Method of processing produced natural gas
Patent Information
- Authority / Receiving Office
- WO · WO
- Patent Type
- Applications
- Current Assignee / Owner
- 1304338 ALBERTA LTD
- Filing Date
- 2026-01-23
- Publication Date
- 2026-08-06
Smart Images
Figure CA2026050108_06082026_PF_FP_ABST
Abstract
Description
METHOD OF PROCESSING PRODUCED NATURAL GASFIELD
[0001] This relates to a method of processing natural gas by generation of cold temperatures and membrane gas separation.BACKGROUND
[0002] Natural gas from a production well may contain impurities, i.e. , water and acid gases along with natural gas liquids. The natural gas pre-treatment of acid gases when present are typically treated in an amine unit and the water moisture is typically treated in a glycol unit. Following pre-treatment, natural gas liquids (NGLs) are cooled and condensed and separated by distillation. The pre-treatment and treatment are intended to ensure well- produced natural gas meets transmission pipeline specifications for transport to market.
[0003] The standard practice to treat sour natural gas is by chemical absorption in an amine unit. The amine unit has two towers, an absorption tower and a regeneration tower. Heat is typically supplied by steam for the chemical amine regeneration in the separation of acid gases from the chemical amine absorbent. The separated sour gases are compressed and routed to either an acid gas injection well or to a sulfur processing unit. The regenerated chemical amine absorbent is recycled back to the absorption tower. The treated sour gas exits the amine absorption tower as sweet gas and is routed to a glycol treatment unit for water moisture removal.
[0004] The standard practice to treat water moisture in natural gas is also by chemical absorption in a glycol unit. The glycol unit also has two towers, an absorption tower and a regeneration tower. Heat is typically supplied by steam for the chemical glycol regeneration in the separation of water from the chemical glycol absorbent. The absorbed and separated water is then cooled and pumped to an injection well and the regenerated chemical glycol absorbent is recycled back to the absorption tower. The treated moisture content natural gas exits the glycol absorption tower as dry sweet gasand is routed to a NGLs recovery unit.
[0005] The NGLs recovery unit, typically consists of a refrigeration plant, heat exchangers, gas separator drums, a distillation tower and reboilers. The refrigeration plant provides cooling through heat exchange to chill and condense the natural gas into a separator before the distillation tower. The separated streams are routed to the distillation tower for fractionation. The tower overhead stream is further cooled by the refrigeration plant to generate a tower reflux stream. The tower bottoms stream is circulated through a reboiler and routed to the distillation tower for fractionation to control light fraction gas composition in the NGLs stream. The distillation tower overhead stream of treated and dry sweet natural gas is routed to a gas compressor station where it is compressed into a transmission gas pipeline and transported to market.SUMMARY
[0006] There is provided a method for pre-treatment and treatment of well-produced natural gas using a combination of heat exchangers, separators, gas turbine expanders and gas membranes. The process eliminates the standard use of amine and glycol units to pre-treat the well-produced natural gas and an external refrigeration source to extract the NGLs.
[0007] As will hereinafter be further described, the interacting step is both direct and indirect. Indirect interaction is achieved through the use of heat exchangers. Direct interaction is achieved by reflux streams to cool, strip and condense gaseous natural gas streams in gas contact separators.
[0008] According to an aspect, a method to pre-treat and treat a well-produced gas stream recovers well gas pressure to generate cold energy for this refrigeration process and produce electricity, and comprises the steps of cooling a well-produced gas stream by self-produced refrigeration and using it indirectly and directly in interactive steps in a counter-current series for selective extraction of hydrocarbon and sour liquids. Indirect cooling is provided by counter-current heat exchangers in series. Direct cooling isprovided by reflux streams to cool, strip and condense heavier gas fractions in a series of contact separators. The cooling, extraction and separation is done at high pressure thus enhancing dew points for condensation. Self-refrigeration is generated by expanding the stripped well-produced gas pressure in a gas expander-generator to a pressure that meets plant self-refrigeration needs. Membranes are used to separate extracted liquids fractions in lieu of fractionation and reboilers.
[0009] According to other aspects, the interacting step may be an indirect interaction through heat exchangers in a counter-current series operation, and may be a direct interaction by a reflux stream to cool, strip and condense in a counter-current series of contact separators; direct interaction by reflux streams may be used to cool, strip and condense in a counter-current series separation in a variable flow to meet various process conditions; membranes may be employed to separate extracted liquids in lieu of fractionation and reboilers; the interacting step may be repeated sequentially at selected gas fractions dew points in separate contact separators to cool, strip, condense and extract liquids from the well-produced natural gas stream; the cooling, stripping, condensing and extraction may be done at near inlet plant pressures, enhancing dew points liquids condensation; a methanol circulating system may be employed to absorb water moisture from a de-watered well gas stream, heat required for methanol regeneration supplied from heat of gas compression; self-refrigeration plant requirements may be controlled by pressure letdown at the gas expander-generator; the recovery of energy from the well-produced gas may reduce the GHG emissions of gas processing when compared to typical gas processing units; the interacting step may be performed in a gas pre-treatment and treatment facility, comprising: heat exchangers, knock out drums, methanol circulating system, contact separators, membranes, gas expandergenerators, pumps, and / or compressor(s); there may be more than one contact separator, each contact separator operating at a selected dew point in order to condense liquids carried in the rich natural gas stream; the refrigeration energy may be supplied by recovery of the inlet gas pressure energy; and the cooling used in the method may be derived entirely from gas pressure and ambient temperatures.
[0010] Other aspects will be apparent from the description and drawings.BRIEF DESCRIPTION OF THE DRAWINGS
[0011] These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to in any way limit the scope of the claims to the particular embodiment or embodiments shown, wherein:FIG. 1 is a schematic diagram of a process that pre-treats and treats well-produced natural gas and recovers NGLs and liquid sour streams using self-generated refrigeration.FIG. 2 is a schematic diagram of a process that pre-treats and treats well-produced sour natural gas and recover NGLs and liquid sour streams using selfgenerated refrigeration. This example involves a two-step natural gas pressure reduction for high pressure gas wells.FIG. 3 is a schematic diagram of a process that pre-treats and treats a well-produced sweet natural gas using self-generated cooling.FIG. 4 is a schematic diagram of a process that pre-treats and treats well-produced sour natural gas and recover NGLs using self-generated refrigeration. This example uses a compressor to boost well-production gas pressure to increase selfrefrigeration capacity, such as when well-produced gas pressure may be insufficient. This may also be used with sweet gas production wells.DETAILED DESCRIPTION
[0012] Processes for treating well-produced natural gas using self-generated refrigeration will now be described with reference to FIG. 1 through 4. The depicted processes may be adapted for sour and sweet wells, depending on whether the natural gas produced by the wells contain H2S or not. As the diagrams are schematics, it will be understood that they may be adapted into facilities by providing suitable equipment. A hydrocarbon well may be considered a natural gas producing well when the produced fluids include a stream of natural gas that is captured by the well operator. While a well may produce both gas and liquid fractions, the present discussion relates to the produced gas fraction and other equipment for handling liquids will not be described further.
[0013] In the example shown in FIG. 1, a natural stream 1 produced from a well, which may contain sour gas, is pre-cooled in heat exchanger 2, and the pre-cooled stream 3 enters knock out drum 4 where condensed water is removed. The condensed water exits knock out drum 4 as water stream 5. The de-watered natural gas stream 6 is injected with a dehydrant, such as methanol in the examples discussed below, through stream 18 to adsorb water moisture in sour gas stream 6. The sour gas / methanol mixture stream 7 enters knock out drum 8 where the methanol / water mixture is separated from the sour gas. The methanol / water mixture exits knock out drum 8 through stream 9 and pumped by pump 10. The pressurized methanol / water stream 11 is pre-heated in heat exchanger 12 and routed through stream 13 to knock out drum 14 to separate the methanol from the water. The water exits knock out drum 14 through stream 15. The methanol stream 16 is cooled and condensed in fin-fan 84, enters pump 17, and is then injected into sour gas line 6. The de-watered sour gas stream 19 enters gas separator 20 to condense and separate the C4+fractions. This condensation and separation is achieved by injecting a cold reflux stream 36 near the top of separator 20 to cool, strip and condense C4+fractions to produce gaseous stream 27. The conditions in separator 20 and / or cold reflux stream 36 may be controlled to generally separate 04’ fractions, which exit via gaseous stream 27, and C4+fractions as a liquid, which exit separator 20 through liquid stream 21.
[0014] While the process describes gaseous stream 27 as containing 04’ fractions and liquid stream 21 as containing C4+fractions, there may be some C4+fractions in gaseous stream 27 and some 04’ fractions in liquid stream 21. Similar considerations apply to other streams, and as such, a reference to Cn+and On’ may be understood to include other components that are lighter or heavier than the named component. The various separation and recycling steps are intended to increase the desired fraction in a given stream. In addition, while the process describes C4+as the heaviest hydrocarbons, the process may be adapted to extract different components, depending on the composition of the inlet gas stream, the desired product streams, the equipment used, and the preferences of the user. Such changes may take into account the different boiling points and phase diagrams for different hydrocarbons.
[0015] C4+liquid fractions in stream 21 enter pump 22, which results in pressurizedC4+fractions in stream 23. The pressurized C4+fractions pass through membrane separator 24 and are routed through stream 25 to storage, while any separated light fractions C4’ exit membrane separator 24 and are routed through stream 26 to stream 37, which may be referred to as a Cs+fractions stream. The overhead gas stream 27 from separator 20, which is primarily C4’ fractions and may include sour gas, is further cooled in heat exchanger 28 to generate a pre-cooled sour gas stream 29 that enters gas separator 30 to condense and separate any Cs+fractions. This condensation and separation is achieved by injecting a cold reflux stream 51 near the top of separator 30 to cool, strip and condense Cs+fractions from gaseous stream 42. The stripped and condensed Cs+fractions exit separator 30 through stream 31 and enters pump 32, which results in pressurized Cs+fractions in stream 33. Stream 33 may then be split into stream 34 and stream 37. Stream 34 is routed through control valve 35 to provide a reflux stream 36 to gas separator 20 to cool, strip and condense C4+fractions as discussed above. Stream 37, is mixed with stream 26, C4’ fractions, and the mixed stream 38 enters membrane separator 39, which separates Cs+fractions from Cs" fraction. The separated Cs+fractions are routed to storage through stream 40 and separated light fractions Cs" from membrane separator 39 are routed through stream 41 to combine with stream 52, which may be a stream of H2S+CO2+C2+fractions. The overhead stream 42 from separator 30 may include sour gas stream and Cs" fractions, exits separator 30 and is further cooled in heat exchanger 43 the pre-cooled sour gas stream 44 enters sour gas separator 45 to condense and separate H2S + CO2 fractions. This condensation and separation is achieved by injecting a cold reflux stream 69 near the top of separator 45 to cool, strip and condense H2S + CO2 fractions from gaseous stream 57. The stripped and condensed H2S+CO2 fractions exit separator 45 through stream 46, enters pump 47 and the pressurized H2S+CO2 fractions stream 48 is split into stream 49 and stream 52. Stream 49 is routed through control valve 50 to provide a reflux stream 51 to gas separator 45 to cool, strip and condense H2S+CO2 fractions. Stream 52, of H2S+CO2 fractions is mixed with stream 56, Cs" fractions, and the mixed stream 53 enters membrane separator 54, the separated H2S+CO2 fractions are routed through stream 55 to a gas injection well or to a sulphur recovery unit. Separated C2+fractions exit membrane separator 54 and are routed through stream 56 to stream 70, C2+fractionsstream. The separator overhead stream C2’ fractions 57 exits separator 45 and is further cooled in heat exchanger 58 and routed through stream 59 into gas expander 60. The decrease in pressure by expander 60, is controlled to generate the cryogenic temperatures required for the pre-treatment and treatment of the well-produced sour gas. The expansion of the well pressure gas in expander 60, generates electricity through generator 61. The cryogenic gas stream 62 enters gas separator 63 to separate the C2+fractions from the Ci+fractions.
[0016] The condensed C2+fractions exit separator 63 through stream 64 enters pump 65 and the pressurized C2+fractions stream 66 is split into stream 67 and stream 70. Stream 67 is routed through control valve 68 to provide a reflux stream 69 to gas separator 45 to cool, strip and condense H2S+CO2 fractions. Stream 70, of C2+fractions is mixed with stream 56, C2+fractions, and the mixed stream 71 enters membrane separator 72, the separated C2+fractions are routed through stream 73 to storage and separated fractions C2’ exit membrane separator 72 and are routed through stream 74 to stream 75, Ci+fractions stream exiting separator 63. The cryogenic gas stream 76 is routed through heat exchanger 58 to cool stream 57, and further routed through stream 77 to heat exchanger 43 to cool stream 42, and further routed through stream 78 to heat exchanger 28 to cool stream 27. The gas stream 79 is routed through to heat exchanger 2 to pre-cool stream 1 and routed through stream 80 to compressor 81 to compress the treated well-produced gas to pipeline transmission pressure. The compressed hot gas stream 82 is routed through heat exchanger 12 to supply heat to methanol / water mixture stream 11 and routed to natural gas transmission pipeline through stream 83.
[0017] As can be seen, the depicted treatment process may occur at or around the same pressure as the pressure of the well gas stream 1. In particular, while some pressure drop may inevitably occur as the stream passes through the various equipment, the pressure is generally maintained at around the same pressure until gas stream 59 is expanded in expander 60.
[0018] While not shown, streams 25, 40, 55, and 73 may be captured in storage vessels for storage or transport, or in other transport / storage equipment.
[0019] The proportion of liquid streams 31, 46, and 64 that are returned as reflux streams 36, 51 , and 69, respectively, or passed through membrane separator 39, 54, and 72, respectively, may vary depending on the preferences of the user, the composition of the input streams, and the desired product streams.
[0020] Referring to FIG. 2, there are gas producing wells that have gas pressures greater than 70 bar. The proposed process is enhanced when these higher pressures are available, an higher well gas pressure results in more power generation, more cold energy generated and lower gas compression requirements. The main difference from FIG. 1 is the introduction of an additional gas expander 285.
[0021] A well-produced natural sour gas stream 201 is pre-cooled in heat exchanger 202, and the pre-cooled stream 203 enters knock out drum 204 where condensed water is removed. The condensed water exits knock out drum 204 through stream 205. The dewater sour gas stream 206 is injected with methanol through stream 218 to adsorb water moisture in sour gas stream 206. The sour gas / methanol mixture stream 207 enters knock out drum 208 where the methanol / water mixture is separated from the sour gas. The methanol / water mixture exits knock out drum 208 through stream 209 and pumped by pump 210. The pressurized methanol / water stream 211 is pre-heated in heat exchanger 212 and routed through stream 213 to knock out drum 214 to separate the methanol from the water. The water exits knock out drum 214 through stream 215. The methanol stream 216 is cooled and condensed in fin-fan 287 and enters pump 217 the pressurized methanol stream 218 is injected into sour gas line 206. The dewatered sour gas stream 284, is routed to expander generator 285. This intermediate decrease in pressure by expander 285, is controlled to generate refrigeration for the pre-treatment and treatment of the well-produced sour gas. The expansion of the well pressure gas in expander 285, generates electricity through generator 286. The cold gas stream 219 enters gas separator 220 to separate the C4+fractions. This intermediate process pressure reduction step allows for a more efficient separation and an increment in power generation.
[0022] The pre-cooled sour gas stream 219 enters gas separator 220 to condense andseparate the C4+fractions. This condensation and separation is achieved by injecting a cold reflux stream 236 near the top of separator 220 to cool, strip and condense C4+fractions from gaseous stream 227. The stripped and condensed C4+fractions exit separator 220 through stream 221 enters pump 222 and the pressurized C4+fractions stream 223 enters membrane separator 224, the separated C4+fractions are routed through stream 225 to storage and separated fractions C4’ exit membrane separator 224 and are routed through stream 226 to stream 237, Cs+fractions stream. The separator overhead sour gas stream 227, C4’ fractions, exits separator 220 and is further cooled in heat exchanger 228 the pre-cooled sour gas stream 229 enters gas separator 230 to condense and separate the Cs+fractions. This condensation and separation is achieved by injecting a cold reflux stream 251 near the top of separator 230 to cool, strip and condense Cs+fractions from gaseous stream 242. The stripped and condensed Cs+fractions exit separator 230 through stream 231 enters pump 232 and the pressurized Cs+fractions stream 233 is split into stream 234 and stream 237. Stream 234 is routed through control valve 235 to provide a reflux stream 236 to gas separator 220 to cool, strip and condense C4+fractions. Stream 237, of Cs+fractions is mixed with stream 226, C4' fractions, and the mixed stream 238 enters membrane separator 239, the separated Cs+fractions are routed through stream 240 to storage and separated fractions Cs" exit membrane separator 239 and are routed through stream 241 to stream 252, H2S+CO2 fractions stream. The separator overhead sour gas stream 242, Cs" fractions, exits separator 230 and is further cooled in heat exchanger 243 the pre-cooled sour gas stream 244 enters sour gas separator 245 to condense and separate H2S+CO2 fractions. This condensation and separation is achieved by injecting a cold reflux stream 269 near the top of separator 245 to cool, strip and condense H2S+CO2 fractions from gaseous stream 257. The stripped and condensed H2S+CO2 fractions exit separator 245 through stream 246, enters pump 247 and the pressurized H2S+CO2 fractions stream 248 is split into stream 249 and stream 252. Stream 249 is routed through control valve 250 to provide a reflux stream 251 to gas separator 245 to cool, strip and condense H2S+CO2 fractions. Stream 252, of H2S+CO2 fractions is mixed with stream 256, Cs" fractions, and the mixed stream 253 enters membrane separator 254, the separated H2S+CO2 fractions are routed through stream 255 to a gas injection well or to a sulphur recovery unit. SeparatedC2+fractions exit membrane separator 254 and are routed through stream 256 to stream 270, C2+fractions stream. The separator overhead stream C2’ fractions 257 exits separator 245 and is further cooled in heat exchanger 258 and routed through stream 259 into gas expander 260. The decrease in pressure by expander 260, is controlled to generate the cryogenic temperatures required for the pre-treatment and treatment of the well-produced sour gas. The expansion of the well pressure gas in expander 260, generates electricity through generator 261. The cryogenic gas stream 262 enters gas separator 263 to separate the C2+fractions from the Ci+fractions.
[0023] The condensed C2+fractions exit separator 263 through stream 264 enters pump 265 and the pressurized C2+fractions stream 266 is split into stream 267 and stream 270. Stream 267 is routed through control valve 268 to provide a reflux stream 269 to gas separator 245 to cool, strip and condense H2S+CO2 fractions. Stream 270, of C2+fractions is mixed with stream 256, C2+fractions, and the mixed stream 271 enters membrane separator 272, the separated C2+fractions are routed through stream 273 to storage and separated fractions C2’ exit membrane separator 272 and are routed through stream 274 to stream 275, Ci+fractions stream exiting separator 263. The cryogenic gas stream 276 is routed through heat exchanger 258 to cool stream 257, and further routed through stream 277 to heat exchanger 243 to cool stream 242, and further routed through stream 278 to heat exchanger 228 to cool stream 227. The gas stream 279 is routed through heat exchanger 202 to pre-cool stream 201 and routed through stream 280 to compressor 281 to compress the treated well-produced gas to pipeline transmission pressure. The compressed hot gas stream 282 is routed through heat exchanger 212 to supply heat to methanol / water mixture stream 211 and routed to natural gas transmission pipeline through stream 283.
[0024] This intermediate process pressure reduction step allows for a more efficient separation and an increment in power generation.
[0025] Referring to FIG. 3 shows another arrangement with just three separators to process a well-produced sweet gas stream.
[0026] A well-produced sweet natural gas stream 301 is pre-cooled in heat exchanger302, and the pre-cooled stream 303 enters knock out drum 304 where condensed water is removed. The condensed water exits knock out drum 304 through stream 305. The dewater sweet gas stream 306 is injected with methanol through stream 318 to adsorb water moisture in sweet gas stream 306. The sour gas / methanol mixture stream 307 enters knock out drum 308 where the methanol / water mixture is separated from the sweet gas. The methanol / water mixture exits knock out drum 308 through stream 309 and pumped by pump 310. The pressurized methanol / water stream 311 is pre-heated in heat exchanger 312 and routed through stream 313 to knock out drum 314 to separate the methanol from the water. The water exits knock out drum 314 through stream 315. The methanol stream 316 is cooled and condensed in fin-fan 368 and enters pump 317 the pressurized methanol stream 318 is injected into sweet gas line 306. The de-watered sweet gas stream 319 enters gas separator 320 to condense and separate the C4+fractions. This condensation and separation is achieved by injecting a cold reflux stream 336 near the top of separator 320 to cool, strip and condense C4+fractions from gaseous stream 327. The stripped and condensed C4+fractions exit separator 320 through stream 321 enters pump 322 and the pressurized C4+fractions stream 323 enters membrane separator 324, the separated C4+fractions are routed through stream 325 to storage and separated fractions C4’ exit membrane separator 324 and are routed through stream 326 to stream 337, Cs+fractions stream. The separator overhead sweet gas stream 327, C4’ fractions, exits separator 320 and is further cooled in heat exchanger 328 the pre-cooled sweet gas stream 329 enters gas separator 330 to condense and separate the Cs+fractions. This condensation and separation is achieved by injecting a cold reflux stream 351 near the top of separator 330 to cool, strip and condense Cs+fractions from gaseous stream 342. The stripped and condensed Cs+fractions exit separator 330 through stream 331 enters pump 332 and the pressurized Cs+fractions stream 333 is split into stream 334 and stream 337. Stream 334 is routed through control valve 335 to provide a reflux stream 336 to gas separator 320 to cool, strip and condense C4+fractions. Stream 337, of Cs+fractions is mixed with stream 326, C4’ fractions, and the mixed stream 338 enters membrane separator 339, the separated Cs+fractions are routed through stream 340 to storage and separated fractions Cs" exit membrane separator 339 and are routed through stream 341 to stream 52, C2+fractions stream. The separator overhead sweet gas stream342, Cs fractions, exits separator 330 and is further cooled in heat exchanger 343 and routed through stream 344 into gas expander 345. The decrease in pressure by expander 345, is controlled to generate the cryogenic temperatures required for the pre-treatment and treatment of the well-produced sweet gas. The expansion of the well pressure gas in expander 345, generates electricity through generator 346. The cryogenic gas stream 347 enters gas separator 348 to separate the C2+fractions from the Ci+fractions.
[0027] The condensed C2+fractions exit gas separator 348 through stream 349 enters pump 350 and the pressurized C2+fractions stream 351 is split into stream 352 and stream 355. Stream 352 is routed through control valve 353 to provide a reflux stream 354 to gas separator 330 to cool, strip and condense Cs+fractions. Stream 355, of C2+fractions is mixed with stream 341, C2+fractions, and the mixed stream 356 enters membrane separator 357, the separated C2+fractions are routed through stream 358 to storage and separated fractions C2’ exit membrane separator 357 and are routed through stream 359 to stream 360, Ci+fractions stream exiting separator 348. The cryogenic gas stream 361 is routed through heat exchanger 343 to cool stream 342, and further routed through stream 362 to heat exchanger 328 to cool stream 327, and further routed through stream 363 to heat exchanger 302 to pre-cool stream 301 and routed through stream 364 to compressor 365 to compress the treated well-produced gas to pipeline transmission pressure. The compressed hot gas stream 82 is routed through heat exchanger 312 to supply heat to methanol / water mixture stream 311 and routed to natural gas transmission pipeline through stream 367.
[0028] Referring to FIG. 4 shows another arrangement where a compressor 468 is added on to the well-production gas stream 401 to boost the plant inlet pressure to meet the self-refrigeration pressure requirements if the well gas pressure is insufficient.
[0029] Well-production gas stream 401 is pre-cooled in heat exchanger 402, and the pre-cooled stream 403 enters knock out drum 404 where condensed water is removed. The condensed water exits knock out drum 404 through stream 405. The de-water sweet gas stream 406 is injected with methanol through stream 418 to adsorb water moisture in sweet gas stream 406. The sour gas / methanol mixture stream 407 enters knock outdrum 408 where the methanol / water mixture is separated from the sweet gas. The methanol / water mixture exits knock out drum 408 through stream 409 and pumped by pump 410. The pressurized methanol / water stream 411 is pre-heated in heat exchanger 412 and routed through stream 413 to knock out drum 414 to separate the methanol from the water. The water exits knock out drum 414 through stream 415. The methanol stream 416 is cooled and condensed in fin-fan 468 and enters pump 417 the pressurized methanol stream 418 is injected into sweet gas line 406. The de-watered sweet gas stream 419 enters gas separator 420 to condense and separate the C4+fractions. This condensation and separation is achieved by injecting a cold reflux stream 436 near the top of separator 420 to cool, strip and condense C4+fractions from gaseous stream 427. The stripped and condensed C4+fractions exit separator 420 through stream 421 enters pump 422 and the pressurized C4+fractions stream 423 enters membrane separator 424, the separated C4+fractions are routed through stream 425 to storage and separated fractions C exit membrane separator 424 and are routed through stream 426 to stream 437, Cs+fractions stream. The separator overhead sweet gas stream 427, C fractions, exits separator 420 and is further cooled in heat exchanger 428 the pre-cooled sweet gas stream 429 enters gas separator 430 to condense and separate the Cs+fractions. This condensation and separation is achieved by injecting a cold reflux stream 451 near the top of separator 430 to cool, strip and condense Cs+fractions from gaseous stream 442. The stripped and condensed Cs+fractions exit separator 430 through stream 431 enters pump 432 and the pressurized Cs+fractions stream 433 is split into stream 434 and stream 437. Stream 434 is routed through control valve 435 to provide a reflux stream 436 to gas separator 420 to cool, strip and condense C4+fractions. Stream 437, of Cs+fractions is mixed with stream 426, C fractions, and the mixed stream 438 enters membrane separator 439, the separated Cs+fractions are routed through stream 440 to storage and separated fractions Cs" exit membrane separator 439 and are routed through stream 441 to stream 52, C2+fractions stream. The separator overhead sweet gas stream 442, C3' fractions, exits separator 430 and is further cooled in heat exchanger 443 and routed through stream 444 into gas expander 445. The decrease in pressure by expander 445, is controlled to generate the cryogenic temperatures required for the pre-treatment and treatment of the well-produced sweet gas. The expansion of the well pressure gasin expander 445, generates electricity through generator 446. The cryogenic gas stream 447 enters gas separator 448 to separate the C2+fractions from the Ci+fractions.
[0030] The condensed C2+fractions exit gas separator 448 through stream 449 enters pump 450 and the pressurized C2+fractions stream 451 is split into stream 452 and stream 455. Stream 452 is routed through control valve 453 to provide a reflux stream 454 to gas separator 430 to cool, strip and condense Cs+fractions. Stream 455, of C2+fractions is mixed with stream 441, C2+fractions, and the mixed stream 456 enters membrane separator 457, the separated C2+fractions are routed through stream 458 to storage and separated fractions C2’ exit membrane separator 457 and are routed through stream 459 to stream 460, Ci+fractions stream exiting separator 448. The cryogenic gas stream 461 is routed through heat exchanger 443 to cool stream 442, and further routed through stream 462 to heat exchanger 428 to cool stream 427, and further routed through stream 463 to heat exchanger 402 to pre-cool stream 401 and routed through stream 464 to compressor 465 to compress the treated well-produced gas to pipeline transmission pressure. The compressed hot gas stream 82 is routed through heat exchanger 412 to supply heat to methanol / water mixture stream 411 and routed to natural gas transmission pipeline through stream 467.
[0031] In the preferred method, the control of the well-produced gas pressure provides the “cold energy” required to condense and extract the NGLs and simultaneously produces electricity. Typically, the industry dissipates the well-produced gas pressure through pressure reducing valves to meet amine and glycol plant pressure operations. The above described method eliminates the common practice of employing amine and glycol units to pre-treat the gas. The described method, employs the principle of direct and indirect chi ller / refrigeration principles to condense and separate the liquids in the gas composition by generating “cold energy” by controlling and expanding the well-produced gas pressure through a gas expander-generator. The cold energy generated is employed in the process by indirect and direct means. The cold energy is employed indirectly by the gaseous streams in heat exchangers whereas cold energy is also provided directly by cold liquid reflux streams to cool, strip and condense “rich” gas in contact separators. This direct mixing provides better heat transfer and eliminates the need for cryogenic andrefrigeration plants to condense NGLs. Moreover, it provides for a wide range of refrigeration temperature operations by controlling the decrease in well-produced gas pressure. The above method allows for ease of “turndown”, the expanded well-produced gas cold energy generation is controlled by a single pressure control setpoint to pre-treat and condense the NGLs in the “rich” gas stream ready for compression and transmission to pipelines.
[0032] Existing plants operate in a mode that first pre-treats the well-produced gas to remove the sour gases in an amine unit. This is followed by a glycol unit to dry the well-produced gas and afterwards refrigeration systems are employed to cool and condense the natural gas liquids (NGLs) before compression of the lean gas to transmission pipelines and distribution to markets. In some cases due to limited well gas production partial pre-treatment is employed and NGLs are recovered at third party gas processing plants. The described process also provides an economic alternative for small gas producers to pre-treat and recover the NGLs by using the well-produced gas pressure. Another feature of the process is the use of membranes to separate the liquid fractions in lieu of traditional reboilers. Membrane technology is well established but has not been used in the gas processing industry in lieu of reboilers. The combination and use of membranes separators in series to route the separated streams is novel in the gas processing industry.
[0033] According to an aspect, there is provided a method to generate electricity and cold energy from a well-produced gas pressure to pre-treat and treat a sour rich gas by indirect and direct refrigeration by pressure control. The first step is the pre-cooling in a heat exchanger of the incoming “rich” natural gas stream, containing methane, ethane, propane, butanes, pentanes, other heavier hydrocarbons, water and sour gases with a counter-current flow of “lean” natural gas. A second step involves the separation of water followed by a methanol injection system to absorb and remove water moisture in the separated gaseous stream. A third step involves the separation of heavier hydrocarbons, sour gases and lighter hydrocarbons in a series of separators by controlling the overhead temperature at each separator by direct contact of a cold reflux stream at each separator. A fourth step involves the addition of heat exchangers between separators to indirectlyrecover cold energy. A fifth step involves the use of membranes to separate and re-route the condensed liquid fractions to storage and further separation. A sixth step involves the ability to control well-produced gas pressure to generate the cold energy for self-process refrigeration and production of electricity. A seventh step provides for ease of “turndown” to meet variable well-gas flowrates.
[0034] The use of the above described method at a well-production gas facility may allow for the following features:1. The present method may be designed to operate without amine or glycol units as the process operates on the principle of refrigeration. The well-gas pressure may be used as the source of energy for the process to produce electricity and selfrefrigeration.2. Sour gases may be recovered as a liquid fraction and pumped in lieu of recovery as gas requiring compression.3. Membranes may be used in lieu of reboilers for recovery of NGLs.4. Methanol may be used to absorb water moisture, and heat for methanol regeneration may be provided by heat of compression.5. Well-produced gas pressure may be recovered and converted into cold energy and electricity to reduce the need for refrigeration and power equipment, therefore reducing the GHG emissions.
[0035] In this patent document, the word "comprising" is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article "a" does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements.
[0036] It will be apparent to one skilled in the art that modifications may be made to the illustrated embodiment without departing from the spirit and scope of the invention as hereinafter defined in the claims.
Claims
What is Claimed is:
1. A method of treating a production gas stream from a hydrocarbon well, the production stream of gas having a gas pressure, the method comprising the steps of:injecting the production stream into a first contact separator to separate a first liquid phase from a first vapour phase, the first contact separator being cooled by a first reflux stream;cooling the first vapour phase in a first heat exchanger;injecting the cooled first vapour phase into a second contact separator to separate a second liquid phase from a second vapour phase, wherein the first reflux stream comprises a portion of the second liquid phase;separating the first liquid phase in a first membrane separator into a first NGL product stream and a first lighter hydrocarbon stream;separating a combination of the first lighter hydrocarbon stream and a further portion of the second liquid phase in a second membrane separator into a second NGL product stream and a second lighter hydrocarbon stream;generating a cold expanded stream by expanding a downstream vapour phase, the downstream vapour phase being derived from the second vapour phase; and using the cold expanded stream to cool the first heat exchanger.
2. The method of claim 1 , further comprising the steps of:cooling the second contact separator using a second reflux stream;cooling the second vapour phase in a second heat exchanger, the second heat exchanger being cooled by the cold expanded stream;injecting the cooled second vapour phase into a third contact separator to separate a third liquid phase from a third vapour phase, the second reflux stream comprising a portion of the second liquid phase;separating a combination of the second lighter hydrocarbon stream and a further portion of the third liquid phase in a third membrane separator into a third NGL product stream and a third lighter hydrocarbon stream;3. The method of claim 2, wherein the downstream vapour phase is derived from the third vapour phase.
4. The method of claim 1 , wherein the downstream vapour phase is passed through a downstream contact separator after expansion to obtain the cold expanded stream and a cold liquid stream.
5. The method of claim 4, wherein the cold liquid stream is passed through a downstream membrane separator to obtain a downstream NGL product stream, and downstream lighter hydrocarbon stream that is combined with the cold expanded stream.
6. The method of claim 2, wherein the third vapour phase is cooled in a third heat exchanger prior to being expanded, the third heat exchanger being cooled by the cold expanded stream.
7. The method of claim 2, wherein the third contact separator is cooled using a third reflux stream.
8. The method of claim 2, wherein the cold expanded stream passes through the second heat exchanger prior to passing through the first heat exchanger.
9. The method of claim 1 , further comprising the step of pressurizing the first liquid phase upstream of the first membrane separator.
10. The method of claim 1 , wherein cold temperatures used in the method is derived entirely from the gas pressure of the production gas stream.
11. The method of claim 1 , wherein a pressure within the first contact separator and the second contact separator is substantially the same as the gas pressure of theproduction gas stream.
12. A method of treating a production gas stream from a hydrocarbon well, the production stream of gas having a gas pressure, the method comprising the steps of:separating a hydrocarbon stream in a contact separator to obtain a first liquid phase and a first vapour phase, the contact separator being cooled by a reflux stream obtained from a second contact separator,passing the first liquid phase from the contact separator through a first membrane separator, the first membrane separator separating a first heavier liquid stream from a first lighter liquid stream;cooling the first vapour phase in a heat exchanger to obtain a cooled first vapour phase and separating the cooled first vapour phase in the second contact separator to obtain a second liquid phase and a second vapour phase, wherein at least a portion of the second liquid phase comprises the reflux stream;passing at least a portion of the first lighter liquid stream and / or a portion of the second liquid phase through a second membrane separator to obtain a second heavier liquid stream and a second lighter liquid stream;expanding a vapour phase derived from the second vapour phase to generate a cold hydrocarbon stream that is used to cool the heat exchanger.
13. The method of claim 12, further comprising the step of dewatering the hydrocarbon stream upstream of the contact separator, wherein dewatering the hydrocarbon stream comprises using a dehydrant loop.
14. The method of claim 12, wherein the hydrocarbon stream comprises hydrogen sulphide, and a further heat exchanger and a further contact separator are used to condense and separate the hydrogen sulphide.
15. The method of claim 12, wherein the method further comprises the use of one or more further contact separators in series with, and downstream from, the secondcontact separator, each of the further contact separators receiving a vapour phase from an upstream contact separator and separating a lighter fraction from a heavier fraction, at least a portion of the heavier fraction being recirculated as a reflux stream.
16. The method of claim 12, further comprising the step of pressurizing the first liquid phase upstream of the first membrane separator.
17. A method of treating a production gas stream from a hydrocarbon well, the method comprising the steps of:injecting the production stream into a first contact separator to separate a first liquid phase from a first vapour phase, the first contact separator being cooled by a first reflux stream;cooling the first vapour phase in a first heat exchanger;injecting the cooled first vapour phase into a second contact separator to separate a second liquid phase from a second vapour phase, wherein the first reflux stream comprises a portion of the second liquid phase;separating the first liquid phase in a first membrane separator into a first NGL product stream and a first lighter hydrocarbon stream;separating a combination of the first lighter hydrocarbon stream and a further portion of the second liquid phase in a second membrane separator into a second NGL product stream and a second lighter hydrocarbon stream;generating a cold expanded stream by expanding a downstream vapour phase, the downstream vapour phase being derived from the second vapour phase; and using the cold expanded stream to cool the first heat exchanger.
18. A method of treating a well-produced gas stream from a hydrocarbon well, the method comprising the steps of:obtaining an inlet gas stream having an inlet gas pressure, the inlet gas stream comprising the well-produced gas stream;extracting water from the inlet gas stream to produce a dewatered gas stream;separating the dewatered gas stream in a first contact separator to obtain a first liquid phase and a first vapour phase, the first contact separator being cooled by a first reflux stream;cooling the first vapour phase in a first heat exchanger to produce a cooled first vapour phase;separating the cooled first vapour phase in a second contact separator to obtain a second liquid phase and a second vapour phase, the second contact separator being cooled by a second reflux stream, and at least a portion of the second liquid phase comprising the first reflux stream;cooling the second vapour phase in a second heat exchanger to obtain a cooled second vapour phase;separating the cooled second vapour phase in a third contact separator to obtain a third liquid phase and a third vapour phase, the third contact separator being cooled by a third reflux stream, and at least a portion of the third liquid phase comprising the second reflux stream;cooling the third vapour phase using at least an expander to obtain a cooled third vapour phase;separating the cooled third vapour phase in a fourth contact separator to obtain a fourth liquid phase and a fourth vapour phase;using the fourth vapour phase as a cooling stream to cool the heat exchangers; passing at least a portion of the first liquid phase through a first membrane separator to obtain a first heavier fraction and a first lighter fraction, the first lighter fraction being combined with at least a portion of the second liquid phase;passing at least a portion of the second liquid phase and / or at least a portion of the first lighter fraction through a second membrane separator to obtain a second heavier fraction and a second lighter fraction, the second lighter fraction being combined with at least a portion of the third liquid phase;passing at least a portion of the third liquid phase and / or at least a portion of the second lighter fraction through a third membrane separator to obtain a third heavier fraction and a third lighter fraction, the third lighter fraction being combined with at leasta portion of the fourth liquid phase;passing at least a portion of the fourth liquid phase and / or at least a portion of the third lighter fraction through a fourth membrane separator to obtain a fourth heavier fraction and a fourth lighter fraction, the fourth lighter fraction being combined with the cooled third vapour phase.