Natural Gas Liquids Recovery Plant

A compact transportable apparatus for flexibly recovering natural gas liquids from a natural gas stream feedstock includes a replaceable segment on one or more natural gas liquids transfer lines that is removable in the field without cutting the line for replacement with different replaceable part, for example, a J-T valve replacing a length of pipe, for flexibility in adjusting performance of the apparatus to match on site or changing conditions of the natural gas stream feedstock. Insulation surrounding the replaceable segment is discontinuous with insulation surrounding the remainder of the natural gas liquids transfer line in which the segment is interposed. This allows separation of the segment from such transfer line without disturbing the insulation of the remainder of that natural gas liquids transfer line if the replaceable segment is removed and replaced with a different replaceable segment.

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Description
CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. provisional applications 61/796,047 and 61/796,057, both filed Nov. 1, 2012, the entirety of the contents of which are incorporated herein by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH AND DEVELOPMENT

Not Applicable

BACKGROUND OF THE DISCLOSURE

1. Field of Disclosure

This invention relates to extraction of liquefiable hydrocarbons from natural gas.

2. Background

Natural gas produced at the wellhead in most cases contains contaminants and natural gas liquids, and must be processed into pipeline-quality dry natural gas, usually by removing oil; water; elements such as sulfur, helium, and carbon dioxide; and natural gas liquids. Dry natural gas is methane, which has one carbon atom. Natural gas liquids (“NGLs”) are hydrocarbon molecules having two or more, up to about eight, carbon atoms, specifically ethane (C2), propane (C3), butanes (n-C4, i-C4), pentanes (n-C5 and i-C5) and “heaviers” (C5+). Pipelines specify quality standards for acceptance of gas into their transmission systems. Included in these standards are generally a requirement that natural gas be delivered at a specified hydrocarbon dew point (“HDP”). The HDP is a temperature below which any vaporized natural gas liquids in the mix will tend to condense at pipeline pressure.

Gas plants designed to recover NGLs from produced natural gas have used a number of processes, originally refrigeration, then in the 1960's lean oil absorption, and in the 1970's cryogenic plants. Refrigeration plants chill natural gas to about −30° F. with an external propane refrigeration system. Depending upon the gas composition and pressure, propane recoveries range from about 30% to 50%. Lean oil absorption is a process in which the NGLs are removed by contacting the natural gas with a liquid hydrocarbon solvent (oil). Lean oil absorption plants can extract about 90%+ of the C3+ in the gas stream and about 30% of the ethane. Cryogenic plants with modifications made in the 1990's allowed propane recoveries to reach close to a 99% extraction level while recovering about 70% of the contained ethane. Essentially, cryogenic processing consists of lowering the temperature of the gas stream to around −120° F. While there are several ways to perform this function, a turbo expander process is most effective, using external refrigerants to chill the gas stream.

All these processes are performed in permanently installed large plants built to process at least 100 million standard cubic feet per day (MMscfd) of natural gas, often 250 MMscfd and larger.

At the other end of the size and capacity spectrum are small skid mounted transportable plants built to be movable for use in short term operating environments as opposed to permanent installations. These plants process as little as about 2 MMscfd, with mid ranges of about 5 to 15 MMscfd. Some extend up 30, 60 or 90 MMscfd. There are two basic types of these skid mounted transportable NGL recovery plants: those that chill the natural gas using a Joule-Thomson process and those that use a vapor compression cycle process employing a circulating refrigerant.

The Joule-Thomson process involves cooling a gas stream by reducing its pressure (adiabatic expansion) through a control valve (a “J-T” valve). Produced liquids are recovered in a cold separator and the gas stream off the top of the separator is used to cool the inlet stream to the J-T valve. The NGL from the cold separator is routed off skid to a pressurized NGL processing tank, but first may be routed through an inlet NGL/gas exchanger. The J-T process may require considerable compression of the feedstock to the plant to achieve the desired pressure drop across the J-T valve.

Transportable skid mounted refrigeration plants generally make use of the well know vapor compression cycle in which a circulating refrigerant such as Freon enters a compressor as a low pressure, low temperature vapor. The refrigerant is compressed by the compressor to a high pressure and temperature gaseous state. The high pressure and temperature gas then enters a condenser. The condenser cools the vapor until it starts condensing the high pressure and temperature gas to a high temperature liquid by transferring heat to a lower temperature medium, usually ambient air. The high temperature liquid then enters an expansion valve located at the entry into a pressure vessel, where pressure of the high temperature liquid abruptly decreases, causing flash evaporation within the vessel (which for this reason is often referred to as a flash drum). Both the vapor and the residual liquid are cooled to the saturation temperature of the liquid at the reduced pressure. The refrigerant then begins the vapor compression cycle again, passing from the flash drum to the compressor as a low pressure, low temperature vapor.

Both a transportable J-T plant and a refrigeration plant are used mainly to reduce HDP to pipeline specifications. A J-T plant has the least capital cost but also recovers the least amount of NGLs. This simple process primarily recovers the C5+ components. Pentane boils at 96.98° F. at atmospheric pressure. In order to meet HDP pipeline specifications, industry standard has been to insulate J-T units to maintain a 30° F. temperature. For 3 or 4 inch diameter piping or larger, this has resulted in use of 1.5-2 inches of insulation. Two inches of insulation holds the J-T cooling effect down to about 20° F.

A problem with J-T plants and transportable skid mounted refrigeration plants is that after the plant is built, changes may need to be made in the plant in order to use it at another short term operating site, for example, the NGL recovery efficiencies for the new site may need to be improved or lessened, according to the composition of the well stream gas produced at that site or due to the ambient conditions at the site, which may range from subfreezing to very hot ambient temperatures according to the season, especially at more northern latitudes, such as in North Dakota. Sometimes a J-T plant or a transportable skid mounted refrigeration plant constructed to a worse case scenario for the composition of well stream gas at a site, on being put into operation at the site, will be found to need efficiencies reduced for the composition of the well stream gas, for example, more NGLs may need to retained in the processed gas in order to meet pipeline BTU minimums while still meeting HDP specifications. Sometimes the composition of the gas or other conditions, including market conditions, will require NGL recovery efficiencies be improved. In order to make these changes, the J-T plant or transportable skid mounted refrigeration plant either has had to be returned to the manufacturing facility to alter the design or components of the plant, typically involving breaking through insulation, cutting out old parts and welding in other components and reforming the insulation, or attempts to make changes involving these tasks have had to be performed at the natural gas production site.

In recent years a revolutionary method of extracting oil and gas from shale deposits by horizontal drilling and hydraulic fracturing has produced vast new reserves of natural gas, and gas supplies have flooded the market. In consequence, natural gas prices have eroded and NGLs have become a more valuable component of natural gas produced from wells. Accordingly, while it is still necessary to meet gas quality specifications for pipelines, it is now desirable to achieve higher J-T plant and transportable refrigeration plant efficiencies than before in recovering valuable NGLs in the well stream. It is further also desirable for J-T plants and transportable refrigeration plants to have more built-in flexibility in order to make changes in the field to meet changed ambient conditions and changed compositions in the well stream gas.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective view of an exemplary embodiment of a natural gas liquids recovery J-T plant in accordance with this invention viewed from one side of the plant. Arbitrarily, for purposes of description, this side is termed the south side. Thus the right end is called the east side, the left end is called the west side, and the opposite side is called the north side.

FIG. 2 is a perspective view of the exemplary embodiment of the natural gas liquids recovery plant of FIG. 1 viewed from the north side.

FIG. 3 is an elevation of the exemplary embodiment of the natural gas liquids recovery plant of FIG. 1 viewed from the south side (a south elevational view).

FIG. 4 is a west elevational view of the natural gas liquids recovery plant of FIG. 1.

FIG. 5 is a north elevational view of the natural gas liquids recovery plant of FIG. 1.

FIG. 6 is an east elevational view of the natural gas liquids recovery plant of FIG. 1.

FIG. 7 is a longitudinal sectional view of an exemplary embodiment of a shell vessel used in a tube-in-shell heat exchanger of an exemplary embodiment of a natural gas liquids recovery plant in accordance with this invention, showing dispositions of baffles along the length of the vessel.

FIG. 8 is a view of a baffle for deployment in the shell of FIG. 7.

FIG. 9 is a view of another baffle for deployment in the shell of FIG. 7.

FIG. 10 is a piping diagram of an exemplary embodiment of a natural gas liquids transfer line of a natural gas liquids recovery plant in accordance with this invention.

FIG. 11 is schematic diagram of an exemplary embodiment of a natural gas liquids recovery plant in accordance with this invention.

FIG. 12 is a schematic diagram of another exemplary embodiment of a natural gas liquids recovery plant in accordance with this invention.

FIG. 13 is a perspective view of an exemplary embodiment of a natural gas liquids recovery plant in accordance with this invention viewed from one side of the plant. Arbitrarily, for purposes of description, this side is termed the south side. Thus the right end is called the east side, the left end is called the west side, and the opposite side is called the north side.

FIG. 14 is a perspective view of the exemplary embodiment of the natural gas liquids recovery plant of FIG. 13 viewed from the north side.

FIG. 15 is an elevation of the exemplary embodiment of the natural gas liquids recovery plant of FIG. 13 viewed from the south side (a south elevational view).

FIG. 16 is a west elevational view of the natural gas liquids recovery plant of FIG. 13.

FIG. 17 is a north elevational view of the natural gas liquids recovery plant of FIG. 13.

FIG. 18 is an east elevational view of the natural gas liquids recovery plant of FIG. 13.

FIG. 19 is a piping diagram of an exemplary embodiment of a natural gas liquids transfer line of a natural gas liquids recovery plant in accordance with this invention.

FIG. 20 is a piping diagram schematic diagram of an exemplary embodiment of another natural gas liquids transfer line of a natural gas liquids recovery plant in accordance with this invention.

FIG. 21 is schematic diagram of an exemplary embodiment of a natural gas liquids recovery plant in accordance with this invention.

FIG. 22 is a portion of the schematic diagram of FIG. 21 to the left of a dividing line demarcated in FIG. 21.

FIG. 23 is a portion of the schematic diagram of FIG. 21 to the right of the dividing line demarcated in FIG. 21.

 DETAILED DESCRIPTION OF EMBODIMENTS

In the following detailed description of exemplary embodiments, reference is made to the accompanying drawings, which form a part hereof and in which are shown by way of illustration examples of exemplary embodiments with which the invention may be practiced. In the drawings and descriptions, like or corresponding parts are marked throughout the specification and drawings with the same reference numerals. The drawings are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness.

Specific details described herein, including what is stated in the Abstract, are in every case a non-limiting description and exemplification of embodiments representing concrete ways in which the concepts of the invention may be practiced. This serves to teach one skilled in the art to employ the present invention in virtually any appropriately detailed system, structure or manner consistent with those concepts. Reference throughout this specification to “an exemplary embodiment” means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one exemplary embodiment of the present invention. Thus, the appearances of the phrase “in an exemplary embodiment” in various places throughout this specification are not necessarily all referring to the same embodiment. Furthermore, the particular features, structures, or characteristics may be combined in any suitable manner in one or more embodiments. It will be seen that various changes and alternatives to the specific described embodiments and the details of those embodiments may be made within the scope of the invention. It will be appreciated that one or more of the elements depicted in the drawings can also be implemented in a more separated or integrated manner, or even removed or rendered as inoperable in certain cases, as is useful in accordance with a particular application. Because many varying and different embodiments may be made within the scope of the inventive concepts herein described and in the exemplary embodiments herein detailed, it is to be understood that the details herein are to be interpreted as illustrative and not as limiting the invention to that which is illustrated and described herein.

Various directions such as “north,” “south”, “east,” “west,” “upper,” “top”, “lower,” “bottom”, “back,” “front,” “transverse,” “perpendicular”, “vertical”, “normal,” “horizontal,” “length,” “width,” “laterally” and so forth used in the detailed description of exemplary embodiments are made only for easier explanation in conjunction with the drawings. The components may be oriented differently while performing the same function and accomplishing the same result as the exemplary embodiments herein detailed embody the concepts of the invention, and such terminologies are not to be understood as limiting the concepts which the embodiments exemplify.

As used herein, the use of the word “a” or “an” when used in conjunction with the term “comprising” (or the synonymous open ended “having” or “including”) in the claims and/or the specification may mean “one,” but it is also consistent with the meaning of “at least one” and “one or more than one.” In addition, as used herein, the phrase “connected” means joined to or placed into communication with, either directly or through intermediate components.

In accordance with this invention, there are disclosed exemplary embodiments for flexibly recovering natural gas liquids from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig. The embodiments comprise a skid; an inlet line for receiving the inlet natural gas stream; first and second one pass tube-in-shell heat exchangers supported on the skid, the second heat exchanger being connected in series with the first heat exchanger by a first transfer line, the first heat exchanger receiving the inlet natural gas stream from the inlet line; a second transfer line for receiving the inlet natural gas stream exiting the second heat exchanger; an NGLs condenser connected to the second transfer line for receiving inlet natural gas stream from the second heat exchanger and operatively sufficient to condense natural gas liquids in the inlet natural gas to two-phase gas-liquid NGLs; a third transfer line for receiving the two-phase gas-liquid NGLs from the NGLs condenser; a gas-liquid separator supported on the skid and connected to the third transfer line, the separator having lower and upper portions for separating two-phase gas-liquid NGLs from natural gas remaining in a single-phase gaseous state as a lean natural gas; a fourth transfer line connected to the separator at the lower portion, for receiving and transporting two-phase gas-liquid NGLs from the separator, the fourth transfer line connecting to the shell of the first heat exchanger proximal a rear end of the shell for shell side flow of NGLs from the rear end toward a front end of the first heat exchanger counter-currently to tube side flow of the inlet natural gas stream entering the first heat exchanger from the inlet line; at least one of the third and fourth transfer lines or both, including a replaceable segment that is removable without cutting the third or fourth transfer line or both, as applicable, for optional replacement of the replaceable segment by a different replaceable segment; a fifth transfer line connected to the shell of the first heat exchanger proximal the front end of the first heat exchanger for receiving a shell side flow stream of NGLs from the front end of the first heat exchanger as product; a sixth transfer line connected to the separator at the upper portion for receiving and transporting a lean natural gas stream from the separator, the sixth transfer line connecting to the shell of the second heat exchanger proximal a rear end of the shell for shell side flow of the lean natural gas stream from the rear end toward a front end of the second heat exchanger counter-currently to tube side flow of inlet natural gas entering the second heat exchanger from the second transfer line; and a seventh transfer line connected to the second heat exchanger proximal the front end of the shell thereof for receiving a shell side flow stream of lean natural gas as a lean gas product.

In exemplary embodiments, valving in at least one of the third or fourth transfer lines or both, upstream of a replaceable segment in the third or fourth transfer lines or both, blocks flow to a replaceable segment in the third or fourth transfer lines or both when the valving is closed. In exemplary embodiments, the replaceable segment either comprises (a) a length of pipe with connectors connecting the pipe with upstream and downstream potions of the third or fourth transfer lines or both that includes or include the replaceable segment, the pipe being downstream of the valving for blocking flow, or (b) a J-T pressure reduction valve with connectors connecting the J-T valve with upstream and downstream potions of the third or fourth transfer line or both that includes or include the replaceable segment, the J-T valve being downstream of the valving for blocking flow. If the replaceable segment comprises the length of pipe, the different replaceable segment comprises a J-T pressure reduction valve with connectors for connecting the J-T valve with upstream and downstream potions of the third or fourth transfer line, or both, that includes the replaceable segment. If the J-T valve comprises the replaceable segment, the different replaceable segment comprises a the length of pipe with connectors for connecting the length of pipe with upstream and downstream potions of the third or fourth transfer line, or both, that includes the replaceable segment.

In exemplary embodiments, the connectors of the length of pipe comprise first and second flanges. The first flange is connected to the pipe for bolting to a flange connected to an upstream portion of the third or fourth transfer lines or both that includes or include the length of pipe. The second flange is connected to the pipe for bolting to a flange connected to a downstream portion of the third or fourth transfer lines or both that includes or include the length of pipe. The connectors of the J-T pressure reduction valve comprise first and second flanges. The first flange is connected to the J-T valve for bolting to a flange connected to the upstream portion of the third or fourth transfer lines or both that includes or include the J-T valve, and the second flange is connected to the J-T valve for bolting to a flange connected to the downstream portion of the third or fourth transfer line or both that includes or include the J-T valve.

In exemplary embodiments, the shells of the first and second heat exchangers, the NGLs condenser, the separator and the first, second, third and fourth transfer lines, including the replaceable segment of the third or fourth transfer line or both the third or fourth transfer lines, as applicable, and the sixth transfer line, are encased in a protectively covered insulation of a kind and thickness sufficient to prevent condensation on the outer surfaces of the shells, the NGLs condenser, the separator, and the first, second, third and fourth transfer lines, including the included replaceable segment or segments, and the sixth transfer line, at a temperature contained within them not below the minimum temperature for which metallurgy of the gas-liquid separator is rated. In exemplary embodiments, the insulation surrounding the replaceable segment or segments is discontinuous with the insulation surrounding the remainder of the third or fourth transfer lines or both, as applicable, for separation from the third or fourth transfer lines without disturbing the remainder of such line or lines if the replaceable segment is removed and replaced with a different replaceable segment.

In an exemplary use, there is provided a process for flexibly recovering NGLs from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig. The exemplary process comprises (a) passing the inlet natural gas stream as a tube side flow though a one-pass shell-and-tube first heat exchanger; (b) passing inlet natural gas effluent from the tube side of the first heat exchanger as a tube side flow stream though a shell-and-tube second heat exchanger having a plurality of one-pass tubes; (c) passing the inlet natural gas effluent from the tube side of the second heat exchanger through a NGLs condenser to reduce the temperature and pressure of the inlet natural gas at least sufficiently to condense NGLs in the inlet natural gas to two-phase gas-liquid NGLs; (d) separating the two-phase gas-liquid NGLs in a gas-liquids separator from remaining single phase natural gas as a lean natural gas; (e) passing the separated two-phase gas-liquid NGLs through a replaceable segment of a transfer line to the shell side of the first heat exchanger, the replaceable segment comprising either a length of pipe if no additional cooling of the two-phase gas-liquid NGLs is desired, or a J-T valve if additional cooling of the two-phase gas-liquid NGLs is desired; (f) passing the two-phase gas-liquid NGLs from step (e) for counter-current flow to inlet natural gas in the tube side of the first heat exchanger at a shell side flow rate effective to increase the temperature of the shell side NGLs exiting the first heat exchanger to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger; (g) regulating removal of NGLs from the shell side of the first heat exchanger to maintain a flow of NGLs passing to the shell side of the first heat exchanger; (h) passing the separated lean natural gas to the shell side of the second heat exchanger; (i) passing the separated lean natural gas from step (h) for counter-current flow to inlet natural gas in the tube side of the second heat exchanger at a shell side flow rate effective to increase the temperature of the shell side lean natural gas exiting the second heat exchanger to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the second heat exchanger, and (j) receiving separately NGLs removed from the shell side of the first heat exchanger and lean natural gas removed from the shell side of the second heat exchanger; (k) while insulating the exterior of the shells of the first and second heat exchangers, the exterior of the separator, and passages within which the steps (c), (e), (f), and (h) are performed, to an extent sufficient to prevent condensation on the outer surfaces of the heat exchangers, the separator, and the passages at a temperature, in steps (a) and (b) in a range between the temperature of the fluid entering the shell side of the heat exchangers and the minimum temperature for which metallurgy of the separator is rated, in step (d), in a range between the temperature of the fluids entering the separator and the minimum temperature for which metallurgy of the separator is rated, and in steps (c), (e), (f), and (h), in a range between the temperature of the fluids in the passages and the minimum temperature for which metallurgy of the separator is rated.

As used for exemplary embodiments herein, the term “NGLs condenser” means either a J-T plant or a refrigeration plant for condensing natural gas liquids in an inlet natural gas to two-phase gas-liquid NGLs.

J-T Plant Exemplary Embodiment

Referring to the drawings, FIGS. 1 and 2 are respectively south and north perspective views and FIGS. 3-6 are respectively south, west, north and east elevational views of an exemplary embodiment of a transportable apparatus, indicated by reference numeral 10, comprising a natural gas liquids J-T plant embodiment in accordance with this invention.

Referring to FIGS. 1-6, the J-T plant comprises a skid 12 and an inlet line 14 for receiving an inlet natural gas stream that has a temperature at atmospheric ambient or higher and a pressure of at least about 400 psig. A one pass shell-and-tube first heat exchanger 16 is supported on skid 12. Referring to FIG. 7 also, first heat exchanger 16 comprises a cylindrical shell pressure vessel 18 having front end 20 and rear end 22. A pass-through tube 24 connected to inlet line 14 at front end 20 of shell 18 receives the inlet natural gas stream for tube side flow inside shell 18. The pass through tube is supported by baffles affixed to interior of shell 18 as described further below. The baffles are not depicted in FIG. 1 in the broken away portion of shell 18 to avoid obscuring tube 24. Pass-through tube 24 has an inner diameter effective at the density and dynamic viscosity of the inlet natural gas stream to produce a tube side flow velocity in a turbulent flow regime, and has an outer diameter relative to the inner diameter of the shell providing an annulus effective to allow a shell side fluid flow rate sufficient, at a thermal conductivity of the pass-through tube, to increase the temperature of the shell side fluid exiting heat exchanger 16 to within a predetermined temperature range less than the temperature of the inlet natural gas entering the pass-through tube 24. In an exemplary embodiment, the predetermined temperature range is within 10 to 100° F. less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger. In an exemplary embodiment, pass-through tube 24 has an exterior diameter that may be from two-thirds to three-fourths the inner diameter of shell vessel 18.

A first transfer line 26 connects to pass-through tube 24 at rear end 22 of first heat exchanger 16 for receiving the inlet natural gas stream exiting first heat exchanger 16.

J-T plant 10 further comprises a one pass shell-and-tube second heat exchanger 28 supported on skid 12. Second heat exchanger 28 includes a hair pin cylindrical shell pressure vessel 30 having a front end 32 and a rear end 34, and is connected on front end 32 to first transfer line 26. A pair of tube sheets (not seen) is transversely affixed to shell 30 inside the front and rear ends 32, 34 of shell 30. A plurality of tubes 33, which in an exemplary embodiment as depicted may be low fin tubes, are longitudinally arranged within shell 30 transversely affixed to and at least partially supported by the said tube sheets, for conducting the inlet natural gas stream introduced into the front end 32 of shell 30 to the rear end 34 of shell 30. In an exemplary embodiment, low fin tubes 33 are arranged to form a tube bundle. The tube bundle is supported by baffles affixed to interior of shell 30 as described further below. The baffles are not depicted FIG. 1 in the view of a broken away portion of shell 30 to avoid obscuring the tube bundle. The low fin tubes 33 have an inner diameter effective at the density and dynamic viscosity of the inlet natural gas stream to produce a tube side flow velocity in a turbulent flow regime, and have an outer diameter effective for the tubes collectively, relative to the inner diameter of shell vessel 30, to provide a flow space around the low fin tubes allowing a shell side fluid flow rate sufficient, for thermal conductivity of the tubes, to increase the temperature of the shell side fluid exiting second heat exchanger 30 to within a predetermined temperature range less than the temperature of the inlet natural gas entering the low fin tubes of second heat exchanger 30. In an exemplary embodiment, the predetermined temperature range is from 1 to 20° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger. In an exemplary embodiment in which the low fin tubes of second heat exchanger 28 are arranged to form a tube bundle, the cross sectional dimension of the tube bundle may be from two-thirds to three-fourths the inner diameter of the shell vessel 30.

In an exemplary embodiment, referring to FIGS. 7-9, the first and second heat exchangers 16, 28 include a plurality of circular plate baffles 19, 21, representatively, affixed within shells 18, 30 transverse to the length of the shell 18 or 30. The baffles divide the interior of the shells into a plurality of chambers “A”, “B”, “C”, “D” etc. Each baffle 19 or 21 has an aperture 23 of diameter sized to transversely receive, for shell 18, pass-though tube 24 with clearance sufficient to support tube 24 and minimize shell side flow between tube 24 and the baffle aperture 23, and for shell 30, low fin tubes 33 with clearance sufficient to support tubes 33 and minimize shell side flow between tubes 33 and the baffle aperture 23. The baffles 19, 21 extend edge to edge within the shell 16 or 30 except at a peripheral cut portion of the baffle 19 or 21, e.g. at 25 for baffle 19, and at 27 for baffle 21, that allows shell side fluid flow from one baffled chamber to the next, e.g., “A” to “B”, ““B” to “C”, “C” to “D” etc., the baffles 19, 21 being affixed in the shell with the cut portion of a baffle, e.g. at 25 for baffle 19, opposite an uncut portion of an adjacent baffle, e.g. at 29 of baffle 21, thereby to reverse shell side flow on opposite sides of a baffle and direct shell side flow across the pass-through tube in shell 18 and across low fin tubes 33 in shell 30 back and forth in adjacent baffled chambers.

A second transfer line 36 receives the inlet natural gas stream exiting second heat exchanger 28. A J-T adiabatic expansion pressure reduction valve 38 interconnects second transfer line 36 and a third transfer line 40. Pressure reduction valve 38 regulates the upstream pressure of the inlet natural gas stream received from second transfer line 36 to a predetermined set point and adiabatically expands the inlet natural gas to reduce the temperature and pressure of that gas. A third transfer line 40 receives the inlet natural gas stream at the reduced pressure and temperature. Pressure drop across valve 38 is sufficient to reduce the temperature of the inlet natural gas at least enough to condense natural gas liquids in the inlet natural gas and produce two-phase gas-liquid NGLs and a single-phase gas. In an exemplary embodiment, J-T valve 38 is a “fail open” valve and has an associated pressure controller 88 that supplies gas pressure to close the valve to a desired set point regulating the upstream pressure. By “fail open” is meant that if no gas pressure is supplied by pressure controller 88, valve 38 remains completely open. Pressure controller 88 has a sensing line input for sensing upstream pressure, for example, from pressure supply line 89 connected to first transfer line 26 (see FIGS. 11 and 12.) Pressure controller 88 receives supply gas from supply gas source branch line 95 (described below) that pressure controller 88 uses to control J-T valve 38.

A horizontal gas-liquid separator 42 is supported on skid 12 and is connected to third transfer line 40 that carries the two-phase gas-liquid NGLs and a single-phase gas resulting from the pressure drop across J-T valve 38. Separator 42 has lower and upper portions 43, 45, respectively. Heavier two-phase gas-liquid NGLs gravitationally collect in the lower portion separate from lighter single-phase gas rising as a lean natural gas in the upper portion.

Referring to FIG. 10, in an exemplary embodiment, a pair of riser lines, 44a and 44b are connected to separator 42 at lower portion 43. Riser lines 44a, 44b receive the two-phase gas-liquid NGLs from separator 42. In particular, for riser line 44a, a vertical pipe 46a rising into lower portion 43 of separator 42 is connected by union 47a to swage 48a, and riser line 44a tees to horizontal, is valved for blockage at ball valve 49a, and runs to common natural gas liquids transfer line 44. Riser line 44b is similarly piped, with like reference numerals suffixed instead by “b.” Lines 44a and 44b unite in a common fourth transfer line 44 and transport the received natural gas liquids to shell 18 of first heat exchanger 16 proximal rear end 22 of shell 18 for shell side flow of natural gas liquids from rear end 22 toward front end 20 of first heat exchanger 16 counter-currently to tube side flow of the inlet natural gas stream entering first heat exchanger 16 from inlet line 14.

In an exemplary embodiment, fourth transfer line 44 for transfer of NGLs includes a replaceable segment 50 between separator 42 and first heat exchanger shell 18. Replaceable segment 50 separates fourth transfer line 44 into an upstream portion 51 proximal to separator 42 and a downstream portion 53 distal from separator 42. Ball valves 49a and 49b and ball valve 52 in fourth transfer line 44 between separator 42 and replaceable segment 50 provide means for blocking NGL flow from separator 42 to replaceable segment 50. In an exemplary embodiment, schematically illustrated in FIG. 10, replaceable segment 50 comprises a length of pipe 54, a first flange 56 connected on pipe 54 and bolting to a flange 57 connected to the upstream portion 51 of fourth transfer line 44, and a second flange 58 connected on pipe 54 and bolting to a flange 59 connected to downstream portion 53 of fourth transfer line 44. Replaceable segment 50 comprising pipe 54 and flanges 56 and 58 is removable by unbolting the flange 56 from flange 57 and unbolting flange 58 from flange 59. Such removal of replaceable segment 50 comprising pipe 54 and flanges 56 and 58 from transfer line 44 permits convenient field replacement of such segment 50 with a bolt up different replaceable segment, in a preferred exemplary embodiment, a second J-T pressure reduction valve, without having to cut out a length of line 44, weld in a second J-T pressure reduction valve, and reinstall insulation (about which see more below). This provides a degree of flexibility for increasing NGL recovery efficiency in the field if on-site conditions call for increased efficiency

Alternatively, replaceable segment 50 may be a second J-T pressure reduction valve with its flanges 56 and 58 bolted up at flanges 57 and 59, and if a lesser efficiency is called for by conditions at the gas conditioning site, second J-T pressure reduction valve may be removed and replaced in the field by unbolting it and bolting in instead segment 50 comprising pipe 54 and flanges flange 56 and 58. A second J-T pressure reduction valve is represented in FIG. 12 at reference numeral 60. The efficiency benefits of a second J-T pressure reduction valve are described below in connection with the description of process with reference to FIGS. 11 and 12. Fourth transfer line 44 ells and tees at 61, 63 respectively and is valved past tee 63 by ball valve 62 before rising to connect into shell 18.

In an exemplary embodiment, although replaceable segment 50 is shown in FIG. 10 placed after junction of the two riser lines 44a and 44b, separator 42 may be drained of NGLs by one line, and replaceable segment 50 placed in that one line, or separator 42 may be drained of NGLs by two riser lines and replaceable segment 50 placed in only one of the lines before junction of the two lines, all as means of flexibly increasing or lessening NGL recovery efficiency of the J-T plant.

A fifth transfer line 64 connects to shell 18 of first heat exchanger 16 proximal the front end 20 of heat exchanger 16 for receiving a shell side flow stream of NGLs from heat exchanger front end 20 and transferring the NGLs off skid as product for use or sale.

In FIGS. 11 and 12, stacked circles off a line or vessel indicated a thermowell (bottom circle) and a temperature indicator (top circle). A single circle indicates a pressure indicator. A circle slanted off a valve is a valve controller.

Referring to FIG. 11, a level controller 66 in fluid communication with the lower portion 43 of gas-liquid separator 42 controls the liquid volume in separator 42. In an exemplary embodiment, level controller 66 comprises a displacer arm with a float providing a sensory mechanism based on the height of liquid in the separator. A pilot associated with the controller 66 operates either a valve 68 connected to fifth transfer line 64 between shell 18 of first heat exchanger 16 and a location of transfer of the NGLs off skid 12, as at 69, or, if replaceable segment 50 of fourth transfer line 44 is, or is replaced by, a second pressure reduction valve 60, instead operates second pressure reduction valve 60. In an exemplary embodiment, valves 60 or 68 are pneumatically operated “fail close” valves, that is, pneumatic pressure is applied to open the valves, absent which the valves remain closed. Pneumatic pressure in line 67 is applied or not from level controller pilot 66 either to valve 68 or alternatively to second J-T valve 60 if it is installed. Control valve 68 or 60 opens with pressure applied or closes absent pressure applied via line 67. In the case of valve 68, the opened valve allows flow of NGLs from the shell side of heat exchanger 16, which in turn allows flow of NGLs into the shell side of heat exchanger 16 from fourth transfer line 44 and from gas-liquid separator 42 into fourth transfer line 44. In the case of valve 60, actuation allows flow of NGLs into the shell side of heat exchanger 16 from fourth transfer line 44 and from gas-liquid separator 42 into fourth transfer line 44. In either case actuation regulates the level of NGLs in gas-liquid separator and flow from gas-liquid separator 42 into the shell side of first heat exchanger 16.

A sixth transfer line 70 connects to gas-liquid separator 42 at upper portion 45 for receiving and transporting a single phase lean natural gas stream from separator 42. Sixth transfer line 70 connects to shell 30 of second heat exchanger 28 proximal rear end 34 thereof, providing shell side flow of the lean natural gas stream from such rear end 34 toward the front end 32 of the second heat exchanger, counter-currently to tube side flow of inlet natural gas entering second heat exchanger 28 from second transfer line 36.

A seventh transfer line 72 connects to second heat exchanger 28 proximal the front end of the shell 30 thereof, for receiving a shell side flow stream of lean natural gas for transfer of the lean natural gas off skid 12, as at 73.

An eighth transfer line 82 is connected either to first transfer line 26 (as shown in FIGS. 1-6 and FIG. 11) or optionally second transfer line 36, and is valved by a temperature controlled valve 84 controlled by a temperature controller 86 (FIG. 11) monitoring the temperature of gas-liquid separator 42. Temperature controlled valve 84 when actuated open by temperature controller 86 passes inlet natural gas from the transfer line it valves to third transfer line 40, post J-T pressure reduction valve 38, to warm the temperature of the inlet natural gas stream passing in third transfer line 40 to gas-liquid separator 42 to an extent preventing the temperature in gas-liquid separator 42 from dropping below the minimum temperature for which metallurgy of gas-liquid separator 42 is rated. A pressure signal 81 from a temperature sensor located inside a thermowell 83 in sixth transfer line 70 is transmitted by temperature indicator 85 to controller 86. Based on a predetermined set point in temperature controller 86, temperature controller 86 applies a pressure signal 83 through line 87 to valve 84. Control valve 84 then opens or closes flow of a hotter inlet natural gas into third transfer line 40.

Lean gas is passed through seventh transfer line 72 off skid 12 to sales or for other use. Gas for pneumatic operation of pressure controller 88, level controller 66 and temperature controller 86 is supplied by a bleed line 91 off seventh transfer line 72. Lean gas in line 91 is dropped in pressure through spring controlled pressure reduction valves 92, 93 and passes into supply gas pot 90. Any condensation of vapor from the lean gas caused by the pressure drops from valves 92, 93 is captured in pot 90. Gas is led from pot 90 by line 94, branched to line 95, and dropped in pressure across pressure reduction valve 96 to a supply gas pressure of from 0 to 30 psi, then fed to pneumatic line 97 and thence to supply branch 98 to J-T valve 38, supply branch 99 to temperature controller 86 and supply branch 11 to pilot 66. Line 94 off pot 90 is controlled by pressure regulator 13 safety valving line 94 to atmosphere in the event of pressure surges in excess of the rated pressure of pot 90. Similarly, gas-liquid separator 42 is safety valved at 15.

Formation of hydrates from any moisture in the inlet natural gas after dehydration off skid is prevented by injection of methanol from a source 35 passed though methanol lines 37, 39 and injected into inlet line 14 and second transfer line 36 at injection fittings 41a, 41b and 55 respectively.

Shells 18 and 30, respectively, of the first and second heat exchangers 16 and 28 are encased in a protectively covered insulation to contain and maintain process temperatures reaching as low as the metallurgical temperature of the gas-liquid separator 42. Referring to FIGS. 1-6 this insulation is represented by a truncated length of insulation thickness, as at 74, 75. The total coverage of the insulation for shells 18 and 30 and for other insulated structure is not shown to avoid obscuring underlying structure. Similarly, gas-liquid separator 42 is encased in a protectively covered insulation, represented by a segment of insulation thickness, as at 76. The first, second, third, fourth transfer lines, respectively 26, 36, 40, 44 (including segment 50 of fourth transfer line 44) and sixth transfer line 70 are also encased in a protectively covered insulation represented by a segment of insulation thickness, shown for example for the sixth transfer line at 80. The insulation is of a kind and thickness sufficient to prevent condensation on the outer surfaces of the shells 18 and 30, the separator 42, and the first, second, third, fourth transfer lines 26, 36, 40, 44 (and included segment 50) and sixth transfer line 70, at a temperature contained within them at least as low as the minimum temperature for which metallurgy of the gas-liquid separator is rated. Suitable insulation that may be used is Trymer™/2000 XP brand polyisocyanurate foam insulation available from or Trymer®/Styrofoam® insulation, both available ITW Insulation Systems, a division of Illinois Tool Works, Inc. Trymer™/2000 XP brand polyisocyanurate foam insulation has a lower K-factor than cellular glass, which is typically used in J-T plants. K-factor is a measure of thermal conductivity, and a lower K-factor has less thermal conductivity.

The insulation surrounding segment 50 is discontinuous with the insulation surrounding the remainder of fourth transfer line 44 to allow separation of the insulation around fourth transfer line 44 without disturbing the remainder of the insulation in line 44 if segment 50 is removed for replacement with a second pressure reduction valve 60 (or if alternatively second J-T valve 60 is replaced by segment 50, as described above). In an exemplary embodiment, the insulation surrounding segment 50 is interiorly matingly contoured to the shape of segment 50 (or alternatively to the shape of second J-T valve 60 if it is initially installed instead of segment 50 as described above) and is longitudinally divided and held to segment 50 (or alternatively to second J-T valve 60) by holders, suitably tension latches, to allow nondestructive separation of the insulation from segment 50 for reuse of the insulation if second J-T valve 60 replaces segment 50 or if segment 50 replaces second J-T valve 60, as described above. In an exemplary embodiment, the insulation of segment 50 comprises a precut removable interior portion (not shown) that when removed conforms the interior of the insulation to the external contour of second J-T valve 60, for reuse of the insulation to insulate second pressure reduction valve 60 if it replaces segment 50.

Referring now to FIG. 11, the operation of an exemplary embodiment of a process for flexibly recovering NGLs from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig is described using the same reference numerals as used to refer to apparatus components of the exemplary embodiments of FIGS. 1-9. The inlet natural gas stream in line 14 is passed as a tube side flow though one-pass shell-and-tube first heat exchanger 16 from front end 20 to rear end 22. The inlet natural gas effluent from the tube side of the first heat exchanger 14 is passed from end 22 by first transfer line 26 into the front end 32 of shell-and-tube second heat exchanger 28 having a plurality of one-pass tubes 33 and flowed on the tube side of the tubes to rear end 34. The inlet natural gas effluent from the tube side of the second heat exchanger 28 is passed from rear end 34 through second transfer line 36 through a J-T valve 38 and into third transfer line 49 to reduce the temperature and pressure of the inlet natural gas at least sufficiently to condense NGLs in the inlet natural gas to two-phase gas-liquid NGLs. The two-phase gas-liquid NGLs are passed from third transfer line 40 into gas-liquid separator 42 and separated in gas-liquids separator 42 from single phase lean natural gas. The separated two-phase gas-liquid NGLs are then passed by fourth transfer line 44 through a second J-T valve 60 (see FIG. 12) at replaceable segment 50 to further reduce the temperature and pressure of the two-phase gas-liquid NGLs. The two-phase gas-liquid NGLs at said further reduced temperature are then passed through downstream portion 53 of line 44 to the shell side of first heat exchanger 16. The two-phase gas-liquid NGLs flow in shell side of first heat exchanger 16 counter-currently to inlet natural gas in the tube side of first heat exchanger 16 at a shell side flow rate effective to increase the temperature of the shell side NGLs exiting the first heat exchanger in fifth transfer line 64 to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger, suitably from 1 to 100° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger. Level control sensor 66 actuates level control valve 68 to discharge NGLs from the shell side of first heat exchanger 16 in fifth transfer line 64 to maintain a regulated flow of NGLs passing to the shell side of the first heat exchanger. Referring back to separator 42, a portion of the inlet natural gas effluent in first transfer line 26 from first heat exchanger 16 (shown in FIG. 11) or in second transfer line 36 from second heat exchanger 28 (not shown in FIG. 11) is passed to the inlet natural gas stream in third transfer line 40 to an extent warming the temperature of the stream in third transfer line entering separator 42 effective to prevent the temperature of the fluids in the gas-liquid separator from dropping below a minimum temperature for which metallurgy of the gas-liquid separator is rated.

The separated lean natural gas in separator 42 is passed from separator 42 through sixth transfer line 70 to the rear end 34 of the shell side of second heat exchanger 28 for counter-current flow to inlet natural gas entering the front end 32 in the tube side of second heat exchanger 28 and is flowed at a shell side flow rate effective to increase the temperature of the shell side lean natural gas exiting the second heat exchanger 16 at front end 32 into seventh transfer line 72 to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the second heat exchanger, suitably from 1 to 20° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger. The NGLs passed from level control valve 68 continue in fifth transfer line 64 to a destination off skid as indicated by the terminus 69 of fifth transfer line. The lean natural gas removed from the shell side of the second heat exchanger passes in seventh transfer line 72 to an off skid location, as indicated at the terminus of line 72 at 73.

During this process, the exterior of the shells of the first and second heat exchangers 16 and 28, the exterior of the separator 42, and the exterior of the first, second, third, fourth, and sixth transfer lines, respectively 26, 36, 40, 44, 70, are insulated, as indicated in FIG. 11, respectively at 74, 75, 76, 71, 77, 78, 79 and 80, to an extent sufficient to prevent condensation on the outer surfaces of the heat exchangers 16 and 28, the separator 42, and second, third, fourth, and sixth transfer lines, respectively 26, 36, 40, 44, 70, at a temperature, for separators 16 and 28 that is in a range between the temperature of the fluid entering the shell side of the heat exchangers and the minimum temperature for which metallurgy of separator 42 is rated, for separator 42, in a range between the temperature of the fluids entering separator 42 and the minimum temperature for which metallurgy of the separator is rated, and in lines steps 26, 36, 40, 44, 70, in a range between the temperature of the fluids in the lines and the minimum temperature for which metallurgy of separator 42 is rated.

The efficiency of a J-T plant exemplary embodiment of the invention is illustrated by the following Examples One through Three. All Examples are produced using HYSIS process simulation software from Aspentech Technology, Inc. 200 Wheeler Road, Burlington, Mass. 01803.

Example One

Example One compares the recoveries of a skid of a construction described above with the recoveries of an example of a prior art third party design of a J-T valve skid.

Conditions are inlet gas temperature 95° F., inlet gas pressure=1350 psig, and inlet gas volume=1.6 MMscfd.

The invention embodiment configuration employs a gas/liquid (“G/L”) heat exchanger 16 comprising a 3 inch pass through pipe and a 6 inch shell; a gas/gas (“G/G”) heat exchanger 28 with 1468 square inches of tubing surface; J-T valve 38; gas liquid separator 42; and J-T valve 60 before L/G heat exchanger 16 as described above.

The conventional commercial J-T skid has in serial sequence a gas/gas (“G/G”) heat exchanger with 457 square inches of tubing area, a J-T valve, and a gas liquid separator and a J-T valve in the sales line after the separator. The embodiment configuration is programmed at only 80% efficiency and the conventional skid is programmed at 100% efficiency.

The temperatures (° F.) at the serial components are:

Invention Embodiment Prior Art 3rd Party Design Shell Out Shell Out Component Tube In Tube Out Shell In (sales) Tube In Tube Out Shell In (sales) G/L Hex 95 90.32 −33.88 80 G/G Hex 90.32 27.12 2.44 82.37 95 59.17 34.97 75.90 J-T Valve 27.12 2.44 59.17 34.97 Separator 2.44 2.44 34.97 34.97 J-T valve 60 2.44 −33.88 J-T valve 34.97 8.129 (sales line)

Table 1 below shows volumetric and compositional recoveries for the composition of inlet natural gas and processes set forth in Example One; recoveries of all C5's and C6's are collectively C5+ recoveries in the i-C5 row.

TABLE 1 Prior Prior Inlet Embodiment Embodiment Art Ex. Art Ex Gas Sales Gas NGL Sales Gas NGL Gas 1.6 1.544 1.582 Volume (MMscfd) NGL 18.47 8.893 Volume (ABPD)* C1 88.92% 90.63% 3.00% 89.53% 3.00% C2 5.22% 5.03% 5.00% 5.18% 4.00% C3 2.44% 2.07% 12.00% 2.34% 9.00% i-C4 1.10% 0.77% 16.00% 1.00% 12.00% n-C4 0.64% 0.40% 12.00% 0.57% 10.00% i-C5 0.33% 0.14% 49.00% 0.25% 61.00% n-C5 0.19% 0.07% C6+ 0.37% 0.05% *Absolute Barrels Per Day

Table 1 shows that the J-T plant of the described embodiment recovers twice as much (208% more) NGLs than a third party conventional prior art design, and the recoveries of the exemplary embodiment reach deeper into the lower molecular weight NGLs than does the prior art design, the recoveries of the described embodiment being less weighted to C5+ heaviers.

Example Two

The following tables show a comparison of recoveries using the embodiment configuration as described above with a J-T valve 60 between separator 42 and G/L heat exchanger 16 verses a J-T plant design having two serial G/G heat exchangers and a second J-T valve in the NGL product line, as in Example One. Conditions are inlet gas temperature 120° F., inlet gas pressure=1350 psig, and inlet gas volume=5 MMscfd.

Invention Embodiment Prior Art 3rd Party Design Shell Out Shell Out Component Tube In Tube Out Shell In (sales) Tube In Tube Out Shell In (sales) G/L Hex 120 116 −18.88 21.76 G/G Hex 116 34.14 3.84 110.7 120 17.53 G/G Hex 47.34 108.5 J-T Valve 34.14 3.84 47.34 17.53 Separator 3.84 3.84 17.53 17.53 J-T valve 60 3.84 −18.88 J-T valve 17.53 −2 (sales line)

Table 2 shows volumetric and compositional recoveries for the composition of inlet natural gas and processes set forth in Example Two; recoveries of all C5's and C6's are collectively C5+ recoveries in the i-C5 row.

TABLE 2 Prior Prior Inlet Embodiment Embodiment Art Ex. Art Ex Gas Sales Gas NGL Sales Gas NGL Gas 5 5.814 4.868 Volume (MMscfd) NGL 84.6 67.7 Volume (ABPD)* C1 88.92% 90.93% 2.50% 90.42% 2.60% C2 5.10% 4.91% 6.50% 4.99% 5.90% C3 2.37% 1.97% 14.40% 2.11% 12.50% i-C4 1.08% 0.72% 16.10% 0.83% 14.40% n-C4 0.64% 0.37% 11.70% 0.45% 10.70% i-C5 0.32% 0.12% 47.40% 0.16% 52.80% n-C5 0.19% 0.06% C6+ 0.56% 0.06% *Absolute Barrels Per Day

Table 2 shows that the J-T plant of the described embodiment recovered 25% more NGLs than a J-T plant having two serial G/G heat exchangers, and the recovery of the exemplary embodiment reached deeper into the lower molecular weight NGLs than did the prior art design, being less weighted to C5+ heaviers.

Example Three

The following tables show a comparison of recoveries using the embodiment configuration as described above with a J-T valve 60 between separator 42 and G/L heat exchanger 16 verses a J-T plant design having two serial G/G heat exchangers and a second J-T valve in the NGL product line, as in Example One. Conditions are inlet gas temperature 120° F., inlet gas pressure=1350 psig, and inlet gas volume=10 MMscfd.

Invention Embodiment Prior Art 3rd Party Design Shell Out Shell Out Component Tube In Tube Out Shell In (sales) Tube In Tube Out Shell In (sales) G/L Hex 120 118.0 −6.99 21.0 G/G Hex 118.0 43.07 13.68 107.9 120 27.36 G/G Hex 56.66 104.4 J-T Valve 43.07 13.68 56.66 27.36 Separator 13.68 13.68 27.36 27.36 J-T valve 60 13.68 −6.99 J-T valve 27.36 9.7 (sales line)

Table 3 shows volumetric and compositional recoveries for the composition of inlet natural gas set forth; recoveries of all C5's and C6's are collectively C5+ recoveries in the i-C5 row.

TABLE 3 Prior Prior Inlet Embodiment Embodiment Art Ex. Art Ex Gas Sales Gas NGL Sales Gas NGL Gas 10 9.707 9.796 Volume (MMscfd) NGL 144.5 112 Volume (ABPD)* C1 88.92% 90.55% 2.60% 90.10% 2.60% C2 5.10% 4.97% 6.00% 5.03% 5.40% C3 2.37% 2.08% 13.00% 2.19% 11.10% i-C4 1.08% 0.80% 14.90% 0.90% 13.10% n-C4 0.64% 0.43% 11.00% 0.50% 9.90% i-C5 0.32% 0.15% 51.20% 0.19% 57.00% n-C5 0.19% 0.07% C6+ 0.56% 0.08%

Table 3 shows that even at twice the throughput of Example Two, the J-T plant of the described embodiment recovered 29% more NGLs than a J-T plant having two serial G/G heat exchangers, and the recovery of the exemplary embodiment reached deeper into the lower molecular weight NGLs than did the prior art design, being less weighted to C5+ heaviers.

Refrigeration Plant Exemplary Embodiment

Referring to the drawings, FIGS. 13 and 14 are respectively south and north perspective views and FIGS. 15-18 are respectively south, west, north and east elevational views of an exemplary embodiment of a transportable apparatus, indicated by reference numeral 10B, comprising a transportable skid mounted refrigeration plant in accordance with this invention. The reference numerals in this embodiment are the same for like components as in the embodiment for the J-T plant.

Referring to FIGS. 13-18, a transportable skid mounted refrigeration plant 10 comprises a skid 12 and an inlet line 14 for receiving an inlet natural gas stream that has a temperature at atmospheric ambient or higher and a pressure of at least about 400 psig. The same one pass shell-and-tube first heat exchangers 16 and 28 as employed for the exemplary embodiment of FIGS. 1-12 are supported on skid 12 with the same internal structure and operation and like connecting first and second transfer lines as already described and that description is incorporated here by reference.

Second transfer line 36 receives the inlet natural gas stream exiting second heat exchanger 28. Pressure regulator valve 65 (FIGS. 21, 23) regulates the upstream pressure of the inlet natural gas stream in second transfer line 36 to a predetermined set point. Second transfer line 36 connects with a tube-in-shell flash drum chiller 100. The inlet natural gas passes as the tube side into flash drum chiller 100 where it is chilled by a cold vapor refrigerant on the shell side of chiller 100 sufficiently to reduce the temperature of the inlet natural gas at least enough to condense natural gas liquids in the inlet natural gas and produce two-phase gas-liquid NGLs and a single-phase gas.

In an exemplary embodiment, two parallel vapor compression refrigerant systems are employed, with compressors and condensers sheltered under housings 101 and 102. In an exemplary embodiment R-404 refrigerant is used. R-404 refrigerant enters the compressors housed in 101, 102 as a low pressure, low temperature vapor. The refrigerant is compressed by the compressors to a high pressure and temperature gaseous state and is passed to condensers housed in 101, 102 that cool the vapor to start it condensing to a high temperature liquid. The high temperature liquid is passed by refrigerant lines 103 and 106 from the condensers in housings 101, 102 respectively, to expansion valves 104, 107 respectively (FIGS. 21, 23), located at the entry into flash drum chiller 100, where pressure of the high temperature liquid abruptly decreases, causing flash evaporation of the refrigerant within vessel 100, cooling the refrigerant vapor and residual refrigerant liquid to the saturation temperature of the refrigerant at the reduced pressure. The refrigerant then passes from chiller 100 back to the compressors in housings 101, 102 as a low pressure, low temperature vapor in return lines 105, 108, respectively.

The chilled natural gas exits chiller 100 and passes into third transfer line 40 for delivery to horizontal gas-liquid separator 42 (FIGS. 19, 21, 23). In an exemplary embodiment, third transfer line 40 for transfer of NGLs to separator 42 includes a replaceable segment 50 between chiller 100 and separator 42. Replaceable segment 50 separates third transfer line 40 into an upstream portion 51 proximal to separator 42 and a downstream portion 53 distal from separator 42. In an exemplary embodiment, schematically illustrated in FIG. 19, replaceable segment 50 comprises a length of pipe 54, a first flange 56 connected on pipe 54 and bolting to a flange 57 connected to the upstream portion 51 of third transfer line 40, and a second flange 58 connected on pipe 54 and bolting to a flange 59 connected to downstream portion 53 of third transfer line 40. Replaceable segment 50 comprising pipe 54 and flanges 56 and 58 is removable by unbolting the flange 56 from flange 57 and unbolting flange 58 from flange 59. Such removal of replaceable segment 50 comprising pipe 54 and flanges 56 and 58 from transfer line 40 permits convenient field replacement of such segment 50 with a bolt up different replaceable component, in a preferred exemplary embodiment, a J-T pressure reduction valve, without having to cut out a length of line 44, weld in a second J-T pressure reduction valve, and reinstall insulation (about which see more below). This provides a degree of flexibility for increasing the efficiency of reducing the content of NGLs from natural gas and increasing NGL recovery in the field if on-site conditions call for increased efficiency

Alternatively, replaceable segment 50 may be already be a J-T pressure reduction valve with its flanges 56 and 58 bolted up at flanges 57 and 59, and if a lesser efficiency is called for by conditions at the natural gas conditioning site, the J-T pressure reduction valve may be removed and replaced in the field by unbolting it and bolting in instead a segment 50 comprising pipe 54 and flanges flange 56 and 58. The efficiency benefits of a J-T pressure reduction valve between chiller 100 and gas-liquids separator 42 are described below Examples Five and Six.

Third transfer line 40 connects into and delivers the two-phase gas-liquid NGLs and a single-phase gas from chiller 100, and optionally, a JT valve at segment 50, into gas-liquid separator 42.

Horizontal gas-liquid separator 42 is supported on skid 12 and has lower and upper portions 43, 45, respectively. Heavier two-phase gas-liquid NGLs gravitationally collect in the lower portion separate from lighter single-phase gas rising as a lean natural gas in the upper portion.

A fourth transfer line 44 transports two-phase gas-liquid NGLs from the lower portion of gas-liquid separator 42 to shell 18 of first heat exchanger 16 proximal rear end 22 of shell 18 for shell side flow of natural gas liquids from rear end 22 toward front end 20 of first heat exchanger 16 counter-currently to tube side flow of the inlet natural gas stream entering first heat exchanger 16 from inlet line 14.

Referring to FIGS. 20, 21, 23, in an exemplary embodiment, fourth transfer line 44 for transfer of NGLs includes a replaceable segment 150 between separator 42 and first heat exchanger shell 18. Replaceable segment 150 separates fourth transfer line 44 into an upstream portion 151 proximal to separator 42 and a downstream portion 153 distal from separator 42. Ball valve 149 in fourth transfer line 44 between separator 42 and replaceable segment 150 provides means for blocking NGL flow from separator 42 to replaceable segment 150. In an exemplary embodiment, schematically illustrated in FIG. 20, replaceable segment 150 comprises a length of pipe 154, a first flange 156 connected on pipe 154 and bolting to a flange 157 connected to the upstream portion 151 of fourth transfer line 44, and a second flange 158 connected on pipe 154 and bolting to a flange 159 connected to downstream portion 153 of fourth transfer line 44. Replaceable segment 150 comprising pipe 154 and flanges 156 and 158 is removable by unbolting flange 156 from flange 157 and unbolting flange 158 from flange 159. Such removal of replaceable segment 150 comprising pipe 154 and flanges 156 and 158 from transfer line 44 permits convenient field replacement of such segment 150 with a bolt up different replaceable component, in a preferred exemplary embodiment, a second J-T pressure reduction valve, without having to cut out a length of line 44, weld in a second J-T pressure reduction valve, and reinstall insulation (about which see more below). This provides a degree of flexibility for increasing NGL recovery efficiency in the field if on-site conditions call for increased efficiency

Alternatively, replaceable segment 150 may be a second J-T pressure reduction valve (second, if replaceable segment 50 has a J-T valve already installed there) with its flanges 156 and 158 bolted up at flanges 157 and 159, and if a lesser efficiency is called for by conditions at the gas conditioning site, the second J-T pressure reduction valve may be removed and replaced in the field by unbolting it and bolting in instead segment 150 comprising pipe 154 and flanges flange 156 and 158. The efficiency benefits of a second J-T pressure reduction valve are described below in Examples Five and Six.

Fourth transfer line 44 ells at 161, 163 respectively rising to connect into shell 18 of gas-liquid separator 16.

A fifth transfer line 64 connects to shell 18 of first heat exchanger 16 proximal the front end 20 of heat exchanger 16 for receiving a shell side flow stream of NGLs from heat exchanger front end 20 and transferring the NGLs off skid as product for use or sale.

In FIGS. 21-23, stacked circles off a line or vessel indicated a thermowell (bottom circle) and a temperature indicator (top circle). A single circle indicates a pressure indicator.

Referring to FIGS. 13-23, a level controller 66 in fluid communication with the lower portion 43 of gas-liquid separator 42 controls the liquid volume in separator 42. In an exemplary embodiment, level controller 66 comprises a displacer arm with a float providing a sensory mechanism based on the height of liquid in the separator. A pilot associated with the controller 66 pneumatically operates either a level control valve 68 connected to fifth transfer line 64 between shell 18 of first heat exchanger 16 and a location of transfer of the NGLs off skid 12, as at 69, or, if replaceable segment 150 of fourth transfer line 44 is or is replaced by a second J-T valve, instead operates second J-T valve 160. In an exemplary embodiment, valves 68 and any second J-T valve at segment 150 are pneumatically operated “fail close” valves, that is, pneumatic pressure is applied to open the valves, absent which the valves remain closed. Pneumatic pressure in line 67 is applied or not from level controller pilot 66 either to valve 68 or alternatively to a second J-T valve if it is installed at segment 150. Control valve 68 any second J-T valve at segment 150 opens with pressure applied or closes absent pressure applied via line 67. In the case of valve 68, the opened valve allows flow of NGLs from the shell side of heat exchanger 16, which in turn allows flow of NGLs into the shell side of heat exchanger 16 from fourth transfer line 44 and from gas-liquid separator 42 into fourth transfer line 44. In the case of any second J-T valve at segment 150, actuation allows flow of NGLs into the shell side of heat exchanger 16 from fourth transfer line 44 and from gas-liquid separator 42 into fourth transfer line 44. In either case actuation regulates the level of NGLs in gas-liquid separator and flow from gas-liquid separator 42 into the shell side of first heat exchanger 16.

A sixth transfer line 70 connects to gas-liquid separator 42 at upper portion 45 for receiving and transporting a single phase lean natural gas stream from separator 42. Sixth transfer line 70 connects to shell 30 of second heat exchanger 28 proximal rear end 34 thereof, providing shell side flow of the lean natural gas stream from such rear end 34 toward the front end 32 of the second heat exchanger, counter-currently to tube side flow of inlet natural gas entering second heat exchanger 28 from second transfer line 36.

A seventh transfer line 72 connects to second heat exchanger 28 proximal the front end of the shell 30 thereof, for receiving a shell side flow stream of lean natural gas for transfer of the lean natural gas off skid 12, as at 73.

Refrigeration compressors in housings 101, 102 are run controlled by a temperature indicator 85 communicating to a temperature controller in housings 101, 102 (FIG. 23) monitoring the temperature of gas-liquid separator 42 to prevent the temperature in gas-liquid separator 42 from dropping below the minimum temperature for which metallurgy of gas-liquid separator 42 is rated. An electric signal 81 from a temperature sensor located inside a thermowell 83 in sixth transfer line 70 is transmitted by temperature indicator 85 to the temperature controller which switches the compressors in housings 101, 102 off or on according to a temperature set point in the controller.

Lean gas is passed through seventh transfer line 72 off skid 12 to sales or for other use. Referring to FIG. 22, gas for pneumatic operation of level controller 66 is supplied by a bleed line 91 off seventh transfer line 72. Lean gas in line 91 is dropped in pressure through spring controlled pressure reduction valves 92, 93 and passes into supply gas pot 90. Any condensation of vapor from the lean gas caused by the pressure drops from valves 92, 93 is captured in pot 90. Gas is led from pot 90 by line 94, branched to line 95, and dropped in pressure across pressure reduction valve 96 to a supply gas pressure of from 0 to 30 psi, then fed to pneumatic line 97 and thence to pilot 66, and from pilot 66 to pneumatic line 67 to level control valve 68. Line 94 off pot 90 is controlled by pressure regulator 13 safety valving line 94 to atmosphere in the event of pressure surges in excess of the rated pressure of pot 90. Similarly, gas-liquid separator 42 is safety valved at 15.

Formation of hydrates from any moisture in the inlet natural gas after dehydration off skid is prevented by injection of methanol from a source 35 passed though methanol lines 37, 39 and injected into inlet line 14 and second transfer line 36 at injection fittings 41a, 41b and 55 respectively.

Shells 18 and 30, respectively, of the first and second heat exchangers 16 and 28 are encased in a protectively covered insulation to contain and maintain process temperatures reaching as low as the metallurgical temperature of the gas-liquid separator 42. Referring to FIGS. 13-18 this insulation is represented by a truncated length of insulation thickness, as at 74, 75. The total coverage of the insulation for shells 18 and 30 and for other insulated structure is not shown to avoid obscuring underlying structure. Similarly, gas-liquid separator 42 is encased in a protectively covered insulation, represented by a segment of insulation thickness, as at 76 (e.g., FIG. 14). The first, second, third, fourth transfer lines, respectively 26, 36, 40, 44 (including segment 50 of fourth transfer line 44) and sixth transfer line 70 are also encased in a protectively covered insulation represented by a segment of insulation thickness, shown for example for the sixth transfer line at 80 (FIG. 23). Chiller 100 is encased in a protectively covered insulation represented by a segment of insulation thickness at 109. The insulation is of a kind and thickness sufficient to prevent condensation on the outer surfaces of the shells 18 and 30, the chiller 100, the separator 42, and the first, second, third, fourth transfer lines 26, 36 (and included segment 50), 40, 44 (and included segment 150) and sixth transfer line 70, at a temperature contained within them at least as low as the minimum temperature for which metallurgy of the gas-liquid separator is rated. Suitable insulation that may be used is the same as stated above in the case of the J-T Plant embodiment, for the same reasons and advantages.

The insulation surrounding segments 50 and 150 is discontinuous with the insulation surrounding the remainder of third and fourth transfer lines 36, 44 respectively to allow separation of the insulation around third and fourth transfer lines 36, 44 respectively without disturbing the remainder of the insulation in lines 36 or 44 if segment 50 or 150, or both, comprising pipe lengths 54, 154 respectively, is or are removed for replacement with a pressure reduction J-T valve (or alternatively if segment 50 or 150 or both each comprising a J-T valve is replaced by pipe lengths 54, 154, respectively, as described above). In an exemplary embodiment, the insulation surrounding segments 50 and 150 is interiorly matingly contoured to the shape of segment 50 or 150 respectively, whether the segment comprise a J-T valve or a length of pipe. The insulation is longitudinally divided and held to segment 50 or 150 by holders, suitably tension latches, to allow nondestructive separation of the insulation from segment 50 or 150 for reuse for a like replaceable segment.

Referring now to FIG. 20-23, the operation of an exemplary embodiment of a process for flexibly recovering NGLs from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig is described using the same reference numerals as used to refer to apparatus components of the exemplary embodiments of FIGS. 13-23. The inlet natural gas stream in line 14 is passed as a tube side flow though one-pass shell-and-tube first heat exchanger 16 from front end 20 to rear end 22. The inlet natural gas effluent from the tube side of the first heat exchanger 14 is passed from end 22 by first transfer line 26 into the front end 32 of shell-and-tube second heat exchanger 28 having a plurality of one-pass tubes 33 and is flowed on the tube side of the tubes to rear end 34. The inlet natural gas effluent from the tube side of the second heat exchanger 28 is passed from rear end 34 through second transfer line 36 through chiller 100 and into third transfer line 49 to reduce the temperature and pressure of the inlet natural gas at least sufficiently to condense NGLs in the inlet natural gas to two-phase gas-liquid NGLs. Optionally, third transfer line includes a J-T valve at replaceable segment 50, further reducing the temperature of the two-phase gas-liquid NGLs. The two-phase gas-liquid NGLs are passed from third transfer line 40 into gas-liquid separator 42 and separated in gas-liquids separator 42 from single phase lean natural gas. The separated two-phase gas-liquid NGLs are then passed by fourth transfer line 44, optionally through a second J-T valve at replaceable segment 150 to further reduce the temperature and pressure of the two-phase gas-liquid NGLs. The two-phase gas-liquid NGLs at said further reduced temperature are then passed through downstream portion 153 of line 44 to the shell side of first heat exchanger 16. The two-phase gas-liquid NGLs flow in shell side of first heat exchanger 16 counter-currently to inlet natural gas in the tube side of first heat exchanger 16 at a shell side flow rate effective to increase the temperature of the shell side NGLs exiting the first heat exchanger in fifth transfer line 64 to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger, for example, from 1 to 100° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger. Level control sensor 66 actuates level control valve 68 to discharge NGLs from the shell side of first heat exchanger 16 in fifth transfer line 64 or, if replaceable segment 150 of fourth transfer line 44 is a second J-T valve, instead operates the second J-T valve to maintain a regulated flow of NGLs passing to the shell side of the first heat exchanger.

The separated lean natural gas in separator 42 is passed from separator 42 through sixth transfer line 70 to the rear end 34 of the shell side of second heat exchanger 28 for counter-current flow to inlet natural gas entering the front end 32 in the tube side of second heat exchanger 28 and is flowed at a shell side flow rate effective to increase the temperature of the shell side lean natural gas exiting the second heat exchanger 16 at front end 32 into seventh transfer line 72 to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the second heat exchanger, suitably from 1 to 20° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger. The NGLs passed from level control valve 68 continue in fifth transfer line 64 to a destination off skid as indicated by the terminus 69 of fifth transfer line. The lean natural gas removed from the shell side of the second heat exchanger passes in seventh transfer line 72 to an off skid location, as indicated at the terminus of line 72 at 73.

During this process, the exterior of the shells of the first and second heat exchangers 16 and 28, the exterior of the chiller 100 and the separator 42, and the exterior of the first, second, third, fourth, and sixth transfer lines, respectively 26, 36, 40, 44, 70, are insulated, as variously indicated in the drawings (insulation for third transfer line 40 is not depicted so as to not obscure details of line 40), respectively at 74, 75, 109, 76, 71, 77, 79 (for the fourth transfer line) and 80 (for the sixth transfer line), to an extent sufficient to prevent condensation on the outer surfaces of the heat exchangers 16 and 28, the chiller 100, the separator 42, and second, third, fourth, and sixth transfer lines, respectively 26, 36, 40, 44, 70, at a temperature, for separators 16 and 28 and chiller 100 that is in a range between the temperature of the fluid entering the shell side of the heat exchangers and the chiller and the minimum temperature for which metallurgy of separator 42 is rated, for separator 42, in a range between the temperature of the fluids entering separator 42 and the minimum temperature for which metallurgy of the separator is rated, and in lines steps 26, 36, 40, 44, 70, in a range between the temperature of the fluids in the lines and the minimum temperature for which metallurgy of separator 42 is rated.

Thus there have been described both J-T plant and refrigeration plant embodiments of this invention in which at least one of the third and fourth transfer lines include a replaceable segment that is removable without cutting the third or fourth transfer line, or both, as applicable, for optional replacement of the replaceable segment by a different replaceable segment.

The efficiency of an exemplary refrigeration plant embodiment of the invention is illustrated by the following Examples. All examples are produced using process simulation software on a natural gas of identical composition, at identical natural gas volume (2.0 MMscfd) and identical temperature (100° F.). Example One has an inlet gas pressure of 611 psig. Examples Two and Three have an inlet gas pressure of 1200 psig. The same process simulation software is used as used for Examples One through Three.

Example Four

Example Four shows the kinds of recoveries achieved with a skidded refrigeration system of a prior art design. The embodiment configuration employs a gas/liquid (“G/L”) heat exchanger 16 comprising a 2 inch pass through pipe and a 3 inch shell; a gas/gas (“G/G”) heat exchanger 28 with 641 square inches of tubing surface; a refrigeration system 100-108; and gas liquid separator 42 with routing of the NGLs to the shell side of the G/L heat exchanger and a routing of the lean gas to the shell side of the G/G heat exchanger.

The temperatures (° F.) at the serial components are:

Prior Art Design Shell Out Component Tube In Tube Out Shell In (sales) G/L Hex 100 94.35 14.66 G/G Hex 94.35 76.46 14.66 92.23 Chiller 76.46 14.66 Separator 14.66 14.66

Table 4 shows volumetric and compositional recoveries for the composition of inlet natural gas set forth; recoveries of all NGL C5's and C6's are collectively C5+ recoveries placed in the i-C5 row.

TABLE 4 Prior Prior Inlet Art Ex. Art Ex Gas Sales Gas NGL Gas 2.0 1.198 Volume (MMscfd) NGL 197.29 Volume (ABPD)* C1 50.35% 68.13% 1.00% C2 22.22% 17.43% 16.9% C3 15.65% 5.87% 42.3% i-C4 1.6% 0.31% 8.1% n-C4 3.30% 0.48% 17.8% i-C5 0.43% 0.03% 12.0% n-C5 0.81% 0.04% C6+ 0.27% 0.00% *Absolute Barrels Per Day

Example Five

The following tables show a comparison of recoveries using the embodiment configuration as described above except with a J-T valve 50 between refrigeration heat exchangers 101, 102 and separator 42.

The temperatures (° F.) at the serial components are:

Invention Embodiment Shell Out Component Tube In Tube Out Shell In (sales) G/L Hex 100 91.96 −19.52 — G/G Hex 91.96 73.58 −19.52 90.96 Chiller 73.58 9.98 J-T valve 9.98 −19.52 Separator −19.52 −19.52

Table 5 below shows volumetric and compositional recoveries for the composition of inlet natural gas set forth; recoveries of all NGL C5's and C6's are collectively C5+ recoveries and placed in the i-C5 row.

TABLE 5 Inlet Embodiment Embodiment Gas Sales Gas NGL Gas 2.0 0.8883 Volume MMscfd NGL 168.33 Volume (ABPD)* C1 50.35% 75.14% 1.1% C2 22.22% 12.63% 16.7% C3 15.65% 3.08% 40.0% i-C4 1.6% .14% 8.0% n-C4 3.30% .20% 18.2% i-C5 0.43% 0.01% 13.3% n-C5 0.81% 0.02% C6+ 0.27% 0.00% *Absolute Barrels Per Day

Table 5 shows that the described embodiment of Example Five recovers 25% more NGLs than a Refrigeration plant having two serial G/G heat exchangers as in Example Four, and the recoveries of the exemplary embodiment reach deeper into the lower molecular weight NGLs than did the prior art design, being less weighted to C5+ heaviers.

Example Six

The following tables show a comparison of recoveries using the embodiment configuration as described in Example Five with an additional J-T valve 150 between separator 42 and G/L heat exchanger 16. Inlet gas conditions are the same as in Example Five.

Invention Embodiment Shell Out Component Tube In Tube Out Shell In (sales) G/L Hex 100 89.99 −48.23 — G/G Hex 89.99 71.94 −20.32 89.03 Refrigeration 71.94 9.16 Hex J-T valve 9.16 −20.32 Separator −20.32 −20.32 J-T valve −20.32 −48.23

Table 6 shows volumetric and compositional recoveries for the composition of inlet natural gas and process set forth in Example Six; recoveries of all C5's and C6's are collectively C5+ recoveries in the i-C5 row.

TABLE 6 Inlet Embodiment Embodiment Gas Sales Gas NGL Gas 2.0 .8808 Volume MMscfd NGL 171.61 Volume (ABPD)* C1 50.35% 75.29% 1.1% C2 22.22% 12.51% 16.8% C3 15.65% 3.03% 40.2% i-C4 1.6% 0.14% 8.0% n-C4 3.30% 0.19% 18.1% i-C5 0.43% 0.01% 13.1% n-C5 0.81% 0.01% C6+ 0.27% 0.00%

From the foregoing, it is seen that the embodiments of Examples Five and Six reach deeper into the natural gas such that methane is about 10% higher in concentration than in the prior art design and C2, C3, C4's, and C5+'s are much lower in concentration. The concentration of ethane is reduced about 40%, propane about 90%, and butanes and pentanes about 230%.

The above-disclosed subject matter is to be considered illustrative, and not restrictive. The appended claims are intended to cover all modifications, enhancements, and other exemplary embodiments that fall within the true scope of the present invention. To the maximum extent allowed by law, the present invention is to be determined by the broadest permissible interpretation of the following claims and their equivalents, unrestricted or limited by the foregoing detailed descriptions of exemplary embodiments of the invention.

Claims

1. Transportable apparatus for flexibly recovering natural gas liquids from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig, comprising:

a. a skid;
b. an inlet line for receiving the inlet natural gas stream;
c. first and second one pass tube-in-shell heat exchangers supported on said skid, said second heat exchanger being connected in series with said first heat exchanger by a first transfer line, said first heat exchanger receiving said inlet natural gas stream from said inlet line;
d. a second transfer line for receiving the inlet natural gas stream exiting said second heat exchanger;
e. an NGLs condenser connected to the second transfer line for receiving inlet natural gas stream from said second heat exchanger and operatively sufficient to condense natural gas liquids in the inlet natural gas to two-phase gas-liquid NGLs,
f. a third transfer line for receiving said two-phase gas-liquid NGLs from the NGLs condenser;
g. a gas-liquid separator supported on said skid and connected to said third transfer line, said separator having lower and upper portions for separating two-phase gas-liquid NGLs from natural gas remaining in a single-phase gaseous state as a lean natural gas;
h. a fourth transfer line connected to said separator at said lower portion, for receiving and transporting two-phase gas-liquid NGLs from said separator, said fourth transfer line connecting to the shell of said first heat exchanger proximal a rear end of the shell for shell side flow of NGLs from said rear end toward a front end of the first heat exchanger counter-currently to tube side flow of the inlet natural gas stream entering the first heat exchanger from said inlet line;
i. at least one of said third and fourth transfer lines or both, including a replaceable segment that is removable without cutting the third or fourth transfer line or both, as applicable, for optional replacement of said replaceable segment by a different replaceable segment;
j. a fifth transfer line connected to the shell of said first heat exchanger proximal the front end of the first heat exchanger for receiving a shell side flow stream of NGLs from the front end of the first heat exchanger as product;
k. a sixth transfer line connected to said separator at said upper portion for receiving and transporting a lean natural gas stream from said separator, said sixth transfer line connecting to the shell of the second heat exchanger proximal a rear end of the shell for shell side flow of the lean natural gas stream from said rear end toward a front end of the second heat exchanger counter-currently to tube side flow of inlet natural gas entering the second heat exchanger from said second transfer line; and
l. a seventh transfer line connected to said second heat exchanger proximal the front end of the shell thereof for receiving a shell side flow stream of lean natural gas as a lean gas product.

2. The apparatus of claim 1 in which said replaceable segment either comprises

a. a length of pipe with connectors connecting the pipe with upstream and downstream potions of said third or fourth transfer lines or both that includes or include said replaceable segment, said pipe being downstream of said valving for blocking flow, or
b. a J-T pressure reduction valve with connectors connecting the J-T valve with upstream and downstream potions of said third or fourth transfer line or both that includes or include said replaceable segment, said J-T valve being downstream of said valving for blocking flow,
and
c. if said replaceable segment comprises said length of pipe, said different replaceable segment comprises a J-T pressure reduction valve with connectors for connecting the J-T valve with upstream and downstream potions of said third or fourth transfer line, or both, that includes said replaceable segment, or
d. if said J-T valve comprises said replaceable segment, said different replaceable segment comprises a said length of pipe with connectors for connecting the length of pipe with upstream and downstream potions of said third or fourth transfer line, or both, that includes said replaceable segment.

3. The apparatus of claim 2 in which said NGLs condenser is a J-T pressure reducing valve, wherein said third transfer line receives the inlet natural gas stream at a pressure and temperature reduced from that in the second transfer line, said reduced pressure and temperature being at least sufficient to condense natural gas liquids in the inlet natural gas to two-phase gas-liquid NGLs, and wherein said replaceable segment is in said fourth transfer line.

4. The apparatus of claim 2 in which said NGLs condenser is a shell-and-tube refrigerant flash drum chiller for receiving the inlet natural gas stream from the second transfer line on the tube side for chilling the received inlet natural gas stream sufficiently to condense natural gas liquids in the inlet natural gas to two-phase gas-liquid NGLs.

5. The apparatus of claim 4 in which both said third and fourth transfer lines include said replaceable segment, and said replaceable segment in said third transfer line comprises a said J-T pressure reduction valve.

6. The apparatus of claim 2 in which

a. the connectors of said length of pipe comprise first and second flanges, said first flange connected to said pipe for bolting to a flange connected to said upstream portion of said third or fourth transfer lines or both that includes or include said length of pipe, and said second flange connected to said pipe for bolting to a flange connected to said downstream portion of said third or fourth transfer lines or both that includes or include said length of pipe, and in which
b. the connectors of said J-T pressure reduction valve comprise first and second flanges, said first flange connected to said J-T valve for bolting to a flange connected to said upstream portion of said third or fourth transfer lines or both that includes or include said J-T valve, and said second flange connected to said J-T valve for bolting to a flange connected to said downstream portion of said third or fourth transfer line or both that includes or include said J-T valve.

7. The apparatus of claim 2 in which said shells of said first and second heat exchangers, said NGLs condenser, said separator and said first, second, third and fourth transfer lines, including said replaceable segment of said third or fourth transfer line or both said third or fourth transfer lines, as applicable, and said sixth transfer line, being encased in a protectively covered insulation of a kind and thickness sufficient to prevent condensation on the outer surfaces of the shells, NGLs condenser, said separator, and said first, second, third and fourth transfer lines, including said included replaceable segment or segments, and said sixth transfer line, at a temperature contained within them not below the minimum temperature for which metallurgy of the gas-liquid separator is rated, the insulation surrounding said replaceable segment or segments being discontinuous with the insulation surrounding the remainder of the third or fourth transfer lines, or both, as applicable, for separation from said third or fourth transfer lines without disturbing said remainder if said replaceable segment is removed and replaced with a different replaceable segment.

8. The apparatus of claim 7 in which said insulation surrounding said segment is internally matingly contoured to the shape of the replaceable segment and is longitudinally divided and held to said segment by holders to allow nondestructive separation of said insulation from said segment for reuse of said insulation if a said different replaceable component replaces said segment.

9. The apparatus of claim 2 in which said first heat exchanger comprises a cylindrical shell pressure vessel having front and rear end, and a pass-through tube connected to said inlet line at said front end of the shell for receiving said inlet natural gas stream for tube side flow inside said shell, said first transfer line connecting to said pass-through tube at said rear end of the first heat exchanger for receiving the inlet natural gas stream exiting said first heat exchanger, and wherein said second heat exchanger comprises a hair pin cylindrical shell pressure vessel having front and rear ends and connected on said front end to said first transfer line, a pair of tube sheets being transversely affixed to said shell inside the front and rear ends of the shell, and a plurality of tubes being longitudinally arranged within the shell transversely affixed to and at least partially supported by the tube sheets for conducting the inlet natural gas stream introduced into the front end of the shell to the rear end of the shell.

10. The apparatus of claim 9 in which the pass-through tube in said first heat exchanger has, and in which the tubes in said second heat exchanger have, an inner diameter effective at the density and dynamic viscosity of the inlet natural gas stream to produce a tube side flow velocity in a turbulent flow regime, and the pass-through tube in said first heat exchanger has, and in which the tubes in said second heat exchanger have, an outer diameter relative to the inner diameter of the shell providing an annulus effective to allow a shell side fluid flow rate sufficient, at a thermal conductivity of the pass-through tube, to increase the temperature of the shell side fluid exiting the respective heat exchangers to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the respective heat exchangers.

11. The apparatus of claim 10 in which said predetermined range is within 1 to 100° F. less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger and is from 1 to 20° F. less than the temperature of the inlet natural gas entering the tube side of such second heat exchanger.

12. The apparatus of claim 11 in which said pass-through tube of said first heat exchanger has an exterior diameter that is, and in which said tubes of said second heat exchanger are arranged to form a tube bundle having a cross sectional dimension that is, from two-thirds to three-fourths the inner diameter of the shell vessel.

13. The apparatus of claim 2 further comprising a level controller pilot in fluid communication with the lower portion of the gas-liquid separator, for actuating either a valve connected to said fifth transfer line between the shell of said first heat exchanger and a location of transfer of the NGLs as product, or, if said replaceable segment of said fourth transfer line is a said J-T valve or is a length of pipe replaced by a said J-T valve, instead actuating said J-T valve in said fourth transfer line, for regulating discharge of NGLs from said gas-liquid separator into said fourth transfer line.

14. The apparatus of claim 2 further comprising an eighth transfer line connected either to said first transfer line or said second transfer line and valved by a temperature controlled valve controlled by a temperature controller monitoring the temperature of the gas-liquid separator, said temperature controlled valve when actuated open by said temperature controller passing inlet natural gas from said transfer line it valves to said third transfer line to warm the temperature of the inlet natural gas stream in the third transfer line passing to the gas-liquid separator to an extent preventing the temperature in the gas-liquid separator from dropping below the minimum temperature for which metallurgy of the gas-liquid separator is rated.

15. A process for flexibly recovering NGLs from an inlet natural gas stream having a temperature at atmospheric ambient or higher and a pressure of at least 400 psig, comprising:

a. passing the inlet natural gas stream as a tube side flow though a one-pass shell-and-tube first heat exchanger;
b. passing inlet natural gas effluent from the tube side of the first heat exchanger as a tube side flow stream though a shell-and-tube second heat exchanger having a plurality of one-pass tubes;
c. passing the inlet natural gas effluent from the tube side of the second heat exchanger through a NGLs condenser to reduce the temperature and pressure of the inlet natural gas at least sufficiently to condense NGLs in the inlet natural gas to two-phase gas-liquid NGLs;
d. separating the two-phase gas-liquid NGLs in a gas-liquids separator from remaining single phase natural gas as a lean natural gas;
e. passing the separated two-phase gas-liquid NGLs through a replaceable segment of a transfer line to the shell side of the first heat exchanger, said replaceable segment comprising either a length of pipe if no additional cooling of the two-phase gas-liquid NGLs is desired, or a J-T valve if additional cooling of the two-phase gas-liquid NGLs is desired;
f. passing the two-phase gas-liquid NGLs from step (e) for counter-current flow to inlet natural gas in the tube side of the first heat exchanger at a shell side flow rate effective to increase the temperature of the shell side NGLs exiting the first heat exchanger to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the first heat exchanger;
g. regulating removal of NGLs from the shell side of the first heat exchanger to maintain a flow of NGLs passing to the shell side of the first heat exchanger;
h. passing the separated lean natural gas to the shell side of the second heat exchanger;
i. passing the separated lean natural gas from step (h) for counter-current flow to inlet natural gas in the tube side of the second heat exchanger at a shell side flow rate effective to increase the temperature of the shell side lean natural gas exiting the second heat exchanger to within a predetermine temperature range less than the temperature of the inlet natural gas entering the tube side of the second heat exchanger; and
j. receiving separately NGLs removed from the shell side of the first heat exchanger and lean natural gas removed from the shell side of the second heat exchanger;
k. while insulating the exterior of the shells of the first and second heat exchangers, the exterior of the separator, and passages within which the steps (c), (e), (f), and (h) are performed, to an extent sufficient to prevent condensation on the outer surfaces of the heat exchangers, the separator, and said passages at a temperature, in steps (a) and (b) in a range between the temperature of the fluid entering the shell side of the heat exchangers and the minimum temperature for which metallurgy of the separator is rated, in step (d), in a range between the temperature of the fluids entering the separator and the minimum temperature for which metallurgy of the separator is rated, and in steps (c), (e), (f), and (h), in a range between the temperature of the fluids in the passages and the minimum temperature for which metallurgy of the separator is rated.

16. The process of claim 15 in which said NGLs condenser is a J-T pressure reducing valve.

17. The process of claim 16 further comprising passing a portion of the inlet natural gas effluent from the first heat exchanger or from the second heat exchanger to the inlet natural gas stream after it is passed through the J-T valve and before passing into said gas-liquids separator to an extent warming the temperature of the stream effective to prevent the temperature of the fluids in the gas-liquid separator from dropping below a predetermined minimum temperature for which metallurgy of the gas-liquid separator is rated.

18. The process of claim 16 in which the lean natural gas shell side flow rate in the second heat exchanger is effective to increase the temperature of the shell side lean natural gas exiting the second heat exchanger to within 5 to 20° F. less than the temperature of the inlet natural gas entering the tube side of the second heat exchanger.

19. The process of claim 15 in which said NGLs condenser is a shell-and-tube refrigerant flash drum chiller.

Patent History
Publication number: 20140174122
Type: Application
Filed: Oct 31, 2013
Publication Date: Jun 26, 2014
Inventors: Gary Cooper (Humble, TX), Donnie W. Vondra (Friendswood, TX), Jimmy D. Vondra (Crystal Beach, TX)
Application Number: 14/068,659
Classifications
Current U.S. Class: Natural Gas (62/618)
International Classification: F25J 3/06 (20060101);