Patent Publication Number: US-2010107686-A1

Title: Method and apparatus for separating one or more c2+ hydrocarbons from a mixed phase hydrocarbon stream

Description:
The present invention relates to a method for separating one or more C 2 + hydrocarbons from a mixed phase hydrocarbon stream such as partly vapourised liquefied natural gas (LNG). 
     Liquid hydrocarbon streams such as LNG are well-known products, and they are commonly transported in a liquid form for vaporisation at a suitable location or terminal. One such terminal is an ‘import terminal’, which can vaporise the LNG for direct use, subsequent piping into a network, etc. 
     In their paper entitled “Processes for High C 2  Recovery from LNG” for IPSI LLC, presented at the AlChE Spring Meeting in April 2006 (6th Tropical Conference on Natural Gas Utilisation, Orlando, Fla., Apr. 23-27, 2006), the authors stated that “re-gasified LNG being imported into the US must meet gas quality requirements before it can be accepted in the US pipeline grid. Towards this goal, many existing and prospective LNG terminal owners are considering C 2 + extraction”. Various arrangements are discussed in the Paper for improving the C 2 + recovery levels using a refluxed demethanizer, such as with residue compression and condensing; see for example its  FIG. 7 . 
     However, the IPSI Paper does not mention how a separate gaseous hydrocarbon stream can be accommodated into its processes. One additional gaseous hydrocarbon stream is boil-off-gas. Boil-off gas is generally always created in any storage or movement of a liquefied hydrocarbon stream such as LNG. Traditionally, boil-off gas from an LNG storage tank is simply compressed and recondensed. This has the problem of additional energy requirements, making it non-efficient. 
     There are other situations or locations, such as an LNG export terminal, where it may also be desired to have C 2 + extraction from a hydrocarbon stream or source, but wherein the problem of efficiently accommodating a separate gaseous hydrocarbon stream such as boil-off gas has not been considered. 
     The present invention provides a method for separating one or more C 2 + hydrocarbons from a mixed phase hydrocarbon stream such as partly vapourised liquefied natural gas, the method at least comprising the steps of: 
     (a) supplying a mixed phase hydrocarbon feed stream to a first gas/liquid separator;
 
(b) separating the hydrocarbon feed stream in the first gas/liquid separator into a first gaseous stream from a first outlet, and at least one C 2 + liquid stream;
 
(c) passing the first gaseous stream through a compressor to provide a compressed stream; and
 
(d) cooling the compressed stream in one or more heat exchangers to provide an at least partly condensed hydrocarbon product stream;
 
wherein a second gaseous stream is added to a stream downstream of the first outlet.
 
     In a further aspect, the present invention provides apparatus for separating one or more C 2 + hydrocarbons from a mixed phase hydrocarbon stream such as liquefied natural gas, the apparatus at least comprising: 
     a first gas/liquid separator having an inlet for a mixed phase hydrocarbon feed stream, a first outlet for a first gaseous stream and a second outlet for at least one C 2 + hydrocarbon liquid stream; 
     a compressor to compress the first gaseous stream to provide a compressed stream; 
     one or more heat exchangers to cool the compressed stream to provide an at least partly condensed hydrocarbon product stream; and 
     a combiner to combine a second gaseous stream with a stream downstream of the first outlet of the gas/liquid separator. 
    
    
     
       Embodiments of the present invention will now be described by way of example only and with reference to the accompanying non-limiting drawings in which: 
         FIG. 1  is a schematic process scheme in accordance with a first embodiment of the present invention; and 
         FIG. 2  is a schematic process scheme in accordance with a second embodiment of the present invention. 
     
    
    
     For the purpose of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components. 
     It is an object of the present invention to reduce the capital and running costs in a method for separating one or more C 2 + hydrocarbons from a mixed phase hydrocarbon stream to accommodate a further gaseous hydrocarbon stream such as boil-off gas. 
     The present methods and apparatus allow to have C 2 + extraction from a hydrocarbon stream or source, wherein a separate gaseous hydrocarbon stream such as boil-off gas is efficiently accommodated. 
     It has been found that using the surprisingly simple method and apparatus described herein, a second gaseous stream can be accommodated into the method for separating one or more C 2 + hydrocarbons from a mixed phase hydrocarbon stream with minimal, if any, additional running or capital costs. 
     A further advantage is provided by avoidance of adding the second gaseous stream into the gas/liquid separator, which would require a larger gas/liquid separator due to the larger gaseous volume involved, and so also lead to increasing capital and running costs. 
     A further advantage is provided by avoidance of adding the second gaseous stream into apparatus for cooling, preferably re-condensing, the first gaseous stream from the gas/liquid separator, where the warmth of the second gaseous stream would disadvantage the desire for the coldest hydrocarbon product stream. 
     Advantageously, the second gaseous stream is recovered as part of a useful product stream. Where the second gaseous stream comprises one or more useful, commercial or otherwise valuable hydrocarbons, these are recovered by the present invention rather than being burnt off or only used as a source of fuel. Thus the method the present invention is also able to provide a greater volume or amount of a product stream than prior art processes. 
     The mixed phase hydrocarbon stream may be any suitable at least partly vapourised hydrocarbon-containing stream, such as a partly vapourised LNG stream, from which it is intended to recover one or more C 2 + liquid streams. The mixed phase hydrocarbon stream may be at least partly vaporised from a liquid source and it may optionally contain also hydrocarbons that have at least partly condensed from a gaseous source. 
     It is remarked that U.S. Pat. No. 6,023,942 discloses a process for liquefying a gas stream rich in methane. If the natural gas stream contains heavy hydrocarbons, these may be extracted by a fractionation process before liquefying the gas. A problem associated with U.S. Pat. No. 6,023,942 that is not addressed in said patent, is what to do when the content of heavy hydrocarbons in an already liquefied product is higher than desired, which may for instance be the case if the fractionation process upstream of the liquefaction is not sufficiently selective to produce a liquefied stream with a level of C 2 + components below a desired maximum. 
     The present methods and apparatuses solve this problem, without the need to modify any pre-liquefaction facilities that may already be available in an existing liquefaction line-up. The presently proposed solution may be added-on to an existing facility at a liquefaction site or an export site, or locally at an import site to be able to modify the content of the liquefied product to comply with local requirements. 
     As is the case for the mixed phase hydrocarbon stream, the second gaseous stream may also be any suitable hydrocarbon-containing stream. Optionally, the second gaseous stream has the same components and composition as the source of the mixed phase hydrocarbon stream. One preferred second gaseous stream is boil-off gas, for example gas evaporated from a liquefied hydrocarbon store or source, such as one or more storage tanks. The storage tanks could be static or moveable, such as storage tanks on a sea-going transporter, or a combination of same. 
     U.S. Pat. No. 6,658,892 B2 shows use of boil-off gas from two LNG storage tanks in a storage area, which is combined with an overhead reject gas from a common flash tank and then fed into a common fuel gas compressor. However, the common flash tank in U.S. Pat. No. 6,658,892 B2 is not intended to provide at least one C 2 + liquid stream, but to produce a bottom LNG stream (line  124 ). Thus, the boil-off gas in U.S. Pat. No. 6,658,892 B2 is not combined with a C 2 + depleted gaseous stream downstream of a gas/liquid separator, but is combined with the reject gas taken from a common flash tank handling cooled feed gas produced from two independent trains. 
     The one or more C 2 + liquid streams provided in step (b) of the present invention comprises at least one stream comprising at least 40 mol % of at least one C 2 + hydrocarbon, such hydrocarbons being one or more selected from the group comprising: ethane, propane, butanes and pentanes. Preferably, at least one of said streams comprises &gt;50 mol %, &gt;60 mol %, &gt;70 mol %, &gt;80 mol % or &gt;90 mol % of at least one C 2 + hydrocarbon. 
       FIG. 1  schematically shows a process scheme (generally indicated with reference number  1 ) for recovering C 2 +, that is ethane and heavier, hydrocarbons from a mixed phase hydrocarbon feed stream  10 . 
     The process shown in  FIG. 1  is equally able to recover just a C 2 , C 3  or C 4 , etc. stream, or C 3 +, C 4 + streams, etc., from a hydrocarbon stream, either as separate streams, or as one or more combined streams, or a combination of same. 
     The mixed phase hydrocarbon feed stream  10  may be any suitable hydrocarbon-containing stream from which it is intended to recover one or more C 2 + liquid streams. The mixed phase hydrocarbon feed stream  10  is preferably at least partly vapourised from a liquid source such as LNG, and has a pressure above ambient, typically between 8 and 15 bar. 
     Prior to the process scheme shown in  FIG. 1 , the mixed phase hydrocarbon feed stream  10  may have been utilised in one or more other processes. One example is use of some of the cold energy of a liquid hydrocarbon stream, such that the mixed phase hydrocarbon feed stream  10  is consequently at least partly vapourised. 
     The mixed phase hydrocarbon stream  10  is preferably provided by a liquid hydrocarbon stream such as a cold stream obtained from a source of LNG, such as a liquid product output stream of a liquefaction plant, or, preferably, from one or more liquefied hydrocarbon storage tanks such as one or more LNG storage tanks. Such tanks may be static or moveable, such as on a sea-going transporter. Thus the source of the LNG could be one or more storage tanks on an LNG vessel or carrier, the LNG being carried by a loading or unloading line at an LNG import or export terminal. These liquefied hydrocarbon storage tanks could be the same as the liquefied hydrocarbon storage tanks that provide the boil-off gas for the second gaseous stream, or they could be different ones, or a combination of the same and different ones. 
     As is customary to the person skilled in the art, the LNG stream may have various compositions. Usually the LNG stream to be vaporized is comprised substantially of methane. The LNG will generally contain varying amounts of hydrocarbons heavier than methane such as ethane, propane, butanes and pentanes. 
     Optionally, the mixed phase hydrocarbon feed stream  10  is comprised substantially of methane, that is at least 80 mol %, preferably at least 90 mol %, 95 mol % or even 99 mol %, methane. 
     The mixed phase hydrocarbon feed stream  10  is supplied to the inlet  22  of a first gas/liquid separator  12 . The nature, design and capacity of the first gas/liquid separator  12  can relate to the nature of the incoming mixed phase hydrocarbon feed stream  10  and the desired streams to be recovered. For example, where it is desired to recover C 2 + hydrocarbons from the mixed phase hydrocarbon feed stream  10  at the bottom of the first gas/liquid separator  12 , the first gas/liquid separator  12  could be a de-methanizer, known in the art. Alternatively, recovery of C 3 + hydrocarbons as a bottom product may use a de-ethanizer, also known in the art. 
     The gas/liquid separator  12  may be any suitable vessel or arrangement for obtaining a gaseous stream and a C 2 + liquid stream, such as a scrubber, distillation column, etc. The gas/liquid separator  12  may comprise more than one separator, column, etc., and may be designed for the separate separation of two or more liquid streams, such as a C 2  stream and a C 3  stream, etc. Such separators usually operate at above ambient pressure, for example 6-12+ bar, depending on the type and recovery of product(s) desired or expected, and optionally with one or more reflux operations. 
     The recovery of C 2 + hydrocarbons from a mixed phase hydrocarbon feed stream  10  could be as part of one of a number of processes using a hydrocarbon feed stream. One process is for ‘purification’ of the hydrocarbon feed stream to minimise heavier hydrocarbons therein, prior to its subsequent use or further processing. Another process is for adjusting the gas quality, for example for meeting a particular heating value downstream. Another process is for providing one or more C 2 + streams, such as liquid petroleum gas (LPG). A combination of one or more of these processes or other objectives may also be desired. 
     For example, it is known that ‘rich’ LNG generally comprises about 5 mol % of C 2 + hydrocarbons, which percentage can be too high for use in certain territories or locations. At least some of C 2 + hydrocarbons (especially ethane, propane and butane) are also termed ‘natural gas liquids’ (NGLs), and the production of NGLs is also commercially attractive. 
     Thus, one particular involvement of the first gas/liquid separator  12  in the process scheme of  FIG. 1  is to reduce the amount of C 2 + hydrocarbons in a methane feed stream, and to provide one or more C 2 + product streams, for example at an import terminal handling rich-LNG. 
     In  FIG. 1 , the first gas/liquid separator  12  shows separation of the hydrocarbon feed stream  10  into a first gaseous stream  20  through a first outlet  23 , and a liquid stream  30  through a second outlet  24 . The liquid stream  30  may comprise one or more separate streams. 
     In the present invention, it is preferred that the first gas/liquid separator  12  is able to recover &gt;80 mol %, &gt;90 mol %, or even ≧95 mol % of the heavier (C 2 +, C 3 +, etc,) hydrocarbons, as the liquid stream or streams  30  from the first gas/liquid separator  12 . 
     The first gaseous stream  20  is combined with a second gaseous stream  40  by a combiner  18 . A combiner  18  may be a distinct combination unit or vessel, or merely a conjunction of streams or pipelines. 
     The second gaseous stream  40  preferably has the same or similar pressure, temperature and other parameters as the first gaseous stream  20  at the combiner  18 . It is also possible for the second gaseous stream  40  to have different parameters and/or conditions. 
     The combination of the first gaseous stream  20  and second gaseous stream  40  provide a combined gaseous stream  50 , which passes into a compressor  14 . The combined gaseous stream  50  has the combination of parameters of the first gaseous stream  20  and second gaseous stream  40 , and is preferably still gaseous and at above ambient pressure. 
     The compressor  14  may comprise one or more compressors in series or parallel or both, designed to compress the combined gaseous stream  50  to a higher pressure, and provide a compressed stream  60 . Under some operating conditions, for example high compression, a portion of the combined gaseous stream  50  may become liquid in the compressor  14 . Thus, the compressed stream  60  may be a mixed phase stream. 
     The compressed stream  60  is then cooled. In  FIG. 1 , the cooling is provided by a first heat exchanger  16 , which may comprise one or more heat exchangers in series, parallel or both. The first heat exchanger  16  cools the compressed stream  60  to provide an at least partly condensed hydrocarbon product stream  70 . The cooling in the heat exchanger  16  is provided by an incoming cold stream  80 , which passes out of the heat exchanger  15  as a warmer stream  80   a . The incoming cold stream  80  may be any suitable cold stream being a dedicated refrigerant stream or any other stream having suitable cold energy that can be recovered. Optionally, it is a cold stream which is available from another part or function of an embodiment of the present invention. 
     The nature and arrangement of the first heat exchanger  16  and of the cold stream  80  are designed to provide the desired hydrocarbon product stream  70  (such as recondensed or partly vaporised LNG) and/or the desired one or more liquid streams  30  and/or to adjust the composition of the desired hydrocarbon product stream  70 . 
     Optionally, a portion (not shown in  FIG. 1 ) of the compressed stream  60  is used directly, for example fed or piped directly to a gas network. 
     The second gaseous stream  40  could be added to one or more of the group comprising: the first gaseous stream  20 , the compressed stream  60 , and the at least partly condensed hydrocarbon product stream  70 ; downstream of the first outlet  23  of the first gas/liquid separator  12 . 
     Thus, in a first alternative embodiment, the second gaseous stream  40  is combined with the compressed stream  60  after the compressor  14 . This may be more suitable where the parameters of the second gaseous stream  40 , especially its pressure, are closer to the parameters of the compressed stream  60  than the first gaseous stream  20 . 
     In a second alternative embodiment, the second gaseous stream  40  may be combined with the at least partly condensed hydrocarbon product stream  70 . 
     This is especially where the parameters of the second gaseous stream  40 , in particular its temperature and pressure, are closer (either inherently or by processing) to those of the at least partly condensed hydrocarbon product stream  70  than the first gaseous stream  40  or the compressed stream  60 . 
       FIG. 2  schematically shows a process scheme (generally indicated with reference number  2 ) for a second embodiment of the present invention. 
     In particular,  FIG. 2  shows a storage tank  32  such as an LNG storage tank at an LNG import terminal. Such storage tanks  32  are known in the art, and are generally designed to store liquefied hydrocarbons such as LNG for a period of time prior to transport and/or use of the LNG. 
     The storage tank  32  shown in  FIG. 2  has a first outlet  25  for a liquid hydrocarbon stream  8 . The storage tank  32  has a second outlet  26  for the passage of ‘boil-off gas’  40   a . Due to the unavoidable inflow of heat into storage tanks of liquid hydrocarbons, which are generally kept at −100° C. or below, such as −160° C. for LNG, the creation of boil-off gas is inevitable. 
     Conventionally, boil-off gas is compressed, and recondensed. However, this requires at least one or more additional recondensers, which also involve additional running costs. 
     It is an object of the present invention to provide an alternative use of boil-off gas which does not require additional capital and/or running costs, or reduces same. 
     In  FIG. 2 , the liquid hydrocarbon stream  8  passes through a heat exchanger  16   a , which may be the same or different from the first heat exchanger  16  shown in  FIG. 1 . In the process scheme  2  shown in  FIG. 2 , involving the first heat exchanger  16  also means that the liquid hydrocarbon stream  8  is equivalent to the incoming cold stream  80  shown in  FIG. 1 , and at least some of its cold energy is used to cool a second stream (discussed hereinbelow) also passing through the heat exchanger  16   a.    
     The heat exchanger  16   a  may be one or more heat exchangers in series, parallel or both, and its arrangement and configuration will be known to those skilled in the art. Preferably, the heat exchanger  16   a  comprises a preheater and/or a condenser as hereinafter described. 
     Through use of at least some of the cold energy of the liquid hydrocarbon stream  8 , the heat exchanger  16   a  provides a mixed phase hydrocarbon feed stream  10  (which may be equivalent to the warmer stream  80   a  shown in  FIG. 1 ), which passes into the first gas/liquid separator  12  through the inlet  22 . The arrangement and configuration of the first gas/liquid separator  12  is described above, and generally provides one or more C 2 + liquid streams  30  through one or more outlets such as second outlet  24  as shown, and a first gaseous stream  20  through a first outlet  23 . 
     The nature of the liquid stream(s)  30  is discussed above.  FIG. 2  shows further use of a liquid stream  30 , which passes into a heat exchanger such as a reboiler  44  to provide a reflux stream  30   a  for re-entry into the first gas/liquid separator  12  via an inlet  26 , and a liquid product stream  30   b . The liquid product stream  30   b  may comprise one or more NGL streams for separate commercial use. 
     The first gaseous stream  20  in  FIG. 2  is supplied into a second gas/liquid separator  36 . The second gas/liquid separator  36  may be any unit or vessel able to allow any liquid to separate out as a liquid stream  90   a , and to provide a third gaseous stream  90  therefrom. As an example, the second gas/liquid separator  36  can be a ‘knock-out drum’ known in the art. 
     The second gas/liquid separator  36  is a convenient receiver of a second gaseous stream  40 , especially a boil-off gas stream  40   a  from the storage tank  32  as shown in  FIG. 2 . A gas/liquid separator usually has a number of fittings or ports, easily able to be adapted to provide one or more additional inlets of gas thereinto. As such, the present invention is also particularly convenient for the introduction of a second gaseous stream  40  into an existing gas/liquid separator such as a knock-out drum, including retro-fitting of a second gaseous stream passage and inlet into an existing plant, design or facility. In this way, the second gas/liquid separator  36  is acting as the combiner  18  of the two gaseous streams as shown in  FIG. 1 . 
     Boil-off gas is by its nature usually normally gaseous, and usually has a temperature below 0° C., such as between −20° C. and −90° C. Usually, but optionally, there is a boil-off gas compressor  34  to compress the boil-off gas stream  40   a  to a greater than ambient pressure, such as between 6-15 bar. Where the storage tank  32  is storing LNG, boil-off gas is usually &gt;70 mol % methane. 
     As the pressure is similar to that of the first gaseous stream  20  supplied by the first gas/liquid separator  12 , minimal energy is required for the combination of the first gaseous stream  20  and a second gaseous stream  40  being the (optionally compressed) boil-off gas stream  40   a , in the second gas/liquid separator  36 . This directly utilises the boil-off gas from the storage vessel  32  as a gaseous stream without requiring additional capital and running costs, in particular the need for other or additional recondensor(s) for the boil-off gas. 
     Furthermore, the introduction of the second gas stream  40  into the second gas/liquid separator  36  avoids the need for a larger first gas/liquid separator  12  to accommodate inflow of the second gaseous stream  40 . It also makes the process of  FIG. 2  independent of the supply of the second gaseous stream  40 , where this may be intermittent and/or variable (for example during loading and unloading of LNG), as well as making the process independent of the temperature of the mixed phase hydrocarbon feed stream  10 . 
     From the second gas/liquid separator  36 , the third gaseous stream  90  is passed into a compressor  14 . As described above, the compressor  14  may be one or more compressors, and provides a compressed stream  60 . 
     The compressed stream  60  passes into the heat exchanger  16   a  (described above), to be cooled by the liquid hydrocarbon stream  8  also passing into the heat exchanger  16   a.    
     It is preferred for the compressed hydrocarbon stream  60  to be cooled as much as possible by the liquid hydrocarbon stream  8 , so as to provide an at least partly condensed hydrocarbon product stream  70  having the largest or greatest amount of cold energy. This is so as to maximise use of the cold energy in the at least partly condensed hydrocarbon product stream  70 . For example, the hydrocarbon product stream  70  may be used in one or more further processes, which partly or fully vaporises the hydrocarbon product stream  70  and recovers its cold energy for integration with one or more other processes such as in a gas separation plant, power plant, etc. 
     It can be seen that the introduction of the relatively warm second gaseous stream  40  into either the colder liquid hydrocarbon stream  8  or the condensing heat exchanger  16   a  would affect maximisation of the condensing of the compressed hydrocarbon stream  60  by the liquid hydrocarbon stream  8 , and it is therefore less desired to carry out such alternative arrangements. 
     In  FIG. 2 , the at least partly condensed hydrocarbon product stream  70  can pass through a splitter  38 . The splitter  38  may be a simple division of one or more streams or pipelines, or may be a distinct unit or vessel such as an accumulator having two or more outlets. The splitter  38  can provide two streams: a first (usually majority) at least partly (preferably fully) liquid stream  100  for subsequent use (such as pumping through a pump  46  and subsequent vaporisation in a vaporiser  48  to supply the hydrocarbon as a vapour product stream  110  to a network); and a second, usually minority, at least partly liquid stream  100   a . After passing through a pressure reduction valve  42 , the second stream  100   a  is an expanded stream  100   b  which can be passed through an inlet  27  into the first gas/liquid separator  12  as a reflux stream. Some gas/liquid separators are more efficient where two or more incoming streams having different temperatures are supplied at different inlets, in a manner known in the art. 
     The second at least partly liquid stream  100   a  is preferably less than 20 mol %, more preferably less than 10 mol %, of the at least partly condensed hydrocarbon product stream  70 . 
     Table 1 gives an overview of estimated pressures and temperatures of the streams at various parts of an example process of  FIG. 2 . 
     
       
         
           
               
               
               
               
             
               
                 TABLE 1 
               
               
                   
               
               
                   
                   
                   
                 Phase 
               
               
                 Line 
                 Pressure (bar) 
                 Temperature (° C.) 
                 composition* 
               
               
                   
               
             
            
               
                   
               
            
           
           
               
               
               
               
            
               
                  8 
                 9.5 
                 −157 
                 L 
               
               
                 10 
                 9.0 
                 −114 
                 V/L 
               
               
                 100b 
                 8.5 
                 −125 
                 V/L 
               
               
                 20 
                 8.5 
                 −121 
                 V 
               
               
                  30b 
                 8.6 
                 −25 
                 L 
               
               
                 40 
                 9.5 
                 −24 
                 V 
               
               
                 60 
                 13.5 
                 −96 
                 V 
               
               
                 100  
                 13.0 
                 −122 or lower 
                 L 
               
               
                   
               
               
                 *V = vapour, L = Liquid 
               
            
           
         
       
     
     The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention.