LOOP LINE FOR H2S TREATMENT

Abstract

The disclosure provides novel method for removal of H.sub.2S from natural gas or other fluid in an oil and gas production facility by the use of a loop line method whereby the fluid passes through a looped pipeline containing H.sub.2S scavenger thereby increasing the contact time of the H.sub.2S scavenger with the gas and thus increasing the efficiency of the removal of H.sub.2S from the gas. The loop line can be added to a facility with an existing H.sub.2S scavenger direct injection line and can also be a standalone H.sub.2S scavenger method.

Claims

1. A method of removing H.sub.2S from a fluid, said method comprising introducing an H.sub.2S scavenger upstream of a pipe loop of at least 25 feet in length, said pipe loop having a uniform degree of curvature and lacking any 90? bends, said pipe loop transporting said fluid containing H.sub.2S, wherein less H.sub.2S scavenger is used in said pipe loop than in a straight pipe of a same length and a same diameter to bring an H.sub.2S level to less than 1 ppm.

2. The method of claim 1, said pipe loop being of at least 50 or at least 100 feet in length.

3. The method of claim 1, said pipe loop is wound around a spool.

4. The method of claim 1, said pipe loop is wound around a spool of at least 4-5 feet or at least 6 feet in diameter.

5. The method of claim 1, wherein said H.sub.2S scavenger is an amine, triazine, an aldehyde, or combinations thereof.

6. An improved method of removing H.sub.2S from natural gas, said method comprising injecting an H.sub.2S scavenger into a straight pipe flowing natural gas containing H.sub.2S, said improvement comprising introducing an H.sub.2S scavenger upstream of a pipe loop, said pipe loop wound around a spool having a core diameter of at least 6 feet and flowing a natural gas containing H.sub.2S therein, wherein less H.sub.2S scavenger is used in said pipe loop than in said straight pipe to bring an H.sub.2S level to less than 1 ppm.

7. The method of claim 6, said pipe loop of at least 25 or at least 50 or at least 100 feet in length.

8. The method of claim 6, wherein said H.sub.2S scavenger is an amine, triazine, an aldehyde, or combinations thereof.

9. A method of removing H.sub.2S from natural gas, said method comprising: a) measuring a concentration of H.sub.2S at a first sampling point in a pipeline carrying natural gas plus H.sub.2S; b) injecting an H.sub.2S scavenger into a length of straight pipe in said pipeline; c) measuring a concentration of H.sub.2S at a sampling point after said straight pipe; d) introducing additional H.sub.2S scavenger upstream of a pipe loop in said pipeline and downstream of said straight pipe, said pipe loop having a uniform curvature; e) measuring a concentration of H.sub.2S at a third sampling point after said pipe loop; f) collecting H.sub.2S-free natural gas at a collection point after said third sampling point.

10. The method of claim 9, wherein said pipe loop is composed of high density polyethylene (HDPE), fiberglass, epoxy-free dry fiberglass, polyvinyl chloride, polyethylene or combinations thereof.

11. The method of claim 9, wherein a total length of said straight pipe plus said pipe loop is at least 100 feet, preferably at least 200 feet.

12. The method of claim 9, wherein said loop line has a diameter of 1-10 inches and a flow rate of 1-10 MMSCF, preferably about 2-6 inches and about 5 MMSCF.

13. The method of claim 9, wherein said pipe loop is wound around a spool having a core of at least 6 feet in diameter.

14. The method of claim 9, wherein said H.sub.2S scavenger is amine, triazine, an aldehyde, or combinations thereof.

15. The method of claim 9, wherein said collected H.sub.2S-free natural gas is processed to form liquified natural gas (LNG).

16. A method of removing H.sub.2S from natural gas, said method comprising: a) measuring a concentration of H.sub.2S at a first sampling point in a pipeline carrying natural gas plus H.sub.2S; b) introducing H.sub.2S scavenger upstream of a pipe loop in said pipeline, said pipe loop having a uniform curvature; c) measuring a concentration of H.sub.2S at a second sampling point after said pipe loop; d) collecting H.sub.2S-free natural gas at a collection point after said second sampling point.

17. The method of claim 16, wherein said pipe loop is composed of high density polyethylene (HDPE), fiberglass, epoxy-free dry fiberglass, polyvinyl chloride, polyethylene or combinations thereof.

18. The method of claim 16, wherein a total length of said pipe loop is at least 25 feet, at least 50 feet or at least 100 feet, and is preferably less than 200 feet.

19. The method of claim 16, wherein said loop line has a diameter of 1-10 inches and a flow rate of 1-10 MMSCF, preferably about 2-6 inches and about 5 MMSCF.

20. The method of claim 16, wherein said pipe loop is wound around a spool having a core of at least 6 feet in diameter.

21. The method of claim 16, wherein said H.sub.2S scavenger is amine, triazine, an aldehyde, or combinations thereof.

22. The method of claim 16, wherein said collected H.sub.2S-free natural gas is processed to form liquified natural gas (LNG).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0048] FIG. 1. Schematic of prior art treatment line (not drawn to scale) wherein at least 200 feet of straight pipe are needed, greatly increasing the footprint of the H.sub.2S mitigation system.

[0049] FIG. 2. Schematic of straight line direct injection of H.sub.2S scavenger chemical converted to have an added loop line. The footprint can be significantly reduced by the addition of a loop line. The second loop line is optional, but may be used where space needs dictate two smaller spools.

[0050] FIG. 3. Schematic of a loop line facility with minimal footprint.

[0051] FIG. 4. Photo of a loop line with multiple loops in a spool added to a direct injection facility.

DETAILED DESCRIPTION

[0052] FIG. 1 shows a prior art straight pipe direction injection facility (100) with sampling ports (101a-c), and scavenger injection valves (103a-b). Since the straight pipe (105) needs to be at least 200 feet for efficacy of the scavenger, a considerable footprint is needed, although with the added sampling and injectors, the line could be 100 feet out and 100 feet in.

[0053] FIG. 2 details a typical straight line system converted by adding a loop line (200). The numbers are the same, but starting with the 200 series, so we have sampling ports (201a-d), and scavenger injection valves (203a-c). With the added loop (207a), the straight pipe (205) can be shorter as loop line (207a) compensates for the decreased length. In this converted system, footprint is reduced, but there is still a straight line, so it can be reduced further if built de novo with a loop line, as shown in FIG. 3.

[0054] In FIG. 2 we also show an optional second loop system (207b). As can be seen, testing for hydrogen sulfide content can be performed before injection, and then again after treatment. By testing at each stage, the optimal amount of hydrogen sulfide scavenger is added. We do not envision needing a second loop, but occasionally space needs may dictate two or more smaller loops instead of one larger loop, as may high levels of H.sub.2S in the gas.

[0055] FIG. 3 shows a new loop line system (300). FIG. 3 shows sampling ports (301a-b), and scavenger injection valves (303), and loop line (307) compensates for the lack of straight pipe. In use, a sample is taken (301a) and concentration of H.sub.2S is measured. A standard gas chromatography and chemiluminescence method as per ASTM D5504-01 or D6228-98 are used for measurement of H.sub.2S concentration. An appropriate amount for scavenger is then injected (303a). Once the fluid has passed through the loop line (307), samples are taken again (301b). The hydrogen sulfide should be at or near zero, if the correct loop length, diameter, flow rate, and level of scavenger were determined in advance, but additional injection (303b) and sampling (301c) ports can be added in case of variance. Here, there is no need for straight pipe, and the footprint may be optimally reduced.

[0056] The gas with the H.sub.2S scavenger travels through multiple loops of pipeline (307) for a retention time of a few minutes to a few hours. Depending on the overall length of the loop, the pipe diameter, the number of turns and the flow rate of the gas, the gas and H.sub.2S scavenger mixture can travel from 6 h to about 12 h in the loop with minimal turbulence or loss of scavenger. With the loop line method, typically 0.5 to 0 ppm of H.sub.2S would be detected at the second sampling point. Sweet gas is collected at the sweet gas outlet 309 and is sent for sale or storage as LNG.

[0057] Although only three loops are shown in FIG. 3 for simplicity of illustration, a typical loop line has a spool with multiple loops wound around it, as shown in FIG. 4. FIG. 4 shows a perspective ground level view of a vertical loop line with multiple loops attached to a direct injection line.

Loop Line in Conjunction with Direct Injection

[0058] In a recent application of this loop line method, two existing US shale gas facilities were chosen for fitting with a loop line. The fields A and B already had direct injection of H.sub.2S scavenger amounting to more than 500 gallons/month of scavenger. However, the H.sub.2S level in the gas after the DI of H.sub.2S scavenger was still very high (35-40 ppm). To reach 0 ppm would have required an estimated 300-500 additional gallons of scavenger. The results of this application are shown below in Table 1.

TABLE-US-00002 TABLE 1 Direct Injection Method H.sub.2S scavenger injection (gallons/ H.sub.2S level after Field H.sub.2S level in gas month) treatment A 120 ppm 700 35 ppm B 240 ppm 1100 40 ppm

[0059] To address the high hydrogen sulfide levels, Flexpipe? (Farnham Quebec CA) loop made of high-density polyethylene, helically wound epoxy-free dry fiberglass, and a protective outer jacket was tested in the loop line method, although high density polyethylene or similar materials could also be used. The Flexpipe? was installed in a natural gas wellpad, downstream of the straight pipe section.

[0060] Upon adding a loop line of same diameter, flow rate, with added injection of only about 110-120 gallons of the same chemicals, the H.sub.2S levels in the sales gas reached 0 ppm, resulting in significant cost saving on scavenger chemicals. The results of this application are shown below in Table 2. As can be seen, we were able to obtain significant cost saving due to the increased efficiency of the loop system.

TABLE-US-00003 TABLE 2 Direct Injection with Loop Line Method H.sub.2S scavenger injection (through Yearly H.sub.2S level Loop Line) H.sub.2S level after chemical Field in gas (gallons/month) treatment saving A 120 ppm 110 0 ppm $270K B 240 ppm 120 0 ppm $490K

(Prophetic) Loop Line System

[0061] In a developing oil and gas facility with medium to low H.sub.2S concentration, a loop line of appropriate material could be installed with no H.sub.2S scavenger direct injection into straight line piping, and instead employing addition of chemicals at any suitable point upstream of the loop. A multi-loop system with a low injection of H.sub.2S scavenger chemical is likely to remove all H.sub.2S from the gas resulting in a 0 ppm level, provided that the pipe diameter, length, flow rate and chemical amounts are tested to provide optimal scavenging. We anticipate that 25-200, probably 100-150 feet of loop piping, with a 2-10, preferably 4-6-inch diameter and optimized flow rates, on a spool core of at least 6 feet diameter will be sufficient to reduce 200-250 ppm of hydrogen sulfide to near zero.

[0062] The examples herein are intended to be illustrative only, and not unduly limit the scope of the appended claims. Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the scope of the disclosure as defined in the claims.

[0063] The following references are incorporated by reference in their entirety: [0064] ELSHIEKH, T. M., et al. Optimum injection dose rate of hydrogen sulfide scavenger for treatment of petroleum crude oil. Egyptian Journal of Petroleum, 2015, 25, 75-78. [0065] ELHATY, I. A. Development in the scavenging efficiency of H.sub.2S scavengers in oil and gas industry. Nat. Volatiles & Essent. Oils, 2022, 9(2), 219-229. [0066] ASTM D5504-01 Standard test method for the determination of sulfur compounds in natural gas and gaseous fuels by gas chromatography and chemiluminescence.