NATURAL GAS PRETREATMENT

PRIORITY CLAIM OF EARLIER NATIONAL APPLICATIONS

[0001] This application claims priority to U.S. Application No. 61/349,453 filed May 28, 2010 and U.S. Application No. 13/091,782 filed April 21, 2011, the contents of which are hereby incorporated by reference.

BACKGROUND OF THE INVENTION

[0002] The present invention relates to a process for processing natural gas. More particularly, this invention relates to an integrated process for treating natural gas that is to be converted to liquefied natural gas (LNG) on a ship based system.

[0003] A new type of vessel is being developed that may revolutionize offshore production of natural gas. The gas industry is currently planning to build a fleet of ships or barges that can be sailed or towed to the site of offshore gas deposits, extract the gas, pretreatment the natural gas to remove impurities, then freeze it to become LNG and then offload the LNG to tankers for shipping to market. It is hoped that these floating liquefied natural gas (FLNG) ships will be cheaper to use than building onshore pretreatment and liquefaction facilities, speed up the time to bring fields on stream and make it economical to exploit small and remote offshore gas fields. It has been estimated that over 1/6 of global gas reserves are in such fields. There are also security advantages to produce gas offshore in some parts of the world instead of in onshore facilities. In addition, the use of FLNG vessels avoids impacting onshore wildlife habitats and the need to move communities due to the onshore space needed for land based facilities.

[0004] In LNG service, the natural gas has to be cleaned before it is sent to a liquefaction unit. Generally, the treated gas CO2 concentration has to be below 50 ppm to avoid freezing of CO2 in the liquefaction process. Water is also removed to avoid hydrate formation. The use of an amine solvent is a well known process and is an accepted technology for land based

LNG pretreatment. For offshore FLNG service, however, there are at least two problems associated with use of a solvent process. First, footprint and weight are two important parameters for the ship and platform builder. When an acid gas such as CO2 is present at an increased concentration in a natural gas feed, the amine absorption column diameter and the amine solvent circulation rate that is needed significantly increases, which leads to large footprint and heavy weight. Second, motion at sea often generates flow maldistribution inside amine absorber and regenerator. This flow maldistribution results in low separation efficiency of a solvent process. Hence, due to the motion, the natural gas stream after the amine treatment may not be able to meet the stringent specifications of acid gases such as C0 ₂ required by liquefaction.

SUMMARY OF THE INVENTION

[0005] The present invention, which is intended to be applied on a movable platform such as on a ship or barge, involves a process for removal of acid gases from a raw natural gas stream comprising first sending the raw natural gas stream through a membrane unit containing a membrane for selective separation of acid gases from natural gas and thereby forming a partially purified natural gas stream having an acid gas content lower than the raw natural gas stream. The resulting partially purified natural gas stream is sent to an amine column to be placed in contact with an aqueous amine absorbent contained within the amine column to further remove acid gases and to form a natural gas product effluent having acid gas content less than the partially purified natural gas stream. The platform containing the equipment used to purify natural gas is subject to movement caused by ocean waves and winds. This movement can cause maldistribution of liquid within vessels and can impact the effectiveness of the amine column in removing acid gases such as carbon dioxide and hydrogen sulfide. The present invention deals with this problem by integrating the membrane system and the amine system by changing the membrane operation conditions or process configurations, hence, changing the feed acid gas concentration to the amine absorber, the integrated system can mitigate the effect of maldistribution and deliver the treated gas meeting the feed specifications for LNG liquefaction. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] FIG. 1 is a graph of amine absorber diameters at different concentrations of carbon dioxide in the natural gas feed.

[0007] FIG. 2 is a graph of the lean solvent circulation rate for amine that is required for different concentrations of carbon dioxide in the natural gas feed. [0008] FIG. 3 is a graph of the effect of maldistribution on amine column performance based upon the carbon dioxide concentration in a treated natural gas stream.

[0009] FIG. 4 is a graph of the carbon dioxide concentration in a treated feed against the carbon dioxide concentration in the untreated feed at a lambda (λ) value of 0.16.

[0010] FIG. 5 is a membrane/amine column system for treating a natural gas stream in which there is a bypass stream to adjust the amount of natural gas that is being treated by the membrane part of the system.

[0011] FIG. 6 is a membrane/amine column system for treating a natural gas stream in which there is a bypass stream around a preheater.

[0012] FIG. 7 is a membrane/amine column system for treating a natural gas stream in which there is a control system to adjust the pressures in the system.

[0013] FIG. 8 is a diagram that shows the directions of motion that influence a platform on the ocean.

DETAILED DESCRIPTION OF THE INVENTION [0014] FIG. 1 shows the relative column diameter needed to treat natural gas streams having CO2 concentrations ranging from 4 to 15 mol-%. FIG. 2 shows the lean solvent circulation rate that would be needed to treat natural gas having these concentrations of CO2 and would still meet specification requirements of less than 50 parts per million CO2 in the natural gas that is being treated. In an offshore service, this will significantly increase the footprint and weight of the system. There are practical limitations on the maximum size of an amine system that can be built and placed topsides of a ship as part of the pretreatment system. A mobile pretreatment system would need to be designed to treat natural gas feeds streams having differing levels of contamination. The FLNG ship or platform would need to continue to work at various sea conditions of wind and waves. Due to the motion of the ship or other platform, maldistribution of a liquid flow inside the columns and inside pressure vessels will occur. This maldistribution can result in a deviation of the process performance. The maldistribution of liquid in a column can be defined using the following equation:

^~ L max +L mi■n where λ is the maldistribution factor and L is the local liquid loading inside the column.

[0015] The larger that λ is, the greater that the maldistribution will be. Using the maldistribution factor, it is possible to simulate the amine absorption column performance under motion conditions. FIG. 3 shows the treated gas CO2 concentration as a function of maldistribution factor λ. At a different λ, the column can be operated at identical operating conditions such as temperature, pressure, and lean solvent circulation flow rate. However, the concentration of CO2 in the treated gas increases from less than 50 ppm (λ = 0) to more than 2000 ppm (λ = 0.2). For a commercial FLNG unit, if the gas to the liquefaction system has a CC"2 concentration at 2000 ppm, the liquefaction will not be able to operate normally due to hydrate generation.

[0016] A solution that has been found to this problem is to integrate the membrane system with the amine system to clean up the gas. In this process, the membrane is used for bulk removal of acid gas from the natural gas, and the amine system is used to finish the clean up of the acid gas to a parts per million level (generally less than 50 ppm) in order to meet the specifications for a liquefaction section of a LNG facility. Since the membrane can remove sufficient acid gas to bring the concentration from a high level to a significantly lower concentration, the amine clean-up system can be much smaller and lighter. Polymeric membrane systems, such as UOP's Separex™ membrane system, have a proven track record of providing bulk acid gas removal in demanding offshore applications. The technology is well suited to treating feed gas streams with high levels of acid gas and reducing the acid gas level to moderate levels that can more easily be treated in an amine unit. Since the membrane technology scales are based on partial pressure of the acid gas in the feed, a membrane system will be inherently smaller, lighter weight, more compact and more robust than an amine unit treating a similarly high acid gas feed stream.

[0017] Not only can the membrane reduce the footprint, weight, and cost, it also can be used as a tool to mitigate the effect of maldistribution on amine column performance so that the integrated process is much more robust. In FIG. 4, assuming the amine absorption column with a maldistribution factor λ = 0.16, when the feed CO2 concentration is 5%, the treated gas CC"2 concentration is above 1500 ppm. However, if we reduce the feed CO2

concentration to 4.2%, the treated gas will have a CO2 concentration below 50 ppm that meets the LNG liquefaction feed specification although the column is running at the same operating conditions and the maldistribution factor does not change. This demonstrates that by changing the membrane operation conditions or process configurations, hence, changing the feed acid gas concentration to the amine absorber, the integrated system can mitigate the effect of maldistribution and deliver the treated gas meeting the feed specifications for LNG liquefaction section.

[0018] The simplest process configuration is shown in FIG. 5 where a bypass stream is designed for the membrane system. When motion becomes stronger and severer and maldistribution happens in the amine process, the bypass stream flow rate will be reduced to obtain the low CO2 concentration to the feed of amine process. More specifically, FIG. 5 is seen a natural gas stream 1 that is sent to a membrane unit 3. A portion 2 of the natural gas stream is shown bypassing the membrane unit 3. Within the membrane unit 3 is shown a permeate side 4 with acid gases such as carbon dioxide and hydrogen sulfide being removed in line 5. A partially treated natural gas stream 7 is shown leaving a retentate side 6 of membrane unit 3. This partially treated natural gas stream 7 is mixed with the bypassing stream 2 to form stream 12. Stream 12 is sent to a column containing a solvent for further treating the natural gas to remove acid gases. Column 8 will normally contain an amine solvent that is known for removal of acid gases. Lean solvent 11 that contains a low amount of acid gases is shown entering column 8 in an upper portion of the column. Treated natural gas stream 10 is shown exiting the top of column 8 and a rich solvent stream 9 containing the acid gases that have been removed from stream 12 is shown exiting the bottom of column 8.

[0019] Another process configuration is shown in FIG. 6 where a bypass is designed for the membrane pre-heater. Based on the property of membrane, at higher temperature, the membrane will have higher flux with the same membrane area. In this configuration, when motion becomes stronger and severer, the pre-heater bypass will be reduced so that the membrane feed will have higher temperature. More acid gas will permeate through the membrane. Hence, the residue which is the feed to amine unit will have lower acid gas concentration.

[0020] More specifically in FIG. 6, is seen a natural gas stream 1 that is sent to a pre- heater 21 through line 22 to membrane unit 3. A portion 20 of natural gas stream 1 is shown bypassing pre-heater 21 and then being combined in line 22 with the natural gas stream that has been heated. Within membrane unit 3 is shown a permeate side 4 with acid gases such as carbon dioxide and hydrogen sulfide being removed in line 5. A partially treated natural gas stream 7 is shown leaving a retentate side 6 of membrane unit 3. This partially treated natural gas stream 7 is sent to a column containing a solvent for further treating the natural gas to remove acid gases. Column 8 will normally contain an amine solvent that is known for removal of acid gases.. Lean solvent 11 that contains a low amount of acid gases is shown entering column 8 in an upper portion of the column. Treated natural gas stream 10 is shown exiting the top of column 8 and a rich solvent stream 9 containing the acid gases that have been removed from partially treated stream 7 is shown exiting the bottom of column 8.

[0021] FIG. 7 shows the third process configuration. In this configuration, the permeate pressure can be adjusted to control the acid gas removal from the membrane. The membrane process can run at higher permeate side pressure when there is no motion. The permeate side pressure can be reduced to increase the acid gas removal when required at severer motion of the ship or platform.

[0022] More specifically in FIG. 7 is seen a natural gas stream 1 that is sent to a membrane unit 3. Within the membrane unit 3 is shown a permeate side 4 with acid gases such as carbon dioxide and hydrogen sulfide being removed in line 5. A process control system 25 is shown measuring the pressure of the acid gas being removed that will control the pressure of the permeate side 4 of the membrane unit 3 depending upon the motion of the ship or platform. A partially treated natural gas stream 7 is shown leaving a retentate side 6 of membrane unit 3. This partially treated natural gas stream 7 is sent to a column containing a solvent, such as an amine solvent, for further treating the natural gas to remove acid gases. Lean solvent 11 that contains a low amount of acid gases is shown entering column 8 in an upper portion of the column. Treated natural gas stream 10 is shown exiting the top of column 8 and a rich solvent stream 9 containing the acid gases that have been removed from partially treated stream 7 is shown exiting the bottom of column 8.

[0023] The advanced control system includes a motion detector which can detect the motion shown in FIG. 8. FIG. 8 shows a top surface of a platform for processing

hydrocarbons. For the purposes of the present application, the equipment that would be mounted on the platform are not shown. What is of importance to an understanding of the present invention are the motions that the platform may be subject to including roll 40, yaw 42, pitch 44, heave 46 and sway 48. The system includes an algorithm to calculate the maldistribution factor based on the motion detected, the control mechanism and program, and the control valves in process configurations such as those shown in FIGS. 5, 6, and 7. When the motion detector detects the motion, the control system will instantaneously send the feed back to the membrane system to either reduce the bypass flow in FIGS. 5 and 6, or reduce the permeate side pressure in FIG. 7, or do a combination of one or more bypass flows and reduction of permeate side pressure in some cases. In order to guarantee that the treated gas from amine unit always meet the acid gas specifications for the LNG liquefaction section, the amine column will be designed with some design margin. However, this design margin can be much less compared to a system that does not have a membrane unit to adjust the purity level of the natural gas stream going into the amine column.