Processing and transport of stranded gas to conserve resources and reduce emissions

Abstract

A method of gas production from a field containing natural gas processing particularly for transport of stranded gas to conserve resources and reduce emissions includes extracting gas a gas supply from a plurality of individual gas wells in the field and initially at the individual gas wells providing a recovery unit having a production capacity matching that of the well for carrying out liquid recovery from the gas supply and compression of the natural gas. When a production rate of the well declines to a low level, typically to about 20% of the original, the recovery unit is removed for redeployment either at a central plant or at other wells which are still at the high production and is substituted by a dehydration system and gas compressor arranged to fill portable pressure vessels typically on trucks for transporting the compressed natural gas to a main pipe line.

Claims

1. A method of gas production from a field containing natural gas comprising: extracting gas supply from a plurality of individual gas wells in the field; in an initial process at the individual gas wells, providing a recovery unit having a production capacity arranged to approximate that of the well for carrying out liquid recovery from the gas supply and compression of natural gas from the gas supply; and transporting the compressed natural gas produced in the initial process to a point of delivery; and in a subsequent process, when a production rate of the well declines to a level which no longer approximates to that of the recovery unit: removing the recovery unit for redeployment; substituting the recovery unit by a dehydration system and gas compressors having a lower production capacity; and transporting the compressed natural gas produced in the subsequent process to said point of delivery.

2. The method according to claim 1 wherein the compressed natural gas is transported at least in part using portable pressure vessels.

3. The method according to claim 2 wherein the gas from each gas well in the subsequent process is compressed, dehydrated and transported from the well by said portable pressure vessels to the point of delivery.

4. The method according to claim 2 wherein the portable pressure vessels are formed of fiber reinforced polymer.

5. The method according to claim 2 wherein a flow rate of the compressed natural gas supplied to the portable pressure vessels is continuous and at a steady rate.

6. The method according to claim 2 wherein the compressed natural gas supplied to the portable pressure vessels is dehydrated to a few PPM of water.

7. The method according to claim 6 wherein the compressed natural gas is dehydrated using a desiccant process using silica-gel or molecular sieve.

8. The method according to claim 2 wherein said transportation of compressed natural gas by the portable pressure vessels is continuous and related to the supply rate so as to avoid requirement on site for stationary high pressure gas storage.

9. The method according to claim 2 wherein the compressed natural gas is processed prior to transportation in said portable pressure vessels to remove small quantities of H.sub.2S.

10. The method according to claim 2 wherein the compressed natural gas is processed prior to transportation in said portable pressure vessels to cool the gas.

11. The method according to claim 2 wherein the compressed natural gas is fed into said portable pressure vessels and distributed by an internal sparger running a full length of the vessel.

12. The method according to claim 11 wherein the sparger lays along a bottom of the vessel.

13. The method according to claim 1 wherein the compressed natural gas is transported using short pipelines to a central processing plant.

14. The method according to claim 1 wherein the initial recovery unit is redeployed to a different well with higher production rate.

15. The method according to claim 1 wherein in the initial process there is provided a liquid recovery unit and compressor at each well.

16. The method according to claim 15 wherein in the initial process the liquid recovery unit is arranged to process the raw gas into potentially commercial products right at the well using simple, small scale processing equipment.

17. The method according to claim 15 wherein in the initial process the liquid recovery unit and compressor are packaged into compact skid mounted units that are easily transportable by truck.

18. The method according to claim 1 wherein in the subsequent process the gas from a plurality of wells is transported to a central plant via pipelines and gas from the central plant is transported to the point of delivery.

19. The method according to claim 18 wherein the initial recovery unit is redeployed to the central plant for separating liquids therefrom.

20. The method according to claim 18 wherein the maximum number of gas wells feeding said central plant is about 10.

21. The method according to claim 19 wherein the initial recovery unit when redeployed to the central plant operates at the central plant in parallel with recovery units at other wells.

22. The method according to claim 18 wherein in the subsequent process the gas is transported from the plurality of wells to the central plant by pipe and the gas from the central plant is transported by said portable pressure vessels.

23. The method according to claim 18 wherein a distance between each of the plurality of wells and the point of delivery is below 100 miles.

24. The method according to claim 1 wherein flaring is reduced by liquid recovery at said recovery unit.

25. The method according to claim 1 wherein said point of delivery comprises a main gas pipeline.

26. The method according to claim 1 wherein in the initial process liquefied petroleum gas and stabilized condensates separated by the recovery unit are recombined with liquids from an oil battery or an upstream oil production separator.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a schematic layout of a first arrangement according to the present invention for reduction of flare gas by recovering propane plus.

(2) FIG. 1b is a schematic layout of the arrangement of FIG. 1 at a high-level.

(3) FIG. 2 is a schematic layout of a second arrangement according to the present invention for total recovery of CNG and liquid from flare gas.

(4) FIG. 2b is a schematic layout of the arrangement of FIG. 2 at a high-level.

(5) FIG. 3 is a schematic layout of a third arrangement according to the present invention for reduction of flare gas by recovering ethane and heavier components.

(6) FIG. 4 is a schematic layout of a fourth arrangement according to the present invention for total recovery of CNG and liquid from flare gas.

(7) FIG. 5 is a schematic layout of a fifth arrangement according to the present invention for total recovery of CNG and liquid from flare gas with rich feed gas.

(8) FIG. 6 is a schematic layout of a sixth arrangement according to the present invention for multiple low flow wells feeding into a central plant.

(9) FIGS. 7, 8, 9 and 10 show plan views of four typical developments of gas fields.

(10) FIGS. 11A, 11B, 11C and 11D show four arrangements for cooling CNG before it enters the tanks, where FIG. 11A shows Joule Thomson cooling from interstage, FIG. 11B shows Joule Thomson cooling from discharge, FIG. 11C shows cooling CNG by external coolant and FIG. 11D shows cooling of the recycle stream.

(11) FIG. 12 is a graph showing the gas temperature profile related to the percentage filling of a tank capacity.

DETAILED DESCRIPTION

(12) FIG. 1 shows reduction of flare gas by recovering propane plus and illustrates a typical facility where the quantity of flare gas is decreased by stripping the gas of liquefied components such as LPG and stabilized condensate. Recovery of liquids typically reduces flaring by as much as 20% depending on the composition of the flare gas. FIG. 1 is a process scheme based on the Clausius Clapeyron Expansion Principle to recover propane and heavier hydrocarbon components. The advantage of this process over conventional turbo expander processes is its extreme flexibility, especially its wide operating range in handling varying flow rates. The LPG produced meets commercial standards for marketing and the stabilized condensate meets commercial standards for Reid vapor pressure. Details of the process may vary somewhat depending on operating conditions, the composition of the gas and the required specifications for the products.

(13) In FIG. 1, items 100 and 101, which are both upstream of the proposed patented process scheme, represent typical production equipment in the field such as a valve 100, to control pressure and flow of the wellstream, and separation equipment 101, which divides the incoming stream into its three respective phases of gas, hydrocarbon liquid, and water. For gas wells, this equipment would primarily be gravitational separators and for oil wells, the equipment is a combination of gravitational separators and oilfield treaters. For gas wells, if liquids from the separation equipment were sufficient to justify production in spite of a lack of market for the gas, then the byproduct gas would conventionally be sent to flare stack 102, likewise for oil batteries. The non-marketable gas is sent to flare.

(14) By the use of this invention, instead of sending what is considered to be waste gas to flare, it is diverted to a compressor 103 and a gas discharge cooler 101, which raises the pressure to approximately 500 PSIA at 120 F. The gas then flows to a desiccant dehydrator 106A/B/C, which may be either two tower or three tower units, depending on conditions, and it may also sometimes remove a small quantity of hydrocarbon liquid in addition to water. For regeneration, either dry product gas or wet inlet gas can be used to regenerate the beds of desiccant. Regeneration gas is typically heated in a salt bath heater 107 and cooled in an air cooled heat exchanger 108 which condenses water and possibly some hydrocarbon liquid which is removed from the regeneration stream in separator 109. The gas from the separator 109 then recombines with inlet gas entering the desiccant towers.

(15) Downstream of the dehydrator the dry gas is divided into two streams, one of which is cooled in a gas/gas exchanger 110, then proceeds to a propane refrigerated chiller 118, then to an expansion valve 119, then enters the gas fractionator 120 below the bottom stage. The other dry gas stream flows to a compressor 111 and a discharge cooler 112 which raises the pressure to approximately 1500 PSIA at 120 F. The gas is then cooled in Gas/Gas exchangers 113 and 115 and in propane refrigerated chiller 114. Propane is the refrigerant normally used in gas processes but other commercial refrigerants could also be used. The chilled gas then enters the expansion valve 116 which lowers the pressure to approximately 450 psia, resulting in an extremely cold feed stream entering the gas fractionator 120 at the top stage of the column. In the FIG. 1 version of the process there is no market for the gas, so the residue gas from the gas fractionator is sent to flare 102 after the liquids have been stripped out.

(16) The bottom liquid product from the gas fractionator 120 contains the propane and heavier components which are to be recovered, but the liquids are heavily loaded with light gases, mainly methane and ethane which should be separated from the liquid product. Most of these light gases can be flashed off in the deethanizer's feed flash drum 121 without losing a significant amount of recoverable liquid. The overhead vapor from the flash drum is sent to flare stack 102.

(17) Bottom liquid from the flash drum 121 is reduced in pressure by a let-down valve which produces a very cold feed stream which enters on the top stage of the deethanizer 126. The deethanizer is typically a top feed fractionator without a reflux condenser but with a bottom reboiler 127 which produces the necessary temperature profile in the column. Normally the specification imposed on the bottom product from the deethanizer is that the molar C.sub.2/C.sub.3 ratio should not exceed 2%. The light gases, mainly methane and ethane that are stripped from the liquid in the deethanizer are sent to the flare 102. Losses overhead of valuable liquids in the deethanizer overhead vapor are not significant.

(18) The bottom liquid that flows from the deethanizer contains the liquid product that can be recovered from the flare gas. The purpose of the debutanizer 128 is to separate the incoming mixture into the final products, normally Liquefied Petroleum Gas (LPG), a mixture of volatile hydrocarbons consisting of mainly propane and butane, and stabilized condensate, consisting mainly of pentanes and heavier. The debutanizer feed enters at about mid stage of the column, and the feed stream is often boosted in pressure with a pump so that the reflux condenser can use ambient air as coolant. The debutanizer has an air cooled reflux condenser 129 and a bottom reboiler 130.

(19) The LPG is a pressurized product so should be stored under pressure. It may be stored on site in a stationary tank to be offloaded into a propane truck, or it could be loaded directly into a trailer stationed at the site to be picked up and delivered to market as required. The commercial specification that normally applies to the LPG is that the C.sub.2/C.sub.3 ratio should not exceed 2%. This ratio is determined in the deethanizer.

(20) The bottom product is stabilized condensate which normally is produced with a Reid Vapor Pressure specification not exceeding 12 psia. From a single source such as a small well the quantity of stabilized condensate can be relatively small. The most convenient way to handle it is to recycle it back to the inlet separation facility 101 and combine it with the liquid hydrocarbon leaving the inlet separator. Alternatively, the stabilized condensate could be cooled by tube and shell or by air cooled heat exchanger, and then stored on site in a small atmospheric tank. The condensate has been de-gassed so has very low vapor pressure to enable storage by atmospheric pressure. It could be trucked to market when the on-site tank was full.

(21) The process equipment in FIG. 1 is self contained and provides a complete processing facility when installed on an individual gas well or oil battery.

(22) FIG. 1b is a simplified block diagram of FIG. 1 showing a typical facility where the quantity of flare gas is decreased by stripping the gas of liquefied components such as LPG and stabilized condensate.

(23) In FIG. 2 is shown an arrangement for the total recovery of CNG and liquid from flare gas. The details of the upstream production facilities, compressors, dehydrators, and liquid recovery packages described in FIG. 1 apply also to FIG. 2. The only difference is that instead of sending residue gas to flare it is compressed, cooled and loaded directly into special CNG tanker trucks to be transported as commercial product to market.

(24) The combined overhead vapors from the gas fractionator, the feed flash drum, and deethanizers, after transferring cold energy back into the deep cut process, are compressed in two stages to a final pressure of approximately 3415 psia. This choice of the final pressure depends on the design of the tanks on the trucks. The inter-stage discharge has a back pressure valve 135 to hold a constant back pressure on the first stage compressor 131 downstream of the air cooled exchanger 132 during the initial stages of filling when tank pressure is below inter-stage pressure. This is to provide Joule Thomson cooling of the gas through valve 135 as it flows into the tank 137 from the time when the tank is empty until the tank pressure equals inter-stage pressure. Cooling the gas during the early stages of filling can prevent the final temperature in the tank from rising too high. When tank pressure reaches inter-stage pressure the gas flow is diverted from the back pressure valve 135 to the Stage 2 compressor 133 and its discharge cooler 134 which then starts up and continues to fill the tank until fully charged. The CNG is metered 136 at the loading station.

(25) As the tanks near their loaded capacity a second truck arrives which is empty. It is connected up in readiness to receive its cargo of CNG when the first truck is fully loaded. Flow of gas during loading is continuous without interruption. The loaded truck departs and carries its cargo to the destination where it is unloaded under controlled conditions into the users system.

(26) FIG. 2b is a simplified block diagram of FIG. 2 showing a typical facility where the flare gas is eliminated by stripping the gas of liquefied components such as LPG and stabilized condensate and the residual gas is compressed, cooled and loaded directly into special CNG tanker trucks to be transported as commercial product to market.

(27) FIG. 3 shows a reduction of flare gas by recovering ethane and heavier components and is generally similar in principle to the process described in FIG. 1. Like FIG. 1, the FIG. 3 process scheme is intended to be installed at individual well sites or oil batteries and it includes compression, dehydration, and recovery of commercial products, but the difference is that the FIG. 3 process also recovers ethane in addition to LPG and stabilized condensate. Ethane is a volatile component and at normal ambient temperatures it is probably a gas having a vapor pressure approaching 1000 psia. Therefore the usual way to ship ethane is as a gas in a pipeline, or it could be compressed and shipped by truck, the same as CNG. Or, if it could be chilled to 0 F. or less it could be shipped as a liquid at about 250 psia, provided that it could be continuously cooled. FIG. 3 recovers ethane as a gas but does not show how it is shipped to market.

(28) The production facilities 100 and 101 upstream of the process in FIG. 3 are identical to the corresponding items 100 and 101 in FIG. 1. The compressors and the dehydrator in FIG. 3 are also identical to those in FIG. 1. The differences are all in the deep cut liquid recovery process.

(29) The first difference occurs when the dry gas is split into two streams. The first stream is cooled by a gas/gas exchanger 110 then flows to a flash drum 117, the overhead vapors from which flow to chiller 118 and valve 119 and enter the gas fractionator 120 as a bottom feed. FIG. 1 had no flash drum. The second dry gas stream flows to compressor 111, cooler 112, exchangers 113 and 115, chiller 114, then through expansion valve 116 to produce an extremely cold stream that enters the gas fractionator 120 as the top feed, the same as in FIG. 1.

(30) Although there are physical similarities to FIG. 1, the process to recover ethane in general requires lower temperatures in the gas fractionator than are required to recover propane and heavier as in FIG. 1. As before, the residue gas from the gas fractionator is sent to flare. The bottom liquid from the gas fractionator is sent to the second fractionator in the line, the demethanizer (122).

(31) For the recovery of ethane the process requires an additional fractionating column, the demethanizer, 122 to remove light gases, principally methane from the liquid mixture. The bottom product from the gas fractionator 120 is reduced in pressure by a level control valve and then enters the demethanizer 122 at a very low temperature as top feed. Liquids from the flash tank 117 also enter the demethanizer at about the midpoint of the column as a second feed. Because the demethanizer 122 has a very cold top feed a reflux condenser is not required. A bottom reboiler 123 provides heat for the necessary temperature profile in the column. The overhead vapor from the demethanizer has no market so is sent to flare. The specification imposed on the bottom product from the demethanizer is typically a molar ratio of C.sub.1/C.sub.2 not exceeding 2%. This is to enable a relatively pure ethane stream to be produced in the following fractionator. The bottom liquid leaving the demethanizer contains all the commercial products to be recovered by the process. Subsequent fractionation just divides the liquid into the desired products.

(32) The bottom liquid exiting the demethanizer 122 flows downstream and enters the deethanizer 124 as feed at approximately the mid-point of the column. The purpose of this deethanizer is to separate the product, ethane gas, as overhead from the propane and heavier components in the feed. Since methane and light gases have already been removed, and since a relatively high reflux ratio is used in the deethanizer 124, a relatively pure ethane product can be produced. The deethanizer has a refrigerated reflux condenser 125 and a bottom reboiler 126. The bottom product from the deethanizer is a liquid mixture of propane and heavier, which, as in FIG. 1, flows to the debutanizer.

(33) The bottom product that flows from the deethanizer 124 contains LPG and stabilized condensate as a liquid mixture and it is the function of the debutanizer 128 to separate the mixture into the desired commercial products. The operation and function of the debutanizer is exactly as described previously for FIG. 1.

(34) FIG. 4 shows the total recovery of CNG and liquid from flare gas and the details of the upstream production facilities, compressors, dehydrators and liquid recovery packages described in FIG. 3 apply also to FIG. 4. The only difference is that instead of sending residue gas to flare it is compressed, cooled, and loaded directly into special CNG tanker trucks to be transported as commercial product to market.

(35) The deep cut process detailed in FIG. 4 recovers ethane in addition to LPG and stabilized condensate. Ethane leaves the process in the form of a gas at a pressure probably below 200 psia. There are various ways to deliver the ethane to market.

(36) a) It could be compressed and delivered by truck using methods similar to the CNG technology

(37) b) It could be transported as a liquid at about 250 psia in a truck refrigerated to below 0 F.

(38) c) If an ethane pipeline was in the area, ethane could be shipped by pipeline. Details of the delivery method for ethane have not been detailed in FIG. 4.

(39) The combined overhead vapors from the gas fractionator and the demethanizer after transferring cold energy back into the deep cut process, are compressed in two stages to a final pressure of approximately 3415 psia. The choice of final pressure depends on the design of the tanks on the trucks. The inter-stage discharge has a back pressure valve 135 to hold a constant back pressure on the first stage compressor 131 down-stream of the air cooled exchanger (132) during the initial stages of filling when tank pressure is below inter-stage pressure. This is to provide Joule Thomson cooling of the gas through valve 135 as it flows into tank 137 from the time when the tank is empty until the tank pressure equals inter-stage pressure. Cooling the gas during the early stages of filling can prevent the final temperature in the tank from rising too high. When tank pressure reaches inter-stage pressure the gas flow is diverted from the back pressure valve 135 to the stage 2 compressor 133 and its discharge cooler 134 which then starts up and continues to fill the tank until fully charged. The CNG is metered at the loading station in meter 136.

(40) As the tanks near their loaded capacity a second truck arrives at the loading station which is empty. It is connected up in readiness to receive its cargo of CNG when the first truck is fully loaded. Flow of gas during loading is continuous without interruption. As flow is transferred from one truck to the other, the loaded truck departs and carries its cargo to the destination where it is unloaded under controlled conditions into the users system.

(41) FIG. 5 shows total recovery of CNG and liquid from flare gas with rich feed gas where the same references are used as in FIGS. 1, 2, 3 and 4. 101 is the three-phase inlet separator as before, but in this case is integral part with the liquid recovery system. Item 138 is the liquid stabilizer which fractionates the hydrocarbon liquid from the inlet separator.

(42) Feed gas that typically enters the deep cut plant is single phase gas which contains no appreciable amount of hydrocarbon liquid because either the gas is lean and is inherently free of liquid as it exits the well or possibly because the free liquid has already been removed by separation equipment upstream of the deep cut facility.

(43) However in some cases the gas, as it leaves the well, contains significant quantities of free liquid, and if there are no separation facilities upstream, it is necessary to provide additional equipment to handle the free liquids entering the system from the inlet stream. The complicating factor in processing these inlet hydrocarbon liquids is that they can be water saturated and in addition to dissolved water, can typically contain 1,000 to 5,000 ppm of entrained water droplets in a very fine dispersion.

(44) It is difficult to remove water from liquid hydrocarbons to the level necessary to permit processing the liquids at cryogenic temperature. The processing of these liquids should therefore be done at temperatures safely above hydrate of freezing temperatures. It is first necessary to use gravitational separation to separate the inlet stream into its respective three phases of gas, hydrocarbon liquid and free water. The gas proceeds from the inlet separator to compression and dehydration as prescribed previously and the free water is sent to disposal. The water wet hydrocarbon liquid from the inlet separator are then fractioned to produce an overhead product consisting of light gases which are recycled back to the inlet separator. The bottom liquid product should meet the necessary specifications determine the design of the fractionator. The liquid specification is sometime 12 psia Reid vapor pressure, or if the liquid is to be processed for ethane recovery the liquid specification is typically a methane/ethane ration of 1%. If the liquid is being processed to recover propane and heavier, the bottom product is typically an ethane/propane ration not exceeding 2%. The fractionation process normally drives almost all of the water overhead, either as water vapor or as liquid from a water draw off tray. But the bottom liquid can still contain traces of water so should not enter this cryogenic plant unless it is first dehydrated.

(45) If the plant is designed to recover propane and heavier, the stabilizer strips the liquid of ethane and other light gases, so the slightly wet liquid can be sent as feed to the debutanizer without causing excessive ethane content in the LPG. The minor amount of water in the feed is not a problem in this debutanizer because it runs hot. Also, the amount of water is so small it does not exceed allowable limits in the products.

(46) FIG. 6 shows an arrangement for Multiple Low Flow Wells Feeding Into a Central Plant where the most likely application for this patented technology is for relatively small gas wells which suffer a severe reduction in gas production within a fairly short time after startup. Initially that gas flow rate may typically be about 2.5 MMscfd, declining gradually by about 80% to a stable, long term flow rate of about 0.5 MMscfd.

(47) FIGS. 1, 2, 3, and 4 show various process configuration to handle the brief period of maximum flow following initial startup for each individual well. The processes described in those figures are of self contained equipment packages which intake raw, unprocessed, water saturated gas and produce marketable commercial products. These equipment packages are basically intended to be temporarily installed at a well site to process the gas from a single well for the duration of the high flow phase of the operation.

(48) When gas production falls to its minimum stable flow rate, the initial high capacity process package is too big to efficiently process the very low gas flow, so the initial process package, being portable, is disconnected from the well and moved to a new well site which has a higher flow rate. The initial big unit can be replaced at this low flow well by a much smaller package consisting of a miniature compressor/dehydrator combination. Deep cut liquid recovery equipment encounters many difficulties when operating at extremely low flow rates, so the liquid recovery system is relocated to a central processing plant which handles the gas from a cluster of several miniature compressor/dehydrator packages located at the low flow well sites.

(49) FIG. 6 shows a typical development where the self contained high capacity units have been replaced by seven of the miniature compressor/dehydrator combinations, each of which sends gas by pipeline to the central gas plant, from the seven well sites. The particular example shown in FIG. 6 recovers CNG, LPG and stabilized condensate in a deep cut facility at the central station. Each of these products is shipped to market by truck. For CNG, the gas is loaded directly into tanker trailers on a continuous basis. CNG trailers are available on site continuously as required so that flow is not interrupted. For LPG, FIG. 6 shows a stationary pressurized LPG tank on site which is pumped periodically into a propane tanker truck when the stationary tank on site is full. Alternatively, a propane trailer can be stationed on site at the central plant which takes the place of the stationary tank, provided that a trailer is on site continuously. When one propane tanker is full a second one is on site, already connected and ready to take on its cargo of LPG. For stabilized condensate, the anticipated production is probably very small, so a small atmospheric storage tank on site at the central plant is sufficient, to be pumped out on a weekly or bi weekly basis and trucked to market. All products leaving the central plant are metered before loading.

(50) Equipment numbers applicable to FIG. 6 are the same as corresponding items of equipment in FIG. 2.

(51) As an alternative to desiccant dehydration at the well-site, it may be practical to use glycol dehydration and use desiccant dehydration at the central plant.

(52) FIGS. 7, 8, 9, 10 show an arrangement for typical development of gas field where the four figures illustrate a typical case of the various stages in the development of a small gas field having a total of thirty marginal gas wells. FIG. 7 shows ten wells tied in, FIG. 8 shows twenty wells tied in, FIG. 9 shows all thirty wells tied in and in production but with the final four wells still in their initial high production phase. FIG. 10 shows the field fully developed with all thirty wells configured for long term low volume production. The three stage development in this particular example had ten wells per stage and three central plants serving ten wells each when the plan was complete.

(53) The characteristics of this reservoir in the example are typical of many tight gas reservoirs, especially shale gas reservoirs, which have an initial flow which can be five times as much as their long term steady flow rate. Usually the deliverability tends to fall quite rapidly following the high production rate following startup. High flow for this type of well might be approximately 2.5 MMscfd which would decline over time to a stable flow of about 0.5 MMscfd which would then continue almost indefinitely. The figures in this example suggest a development plan for this type of field.

(54) The development scheme for this field is to take advantage of the brief period of maximum production by installing portable self contained processing facilities which can handle the high flow period which on an individual well basis is complete and can produce CNG, LNG stabilized condensate, and possibly in some cases, ethane. This scheme enables the field to get into production quickly based on very few wells tied in and using miniature processing equipment to begin generating revenue right away from the sale of gas and liquids. The high flow facility at each well site is complete and self contained requiring only utilities from the power grid if available.

(55) The scheme for this particular example calls for using four high capacity portable processing packages which are installed either one at a time or all four simultaneously in a tight cluster that can enable a planned expansion of a gathering system when the high capacity units are moved onto new wells to be replaced by low capacity compressor/dehydrator packages. The four high capacity units, each processing 2.5 MMscfd for a total of 10 MMscfd are moved step by step until all ten wells of the first ten well clusters are in production, four at high capacity and six at low capacity producing 0.5 MMSCFD each for an overall production of 13 MMscfd. As each set of four high volume units run down to 0.5 MMscfd, the portable high capacity units are moved on to new high volume wells to be replaced by miniature compressor/dehydrator combinations designed for 0.5 MMscfd each. Meanwhile, this central plant which uses a deep cut cryogenic process to produce CNG, LNG and Stabilized Condensate should be ready to accept the dry field gas from the low volume compressor/dehydrator units as soon as they are installed. Dry gas arrives at the central plant at about 500 psia.

(56) Development proceeds in this way until the first cluster of ten wells is in production. FIG. 7 illustrates this, showing four high capacity wells and six low capacity wells which at this point are sending 3 MMscfd to the central plant which is designed for an ultimate capacity of 5 MMscfd when all ten wells are tied in to the plant. The four high capacity self contained units in FIG. 7 are processing 10 MMscfd in total and sending commercial products directly to market by truck. The central plant likewise sends commercial products to market by truck.

(57) Among the things to consider in preparing a development plan is the location of the central plant among the cluster of wells. It should be placed so that the cost of the gathering system is minimized. The design and location of well stream metering equipment should also be considered if it is within the scope of the project. Reservoir engineers can recommend the sequence of developing new wells. For diagrammatic simplicity FIGS. 7 to 10 show development proceeding in an orderly way from south to north. Reservoir science, taking account of the delicate and sometimes temperamental nature of tight reservoirs may dictate otherwise.

(58) FIG. 8 shows the first cluster of ten wells fully developed and tied in to the central plant. All ten wells of the second cluster are in production with four wells in high production mode and six wells in low production and tied in to control plant #2. As in FIG. 7, CNG, LNG, and stabilized condensate are delivered to market by truck. The example shows the CNG being unloaded into a pipeline; this probably requires a compressor to empty the truck. Delivery of CNG for industrial or domestic users may not require a compressor.

(59) FIG. 9, like FIG. 8 shows the next stage of development with all thirty wells in production with the final four wells still in their high volume mode. Six wells are tied into the gathering system and are producing into central plant #3.

(60) FIG. 10 shows the field fully developed with all 30 wells producing at 0.5 MMscfd each and tied in to their respective central plants.

(61) This example illustrates the development of only one hypothetical field. The general principles are applicable to many fields but each case is different and the development plan should be specific to each situation.

(62) FIGS. 11A to 11D show a number of arrangements for cooling CNG before it enters the tanks, assuming the truck tanks are considered empty at 165 psia and full at 3415 psia. Compression of gas into the tanks begins at 165 psia and ends at 3415 psia. As the tanks are filled, the gas already in the tanks increases in pressure and becomes warmer due to heat of compression. If the discharge cooler of the compressor cools the gas to 120 F. and if no further cooling occurs except convective cooling from the cool walls of the tank, the final average temperature in the tanks can be approximately 160 F. It is desirable to cool the gas further to increase the payload carried in the tanks. For example, if the temperature could be lowered by 30 F. the weight of gas carried in the tanks would increase by approximately 8%. Another issue to consider if composite materials are used in the tanks, excessive temperature can degrade the non metallic components in the tank, increasing possible risk of failure. As compression proceeds the gas initially in the tank is pushed to the far end of the tank and because this initial gas experiences the greatest change in pressure it also experiences the greatest increase in temperature. The far end of the tank becomes very hot while the inlet end remains cool. To prevent this misdistribution of temperature the inlet nozzle is connected to an inlet sparger that runs the full length of the tank to evenly distribute the gas as it enters the tank. This can produce an even, average, temperature rise for the full length of the tank, rather than one hot end and one cool end. The sparger runs along the bottom of the shell of the tank to act as a pickup duct for any liquid that may condense in the tank.

(63) FIG. 11A shows an arrangement for Joule Thomson cooling from interstage where maintaining a back pressure on the interstage gas and choking it directly into the trucks' tanks produces a maximum temperature drop of about 50 to 60 F. for the gas initially flowing into the empty tank. This cooling effect can continue until the tank pressure equals interstage pressure. At that time the back pressure valve 135 is by passed and compressor 133 and cooler 134 start up and gas flowing into the tank can be constant at approximately 120 F. This system adds to horsepower hours to produce cooling.

(64) FIG. 11B shows an arrangement for Joule Thomson cooling from discharge which uses Joule Thomson for cooling by maintaining a back pressure on the discharge gas entering the tank. The advantage of this system is that the back pressure setting is variable between interstage pressure and final pressure. As before, when tank pressure equals the back pressure, the choke is bypassed. Joule Thomson cooling adds to horse power hours to produce cooling.

(65) FIG. 11C shows an arrangement for cooling CNG by external coolant where the discharge air cooler lowers the gas temperature to approximately 120 F., depending on ambient temperature. If an alternate coolant such as cooling water is available for exchanger (138) it possibly lowers the temperature by a further 40 F. Or, if refrigeration is used it lowers the inlet temperature sufficiently that that the final average temperature in the tanks can be about 120 F. The advantage of an external cooling is that it is constant throughout the filling cycle. Excessive cooling should be avoided however to avoid extreme cryogenic temperatures when the tanks are unloaded.

(66) FIG. 11D shows an arrangement for cooling of recycle stream where instead of precooling the gas before it enters the tank so that when it undergoes compression inside the tank it is not too hot, an alternate approach is to recycle the gas in the tanks after it has become heated due to compression through a cooler 139 to remove the heat of compression directly. An external coolant such as ambient air or cooling water can be used. This cooled recycle gas is combined with inlet gas entering the tanks. A means to circulate the recycle gas should be used. Because pressure losses in the recycle circuit are very low, an educator (140) can be used to provide the motive power as shown in FIG. 11D. Recycle gas flow through the eductor should be positively controlled to avoid adding excessive loads to the compressor (133). Alternately a blower or compressor could be used in the circuit to recycle the cooled gas.

(67) FIG. 12 shows the temperature profile during the filling phase of a tank: the choking effect of the back pressure valve on the final-stage compressor produces cooling. The cooling at the beginning of the fill cycle is sufficient to reduce the final average gas temperature to a desired level.