PROCESS FOR REMOVING METAL NAPHTHENATE FROM CRUDE HYDROCARBON MIXTURES

Abstract

The present invention provides a process for removing metal naphthenate from a crude hydrocarbon mixture comprising: —mixing said crude hydrocarbon mixture (1) comprising metal naphthenate with an acid (3) in the presence of water, wherein said acid converts said metal naphthenate to naphthenic acids and metal salts; —allowing said metal salt to partition into a water phase; —separating said crude heavy hydrocarbon mixture (5) comprising naphthenic acid and said water phase (6) comprising said metal salt; and —preferably pumping said water phase comprising metal salt to a formation.

Claims

1. A process for removing metal naphthenate from a crude hydrocarbon mixture comprising: mixing said crude hydrocarbon mixture comprising metal naphthenate with an acid in the presence of water, wherein said acid converts said metal naphthenate to naphthenic acids and metal salts; allowing said metal salt to partition into a water phase; separating said crude heavy hydrocarbon mixture comprising naphthenic acid and said water phase comprising said metal salt; and preferably pumping said water phase comprising metal salt to a formation.

2. A process as claimed in claim 1, comprising pumping said water phase comprising metal salt to a formation.

3. A process as claimed in claim 1, wherein said crude hydrocarbon mixture initially comprises at least 40 ppm wt of said metal naphthenate.

4. A process as claimed in claim 1, wherein said metal naphthenate is calcium naphthenate.

5. A process as claimed in claim 1, wherein said crude hydrocarbon mixture is a crude heavy hydrocarbon mixture.

6. A process as claimed in claim 1, further comprising adding diluent to said crude hydrocarbon mixture, prior to mixing said crude hydrocarbon mixture with said acid.

7. A process as claimed in claim 1, wherein said acid has a pKa of less than 7.

8. A process as claimed in claim 1, wherein said acid is an inorganic acid.

9. A process as claimed in claim 8, wherein said acid is selected from hydrochloric acid, nitric acid, hydrobromic acid, hydroiodic acid, perchloric acid and phosphoric acid.

10. A process as claimed in claim 1, wherein said acid is an organic acid.

11. A process as claimed in claim 10, wherein said acid is selected from acetic acid, formic acid, glycolic acid, gluconic acid, glyoxal (aldehyde), glyoxylic acid, thioglycolic acid, citric acid, lactic acid, trifluoroacetic acid, chloroacetic acid, ascorbic acid, benzoic acid, propionic acid, phthalic acid, fumaric acid, oxalic acid, tartaric acid, maleic acid, succinic acid, malic acid, methanesulfonic acid, benzenesulfonic acid and p-toluenesulfonic acid.

12. A process as claimed in claim 1, wherein said mixing is achieved by injecting said acid into a line conveying said crude hydrocarbon mixture.

13. A process as claimed in claim 1, wherein said line is a production pipeline.

14. A process as claimed in claim 1, wherein said mixing creates water droplets comprising said acid.

15. A process as claimed in claim 1, wherein said acid is added to a crude hydrocarbon mixture extracted from a subterranean formation.

16. A process as claimed in claim 15, wherein said acid is added prior to bulk separation of said crude hydrocarbon mixture into crude hydrocarbon mixture and water.

17. A process as claimed in claim 1, wherein said crude hydrocarbon mixture comprises at least 95% by volume of hydrocarbon.

18. A process as claimed in claim 17, wherein said acid is added after bulk separation and prior to a second separation.

19. A process as claimed in claim 1, wherein said acid is added prior to bulk separation and prior to a second separation.

20. A process as claimed in claim 1, which is carried out at a wellsite.

21. A process as claimed in claim 1, wherein said crude hydrocarbon mixture obtained after separation comprises less than 100 ppm wt metal ion as metal naphthenate.

22. A process as claimed in claim 1, wherein said crude hydrocarbon mixture obtained after separation comprises 0.1 to 12 wt % naphthenic acid.

23. A process as claimed in claim 1, further comprising treating said crude hydrocarbon mixture comprising naphthenic acid to reduce its API.

24. A process as claimed in claim 1, further comprising pumping said crude hydrocarbon mixture comprising naphthenic acid to a refinery.

25. A process for producing hydrocarbon from a hydrocarbon containing formation comprising: extracting a crude hydrocarbon mixture from a hydrocarbon containing formation; mixing said crude hydrocarbon mixture comprising metal naphthenate with an acid in the presence of water, wherein said acid converts said metal naphthenate to naphthenic acid and metal salt; allowing said metal salt to partition into a water phase; separating said crude hydrocarbon mixture comprising naphthenic acid and said water phase comprising said metal salt; pumping said crude hydrocarbon mixture comprising naphthenic acid to a refinery; and preferably pumping said water phase comprising metal salt to a formation.

26. A process as claimed in claim 25, further comprising adding a diluent to said crude hydrocarbon mixture extracted from said formation prior to mixing with said acid.

27. A process as claimed in claim 25, further comprising upgrading said crude hydrocarbon mixture comprising naphthenic acid prior to pumping to a refinery.

28. A system for removing metal naphthenate from a crude hydrocarbon mixture comprising: a container comprising an acid; a line for conveying a crude hydrocarbon mixture to a separator; a means for adding said acid to said line conveying a crude hydrocarbon mixture to a separator, wherein said means is fluidly connected to said container comprising acid; a first separator for separating a crude hydrocarbon mixture comprising naphthenic acid and a water phase comprising a metal salt, wherein said separator has an inlet for crude hydrocarbon mixture, an outlet for crude hydrocarbon mixture comprising naphthenic acid and an outlet for a water phase comprising a metal salt; and preferably a line for conveying said water phase comprising a metal salt into a formation.

29. A system as claimed in claim 28, wherein said outlet for crude hydrocarbon mixture comprising naphthenic acid of said separator is fluidly connected to a treater.

30. A system as claimed in claim 29, wherein said outlet for crude hydrocarbon mixture comprising naphthenic acid of said separator is fluidly connected to a second separator.

31. A system as claimed in claim 30, further comprising a second means for adding said acid in between said first separator and said second separator, wherein said second means is fluidly connected to said container comprising acid.

32. A system as claimed in claim 28, wherein said first separator is a bulk separator.

33. A system as claimed in claim 30, wherein said second separator is a gravity separator.

34. A crude hydrocarbon mixture obtainable by the process of claim 1.

35. A crude hydrocarbon mixture obtained by the process of claim 1.

36. A crude hydrocarbon mixture comprising 0.1 to 12 wt % naphthenic acid and less than 100 ppm wt metal ion as metal naphthenate.

37. Use of an acid to remove metal naphthenate from a crude hydrocarbon mixture, comprising adding said acid to said crude hydrocarbon mixture in the presence of water to form naphthenic acid and metal salt and separating said crude heavy hydrocarbon mixture comprising naphthenic acid and said water phase comprising said metal salt and preferably pumping said water phase comprising said metal salt into a formation.

Description

DESCRIPTION OF THE FIGURES

[0089] FIG. 1 is a schematic of a preferred process and system of the present invention;

[0090] FIG. 2 is a schematic of another preferred process and system of the present invention;

[0091] FIG. 3 is a plot of Ca (ppm) in the hydrocarbon phase versus acetic acid concentration in a bottle experiment;

[0092] FIG. 4 is a plot of Ca (ppm) in the hydrocarbon phase versus pH in a bottle experiment; and

[0093] FIG. 5 is a plot of Ca (ppm) in the hydrocarbon phase versus stoichiometric amount of acetic acid added.

DETAILED DESCRIPTION OF THE FIGURES

[0094] Referring to FIG. 1, a crude hydrocarbon mixture comprising metal naphthenate such as calcium naphthenate is extracted from a formation. The crude hydrocarbon mixture also comprises water. The crude hydrocarbon mixture extracted from the formation typically has a calcium naphthenate content of 400-1000 ppm wt. Its API is typically around 18°.

[0095] The crude hydrocarbon mixture is pumped via line 1 to bulk separator 2. An acid is added via line 3 into the crude hydrocarbon mixture during its transportation to the bulk separator. Due to the fact that the crude hydrocarbon mixture is flowing at a high velocity in the line 3, the acid forms into water droplets. The formation of droplets means that a high level of contact is achieved between the metal naphthenate and the acid even though they are present in different phases, i.e. hydrocarbon and water respectively.

[0096] The acid reacts with the metal naphthenate to produce naphthenic acid and metal salt, e.g. Ca.sup.2+. The metal salt partitions into the water phase whereas the naphthenic acid remains in the crude hydrocarbon mixture. In the separator 2 any gas is removed via line 4 and the hydrocarbon and water phases are allowed to separate. The separation process is enhanced by the removal of metal naphthenate from the crude hydrocarbon mixture. Once separation is completed, the crude hydrocarbon mixture comprising naphthenic acid is transported via line 5 to a treater unit 7. In the treater unit 7 the crude hydrocarbon mixture comprising naphthenic acid is upgraded prior to pumping to a refinery. The water phase comprising metal salt such as Ca.sup.2+ is removed from the separator via line 6 and is pumped into a hydrocarbon-depleted formation in the vicinity of the well site.

[0097] The crude hydrocarbon mixture obtained from the separator 2 typically has a calcium naphthenate content of 0-100 ppm wt and a naphthenic acid content of 0.1 to 12 wt %. Its API is typically around 18°. After upgrading, the crude hydrocarbon mixture typically has a calcium naphthenate content of 0-100 ppm wt and a naphthenic acid content of 0.1 to 12 wt %. Its API is typically around 20°.

[0098] Referring to FIG. 2, the process and system are identical in many ways to that shown in FIG. 1 and thus identical reference numerals are used. In the process shown in FIG. 2, however, a diluent is added to the crude hydrocarbon mixture via line 11 during its transportation to separator 2.

[0099] Additionally the crude hydrocarbon mixture comprising naphthenic acid is transported via line 5 to a second separator 10. Further acid is added via line 3′ to the crude hydrocarbon mixture during its transportation to the second separator 10. As described above in relation to FIG. 1, droplets of aqueous acid are formed and provide a high surface area for contact with metal naphthenate present in the crude hydrocarbon mixture. Optionally further water is added via line 9 into the second separator 10 to improve the separation process. Once separation is completed, the crude hydrocarbon mixture comprising naphthenic acid is transported via line 8 to a treater unit 7 and the water phase comprising metal salt such as Ca.sup.2+ is removed from the separator via line 6′ and is pumped into a hydrocarbon-depleted formation in the vicinity of the well site.

[0100] The crude hydrocarbon mixture obtained from the separator 10 typically has a calcium naphthenate content of 0-100 ppm wt and a naphthenic acid content of 0.1 to 12 wt %. Its API is typically around 18°. After upgrading, the crude hydrocarbon mixture typically has a calcium naphthenate content of 0-100 ppm wt and a naphthenic acid content of 0.1 to 12 wt %. Its API is typically around 20°.

[0101] The advantages of the present invention include: [0102] Avoids the expensive process of removing metal naphthenates in the refinery [0103] Improves the bulk separation process [0104] Improves any subsequent separation process [0105] Metal salts removed in the water phase may ultimately be pumped back into the hydrocarbon formation for pressure maintenance [0106] Installation at wellsite

Examples

Example 1—Bench Scale Bottle Test of Calcium Removal by Acetic Acid

[0107] A series of bottle experiments were carried out wherein acetic acid was added to a mixture of Bressay crude oil with xylene (50/50 vol %) mixed with synthetic formation water with 16940 ppm Na (as NaCl) and 1719 ppm Ca (as CaCl.sub.2). After mixing and separation, the amount of Ca remaining in the oil phase was determined by ICP.

[0108] The results are shown in FIG. 3 wherein the Y axis is the amount of Ca present in the oil phase after separation and the X axis is the amount of acetic acid added. The results show that there was less Ca present in the oil phase when higher amounts of acetic acid were added.

Example 2—Bench Scale Bottle Test of Calcium Removal and Naphthenate Formation at Different pH Levels

[0109] A series of bottle experiments were carried out wherein acetic acid was added to a mixture of Bressay crude oil with xylene (50/50 vol %) mixed with synthetic formation water with 16940 ppm Na (as NaCl) and 1719 ppm Ca (as CaCl.sub.2). The mixture was buffered to the desired pH-level by adding MOPS-buffer. After mixing the pH level of the water phase was measured and after separation the amount of Ca remaining in the oil phase was determined by ICP.

[0110] The results are shown in FIG. 4 wherein the Y axis is the amount of Ca present in the oil phase after separation and the X axis is pH. The results show that if a pH of 6.3 or lower is achieved that Ca removal from the oil phase occurs. (The red and blue symbols represent two independent experiments.)

Example 3—Continuous Flow Experiment

[0111] Bressay/Åsgard crude (85/15 vol %) was mixed with synthetic formation water, with 16940 ppm Na (as NaCl) and 1719 ppm Ca (as CaCl.sub.2). The water cut was 20-25 vol %.

[0112] Acetic acid was then added continuously in a stoichiometric amount according to the equilibrium equation, i.e. an amount equal to 1.0 on the X-axis. A static mixer present in the line after the acid injection point ensured mixing of the phases. After a fixed amount of time of 20 minutes, the phases were separated and the amount of Ca present in the oil phase determined by ICP.

[0113] The results are shown in FIG. 5 wherein the Y axis is the amount of Ca present in the oil phase after separation and the X axis is the stoichiometric amount of acid added. It can be seen from FIG. 5 that about 1.2 stoichiometric equivalents of acid are required to remove all of the calcium. (Three independent experiments; grey, yellow and red were carried out at 0° C., 40° C. and 70° C. respectively).