High purity CO2 and BTEX recovery

Method and apparatus for producing high purity, food grade CO 2 and recovering valuable BTEX fuel from hydrocarbon mixtures such as from a natural gas well. The method involves dehydrating the hydrocarbon mixture and separating the dehydrated mixture into gas and liquid phases, followed by further separation of the liquid phase to produce the BTEX fuel and condensation and distillation of the vapor phase to produce the high purity CO 2 . The BTEX fuel is recovered at the temperature and pressure that meets specifications for transportation and storage of gasoline, facilitating its sale to market, and the high purity CO 2 is produced is produced as liquid CO 2 for storage and transportation.

DESCRIPTION OF THE PREFERRED EMBODIMENT Both the method and apparatus described herein are optimized for a typical CO 2 process plant that might produce approximately 250 tons of CO 2 per day. Those skilled in the art will recognize, however, that it may be necessary to make certain changes in the preferred embodiments described herein in accordance with the production specifications for a particular CO 2 process plant. Referring to FIG. 1 , there is shown a schematic diagram of a preferred method of purifying CO 2 from a hydrocarbon mixture in accordance with the teachings of the present invention. At the wellhead 10 , the natural gas includes water and a number of other impurities such that the natural gas undergoes inlet separation and filtration to remove entrained solids, followed by stripping. Amine stripping is generally the method of choice such that this process is summarized by the reference to amine treatment at reference numeral 12 in FIG. 1 . The resulting natural gas is sent to market as at reference numeral 14 and the remaining hydrocarbon mixture is the inlet stream for the method of the present invention. In the first step of the method of the present invention, the hydrocarbon mixture resulting from the stripping of natural gas is dehydrated as at step 16 . Dehydration can be accomplished in several ways as known in the art such as by injecting methanol to eliminate hydration formation and freezing of the water to allow separation of water from the hydrocarbon mixture, by ethylene glycol dehydration tower, or by equivalent methods. Methanol injection is preferred for dehydration in the method of the present invention, and the methanol is preferably injected upstream of a heat exchanger (not shown in FIG. 1 ) to give better mixing with the hydrocarbon mixture and subsequent separation of liquid and vapor at approximately 15° F. as at step 20 . Separation step 20 is preferably accomplished at relatively high pressures of about 300-320 psia. Liquid from separator 20 , which includes water, heavier (long chain) hydrocarbons, and heavier (BTEX) hydrocarbons, is heated as at 22 to about 80° F. and, while still at about 290 psia, undergoes a second separation step as at 24 . In the preferred embodiment, this second separation step is accomplished by quiet separation in a three phase, high pressure tank separator, described in more detail below. Vapor from this second separation step 24 is flared as at step 26 or optionally recycled (for instance, to the inlet stream) and clean water is dumped as at 28 . The remaining liquid, comprising mainly heavier chain and aromatic hydrocarbons, is then stabilized at step 30 by heating to a slightly higher temperature (about 90° F.) and storing in a two-phase separation tank at a much lower pressure of approximately 20 psia. The vapors from this stabilization step 30 are once again flared as at 26 or optionally recycled and the resulting stabilized liquid, in the form of valuable BTEX fuel, is marketed as at step 32 . Returning to separator 20 , the vapor is cooled at step 36 from about &plus;15° F. to about −15° F. while pressure is maintained at about 290 psia. The vapor is then distilled at step 38 . Overhead vapors from distillation column 38 are flared at step 26 . The liquid bottoms from distillation column 38 are distilled at step 40 , but in this second distillation step 40 , the liquid bottoms are routed to the high pressure separation tank 24 and it is the vapor that includes the high purity CO 2 . The vapor from second distillation step 40 is then polished by absorption at step 42 through activated carbon and then condensed to give high purity, food grade liquid CO 2 to market 44 . Referring now to FIG. 2 , there is shown a schematic diagram of a preferred embodiment of an apparatus for. recovering high purity CO 2 and the valuable BTEX fuel from a hydrocarbon mixture such as from a natural gas well that is constructed in accordance with the present invention. Those skilled in the art will recognize that, although reference is made herein to recovering CO 2 and BTEX fuel from a natural gas well, the method and apparatus of the present invention are also adaptable for recovering one or the other, or both, of these valuable products from almost any hydrocarbon source with modification of specific operating parameters in a manner that will be known to those skilled in the art who have the benefit of this disclosure as may be needed depending upon the content and components of the inlet gas. For this reason, the inlet gas to the method and apparatus of the present invention is referred to herein as a “hydrocarbon mixture.” In the preferred embodiment shown in FIG. 2, a hydrocarbon mixture such as results from amine stripping of natural gas is routed first through a free water, knock-out, two-stage carbon steel separator D 1 and then to a rotary screw, oil flooded compressor C 1 . Those skilled in the art will recognize that compressor C 1 could also be a reciprocating compressor. The output stream from compressor C 1 is cooled in an ammonia, water, or air cooled carbon steel tube heat exchanger. HE 1 and then compressed in a second rotary screw compressor C 2 to approximately 300 psig and further cooled in a second heat exchanger HE 2 . Compressor C 2 can also be a reciprocating compressor, but may handle more vapor than compressor C 1 due to recycling. Heat exchanger HE 2 is also an ammonia, water, or air-cooled carbon steel tube heat exchanger. For dehydration, methanol is injected into the output stream of heat exchanger HE 2 upstream of a third heat exchanger HE 3 (to give better mixing) that prevents hydrate formation and freezing of the water vapor for subsequent separation of the water vapor in three phase separator D 5 at about &plus;15° F. Heat exchanger HE 3 is also a carbon steel tube beat exchanger, but because of the temperature, must be cooled with ammonia or chilled glycol. Separator D 5 is of a type known in the art with internal baffles and coalescing mesh pad for removing liquids from a vapor stream. The cold liquid from separator D 5 includes heavier hydrocarbons, water, and the heavier, aromatic BTEX hydrocarbons and the cold vapor output from separator D 5 includes light hydrocarbons and CO 2 . The cold liquid output from separator D 5 is heated in heat exchanger HE 4 with either hot CO 2 vapor or hot ammonia to about &plus;80° F. and, still at about 250 psia, is routed to a large tank for high pressure, “quiet” separation in high pressure tank HPT 3 , shown in FIG. 3 . High pressure tank HPT 3 is a large, horizontal propane, or so-called “bullet-type” tank with a three stage “tail end” outlet and a design working pressure of about 250 psig, operating at about 220-230 psig and an 80-90° F. stabilization temperature. Referring to FIG. 3 , it can be seen that tank HPT 3 includes liquid floats 50 , 52 and valves 54 , 56 for two layers of liquid. High pressure tank HPT 3 is preferably at least a 30,000 gallon tank so that the liquid that accumulates therein resides in the tank long enough for the liquid to de-gas and to separate into hydrocarbon/BTEX and water layers 58 , 60 . The float 50 rides on the hydrocarbon/BTEX layer 58 and that layer 58 is drawn off through valve 54 when that layer 58 accumulates to a specified level. Similarly, the float 52 rides at the interface between the hydrocarbon/BTEX layer 58 and the water layer 60 and water is dumped through valve 56 . Vapors in the ullage 62 of high pressure tank HPT 3 are periodically drawn off and routed to a waste flare or optionally recycled to separator D 1 . The hydrocarbon/BTEX liquid drawn from high pressure tank HPT 3 is heated in heat exchanger HE 5 to about 85-90° F. and pressure is dropped to about 20 psia to match gasoline storage and transportation specifications for highway hauling of the BTEX fuel. However, before the BTEX fuel is ready to market, it is preferably separated in a two-phase (liquid and vapor) separator tank T 2 . Tank T 2 is also preferably a bullet-type horizontal tank that is provided with a liquid level indicator of the type described above. Vapors from the ullage of tank T 2 are periodically drawn off and routed to a waste flare or optionally recycled to separator D 1 and, when the liquid level indicator reaches a high enough level, the valuable BTEX fuel is drained from the tank for transport to market. Returning now to separator D 5 on FIG. 2 , the vapors are routed to another heat exchanger HE 6 to further decrease to the condensation temperature of about −15° F. Again because of the temperatures, heat exchanger HE 6 is ammonia or glycol chilled. The cold liquids are then introduced into approximately the middle of distillation column COL 1 for rejection of hydrocarbon ethanes (and lighter). As shown in FIG. 4 , the light end vapors are stripped off with an overhead condenser OC 1 that may be internal or external to column COL 1 (reflux rate of about 1.5 to 4.0 cycles depending on refrigeration economics), and are routed to a waste flare or optionally recycled to separator D 1 . The heavy ends are concentrated as liquid with a reboiler RB 1 and, as can be seen by reference to FIG. 4 , introduced into the midpoint of a second distillation column COL 2 . Second column COL 2 rejects the liquids and the vapors are refluxed several times (reflux rates of about 1 to 3 cycles), condensing each time at overhead condenser OC 2 and removing about 6 million BTU/hour each time (depending again upon economics), to stabilize the effluent. Heavy ends are concentrated by reboiler RB 2 and recycled back to high pressure separation tank HPT 3 . As can be seen by reference to the operating parameters of distillation columns COL 1 and COL 2 in FIG. 4 , the reboilers RB 1 and RB 2 add a relatively large amount of heat relative to the cold temperatures in the columns COL 1 and COL 2 to provide good flow in both directions. The reboiler RB 2 for column COL 2 needs even more energy to operate than RB 1 , so heat is about 4-8 million BTU/hour. The cold (approximately −4° F.) vapor stream from the product distillation column COL 2 is routed to an absorption bed of activated carbon for final polishing. In the preferred embodiment shown in FIG. 4 , two absorption beds A 1 and A 2 are provided and, because of the relatively high ethane and propane levels compared to food grade in the input vapor, the input stream is switched from bed A 1 to bed A 2 approximately every four hours (or such other interval as required by the hydrocarbon content of the particular vapor) with purging of the other bed with high purity CO 2 . Of course bed diameter and height is optimized in the manner known in the art for a particular flow rate through the bed. The vapor output from absorption beds A 1 and A 2 (at about 0 to −1° F.) is routed through another heat exchanger HE 7 to liquefy the high purity CO 2 at about −12° F. and the high purity CO 2 is then stored in a conventional horizontal bullet-type storage tank T 3 that may be high pressure with an internal liquid level indicator. Boil-off from tank T 3 that is not used for purging is recycled to the input stream to compressor C 2 (see FIG. 2 ) at about 70-80 psia and, as needed, to purge and cool the absorption beds A 1 and A 2 during regeneration. The foregoing description of the preferred embodiments of the invention has been presented for purposes of illustration and description. It is not intended to be exhaustive or to limit the invention to the precise form disclosed, and many modifications and variations are possible in light of the above teaching without deviating from the spirit and the scope of the invention. The embodiments described are selected to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilize the invention in various embodiments and with various modifications as suited to the particular purpose contemplated. It is intended that the scope of the invention be defined by the claims appended hereto.