Patent Publication Number: US-2003230195-A1

Title: Purification of natural hydrocarbons

Description:
CROSS REFERENCE TO RELATED APPLICATIONS  
     [0001] This application is a continuation of PCT/GB01/04130 filed Sep. 17, 2001 and published, in English, as WO 02/24838 A1 on Mar. 28, 2002 and claims priority from British patent application no. 0022688.6 filed Sep. 15, 2000, the entire contents of which are incorporated herein by reference. 
    
    
     
       BACKGROUND OF THE INVENTION  
       [0002] 1. Field of the Invention  
       [0003] This invention relates to a process and equipment for the purification of natural hydrocarbons, and relates more particularly but not exclusively to a novel process and equipment for the removal and environmentally safe disposal of sour reservoir components. The process and equipment are particularly directed to the removal of sour reservoir components, such as hydrogen sulphide (H 2 S) and carbon dioxide (CO 2 ), from a production gas stream.  
       [0004] 2. Description of Related Art  
       [0005] Buried deposits of natural hydrocarbons, known as “reservoirs”, may contain gas and/or oil, commonly contaminated with undesirable substances, e.g. hydrogen sulphide and/or carbon dioxide. Currently, hydrogen sulphide can be removed from the production gas stream through a number of means. The most common means are absorption processes and chemical treatment.  
       [0006] Absorption with water or another absorbent, such as amines, can be used to remove H 2 S and CO 2 , however the regeneration of the used absorbent stream, through pressure reduction and heating to drive off the sour components, results in the release of a sour-gas-rich gaseous stream which is normally incinerated. The burning of H 2 S results in the formation and emission of acid SOX gases which are known to be harmful to the environment.  
       [0007] Chemical reactants, such as triazine injected into the production streams or beds packed with zinc oxide, are used to remove reservoir H 2 S through chemical reaction. The high quantities of reactants required to achieve the necessary reduction in H 2 S concentration usually results in a high chemical usage and consequent high operating cost.  
       BRIEF SUMMARY OF THE INVENTION  
       [0008] The present invention aims to provide a process and equipment by which the bulk of the sour gas reservoir components can be removed from a production gas stream, at a relatively low operating cost, and returned to the reservoir for environmentally safe disposal.  
       [0009] According to a first aspect of the present invention there is provided a process for the separation and disposal of sour reservoir components initially contained in natural hydrocarbon produced from a reservoir, the process being characterized in that it includes the steps of absorbing the sour reservoir components in a liquid absorbent to form a solution and injecting said solution into a well.  
       [0010] Preferably, the liquid absorbent is water.  
       [0011] Advantageously, the step of absorbing is performed within a contractor column that is a multiple-stage packed column, or tray column.  
       [0012] Preferably, the natural hydrocarbons and sour reservoir components are gaseous and are compressed in a gas compression means prior to being treated by said process.  
       [0013] According to a second aspect of the present invention there is provided equipment for the separation and disposal of sour reservoir components, said equipment being characterized by including absorbing means, hydrocarbon feeding means for feeding said absorbing means with natural hydrocarbons containing sour reservoir components, a source of liquid absorbent, absorbent feeding means for feeding said absorbing means with liquid absorbent from said source, said absorbing means functioning in use of said equipment to scrub said natural hydrocarbons with said liquid absorbent so as to dissolve said sour reservoir components in said liquid absorbent and thereby form a solution, and solution discharging means for discharging said solution from said absorbing means.  
       [0014] Said equipment preferably further comprises solution injection means for re-injecting said solution into the reservoir that produced said natural hydrocarbons, or into geological formations adjacent said reservoir.  
       [0015] Said absorbing means is preferably a contactor column that may be a multiple-storage packed column or tray column.  
       [0016] Said source of liquid absorbent is preferably a source of water, and the water is preferably rendered substantially free of oxygen and substantially free of solids.  
       [0017] Said hydrocarbon feeding means may include heating means and/or pressurization means operable to cause hydrocarbons to be fed to said absorbing means at predetermined temperatures and/or at predetermined pressures.  
       [0018] According to a third aspect of the present invention there is provided a process for disposing of sour water, said process comprising the step of re-injecting said sour water into a hydrocarbon reservoir. Said hydrocarbon reservoir may be a producing reservoir or a depleted reservoir. 
     
    
    
     BRIEF DESCRIPTION OF THE DRAWING  
     [0019] Embodiments of the invention will now be described by way of example with reference to the accompanying drawing, the sole FIGURE of which is a schematic diagram of a preferred embodiment. 
    
    
     DETAILED DESCRIPTION  
     [0020] It is envisaged that the process and equipment of the preferred embodiment will be operated within a gas production compression and treatment train that may be located immediately downstream of a gas-producing wellhead. It should be noted that this configuration is given by way of example only and that the invention is by no means limited to a single configuration.  
     [0021] Sour, wet, gases from production separators (not shown) are compressed in a typical gas compression train and these gases are then delivered to a sour gas scrubbing system  10  as shown in the sole FIGURE of the accompanying drawing. (Separate compression of the sour gases will not be necessary if the operating pressure of the production separators is maintained at a sufficiently high pressure to permit treatment of the sour gases in the system  10  without the need for compression facilities).  
     [0022] The operating conditions of the scrubbing system  10  are carefully chosen to maximize the effectiveness of the water scrubbing operation, whilst preventing hydrocarbon condensate formation and hydrate formation.  
     [0023] The sour production gases in the incoming stream  12  are conditioned by controlled heating or cooling to approximately 30° Celsius and delivered via a gas/liquid separator  14  to ensure adequate separation of production gas from any condensed hydrocarbons and water. The separated gas stream  16  output from the separator  14  is routed to a sour gas contactor  18  while the separated liquid hydrocarbon and water stream  20  output from the separator  14  is routed back to the upstream production separators through a suitable flow control valve  22 .  
     [0024] The contactor  18  is fed along a supply line  24  with injection-grade water from a water supply  26 . Within the contactor  18 , the separated gas stream  16  is contacted counter-currently with the water absorbent stream  24 . The contactor  18  is in the form of a column that is a multiple-stage packed column or a multiple-stage tray column. The absorbent stream  24  strips water soluble components, those of particular interest being H 2 S and CO 2  from the production gas stream  16  as the counter-current production gas and water absorbent streams contact each other within the contactor  18 . The resultant production gas stream  28  exits the sour gas contactor  18  with a much reduced H 2 S and CO 2  component concentration. This wet, sweetened, production gas stream  28  is then routed to downstream facilities (not shown) for further treatment, typically drying, and delivery.  
     [0025] Depending upon the effectiveness of a specific design, some further final polishing of the gas stream  28  may be necessary to ensure the delivery sour gas component specification.  
     [0026] Absorbent water from the source  26  is injection quality water. Oxygen-free and filtered seawater or produced water may be used as the absorbent. The absorbent water stream  24  will be conditioned to a few degrees Celsius higher than the temperature of the sour gas production stream  16  to prevent hydrocarbon gas condensation within the contactor  18 . The absorbent water stream  24  is delivered to the sour gas contactor  18  at a suitable pressure through use of a dedicated pump (not shown) or through a tie-in to an injection water distribution system (not shown) of adequate operating pressure.  
     [0027] It is to be understood that the performance requirements for heating, cooling and pressure generating equipment, necessary to achieve the required supply conditions for the sour production gas stream  16  and the absorbent water stream  28 , are dependent upon the associated compression systems and water injection system.  
     [0028] The contactor  18  is a typical design similar to gas dehydration glycol contactors in use in the offshore oil and gas industry, i.e. packed columns or tray columns. This contactor design will include a skimming facility  30  to remove any hydrocarbon condensate which may accumulate within the contactor  18 . This may occur as a result of condensation within the contactor  18  or associated pipework or from poor separation within the upstream separation facility  14 . Condensate is tapped from the contactor  18  along a discharge line  32  under the control of valve  34  operated by a condensate level sensor  36  suitably coupled to the contactor  18 . Skimmed condensate will be routed back to the upstream production separators.  
     [0029] The water stream  38 , rich in absorbed sour components that results from operation of the contactor  18 , is discharged from the bottom of the contactor  18  and is routed to a water injection pump  40  to raise the pressure of the sour water stream  38  to the required reservoir injection pressure. The water injection pump discharge  42  is routed to a water injection wellhead  44 , from where it is conducted into the disposal or pressure maintenance reservoir  46 . The pump discharge  42  is controlled by a suitable valve  48  that is operated by a level controller  50  suitably coupled to the contactor  18 .  
     [0030] In typical use of the invention it will be appropriate to analyze the vapor liquid equilibria and to assess the optimum operating conditions of the sour gas contactor  18 . Higher pressure operation increases the partial pressure of particular components in the gas stream  16 , which consequently increases their solubility in water. Solubility also increases with reduced absorbent temperature, however the possibility of hydrate formation at high operating pressures must be guarded against.  
     [0031] The inventive process of sour water re-injection will be advantageous to oil and gas processing systems where operating costs and environmental impact must be minimized. A typical example of the benefit of this sour water re-injection system would be seen in its application to a new reservoir development where the cost of removing sour gases has a significant contribution to the economics of the project.  
     [0032] Another advantage of this invention is that it combines known technologies and methods in a simple way to give a low risk, low cost, alternative sour gas separation and disposal system. The operability of the invention can be easily assessed using industry standard process simulation tools.  
     [0033] Modifications and variations of the invention can be adopted without departing from the scope of the invention as defined in the appended claims. For example, liquid absorbents other than water can be employed, and suitable contactors other than packed columns or tray columns can be employed for absorbing sour components in the natural hydrocarbons.