Patent Application
20060043002
This invention relates generally to production of natural gas from subterranean wells, and more specifically relates to the removal and recovery of sulfur which may be present when natural gas is produced from sour and other gas wells.
When natural gas is produced from gas wells and particularly from sour gas wells, solid sulfur or sulfur vapor is often generated if the gas is quite hot and accumulates or condenses on the well tubing itself and over time builds up thus reducing the gas flow or even plugging the well. This accumulated sulfur must be removed. One solution used in the past is application at the well of a sulfur scavenger composition which dissolves the sulfur, with the scavenger solution containing the sulfur then being discarded. This solution while it can be perfectly effective, is also both economically wasteful and environmentally detrimental.
In U.S. Pat. No. 4,322,307 to Roland Kettner a process is disclosed for treating a sour gas well in which an alkyl naphthalene base sulfur solvent is mixed with an oil carrier and circulated into the well and then recovered from the well mixed with the produced gas. After further processing the sulfur is crystallized from the solvent under suitable cooling conditions and the solvent recovered for re-use. The sulfur from the separation is described in the patent as being delivered to a suitable sulfur disposal facility. The aforementioned carrier oil which is mixed with the solvent is needed so that a sufficient density differential can be achieved in order to readily accommodate separation of the solvent from entrained water contained in the production fluid. The cited patent also contains a discussion of additional prior art processes and methodology that have been used in the past for removal of the sulfur by means of various solvents and the like.
The process of the U.S. Pat. No. 4,322,307 patent while potentially useful is based on a solvent with a vapor pressure that is high enough to cause losses to the gas phase, when compared to the solvents used in the present invention. The U.S. Pat. No. 4,322,307 solvent used is less economical and less environmentally friendly than the solvents of the present invention due to the higher vapor losses of the solvents used in that patent.
Now in accordance with the present invention the sulfur sought to be removed from the gas producing well is dissolved in a high boiling point, relatively pure and low cost non-aqueous solvent, the solvent further being more environmentally friendly than those used in the prior art. Neither does the solvent used in the invention require in its use mixing with a carrier oil. The sulfur is removed from the solvent by lowering the temperature of the solution to precipitate the solvent, with the sulfur then being separated and used as a relatively pure product. The regenerated solution, then lower in sulfur concentration, is injected back down the well hole to dissolve additional sulfur and may then be reutilized in subsequent cycles of the process.
The invention is diagrammatically illustrated, by way of example, in the drawing appended hereto, in which:
The FIGURE is a schematic block diagram of a system for well head sulfur removal operating in accordance with the present invention.
In accordance with the present invention a sulfur solvent is utilized which has a high solubility for elemental sulfur and a low vapor pressure, thereby reducing the chemical consumption costs. The non-aqueous solvent is selected from the group consisting of diphenyl ethers, dibenzyl ethers, terphenyls and alkylated terphenyls, diphenylethanes and alkylated diphenylethanes, and mixtures thereof. Preferably the selected member or members should have a boiling point above 290° C. (at one atmosphere). Preferably further, the solvent consists of one or more diphenyl ethers. The solvent is injected downhole at a typical pressure in the range of atmospheric to 4,000 psi. No mixing of the solvent with a carrier oil is needed. Preferably, relatively high pressures in the range of 2000 to 4000 psi are used. The solvent is heat stable at well over 260° F. and will readily dissolve any elemental sulfur deposits. The sulfur laden solvent is transported with the gas to the wellhead where it is separated from the gas in a high pressure gas liquid separator. The solvent and any associated water is flashed and separated prior to regeneration and crystallization. The sulfur is crystallized and separated from the solvent and the regenerated solvent is reinjected into the well. Any vaporization losses are made up by using a solvent make up system.
Referring to the appended schematic FIGURE, a system 10 in accordance with the present invention is shown. Wellhead gas 12 is taken from a well at an underground subterranean formation and includes the gas which is usually (but not necessarily) sour along with the solvent which has been previously injected and may contain residual quantities of dissolved sulfur. The extracted gas and solvent are provided to a high pressure gas-liquid separator 14. The product gas is taken at 16 for its intended ultimate use. The solvent and dissolved sulfur proceeds from separator 14 via line 18 to a flash tank separator 20. The gas component is flashed there and exits at 22 where it can be recompressed or flared. Sour water is taken as one separated product at line 24. The solvent containing the dissolved sulfur proceeds via line 26 to a loop 28 which includes a recirculation pump 30 and a heat exchanger 32. The cooled solution enters a crystalizer tank 34 where the sulfur is crystallized and the solvent then returned via line 36 to a surge tank 38 heated with a steam line 40. The solvent proceeds from surge tank 38 via line 41 to the main injection pump 42 and then downhole at 44. A chemical make up storage tank is provided at 46 which via a metering pump 48 provides make up solvent to tank 38 by line 50.
The sulfur (slurry) taken from crystalizer tank 34 proceeds via line 52 and a filter feedpump 54 which pumps the sulfur slurry to a pressure filter 56. Sulfur cake 60 is separated at that point and removed via 58 as relatively high purity sulfur. A solvent recovery system with clean solvent tank 62 provides clean wash solvent and wash water by line 64 to the pressure filter. Dirty wash solvent and wash water proceeds from the filter to tank 62 via line 66. Oily water blow down is taken at line 68 from the solvent tank and discarded or further treated for purification.
It should be noted that the sulfur crystallization process per se described herein is used with suitable solvents in the processes disclosed in several patents to David W. DeBerry et al., such as U.S. Pat. No. 6,416,729. The formation of large sulfur crystals by means of the present invention provides sulfur that is up to 99 percent pure and leaves the filter with only 2 to 5 percent water. In consequence the sulfur product is relatively dry and is of sufficient purity that it can be used in agricultural applications, blended into Claus sulfur (if available) or sent to a land fill as non-hazardous waste.
While the present invention has been set forth in terms of specific embodiments thereof, the instant disclosure is such that numerous variations upon the invention are now enabled to those skilled in the art, which variations yet reside within the scope of the present teaching. Accordingly, the invention is to be broadly construed and limited only by the scope and spirit of the claims now appended hereto.
This application claims priority from U.S. Provisional patent application Ser. No. 60/604,510 filed Aug. 26, 2004.
| Number | Date | Country | |
|---|---|---|---|
| 60604510 | Aug 2004 | US |
