systems or methods described herein can be omitted in certain depicted configurations for the sake of clarity.

[0027] When LNG product is blended with lighter hydrocarbons, there is a general concern about the formation of different density stratified liquid layers (or strata) in the storage vessel. Typically, heat leaking into the blended LNG product via the storage vessel walls will slowly heat the blended LNG in contact with the vessel walls and floor. This warmer blended LNG has a lower density, which increases its buoyancy, slowly causing the warmer blended LNG to rise in the bulk LNG inventory. At the top of the liquid column (the liquid-vapor interface), the warmer LNG releases the accumulated excess heat by evaporation, becomes cooler and denser, which in turn reduces its buoyancy, slowly causing the cooler blended LNG to sink in the bulk LNG inventory. This natural convection will occur continuously as long as the density difference within the blended LNG bulk inventory is less than 1%. In the event that the density difference in the bulk is greater than 1%, different LNG layers will form, thereby interrupting the natural convection of the bulk LNG. Maintaining homogeneity and mitigating stratification is necessary when there is a possibility of introducing LNG blends with different densities into the same vessel, particularly when the density difference between, for example, lean LNG (methane) and liquefied ethane in this case is at least 10%. Once a stratified liquid layer is formed, a turnover can occur when the density difference between the two layers becomes small enough for natural convection from the bottom layer to reach the free surface. Subsequent mixing of these layers is accompanied by a large increase in the normal vaporization rate, which will be proportional to the excess heat accumulated in the bottom layer. This physical phenomenon associated with the mixing of stratified layers of LNG is commonly and descriptively referred to as "turnover". However, a high intensity turnover can result in vapor release that exceeds the design vapor handling capacity of the vessel, and thus can cause overpressure and potentially rupture the storage vessel.

[0028] While the present disclosure generally refers to LNG and ethane as the two liquefied hydrocarbon streams that benefit from the blending methods described herein, it should be understood that the principles provided by the present disclosure are applicable to blending other liquefied hydrocarbon streams, such as (i) LNG with liquefied propane, or (ii) LNG with a mixture of liquefied ethane, liquefied propane, liquefied butane, and any combination thereof.

[0029] As used herein, the term "hydrocarbon" has its ordinary meaning, which includes molecules composed of carbon and hydrogen in various combinations, and can be of fossil (e.g., natural gas) or biological origin (e.g., biogenic methane). The term "liquefied hydrocarbon" refers to a hydrocarbon that exists as a gas at atmospheric pressure and temperature, and will change state and become a liquid under new pressure and temperature conditions due to a decrease in temperature and / or an increase in pressure, or a combination of both. In some cases (as in the case of natural gas liquefaction), this phase change can also be combined with a subsequent operational pressure reduction to meet downstream processes (e.g., atmospheric storage of LNG), further reducing the temperature of the liquefied hydrocarbon stream. The specific combination of pressure and temperature at which a gas is liquefied varies with the type of hydrocarbon. Additionally, hydrocarbons can be described as light or heavy depending on the number of carbon atoms and hydrogen atoms in the molecule. Examples of liquefied hydrocarbons include alkanes (or paraffins) (such as methane - CH4; ethane - C2H6; propane C3H8; butanes: n-butane and isobutane - C4H10; natural gasoline or pentanes plus - C5H12; and heavier substances); and alkenes (or olefins) (such as ethylene - C2H4, propylene - C3H6, n-butenes and isobutenes - C4H8). 10 12 44

[0030] ​​​The present disclosure provides methods for blending operations of two liquefied hydrocarbon streams at an LNG facility to produce a liquefied natural gas having a desired composition that mitigates the risk of stratification. Further, certain embodiments of the methods of the present disclosure allow for at least a portion (including all) of the blended product stream to be directed to a send-out system with the option of partially or completely bypassing a storage vessel. As used herein, the term send-out system has its ordinary meaning and generally refers to pump equipment that sends a liquefied hydrocarbon stream, such as LNG, to downstream processing, such as converting the liquefied hydrocarbon stream to a vapor for delivery to a pipeline system for consumer use, and / or loading the liquefied blended product for distribution, including ISO containers, road or rail cars, fueling, etc. In the context of a facility, particularly a regasification facility, the facility typically provides liquefied hydrocarbon to a send-out system for downstream processing via a storage vessel that is in fluid communication with such send-out system. Embodiments of the present disclosure provide the option of providing the blended product to the send-out system without first passing the blended LNG stream through a storage vessel, thereby improving operational efficiency. Additionally, such bypassing of the storage vessel reduces the need to interface a boil-off gas (BOG) management system that is used to manage BOG formed from the portion that enters the receiving vessel. This is particularly valuable for BOG management systems that are operational constraints, particularly significant constraints, of the asset. Further, such bypassing of the storage vessel reduces and even potentially eliminates any risk associated with stratification in the storage vessel, thereby allowing for relaxation of the proposed mitigation measures. Embodiments of the inventive methods can provide other additional benefits that will be apparent to those of ordinary skill in the art. Additionally, certain embodiments of the methods described herein can be suitably adapted for blending of lean LNG with liquefied ethane to meet desired LNG and / or natural gas specifications (such as Wobbe Index (WI), Lower Heating Value (LHV), Methane Number (MN), or Incomplete Combustion Factor (ICF)) at various LNG facilities or sites using existing infrastructure of the respective site.

[0031] Figures 1 to 4 Various facilities are depicted that include a storage vessel 102 for storing a first liquefied hydrocarbon, preferably LNG, and a send-out system 106 for providing a liquefied hydrocarbon stream to downstream processing, such as a regasification plant. The depicted facilities also include a network of conduits in fluid communication with both the storage vessel 102 and the send-out system 106. Optionally, the LNG facility can also include a return combination conduit 160 to provide fluid communication between the combination conduit 116 and the storage vessel 102. Although Figures 1 to 4Conduit 160 is depicted as directing the combined stream from conduit 116 to vessel 102, but it should be understood that the conduit can alternatively or additionally direct the combined stream from conduit 116 to another suitable storage vessel (onshore and / or marine vessel) even if not explicitly depicted. Generally, liquefied natural gas (LNG) is natural gas (primarily methane) that has been liquefied. It should be understood that certain portions of the conduit network, such as recirculation and loading / unloading conduits, are omitted from the drawings, such as not explicitly mentioned, but are still part of the facility as understood by one of ordinary skill in the art. Depending on the application, LNG can be stored in vessels 102 and / or 106 at temperatures below -110°C, and more typically below -145°C, such as between -159°C and -162°C. At the beginning of the blending operation, the LNG in vessel 102 is typically lean LNG. In certain embodiments involving directing the combined or blended stream back to vessel 102, then the composition of the LNG will be“richer” at the end of the blending operation than at the beginning. Generally speaking, “lean” LNG has a relatively lower heating value, while“rich” LNG contains a greater proportion of heavier hydrocarbons, which impart a higher heating value. Lean LNG can be further enriched, such as by the methods described herein, to meet various market quality specifications, such as Wobbe Index (WI), Lower Heating Value (LHV), Methane Number (MN), or Incomplete Combustion Factor (ICF).

[0032] The conduit network includes a first blending point, which can be referred to as LNG-ethane blending point 108, located between the dock and storage vessel (102) with reference to the preferred embodiment. The conduit network also includes a first conduit segment 110 (which can be referred to as LNG conduit 110 for the preferred embodiment where the first liquefied hydrocarbon is LNG) and a second conduit segment 112 (which can be referred to as ethane conduit 112 for the preferred embodiment where the second liquefied hydrocarbon is ethane). The first conduit segment 110 provides fluid communication between the first storage vessel 102 and the first blending point 108. The second conduit segment 112 provides fluid communication between a storage vessel 114 for the second liquefied hydrocarbon and the first blending point 108. With reference to the preferred embodiment where the second liquefied hydrocarbon is ethane, vessel 114 can be referred to as ethane source 114. The first blending point 108 is a fluid conduit junction between the first conduit segment 110 and the second conduit segment 112. Preferably, the first blending point 108 is a junction at or near the connection between the recirculation line and the offloading line. As can be seen, blending point 108 is also upstream of the send-out system 106. The blending point 108 is a fluid conduit junction known to those of skill in the art. For example, suitable examples of blending point 108 include a tee junction, a Y-junction, a mixing tee, a Y-tube fitting, and any combination thereof.

[0033] In a preferred embodiment, the second liquefied hydrocarbon is ethane. Depending on the application, the liquefied ethane can be stored at temperatures below -30°C, and more typically below -75°C, such as between -80°C and -89°C. Although Figure 1 Ethane source 114 is depicted as being on a vessel, such as a liquefied ethane carrier, but it should be understood that ethane source 114 can additionally or alternatively be a land-based storage vessel as known to those of ordinary skill. The network of conduits further includes a combination conduit 116 to provide fluid communication between the first blending point 108 and the send-out system 106 for downstream processing, such as conversion of the liquefied hydrocarbon stream to a vapor for delivery to a pipeline system for consumer use. In certain assets, such as a liquid-in liquid-out LNG asset, the send-out system can include cryogenic distribution pipelines, or alternatively pump equipment and LNG loading facilities for LNG ships (e.g., fueling ships), LNG highway tankers, LNG rail cars, and / or LNG ISO containers.

[0034] Suitable storage for liquefied hydrocarbons such as LNG, liquefied ethane, and other substances mentioned herein are known to those of ordinary skill. For example, a suitable example can include a single containment system, which generally has an inner wall or primary container that contains the refrigerated liquid and can be self-supporting. The inner container can be surrounded by an outer wall, thereby forming an annular space that can be kept insulated. The single containment system can be further insulated, such as the base and top, as well as external insulation. Another suitable example includes a double containment system, which generally adds a secondary wall that is capable of containing both liquid and vapor over the single containment system.

[0035] A first stream of the first liquefied hydrocarbon, preferably liquefied natural gas (LNG), is pumped from the storage vessel 102 through a first conduit segment 110 (which can be referred to as a LNG conduit 110 for the preferred embodiment) to the first blending point 108. See Figure 1Pumping of the LNG stream can be accomplished at least by pump equipment 120. The liquefied ethane stream is pumped from the ethane source 114 through the ethane conduit 112 to the LNG-ethane blending point 108. As used herein, the term "liquefied ethane," "liquid ethane," or "ethane" refers to a liquefied hydrocarbon stream comprising at least 50 mol%, preferably at least 95 mol% ethane. As mentioned elsewhere in this disclosure, liquefied hydrocarbons other than LNG and liquefied ethane can be blended using the methods described herein. For example, if LNG is blended with liquefied propane, the liquefied hydrocarbon stream that is liquefied propane comprises at least 50 mol%, preferably at least 95 mol% propane; and if it is liquefied butane, the stream comprises at least 50 mol% butane, preferably at least 95 mol%. Optionally, if the liquefied hydrocarbon stream is not comprised substantially of its namesake component (e.g., the liquefied ethane stream is not substantially all ethane), the remainder of the stream is selected from the group consisting of ethane, methane, propane, butane, and any combination thereof, as applicable. For example, an example of a mixture of liquefied hydrocarbons as defined herein can be LPG, which stands for liquefied petroleum gas, which includes mixtures that are predominantly propane, predominantly butane, or a mixture of both propane and butane.

[0036] Referring to Figure 1 Pumping of the liquefied ethane stream can be accomplished at least by pump equipment 118. The first LNG stream and the ethane stream are combined at the LNG-ethane blending point 108 at a volumetric blend ratio of LNG to ethane in the range of 1 :500 and up to 500: 1, preferably 1 : 100 and up to 500: 1, and more preferably 1 : 10 and up to 500: 1, to provide a combined stream. It will be appreciated that a person of ordinary skill can take into account various factors, such as the specifications and safe operating ranges (SOEs) of equipment and infrastructure involved in the blending operation (e.g., conduit networks, pumps, storage vessels, valves, etc.), to select suitable flow rates of the first LNG stream and the liquefied ethane stream to achieve the desired blend ratio within the ranges described herein. The appropriate number of pumps and types of pumps to implement the methods described herein are known to a person of ordinary skill. Additionally or alternatively, the pump equipment can be part of existing infrastructure and equipment of a facility, such as a regasification plant.

[0037] In one embodiment, the combined stream can be provided from the first blending point 108 to the blended product storage send-out system 106 via at least the combination conduit 116, back to the vessel 102 via conduit 160 or not, and / or to another suitable storage vessel. In certain embodiments, if the combined stream is directed back to the vessel 102, the product in the vessel 102 can also be directed to the send-out system 106, typically using existing infrastructure (not shown) of the particular facility such as the LNG import facility. Preferably, the flow rates of the LNG stream and the flow rate of the ethane stream provide a suitable force to move the combined stream to the send-out system 106, or to the LNG storage vessel 102 (or another storage vessel (not depicted)), by way of the respective pumps, without the need for additional pumping equipment.

[0038] The conduit network can include a plurality of valves as known to those of ordinary skill in the art to control the flow of the various streams. See, for example, Figure 1 Optionally, the LNG conduit 110 can include a valve 122 to control the flow of the first LNG stream from the storage vessel 102 to the LNG-ethane blending point 108. Optionally, the ethane conduit 112 includes a valve 124 to control the flow of the liquefied ethane stream from the ethane source 114 to the LNG-ethane blending point 108. In embodiments that include the return combination conduit 160, the conduit 160 can include a valve 162 to control the flow from the combination conduit 116 to the vessel 102 (and / or another suitable storage vessel (not shown)). The valve 162 can be manipulated or controlled to allow the combined stream to partially or completely bypass the vessel 102. Regardless of the number of valves positioned throughout the conduit network (such as the LNG conduit 110, the ethane conduit 112, and the combination conduits 160 and 116) to control the flow of the respective streams, the conduit network includes a final valve 126. The final valve 126 is the last valve that the combined stream flows through before being introduced to the send-out system 106. That is, the final valve 126 is the valve that is immediately upstream of the inlet to the blended product storage vessel send-out system 106. For embodiments that also include the return combination conduit 160, the valve 162 is also considered to be another final valve before the combined product is introduced to the vessel 102.

[0039] At least during the blending operation, the combined conduit 116 and optional conduit 160 has an operating pressure, at least due to the flow of the merged stream through the respective combined conduit 116 and forces exerted by any available flow control devices in the conduit, such as the final valve 126 and optional valve 162. As the merged stream is provided to its destination (the offloading system 106 and / or the vessel 102 (or another vessel)), the portion of the respective combined conduit 116 and / or 160 between the LNG-ethane blending point 108 and upstream of the respective final valve 126 and / or 162 is provided with an operating pressure that is higher than the saturation pressure of the merged stream, preferably at least 0.1 bar higher than the saturation pressure of the merged stream, more preferably at least 0.5 bar higher, and most preferably at least 1.2 bar higher. An operating pressure that is at least 1.2 bar higher than the saturation pressure of the merged stream is most preferred as it provides the most preferred cushion to accommodate fluctuations in pressure conditions along the conduit 116, but embodiments with lower operating pressures higher than the saturation pressure of the merged stream can still provide the benefits described herein. The saturation pressure of the merged stream can change as it travels through the conduit 116 towards the blended product storage vessel 106 due to, at least, heat transfer from the environment and / or equipment. Generally, the saturation pressure of the merged stream increases as it travels through the combined conduit 116 towards the vessel 106. The operating pressure of the combined conduit 116 between the LNG-ethane blending point 108 and the final valve 126 is preferably adjusted frequently in response to monitoring to accommodate the increase in saturation pressure, and / or the saturation pressure of the merged stream can be reduced to ensure that the operating pressure remains higher than the saturation pressure of the merged stream as the saturation pressure changes. In addition to other benefits described elsewhere in this disclosure, by providing an operating pressure in the portion of the combined conduit 116 between the blending point 108 and the final valve 126 that is equal to or higher than the saturation pressure of the merged stream, the methods described herein mitigate two-phase flow formation (whether partial or sustained two-phase flow formation) in that portion of the combined conduit 116. Thus, as is known to one of ordinary skill in the art, the methods described herein can minimize operational disturbances and equipment damage (e.g., cavitation-driven corrosion of valves). The term “saturation pressure” has its ordinary meaning and includes the definition of the pressure at which a fluid exists as both a vapor and a liquid, and for a given temperature, the rate of evaporation is equal to the rate of condensation. In this case, the saturation pressure of the merged stream is the pressure at which the merged stream exhibits both a gas phase and a liquid phase that are in thermodynamic equilibrium at the temperature of the merged stream. One of ordinary skill can appropriately determine the saturation pressure of the merged stream based on the temperature of the merged stream and the blending ratio (both of which can be measured by sensors) while in the respective combined conduit 160 and / or 116 between the LNG-ethane blending point 108 and the respective final valve 126 and / or 162. The conduit network can include suitable sensors known to one of ordinary skill in the art to provide the relevant data to implement the methods described herein.Examples of suitable sensors include a hydrometer, gravimeter, densimeter, density measurement sensor, gravity measurement sensor, pressure transducer, temperature sensor, flow meter, mass flow meter, Coriolis flow meter, other measurement sensors for determining density, gravity, or other variables as will be appreciated by those skilled in the art, or some combination thereof. Determination of the saturation pressure of the combined stream can be done manually or autonomously using a computer or other similar process control system, such that subsequent corrective action (e.g., increasing system operating pressure, increasing blend ratio, or other) can be implemented as needed. The methods described herein provide an operating pressure in the respective combined conduit 116 and / or 160 between the LNG-ethane blend point 108 and the respective final valve 126 or 162 that is higher than the saturation pressure of the combined stream, preferably at least 0.1 bar higher, more preferably at least 0.5 bar higher, and most preferably at least 1.2 bar higher than the saturation pressure of the combined stream. Providing such an operating pressure that is higher than the saturation pressure of the combined stream enables the combined stream to remain in a liquid phase as it flows through these conduit segments, regardless of how the pressure conditions vary along such conduit segments.

[0040] Suitably, the operating pressure of the combined stream in the combined conduit, as well as other portions of the conduit network, can be monitored, such as by a sensor, as will be appreciated by those of ordinary skill in the art. Monitoring can allow for continuous monitoring of the operating conditions of the combined stream to ensure that the operating pressure in the combined conduit 116 remains higher than the saturation pressure of the combined stream (preferably at least 0.1 bar, 0.5 bar, or 1.2 bar higher). Optionally and preferably, the operating pressure of the combined stream upstream of the respective final valve 162 or 126 that is higher than the saturation pressure of the combined stream can be provided by adjusting the percent opening of the respective final valve 126 or 162 to provide the desired operating pressure upstream of the respective final valve. The percent opening of the final valve 126 can be continuously adjusted as needed during blending operations to provide the desired operating pressure at or above the saturation pressure of the combined stream as described herein.

[0041] Optionally, additionally, or alternatively, the saturation pressure of the combined stream can be reduced at the LNG-ethane blend point 108 and / or along the combined conduit 116 by providing an additional blend point by adjusting the volumetric ratio of the first LNG stream and the liquefied ethane. Generally, an additional blend point allows for more LNG to be added to the combined stream, which reduces the saturation pressure of the combined stream, providing another option to ensure that the operating pressure of the combined stream is achieved to be higher than the saturation pressure of the combined stream. See, for example, Figure 2 The combined conduit 116 further includes a subsequent blend point 208 located upstream of the valve 162 (if present), upstream of the final valve 126, and downstream of the LNG-ethane blend point 108. As Figure 2As can be seen, the conduit network further includes another conduit segment 216 (which can be referred to as a second LNG conduit 216 for the preferred embodiment) to provide fluid communication between the storage vessel 102 (or a second suitable source of LNG, which is not depicted in Figure 2 the drawings) and the subsequent blend point 208. In the case where the second LNG stream is from the storage vessel 102, the second LNG conduit 216 can provide fluid communication between the subsequent blend point 208 and the vessel 102 via connection with the LNG conduit 110, or it can be connected directly to the vessel 102. When desired, a second stream of the first liquefied hydrocarbon (preferably LNG) can be provided from the storage vessel 102 (or a second source of LNG) to the subsequent blend point 208 via the second LNG conduit 216. Optionally and preferably, the second LNG conduit 216 can further include a valve 222 to control the flow of the second LNG stream through the second LNG conduit 216. For example, the valve 222 can be closed when blending is not desired at the subsequent blend point 208, and the valve can be opened when additional LNG is desired to be blended into the combined stream. The valve 222 can be adjusted to achieve the desired blend ratio at the subsequent blend point 208. In Figure 2 the drawings, the combined stream and the second LNG stream are combined at the subsequent blend point 208 in a ratio ranging from 25: 1, preferably 50: 1, and up to 500: 1, and the first LNG stream and the ethane stream are combined at the LNG-ethane blend point 108 in a ratio ranging from preferably 1 : 100 and up to 50: 1. Because of the additional blend point provided, the ratio of LNG to ethane at the LNG-ethane blend point 108 can be less than if there were only a single blend point (i.e., 108). For example, in a single blend point scenario, the ratio of LNG to ethane at the LNG-ethane blend point is in the range of 1 : 500 and up to 500: 1, whereas in a multiple blend point scenario as Figure 2 depicted, the ratio of LNG to ethane at the LNG-ethane blend point 108 is in the range of 1 : 500, preferably 1 : 100, and up to 50: 1, and the ratio of the combined stream to the second LNG stream at the subsequent blend point 208 is in the range of 25: 1, preferably 50: 1, and up to 500: 1. As will be understood by one of ordinary skill in the art, for a multiple blend point scenario, the blend ratio ranges provided can be extended or changed to suit asset and / or process specific requirements. For example, a first blend point can have a blend ratio of 1 : 1, while a second blend point can have a blend ratio of 47: 1.

[0042] Optionally, additionally, or alternatively, there can be different blend points downstream of the final valve 126. For example, see Figure 3The combined conduit 116 also includes a subsequent blending point 308 downstream of the final valve 126 and upstream of the send-out system 106. Optionally and alternatively, the subsequent blending point 308 can be located upstream of the final valve 126, depending on the specific arrangement of the existing infrastructure of the plant where the blending operation is being performed. The conduit network can also include a BOG conduit 148 that provides fluid communication between the storage vessel 102 (and / or the vapor space of other containers available at the LNG asset, but not depicted in the provided figures) and a boil-off gas (BOG) management system 150. During operation of the LNG facility 100, including when LNG is stored in the vessel 102, BOG is generated in the vessel 102 (and / or other containers available at the LNG asset, but not depicted in the provided figures) due to, at least, heat leakage from the environment and / or energy input from the unloading pumps, as well as flash vapor due to the pressure differential between the LNG carrier and the storage vessel 106. The BOG (in vapor phase) is typically removed from the storage vessel 102 (and / or other containers available at the LNG asset, but not depicted in the provided figures) to mitigate the effects of pressure build-up caused by the BOG remaining in the vessel 102. The BOG management system 150 typically includes a boil-off gas compressor and a condenser column to condense (although other technical options and configurations can be applied) and recover the BOG as LNG, which is provided to the send-out system 116A via a return conduit 316.

[0043] As can be seen in Figure 3 , the conduit network also includes a third LNG conduit 316 to provide fluid communication between a source of a first liquefied hydrocarbon (such as LNG, which can be different from the vessel 102, optionally the BOG management system 150 as depicted) and the subsequent blending point 308. When needed, another LNG stream can be provided from the BOG management system 150 to the subsequent blending point 308 via the third LNG conduit 316. Although not depicted, it should be understood that the third LNG conduit 316 can also include a valve to control the flow of LNG stream therethrough. In Figure 3 , the combined stream and the LNG stream from the BOG management system 150 are combined at the subsequent blending point 208 at a ratio in the range of 25: 1, preferably 50: 1, and up to 500: 1, and the first LNG stream and the ethane stream are combined at the LNG-ethane blending point 108 at a ratio in the range of preferably 25: 1, preferably 50: 1, and up to 500: 1. For the Figure 3 multi-blending point scenario depicted in , the blending ratio of LNG to ethane at the LNG-ethane blending point 108 is in the range of 1:500, preferably 1: 100, and up to 50: 1, and at the subsequent blending point 308, the ratio of the combined stream to the LNG stream from the BOG management system 150 is in the range of 25: 1, preferably 50: 1, and up to 500: 1 at the subsequent blending point 308.

[0044] Referring to Figure 3 and Figure 4 , the conduit network can also optionally include a conduit 152 downstream of the blend point 108 and blend point 208 (if present) to provide fluid communication between the combined conduit 116 and the BOG management system 150. As standard in recondenser-based BOG management systems, at least a portion of the merged stream can be provided to the BOG management system 150 for recondensing the BOG stream 148 (and / or other BOG streams originating from other LNG storage vessels or on-site processes, but not shown in the provided figures). The blended LNG conduit 152 can also include a valve (not shown) to allow control of the amount of merged stream (if any) provided to the BOG management system 150. Optionally, alternatively, or additionally, the blended LNG stream 152 can be used for another purpose internal or external to the BOG management system 150, not shown in the provided figures.

[0045] Optionally, additionally, or alternatively, two additional blend points can be present with the LNG-ethane blend point 108. For example, referring to Figure 4 , the combined conduit 116 includes a subsequent blend point 208 and a subsequent blend point 308 as described in Figure 2 and Figure 3 , respectively. For the multi-blend point scenario depicted in Figure 4 , (i) the blend ratio of LNG to ethane at the LNG-ethane blend point 108 is in the range of 1 :500, preferably 1 : 100, and up to 50: 1, (ii) the blend ratio of the merged stream to the second LNG stream at the subsequent blend point 208 is in the range of 25: 1, preferably 50: 1, and up to 150: 1, and (iii) the blend ratio of the merged stream to the LNG stream from the BOG management system 150 at the subsequent blend point 308 is in the range of 100: 1, preferably 150: 1, and up to 500: 1. Depending on the particular configuration of the assets implementing the blending process, the conduit network can include more than three blend points (such as 108, 208, and 308) depicted in the figures to achieve the desired operating pressure higher than the saturation pressure of the merged stream. As understood by one of ordinary skill in the art, for multi-blend point scenarios, the provided blend ratio ranges can be extended or changed to suit asset and / or process-specific requirements. For example, a first blend point (such as 108) can have a blend ratio of the first liquefied hydrocarbon stream to the second liquefied hydrocarbon stream of 1 : 1, while a subsequent blend point (such as 208 and / or 308) can have a blend ratio of the merged stream to the first liquefied hydrocarbon stream of 47: 1.

[0046] Optionally and preferably, various blending scenarios (such as single or multiple blending points) and blending ratios within the provided ranges can be selected to achieve a volumetric blending ratio of LNG to ethane of at least 2: 1, preferably at least 3: 1, more preferably at least 4: 1 in the combined stream downstream of final valve 162 and / or final valve 126 (for scenarios involving a single blending point and / or multiple blending points with a subsequent blending point 208) or downstream of subsequent blending point 308 (for scenarios including blending point 308).

[0047] It will be appreciated that BOG management system 150 can be present in other figures such as Figure 1 where BOG conduit 148 is present to provide fluid communication between storage vessel 102 (or other container or reservoir present at the site) and BOG management system 150 to manage BOG accumulation in storage vessel 102 (or other container or reservoir present at the site) as described herein and known to one of ordinary skill, including as part of the existing infrastructure of an LNG plant. BOG management system 150 can be bypassed during blending operations, such as at least Figure 1 and Figure 2 as shown in

[0048] Optionally and preferably, the first LNG stream is pumped to LNG-ethane blending point 108 at a volumetric flow rate and pressure, which can be adjusted throughout the blending operation to meet the relevant process requirements. While the flow rate and pressure of the first LNG stream pumped to blending point 108 can be adjusted, it is preferred to minimize the rate of change in operation of the first LNG stream to a reasonable and / or practical extent. At the same time, the volumetric flow rate and pressure of the liquefied ethane stream in ethane conduit 112 can be adjusted as appropriate to meet the required blending ratio at LNG-ethane blending point 108, which for a single blending point is in the range of 1 :500, preferably 1 : 100 to 500: 1, of LNG to liquefied ethane, or in scenarios involving multiple blending points as described herein, the various blending ratio ranges at the other blending points.

[0049] The embodiments described in this disclosure provide options for implementation, such as choosing between a single point blending operation or a multi-point process to allow various factors to be considered in optimizing the blending operation as desired. For example, where the facility has a hydraulic restriction in the conduit segment upstream of the first blending point 108, such as at least a portion of the conduit 110 leading to the first blending point having a reduced internal diameter, such as 12 inches or less, or less than the diameter of the conduit 116 and / or the conduit 112. Multi-point blending operations can be more suitable for such situations as such restrictions would limit a single point blending operation, such as in terms of flow rate and blending ratio possibilities, including a reduction in the amount of second liquefied hydrocarbon that can be blended, and higher operating costs. Additionally, multi-point blending operations allow for improved control and flexibility over the overall operation.

[0050] Referring to Figures 1 to 4 The combined conduit 116 continues through the final valve 126 to provide the merged stream (which can be from a single or multi-blending point) to the send-out system 106 downstream of the final valve 126. Optionally and preferably, the operating pressure of the merged stream is increased through the send-out system 106 to produce a pressurized merged stream, which is provided to a downstream LNG vaporizer system to produce a regasified natural gas stream having a pressure suitable for entry into a fluidly connected natural gas utility grid. Suitable components or equipment for increasing the pressure at the send-out system 106 are provided elsewhere in this disclosure, and a person of ordinary skill can select based on the particular conditions and parameters of a certain facility or equipment.

[0051] Optionally, additionally, or alternatively, the operating pressure of the respective combined conduit 116 (including 116A) and / or 160 and the merged stream therein is also affected by the operating conditions of the downstream system in fluid communication with the conduit located downstream of the respective final valve 162 or 126, as understood by a person of ordinary skill in the art.

[0052] Optionally, the blending operation can be further improved, such as reducing the amount of time to complete the blending operation, by providing an operating pressure to the receiving storage vessel (the storage vessel to which the merged stream is provided, such as the vessel 102) that is higher than the saturation pressure of the merged stream. It should be understood that the higher operating pressure is limited by the safety operating parameters of the respective storage vessel. Preferably, the operating pressure of the vessel receiving the merged stream is at least 5% higher than the saturation pressure of the merged stream, more preferably at least 50% higher, and most preferably at least 100% higher. A suitable way to provide an operating pressure to such a vessel that is higher than the saturation pressure of the merged stream is to adjust the BOG pressure set point as known by a person of ordinary skill in the art.

[0053] The option to provide a receiving storage vessel with an operating pressure higher than the saturation pressure of the combined stream is limited by the safety operating parameters of the respective storage vessel, which are not typical in the standard operating practice of these storage vessels, primarily storing liquefied hydrocarbons for transport, and can be implemented as needed. If implemented, the respective storage vessel is temporarily provided with a higher operating pressure during part or all of the duration of the blending operation, or even after the blending operation as needed.

[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 keep the temperature of the product in the storage vessel correspondingly low, to optimize the volumetric capacity of the storage vessel and to reduce BOG formation. Lower operating pressure is more desirable in the long run as it can help to minimize LNG quality variation over time. It will be appreciated that the standard practice of maintaining a low operating pressure for a receiving storage vessel can also be selected as an option during part or all of the blending operation. The desired operating pressure for a particular receiving vessel is achieved primarily by managing the BOG for the respective vessel, which is typically done through the associated BOG management system. By providing a higher operating pressure for the applicable storage vessel during the blending operation, the flashing of the combined stream as it enters the respective storage vessel is reduced or even potentially eliminated, thereby minimizing or even eliminating the boil-off gas formation rate associated with the blending operation. A minimum or zero BOG formation rate during the blending operation can relax the constraints on boil-off gas management, which reduces the operational time. Once the blending operation is complete, the operating pressure of the respective vessel can be reduced to return it to the standard operating pressure, or optionally maintained at that operating pressure in accordance with the relevant technical and contractual constraints imposed on the vessel and its cargo. After the blending operation, the BOG can be managed using standard operating procedures, thereby allowing the blending operation to be performed without any time delay associated with BOG management.

[0055] The method of the present disclosure addresses certain negative effects of in-tank blending of two different liquefied hydrocarbons, such as stratification, by facilitating the in-line blending of the two different liquefied hydrocarbons in the conduit at an operating pressure higher than the saturation pressure of the combined stream. Because the saturation pressure of the combined stream can vary throughout its journey from the blending point 108 to its destination, such as back to the vessel 102, reference to the saturation pressure of the combined stream is generally in the context of a particular segment of the conduit. Adjusting the blending ratio and / or providing additional blending points as described herein are some suitable ways to manipulate the operating pressure of the relevant segment of the conduit and / or to affect the saturation pressure of the combined stream in the relevant segment to achieve the desired operating pressure level higher than the saturation pressure of the combined stream, from time to time to ensure that it remains in the liquid state.

[0056] Additionally, the methods described herein also provide an option to minimize the BOG management requirements during the blending operation, and thus reduce the operating time of the blending operation, by providing an operating pressure to the respective receiving storage vessel that is higher than the saturation pressure of the combined stream to minimize flashing of the combined stream into the respective storage vessel.

[0057] As noted in the present disclosure, the methods herein can be used to perform a blending operation of two liquefied hydrocarbon streams, such as LNG and liquefied ethane, particularly at existing facilities that use infrastructure that has been used for standard operations, such as LNG regasification. For example, an LNG facility that delivers LNG or natural gas to downstream users that is intended to deliver "rich" LNG to the downstream users, while being limited by lean LNG entering from the global market, can employ the methods described herein to add liquefied ethane (or another lighter hydrocarbon or mixture of light hydrocarbons) to the LNG of the facility using existing infrastructure, such as pump equipment, conduits, and valves, etc. When a blending operation is needed, certain operating parameters of the facility can be changed to implement the methods described herein.

[0058] During standard operations, the LNG import facility is operated at its standard parameters to achieve regasification of the LNG. When it is desired to blend the LNG with another liquefied hydrocarbon, the methods described herein can be employed with minimal changes to the existing infrastructure and ease of transitioning between the blending mode and the normal plant operation mode, such as send-out for downstream processing. Prior to the start of the blending operation, the product in storage vessel 102 is typically lean LNG, which can be further enriched with another liquefied hydrocarbon. Prior to combining the lean LNG with another liquefied hydrocarbon, such as ethane, the lean LNG is taken from storage vessel 102 to the LNG terminal and back to the LNG storage vessel (such as from vessel 102 via conduit 110 (or another similar conduit) to blending point 108, back to vessel 102 (or another vessel) via conduit 160, through BOG management system 150 (partially or completely, such as shown in Figure 3 and Figure 4 shown) and to send-out system 106 or completely bypassing BOG management system 150 (such as shown in Figure 1 and Figure 2 shown)).

[0059] Prior to providing the second liquefied hydrocarbon stream to the first blending point 108, the lean LNG from the storage vessel 102 is preferably first provided to the blending point 108 and to the send-out system 106 at least via conduit 116 and optionally back to vessels 102 (both can be part of normal send-out operations) and 106 to ensure cooling of at least the blending path of the combined stream. After establishing circulation of the first liquefied hydrocarbon, the second liquefied hydrocarbon stream can be pumped from the second vessel 114 to start the blending operation in accordance with aspects described in the present disclosure. This includes providing the combined stream to the send-out system 106 at an operating pressure that is higher than the saturation pressure of the combined stream. Additional benefits of (i) recirculating LNG prior to the addition of the second liquefied hydrocarbon (such as liquefied ethane) and (ii) recirculating LNG during the blending operation (in various circulation scenarios) include keeping the various conduits cryogenic to minimize the formation of vapor, particularly at the blending point 108, and to facilitate mixing. Furthermore, if desired and equipment is available, circulation of the LNG provides the LNG to the BOG management system 150, which enables recondensation of BOG upstream of the LNG send-out system 106. Circulation of the lean LNG as described can be facilitated by various pumping equipment, such as pumps 118 and 120. Once circulation of the lean LNG has been established, if not already done, the liquefied ethane stream can be pumped from the ethane source 114 to start the blending operation in accordance with aspects described in the present disclosure. That is, the first LNG stream is pumped into the conduit network prior to the liquefied ethane stream.

[0060] The combined stream can be returned to vessel 102 or another vessel as part of a circulation or recirculation route while having an operating pressure in at least the portion of conduit 116 between the blending point 108 and the final valve 162 that is higher than the saturation pressure of the combined stream. Additionally or alternatively, certain embodiments of the methods described herein provide an option to partially or completely bypass the storage vessel (such as vessel 102) by directing the combined stream to the send-out system 106 at an operating pressure that is higher than the saturation pressure of the combined stream, without being provided to a vessel (such as 102) via conduit 160, at least in the portion of conduit 116 between the blending point 108 and the final valve 126. The operating pressure of the combined stream is increased by the send-out system 106 to produce a pressurized combined stream that is provided to a downstream LNG vaporizer system to produce a regasified natural gas stream that has a pressure suitable for entry into a fluidly connected natural gas utility grid. Suitable components or equipment for increasing the pressure at the send-out system 106 are provided elsewhere in the present disclosure and can be selected by one of ordinary skill based on the particular conditions and parameters of a certain facility or equipment.

[0061] The operating parameters of the blending operation, as described herein, affect the operating pressure of the conduit network compared to the standard operating parameters. Optionally and preferably, the conduit network is provided with an operating pressure of at least 2 bar g (bar gauge) to accommodate the effects from the blending operation while meeting the operating parameters. Suitable methods for providing such operating pressure to the conduit network are known to those of ordinary skill in the art. Once the blending operation is complete, such as when the desired amount of the second liquefied hydrocarbon (such as liquefied ethane) has been blended, the flow of liquefied ethane is gradually reduced and stopped. The standard operation is resumed, including returning the operating pressure of the conduit network to its standard parameters. The properties of the regasified blended product downstream of the send-out system 106, which is preferably "rich" LNG (e.g., Wobbe index) relative to the LNG prior to blending, can be constantly monitored to ensure that the natural gas provided to the utility grid meets certain 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 for adjustment of the blending ratio between the two liquefied hydrocarbon streams to ensure that the regasified blended product stream meets the required product quality specifications. The same principle applies to applications where the blended LNG is supplied to other downstream users, as in the case of import and export terminals (as described in

[0031] ). For embodiments where the operating pressure of the respective storage vessel (such as 102) has been increased above the saturation pressure of the combined stream, the operating pressure of the respective vessel can also be reduced to its standard parameters. After the blending operation, the blended product in vessel 102 can be stored as inventory or otherwise managed, such as distributed according to contractual obligations.

[0062] In some applications, the combined stream can be recirculated or distributed among various storage vessels (not shown) such that at least a portion (including all) of the combined stream is provided to the blending point as if it were lean LNG, in which case accumulation of the second liquefied hydrocarbon (such as liquefied ethane) can occur. That is, as the blending operation proceeds over time, the first liquefied hydrocarbon stream pumped to the first blending point 108 contains an increasing amount of the second liquefied hydrocarbon over time. Such accumulation can be addressed by adjusting the blending ratio at the LNG-ethane blending point 108. LNG facilities typically include equipment that continuously monitors the properties of the LNG flowing through the conduit network, including sensors (e.g., flow rate). The continuous monitors allow for continuous adjustment of the flow rate of the respective streams (preferably the liquefied ethane stream) to achieve the desired blending ratio.

[0063] Optionally and preferably, the flow of the combined stream in the portion of the combined conduit 160 and 116 upstream of the valve 162 and the final valve 126 preferably occurs in a turbulent flow regime.

[0064] While not depicted, it should be understood that the principles described herein can be applied to provide blending between a liquefied ethane carrier and a floating storage and regasification unit (FSRU), which typically includes an LNG storage vessel, a BOG management system, and a send-out system.

[0065] The methods provided herein, which include the inline mixing of a first LNG stream and a liquefied ethane stream, particularly in a turbulent regime, can maximize the mixing of LNG and liquefied ethane in the combined stream, thereby enabling the combined stream to exhibit a uniform composition and characteristics (e.g., density) such that it can be provided to a storage vessel 102 (or other vessel, whether on-site or on a vessel) and / or a send-out system 106 in a uniform state, which reduces the risk of fluid stratification, or commercial issues at the point of handoff (e.g., a natural gas grid injection point). However, due to the difference in specific enthalpy of the lean LNG and the liquid ethane stream, the inline blending operation can introduce partial vaporization and form a two-phase stream, which can introduce the risk of undesirable pipe over-vibration, leading to stress and fatigue of the pipe. The methods described herein address the potential two-phase stream formation by maintaining the operating pressure in the combined stream above the saturation pressure of the combined stream.

[0066] While not shown, it should be understood that some, including all, aspects of the methods described herein can be controlled and / or implemented with a computer program. The computer program can be referred to as a controller. For example, the discharge pressure and flow of the pumps can be controlled with a computer program, the operating pressure of the system can be controlled by manipulating the percent open of the flow control valves, etc. Suitable computer programs include computer programs executed by a data processor. As used herein, reference to a computer program is intended to encompass a program element and / or computer readable medium bearing computer readable instructions for controlling a computer system to coordinate the performance of the above described methods. The computer program can be implemented as computer readable instructions code and can be stored on a computer readable medium (removable disk, volatile or non-volatile memory, embedded memory / processor, etc.) using any suitable programming language such as, for example, JAVA, C++. The instructions code can be operable to program a computer or any other programmable device to carry out the intended functions. The computer program can be available from a network such as the World Wide Web, from a service provider, or it can be downloaded into the network (e.g., from a diskette or from a computer readable medium). Various aspects described herein can be implemented respectively by means of a computer program element respectively software, wherein the computing program element, which, for example, can be stored on a computer usable medium, for example, in a segment of a RAM (Random Access Memory) or the memory of the processor, comprises all the procedures and data that are required for the operation of the methods described above. Additionally or alternatively, any or all aspects described herein can be performed manually by one or more human operators having relevant operational knowledge.

[0067] While specific embodiments have been described herein, it will be appreciated that such description is not intended to limit the embodiments described. Rather, any combination of the features and elements provided above (whether or not involving different embodiments) is contemplated to implement and practice the embodiments contemplated. Furthermore, although the embodiments disclosed herein can have the advantages of being superior to other possible solutions or to the prior art, whether or not a particular advantage is achieved by a given embodiment is not limiting of the scope of the application. Thus, aspects, features, embodiments, and advantages described herein are merely illustrative and are not considered elements or limitations of the appended claims, unless the claim explicitly states otherwise.

Claims

1. A method for blending two or more liquefied hydrocarbon streams at a facility, said facility comprising: - A first storage container (102) for storing a first liquefied hydrocarbon, optionally the first liquefied hydrocarbon being liquefied natural gas. - A delivery system (106) delivers the first liquefied hydrocarbon to downstream processing equipment, optionally including a regasification unit, and - Catheter network, the catheter network including i. A first blending point (108), located downstream of the first storage container (102) and upstream of the delivery system (106), ii. A first conduit segment (110) providing fluid communication between the first storage container (102) and the first mixing point (108), iii. A second conduit segment (112) provides fluid communication between a source (114) of a second liquefied hydrocarbon and the first blending point (108), wherein the second liquefied hydrocarbon is optionally selected from the group consisting of liquefied ethane, liquefied butane, liquefied propane, and any combination thereof; iv. A combination conduit (116) providing fluid communication between the first mixing point (108) and the delivery system (106), wherein the combination conduit (116) includes a first final valve (126) immediately upstream of the inlet of the delivery system (106). The method includes: (a) Pumping a first liquefied hydrocarbon stream from the first storage container (102) via the first conduit segment (110) to the first blending point (108); (b) Pumping a second liquefied hydrocarbon stream from the source (114) of the second liquefied hydrocarbon to the first blending point (108) via the second conduit segment (112); (c) At the first blending point (108), the first liquefied hydrocarbon stream and the second liquefied hydrocarbon stream are combined at a volume ratio of 1:500, preferably 1:100, and up to 500:1, to provide a combined stream; and (d) Providing at least a portion, including all, of the combined flow from the first blending point (108) to the delivery system (106) via the combined conduit (116), and (e) When the combined flow is located in the section of the combined conduit (116) between the first blending point (108) and the first final valve (126), an operating pressure higher than the saturation pressure of the combined flow is provided to the combined flow (preferably at least 0.1 bar higher, more preferably at least 0.5 bar higher, and most preferably at least 1.2 bar higher).

2. The method of claim 1, wherein the conduit network further comprises a reflux combination conduit (160) providing fluid communication between the first mixing point (108) and the storage container, optionally wherein the storage container is the first storage container (102), wherein the reflux combination conduit (160) includes a second final valve immediately upstream of the outlet of the reflux combination conduit, wherein the method further comprises: At least a portion of the combined flow is supplied from a section of the combined conduit upstream of the first final valve (126) to the storage container. When the portion of the combined flow is located between the segments of the combined conduit (116) between the first blending point (108) and the second final valve (126), an operating pressure higher than the saturation pressure of the combined flow (preferably at least 0.1 bar higher, more preferably at least 0.5 bar higher, and most preferably at least 1.2 bar higher) is provided to the portion of the combined flow.

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

4. The method according to any of the preceding claims, wherein the combined conduit (116) further comprises a first subsequent blending point (208) located upstream of the first final valve (126) and downstream of the first blending point (108), and optionally upstream or downstream of the reflux combined conduit (160), wherein the method further comprises: (f) A second stream of the first liquefied hydrocarbon is provided from the source of the first liquefied hydrocarbon, optionally the first storage container (102), to the first subsequent blending point (208); (g) At the first subsequent blending point (208), the combined stream and the second stream of the first liquefied hydrocarbon are combined at a volume ratio of 25:1, preferably 50:1 and up to 500:1, wherein the first stream of the first liquefied hydrocarbon and the second liquefied hydrocarbon ethane stream are combined at the first blending point (108) at a volume ratio of 1:500, preferably 1:100 and up to 50:

1.

5. The method of claim 4, wherein the combined 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), wherein the method comprises: (f) A third stream of the first liquefied hydrocarbon is provided from the source of the first liquefied hydrocarbon to the second subsequent blending point (308), wherein the source is optionally different from the first storage container (102), and optionally includes an evaporative gas management system (150). (g) At the second subsequent blending point (308), the merged stream and the third stream of the first liquefied hydrocarbon are combined at a volume ratio of 25:1, preferably 50:1 and up to 150:1, wherein the first liquefied hydrocarbon stream and the second liquefied hydrocarbon stream are combined at the first blending point (108) at a volume ratio of 1:500, preferably 1:100 and up to 50:1, and wherein the merged stream and the second stream of the first liquefied hydrocarbon are combined at the first subsequent blending point (208) at a volume ratio of 100:1, preferably 150:1 and up to 500:

1.

6. The method of claim 1, wherein the combined 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), wherein the method comprises: (f) Providing another stream of the first liquefied hydrocarbon from the source of the first liquefied hydrocarbon to the subsequent blending point (308), optionally wherein the source is different from the first storage container (102), and optionally including an evaporative gas management system (150); (g) At the subsequent blending point (308), the merged stream and the other stream of the first liquefied hydrocarbon are combined at a volume ratio in the range of 25:1, preferably 50:1 and up to 500:1, and wherein the first stream of the first liquefied hydrocarbon and the stream of the second liquefied hydrocarbon are combined at the first blending point (108) at a volume ratio in the range of 1:500, preferably 1:100 and up to 50:

1.

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

1.

8. The method according to any of the preceding claims, further comprising: Provide a total operating pressure of at least 2 bar to the catheter network.

9. The method according to any of the preceding claims, further comprising: The operating pressure of the merged flow downstream of the second final valve (162) is reduced to less than the saturation pressure of the merged flow.

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

11. The method according to any of the preceding claims, wherein step (a) is performed prior to step (b).

12. The method of claim 11, wherein step (a) comprises circulating the first stream of the first liquefied hydrocarbon from the first storage container (102) through a first portion (110) of the conduit, the combined conduit (116), optionally back to the first storage container (102), and optionally through an evaporative gas management system (150).

13. The method according to any of the preceding claims, wherein the second liquefied hydrocarbon is liquefied ethane, and the source of the liquefied ethane is selected from the group consisting of onshore storage and ethane transport vessels and any combination thereof.

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

15. The method according to any of the preceding claims further includes providing the contents of the storage container (102) to the delivery system (106).

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