Abstract:
The invention describes a system and method for hydrogen sulfide decontamination of natural gas using a scavenging reagent. The system uses a scavenging reagent within two reactors wherein the consumption of scavenging reagent is optimized by the control of flow of clean and partially-consumed scavenging reagent within and between the two reactors.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of priority under 35 U.S.C. §120 of U.S. Provisional Patent Application No. 60/981,333 filed Oct. 19, 2007, the entire contents of which are incorporated herein by reference. 
    
    
     FIELD OF THE INVENTION 
     The invention describes a system and method for hydrogen sulfide decontamination of natural gas using a scavenging reagent. The system uses a scavenging reagent within two reactors wherein the consumption of scavenging reagent is optimized by the control of flow of clean and partially-consumed scavenging reagent within and between the two reactors. 
     BACKGROUND OF THE INVENTION 
     As is known, hydrogen sulfide (H 2 S) is a highly poisonous and corrosive contaminant of natural gas and crude petroleum. While only relatively small amounts of H 2 S occur in crude petroleum, natural gas can contain up to 40% by volume. As a result, H 2 S must be removed to acceptable levels prior to delivery to the refinery or main gas distribution system. Generally, in order to meet governmental, technical and natural gas sales specifications, H 2 S concentrations must be at very low levels (usually less than 16 ppm). 
     Hydrogen sulfide is a covalent hydride structurally related to water (H 2 O) as oxygen and sulfur occur in the same periodic table group. However, hydrogen sulfide is weakly acidic, dissociating in aqueous solution into hydrogen cations H +  and the hydrosulfide anion HS − :
 
H 2 S→HS − +H + 
 
     Hydrogen sulfide reacts with many metals cations to produce the corresponding metal sulfides. 
     In petroleum refineries, the normal hydrodesulfurization processes liberate sulfur from petroleum by the action of hydrogen. The resulting H 2 S is converted to elemental sulfur by partial combustion via the Claus process, which is a major source of elemental sulfur. 
     The most highly utilized processes for sweetening sour natural gas is to use amine solutions to remove the hydrogen sulfide. These processes are known simply as the ‘amine processes’, or alternatively as the Girdler process, and are used in 95 percent of North American gas sweetening operations. Generally, the sour gas is run through a tower, which contains the amine solution. This solution has an affinity for sulfur, and absorbs it much like glycol absorbing water. There are several amine solutions that are commonly used, including monoethanolamine (MEA), methyldiethanolamine (MDEA), and diethanolamine (DEA) each of which in their liquid form, will absorb sulfur compounds from natural gas as it passes through the column. The effluent gas or sweet gas is virtually free of H 2 S compounds. Like the process for NGL extraction and glycol dehydration, the amine solution used can be regenerated (that is, the absorbed sulfur is removed), allowing it to be reused to treat more sour gas. This technology is capital intensive and is generally more suitable for larger scale operations. 
     In other systems, the use of liquid scavengers within columns is also known. In these systems, sour gas and a liquid scavenger agent are introduced into a column. The scavenger reacts with sour gas within the column such that both sweet gas and “spent” scavenger are removed from the top of the column. The most common liquid scavenger is an amine-aldehyde condensate manufactured by an exothermic reaction of monoethanolamine and formaldehyde. Water and methanol are usually required to keep the formaldehyde in solution and prevent polymerization. The resulting “scavenger” product is a hexahydrotriazine, and is commonly called “triazine” in the industry. The “triazine” is typically offered in a water-based solution. In most applications, the reaction products are also water soluble, with very low toxicity characteristics making this a relatively simple system to handle. Other scavenging reagents are known to those skilled in the art. 
     Importantly, the scavenging reactions between triazine and H 2 S can be “overspent” such that the reaction products are solids. Generally, it is preferred that solid reaction products are not produced for ease of subsequent handling. Thus, most reactions are controlled to underutilize the scavenging reagent. 
     While the liquid scavenger system is a relatively cost effective system as a result of the relatively low capital cost of equipment, simple logistics, and simple waste treatment, the cost of scavenger reagent is relatively high. Typically, as a result of the cost of the liquid scavenger, the overall process cost of H 2 S removal will range from a low of $8/pound to $20/pound of H 2 S removed. Notwithstanding the cost of reagent, the liquid scavenger system is a preferred system for offshore gas treatment and onshore sites where there is a relatively small amount of H 2 S that needs to be treated. 
     However, there continues to be a need for a technology that improves the efficiency of utilization of scavenger reagent, such that the overall process economics can be improved. 
     SUMMARY OF THE INVENTION 
     In accordance with the invention, there is provided a system and method for improving the efficiency of utilization of scavenger chemical reagent in a sour gas treatment process. 
     In a first embodiment, the invention provides a system for removing hydrogen sulfide from natural gas comprising: a first reactor for reacting a partially-consumed scavenging reagent with sour natural gas and for producing partially-sweetened natural gas; a separator operatively connected to the first reactor for separating consumed scavenging reagent from the partially-sweetened natural gas; a second reactor operatively connected to the separator for reacting clean scavenging reagent with the partially-sweetened natural gas and for producing sweetened natural gas; a scavenging reagent delivery system operatively connected to the first reactor and second reactor, the scavenging reagent delivery system for delivering clean scavenging reagent to the second reactor and partially-consumed scavenging reagent to the first reactor; and, a control system for controlling the relative flow of scavenging reagent to the first and second reactors in response to the hydrogen sulfide concentration within the partially-sweetened natural gas. 
     In a further embodiment, the invention provides a method for removing hydrogen sulfide from natural gas comprising the following steps in any order: a) reacting a partially-consumed scavenging reagent with sour natural gas to produce a partially-sweetened natural gas and consumed scavenging reagent; b) separating consumed scavenging reagent from the partially-sweetened natural gas; and, c) reacting clean scavenging reagent with the partially-sweetened natural gas to produce sweetened natural gas; wherein the clean scavenging reagent from step c) is used as partially-consumed scavenging reagent in step a). 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The invention is described by the following detailed description and drawings wherein: 
         FIG. 1  is a schematic diagram of a hydrogen sulfide plant and polishing system in accordance with the prior art; 
         FIG. 2  is a schematic diagram of a hydrogen sulfide processing plant and polishing system in accordance with the invention; and 
         FIG. 2A  is a schematic diagram of a hydrogen sulfide processing plant and polishing system in accordance with an alternate embodiment of the invention. 
     
    
    
     DETAILED DESCRIPTION 
     In accordance with the invention and with reference to the figures, embodiments of a system and method for removing hydrogen sulfide from natural gas are described. 
     The system and method improves the efficiency of scavenger reagent (SR) utilization in typical hydrogen sulfide sweetening processes. 
     As shown in  FIG. 1  and in accordance with the prior art, a typical hydrogen sulfide treatment plant utilizing a scavenger reagent includes a primary reactor (or column)  10  and separator  12 . Sour gas  10   a  is introduced at a low point  10   b  in the column together with SR  10   c  from a fresh SR source  14  by pump  11 . The sour gas and SR pass upwardly through the column whereby the sour gas is sweetened and the SR is consumed as known to those skilled in the art. The sweetened gas and SR  10   d  collectively pass over the top of the column and thereafter enter separator  12  whereby the sweetened gas and liquid SR are separated on the basis of density. The liquid SR is removed from the bottom  12   a  of the separator and delivered to a spent reagent tank  16  for disposal and the sweetened gas is removed from the top  12   b  of the separator for delivery. The system is controlled by an appropriate control and feed back system  18  to monitor the H 2 S concentration in the sweetened gas  12   b  and to control the flow of SR to the column  10  through pump  11 . 
     In order for the sweetening reactions to proceed and to ensure that the sweetened gas meets the appropriate regulatory standard for H 2 S removal, the SR must be added in significant excess to ensure that the H 2 S removal reaction proceeds to completion. As a result, due to normal fluctuations in the H 2 S concentration entering the column  10 , and to provide an appropriate safety margin, significant amounts of SR delivered to the spent reagent tank  16  may be unreacted. 
     In accordance with the invention, and with reference to  FIG. 2 , a system to improve the efficiency of SR utilization is provided. Generally, the primary desulfurization system  10 ,  12  is used with partially-consumed SR  20   a  to produce a “semi-sweet” gas  12   b  and clean SR  14   a  is used to polish the semi-sweet gas  12   b  to produce a sweet gas  20   b . As a result, the system, by virtue of the use of clean SR in the final polishing step enables more effective control of the utilization of SR. 
     In accordance with the invention, the system as described in  FIG. 1  is modified to include a polishing system  20  comprising a second column that functions similarly to column  10  with the exception that it is operated as a combined reactor and separator. In addition, the system introduces clean SR  14   a  directly to column  20  prior to introduction into column  10  and the system is controlled such that semi-sweet gas  12   b  is introduced into column  20 . In addition, the system includes pump  11   a  to deliver clean SR to column  20  and the control system  18  is modified to balance the effective flow rates through both pumps  11 ,  11   a  in response to the measured H 2 S concentration from separator  12 , reagent levels in column  20  as measured by level controller  20   c  and in the produced sweetened gas. 
     Generally, the control system operates to ensure that the H 2 S concentration exiting column  20  is low (generally less than 16 ppm, ideally 0 ppm). Primary control of the system is by conducted on the basis of the measured H 2 S level between separator  12  and column  20 . For example, for a given set of operating parameters (i.e. based on the H 2 S levels, system volumes and stoichiometry of the specific system), the system may be designed such that the measured H 2 S level in semi-sweet gas  12   b  is in the range of 10-100 ppm in order that a desired H 2 S level of the sweet gas is at the desired level (ideally 0 ppm). As such, if the control system determines that the H 2 S level is within this range, pumps  11  and  11   a  will in turn be run at a given flow rate. If the H 2 S level is detected to be above this range, indicating a possible spike in H 2 S level in the source gas, the control system will increase flow rates through pumps  11 ,  11   a  so as to increase the flow of SR within the columns. Similarly, a decrease in H 2 S level below this range, will cause a decrease in flow rates through pumps  11 ,  11   a  so as to reduce the flow of SR in the columns. Readings of H 2 S concentrations in the sweet gas  20   b  and source gas  10   a  may be made for safety purposes and reference points but are generally not required for system control after the system is operating. 
     By way of representative example, the control system and the balance of SR is described as follows: If the semi-sweet gas  12   b  is 95% desulfurized in column  10 , the remaining 5% of the H 2 S is removed by reacting the semi-sweet gas with clean SR in column  20 . The clean SR ensures that the desulfurization reactions in column  20  proceed to effectively 100% completion whilst depleting only 5% of the desulfurization capacity of the specific volume of clean SR. The partially-consumed SR  20   a  is introduced into column  10  at a flow rate that ensures the complete utilization of SR to produce semi-sweet gas  12   b . By responding to changes in the H 2 S concentration in semi-sweet gas  12   b , the controller  18  can adjust the relative flow rates of SR between columns  10  and  20  and the level of SR within column  20 . As a result, the system can be controlled to more effectively ensure complete utilization of SR whilst producing sweet gas. Thus, depleted SR entering tank  16  is fully depleted. 
     In a further embodiment as shown in  FIG. 2A , partially consumed SR  20   a  is returned to tank  14   a  prior to pumping to column  10 . From a practical perspective, this configuration may be preferred in the field particularly if the system is being retro-fit to a system in accordance with the prior art. 
     As a result, the system is able to effectively utilize SR without the shortcomings of the prior art by specifically being able to fully utilize the SR. 
     EXAMPLE 
     A cost comparison between the prior art and the subject process is detailed in Table 1 for a triazine SR under the stated operating conditions. It is understood that specific operating conditions will vary depending on the numerous variables including vessel sizes, operating pressures and temperature and gas source as may be established for or measured at a particular site. 
     
       
         
               
             
               
               
               
             
               
             
               
               
               
             
           
               
                 TABLE 1 
               
               
                   
               
               
                 Cost Comparison at Representative Operating Conditions 
               
               
                   
               
             
             
               
                 Operating Conditions 
               
               
                   
               
             
          
           
               
                   
                 Design Pressure 
                 1440 psia 
               
               
                   
                 Operating Pressure 
                 300 psia 
               
               
                   
                 Operating Temp 
                 90° F. 
               
               
                   
                 Gas Flow 
                 1.0 MMscfd 
               
               
                   
                 H 2 S Inlet 
                 2400 ppm 
               
               
                   
                 H 2 S Outlet 
                 0 ppm 
               
               
                   
                 Scavenging Reagent 
                 Triazine 
               
               
                   
                 Scavenging Rate 
                 0.2 L/ppm/MMscfd 
               
               
                   
                 (100%) 
               
               
                   
                   
               
             
          
           
               
                 Cost Comparison 
               
             
          
           
               
                 Parameter 
                 Subject Process 
                 Prior Art Process 
               
               
                   
               
               
                 System Efficiency 
                 100% 
                 80% 
               
               
                 Scavenging Rate 
                 0.2 l/ppm/MMscf 
                 0.25 l/ppm/MMscf 
               
               
                 Daily Chemical Use 
                 480 l/day 
                 600 l/day 
               
               
                 Cost/Liter 
                 3 $/liter 
                 3 $/liter 
               
               
                 Daily Chemical Cost 
                 1440 $/day 
                 1800 $/day 
               
               
                 Process Cost 
                 1.44 $/Mcf 
                 1.8 $/Mcf 
               
               
                 Changeout/fill frequency 
                 67 Days 
                 53 Days 
               
               
                 Changeout per year 
                 5.5 Fills/year 
                 7 Fills/year 
               
               
                 Annual Chemical Cost 
                 $525,000/year 
                 $657,000 $/year 
               
               
                 Annual Savings 
                 $131,400/year 
               
               
                   
               
             
          
         
       
     
     As shown, it is clear that based on the efficiency of fully using the SR, significant costs savings can be realized with the subject technology for a typical sour gas well. 
     Although the present invention has been described and illustrated with respect to preferred embodiments and preferred uses thereof, it is not to be so limited since modifications and changes can be made therein which are within the full, intended scope of the invention.