Patent Grant
11280451
The embodiments described herein relate to the process and method for storage and transportation and delivery of natural gas under conditions of pressure and temperature utilizing the added presence of liquid form of light-hydrocarbon solvents to facilitate greater density levels for the natural gas component of the mixture.
Natural gas is primarily moved by pipelines on land. Where it is impractical or prohibitively expensive to move the product by pipeline, LNG shipping systems have provided a solution above a certain threshold of reserve size. With the increasingly expensive implementation of LNG systems being answered by economies of scale of larger and larger facilities, the industry has moved away from a capability to service the smaller and most abundant reserves. Many of these reserves are remotely located and have not been economical to exploit using LNG systems.
Recent work by the industry seeks to improve delivery capabilities by introducing floating LNG liquefaction plants and storage at the gas field and installing on board re-gasification equipment on LNG carriers for offloading gas offshore to nearby market locations that have opposed land based LNG receiving and processing terminals. To further reduce energy consumption by simplification of process needs, the use of pressurized LNG (PLNG) is once again under review by the industry for improvement of economics in an era of steeply rising costs for the LNG industry as a whole. See, e.g., U.S. Pat. Nos. 3,298,805; 6,460,721; 6,560,988, 6,751,985; 6,877,454; 7,147,124; 7,360,367.
The demanding economics of fringe area development of reserves of “stranded gas” worldwide dictate improvements of service beyond those offered by floating LNG and pressurized LNG technologies for full exploitation of this energy source.
The advent of Compressed Natural Gas (CNG) transportation systems, to cater to the needs of a world market of increasing demand, has led to many proposals in the past decade. However, during this same time period there has only been one small system placed into full commercial service on a meaningful scale. CNG systems inherently battle design codes that regulate wall thicknesses of their containment systems with respect to operating pressures. The higher the pressure, the better the density of the stored gas with diminishing returns—however, the limitations of “mass of gas-to-mass of containment material” have forced the industry to look in other directions for economic improvements on the capital tied up in CNG containment and process equipment. See, e.g., U.S. Pat. Nos. 5,803,005; 5,839,383; 6,003,460; 6,449,961, 6,655,155; 6,725,671; 6,994,104; 7,257,952.
One solution outlined in U.S. Pat. No. 7,607,310, which is incorporated herein by reference, provides a methodology to both create and store a liquid phase mix of natural gas and light-hydrocarbon solvent under preferred temperature conditions of below −40° to about −80° F. and preferred pressure conditions of about 1200 psig to about 2150 psig. The liquid phase mix of natural gas and light-hydrocarbon solvent is referred to hereafter as Compressed Gas Liquid (CGL) product or mixture. Although the CGL technology enables improved cargo density with the combination of lower process energy for a liquid state storage not attainable by LNG, PLNG and CNG systems and processes, the demanding economics of fringe area development of reserves dictate the need to increase cargo density, reduce process energy, and reduce containment vessel mass.
Accordingly, it is desirable to provide systems and methods that facilitate economic development of remote or stranded reserves to be realized by a means not afforded by LNG, PLNG or CNG systems and utilize CGL systems and process for natural gas storage to realize increased cargo density, reduction of process energy, and reduction in containment vessel mass inherent.
Embodiments provided herein are directed to systems and methods to both create and store a denser liquid phase mix of natural gas and light-hydrocarbon solvent under temperature and pressure conditions that facilitate improved volumetric ratios of the stored gas within containment systems of lighter construction. In a preferred embodiment, improved density of storage of natural gas, as compared to compressed natural gas (CNG) and pressurized liquid natural gas (PLNG) at the same temperature and pressure conditions, is enabled using hydrocarbon solvents such as light-hydrocarbon based solvents including ethane, propane and butane, a natural gas liquid (NGL) based solvent or a liquid petroleum gas (LPG) based solvent under overall temperature conditions from less than −80° F. to about −120° F. with overall pressure conditions ranging from about 300 psig to about 1800 psig, and under enhanced pressure conditions ranging from about 300 psig to less than 900 psig, or, more preferably, under enhanced pressure conditions ranging from about 500 psig to less than 900 psig.
The embodiments described herein are also directed to a scalable means of receiving raw production (including NGLs) or semi-conditioned natural gas, conditioning the gas, producing a compressed gas liquid (CGL) product comprising a liquid phase mix of the natural gas and the light-hydrocarbon solvent, and transporting the CGL product to a market where pipeline quality gas or fractionated products are delivered in a manner utilizing less energy than either CNG or LNG systems and giving a better ratio of cargo-mass to containment-mass for the natural gas component in the shipment than that offered by CNG systems.
Other systems, methods, features and advantages of the embodiments will be or will become apparent to one with skill in the art upon examination of the following figures and detailed description.
The details of the embodiments, including fabrication, structure and operation, may be gleaned in part by study of the accompanying figures, in which like reference numerals refer to like parts. The components in the figures are not necessarily to scale, emphasis instead being placed upon illustrating the principles of the embodiments described herein. Moreover, all illustrations are intended to convey concepts, where relative sizes, shapes and other detailed attributes may be illustrated schematically rather than literally or precisely.
Embodiments provided herein are directed to systems and methods to both create and store a liquid phase mix of natural gas and light hydrocarbon solvent under temperature and pressure conditions that facilitate improved volumetric ratios of the stored gas within containment systems of light construction. In a preferred embodiment, improved density of storage of natural gas, as compared to compressed natural gas (CNG) and pressurized liquid natural gas (PLNG) at the same temperature and pressure conditions, is enabled using hydrocarbon solvents such as light hydrocarbons based solvents such as ethane, propane and butane, a natural gas liquid (NGL) based solvent or a liquid petroleum gas (LPG) based solvent under temperature conditions from less than −80° F. to about −120° F. with overall pressure conditions ranging from about 300 psig to about 1800 psig, and under enhanced pressure conditions ranging from about 300 psig to less than 900 psig, or, more preferably, under enhanced and pressure conditions ranging from about 500 psig to less than 900 psig.
This application relates to U.S. application Ser. No. 12/486,627, filed Jun. 17, 2009, and U.S. Provisional Application No. 61/392,135, filed Oct. 12, 2010, which are fully incorporated by reference.
Before turning to the manner in which the present embodiments function, a brief review of the theory of ideal gases is provided. The combination of Boyles Law, Charles' Law and the Pressure Law yields the relationship for changing conditions under which a gas is stored:
(P1*V1)/T1=(P2*V2)/T2=Constant (1)
Where P=Absolute Pressure
V=Gas Volume
T=Absolute Temperature
A value R is attributed to a fixed value, known as the Universal Gas Constant. Hence a general equation can be written as follows:
P*V=R*T (2)
This ideal gas relationship is suited to low pressures, but falls short on accuracy for real gas behavior under higher pressures experienced in the practical world.
To account for the difference in intermolecular force behavior between an ideal gas and a real gas a corrective dimensionless compressibility factor known as z is introduced. The value of z is a condition of the gas constituents and the pressure and temperature conditions of containment. Hence:
P*V=z*R*T (3)
Rewriting in the form of Molecular Mass (MW), the relationship takes the form:
P*V=z*R*T=(Z*R*T)/(MW) (4)
where a specific value of z relative to the gas constituents, temperature and pressure, now referred to as Z is introduced. This equation is then rewritten to account for gas density ρ=1/V.
Hence:
ρ=P*(MW)/(Z*R*T) (5)
This relationship is the origin for gas phase densities used in the embodiments described herein.
The Gas Processors Suppliers Association publishes an Engineering Data Book for the industry which shows the graphical relationship of Z for all light hydrocarbon mixes of molecular mass below a value of MW=40. Based on the Theorem of Corresponding States, this chart uses pseudo reduced values of the storage conditions of pressure and temperature to give the compressibility factor Z for all relevant light-hydrocarbon mixes irrespective of phase or constituent mix. The pseudo reduced values of temperature and pressure conditions are expressed as absolute values of these measured properties divided by the critical property of the subject hydrocarbon mix.
The embodiments described herein seek to accelerate the onset of a denser storage value of natural gas through the addition of light-hydrocarbon solvents. As can be seen from Equation (5), increased density is obtained where the value of Z decreases. In the selected area of operation of the embodiments described herein, the value of Z of natural gas is reduced by the introduction of a light-hydrocarbon solvent to the natural gas to create a liquid phase mixture of the solvent and natural gas referred to herein as a compressed gas liquid (CGL) mixture.
It is thus seen that all four storage technologies transition from LNG to PLNG to CGL to CNG moving from the lower left to upper right of the Z factor chart. Each is distinct in its own right, with the storage condition brought about through the application of cooling and compression. The heaviest energy loads relative to compressed state lie at the extremes of these storage conditions, in the LNG and CNG technologies. Heat of compression and required cooling for CNG and the last 50° F. of cooling (as noted by Woodall, U.S. Pat. No. 6,085,828) in the case of LNG justifies gravitating towards CGL technology in the mid field for storage conditions requiring the least energy input, which allows for more of a wellhead gas to be available for sale to the market.
Without limitation in the following quoted values, CGL technology offers the best storage compression for energy expenditure per unit of natural gas delivered. Measured against LNG at an approximate volumetric ratio (V/V) of 600:1, these alternatives require less exotic materials and processing to yield an upper V/V value for CGL of approximately 400:1 as described below.
For a given storage condition defined by a temperature and pressure coordinate, it is found that there is a specific ratio of solvent to natural gas that yields the highest net volumetric ratio for the stored natural gas within the CGL mixture at the defined storage conditions for a predetermined solvent and composition of natural gas. In order to maintain the optimum volumetric ratio (storage efficiency), a control loop is built into the loading system. At frequent intervals, the control loop monitors the fluctuating composition of the input natural gas stream and adjusts the mol percentage of added solvent to maintain an optimum storage density of the resulting CGL mixture.
Turning to
As depicted, the solvent optimizer control loop 140 includes a solvent optimizer unit or controller 142, which has a processor upon which a solvent optimizer software program runs. The solvent optimizer unit 142 is coupled to a solvent flow meter 144 disposed in the solvent injector line 137 after the solvent injection pump 138. The solvent optimizer unit 142 is also coupled to a flow control valve 146 disposed in the solvent injector line 137 after the solvent flow meter 144. The solvent optimizer control loop 140 further includes a gas chromatograph unit 148 coupled to the solvent optimizer unit 142.
In operation, the gas chromatograph unit 148 determines the composition of the incoming gas 101 received from a location prior to the metering run 132 and/or a location prior to the static mixer 103. The gas chromatograph unit 148 determines the composition of the incoming solvent 102 received from a location in the injection line 137 prior to the flow meter 144 and the composition of the outgoing warm CGL product 105 received from a location in the discharge line 135 prior to the CGL exchanger 104. The composition of the gas 101, solvent 102 and CGL product 105 is communicated by the gas chromatograph unit 148 to the solvent optimizer unit 142. The solvent optimizer unit 142 also receives the flow rate of the gas 101 from the flow sensors 143A, 143B, 143C and 143D and the flow rate of the solvent 102 from the flow meter 144. As discussed with regard to
As depicted in
As step 1150 indicates, the program continues to calculate the net volumetric ratio until it determines that increasing the solvent-to-gas ratio of the mixture does not allow for the storage of more of the gas for the storage conditions. Once the max volumetric ratio (V/V) is determined, the flow control valve is opened at step 1152 if it is not already open. At step 1154 the program determines if the actual flow rate of the solvent measured by the flow meter 144 matches the flow rate corresponding to the optimum solvent mol fraction calculated at step 1148. If the flow rates match, no action is required as indicated at step 1156. If the flow rates do not match, the flow control valve 146 is adjusted at step 1158.
An additional check is provided at steps 1160 and 1162 to insure that the proper solvent flow rate is being provided. As indicated, the composition of the warm CGL product 105 is determined at step 1160. At step 1162, the program compares the properties of a CGL product based on the calculated solvent-to-gas ratio with the properties of the warm CGL product 105. If the properties match, no action is required as indicated at step 1164. If the properties do not match, the program adjusts the flow control valve at step 1158 to produce a warm CGL product 105 with properties that match the properties of a CGL product based on the calculated solvent-to-gas ratio.
U.S. Pat. No. 7,607,310, which is incorporated herein by reference, describes a methodology to both create and store a supply of CGL product under temperature conditions of preferably ranging from less than −40° F. to about −80° F. and pressure conditions of about 1200 psig to about 2150 psig with storage densities for the natural gas component of the CGL product being greater than the storage densities of CNG for the same storage temperature and pressure.
Turning to
As the CGL product 105 flows into the containment system 106 it displaces displacement fluid 107 causing it to flow through an isolation valve 124 positioned in a line returning to a displacement fluid tank 109 and set to open. A pressure control valve 127 in this return line retains the displacement fluid 107 at sufficient back pressure to ensure the CGL product 105 is maintained in a liquid state in the containment system 106. During the loading process, an isolation valve 125 in a displacement fluid inlet line is set to closed.
Upon reaching its destination, a transportation vessel or carrier transporting the CGL product 105 unloads the CGL product 105 from the containment system through an unloading process 120 that utilizes a pump 126 to reverse the flow F of the displacement fluid 107 from the storage tank 109 through an open isolation valve 125 to containment pipe bundles 106 to push the lighter CGL product 105 into a process header towards fractionating equipment of a CGL separation process train 129. The displaced CGL product 105 is removed from the containment system 106 against the back pressure of control valve 123 in the process header through isolation valve 122 which is now set to open. The CGL product 105 is held in the liquid state until this point, and only flashes to a gaseous/liquid process feed after passing through the pressure control valve 123. During this process, isolation valves 121 and 124 remain in the closed voyage setting.
In the further interests of the limited storage space on board a marine vessel, once the CGL load is pushed out of containment, valves 122 and 125 are closed and the displacement fluid 107 is returned by a low pressure line (not shown) to the tank 109 for reuse in the filling/emptying of a successive pipe bundle (not shown). The reused fluid is again delivered via pump 126 feeding a newly opened manifold valve (not shown) in succession to the now closed valve 125 to the successive pipe bundle. Meanwhile the pipeline containment 106, now drained of displacement fluid, is purged with a nitrogen blanket gas 128 to and left in an inert state as an “empty” isolated pipe bundle.
U.S. Pat. No. 7,219,682, which illustrates one such displacement fluid method adaptable to the embodiments described herein, is incorporated herein by reference.
Irrespective of containment material, containment mass ratios achievable in a CGL system are improved upon by storing the CGL product under temperature conditions from less than −80° to about −120° F. with pressure conditions ranging from about 300 psig to about 1800 psig and under enhanced pressure conditions ranging from about 300 psig to less than 900 psig or, more preferably, under enhanced pressure conditions ranging from about 500 psig to less than 900 psig.
With reference to
To achieve the best case performance of 300 to 400 volumetric ratio range, the percentage mol amount of solvent concentration in the CGL product mix rises from about 10% mol at low temperature and low pressure conditions to higher concentrations of 16 to 21% mol at mid range conditions, and then tapers to lower concentrations in the range of 8 to 13% at the highest temperature, highest pressure conditions. On either side of this region of improved performance there is a fall off in the gain of V/V for CGL storage relative to that for CNG and PLNG storage of straight natural gas. In higher pressure, lower temperature regions the storage densities of CGL storage approaches the storage densities of PLNG storage. The further away from this effective region, the lower the percentages of solvent are dictated for CGL storage to approach the V/V values of PLNG storage. Superior values of V/V for PLNG storage of straight natural gas in this region are commercially attractive, but are subject to a more energy intensive process than is required for CGL storage in areas of interest along the effective region.
CGL storage performance similarly tapers off as one moves away from the effective region to lower pressure higher temperature storage points. Here the achieved values of V/V are measured against the performance of CNG storage. To attain the best values of V/V, the requirement for a liquid state of the CGL product demands greater mol percentages of solvent be added to the CGL product mix as conditions move away from the region—a situation not so much suited to tight maritime limits on storage space, as it is to land based service such as peak shaving systems.
The increasing levels of solvent demanded in this area for CGL to outperform CNG places the technology against a law of diminishing returns relative for the available space for natural gas molecules to fit in the CGL product mix. Eventually the value of V/V for CGL storage abruptly falls off compared to that of CNG storage. The superior, but low values of V/V for CNG storage in this region have limited commercial attraction because of the low gas cargo mass to containment mass ratio.
As depicted in
Overall it is clear from
Referring to
Referring to
Referring to
Referring to
Referring to
Other embodiments described below are directed to a total delivery system built around CGL production and containment and, more particularly, to systems and methods that utilize modularized storage and process equipment scaled and configured for floating service vessels, platforms, and transport vessels to yield a total solution to the specific needs of a supply chain, enabling rapid economic development of remote reserves to be realized by a means not afforded by liquid natural gas (LNG) or compressed natural gas (CNG) systems, in particular reserves at a land or sea location of a size deemed “stranded” or “remote” by the natural gas industry. The systems and methods described herein provide a full value chain to the reserve owner with one business model that covers the raw production gas processing, conditioning, transporting and delivering to market pipeline quality gas or fractionated products—unlike that of LNG and CNG.
Moreover, the special processes and equipment needed for CNG and LNG systems are not needed for a CGL based system. The operation specifications and construction layout of the containment system also advantageously enables the storage of straight ethane and NGL products in sectioned zones or holds of a vessel on occasions warranting mixed transport.
In accordance with a preferred embodiment, as depicted in
To contain the CGL cargo, the containment system preferably comprises a carbon steel, pipeline-specification, tubular network nested in place within a chilled environment carried on the vessel. The pipe essentially forms a continuous series of parallel serpentine loops, sectioned by valves and manifolds.
The vessel layout is typically divided into one or more insulated and covered cargo holds, containing modular racked frames, each carrying bundles of nested storage pipe that are connected end-to-end to form a single continuous pipeline. Enclosing the containment system located in the cargo hold allows the circulation of a chilled nitrogen stream or blanket to maintain the cargo at its desired storage temperature throughout the voyage. This nitrogen also provides an inert buffer zone which can be monitored for CGL product leaks from the containment system. In the event of a leak, the manifold connections are arranged such that any leaking pipe string or bundle can be sectioned, isolated and vented to emergency flare and subsequently purged with nitrogen without blowing down the complete hold.
At the delivery point or market location, the CGL product is completely unloaded from the containment system using a displacement fluid, which unlike LNG and most CNG systems does not leave a “heel” or “boot” quantity of gas behind. The unloaded CGL product is then reduced in pressure outside of the containment system in low temperature process equipment where the start of the fractionation of the natural gas constituents begins. The process of separation of the light hydrocarbon liquid is accomplished using a standard fractionation train, preferably with individual rectifier and stripper sections in consideration of marine stability.
Compact modular membrane separators can also be used in the extraction of solvent from the CGL. This separation process frees the natural gas and enables it to be conditioned to market specifications while recovering the solvent fluid.
Trim control of minor light hydrocarbon components, such as ethane, propane and butane for BTU and Wobbe Index requirements, yields a market specification natural gas mixture for direct offloading to a buoy connected with shore storage and transmission facilities.
The hydrocarbon solvent is returned to vessel storage and any excess C2, C3, C4 and C5+ components following market tuning of the natural gas can be offloaded separately as fractionated products or value added feedstock supply credited to the account of the shipper.
For ethane and NGL transportation, or partial load transportation, sectioning of the containment piping also allows a portion of the cargo space to be utilized for dedicated NGL transport or to be isolated for partial loading of containment system or ballast loading. Critical temperatures and properties of ethane, propane and butane permit liquid phase loading, storage and unloading of these products utilizing allocated CGL containment components. Vessels, barges and buoys can be readily customized with interconnected common or specific modular process equipment to meet this purpose. The availability of de-propanizer and de-butanizer modules on board vessels, or offloading facilities permits delivery with a process option if market specifications demand upgraded product.
As depicted in
The barges 14 equipped for production and storage and the barges 20 equipped for separation can conveniently be relocated to different natural gas sources and gas market destinations as determined by contract, market and field conditions. The configuration of the barges 14 and 20, having a modular assembly, can accordingly be outfitted as required to suit route, field, market or contract conditions.
In an alternative embodiment, as depicted in
As illustrated in Table 1 below, the natural gas cargo density and containment mass ratios achievable in a CGL system surpass those achievable in a CNG system. Table 1 provides comparable performance values for storage of natural gas applicable to the embodiments described herein and the CNG system typified by the work of Bishop, U.S. Pat. No. 6,655,155, for qualified gas mixes. The data is given in all cases for similar containment material of low temperature carbon steel suited for service at the temperatures shown.
The specific gravity (SG) value for the mixtures shown in Table 1 is not a restrictive value for CGL product mixtures. It is given here as a realistic comparative level to relate natural gas storage densities for CGL based systems performance to that of the best large commercial scale natural gas storage densities attained by the patented CNG technology described in Bishop.
The CNG 1 values, along with those for CGL 1 and CGL 2 are also shown as “net” values for the 0.6 SG natural gas component contained within the 0.7 SG mixtures to compare operational performances with that of a straight CNG case illustrated as CNG 2. The 0.7 SG mixes shown in Table 1 contain an equivalent propane constituent of 14.5 mol percent. The likelihood of finding this 0.7 SG mixture in nature is infrequent for the CNG 1 transport system and would therefore require that the natural gas mix be spiked with a heavier light hydrocarbon to obtain the dense phase mixture used for CNG as proposed by Bishop. The CGL process, on the other hand and without restriction, deliberately produces a product used in this illustration of 0.7 SG range for transport containment.
The cargo mass-to-containment mass ratio values shown for CGL 1, CGL 2, and CNG 2 system are all values for market specification natural gas carried by each system. For purposes of comparison of the containment mass ratio of all technologies delivering market specification natural gas component gas, the “net” component of the CNG 1 stored mixture is derived. It is clear that the CNG systems, limited to the gaseous phase and associated pressure vessel design codes, are not able to attain the cargo mass-to-containment mass ratio (natural gas to steel) performance levels that the embodiments described herein achieve using CGL product (liquid phase) to deliver market specification natural gas.
Table 2 below illustrates containment conditions of CGL product where a variation in solvent ratio to suit select storage pressures and temperatures yields an improvement of storage densities. Through the use of more moderate pressures at lower temperatures than previously discussed, and applying the applicable design codes, reduced values of wall thickness from those shown in Table 1 can be obtained. Values for the mass ratio of gas-to-steel for CGL product of over 3.5 times the values for CNG quoted earlier are thereby achievable.
The natural gas cargo density and containment mass ratios achievable in a CGL system are improved upon by storing the CGL product under temperature conditions from less than −80° to about −120° F. with pressure conditions ranging from about 300 psig to about 1800 psig, and under enhanced pressure conditions ranging from about 300 psig to less than 900 psig, and, more preferably, under enhanced pressure conditions ranging from about 500 psig to less than 900 psig.
Referring to
Line plots of M/M values are further displaced on account of code requirements for material specification changes as temperatures decrease. The containment material is preferably high strength low temperature carbon steel suited to temperature conditions down to −55° F. At lower temperatures the material specification changes to lower strength stainless or nickel steels. Given the design requirement for greater wall thickness values for lower strength materials used in pressure containment systems there is an attendant step down in the M/M value as expected for both CGL and CNG/PLNG cases examined here. How these values recover as temperatures further decrease is illustrated in these figures. A different behavior will be expected of a continuously used composite containment throughout the temperature band.
For instance, in
Referring to
Referring to
Referring to
Referring to
Turning to
As shown in
As shown in
Turning to
As noted above, the carrier vessel 300 advantageously includes modularized processing equipment including, for example, a modular gas loading and CGL production system 302 having a refrigeration heat exchanger module 304, a refrigerator compressor module 306, and vent scrubber modules 308, and a CGL fractionation offloading system 310 having a power generation module 312, a heat medium module 314, a nitrogen generation module 316, and a methanol recovery module 318. Other modules on the vessel include, for example, a metering module 320, a gas compressor module 322, gas scrubber modules 324, a fluid displacement pump module 330, a CGL circulation module 332, natural gas recovery tower modules 334, and solvent recovery tower modules 336. The vessel also preferably includes a special duty module space 326 and gas loading and offloading connections 328.
The loading barge 400 preferably includes CGL product storage modules 402 and modularized processing equipment including, for example, a gas metering module 408, a mol sieve module 410, gas compression modules 412, a gas scrubber module 414, power generation modules 418, a fuel treatment module 420, a cooling module 424, refrigeration modules 428 and 432, refrigeration heat exchanger modules 430, and vent module 434. In addition, the loading barge preferably includes a special duty module space 436, a loading boom 404 with a line 405 to receive solvent from a carrier and a line 406 to transmit CGL product to a carrier, a gas receiving line 422, and a helipad and control center 426.
The flexibility to deliver to any number of ports according to changes in market demand and the pricing of a spot market for natural gas supplies and NGLs would require that the individual vessel be configured to be self contained for offloading natural gas from its CGL cargo, and recycling the hydrocarbon solvent to onboard storage in preparation for use on the next voyage. Such a vessel now has the flexibility to deliver interchangeable gas mixtures to meet the individual market specifications of the selected ports.
At the rear of the vessel 500, deck space is provided for the modular placement of necessary process equipment in a more compact area than would be available on board a converted vessel. The modularized processing equipment includes, for example, displacement fluid pump modules 510, refrigeration condenser modules 512, a refrigeration scrubber and economizer module 514, a fuel process module 516, refrigeration compressor modules 520, nitrogen generator modules 522, a CGL product circulation module 524, a water treatment module 526, and a reverse osmosis water module 528. As shown, the containment fittings for the CGL product containment system 506 are preferably above the water line. The containment modules 508A, 508B and 508C of the containment system 506, which could include one or more modules, are positioned in the one or more containment holds 532 and enclosed in a nitrogen hood or cover 507.
Turning to
The disclosed embodiments advantageously make a larger portion of the gas produced in the field available to the market place, due to low process energy demand associated with the embodiments. Assuming all the process energy can be measured against a unit BTU content of the natural gas produced in the field, a measure to depict percentage breakout of the requirements of each of the LNG, CNG and CGL process systems can be tabulated as shown below in Table 3.
If each of the aforementioned systems starts with a High Heat Value (HHV) of 1085 BTU/ft3, the LNG process reduces HHV to 1015 BTU/ft3 for transportation through extraction of NGLs. Make-up BTU spiking and crediting the energy content of extracted NGLs is included for LNG case to level the playing field. A heat rate of 9750 BTU per kW·hr for process energy demand is used in all cases.
With credit for NGL's, the LNG process will sum up to 85% total value for Market delivery of BTUs—a quantity still less than the deliverable of the embodiments described herein. Results are typical for individual technologies. The data provided in Table 3 was sourced as follows: LNG—third party report by Zeus Energy Consulting Group 2007; CNG—Bishop U.S. Pat. No. 6,655,155; and CGL—internal study by SeaOne Maritime Corp.
Overall the disclosed embodiments provide a more practical and rapid deployment of equipment to access remote, as well as developed natural gas reserves, than has hitherto been provided by either LNG or CNG systems in all of their various configurations. Materials required are of a non exotic nature, and able to be readily supplied from standard oilfield sources and fabricated in a large number of industry yards worldwide.
Turning to
However, gas with high content condensates could be handled by providing additional separator capacity to the separator equipment 812. For natural gas mixes with undesirable levels of acid gasses such as CO2 and H2S, Chlorides, Mercury and Nitrogen the bypass valves 803, 811 and 819 at modular connection points 801, 809 and 817 can be closed as needed and the gas stream routed through selectively attached process modules 820, 822 and 824 tied in to the associated branch piping and isolation valves 805, 807, 813, 815, 821 and 823 shown at each by pass station 801, 809 and 817. For example, raw gas from the Malaysian deepwater fields of Sabah and Sarawak containing unacceptable levels of acid gas could be routed around a closed by-pass valve 803 and through open isolation valves 805 and 807 and processed in an attached module 820 where amine absorption and iron sponge systems extract the CO2, H2S, and sulfur compounds. A process system module for the removal of mercury and chlorides is best positioned downstream of dehydration unit 814. This module 822 takes the gas stream routed around a closed by-pass valve 811 through open isolation valves 813 and 815, and comprises a vitrification process, molecular sieves or activated carbon filters. For raw gas with high levels of nitrogen as found in some areas of the Gulf of Mexico, the gas stream is routed around a closed by-pass valve 819 and through open isolation valves 821 and 823, passing the natural gas stream through a selected process module 824 of suitable capacity to remove nitrogen from the gas stream. Available process types include membrane separation technology, absorptive/adsorptive tower and a cryogenic process attached to the vessel's nitrogen purge system and storage pre chilling units.
The extraction process described above can also provide a first stage to the NGL module 816, providing additional capacity required to deal with high liquids mixes such as those found in the East Qatar field.
In the foregoing specification, the invention has been described with reference to specific embodiments thereof. It will, however, be evident that various modifications and changes may be made thereto without departing from the broader spirit and scope of the invention. For example, the reader is to understand that the specific ordering and combination of process actions shown in the process flow diagrams described herein is merely illustrative and follows industry practices, unless otherwise stated, and the invention can be performed using different or additional process actions as they become available, or a different combination or ordering of process actions. As another example, each feature of one embodiment can be mixed and matched with other features shown in other embodiments. Features and processes known to those of ordinary skill may similarly be incorporated as desired. Additionally and obviously, features may be added or subtracted as required by service conditions. Accordingly, the invention is not to be restricted except in light of the attached claims and their equivalents.
This application is a continuation of U.S. patent application Ser. No. 16/134,640, filed Sep. 18, 2018, which is a continuation of U.S. patent application Ser. No. 15/387,360, filed Dec. 21, 2016, now U.S. Pat. No. 10,100,980, which is a continuation of U.S. patent application Ser. No. 14/881,619, filed Oct. 13, 2015, now U.S. Pat. No. 9,574,710, which is a continuation of U.S. patent application Ser. No. 13/272,136, filed Oct. 12, 2011, now U.S. Pat. No. 9,182,080, which claims the benefit of U.S. Provisional Appl. No. 61/392,135, filed Oct. 12, 2010, which are fully incorporated by reference.
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