Patent Application
20190011180
The present invention is broadly directed to the separation of well fluid stream(s) hydrocarbon components when main feed stream(s) to a single separation unit are provided at one or more substantially different pressures of hydrocarbon streams, such where production wells or upstream compression result in gathering feed streams to a separation unit at different pressures. The separation is accomplished in such away so that main product sales gas stream is fully enriched with propane and butanes contained in the hydrocarbon feed stream(s).
It is well known to supply a well stream feed fluid to conventional gas processing plants mainly comprising a dew-pointing unit to produce sales gas with certain dew point spec and a liquid stabilization unit to produce a stabilized oil/condensate stream(s) meeting RVP specification. Commonly liquid from dew-pointing is directed to liquid stabilizer. If the feed fluid is typically rich in C2-C4 cut then NGL (mainly C3-C4) is built-up in the recycle stream from the stabilizer OVHD to LTS section ending to loss of revenue through flaring.
The natural gas separation unit is at a single pressure and thereafter to obtain desired product streams from that separation unit. Within the separation unit, for example, are chilling, turbo-expansion, J-T, compression and separation steps to accomplish a desired set of product streams. It is well known that a sales gas stream, stabilized condensate, and a stabilized bottoms oil streams are among those desired set of product streams. Commonly fuel gas needed is taken from sales gas stream containing propane and butanes components
Where wellhead production or upstream compression of one feed stream to a separation unit is substantially higher than another feed stream to the separation unit, the prior art separation unit will cause one stream to be reduced in pressure or the other stream to be compressed so that a single pressure feed stream is processed in the separation unit. Thus, where wellhead production or upstream compression of one feed stream causes it to be substantially greater than another feed stream to a separation unit, the prior art instructs one skilled in the art of natural gas separations to combine those two streams and to further process them at a single pressure.
Further, it is well known in the prior art of natural gas processing that “sales gas” is separated by low temperature separation in a thermodynamically single stage separation from wellhead natural gas in remote locations and transported away by pipeline to downstream central NGL recovery complex. Specifically and due to NGL build-up mentioned above, valuable amounts of propane and butanes are commonly flared in stabilizer OVHD compressed recycle gas especially for rich feed fluid and/or high CGR hydrocarbon feed fluid on-site near wellheads after gas-dew pointing and liquid stabilization to obtain sales gas. The economic incentive of maximizing recovery of propane and butanes by separating a maximum amount into sales gas to pipeline transportation together with having a robust and stable operation are obvious in those circumstances. However, the prior art comprises processes have failed to use sales gas transportation pipelines so recover a maximum amount of propane and/or butanes into sales gas, fractionating the sales gas to a safe margin within a certain gas dewpointing unit that will not result in hydrocarbon liquid condensation in the pipe line so that hydrocarbon liquid does not condense at transportation pipeline pressures and temperatures in all operating cases (summer, winter, turn down, etc.)
Sales gas specifications are well known in the art and comprises at least a maximum allowable hydrocarbon dewpoint temperature at a certain pressure. Generally, propane and butanes are permissible in sales gas product streams to an extremely low level, for example, often less than 0.2 mole percent, with the balance of heavier hydrocarbon components, for example, at less than 0.1 mole percent. This has led to significant problems in natural gas separations at remote locations, whereby levels of propane and butanes that cannot be released to the sales gas product accumulate in the internal process streams as a natural result of their typically low levels permitted in condensate and heavy oil product streams. Separation steps in the prior art natural gas processing in remote locations for gas dewpointing and condensate and/or sales oil product streams are associated with that NGL buildup of propane and butanes.
There is a need for a new process configuration for gas separation and condensate and/or oil stabilization unit process to overcome NGL build-up and ensure a stable plane operation in which a high pressure section of a separation unit operates at a relatively high pressure to initially process and separate a high pressure feed stream and a low pressure section of the separation unit to initially process and separate a low pressure feed stream, where the high pressure section and the low pressure section are integral with and exchange streams to accomplish a desired separation of a natural gas stream. Further, there is a need for a natural gas dew pointing and liquid stabilization process where sales gas fractionation and/or absorption control provides for increased levels of propane and butanes in the sales gas fraction and also to recover propane and butanes components from fuel gas taken from sales gas.
The present invention is a separation unit process in which a high pressure section of a separation unit operates at a relatively high pressure to initially process and separate a high pressure feed stream and a low pressure section of the separation unit to initially process and separate a low pressure feed stream, where the high pressure section and the low pressure section are integral with and exchange streams to accomplish a desired separation of a natural gas stream.
This present invention comprises integration of two primary processing sections. The first is a gas dewpointing section where extremely tight control to maximize heavier components in a sales gas is achieved within a required sales gas product dewpoint that includes a maximum permissible enrichment with propane and butanes as compared with the prior art to prevent buildup of propane and butanes in internal streams. The second section is a condensate and/or oil stabilization section. These two sections operated integrally to form what is referred to as the Integrated Dewponting and Stabilization (IDS) process.
A critical feature of the invention separation unit is a first separation stage for low pressure feed and a first separation stage for the high pressure feed, whereafter (1) liquid from the low pressure first separation stage is combined with liquid from the high pressure separation stage and (2) gas from the high pressure first separation stage is combined with compressed gas from the low pressure separation stage. These steps are critical to savings in equipment and energy in order to transfer desired portions of the low pressure feed to the high pressure section and desired portions of the high pressure feed to the low pressure section. The only other compression equipment necessary to accomplish the above transfers between the low pressure section and the high pressure section is a liquid pump for the liquid from the low pressure first separation stage to combine it with liquid from the high pressure separation stage. Thus, compression energy of the gas from the high pressure first separation stage is preserved by compressing only the lighter components of the low pressure feed in the gas from the low pressure separation stage and further processing that combined gas stream at a relatively higher pressure, thereby reducing ultimate gas compression requirements for a sales gas stream. The sales gas stream also comprises a separated portion of the gas from the high pressure first stage separation stage.
It is well known that local fuel gas for plant utilities like fired heaters, power generation, etc. in remote areas processing natural gas streams is a problem. Fuel gas for gas burners in fired heaters is typically required to have a relatively narrow range of components for optimum operation of the fired heater overall. While the gas burners can operate with components well outside of the recommended ranges, overall efficiency and operation of the fired heater suffers from using flames of fuel gas with very different component ranges than those used for an original design. Further, fuel gas generated from operation of a natural gas separation unit is often a portion of a desired sales gas product stream with substantial economic value as a stream having specification composition for which processing energy has been expended and for which equipment has been purchased.
The present invention has integrated into the operation of the high pressure section (gas dewpointing) and the low pressure section (oil/condensate stabilization) a fuel gas section that receives a portion of a combined stream after splitting off the sales gas product. The fuel gas section produces a fuel gas of desired component ranges of components that are of lesser economic value to the overall process, a substantial improvement over prior art natural gas separation processes by recovering propane and butanes contained in the fuel gas stream
The present invention requires, but not limited to, a closed loop propane refrigeration system for multiple heat exchange steps, but no colder temperatures than that required for external refrigeration sources for operation of the invention processes. Refrigeration is also provided by other low temperature separation technique e.g. JT, post chilling JT, turbo-expansion, etc.
A first invention separation unit operates to produce sales gas, fuel gas, sales condensate, and sales oil streams. A second invention separation unit operates to produce sales gas, fuel gas, and a stabilized oil stream. Both invention separation units operate using the above described first separation stages and exchange of gas and liquid streams, although downstream equipment and processing steps differ between the first and second invention separation units to achieve those desired product streams.
Further, the present invention in a second embodiment provides for a natural gas fractionation process where fractionation control provides for increased levels of propane and butanes in the sales gas fraction ensuring elimination of hydrocarbon build-up and hence no flaring. In some circumstances, as much as ninety-nine percent of propane and butanes in feed streams from wellhead production is recovered into and transported in a sales gas transportation pipeline to a distant NGL extraction complex. The distant processing facility optionally recover and separate the propane and butanes from the sales gas for separate product distribution.
Various objects and advantages of the present invention will become apparent from the following description taken in conjunction with the accompanying drawings wherein are set forth, by way of illustration and example, certain embodiments of this invention. The drawings submitted herewith constitute a part of this specification, include exemplary embodiments of the present invention, and illustrate various objects and features thereof.
As required, detailed embodiments of the present invention are disclosed herein; however, it is to be understood that the disclosed embodiments are merely exemplary of the invention, which may be embodied in various forms. Therefore, specific structural and functional details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the present invention in virtually any appropriately detailed structure.
For
HP FEED at high pressure from wellhead production or upstream compressing is supplied to first separation drum V-101. LP FEED at lower pressure from wellhead production or other sources is supplied to first stage separation drum V-100.
The above described critical exchange of streams is shown at (1) gas stream 4 from drum V-101 is fed to separation drum V-108 to combine with a compressed and cooled stream in the low pressure section of the separation unit and (2) liquid stream 2 is pumped (pump not shown; as indicated in the drawing figures and in the stream data in
Beginning again with stream LP FEED, V-100 receives that stream and streams 35 and 38, all combining there to be separated into gas stream 1 and liquid stream 2. Stream 1 is compressed in compressor K-101 to form stream 41 and is air cooled in air cooler AC-102, forming stream 42, which is fed to drum V-107. Stream 42 is separated into liquid stream 35 (returned to drum V-100) and gas stream 33, which is fed into drum V-108 with gas stream 4 (from high pressure first stage separation drum V-101) and separated there into liquid stream 38 (returned to drum V-100) and gas stream 36, which is fed to combined unit U-1 to remove for acid gas, water and mercury to form a stream cooled in exchanger E105 to form stream 42. Stream 42 is fed to column T-101, which also receives liquid stream 72. Column T-101 comprises a propane refrigerant-cooled condenser and separator unit C2 to generate reflux for column T-101 and a reboiler R2 for reboiling column T-101. Column T-101 forms overhead gas stream 43, which is warmed in exchanger E-105 to form stream 52. Stream 52 is compressed in compressor K-102 to form stream 60, which is air cooled in air cooler AC-103 to form stream 62. Stream 62 is split into two gas stream, one treated in mole sieve dehydration unit U-2 to form stream 65 and the other compressed in compressor K-104 to form gas stream 60, which is cooled in air cooler AC-104 to form the stream SALES GAS to sales gas specifications. Column T-101 forms bottom stream 44, which is cooled in exchanger E-102 to form stream 45, which results in a liquid stream split into two streams, one stream SALES COND, which is sales condensate to well known specifications, and stream 50.
Referring again to
Stream 50 (from a bottoms stream of column T-101) and stream 65 (a portion of the overhead gas stream of column T-101) are cooled multi-stream exchanger LNG-100 against stream C3a (a propane refrigerant stream) and streams 70 and 78. Stream 65 is cooled to form stream 66, which is fed to the bottom of column T-100, an absorber column. Stream 50 is cooled to form stream 51, which is combined with the overhead gas stream of column T-100, the combined stream being cooled in multi-stream exchanger LNG-101 against stream C3b (a propane refrigerant stream) and streams 69 and 76 to form stream 74. Stream 74 is separated in drum V-103 to gas stream 76 and liquid stream 77. Liquid stream 77 is fed to the top stage of column T-100 to provide absorbing liquid. Gas stream 76 is warmed to form stream 78 and warmed again in multi-stream exchanger LNG-100 to form stream FUEL to provide specification range fuel gas.
Column T-100 produces an bottoms liquid stream 69, which is warmed in exchanger LNG-100 to form stream 71, which in turn is further warmed in exchanger E-102 to form stream 72, which is fed to column T-101.
HP FEED at high pressure from wellhead production or upstream compressing is supplied to first separation drum V-101. LP FEED at lower pressure from wellhead production or other sources is supplied to first stage separation drum V-100.
The above described critical exchange of streams is shown at (1) gas stream 4 from drum V-101 is fed to separation drum V-108 to combine with a compressed and cooled stream in the low pressure section of the separation unit and (2) liquid stream 7 is pumped (pump not shown; as indicated in the drawing figures and in the stream data in
Beginning again with stream LP FEED, V-100 receives that stream and streams 46 and 48, all combining there to be separated into gas stream 1 and liquid stream 2. Stream 1 is compressed in compressor K-101 to form stream 41 and is air cooled in air cooler AC-102, forming stream 42, which is fed to drum V-107. Stream 42 is separated into liquid stream 46 (returned to drum V-100) and gas stream 47, which is fed into drum V-108 with gas stream 4 (from high pressure first stage separation drum V-101) and separated there into liquid stream 48 (returned to drum V-100) and gas stream 47, which is fed to combined unit U-1 to remove for acid gas, water and mercury to form a stream cooled in exchanger E105 to form stream 53. Stream 53 is further cooled in exchanger E-107 against propane refrigerant and fed to the bottom stage of column C5 SCRUBBER, an absorber column. Column C5 SCRUBBER receives stream 34 to a top stage to produce an overhead gas stream 55, which is warmed in exchanger E-105 to form stream 59. Stream 59 is combined with stream 30, the combined stream compressed in compressor K-102 to form stream 62, which is cooled in air cooler AC-103 to form stream 63. Stream 63 is split into two gas stream, one treated in mole sieve unit U-2 to form stream 72 and the other compressed in compressor K-104 to form gas stream 67, which is cooled in air cooler AC-104 to form the stream SALES GAS to sales gas specifications.
Referring again to
A liquid stream 26 from drum V-111 is fed to a top stage of column Stab-1 to provide reflux for the column. The bottoms liquid stream 56 is cooled in exchanger E-103 to form stream 58, which is fed to column Stab-1 with stream 79. The gas stream 23 from drum V-111 is treated in TEG dehydration and mercury removed unit U-4 and is then split into two streams, one stream being cooled in air cooler AC-107 to form stream 32, which is in turn cooled in exchanger E-103 to form stream 33. Stream 33 is cooled in exchanger E-104 (against propane refrigerant) to form stream 34, which is fed to the top stage of column C5 SCRUBBER. The second of the split streams from stream 23 is stream 30, which is combined with stream 59 (from the overhead gas stream of column C5 SCRUBBER).
The processes of
It will be understood that the present invention embodiments for a process of separating hydrocarbon fluid feeds at two pressures can be thought of as a process for separating a hydrocarbon fluid feed at a single high pressure, where the above LP feed liquid is fed to the HP feed drum and the LP feed gas is compressed to a higher pressure or all of hydrocarbon fluid feed is provided at the pressure of the HP feed and processed as if there were no LP feed.
It is to be understood that while certain forms of the present invention have been illustrated and described herein, it is not to be limited to the specific forms or arrangement of parts described and shown.
